BNP Paribas Bank Polska
Annual Report 2013

Plain-text annual report

Highlights Financial ($ thousands, except per share) Production revenues Funds from operations(1) Per share(1) (2) Dividends declared(3) Per share Net income Per share(4) Adjusted net income(5) Per share(4) Total assets Long-term debt, net of working capital Long-term debt, net of adjusted working capital(6) Shareholders’ equity Capital expenditures: Exploration and development Acquisitions, net of dispositions ANNUAL REPORT 2013 Three months ended December 31, 2013 2012 % Change Years ended December 31, 2012 2013 % Change 245,466 223,021 124,354 0.62 110,015 0.57 38,904 0.21 6,667 0.03 23,702 0.12 63,481 0.36 14,442 0.07 16,535 0.09 10% 13% 9% (39%) (42%) (54%) (57%) 43% 33% 964,312 832,491 16% 477,578 2.42 152,968 0.84 49,505 0.25 75,297 0.38 378,667 2.16 224,801 1.44 64,202 0.37 58,049 0.33 26% 12% (32%) (42%) (23%) (32%) 30% 15% 4,235,626 4,062,852 4% 1,155,764 963,678 20% 1,124,198 963,500 17% 2,270,015 2,285,889 (1%) 111,596 4,815 76,937 118,837 45% (96%) 443,829 20,530 402,090 (10,956) 10% 287% Weighted average outstanding equivalent shares: (thousands) Basic 199,254 Diluted 201,756 (4) 192,638 194,322 3% 4% 197,296 199,340 175,581 176,747 12% 13% 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 ($/boe)(10) 287 15,103 12,208 75,072 3.54 49.35 72.73 8.77 1.21 12.91 20.82 269 14,563 12,395 71,842 3.22 42.60 75.73 8.69 1.22 12.67 19.12 7% 4% (2%) 4% 10% 16% (4%) 1% (1%) 2% 9% 278 15,093 12,039 73,406 3.35 47.61 79.32 8.93 1.15 13.00 20.54 253 14,074 12,997 69,250 2.60 45.19 77.30 9.07 1.10 10% 7% (7%) 6% 29% 5% 3% (2%) 5% 13.26 (2%) 17.70 16% 1 Highlights (cont’d) Drilling (gross wells): Natural gas Oil Average success rate Land: Undeveloped (net acres) Total (net acres) Reserves: (11) Proved: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) Proved plus probable: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) % Proved producing % Proved % Probable Net present value of future cash flow before income taxes ($ millions): 0% discount rate 5% discount rate 10% discount rate 15% discount rate Reserve life index (years): (12) Total proved Total proved plus probable Reserves (boe per thousand shares - basic): Total proved Total proved plus probable Finding and development expenditures – proved plus probable ($/boe): Including changes in future development expenditures Excluding changes in future development expenditures Finding, development and acquisition expenditures – proved plus probable ($/boe): Including changes in future development expenditures Excluding changes in future development expenditures Recycle ratio – proved plus probable: (13) Including changes in future development expenditures Excluding changes in future development expenditures Years ended December 31, 2013 128 58 68 98% 2012 115 47 67 99% % Change 11% 23% 1% (1%) 1,281,191 2,891,947 1,253,141 2,832,701 2% 2% 3% 3% 3% 7% 7% 7% (1%) (3%) 3% 8% 10% 12% 13% (5%) (2%) - 4% (18%) 3% (1%) 25% 19% (8%) 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 11.56 11.03 8.75 1.9 2.3 921.0 94,914 248,409 1,372.3 143,505 372,220 40% 67% 33% 9,005 5,742 4,126 3,183 9.6 13.5 1,283 1,924 14.66 11.23 11.16 6.98 1.6 2.5 NOTES: (1) Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating 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. (2) Basic funds from operations per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. (3) Dividends declared includes both cash dividends and common shares issued pursuant to Bonavista's dividend reinvestment plan (DRIP) and Bonavista's stock dividend program (SDP). For the three months ended December 31, 2013 approximately 1.2 million common shares were issued under the DRIP and SDP with an approximate value of $14.2 million. For the year ended December 31, 2013, approximately 4.6 million common shares were issued under the DRIP and SDP with an approximate value of $59.2 million. (4) Basic net income per share calculations include exchangeable shares which are convertible into common shares on certain terms and conditions. (5) Amounts have been adjusted to exclude unrealized gains and losses on financial instrument commodity contracts. (6) Amounts have been adjusted to exclude associated assets or liabilities from financial instrument commodity contracts and decommissioning liabilities. (7) Oil includes light, medium and heavy oil. (8) Product prices include realized gains and losses on financial instrument commodity contracts. (9) Cash costs equal the total of operating, transportation, general and administrative, and financing expenses. (10) Operating netback equals production revenues including realized gains and losses on financial instrument commodity contracts, less royalties, operating and transportation expenses, calculated on a boe basis. (11) Working interest reserves are gross reserves prior to deduction of royalties and without including any of Bonavista’s royalty interests. (12) Calculated based on the amount for the relevant reserve category divided by the 2014 production forecast prepared by the independent reserve evaluator (GLJ). (13) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition expenditures per boe. 2 Share Trading Statistics ($ per share, except volume) High Low Close Average Daily Volume - Shares MESSAGE TO SHAREHOLDERS December 31, 2013 September 30, 2013 June 30, 2013 March 31, 2013 Three months ended 14.04 11.25 13.92 1,000,966 14.37 12.70 12.93 620,864 16.77 13.33 13.65 428,813 15.18 12.25 14.94 676,012 In 2013, Bonavista successfully executed on its commitment to maximize shareholder value demonstrated by a solid year of performance as we validated the quality of our asset base and the capabilities of our team. As a key component of our business plan, we demonstrated a 26% increase in our funds from operations over 2012, representing growth of 12% on a per share basis. Improved natural gas prices and our focus on enhancing our operating and capital efficiencies were the primary sources for this increase in funds from operations. This was evidenced by steadily lowering our cost of adding production to approximately $21,000 per boe per day during the fourth quarter of 2013 from $32,500 per boe per day during the fourth quarter of 2012, on a trailing 12 month basis. Additionally, our ability to improve our finding and development costs by 18% to $11.95 per boe (including changes in future development expenditures) and our finding, development and acquisition costs to $11.03 per boe (including changes in future development expenditures) are a testament to this focus on efficiency gains. Lastly, we achieved a two percent improvement in operating and cash costs and when included with a seven percent increase in realized product prices, resulted in a year-over-year improvement in our recycle ratio to 1.9:1 from 1.6:1 in 2012. These achievements were realized by focusing our attention in our West Central and Deep Basin core areas where we have the opportunity and expertise to drive enhancements in our performance and execution. Our strategy has led to an increased concentration of land, production and reserves in these multi-zone, prolific areas of the Western Canadian Sedimentary Basin. As a result, a group of non-core assets which cannot compete for investment within these core areas were rationalized for approximately $110.9 million as part of our concentration strategy. Our business plan to maximize shareholder value is based upon a balanced approach of generating income and growth. In 2013, we experienced a six percent increase in our production volumes while our dividend program delivered an annualized yield of approximately six percent, collectively exceeding our total return goal. Our growth strategy is centered on achieving total returns in excess of 10% at fixed commodity prices of $3.50 per gj for natural gas at AECO and Cdn$95.00 per bbl WTI equivalent over the next five years. The continued success of this business plan will lie in our ability to remain focused on continued improvements in both operating and capital efficiencies and our ability to manage risk and safeguard our funds from operations through our hedging strategy. The successful implementation of our business plan has led to multiple achievements during 2013, some of which are outlined below. Operational and Financial Accomplishments for 2013 include: • Achieved a record average annual production rate of 73,406 boe per day, representing a 6% increase over last year and record quarterly production of 75,072 boe per day in the fourth quarter. Bonavista is currently producing approximately 74,000 boe per day, net of recent dispositions of approximately 2,500 boe per day in the first quarter of 2014 for proceeds of $103 million; Improved our 2013 operating costs on a per boe basis by 2% to $8.93 per boe from $9.07 per boe as compared to 2012. Operating costs for the three months ended December 31, 2013 were $8.77 per boe; • • Executed an effective capital expenditure program, investing $443.8 million in exploration and development activities drilling 128 wells with an overall success rate of 98%. In the fourth quarter, Bonavista spent approximately $111.6 million on exploration and development, drilling 27 wells with an overall success rate of 100%; • Production revenues were 16% higher at $964.3 million in 2013 when compared to 2012. For the fourth quarter, production revenues were $245.5 million representing a 10% increase from the fourth quarter of 2012; • Realized funds from operations of $477.6 million in 2013 representing a 26% increase from 2012. Funds from operations during the fourth quarter were $124.4 million, a 13% improvement from the same period in 2012; 3 • Managed our exposure to commodity price fluctuations for 2014 resulting in approximately 66% of our forecasted net natural gas revenues hedged at an average floor price of $3.40 per gj at AECO and 70% of our net oil and liquids revenues hedged at an average floor price of Cdn$89.35 per bbl WTI. Additionally, in 2015 we have hedged approximately 50% of net natural gas revenues at an average floor price of $3.60 per gj at AECO and 30% of our net oil and liquids revenues at an average floor price of Cdn$90.00 per bbl WTI; • Delivered cumulative dividends of over $2.6 billion or $27.03 per common share since we introduced an income component to our shareholder return in July 2003; and • Elected to reduce the commitment amount under our bank credit facility to $600 million from $1.0 billion. The $400 million reduction in the commitment results in annual savings of approximately $1.7 million in standby fees or $0.06 per boe on our cash costs. With the reduction, we still have committed bank credit availability of approximately $367.8 million. The weighted average interest rate under the bank facility was 3.1% for the year ended December 31, 2013. 2013 Reserves Highlights • Replaced 2013 annual production by 198%, adding 53.1 mmboe of proved plus probable reserves, bringing total year end 2013 reserves to 398.5 mmboe representing a 7% increase over 2012, equivalent to a 4% per share increase; • Generated a solid reserve life index of 9.1 years on a proved basis and 13.2 years on a proved plus probable basis; • Reduced finding and development costs (excluding acquisitions and divestitures) by 18% to $11.95 per boe on a proved plus probable basis (including changes in future development capital) which reflects the improvement in capital efficiencies achieved in 2013 with our exploration and development program; • Achieved 2013 finding, development and acquisition costs, including changes in future development expenditures, of $14.60 per boe on a proved basis ($13.44 per boe excluding changes in future development expenditures) and $11.03 per boe on a proved plus probable basis ($8.75 per boe excluding changes in future development expenditures); • Three year average finding, development and acquisition costs, including changes in future development expenditures are $15.31 per boe on a proved basis ($10.93 per boe excluding changes in future development expenditures) and $12.07 per boe on a proved plus probable basis ($9.37 per boe excluding changes in future development expenditures); • Generated an attractive proved plus probable operating netback recycle ratio of 1.9:1 based on 2013 operating • netbacks and 2.2:1 based on forecasted 2014 operating netbacks; and Increased proved plus probable future development capital by 9% to $1.5 billion, representing the future growth and development potential in our asset portfolio. Future development capital as a ratio of forecasted 2014 capital expenditures and cash flow are 3.1:1 and 2.5:1 times respectively. 2013 Acquisition and Divestiture Highlights • Completed 30 property transactions in 2013, resulting in net expenditures of $20.5 million; • Completed acquisitions of $131.4 million adding production of 3,670 boe per day at closing and 2,430 boe per day on average for the year and proved plus probable reserves of 20.5 mmboe; • Divested of $110.9 million of non-core assets comprising 1,290 boe per day of production at closing and 745 boe per day on average for the year and 5.8 mmboe of proved plus probable reserves; and • Closed a strategic acquisition during the fourth quarter in the Deep Basin area of $29 million, adding production of approximately 725 boe per day and over 26 Bluesky locations. Since closing, optimization and drilling investment of $9.7 million has resulted in production growing to approximately 2,100 boe per day. 4 2013 Core Area Highlights West Central Alberta Core Area Hoadley Glauconite Liquids Rich Natural Gas: Bonavista drilled 12 horizontal Glauconite wells during the fourth quarter for a total of 42 wells in 2013. Our activity during the year was focused primarily on optimizing capital efficiencies. We achieved this through maximizing facility and infrastructure utilization while reducing the development cost of this substantial resource through initiatives like our extended reach horizontal well program. Based upon our first three extended reach horizontal wells, we experienced an average cost reduction of 13% per well when compared to the cost of equivalent reservoir access from two wells. As we refine this extended reach technology, we expect the use of this development technique to improve capital efficiencies throughout the entire Glauconite trend. Our Glauconite horizontal well program in 2013 exceeded our expectations with average first month production rates of 500 boe per day. Production from the Hoadley Glauconite play in 2013 was 16,860 boe per day representing a 13% increase from the prior year. We have been successful with our cost structure achieving an overall reduction in costs of four percent when compared to 2012. Bonavista’s Hoadley development program generates an internal rate of return of 50% and a recycle ratio of 3.8:1 at an AECO price of $3.50 per gj. These compelling economics rank it amongst the top natural gas plays in North America. Given these attractive economics, the predictability of well performance and our continued success in optimizing capital efficiencies, we have increased our 2014 activity by 57%, with plans to spend $141 million drilling approximately 66 wells. This level of development will result in a record year of activity for Bonavista within the Hoadley Glauconite trend. To support this increase in activity, Bonavista has recently partnered with an area midstream operator, in the building of two 28 kilometer pipelines which will provide an incremental 130 mmcf per day of gathering capacity from the Hoadley Glauconite play to the Rimbey processing facility. The two pipelines include a 12 inch line to gather natural gas and a six inch line to gather natural gas liquids. This project is scheduled to be commissioned in the third quarter of 2014. Additionally, during the first quarter of 2015, we expect the commissioning of the Rimbey deep cut facility which will positively impact our economics as a result of increased natural gas liquids recoveries. Bonavista continues to be an industry leader in the Hoadley Glauconite play having drilled a total of 186 horizontal wells since 2008. Our land acquisition program and down spacing initiatives have resulted in a current drilling inventory in excess of 400 horizontal locations. With more than 75% of the original natural gas in place remaining in the reservoir, a stable inventory contemplating four wells per section, and the predictability and repeatability of the reservoir, the Glauconite will remain the anchor development project for Bonavista in 2014. Cardium Light Oil: Bonavista drilled two horizontal Cardium wells in the fourth quarter bringing total 2013 activity to 27 wells. The 2013 program involved the development of emerging areas of our land base such as Lochend and Strachan to confirm our understanding of reservoir capabilities. Despite this commitment to emerging areas in 2013, our continued focus on improving capital efficiencies has resulted in cost reductions on average of approximately $200,000 per well when compared to 2012. The Willesden Green area has been a focus area over the past 18 months. With numerous wells on production for a full year we are confident in our completion approach of utilizing slick water fracture treatments to generate a 10% to 15% improvement in well performance. Our 2014 development plans involve drilling five wells and initiating a water flood pilot. At Lochend, we drilled one well in the fourth quarter and seven wells in total for the year. Despite being constrained by facility limitations, initial well performance has been strong with first month production averaging over 300 boe per day. As a result of this well performance, we invested approximately $9 million in the construction of a 29 kilometer, eight inch pipeline from Lochend to a deep cut facility at Harmattan during the fourth quarter. This pipeline addition will not only add to our extensive operated infrastructure, it will create an unrestricted flow path for our current producing wells and will adequately accommodate our planned activity for 2014 at Lochend. Our 2014 capital expenditure plan is primarily focused on development in Willesden Green and Lochend, totaling approximately $53 million and drilling 20 wells. We have remained prudently active in the Cardium over the past five years drilling a total of 113 horizontal wells to date, while maintaining a healthy inventory of horizontal locations, representing a profitable, multi-year development opportunity. 5 Ellerslie Liquids Rich Natural Gas: During the fourth quarter, Bonavista drilled one horizontal Ellerslie oil well at Garrington, which had an initial 30-day rate of 350 boe per day, which includes 170 bbls per day of oil production. We expect this well to perform similar to our offset well that has demonstrated stable production performance at an average 190 bbls per day of oil over the first eight months. The significant presence of oil in the Ellerslie at Garrington creates an attractive netback of $40 per boe resulting in individual well payouts of approximately one year. In the second half of 2013, we drilled our first liquids rich natural gas Ellerslie horizontal well at Westerose which has demonstrated an initial 90-day production rate of 840 boe per day. With a well cost of $2.7 million, the economic performance of this well has encouraged our investment in a three dimensional seismic program to determine the extent of the Ellerslie reservoir. Similarly at Caroline, we drilled an Ellerslie liquids rich natural gas horizontal well in the second half of 2013. Despite having many operational challenges with the well, we successfully completed four stages (originally designed for 12) resulting in a stable rate of 525 boe per day over its first five months of production. We are exceedingly pleased with our development results in the Ellerslie formation throughout 2013. Hence, our 2014 plan contemplates a drilling program of 12 wells with an associated budget of approximately $44 million, representing a two-fold increase in activity over 2013. We will focus on the opportunities with lower operational risk at Garrington and Westerose where we anticipate an increase in execution success. As we become more intimate with the reservoir, we anticipate well performance that continues to meet or exceed our expectations. With a meaningful oil and natural gas liquids yields of approximately 100 bbls per mmcf on average, economic performance will continue to strengthen as we refine our operational approach. As an active operator in the Ellerslie over the past decade, our strategy had been to continue to strengthen our land position as we delineated the resource opportunity with vertical well development. Over the past 24 months we have acquired valuable horizontal operational experience in the play which has enhanced and accelerated the value of this play within our organization. Since 2010, we have grown our inventory of horizontal locations in excess of 200 locations and have assembled an extensive land base of 135 prospective sections. With netbacks currently averaging $30 per boe and decline rates approximating 50% in the first year of production, our 2013 activity has certainly exceeded our economic expectations. Consequently, we see the Ellerslie becoming a cornerstone of our development program in the near future. Deep Basin Core Area Bonavista had an active drilling program in the fourth quarter participating in 10 horizontal wells bringing our total 2013 drilling activity to 21 horizontal wells in our Deep Basin core area. We have been tremendously pleased with the overall results and look forward to continued success. Current production in the Deep Basin core area is approximately 16,500 boe per day and has grown 22% from a year ago. Our capital plan for 2014 involves spending $102 million, drilling 29 wells and infrastructure spending of $34 million. Our expansion in this core area is expected to result in capital efficiency improvements as larger drilling programs take place. Over the past four years, we have assembled a position of approximately 238,000 net acres with over 200 future horizontal locations. Bonavista currently operates natural gas processing capacity of approximately 230 mmcf per day and we continue to invest in additional infrastructure in 2014. We see the Deep Basin core area providing both near- term and mid-term growth especially as we transition from the building phase to commercial development with many of our plays. We remain committed to our Deep Basin area and are confident about its growth profile. Wilrich Natural Gas: We have experienced tremendous success with the Wilrich formation in 2013. Building on an important asset acquisition of 5,000 boe per day of production and 79,000 net acres of land in 2012, we exited 2013 acquiring access to an additional 26,000 acres of land and have added 2,800 boe per day of production through our exploration and development program. The majority of this land acquisition throughout 2013 has taken place in the Ansell area of the Deep Basin. Early in 2013, we gained access to 20,000 acres of Wilrich land at Ansell and have since drilled and completed two horizontal wells on this acreage. The results of these two wells have exceeded our expectations at restricted 90-day production rates averaging 900 boe per day per well. The first well has been on production for 10 months and has cumulatively produced 1.2 bcf of raw natural gas in that period of time. Currently, with access to over 44 sections of land at Ansell and the potential of multiple prospective zones, we have planned an $84 million capital budget for this area for 2014. We have committed to drilling 12 wells, five of which will be drilled in the first quarter of 2014. The first two have been drilled and completed using one drilling pad and have resulted in a combined rate of 34 mmcf per day after a 50 hour flow test. We have also committed to an infrastructure project in the first quarter of 2014, consisting of a 10 inch, 100 mmcf per day pipeline and a 30 mmcf per day compressor station. The pipeline and compressor station are expected to be commissioned by April 2014. The economic performance of our Wilrich play in Ansell is compelling at a natural gas price 6 of $3.50 per gj at AECO. Single-well economics portray a recycle ratio of 3.5:1 with a 10 month payout. The impact of a stronger natural gas price, coupled with the success of our 2013 drilling program speaks well to the future development of this play. At Marlboro, Bonavista holds approximately 28,000 net acres of Wilrich land. Our 2013 drilling program involved six gross horizontal wells (4.8 net) drilled into the Wilrich formation with these wells currently producing at a combined net rate of 1,700 boe per day. The Wilrich at Marlboro provides Bonavista with an additional 35 horizontal drilling locations. Although the natural gas from the Wilrich formation at Marlboro tends to have less associated natural gas liquids, economics remain robust due to the prolific production performance with payouts under two years and rates of return in excess of 35% at a natural gas price of $3.50 per gj at AECO. Bluesky Liquids Rich Natural Gas: In the fourth quarter, Bonavista participated in five horizontal Bluesky wells consisting of two operated and three non- operated, totaling nine wells for 2013. Our latest Pine Creek horizontal well drilled in the fourth quarter is our highest rate Bluesky result to date, producing at an average 30-day raw natural gas rate of 8.6 mmcf per day and 35 bbls per mmcf of liquids, of which 50% is condensate. We remained active during the fourth quarter by adding to our Bluesky position in Pine Creek with the acquisition of approximately 725 boe per day of Bluesky production and access to approximately 12,000 net acres of Bluesky rights where we have identified an additional 25 horizontal locations. On a rate of return perspective, the individual well economics of the Bluesky are the best of our liquids rich natural gas plays. Additional Emerging Opportunities The Blueberry Montney play remains an important part of our long-term development plans. Industry activity in the Montney formation remains strong on all fronts with recent industry acquisition metrics of approximately $4,000 per acre, solidifying our interpretation of the value of our land base. Through focused efforts on efficiencies, we reduced our drilling, completion and tie-in costs to $6.3 million representing a 25% reduction from the average of the previous wells drilled into the formation. As our industry remains focused on exporting Canadian natural gas from the west coast, the Blueberry Montney field will continue to play an important role as a potential supply, as it is uniquely positioned to participate in LNG export economics. Meanwhile, Bonavista will continue to improve its understanding of the technology required to optimize the recovery of the Montney liquids rich resource at our Blueberry field. As such, we have planned to drill two wells in Blueberry during 2014. In addition, Bonavista drilled and completed a Falher horizontal well in the West Central Alberta core area during the third quarter which has resulted in an initial 90-day production rate of approximately 600 boe per day including 60 bbls per mmcf of natural gas liquids. With the success of this well, we plan on additional reservoir delineation by drilling five horizontal wells in 2014. Strengths of Bonavista Energy Corporation Throughout our 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 volatility and uncertainly inherent in a commodity business like the energy sector. We have consistently improved the quality of our projects and have maintained a high level of investment activity on our asset base. This has resulted in an increase in corporate production by approximately 110% since converting to an energy trust in July 2003 and a further 10% since converting back to a corporation three years ago. 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 within the Western Canadian Sedimentary Basin. Our experienced technical teams have a solid understanding of our assets as they exercise the discipline and commitment required to deliver long-term value to our shareholders. We actively participate in undeveloped land purchases, producing property acquisitions and farm-in opportunities, which have all enhanced the quality of our extensive drilling inventory. These activities have led to low cost reserve additions and a predictable production base that continues to grow at a steady pace. Our production is currently approximately 65% natural gas weighted and is geographically focused in multi-zone regions primarily in Alberta. The predictable production performance and low cost structure of our asset base ensures favourable operating netbacks in most operating environments. Furthermore, our assets are predominantly operated by Bonavista, providing control over the pace of operations and direct influence over our operating and capital cost efficiencies. Our team brings a successful track record of executing low to medium risk development programs, while incorporating acquisitions and sound financial management. Our Board of Directors and management team possess extensive experience in the oil and natural gas business. They have successfully guided our organization through many different economic cycles utilizing a proven strategy consisting of disciplined cost controls and prudent financial management. Directors, management and employees also own approximately 13% of the equity of Bonavista, aligning our interests with external shareholders. 7 Outlook With the recent strengthening in natural gas prices due to cold weather across much of North America, we remain cautiously optimistic as we move into 2014. We do however remain aware of the robust natural gas production capability on this continent. This capability has been powered by prolific resource discoveries, associated natural gas production from oil and liquids drilling and continued improvements in the techniques used to exploit these resources. Given this backdrop, Bonavista will maintain a disciplined approach to commodity hedging and continue to take advantage of the recent increases in natural gas prices to secure future funds from operations. Operationally, we will continue to focus on being one of the most efficient producers within our peer group and continue to pursue low cost, repeatable opportunities throughout our concentrated portfolio of assets. These strategies coupled with our on-going asset concentration program will support our commitment to maximize shareholder returns through a balance of income and growth. To support this strategy and in light of the successful first quarter dispositions, Bonavista has a budgeted capital program of between $460 and $500 million in 2014. This includes spending between $560 and $600 million on exploration and development activities, offset by approximately $100 million of dispositions and does not contemplate further acquisitions at this time. The exploration and development program is expected to result in approximately 150 wells drilled and an average daily production forecast for the year of between 76,000 and 78,000 boe per day. Using the mid-point of our production estimate, Bonavista will deliver approximately five percent production growth in 2014 in spite of the non-core dispositions. With current commodity prices and hedges in place, we expect to exit 2014 with a debt to funds from operations ratio of approximately 1.8:1 and an all in payout ratio of 106%. Bonavista wishes to announce that Mr. Harry Knutson is retiring from the Board of Directors of the Company effective today. Mr. Knutson has served on the Board of Directors since 1997 and has provided valuable guidance, expertise and oversight since then. We would like to thank him for his 17 years of service to Bonavista and wish him all the best in the future. Bonavista previously announced the addition of Ms. Sue Lee as a member of the Board of Directors in November 2013 and is currently conducting a search for an additional director, which we expect to communicate at our next annual general meeting in May. We thank our employees and directors for their commitment and dedication to our strategy throughout the year and our shareholders for their trust and support. We firmly believe that we have the right people and assets required to execute our five year strategy with efficiency and precision. Our employees are the foundation of our continued success. On behalf of the Board of Directors Keith A. MacPhail Executive Chairman February 27, 2014 Calgary, Alberta Jason E. Skehar President and Chief Executive Officer 8 MANAGEMENT’S DISCUSSION AND ANALYSIS Management’s discussion and analysis (“MD&A”) of the financial condition and results of operations should be read in conjunction with Bonavista Energy Corporation’s (“Bonavista” or the “Corporation”) audited consolidated financial statements for the year ended December 31, 2013. The following MD&A of the financial condition and results of operations was prepared at, and is dated February 27, 2014. Basis of Presentation - The financial data presented below has been prepared in accordance with International Financial Reporting Standards ("IFRS"). For the purpose of calculating unit costs, natural gas is converted to a barrel of oil equivalent (“boe”) using six thousand cubic feet of natural gas equal to one barrel of oil unless otherwise stated. A boe may be misleading, particularly if used in isolation. A boe conversion of 6 Mcf to one barrel is based on an energy equivalent conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Forward-Looking Statements – Certain information set forth in this document, including management’s assessment of Bonavista’s future plans and operations, contains forward-looking statements including: (i) forecasted capital expenditures and plans; (ii) exploration, drilling and development plans; (iii) prospects and drilling inventory and locations; (iv) anticipated production rates; (v) anticipated operating and service costs; (vi) Bonavista’s 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 Bonavista’s 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, 2013 led to the drilling of 128 wells within its core regions and a success rate of 98%. This program resulted in 58 liquids rich natural gas wells and 68 oil wells. Bonavista's exploration and development program for the three months ended December 31, 2013, led to the drilling of 27 wells within Bonavista’s core region and a success rate of 100%. The program resulted in 18 liquids rich natural gas wells and 9 oil wells. Profitability continues to guide the exploration and development program which remains flexible to changes in commodity price, development risk and economic success. Aligned with Bonavista’s expectations, fourth quarter exploration and development programs have delivered solid rates of return and have reinforced management’s confidence in the deliverability and repeatability of Bonavista’s extensive drilling inventory. Reserves - Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure (“NI 51-101”). Of the net present value of the Corporation's reserves, 87% were evaluated by independent third-party engineers, GLJ Petroleum Consultants Ltd. ("GLJ") in their report dated February 20, 2014. The balance of approximately 13% 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, 2013 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. 9  Natural Gas (mmcf) Reserves:(1)(4) Proved: Proved producing Proved non-producing Proved undeveloped Total proved Probable Total proved plus probable Proved reserve life index (years)(3) Proved plus probable reserve life index (years)(3) 575,880 19,319 355,169 950,368 521,634 1,472,002 Light and Medium Oil (mbbls) Heavy Oil (mbbls) Natural Gas Liquids (mbbls) Total Reserves(2) (mboe) 21,450 720 4,914 27,085 11,733 38,818 3,153 431 266 3,851 2,109 5,959 34,250 984 31,652 66,886 41,532 108,418 154,833 5,356 96,028 256,216 142,313 398,529 9.1 13.2 (1) (2) (3) (4) Bonavista’s gross reserves are based on the GLJ reserve report dated February 20, 2014, GLJ reserve estimates based on forecast prices and costs as of January 1, 2014. Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Calculated based on the amount for the relevant reserve category divided by the 2014 production forecast prepared by GLJ. Amounts may not add due to rounding. Reserve Reconciliation:(1) Balance, December 31, 2012 Extensions and improved recovery Technical revisions Acquisitions Dispositions Economic factors Production Balance, December 31, 2013 Amounts may not add due to rounding. (1) Proved (mboe) 248,409 22,749 3,240 13,437 (4,750) (112) (26,755) 256,216 Probable (mboe) 123,811 19,198 (6,382) 7,027 (1,059) (283) - 142,313 Proved plus Probable (mboe) 372,220 41,946 (3,142) 20,464 (5,809) (396) (26,755) 398,529 Bonavista’s 2013 year-end proved reserves totaled 256.2 mmboe, a 3% increase compared to the 248.4 mmboe at year-end 2012. Furthermore, Bonavista’s proved plus probable reserves increased by 7% to 398.5 mmboe when compared to the 372.2 mmboe at year-end 2012. 10 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: Proved plus probable reserves (mboe):(1) Opening balance Discoveries and extensions Acquisitions and dispositions Revisions and economic factors Production Closing balance Operating netback ($/boe)(2) Operating netback ($/boe) three-year average(2) Finding and development expenditures: Total F&D expenditures (excluding changes in future development expenditures) ($millions) Proved plus probable F&D costs ($/boe)(3) F&D recycle ratio(4) Proved plus probable F&D three-year costs ($/boe)(3) F&D recycle ratio three-year average(4) Total F&D expenditures (including changes in future development expenditures) ($millions) Proved plus probable F&D costs ($/boe)(3) F&D recycle ratio(4) Proved plus probable F&D three-year costs ($/boe)(3) F&D recycle ratio three-year average(4) Finding, development and acquisition expenditures: Total FD&A expenditures (excluding changes in future development expenditures) ($millions) Proved plus probable FD&A costs ($/boe)(3) FD&A recycle ratio(4) Proved plus probable FD&A three-year costs ($/boe)(3) FD&A recycle ratio three-year average(4) 2013 2012 2011 372,220 41,946 14,655 (3,537) (26,755) 398,529 20.54 20.92 341,390 36,645 20,266 (844) (25,236) 372,220 17.70 22.03 310,749 33,667 22,402 (365) (25,063) 341,390 24.53 24.05 443.8 11.56 1.8 12.09 1.7 458.8 11.95 1.7 13.62 1.5 464.4 8.75 2.3 9.37 2.2 402.1 11.23 1.6 11.30 1.9 524.7 14.66 1.2 13.89 1.6 391.1 6.98 2.5 9.02 2.4 453.6 13.62 1.8 11.35 2.1 480.5 14.43 1.7 13.32 1.8 617.1 11.08 2.2 9.15 2.6 Total FD&A expenditures (including changes in future development expenditures) ($millions) Proved plus probable FD&A costs ($/boe)(3) FD&A recycle ratio(4) Proved plus probable FD&A three-year costs ($/boe)(3) FD&A recycle ratio three-year average(4) (1) (2) Operating netback is calculated using production revenues including realized gains and losses on financial instruments commodity contracts less royalties, transportation and operating costs 585.1 11.03 1.9 12.07 1.7 778.7 13.98 1.8 12.86 1.9 625.8 11.16 1.6 12.82 1.7 Amounts may not add due to rounding. calculated on a per barrel of oil equivalent basis. (3) (4) Both F&D and FD&A costs take into account reserve revisions during the year on a per barrel of oil equivalent basis (6:1). Recycle ratio is defined as operating netback per barrel of oil equivalent divided by either F&D or FD&A costs on a per barrel of oil equivalent. Bonavista demonstrated significant improvements in its recycle ratio delivering a ratio of 1.9:1 for proved plus probable reserves and 1.7:1 for proved reserves including revisions and changes in future development expenditures; excluding changes in future development expenditures, the proved plus probable recycle ratio improved to 2.3:1 and the proved recycle ratio remained at 1.8:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista’s Annual Information Form that will be filed on SEDAR. 11 Financial and operating highlights - The following is a summary of key financial and operating results for the respective periods noted: ($ thousands, except per boe and share amounts where noted) Three months ended December 31, 2013 2012 Years ended December 31, 2013 2012 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 and amortization per boe Net finance costs per boe Deferred income taxes per boe Net income per boe per share – basic Dividends declared per share Funds from operations per boe per share – basic 3.54 49.35 72.73 287 15,103 12,208 75,072 245,466 35.54 30,099 4.36 12.3% 60,601 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 38,904 0.21 124,354 18.00 0.62 3.22 42.60 75.73 269 14,563 12,395 71,842 223,021 33.74 29,650 4.49 13.3% 57,464 8.69 9,732 1.47 8,049 1.22 5,845 0.88 90,282 13.66 18,284 2.77 7,822 1.18 14,442 2.19 0.07 63,481 0.36 110,015 16.65 0.57 3.35 47.61 79.32 278 15,093 12,039 73,406 964,312 35.99 124,489 4.65 12.9% 239,196 8.93 36,595 1.37 30,802 1.15 23,868 0.89 349,285 13.04 94,709 3.53 24,043 0.90 49,505 1.85 0.25 152,968 0.84 477,578 17.82 2.42 2.60 45.19 77.30 253 14,074 12,997 69,250 832,491 32.85 124,300 4.90 14.9% 229,847 9.07 38,367 1.51 27,927 1.10 19,450 0.77 331,023 13.06 41,611 1.64 26,292 1.04 64,202 2.53 0.37 224,801 1.44 378,667 14.94 2.16 12 Production - For the year ended December 31, 2013, total production increased by 6% to 73,406 boe per day when compared to 69,250 boe per day for the same period a year ago. This increase in volumes is due to a highly productive exploration and development program coupled with the successful execution of Bonavista’s acquisition and divestiture strategy. Natural gas production increased by 10% to 278 mmcf per day for the year ended December 31, 2013 compared to 253 mmcf per day for the same period a year ago. Natural gas liquids production increased by 7% to 15,093 bbls per day in 2013 from 14,074 bbls per day for the same period in 2012, due in large part to Bonavista’s continued emphasis on drilling liquids rich natural gas wells. Oil production decreased by 7% to 12,039 bbls per day in 2013 from 12,997 bbls per day for the same period in 2012, due to a number of oil weighted property dispositions in late 2012 and throughout 2013. For the fourth quarter of 2013, total production increased by 4% to 75,072 boe per day when compared to 71,842 boe per day for the same period a year ago. Natural gas production increased by 7% to 287 mmcf per day in the fourth quarter of 2013 compared to 269 mmcf per day for the same period a year ago. Natural gas liquids production increased by 4% to 15,103 bbls per day in the fourth quarter of 2013 compared to 14,563 bbls per day for the same period in 2012. Oil production decreased by 2% to 12,208 bbls per day in the fourth quarter of 2013 from 12,395 bbls per day for the same period in 2012. Throughout the fourth quarter of 2013 Bonavista experienced a reduction in natural gas processing efficiency, at two of the major midstream facilities that handle our volumes, resulting in an unexpected loss of approximately 200 bbls per day of natural gas liquids production for the quarter. 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, 2013 287 15,103 12,208 75,072 2012 269 14,563 12,395 71,842 2013 278 15,093 12,039 73,406 2012 253 14,074 12,997 69,250 Bonavista’s current production is approximately 74,000 boe per day, net of dispositions of approximately 2,500 boe per day, completed in the first quarter of 2014. The Corporation’s current production consists of 65% natural gas, 21% natural gas liquids and 14% oil. Production revenues - Production revenues for the year ended December 31, 2013 increased by 16% to $964.3 million when compared to $832.5 million for the same prior year period, due to a 6% increase in production volumes and a 10% increase in revenues per boe. For the year ended December 31, 2013, natural gas prices increased by 29% to $3.35 per mcf, when compared to $2.60 per mcf realized in the same period in 2012. Natural gas liquids prices increased by 5% to $47.61 per bbl for the year ended December 31, 2013 from $45.19 per bbl for the same period in 2012. For the year ended December 31, 2013, oil pricing increased by 3% to $79.32 per bbl, compared to $77.30 per bbl for the same period a year ago. Production revenues for the fourth quarter of 2013 increased by 10% to $245.5 million when compared to $223.0 million for the same period a year ago, due to a 4% increase in production volumes and a 5% increase in revenues per boe. For the three months ended December 31, 2013, natural gas prices increased by 10% to $3.54 per mcf, when compared to $3.22 per mcf realized in the same period in 2012. Natural gas liquids pricing increased by 16% to $49.35 per bbl for the three months ended December 31, 2013 from $42.60 per bbl for the same period in 2012. For the three months ended December 31, 2013, oil pricing decreased by 4% to $72.73 per bbl, compared to $75.73 per bbl for the same period a year ago. 13 The following table highlights Bonavista's realized commodity pricing for the three months and year ended December 31: Natural gas ($/mcf): Production revenues Realized gains (losses) on financial instrument commodity contracts Natural gas liquids ($/bbl): Production revenues Oil ($/bbl): Production revenues Realized gains (losses) on financial instrument commodity contracts Total ($/boe): Production revenues Realized gains (losses) on financial instrument commodity contracts Three months ended December 31, 2013 2012 Years ended December 31, 2013 2012 $ 3.50 $ 3.28 $ 3.35 $ 0.04 3.54 49.35 49.35 75.21 (2.48) 72.73 35.54 (0.26) (0.06) 3.22 42.60 42.60 74.25 1.48 75.73 33.74 0.03 - 3.35 47.61 47.61 82.51 (3.19) 79.32 35.99 (0.51) $ 35.28 $ 33.77 $ 35.48 $ 2.52 0.08 2.60 45.19 45.19 76.93 0.37 77.30 32.85 0.34 33.19 Risk management activities - As part of Bonavista’s financial management strategy, the Corporation has adopted a disciplined commodity price risk management program. The purpose of this program is to stabilize funds from operations against volatile commodity prices and to protect acquisition economics. Bonavista’s Board of Directors has approved a commodity price risk management limit of 70% for 2014 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 in which an executed hedge is made. We primarily use swaps and costless collars which limits Bonavista’s exposure to volatility in commodity prices, while in the case of costless collars allows for participation in commodity price increases. For the year ended December 31, 2013, the 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 contracts and a $14.0 million loss on oil commodity contracts. For the same period in 2012, the risk management program on financial instrument commodity contracts resulted in a gain of $16.8 million, consisting of a realized gain of $8.6 million and an unrealized gain of $8.2 million. The realized gain of $8.6 million consisted of a $6.8 million gain on natural gas commodity contracts and a $1.8 gain on oil commodity contracts. For the fourth quarter of 2013, the risk management program on financial instrument commodity contracts resulted in a loss of $24.5 million, consisting of a realized loss of $1.8 million and an unrealized loss of $22.7 million. The realized loss of $1.8 million was the result of a loss of $2.8 million on oil commodity contracts, offset by a gain of $1.0 million on natural gas commodity contracts. For the same period in 2012, the risk management program on financial instrument commodity contracts resulted in a loss of $2.6 million, consisting of a realized gain of $204,000 and an unrealized loss of $2.8 million. The realized gain of $204,000 was the result of a gain of $1.7 million on oil commodity contracts, offset by a loss of $1.5 million on natural gas commodity contracts. Commodity price risk is the risk that future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand, but also by the relationship between the Canadian and United States dollar. 14 i) Financial instrument commodity contracts: As at December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume Average Price Term 5,000 40,000 15,000 15,000 10,000 20,000 8,000 3,500 500 gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d bbls/d bbls/d bbls/d CDN $3.50 - CDN $4.00 - AECO CDN $2.93 - CDN $3.73 - AECO CDN $3.33 - CDN $4.09 - AECO CDN $3.38 - CDN $3.95 - AECO CDN $2.85 - CDN $3.50 - AECO CDN $3.53 - CDN $4.02 - AECO CDN $89.78 - CDN $98.65 - WTI CDN $88.36 - CDN $98.09 - WTI CDN $87.50 - CDN $97.50 - WTI January 1, 2014 - March 31, 2014 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 April 1, 2014 - October 31, 2014 January 1, 2015 - December 31, 2015 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 January 1, 2015 - December 31, 2015 Subsequent to December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume 10,000 5,000 25,000 Average Price Term gjs/d gjs/d gjs/d CDN $3.50 - CDN $3.75 - AECO CDN $3.50 - CDN $4.00 - AECO CDN $3.50 - CDN $3.87 - AECO April 1, 2014 - October 31, 2014 November 1, 2014 - March 31, 2015 January 1, 2015 - December 31, 2015 As at December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume 55,000 10,000 5,000 5,000 40,000 5,000 5,000 25,000 15,825 26,375 35,000 5,000 500 gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d bbls/d Price CDN $3.45 CDN $3.52 CDN $3.35 CDN $3.48 CDN $3.63 CDN $3.49 CDN $3.71 CDN $3.53 US $3.62 US $3.80 US $(0.48) US $(0.48) US 50% Contract Term January 1, 2014 - December 31, 2014 Swap - AECO January 1, 2014 - December 31, 2015 Swap - AECO Swap - AECO January 1, 2014 - March 31, 2014 Swap - AECO April 1, 2014 - October 31, 2014 Swap - AECO April 1, 2014 - December 31, 2014 Swap - AECO April 1, 2014 - March 31, 2015 Swap - AECO November 1, 2014 - March 31, 2015 Swap - AECO January 1, 2015 - December 31, 2015 April 1, 2014 - October 31, 2014 Swap - NYMEX Swap - NYMEX April 1, 2014 - December 31 2014 Swap - NYMEX Basis April 1, 2014 - December 31, 2014 Swap - NYMEX Basis November 1, 2014 - December 31, 2014 Swap - CNWY/WTI April 1, 2014 - March 31, 2015 Subsequent to December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume 10,000 75,000 1,000 gjs/d gjs/d bbls/d Price CDN $3.90 CDN $3.73 US 51% Contract Term Swap - AECO Swap - AECO Swap - CNWY/WTI April 1, 2014 - October 31, 2014 January 1, 2015 - December 31, 2015 April 1, 2014 - March 31, 2015 As at December 31, 2013, Bonavista also entered into the following contracts to purchase electricity: Volume Mwh 6 2 Mwh Price CDN $50.88 CDN $52.00 Contract Swap - AESO Swap - AESO Term January 1, 2014 - December 31, 2015 January 1, 2016 - December 31, 2016 15 Financial instrument commodity contracts are recorded on the consolidated statements of financial position at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statements of income and comprehensive income. As at December 31, 2013, the fair market value recorded on the consolidated statement of financial position for these financial instrument commodity contracts was a net liability of $34.9 million (2012 - $504,000). These financial instrument commodity contracts had the following gains and losses reflected in the consolidated statements of income and comprehensive income: 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, 2013 2012 2013 2012 $ (1,769) $ 204 $(13,652) $ 8,851 (22,742) $ (24,511) $ (2,793) (2,589) (34,426) 8,210 $(48,078) $ 16,791 A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $6.8 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2013 (2012 - $3.5 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of approximately $3.5 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2013 (2012 - $1.6 million). Royalties - Royalties for the year ended December 31, 2013 were consistent at $124.5 million as compared to $124.3 million for the year ended December 31, 2012, while production volumes increased by 6% over the same period. Royalties as a percentage of revenues for 2013 decreased to 12.9% compared to 14.9% in the same period in 2012. The decrease in royalties as a percentage of revenues is largely the result of natural gas revenues, which attract a lower royalty rate, comprising a larger percentage of the overall total revenues. For the three months ended December 31, 2013, royalties increased slightly to $30.1 million from $29.7 million for the same period a year ago. Royalties as a percentage of revenues for the fourth quarter of 2013 decreased to 12.3% when compared to 13.3% for the same period in 2012 due to the reasons stated above. The following table highlights Bonavista's royalties by product for the three months and year ended December 31: Natural gas ($/mcf): Royalties % of revenues Natural gas liquids ($/bbl): Royalties % of revenues Oil ($/bbl): Royalties % of revenues Total ($/boe): Royalties % of revenues Three months ended December 31, 2013 2012 0.19 5.5% 9.51 19.3% 10.55 14.0% 4.36 12.3% 0.20 6.1% 9.43 22.1% 10.57 14.2% 4.49 13.3% Years ended December 31, 2013 0.19 5.7% 9.78 20.5% 11.63 14.1% 4.65 12.9% 2012 0.17 6.6% 10.00 22.1% 12.06 15.7% 4.90 14.9% Operating expenses - Operating expenses for the year ended December 31, 2013 increased by 4% to $239.2 million compared to $229.8 million for the same period in 2012 and on a per boe basis decreased by 2% to $8.93 per boe, from $9.07 per boe for the same period in 2012. On a per boe basis, operating costs decreased by 2% year over year as a result of a 6% increase in production volumes, disciplined cost control, the realization of cost efficiencies within Bonavista’s core areas and the disposition of higher cost non-core assets. For the three months ended December 31, 2013 operating expenses increased by 5% to $60.6 million compared to $57.5 million for the same period a year ago. On a per boe basis operating expenses were relatively unchanged at $8.77 per boe and $8.69 per boe for the three months ended December 31, 2013 and 2012, respectively. Absolute operating expenses increased during the three months ended December 31, 2013 when compared to the same period in 2012, largely as a result of increases in fluid hauling costs associated with Bonavista’s new oil volumes, increased road maintenance due to significant snowfall, as well as an increase in costs for field staff to support growth in production 16 volumes. These increases were partially offset by a reduction in average fourth quarter utility rates and lower third-party processing fees. The following table highlights Bonavista's operating expenses by product for the three months and year ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31, Years ended December 31, $ 2013 1.18 10.71 13.08 $ $ 8.77 $ 2012 1.15 10.94 12.57 8.69 $ $ 2013 1.20 10.93 12.96 8.93 2012 1.23 10.90 12.59 9.07 $ $ Transportation expenses - For the year ended December 31, 2013, transportation expenses decreased by 5% to $36.6 million compared to $38.4 million for the same period in 2012. For the year ended December 31, 2013, transportation costs on a per boe basis have decreased 9% to $1.37 per boe from $1.51 per boe in the same period in 2012. The decrease in absolute and per boe transportation expenses for the year ended December 31, 2013 when compared to the same 2012 period, is the result of changes in the terms of natural gas liquids contracts effective April 1, 2013. The decrease in natural gas liquids transportation expenses was partially offset by an increase in average oil transportation rates resulting from pipeline capacity constraints causing Bonavista to use alternative means of transportation to move production volumes to market. For the three months ended December 31, 2013, transportation expenses decreased by 5% to $9.2 million compared to $9.7 million for the same period in 2012. For the three months ended December 31, 2013, transportation costs on a per boe basis decreased by 10% to $1.33 per boe, compared to $1.47 per boe in the same period in 2012. The decrease in absolute transportation expenses and on a per boe basis for the three months ended December 31, 2013, is due to similar reasons as stated above. The following table highlights Bonavista’s transportation costs by product for the three months and years ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31, Years ended December 31, 2013 0.26 0.15 1.99 1.33 $ $ 2012 0.26 0.89 1.91 1.47 $ $ $ $ 2013 0.25 0.34 2.07 1.37 2012 0.26 0.87 1.99 1.51 $ $ General and administrative expenses - General and administrative expenses, after overhead recoveries, increased by 10% to $30.8 million for the year ended December 31, 2013 from $27.9 million in the same period in 2012 and increased by 4% to $8.4 million for the three months ended December 31, 2013 from $8.0 million in the same period in 2012. On a per boe basis, general and administrative expenses increased by 5% to $1.15 per boe for the year ended December 31, 2013 from $1.10 per boe in the same period in 2012 and decreased by 1% for the three months ended December 31, 2013 to $1.21 per boe from $1.22 per boe in the same period in 2012. The increase in general and administrative expenses in the fourth quarter and year ended December 31, 2013, when compared to the same periods in 2012 is largely due to higher staffing levels required to manage Bonavista’s growing business. Even with the recent increases in general and administrative expenses, Bonavista’s current rate of general and administrative expenses on a per boe basis remains competitive in its sector. In relation to the stock option and common share rights incentive plans and restricted share award and restricted common share incentive plans, Bonavista recorded a share-based compensation charge of $5.8 million and $23.9 million for the three months and year ended December 31, 2013, respectively, compared to $5.8 million and $19.5 million for the same periods in 2012. Depletion, depreciation and amortization expenses - Depletion, depreciation and amortization expenses increased by 6% to $349.3 million for the year ended December 31, 2013 from $331.0 million for the same period in 2012. The increase in depletion, depreciation and amortization expenses year over year is related to a 6% increase in production volumes offset by slightly lower costs related to finding, developing and acquiring reserves. For the three months ended December 31, 2013, depreciation, depletion and amortization expenses increased slightly to $90.8 million from $90.3 million for the same period in 2012 largely due to a 4% increase in production volumes offset by an overall decrease in costs related to finding, developing and acquiring reserves. On a per boe basis for the year ended December 31, 2013, the average charge remained relatively unchanged at $13.04 per boe compared to $13.06 per boe 17 for the same period in 2012 and for the three months ended December 31, 2013, the average charge decreased by 4% to $13.15 per boe from $13.66 per boe for the same period a year ago. Net financing costs - Net financing costs increased 128% to $94.7 million for the year ended December 31, 2013 from $41.6 million for the same period in 2012, mainly due to foreign exchange losses associated with the revaluation of Bonavista’s US denominated senior unsecured notes. For the year ended December 31, 2013, net financing costs increased 115% to $3.53 per boe from $1.64 per boe for the same period in 2012. Net financing costs, excluding non- cash amounts, increased 3% to $42.0 million for the year ended December 31, 2013, as compared to $40.9 for the year ended December 31, 2012. For the three months ended December 31, 2013, net financing costs, excluding non-cash amounts, on a per boe basis decreased 2% to $1.57 per boe compared to $1.61 per boe in the same period in 2012. For the three months ended December 31, 2013, net financing costs increased 102% to $37.0 million from $18.3 million for the same period in 2012, due to similar reasons as stated above. For the three months ended December 31, 2013, net financing costs on a per boe basis increased 93% to $5.35 per boe compared to $2.77 per boe for the same period in 2012. Net financing costs, excluding non-cash amounts, increased 17% to $11.1 million for the three months ended December 31, 2013, as compared to $9.5 million for the three months ended December 31, 2012 due to higher average debt outstanding. For the three months ended December 31, 2013, net financing costs, excluding non-cash amounts, on a per boe basis increased 11% to $1.60 per boe compared to $1.44 per boe in the same period in 2012 for the same reasons as described above. As part of the financial management program, Bonavista mitigates its currency risk associated with its repayment of its US senior unsecured notes by utilizing foreign exchange forward contracts. In the third quarter of 2011, Bonavista entered into the following foreign exchange forward contracts to manage its currency risk associated with its repayment of its US senior unsecured notes: Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US purchased forward US purchased forward US purchased forward Notional US$ $30,000,000 $53,300,000 $16,500,000 CDN$/US$ 0.995 0.995 0.995 As at December 31, 2013, the fair market value recorded on the consolidated statement of financial position for those financial instrument contracts was a long-term asset of $8.0 million (2012 – $4.3 million). A $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $709,000 on net income for those foreign exchange forward contracts in place as at December 31, 2013 (2012 - $655,000). Deferred income taxes - The provision for deferred income taxes for the year ended December 31, 2013, was $24.0 million compared to $26.3 million during the same period in 2012. For the three months ended December 31, 2013 the deferred income tax provision was $1.2 million compared to a provision of $7.8 million during the same period in 2012. The deferred income tax provision for the year ended December 31, 2013 is higher than the provision calculated using the current statutory rate. This is mainly due to the income tax treatment of foreign currency translation losses on long-term debt and non-deductible share-based compensation, offset by the income tax treatment of the disposition of a capital asset. Bonavista made no cash payments or tax installments for the three months and year ended December 31, 2013 or for the comparative periods in 2012. Funds from operations, net income and comprehensive income - For the year ended December 31, 2013, Bonavista experienced a 26% increase in funds from operations to $477.6 million ($2.42 per share, basic) from $378.7 million ($2.16 per share, basic) for the same period in 2012, mainly due to a 10% increase in product prices, cash cost reductions of 2% and a 6% increase in production volumes. For the three months ended December 31, 2013, Bonavista experienced a 13% increase in funds from operations to $124.4 million ($0.62 per share, basic) from $110.0 million ($0.57 per share, basic) for the same period in 2012, due to higher product prices and a 4% increase in production volumes. Net income and comprehensive income for the year ended December 31, 2013, decreased 23% to $49.5 million ($0.25 per share, basic) from $64.2 million ($0.37 per share, basic) for the same period in 2012, due largely to foreign exchange losses on the revaluation of Bonavista’s US denominated senior unsecured notes. Net income and comprehensive income for the three months ended December 31, 2013, was $6.7 million ($0.03 per share, basic) compared to $14.4 million ($0.07 per share, basic) for the same period in 2012, largely due to the same reasons described above. 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: (thousands) Cash flow from operating activities Interest expense Decommissioning expenditures Changes in non-cash working capital Three months ended December 31, Years ended December 31, 2013 2012 2013 2012 $ 115,021 (11,076) 10,539 9,870 $ 102,886 (9,487) 11,410 5,206 $ 486,605 (42,000) 30,143 2,830 $ 407,481 (40,878) 25,530 (13,466) Funds from operations $ 124,354 $ 110,015 $ 477,578 $ 378,667 Capital expenditures - Net capital expenditures for the year ended December 31, 2013 were $470.5 million, consisting of $443.8 million spent on exploration and development activities, $131.4 million spent on property acquisitions, property dispositions of $110.9 million and head office expenditures of $6.2 million. For the same period in 2012, net capital expenditures were $394.4 million, consisting of $402.1 million spent on exploration and development activities, $169.9 million spent on acquisitions, property dispositions of $180.8 million and head office expenditures of $3.3 million. Net capital expenditures for the three months ended December 31, 2013 were $118.5 million, consisting of $111.6 million spent on exploration and development activities, $45.1 million spent on property acquisitions, property dispositions of $40.3 million and head office expenditures of $2.1 million. For the same period in 2012, net capital expenditures were $196.5 million, consisting of $76.9 million spent on exploration and development activities, $164.8 million spent on property acquisitions, property dispositions of $45.9 million and head office expenditures of $704,000. The following table outlines capital expenditures by category for the three months and years ended December 31: (thousands) Land acquisitions Geological and geophysical Drilling and completion Production equipment and facilities Exploration and development expenditures Cash used for business and property acquisitions Cash received on dispositions Head office expenditures Three months ended December 31, 2013 $ 11,952 1,544 72,412 25,688 $ 2012 2,099 1,921 56,842 16,075 Years ended December 31, 2013 2012 $ 24,825 13,780 308,354 96,870 $ 14,520 13,557 295,406 78,607 $ 111,596 $ 76,937 $ 443,829 $ 402,090 32,231 (27,416) 2,066 164,757 (45,920) 704 118,559 (98,029) 6,183 169,891 (180,848) 3,307 Net capital expenditures $ 118,477 $ 196,478 $ 470,542 $ 394,440 Liquidity and capital resources – As at December 31, 2013 Bonavista’s 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 annualized funds from operations ratio of 2.1:1. Bonavista’s long-term debt consists of both bank debt and senior unsecured notes. As at December 31, 2013 Bonavista’s bank debt, including working capital, was $307.3 million with a weighted average interest rate of 3.1% (2012 – 3.1%) and a current maturity date of September 10, 2016. As at December 31, 2013 Bonavista had approximately $367.8 million of unused borrowing capacity on its $600 million bank credit facility. Bonavista’s senior unsecured notes totaled $816.9 million as at December 31, 2013 which consisted of US$705 million (CDN$746.9 million) and CDN$70 million with a fixed weighted average interest rate of 4.1% (2012-4.2%). The maturity dates on the senior unsecured notes range from November 2, 2015 to May 23, 2025 with approximately CDN$618 million due between 2020 and 2025 with interest rates ranging from 3.68% and 4.47%. This long-term, low cost debt is mainly US dollar denominated of which, US$100 million has been hedged using foreign exchange contracts. In addition to using foreign exchange contracts to hedge against the US denominated debt exposure, Bonavista’s revenue stream is naturally hedged as North American crude oil and natural gas benchmark prices are denominated in US dollars. On April 12, 2013, Bonavista agreed to increase 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 19 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. On May 23, 2013, Bonavista issued the following senior unsecured notes by way of 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 issued by private placement are summarized below: Issued Date May 23, 2013 May 23, 2013 May 23, 2013 Principal US $85 million CDN $20 million US $20 million Coupon Rate 3.68% 4.09% 3.78% Maturity Date May 23, 2023 May 23, 2023 May 23, 2025 Bonavista is in compliance with all of the covenants under both its bank credit facilities and its senior unsecured notes. For 2014, Bonavista plans to invest between $460 and $500 million on its capital program within its core regions, which is comprised of an exploration and development program between $560 and $600 million and dispositions of approximately $100 million. Bonavista intends on financing this capital program with a combination of funds from operations, its dividend reinvestment and stock dividend plans and to the extent required its existing bank credit facility. Bonavista remains committed to the fundamental principle of maintaining financial flexibility and the prudent use of debt. Shareholders’ equity - As at December 31, 2013, Bonavista had 199.9 million equivalent common shares outstanding. This includes 10.7 million exchangeable shares, which are exchangeable into 12.9 million common shares. The exchange ratio in effect at December 31, 2013 for exchangeable shares was 1.20836:1. As at February 27, 2014, Bonavista had 201.1 million equivalent common shares outstanding. This includes 10.4 million exchangeable shares, which are exchangeable into 12.7 million common shares. The exchange ratio in effect at February 27, 2014 for exchangeable shares was 1.22019:1. In addition, Bonavista has 7.8 million stock option and common share incentive rights outstanding as at February 27, 2014, with an average exercise price of $19.63 per common share. Dividends - For the year ended December 31, 2013, Bonavista declared dividends of $153.0 million ($0.84 per share) compared to $224.8 million ($1.44 per share) in the same period in 2012. For the three months ended December 31, 2013, Bonavista declared dividends of $38.9 million ($0.21 per share) compared to $63.5 million ($0.36 per share) in the same period in 2012. Bonavista announces its dividend policy on a quarterly basis and confirms its dividend payment on a monthly basis. Dividends are approved by the Board of Directors and are dependent upon the commodity price environment, production levels, and the amount of capital expenditures to be financed from funds from operations. As such, on January 9, 2013, Bonavista announced a reduction in the monthly dividend from $0.12 per share to $0.07 per share. Although numerous initiatives had been employed throughout 2012 to preserve the prior dividend, the forward commodity prices did not allow for these activities to continue under Bonavista’s growth plus dividend business model. The long-term goal of Bonavista’s business model remains intact with a commitment to generate an attractive return to shareholders through a sustainable balance between dividends and corporate growth. Distributing between 25% and 35% 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. 20 Annual financial information - The following table highlights selected annual financial information for each of the three years ended December 31, 2013, 2012 and 2011: Years ended December 31, 2013 2012 2011 (thousands, except per share amounts) Consolidated Statement of Income and Comprehensive Income Information: Production revenues, net of royalties Funds from operations Per share – basic Per share – diluted Net income Per share – basic Per share – diluted Consolidated Statement of Financial Position Information: Net capital expenditures Total assets Working capital deficiency Long-term debt Shareholders’ equity Dividends declared $ 839,823 477,578 2.42 2.40 49,505 0.25 0.25 $ 708,191 378,667 2.16 2.14 64,202 0.37 0.36 $ 882,672 553,303 3.44 3.42 137,184 0.85 0.85 $ 470,542 4,235,626 (109,587) 1,046,177 2,270,015 152,968 $ 394,440 4,062,852 (74,607) 889,071 2,285,889 224,801 $ 617,071 3,924,160 (51,110) 1,080,605 2,001,802 200,032 Quarterly financial information - The following table highlights Bonavista’s performance for the eight quarterly periods ending on March 31, 2012 to December 31, 2013: Production revenues Net income (loss) Basic Diluted December 31 September 30 June 30 245,466 6,667 0.03 0.03 246,413 22,950 0.12 0.11 244,940 23,107 0.12 0.12 March 31 227,493 (3,219) (0.02) (0.02) December 31 September 30 188,610 2,484 0.01 0.01 223,021 14,442 0.07 0.07 June 30 March 31 193,826 3,553 0.02 0.02 227,034 43,723 0.26 0.26 2013 2012 Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and changes in production volumes. Net income in the past eight quarters has fluctuated from a deficit of $3.2 million in the first quarter of 2013 to a high of $43.7 million in the first quarter of 2012. These fluctuations are primarily influenced by production volumes; commodity prices; realized and unrealized gains and losses on financial instrument commodity contracts; gains and losses on foreign exchange; and future income tax recoveries associated with the reduction in corporate income tax rates. Disclosure controls and procedures - Disclosure controls and procedures have been designed to ensure that information to be disclosed by Bonavista is accumulated and communicated to management, as appropriate, to allow timely decisions regarding required disclosures. The Chief Executive Officer and Chief Financial Officer have concluded, as of the end of the period covered by the interim and year end filings, that Bonavista’s disclosure controls and procedures are appropriately designed and operating effectively to provide reasonable assurance that material information relating to the issuer is made known to them by others within the Corporation. Internal control over financial reporting - Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system is met. Management has reporting as defined by assessed National Instrument 52-109, Certification of Disclosure in Issuers’ Annual and Interim Filings. Management’s assessment was based on the framework in Internal Control – Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management has concluded that their internal control over financial reporting was effective as of December 31, 2013. There were no changes made to Bonavista’s internal controls over financial reporting during the year ended December 31, 2013. the effectiveness of Bonavista’s internal control over financial 21 Changes in accounting policies – On January 1, 2013, Bonavista adopted the following new standards and amendments which became effective for annual periods on or after January 1, 2013: • • • • IFRS 10, “Consolidated Financial Statements,” supersedes IAS 27 “Consolidated and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities. The adoption of this standard had no impact on the amounts recorded in Bonavista’s financial statements. IFRS 11, “Joint Arrangements,” whereby joint arrangements are classified as either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting. The adoption of this standard had no impact on the amounts recorded in Bonavista’s financial statements. IFRS 12, “Disclosure of Interest in Other Entities,” combines the disclosure requirements for entities that have interest in subsidiaries, joint arrangements, and associates as well as unconsolidated structured entities. The adoption of this standard had no impact on Bonavista’s financial statements. IFRS 13, “Fair Value Measurement,” establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard also requires additional annual fair value disclosures, as well as additional interim disclosures. The adoption of this standard had no material impact on Bonavista’s financial statements. • Amendments to IAS 32, “Financial Instruments: Presentation” clarify the requirements for offsetting financial assets with financial liabilities. Amendments to IFRS 7, "Financial Instruments: Disclosures," develop common disclosure requirements for financial assets and financial liabilities that are offset in the financial statements, or that are subject to enforceable master netting arrangements or similar agreements. The adoption of these amendments has no impact on Bonavista's financial statements. Future accounting policies – In May 2013, the IASB issued amendments to IAS 36, “Impairment of Assets” which will restrict the requirements to disclose the recoverable amount of an asset or CGU to periods in which an impairment loss has been recognized or reverses. The amendment also expands and clarifies the disclosure requirements applicable when an impairment loss has been recognized or reversed in the period. The amendments apply retrospectively for annual periods beginning on or after January 1, 2014. Bonavista plans to adopt the amendments in its financial statements for the annual period beginning on January 1, 2014. The adoption will impact Bonavista’s disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized. In May 2013, the IASB issued IFRIC 21, “Levies” which provides guidance on accounting for levies in accordance with the requirements of IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”. The interpretation clarifies that an entity is to recognize a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that a levy liability is to be accrued progressively only if the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. IFRIC 21 is effective for annual period commencing on or after January 1, 2014 and is to be applied retrospectively. Bonavista intends to adopt IFRIC 21 in its financial statements for the annual periods beginning on January 1, 2014. Bonavista is currently assessing but has not yet determined the impact of the adoption of the amendments. In November 2013, the IASB issued amendments to the recognition, presentation and disclosure to pension accounting under IAS 19, “Employee Benefits”. The amendments apply retrospectively for annual periods beginning on or after July 1, 2014. Bonavista intends to adopt these amendments in its financial statements for the annual period beginning on January 1, 2014, no impact to the financial statements is expected. In November 2009 the IASB issued IFRS 9, “Financial Instruments” as the first step in its project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. IFRS 9 introduced new requirements for classifying and measuring financial assets. On October 28, 2010, the IASB reissued IFRS 9, incorporating new requirements on accounting for financial liabilities. The new standard eliminates the existing multiple classification and measurement categories under IAS 39 of held-to-maturity, available-for-sale and loans receivable and replaces them with a single model that has only two classification categories: amortized cost and fair value. 22 In November 2013, the IASB issued a new general hedge accounting standard which forms part of IFRS 9. While hedge accounting remains optional under IFRS 9, the new general hedge accounting statement was designed to more closely align hedge accounting with the risk management activities of an entity. The new standard does not fundamentally change the types of hedging relationships or the requirements to measure and recognize ineffectiveness, however, it does provide for more hedging strategies to qualify for hedge accounting and introduces more judgment into the assessment of hedge effectiveness. In July of 2013, the IASB deferred the mandatory effective date of IFRS 9, which previously had been effective for annual periods beginning on or after January 1, 2015. The IASB has yet to determine the mandatory effective date; early adoption of the new standard is still permitted. The extent of the impact of the adoption of IFRS 9 on Bonavista’s financial statements has not yet been determined. In December 2013, the IASB issued narrow-scope amendments to a total of nine standards as part of its annual improvement process. The improvement process is designed to make non-urgent but necessary amendments to IFRS. Some of the amendments made to the existing standards included; clarifying the definition of “vesting conditions” in IFRS 2, “Share-based payment”; defining the classification and measurement of contingent consideration; scope exclusion for the formation of joint arrangements in IFRS 3, “Business Combinations”; and modifying the definition of a “related party” in IAS 24, “Related Party Disclosures”. Bonavista intends to adopt these amendments in its financial statement for the annual period beginning on January 1, 2014. The adoption of these amendments is not expected to have a material impact on the financial statements. Significant accounting judgments and 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. • 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. As at December 31, 2013 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. For the year ended December 31, 2013 the following benchmark reference prices were used by Bonavista’s independent reserve evaluator and adjusted for commodity differentials specific to the Corporation. Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Remainder (1) (1) WTI Oil (US$/bbl) 97.50 97.50 97.50 97.50 97.50 97.50 98.54 100.51 102.52 104.57 2.0% AECO Gas (CDN$/mmbtu) 4.03 4.26 4.50 4.74 4.97 5.21 5.33 5.44 5.55 5.66 2.0% CDN$/US$ Exchange Rates 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 Percentage change represents the change in each year after 2023 to the end of the reserve life. For the years ended December 31, 2013 and December 31, 2012 no impairment was recognized. In addition, the recoverable amount of the CGU to which Bonavista’s goodwill is allocated continues to support the carrying amount of the goodwill. • 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 23 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 capital expenditures incurred to date along with future development capital required to develop both proved plus probable reserves. • Decommissioning liabilities - The provision for decommissioning liabilities is based on estimates of costs and planned remediation projects. Actual costs may differ from those estimated due to changes in governing environment laws and regulations, technological changes, and market conditions. • 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. 24 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 27, 2014 Calgary, Alberta 25 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, 2013 and December 31, 2012, 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, 2013 and December 31, 2012, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards. Chartered Accountants Calgary, Canada February 27, 2014 26 BONAVISTA ENERGY CORPORATION Consolidated Statements of Financial Position (thousands) Assets: Current assets: Accounts receivable Prepaid expenses Marketable securities Other assets Financial instrument commodity contracts Financial instrument commodity contracts Financial instrument contracts Property, plant and equipment Exploration and evaluation assets Goodwill Liabilities and Shareholders’ Equity: Current liabilities: December 31, December 31, Notes 2013 2012 $ 124,431 $ 102,500 7,322 2,645 13,786 419 148,603 346 8,023 11,089 2,768 12,191 8,608 137,156 1,224 4,293 3,845,344 3,691,572 222,085 11,225 217,382 11,225 $ 4,235,626 $ 4,062,852 (4) (4) (8) (9) (9) Accounts payable and accrued liabilities $ 213,118 $ 181,674 Decommissioning liabilities Dividends payable Financial instrument commodity contracts Financial instrument commodity contracts Long-term debt Other long-term liabilities Decommissioning liabilities Deferred income taxes Shareholders’ equity: Shareholders’ capital Exchangeable shares Contributed surplus Deficit Commitments (4) (4) (12) (13) (14) (11) (15) 9,313 13,087 31,985 267,503 3,710 1,046,177 13,853 397,174 237,194 - 21,303 8,786 211,763 1,550 889,071 13,650 447,753 213,176 2,228,210 2,059,305 307,468 61,247 (326,910) 405,183 44,848 (223,447) 2,270,015 2,285,889 $ 4,235,626 $ 4,062,852 See accompanying notes to the consolidated financial statements. Approved on behalf of the Board of Directors of Bonavista Energy Corporation: Ian S. Brown, Director Michael M. Kanovsky, Director 27 BONAVISTA ENERGY CORPORATION Consolidated Statements of Income and Comprehensive Income Years ended December 31, (thousands, except per share amounts) Revenues: Production Royalties Realized gains (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 Notes 2013 2012 $ 964,312 $ 832,491 (124,489) (124,300) 839,823 708,191 (13,652) (34,426) 8,581 8,210 (48,078) 16,791 791,745 724,982 239,196 229,847 36,595 30,802 23,868 (38,115) (18,143) 38,367 27,927 19,450 (59,675) 5,938 Depletion, depreciation and amortization (8) 349,285 331,023 Income from operating activities Finance costs Finance income Net finance costs Income before taxes Deferred income taxes Net income and comprehensive income Net income per share – basic Net income per share – diluted See accompanying notes to the consolidated financial statements. 623,488 592,877 168,257 98,439 132,105 53,350 (3,730) (11,739) 94,709 41,611 73,548 24,043 90,494 26,292 $ 49,505 $ 64,202 $ $ 0.25 $ 0.37 0.25 $ 0.36 (6) (6) (14) (11) (11) 28 BONAVISTA ENERGY CORPORATION Consolidated Statements of Changes in Equity For the years ended December 31, Shareholders’ capital Exchangeable shares Contributed surplus Total shareholders’ equity Deficit (thousands) Balance as at December 31, 2012 $ 2,059,305 $ 405,183 $ 44,848 $ (223,447) $ 2,285,889 Net income Issue costs, net of future tax benefit Issued for cash on exercise of common share incentive rights Exercise of common share incentive rights Conversion of restricted share awards Share-based compensation expense Share-based compensation capitalized Issued pursuant to the dividend reinvestment and stock dividend plans Exchangeable shares exchanged for common shares Dividends declared - (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 Balance as at December 31, 2011 $ 1,446,804 $ 585,754 $ 32,092 $ (62,848) $ 2,001,802 Net income Issuance of equity, net of issue costs Issued for cash on exercise of common share incentive rights Exercise of common share incentive rights Conversion of restricted share awards Share-based compensation expense Share-based compensation capitalized Issued pursuant to the dividend reinvestment and stock dividend plans Exchangeable shares exchanged for common shares Dividends declared - 334,736 4,510 4,609 5,183 - - 82,892 - - - - - - - - 180,571 (180,571) - - - - - (4,609) (5,183) 20,070 2,478 - - - 64,202 64,202 - - - - - - - - 334,736 4,510 - - 20,070 2,478 82,892 - (224,801) (224,801) Balance as at December 31, 2012 $ 2,059,305 $ 405,183 $ 44,848 $ (223,447) $ 2,285,889 See accompanying notes to the consolidated financial statements. 29 BONAVISTA ENERGY CORPORATION Consolidated Statements of Cash Flows Years ended December 31, (thousands) Cash provided by (used in): Operating Activities: Net income Adjustments for: Depletion, depreciation and amortization 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 Financing Activities: Issuance of senior notes Issuance of equity, net of issue costs Proceeds on exercise of common share incentive rights Dividends paid Interest paid Proceeds from long-term debt Repayment of long-term debt Investing Activities: Business acquisitions Exploration and development Property and other business acquisitions Property dispositions Office equipment Changes in non-cash working capital items (7) Changes in non-cash working capital items (7) Change in cash Cash, beginning of year Cash, end of year See accompanying notes to the consolidated financial statements. Notes 2013 2012 $ 49,505 $ 64,202 (8) 349,285 23,868 331,023 18,364 34,426 (8,210) (38,115) (59,675) (18,143) 94,709 24,043 (30,143) (2,830) 5,938 41,611 26,292 (25,530) 13,466 486,605 407,481 229,226 - (99) 331,188 1,984 4,510 (102,022) (137,898) (40,793) 119,791 (40,907) - (235,970) (182,329) (27,883) (25,436) (10) (102,284) (155,266) (443,829) (402,090) (16,275) 98,029 (6,183) 11,820 (14,626) 180,848 (3,307) 12,396 (458,722) (382,045) - - - $ $ - - - 30 BONAVISTA ENERGY CORPORATION Notes to the Consolidated Financial Statements For the year ended December 31, 2013 and 2012 Structure of the Corporation and Basis of Presentation: The principal undertakings of Bonavista Energy Corporation and its subsidiaries, (“Bonavista” or the “Corporation”), are to carry on the business of acquiring, developing and holding interests in oil and natural gas properties and assets. Bonavista's principal place of business is located at 1500, 525 - 8th Avenue SW, Calgary, Alberta, Canada T2P 1G1. 1. Basis of presentation: a) Statement of compliance: The consolidated financial statements (the "financial statements") have been prepared in accordance with International Financial Reporting Standards ("IFRS") as issued by the International Accounting Standards Board (IASB). A summary of Bonavista's significant accounting policies under IFRS are presented in note 2. The consolidated financial statements were authorized for issue by the Board of the Corporation on February 27, 2014. b) Basis of measurement: The consolidated financial statements have been prepared on the historical cost basis except for the following: i) derivative financial instruments are measured at fair value; and ii) liabilities for cash-settled share-based compensation are measured at fair market value. c) Functional and presentation currency: These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional currency. d) Use of 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 the Corporation’s operating environment changes. Estimates and underlying assumptions are reviewed on an ongoing basis by management. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. The key sources of estimation uncertainty to the carrying amounts of assets and liabilities are discussed below: i) 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. 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. As at December 31, 2013 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. For the year ended December 31, 2013 the following benchmark reference prices were used by Bonavista’s independent reserve evaluator and adjusted for commodity differentials specific to the Corporation. 31 Year 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 Remainder (1) (1) WTI Oil (US$/bbl) 97.50 97.50 97.50 97.50 97.50 97.50 98.54 100.51 102.52 104.57 2.0% AECO Gas (CDN$/mmbtu) 4.03 4.26 4.50 4.74 4.97 5.21 5.33 5.44 5.55 5.66 2.0% CDN$/US$ Exchange Rates 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 0.95 Percentage change represents the change in each year after 2023 to the end of the reserve life. 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 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 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: The accounting policies set out below have been applied consistently to all periods presented in these consolidated financial statements, and have been applied consistently by the Corporation and its subsidiaries. a) Basis of consolidation: The consolidated financial statements comprise the financial statements of the Corporation and its subsidiaries as at December 31, 2013. Subsidiaries are consolidated from the date of acquisition, being the date on which the Corporation obtains control, and continues to be consolidated until the date that control ceases. Control exists when the Corporation has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. All intercompany balances and transactions, and any unrealized income and expenses, arising from intercompany transactions are eliminated in full. 32 Many of the Corporation's oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Corporation's share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs. b) Foreign currency: Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars at the period end exchange rate. Non-monetary assets and liabilities denominated in foreign currencies that are measured at fair value are translated to the functional currency at the exchange rate at the date that the fair value was determined. Foreign currency differences arising on translation are recognized in profit or loss. c) Financial instruments: i) Non-derivative financial assets: The Corporation initially recognizes loans, receivables and deposits on the date that they are originated. All other financial assets (including assets designated at fair value through profit or loss) are recognized initially on the date at which the Corporation becomes a party to the contractual provisions of the instrument. The Corporation derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Corporation is recognized as a separate asset or liability. Financial assets and liabilities are offset and the net amount is presented in the statement of consolidated financial position when, and only when, the Corporation has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously. The Corporation classifies non-derivative financial assets into the following categories: financial assets at fair value through profit or loss, held-to-maturity financial assets, loans and receivables and available-for-sale financial assets. Financial assets at fair value through profit or loss A financial asset is classified at fair value through profit or loss if it is classified as held for trading or is designated as such upon initial recognition. Financial assets are designated at fair value through profit or loss if the Corporation manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Corporation’s documented risk management or investment strategy. Attributable transaction costs are recognized in profit or loss as incurred. Financial assets at fair value through profit or loss are measured at fair value, and changes therein are recognized in the consolidated statement of income. Loans and receivables Loans and receivables are financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, loans and receivables are measured at amortized cost using the effective interest method, less any impairment losses. Loans and receivables comprise of cash and cash equivalents, and trade and other receivables. Cash and cash equivalents Cash and cash equivalents comprise cash balances and call deposits with original maturities of three months or less. ii) Non-derivative financial liabilities: The Corporation initially recognizes debt securities issued and subordinated liabilities on the date that they are originated. All other financial liabilities (including liabilities designated at fair value through profit or loss) are recognized initially on the trade date at which the Corporation becomes a party to the contractual provisions of the instrument. The Corporation derecognizes a financial liability when its contractual obligations are discharged or cancelled or expired. The Corporation classifies non-derivative financial liabilities into the other financial liabilities category. Such financial liabilities are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, these financial liabilities are measured at amortized cost using the effective interest method. Other financial liabilities comprise loans and borrowings, bank overdrafts, and trade and other payables. Bank overdrafts that are repayable on demand and form an integral part of the Corporation’s cash management are included as a component of cash and cash equivalents for the purpose of the statement of cash flows. iii) Derivative financial instruments: The Corporation has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices and foreign exchange rates. These instruments are not used for trading or speculative purposes. The Corporation has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Corporation considers all commodity contracts and foreign exchange contracts to be economic hedges. Derivatives are recognized initially at fair value 33 and any attributable transaction costs are recognized in profit or loss when incurred. Subsequent to initial recognition, derivatives are measured at fair value, and changes therein are recognized immediately in profit or loss. The Corporation has accounted for its forward physical delivery sales contracts, which were entered into and continue to be held for the purpose of receipt or delivery, of non-financial items in accordance with its expected purchase, sale or usage requirements as executory contracts. As such, these contracts are not considered to be derivative financial instruments and have not been recorded at fair value on the balance sheet. Settlements on these physical sales contracts are recognized in oil and natural gas revenues. Embedded derivatives are separated from the host contract and accounted for separately if the economic characteristics and risks of the host contract and the embedded derivative are not closely related, a separate instrument with the same terms as the embedded derivative would meet the definition of a derivative, and the combined instrument is not measured at fair value through profit or loss. Changes in the fair value of separable embedded derivatives are recognized immediately in the consolidated statement of income. Financial assets designated at fair value through profit or loss are comprised of interest rate swaps and forward exchange contracts. iv) Shareholders’ capital and Exchangeable shares: Common shares and exchangeable shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects. d) Exploration and evaluation assets and property, plant and equipment: i) Recognition and measurement: Pre-licence costs are recognized in the consolidated statement of income as incurred. Exploration and evaluation expenditures: Exploration and evaluation (“E&E”) costs, including the costs of acquiring licences and directly attributable general and administrative costs 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. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when total proved plus probable reserves are determined to exist. A review of each exploration licence or field is carried out, at least annually, to ascertain whether proved plus probable reserves have been discovered. Upon determination of total proved plus probable reserves, intangible E&E assets attributable to those reserves are transferred from E&E assets to a separate category within tangible assets referred to as oil and natural gas properties. Development and production costs: Items of property, plant and equipment, which include oil and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. Development and production assets are grouped into cash generating units for impairment testing. Gains and losses on dispositions of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net within “gains (losses) on disposition of property, plant and equipment” in the consolidated statement of income. ii) Subsequent costs: Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved or proved plus probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in the consolidated statement of income as incurred. iii) Depletion, depreciation and amortization: The net carrying amount of development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related proved 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. 34 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 Oil and natural gas properties 15 years Based on CGU Reserve Life For other assets, depreciation is recognized in profit or loss on a straight-line basis over the estimated useful lives of each part of an item of property, plant and equipment. Leased assets are depreciated over the shorter of the lease term and their useful lives unless it is reasonably certain that the Corporation will obtain ownership by the end of the lease term. The estimated useful lives for other assets for the current and comparative years are as follows: Office equipment Fixtures and fittings Leaseholds 5 years 5 years 9.5 years Depreciation methods, useful lives and residual values are reviewed at each reporting date. e) Goodwill and Exploration and evaluation assets: i) Goodwill: Goodwill arises on the acquisition of businesses, subsidiaries, associates and joint ventures. Goodwill is measured at cost less accumulated impairment losses. Goodwill is evaluated for impairment on an annual basis, or more frequently if potential indicators of impairment exist. ii) Exploration and evaluation assets: Other intangible assets that are acquired by the Corporation, which have finite useful lives, are measured at cost less accumulated amortization and accumulated impairment losses. Subsequent expenditure is capitalized only when it increases the future economic benefits embodied in the specific asset to which it relates. Amortization is recognized in profit or loss on a straight-line basis over the estimated useful lives of other intangible assets, other than goodwill, from the date they were available for use. 35 f) Impairment: i) Non-derivative financial assets: A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in the consolidated statement of income. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in the consolidated statement of income. ii) Non-financial assets: The carrying amounts of the Corporation’s non-financial assets, other than E&E assets and deferred income tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet available for use an impairment test is completed each year. E&E assets are assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets, the CGU. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. 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. An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized. g) Employee benefits: i) Share-based compensation: Long-term incentives are granted to officers, directors, employees and certain consultants in accordance with the Corporation’s stock option, 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. 36 ii) Short-term employee benefits: Short-term employee benefit obligations are expensed as the related service is provided. A liability is recognized for the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Corporation has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee, and the obligation can be estimated reliably. h) Lease payments: Payments made under operating leases are recognized in profit and loss on a straight-line basis over the term of the lease. Lease incentives received are recognized as an integral part of the total lease expense, over the term of the lease. i) Provisions: A provision is recognized if, as a result of a past event, the Corporation has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses. j) Decommissioning liabilities: The Corporation’s activities give rise to dismantling, decommissioning and site disturbance remediation activities. Provision is made for the estimated cost of site restoration and capitalized in the relevant asset category. Decommissioning liabilities are measured at the present value of management’s best estimate of expenditure required to settle the present obligation at the balance sheet date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as finance costs whereas increases/decreases due to changes in the estimated future cash flows are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established. k) Revenues: Revenues from the sale of oil and natural gas are recorded when the significant risks and rewards of ownership of the product is transferred to the buyer, which is usually when legal title passes to the external party. This is generally at the time product enters the pipeline. Revenues are measured net of discounts, customs, duties and royalties. With respect to the latter, the entity is acting as a collection agent on behalf of others. Royalty income is recognized as it accrues in accordance with the terms of the overriding royalty agreements. l) Finance income and costs: Finance costs comprise of interest expense on borrowings, unwinding of the discount on provisions and impairment losses recognized on financial assets, fair value losses on financial assets at fair value through profit and loss. Interest income is recognized as it accrues in profit or loss, using the effective interest method. Foreign currency gains and losses, are reported under finance income or expenses. m) Income taxes: Income tax expense comprises current and deferred income taxes. Current and deferred income taxes are recognized in the consolidated statement of income except to the extent that it relates to a business combination, or items recognized directly in equity or in other comprehensive income. Current tax is the expected tax payable or receivable on the taxable income or loss for the period, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years. Deferred income taxes are recognized in respect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred income taxes are not recognized for: • • • temporary differences on the initial recognition of assets or liabilities in a transaction that is not a business combination and that affects neither accounting nor taxable profit or loss; and temporary differences related to investments in subsidiaries to the extent that it is probable that they will not reverse in the foreseeable future; and taxable temporary differences arising on the initial recognition of goodwill. Deferred income taxes are measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. 37 Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously. A deferred income tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. n) Net income per share: Basic net income per share is calculated by dividing the profit or loss attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees. 3. New accounting standards: Changes in accounting policies On January 1, 2013, Bonavista adopted the following new standards and amendments which became effective for annual periods on or after January 1, 2013: • • • • IFRS 10, “Consolidated Financial Statements,” supersedes IAS 27 “Consolidated and Separate Financial Statements” and SIC-12 “Consolidation - Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities. The adoption of this standard had no impact on the amounts recorded in Bonavista’s financial statements. IFRS 11, “Joint Arrangements,” whereby joint arrangements are classified as either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting. The adoption of this standard had no impact on the amounts recorded in Bonavista’s financial statements. IFRS 12, “Disclosure of Interest in Other Entities,” combines the disclosure requirements for entities that have interest in subsidiaries, joint arrangements, and associates as well as unconsolidated structured entities. The adoption of this standard had no impact on Bonavista’s financial statements. IFRS 13, “Fair Value Measurement,” establishes a framework for measuring fair value and sets out disclosure requirements for fair value measurements. This standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard also requires additional annual fair value disclosures, as well as additional interim disclosures. The adoption of this standard had no material impact on Bonavista’s financial statements. • Amendments to IAS 32, “Financial Instruments: Presentation” clarify the requirements for offsetting financial assets with financial liabilities. Amendments to IFRS 7, "Financial Instruments: Disclosures," develop common disclosure requirements for financial assets and financial liabilities that are offset in the financial statements, or that are subject to enforceable master netting arrangements or similar agreements. The adoption of these amendments has no impact on Bonavista's financial statements. Future accounting policies In May 2013, the IASB issued amendments to IAS 36, “Impairment of Assets” which will restrict the requirements to disclose the recoverable amount of an asset or CGU to periods in which an impairment loss has been recognized or reverses. The amendment also expands and clarifies the disclosure requirements applicable when an impairment loss has been recognized or reversed in the period. The amendments apply retrospectively for annual periods beginning on or after January 1, 2014. Bonavista plans to adopt the amendments in its financial statements for the annual period beginning on January 1, 2014. The adoption will impact Bonavista’s disclosures in the notes to the financial statements in periods when an impairment loss or impairment reversal is recognized. In May 2013, the IASB issued IFRIC 21, “Levies” which provides guidance on accounting for levies in accordance with the requirements of IAS 37, “Provisions, Contingent Liabilities and Contingent Assets”. The interpretation clarifies that an entity is to recognize a liability for a levy when the activity that triggers payment, as identified by the relevant legislation, occurs. The interpretation also clarifies that a levy liability is to be accrued progressively only if the activity that triggers payment occurs over a period of time, in accordance with the relevant legislation. IFRIC 21 is effective for annual periods commencing on or after January 1, 2014 and is to be applied retrospectively. Bonavista intends to adopt IFRIC 21 in its financial statements for the annual periods beginning on January 1, 2014. Bonavista is currently assessing but has not yet determined the impact of the adoption of the amendments. In November 2013, the IASB issued amendments to the recognition, presentation and disclosure to pension accounting under IAS 19, “Employee Benefits”. The amendments apply retrospectively for annual periods beginning on or after July 1, 2014. Bonavista intends to adopt these amendments in its financial statements for the annual period beginning on January 1, 2014; no impact to the financial statements is expected. 38 In November 2009 the IASB issued IFRS 9, “Financial Instruments” as the first step in its project to replace IAS 39 “Financial Instruments: Recognition and Measurement”. IFRS 9 introduced new requirements for classifying and measuring financial assets. On October 28, 2010, the IASB reissued IFRS 9, incorporating new requirements on accounting for financial liabilities. The new standard eliminates the existing multiple classification and measurement categories under IAS 39 of held-to-maturity, available-for-sale and loans receivable and replaces them with a single model that has only two classification categories: amortized cost and fair value. In November 2013, the IASB issued a new general hedge accounting standard which forms part of IFRS 9. While hedge accounting remains optional under IFRS 9, the new general hedge accounting statement was designed to more closely align hedge accounting with the risk management activities of an entity. The new standard does not fundamentally change the types of hedging relationships or the requirements to measure and recognize ineffectiveness, however, it does provide for more hedging strategies to qualify for hedge accounting and introduces more judgment into the assessment of hedge effectiveness. In July of 2013, the IASB deferred the mandatory effective date of IFRS 9, which previously had been effective for annual periods beginning on or after January 1, 2015. The IASB has yet to determine the mandatory effective date; early adoption of the new standard is still permitted. The extent of the impact of the adoption of IFRS 9 on Bonavista’s financial statements has not yet been determined. In December 2013, the IASB issued narrow-scope amendments to a total of nine standards as part of its annual improvement process. The improvement process is designed to make non-urgent but necessary amendments to IFRS. Some of the amendments made to the existing standards included; clarifying the definition of “vesting conditions” in IFRS 2, “Share-based payment”; defining the classification and measurement of contingent consideration; scope exclusion for the formation of joint arrangements in IFRS 3, “Business Combinations”; and modifying the definition of a “related party” in IAS 24, “Related Party Disclosures”. Bonavista intends to adopt these amendments in its financial statement for the annual period beginning on January 1, 2014. The adoption of these amendments is not expected to have a material impact on the financial statements. 4. Financial risk management: Bonavista has exposure to credit and market risks from its use of financial instruments. This note provides information about the Corporation's exposure to each of these risks, the Corporation's objectives, policies and processes for measuring and managing risk. Further quantitative disclosures are included throughout these financial statements. a) Credit risk: Credit risk is the risk of financial loss to the Corporation if a customer or counterparty to a financial instrument fails to meet its contractual obligation and arises, primarily from joint venture partners, marketers and financial intermediaries. The Corporation’s accounts receivable are with customers and joint venture partners in the oil and natural gas business and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. The Corporation routinely assesses the financial strength of its customers. The Corporation may be exposed to certain losses in the event of non-performance by counterparties to financial instrument contracts. The Corporation mitigates this risk by entering into transactions with highly rated financial institutions. The carrying amount of accounts receivable represents the maximum credit exposure. As at December 31, 2013 Bonavista’s receivables consisted of $89.0 million of receivables from oil and natural gas marketers which has substantially been collected subsequent to December 31, 2013 and $32.6 million from joint venture partners of which $13.8 million has been subsequently collected. As at December 31, 2013 Bonavista has $10.2 million in accounts receivable that is considered to be past due. Although these amounts have been outstanding for greater than 90 days, they are still deemed to be collectible. As the operator of properties, Bonavista has the ability to withhold production to joint venture partners, who are in default of amounts owing. The Corporation does not have an allowance for doubtful accounts as at December 31, 2013 and did not provide for any doubtful accounts during the year ended December 31, 2012. b) Liquidity risk: Liquidity risk is the risk that Bonavista will encounter difficulty in meeting obligations associated with the financial liabilities. The Corporation's financial liabilities consist of accounts payable and accrued liabilities, dividends payable, financial instruments contracts, bank debt, and senior unsecured notes. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities, and capital expenditures. Bonavista processes invoices within a normal payment period. Accounts payable and accrued liabilities have contractual maturities of less than one year. Dividends payable are declared on a monthly basis and are dependent upon a number of factors including current and future commodity prices, foreign exchange rates, 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 three to ten years on foreign exchange hedge contracts. Bonavista’s four year revolving credit facility, as outlined in note 12, may at the request of the Corporation with the consent of the lenders, be extended on an annual basis beyond the existing term. The Corporation also has a series of senior unsecured notes outstanding, as outlined in note 12, which range in maturities from November 2, 2015 to May 23, 2025. The Corporation also maintains and monitors a certain level of cash flow, which is used to partially finance all operating, investing and capital expenditures. 39 c) Commodity price risk: Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand but also by the relationship between the Canadian and United States dollar. Bonavista mitigates a portion of the commodity price risk through the use of various financial instrument commodity contracts and physical delivery sales contracts. The Corporation's policy is to enter into commodity price contracts when considered appropriate to a maximum of 70% for 2014 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. Financial instrument commodity contracts: As at December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume Average Price Term 5,000 40,000 15,000 15,000 10,000 20,000 8,000 3,500 500 gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d bbls/d bbls/d bbls/d CDN $3.50 - CDN $4.00 - AECO CDN $2.93 - CDN $3.73 - AECO CDN $3.33 - CDN $4.09 - AECO CDN $3.38 - CDN $3.95 - AECO CDN $2.85 - CDN $3.50 - AECO CDN $3.53 - CDN $4.02 - AECO CDN $89.78 - CDN $98.65 - WTI CDN $88.36 - CDN $98.09 - WTI CDN $87.50 - CDN $97.50 - WTI January 1, 2014 - March 31, 2014 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 April 1, 2014 - October 31, 2014 January 1, 2015 - December 31, 2015 January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 January 1, 2015 - December 31, 2015 Subsequent to December 31, 2013, Bonavista entered into the following costless collars to sell oil and natural gas as follows: Volume 10,000 5,000 25,000 Average Price Term gjs/d gjs/d gjs/d CDN $3.50 - CDN $3.75 - AECO CDN $3.50 - CDN $4.00 - AECO CDN $3.50 - CDN $3.87 - AECO April 1, 2014 - October 31, 2014 November 1, 2014 - March 31, 2015 January 1, 2015 - December 31, 2015 As at December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume 55,000 10,000 5,000 5,000 40,000 5,000 5,000 25,000 15,825 26,375 35,000 5,000 500 gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d gjs/d bbls/d Price CDN $3.45 CDN $3.52 CDN $3.35 CDN $3.48 CDN $3.63 CDN $3.49 CDN $3.71 CDN $3.53 US $3.62 US $3.80 US $(0.48) US $(0.48) US 50% Contract Term Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - AECO Swap - NYMEX Swap - NYMEX Swap - NYMEX Basis Swap - NYMEX Basis Swap - CNWY/WTI January 1, 2014 - December 31, 2014 January 1, 2014 - December 31, 2015 January 1, 2014 - March 31, 2014 April 1, 2014 - October 31, 2014 April 1, 2014 - December 31, 2014 April 1, 2014 - March 31, 2015 November 1, 2014 - March 31, 2015 January 1, 2015 - December 31, 2015 April 1, 2014 - October 31, 2014 April 1, 2014 - December 31 2014 April 1, 2014 - December 31, 2014 November 1, 2014 - December 31, 2014 April 1, 2014 - March 31, 2015 Subsequent to December 31, 2013, Bonavista entered into the following contracts to manage its overall commodity exposure: Volume 10,000 75,000 1,000 gjs/d gjs/d bbls/d Price CDN $3.90 CDN $3.73 US 51% Contract Term Swap - AECO Swap - AECO Swap - CNWY/WTI April 1, 2014 - October 31, 2014 January 1, 2015 - December 31, 2015 April 1, 2014 - March 31, 2015 40 As at December 31, 2013, Bonavista entered into the following contracts to purchase electricity: Volume 6 2 Mwh Mwh Price CDN $50.88 CDN $52.00 Contract Swap - AESO Swap - AESO Term January 1, 2014 - December 31, 2015 January 1, 2016 - December 31, 2016 Financial instrument commodity contracts are recorded on the consolidated statement of financial position at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statements of income and comprehensive income. A $0.10 change in the price per thousand cubic feet of natural gas - AECO would have an impact of approximately $6.8 million on net in place as at December 31, 2013 (2012 - $3.5 million). A $1.00 change in the price per barrel of oil - WTI would have an impact of approximately $3.5 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2013 (2012 - $1.6 million). instrument commodity contracts that were financial income those for d) Foreign exchange risk: Commodity prices are largely denominated in US dollars and as a result the prices that Canadian producers receive is determined by the relationship between the US and Canadian dollar. In addition, Bonavista also has US denominated debt and interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the due date. On July 21, 2011, Bonavista entered into an agreement with three financial intermediaries to purchase the following US dollars that coincide with Bonavista’s note repayment commitments: Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US$ purchased forward US$ purchased forward US$ purchased forward Notional US$ $30,000,000 $53,300,000 $16,500,000 CDN$/US$ 0.995 0.995 0.995 A $0.01 change in CDN$/US$ exchange rate would have an impact of approximately $709,000 on net income for those foreign exchange forward contracts in place as at December 31, 2013 (2012 - $655,000). e) Interest rate risk: Bonavista is exposed to interest rate risk on its outstanding bank debt, as it has a floating interest rate and consequently changes to interest rates would impact the Corporation’s future cash flows. If interest rates applicable to the variable rate debt increases by 1% it is estimated that Bonavista’s net income for the year ended December 31, 2013 would decrease by $2.2 million (2012 - $3.6 million). Fair value of financial instruments: The fair value of the financial instruments carried on Bonavista’s consolidated statement of financial position is classified according to the following hierarchy based on the amount of observable inputs used to value the financial instruments. Level 1 – quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 – pricing inputs are other than quoted prices in active markets included in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace. Level 3 – valuation in this level are those with inputs for the asset or liabilities that are not based on observable market data. The Corporation’s marketable securities have been classified as Level 1, financial instrument contracts, bank debt and senior unsecured notes are classified as Level 2. 41 The fair market value recorded on the consolidated statements of financial position for these financial instrument contracts were as follows: (thousands) Current asset: Marketable securities(1) Financial instrument commodity contract(2) Long-term asset: Financial instrument commodity contract(2) Financial instrument contract(2) Current liabilities: Financial instrument commodity contract(2) Long-term liability: Financial instrument commodity contract(2) Net asset/(liability) (1) (2) Level 1 Level 2 December 31, December 31, 2013 2012 $ 2,645 419 $ 2,768 8,608 346 8,023 1,224 4,293 (31,985) (8,786) (3,710) (1,550) $ (24,262) $ 6,557 Bank debt bears interest at a floating market rate and accordingly the fair market value approximates the carrying value. The fair market value of the senior unsecured notes as at December 31, 2013 is approximately $789.2 million (2012 - $579.8 million), compared to a carrying amount of $819.8 million (2012 - $547.5 million). 5. Capital management: The Corporation's objective when managing capital is to maintain a flexible capital structure which allows it to execute its growth strategy through strategic acquisitions and expenditures on exploration and development activities while maintaining a strong financial position that provides its shareholders with stable dividends and rates of return. The Corporation considers its capital structure to include working capital (excluding associated assets and liabilities from financial instrument contracts 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). The Corporation's strategy is to maintain a ratio of less than 2.0 to 1. This strategy is more restrictive than the existing financial covenants on both the Corporation's bank credit facility and senior unsecured notes. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As at December 31, 2013, Bonavista’s ratio of net debt to fourth quarter annualized funds from operations was 2.1 to 1 (2012 - 2.2 to 1), which is slightly above the range established by the Corporation. 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 Three months ended December 31, 2013 December 31, 2012 $ $ $ 115,021 (11,076) 10,539 9,870 124,354 497,416 $ $ $ 102,886 (9,487) 11,410 5,206 110,015 440,060 To facilitate the management of this ratio, the Corporation prepares annual funds from operations and capital expenditure budgets, which are updated as necessary, and are reviewed and periodically approved by Bonavista’s Board of Directors. The Corporation manages its capital structure and makes adjustments by continually monitoring its business conditions, including: the current economic conditions; the risk characteristics of Bonavista’s oil and natural gas assets; the depth of its investment opportunities; current and forecasted net debt levels; current and forecasted commodity prices; and other factors that influence commodity prices and funds from operations, such as quality and basis differentials, royalties, operating costs and transportation costs. 42 To maintain or adjust the capital structure, Bonavista will consider: its forecasted ratio of net debt to forecasted funds from operations while attempting to finance an acceptable capital expenditure program including acquisition opportunities; the current level of bank credit available from the Corporation's lenders; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the capital expenditure program; issuance of new equity if available on favourable terms; and its level of dividends payable to its shareholders. The Corporation's shareholders' capital is not subject to external restrictions, however, the Corporation's bank credit facility and senior unsecured notes do contain financial covenants that are outlined in note 12 of the consolidated financial statements. 6. Finance costs and income: a) Finance costs: Finance costs: Interest on bank debt Interest on notes payable Accretion of decommissioning liabilities Unrealized loss on marketable securities Foreign exchange loss Accretion on other liabilities Finance costs b) Finance income: Finance income: Unrealized gain on financial instrument contracts Foreign exchange gain Finance income Year ended December 31, 2013 Year ended December 31, 2012 13,347 30,339 10,566 123 42,373 1,691 98,439 $ 19,278 23,445 9,895 732 - - $ 53,350 Year ended December 31, 2013 Year ended December 31, 2012 (3,730) - (3,730) $ $ (689) (11,050) (11,739) $ $ $ $ The Corporation’s effective interest rate for the year ending December 31, 2013 was approximately 4.4% (2012 - 4.1%). 7. Supplemented cash flow information: Changes in non-cash working capital is comprised of: Year ended December 31, 2013 Year ended December 31, 2012 Source/(use) of cash Accounts receivable Prepaid expenses Marketable securities Other assets Accounts payable and accrued liabilities, net of interest accrual Related to: Operating activities Investing activities $ $ $ $ (21,931) 3,767 - (1,595) 28,749 8,990 (2,830) 11,820 8,990 $ $ $ $ 30,824 (1,429) (3,500) (3,536) 3,503 25,862 13,466 12,396 25,862 43 8. Property, plant and equipment: Cost: Oil and natural gas properties Facilities Other assets Total Balance as at December 31, 2011 $ 3,588,447 $ 494,132 $ 15,068 $ 4,097,647 Additions Acquisitions Transfer from exploration and evaluation Changes in decommissioning liabilities 380,105 148,574 25,076 19,256 9,943 32,767 - - Dispositions (129,831) (24,561) 3,307 - - - - 393,355 181,341 25,076 19,256 (154,392) Balance as at December 31, 2012 $ 4,031,627 $ 512,281 $ 18,375 $ 4,562,283 Additions Acquisitions Transfer from exploration and evaluation Changes in decommissioning liabilities Dispositions 412,638 116,156 15,563 (26,607) (77,414) 15,409 25,797 - - (14,909) 6,183 - - - - 434,230 141,953 15,563 (26,607) (92,323) Balance as at December 31, 2013 $ 4,471,963 $ 538,578 $ 24,558 $ 5,035,099 Depletion, depreciation and amortization: Balance as at December 31, 2011 $ (532,427) $ (43,187) $ (3,186) $ (578,800) Depletion, depreciation and amortization Dispositions (304,746) 35,301 (23,703) 3,811 (2,574) (331,023) - 39,112 Balance as at December 31, 2012 $ (801,872) $ (63,079) $ (5,760) $ (870,711) Depletion, depreciation and amortization Dispositions (320,117) 27,431 (25,740) 2,810 (3,428) (349,285) - 30,241 Balance as at December 31, 2013 $ (1,094,558) $ (86,009) $ (9,188) $ (1,189,755) Net book value as at December 31, 2013 $ 3,377,405 $ 452,569 $ 15,370 $ 3,845,344 Net book value as at December 31, 2012 $ 3,229,755 $ 449,202 $ 12,615 $ 3,691,572 For the year ended December 31, 2013, Bonavista capitalized $8.7 million (2012 - $8.8 million) of direct general and administrative expenses. 9. Goodwill and Exploration and evaluation assets : (thousands) Balance as at December 31, 2011 $ 11,225 $ 233,642 Goodwill Exploration and evaluation assets Additions Acquisitions Dispositions Transfers to property, plant and equipment - - - - 14,520 6,127 (11,831) (25,076) Balance as at December 31, 2012 $ 11,225 $ 217,382 Additions Acquisitions Dispositions Transfers to property, plant and equipment - - - - 24,825 2,876 (7,435) (15,563) Balance as at December 31, 2013 $ 11,225 $ 222,085 Exploration and evaluation assets consist of the Corporation’s exploration projects which are pending the determination of proved or probable reserves. Additions represent the Corporation’s share of costs incurred on E&E assets during the year. 44 There were no incidents of impairment identified on the Corporation’s exploration and evaluation assets for the years ended December 31, 2013 and December 31, 2012. The impairment test of goodwill concluded that the estimated recoverable amount exceeded the carrying amount for the years ended December 31, 2013 and December 31, 2012. As such, no goodwill impairment existed. 10. Acquisitions: a) On January 9, 2013, Bonavista completed the acquisition of certain multi-zone oil and liquids rich natural gas assets located within its Deep Basin core area in west central Alberta. The assets were acquired for cash consideration of $72.5 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 (thousands) Purchase consideration: Cash Total purchase consideration Amount $ 2,682 14,080 64,916 (9,189) $ 72,489 $ $ 72,489 72,489 In the period from January 9, 2013 to December 31, 2013, the acquisition contributed revenues of $18.8 million and net income of $2.4 million, which are included in the consolidated statement of income for the year ended December 31, 2013. In conjunction with the transaction, Bonavista expensed $95,000 of applicable transaction costs. b) On November 6, 2013, Bonavista completed the acquisition of certain multi-zone oil and liquids rich natural gas assets located within its Deep Basin core area in west central Alberta. The assets were acquired for cash consideration and oil and natural gas properties totaling $42.6 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 (thousands) Purchase consideration: Cash Oil and natural gas properties Total purchase consideration Amount $ 194 8,800 36,415 (2,767) $ 42,642 $ $ 29,795 12,847 42,642 In the period from November 6, 2013 to December 31, 2013 the acquisition contributed revenues of $1.5 million and net income of $193,000 which is included in the consolidated statement of income for the year ended December 31, 2013. If the acquisition had occurred on January 1, 2013, management estimates that the acquisition would have contributed revenues of $10.5 million and net income of $1.2 million for the year ended December 31, 2013. In conjunction with the transaction, Bonavista expensed $25,000 of applicable transaction costs. c) Subsequent to December 31, 2013, Bonavista disposed of non-core properties for proceeds of approximately $103 million with combined production of approximately 2,500 boe per day. These properties are located in northwest Alberta and the Provost area of Alberta. 45 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, 2013 were $0.84 per share (2012 - $1.44 per share). Bonavista announced that it had adopted a dividend reinvestment plan ("DRIP") and stock dividend plan (“SDP”) on December 31, 2011 and May 3, 2012 respectively. The DRIP and SDP provide eligible holders of common shares the option to reinvest cash dividends into common shares issued either from treasury at a five per cent discount to the prevailing average market price or acquired through the facilities of the Toronto Stock Exchange at prevailing market rates with no discount. Under the DRIP, a cash dividend is paid to the common shareholder and then immediately reinvested in new common shares. Under the SDP program, dividends are paid directly in common shares to electing participants. The implementation of the DRIP began in January 2012 and the implementation of the SDP began in June 2012. The exchangeable shares of Bonavista are exchangeable into common shares based on the exchange ratio, which is adjusted monthly, to reflect dividends paid on common shares. As a result, dividends are not paid on exchangeable shares. The holders of exchangeable shares are entitled to one vote times the exchange ratio for each exchangeable share. a) Issued and outstanding: i) Common shares: (thousands) Balance as at December 31, 2011 Issued for cash Issued on conversion of exchangeable shares Issued pursuant to the dividend reinvestment and stock dividend plans Issued upon exercise of common share incentive rights Share-based compensation Issue costs, net of future tax benefit Conversion of restricted share awards Balance as at December 31, 2012 Issued on conversion of exchangeable shares Issued pursuant to the dividend reinvestment and stock dividend plans Issued upon exercise of common share incentive rights Share-based compensation Issue costs, net of future tax benefit Conversion of restricted share awards Number of Shares 144,098 20,930 6,953 5,034 372 - - 135 177,522 4,023 4,562 208 - - 647 Amount $ 1,446,804 345,345 180,571 82,892 4,510 9,792 (10,609) - $ 2,059,305 97,715 59,162 1,984 10,118 (74) - Balance as at December 31, 2013 186,962 $ 2,228,210 ii) Exchangeable shares: (thousands) Balance, beginning of year Exchanged for common shares Balance, end of year Exchange ratio, end of year Year ended December 31, 2013 Year ended December 31, 2012 Number Amount Number Amount 14,069 (3,393) $ 405,183 (97,715) 20,339 (6,270) $ 585,754 (180,571) 10,676 $ 307,468 14,069 $ 405,183 1.20836 - 1.13313 - Common shares issuable on exchange 12,900 $ 307,468 15,942 $ 405,183 The holders of the Corporation’s exchangeable shares shall be entitled to notice of, to attend at, and to that number of votes equal to the number of exchangeable shares held multiplied by the exchange ratio in effect at the meeting record date at any meeting of the shareholders of Bonavista. In accordance with the provisions of the Corporation’s exchangeable shares, Bonavista may require, at any time, the exchange of that number of the Corporation’s exchangeable shares as determined by the Board of Directors on the basis of the exchange ratio in effect on the date set by Bonavista (the “Compulsory Exchange Date”). On and after the applicable Compulsory Exchange Date, the holders 46 of the Corporation’s exchangeable shares called for exchange shall cease to be holders of such Corporation’s exchangeable shares and shall not be entitled to exercise any of the rights of holders in respect thereof, other than; (i) the right to receive their proportionate part of the common shares; and (ii) the right to receive any declared and unpaid dividends on such common shares. b) Share-based compensation: Bonavista has option and 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. i) Stock option and common share incentive rights plans: Upon conversion to a corporation, the stock option plan of the Corporation was established and the common share rights incentive plan (formerly the trust unit rights incentive plan of the Trust) was amended. The amended plan provided that all rights to acquire trust units became rights to acquire common shares. 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 period Dividend yield Volatility Risk-free interest rate Forfeiture rate (1) Expected life December 31, 2013 December 31, 2012 6.57% 38.97% 1.64% 8.78% 5.0 7.90% 39.82% 1.28% 8.14% 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 as at December 31, 2011 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2012 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2013 Exercisable as at December 31, 2013 Number of Stock Options/Common Share Incentive Rights 5,295,478 2,762,385 (371,678) (1,280,949) - 6,405,236 1,282,823 (211,140) (678,441) - 6,798,478 3,125,778 Weighted Average Exercise Price $ 22.65 18.62 (12.13) (23.45) (0.66) $ 20.75 13.84 (9.38) (21.17) (0.26) 19.52 21.00 $ $ As at December 31, 2013 there are 5.5 million stock options outstanding (2012 - 4.4 million) of which 2.1 million are exercisable (2012 - 654,376) and 1.3 million common share incentive rights outstanding (2012 - 2.0 million) with 1.1 million exercisable (2012 - 1.2 million). 47 The range of exercise prices of the outstanding stock option and common share incentive rights plans is as follows: Stock Options/Common Share Incentive Rights Outstanding Weighted average remaining contractual life (years) Weighted average exercise price Number outstanding Range of exercise prices $ 8.54 – 15.53 15.54 – 25.80 25.81 – 30.73 2,888,780 2,130,808 1,778,890 $ 8.54 – 30.73 6,798,478 3.5 2.4 2.3 2.8 $ 13.83 20.46 27.62 $ 19.52 ii) Incentive award and restricted share award incentive plans: Stock Options/Common Share Incentive Rights Exercisable Number exercisable Weighted average exercise price 803,356 1,293,675 1,028,747 $ 12.48 20.76 27.94 3,125,778 $ 21.00 Bonavista’s incentive award and restricted share award incentive plans provide compensation in relation to a notional number of underlying common shares to directors, officers, employees and certain consultants. Awards granted between 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. 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 forecasted dividends. This fair value is recognized as share-based compensation expense over the vesting period with a corresponding increase to contributed surplus. Upon the 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 award and restricted share award incentive plans outstanding at December 31: Balance as at December 31, 2011 Granted Exercised Forfeited Balance as at December 31, 2012 Granted Exercised Forfeited Balance as at December 31, 2013 487,484 1,480,706 (178,432) (151,538) 1,638,220 1,600,582 (646,544) (135,173) 2,457,085 As at December 31, 2013, there were 2.5 million incentive and restricted share awards (2012 - 1.6 million) outstanding. As at December 31, 2013, the balance of contributed surplus attributable to the share-based compensation awards was $61.2 million (2012 - $44.8 million). Share-based compensation expense recognized in the year ended December 31, 2013 was $23.9 million (2012 - $19.5 million). For the year ended December 31, 2013, $2.6 million of share-based compensation expense was capitalized to property, plant and equipment (2012 - $2.9 million). 48 c) Per share amounts: The following table summarizes the weighted average common shares and exchangeable shares used in calculating net income per equivalent share: (thousands) Common shares Exchangeable shares converted at the exchange ratio Basic equivalent shares Stock option and common share incentive rights Restricted share awards and restricted common share rights Year ended December 31, 2013 Year ended December 31, 2012 181,685 15,611 197,296 125 1,919 154,551 21,030 175,581 223 943 Diluted equivalent shares 199,340 176,747 12. Long-term debt: (thousands) Bank credit facility Senior unsecured notes Balance, end of year a) Bank credit facility: December 31, 2013 December 31, 2012 $ 229,323 816,854 $ 1,046,177 $ 344,195 544,876 $ 889,071 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, 2016. Bonavista also has in place a $50 million demand working capital facility, which is subject to the same covenants as the credit facility. The credit facility provides that advances may be made by way of prime rate loans, bankers' acceptances and/or US dollar LIBOR advances. These advances bear interest at the banks' prime rate and/or at money market rates plus a stamping fee. The credit facility is a four year revolving credit and may, at the request of Corporation with the consent of the lenders, be extended on an annual basis beyond the existing term. There is an accordion feature providing that at any time during the term, on participation of any existing or additional lenders, the Corporation can increase the facility by $250 million. Under the terms of the bank credit facility, Bonavista has provided the covenant that its: (i) consolidated senior debt borrowing will not exceed three times net income before unrealized gains and losses on financial instrument contracts and marketable securities, interest, taxes and depreciation, depletion, 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. b) Senior unsecured notes issued under a master shelf agreement: The Corporation entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. In 2010, the Corporation drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25 million maturing on June 4, 2016 and the remaining US$25 million maturing on June 4, 2017. In the second quarter of 2013, Bonavista agreed to increase 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. 49 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 CDN $50.0 million US $90.0 million US $160.0 million US $50.0 million US $150.0 million US $85.0 million CDN $20.0 million US $20.0 million Coupon Rate 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, 2013, Bonavista was in compliance with all the covenants under its credit facilities and senior unsecured notes. The weighted average interest rate under the bank credit facility was 3.1% for the year ended December 31, 2013 (2012 - 3.1%). The average interest rate on Bonavista’s outstanding long-term notes as at December 31, 2013 was 4.1% (2012 – 4.2%). 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 $406.5 million as at December 31, 2013 (2012 - $447.8 million), based on an estimated total future undiscounted liability of approximately $1.4 billion (2012 - $899.4 million). At December 31, 2013 management estimates expenditures required to settle the liability will be made over the next 55 years with the majority of payments being made in years 2048 to 2064. A risk- free rate of approximately 3.2% (2012 - 2.4%) based on the Bank of Canada’s long-term risk-free bond rate and an inflation rate of 2% (2012 - 2%) were used to calculate the present value of the decommissioning liability. The impact of the change in the risk free rate is reflected in the table below in the category change in estimate. A reconciliation of the decommissioning liabilities is provided below: (thousands) Balance, beginning of year Accretion expense Liabilities incurred Liabilities acquired Liabilities disposed Liabilities settled Change in estimate (1) Balance, end of year $ Current portion of decommissioning liabilities Long-term decommissioning liabilities (1) Relates to changes in estimates, discount rates and anticipated settlement of decommissioning liabilities. Year ended December 31, 2013 Year ended December 31, 2012 $ 447,753 $ 444,132 10,566 6,394 13,423 (14,899) (30,143) (26,607) 406,487 9,313 397,174 9,895 5,173 15,805 (35,635) (25,530) 33,913 $ 447,753 - 447,753 50 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 Effect of tax rate changes and rate variance Other Year ended December 31, 2013 Year ended December 31, 2012 $ 73,548 $ 90,494 25.1% 18,461 (2,436) (2,436) 4,845 5,370 264 (25) 25.1% 22,714 - - (1,470) 4,873 (64) 239 Deferred income taxes $ 24,043 $ 26,292 The tax rate consists of the combined federal and provincial statutory tax rates for Bonavista for the years ended December 31, 2013 and December 31, 2012. The general combined federal and provincial tax rate increased slightly in 2013 due to the BC provincial rate increasing from 10 percent in 2012 to 11 percent effective April 1, 2013. December 31, 2013 December 31, 2012 (thousands) Deferred income tax liabilities: Capital assets in excess of tax value $ 463,502 $ Partnership deferral Foreign exchange on long-term debt Debt issue costs Deferred income tax assets: Decommissioning liabilities Non-capital losses Other liability Issue costs Financial instrument contracts Marketable securities Share-based compensation - (2,151) 1,455 (101,988) (105,993) (3,786) (4,465) (8,764) - (616) 348,848 92,306 2,694 1,656 (112,207) (107,704) (4,046) (8,153) (126) (92) - Deferred income tax liability $ 237,194 $ 213,176 The December 31, 2012 comparative deferred income tax liability presented above includes a deferred income tax liability for the deferral of partnership income. During the year ended December 31, 2013, Bonavista wound up its partnership eliminating any deferral of partnership income. 51 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 $ 348,848 $ 113,960 $ Decommissioning liabilities Non-capital losses Partnership deferral Issue costs Other liability Foreign exchange Debt issue costs Financial instrument contracts Marketable securities Share-based compensation (112,207) (107,704) 92,306 (8,153) (4,046) 2,694 1,656 (126) (92) - 10,913 1,711 (92,306) 3,713 260 (4,845) (201) (8,638) 92 (616) - - - - (25) - - - - - - $ 213,176 $ 24,043 $ (25) $ $ 694 $ 463,502 (694) - - - - - - - - - - (101,988) (105,993) - (4,465) (3,786) (2,151) 1,455 (8,764) - (616) $ 237,194 Balance December 31, 2011 (Asset)/ Liability Recognized in profit and loss (Asset)/ Liability Recognized in equity (Asset)/ Liability Acquired in business combinations (Asset)/ Liability Balance December 31, 2012 (Asset)/ Liability (thousands) Property, plant and equipment $ 271,029 $ 68,980 $ Decommissioning liabilities Non-capital losses Partnership deferral Issue costs Other liability Foreign exchange Debt issue costs Financial instrument contracts Marketable securities Share-based compensation (111,300) (99,720) 137,069 (5,865) - 772 32 (1,732) - (616) 2,956 (7,984) (44,763) 1,260 167 1,922 1,624 1,606 (92) 616 - - - - (3,548) - - - - - $ 8,839 $ 348,848 (3,863) - - - (4,213) - - - - - (112,207) (107,704) 92,306 (8,153) (4,046) 2,694 1,656 (126) (92) - $ 189,669 $ 26,292 $ (3,548) $ 763 $ 213,176 52 The following is a summary of the estimated tax pools: (thousands) Canadian oil and gas property expense $ 937,202 $ 1,032,539 December 31, 2013 December 31, 2012 Canadian development expense Canadian exploration expense Undepreciated capital cost Non-capital losses Other Total 723,968 149,719 431,025 391,788 17,796 645,918 73,223 428,513 391,041 32,535 $ 2,651,498 $ 2,603,769 Non-capital losses carry forward of $391.8 million (2012 - $391.0 million) expire in the years 2025 through 2033. Bonavista has capital losses of $48.7 million (2012 - $67.8 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, 2013 and 2012 Bonavista paid no tax installments. 15. Commitments: The following table details Bonavista’s contractual obligations for long-term debt, lease obligations, and other purchase commitments as at December 31, 2013: (thousands) Long-term debt repayments (1)(3) Interest payments (2)(3) Office lease (4) Drilling service contracts (5) Transportation expenses Total 2014 2015 2016 2017 2018 and thereafter Payments Due by Year $ 1,046,177 243,180 41,192 70,700 44,111 $ - 33,568 5,929 35,266 17,229 $ 50,000 33,257 6,068 29,527 11,511 $ 255,913 31,027 6,068 5,907 7,298 $ 122,314 29,160 6,068 - 4,070 $ 617,950 116,168 17,059 - 4,003 Total contractual obligations $ 1,445,360 $ 91,992 $ 130,363 $ 306,213 $ 161,612 $ 755,180 (1) Long-term debt repayments include the bank loan facility and principal payments due on senior unsecured notes. Based on the existing terms of the revolving bank credit facility, the amounts owing under this facility are required to be paid in 2016. Fixed interest payments on senior unsecured notes. US dollars payments are converted using the exchange rate of $1.0636 CDN/US dollar. (2) (3) (4) Office lease expires July 31, 2020. (5) The drilling service contracts are with two service providers extending over a three year term. 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 Year ended Year ended December 31, 2013 December 31, 2012 $ $ 7,337 31,125 $ 38,462 $ 6,409 26,684 33,093 53 b) Compensation of key management personnel: 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 Year ended December 31, 2013 December 31, 2012 $ $ 3,513 4,133 7,646 $ $ 2,823 6,523 9,346 54 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) Ronald J. Poelzer (5) Christopher P. Slubicki (2)(3) Walter C. Yeates (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 Scott H. Hanson, Vice President, Production Bruce W. Jensen, Vice President, Engineering Dean M. Kobelka, Vice President, Finance Magni Lake, Vice President, Marketing Wayne E. Merkel, Vice President, Exploration Lynda J. Robinson, Vice President, Human Resources and Administration Hank R. Spence, Vice President, Operations Cory J. Stewart, Vice President, Land Grant A. Zawalsky, Corporate Secretary FOR FURTHER INFORMATION CONTACT: Keith A. MacPhail Executive Chairman or Jason E. Skehar President and CEO AUDITORS KPMG LLP Chartered Accountants Calgary, Alberta BANKERS Canadian Imperial Bank of Commerce The Toronto-Dominion Bank Bank of Montreal Royal Bank of Canada The Bank of Nova Scotia National Bank of Canada Alberta Treasury Branches Citibank, N.A. (Canadian Branch) HSBC Bank Canada Sumitomo Mitsui Banking Corporation of Canada Union Bank of California, N.A. (Canada Branch) Calgary, Alberta ENGINEERING CONSULTANTS GLJ Petroleum Consultants Ltd. Calgary, Alberta LEGAL COUNSEL Burnet, Duckworth & Palmer LLP Calgary, Alberta REGISTRAR AND TRANSFER AGENT Valiant Trust Company Calgary, Alberta STOCK EXCHANGE LISTING Toronto Stock Exchange Trading Symbol “BNP” HEAD OFFICE 1500, 525 – 8th Avenue SW Calgary, Alberta T2P 1G1 Telephone: (403) 213-4300 (403) 262-5184 Facsimile: investor.relations@bonavistaenergy.com Email: www.bonavistaenergy.com Website: or Glenn A. Hamilton Senior Vice President and CFO 55 

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