2011 ANNUAL REPORT TO SHAREHOLDERS Strong and Steady… since 1997 BONAVISTA 2011 Annual Report CONTENTS Bonavista 2011 Highlights 03 A Note to our Shareholders 04 Asset Base Overview 08 Key Play Highlights 10 Our Team at Work 14 Management’s Discussion and Analysis 18 Financial Statements 35 Notes to the Financial Statements 39 Key Strategies For the past 14 years we have maintained a firm commitment to several core business principles. These principles have stood the test of time and will continue to drive our future success: • • • • • • Attract and retain an entrepreneurial and knowledgeable team to apply disciplined technical, operational and financial expertise Create operational strength and dominance in geographically focused regions Build a high quality, low cost asset base with appropriate commodity balance, capable of delivering profitable growth Enforce capital efficiency and strict cost controls through acute attention to detail Preserve financial strength and flexibility to take advantage of new opportunities Pursue strategic acquisitions to add opportunity rich, high quality assets to our portfolio Commitment to Value Creation Bonavista takes a long term approach to value creation. We seek to maximize profitability as opposed to the pursuit of growth at any cost. We strive to create shareholder value by pursuing low risk, repeatable drilling opportunities and complement this activity with strategic acquisitions while maintaining a conservative approach to financial management. Our goal is to provide an attractive total return to our shareholders appropriately balanced between production growth and dividend income within a business model based on long term sustainability. To explore this Annual Report in more detail, visit us online at: www.BONAVISTAENERGY.com 02 BONAVISTA 2011 ANNUAL REPORT BONAVISTA 2011 Highlights PRODUCTION GROWTH 5% 11% $13.39 RESERVES GROWTH FINDING, DEVELOPMENT AND ACQUISITION COSTS 2011 PRODUCTION 69,332 BOE PER DAY 230% ANNUAL PRODUCTION REPLACEMENT 100% DRILLING SUCCESS $1.44 DIVIDENDS PER SHARE PRODUCTION GROWTH (BOE/day) RESERVES GROWTH (MMBOE) 80,000 65,000 50,000 35,000 20,000 66,259 69,332 52,505 53,190 55,299 2007 2008 2009 2010 2011 350 295 240 185 130 75 344.7 311.8 272.6 179.5 191.1 2007 2008 2009 2010 2011 Natural Gas Oil & Liquids Natural Gas Oil & Liquids TOTAL RETURN (1997 - 2011) TSX Oil Gas Exploration Index S&P/TSX Index Bonavista Total Return 32% average annual return to shareholders 5,500 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0 7 9 9 1 8 9 9 1 9 9 9 1 0 0 0 2 1 0 0 2 2 0 0 2 3 0 0 2 4 0 0 2 5 0 0 2 6 0 0 2 7 0 0 2 8 0 0 2 9 0 0 2 0 1 0 2 1 1 0 2 2011 ANNUAL REPORT 03 BONAVISTA A Note to our Shareholders Reflecting on 2011 The Bonavista Team The year 2011 marked the first year Bonavista operated as a dividend paying corporation after converting from the energy trust structure on December 31, 2010. With our proven operating strategies unchanged, we reentered a corporate structure with the confidence knowing that Bonavista was well positioned to offer our shareholders an attractive return comprised of a balance between growth and income. Although we witnessed encouraging improvements in the North American economy in 2011, numerous events around the globe caused continued volatility in both commodity and equity prices. During the year, crude oil prices fluctuated between $75.00 and $115.00 per barrel and on average, posted a 19% improvement over 2010. Conversely, North American natural gas prices were eroded by a significant supply imbalance and declined approximately 10% on average in 2011. As we enter 2012, we are witnessing natural gas prices at depressed levels not seen for over a decade forcing us to take a more cautious approach to spending this year. Supporting our high-quality asset base, our proven operational strategies and our financial discipline, is a team of exceptional and committed people, who have applied their skills consistently over time to generate a strong track record of success. Led by a proven and experienced management group, every member of the Bonavista team has a deep understanding of our assets and our operating strategies. Collectively, we are committed to applying the highest technical, operational, and financial skills in innovative ways to create long term value for our shareholders. Over the past year, we have successfully attracted 68 new employees, enhancing our team as we position ourselves to capitalize on future growth opportunities. This approach to value creation comes through building a team who are both owners and partners, creating a strong alignment with the interests of our shareholders. Together, our directors, management, and employees own approximately 14% of the company. Capital Expenditures Bonavista completed an active capital program in 2011 investing a record $453.6 million in exploration and development activities drilling 143 wells with a remarkable 100% success rate. This success was largely attributable to our utilization of horizontal drilling and multi-stage stimulation techniques on 122 wells, targeting large tight reservoirs including the Glauconite, Cardium, Bluesky, Rock Creek and Montney formations. Our application of horizontal multi-stage drilling “Bonavista continually strives to maintain a low cost structure and a high degree of flexibility.” While this prolonged downturn in natural gas prices has negatively impacted our company and the industry directly, it has also created opportunities. Bonavista closed two strategic private company acquisitions totaling $173.9 million at attractive transaction metrics in 2011. These acquisitions overlapped nicely with our existing assets and base of operations within our West Central Alberta core region and will provide incremental growth opportunities for us in the years ahead. As a testament to our conservative financial management, we concurrently completed an equity financing of $192.0 million to support the incremental acquisition expenditures thereby maintaining our balance sheet strength and financial flexibility. Due to considerable volatility, Bonavista continually strives to maintain a low cost structure, a high degree of flexibility and the agility to respond to the ever changing industry conditions as we allocate capital to the highest rate of return projects. 04 BONAVISTA 2011 ANNUAL REPORT “Bonavista has delivered over $2.1 billion or $24.87 per share in cumulative dividends to our shareholders.” has increased significantly over the past five years, drilling 85% of our wells horizontally in 2011, up from only 4% in 2007. Furthermore, we’ve also expanded the scope of application beyond our five key plays by testing eight other emerging resource prospects in 2011 with encouraging results. To accommodate future anticipated production growth from our land base, we invested a total of $80.0 million in infrastructure assets in 2011, enhancing the capability of our gathering, compression and processing facilities. Complementing our exploration and development activity, we invested an additional $193.9 million on 23 synergistic property transactions within our core regions which included the two private company acquisitions for $173.9 million mentioned above. Divestitures of $30.4 million in non-core assets resulted in net acquisition and divestiture expenditures of $163.5 million for the year. We also acquired approximately 117,200 net acres of undeveloped land in 2011 for a total of $42.3 million, further enhancing our organic growth opportunities. 2011 Operating and Financial Results Our 2011 investment activities led to record production volumes of 69,332 boe per day representing a 5% increase over 2010 and increased proved and probable reserves by 11% to 344.7 mmboe. is highlighted by the following Reserves growth key metrics: in 2011 • • • Achieved attractive finding, development and acquisition costs, including changes in future development expenditures, of $18.22 per boe on a proved basis ($17.32 per boe excluding changes in future development expenditures) and $13.39 per boe on a proved and probable basis ($10.61 per boe excluding changes in future development expenditures); Attained a 2011 proved and probable operating netback recycle ratio of 1.8:1 as a result of this level of finding, development and acquisition costs, including future development capital (2.3:1 recycle ratio excluding future development costs); and Increased proved and probable future development capital by 15% to $1.1 billion, representing the significant development and growth potential on our asset base while remaining at a manageable level within two times trailing cash flow. Our low cost business model enabled us to efficiently convert our production into cash flow of $553 million ($3.44 per share) for the year. With a stable monthly dividend of $0.12 per share, we distributed $200.0 million ($1.44 per share) to our shareholders in 2011, or 36% of cash flow. Since inception as an in July 2003, Bonavista has delivered over energy trust $2.1 billion or $24.87 per share in cumulative dividends to our shareholders. The remainder of our cash flow has been profitably reinvested in the business growing production and reserves by approximately 90% and 220% respectively over the same time period. • Added 58.2 mmboe of proved and probable reserves, of which 48% were in the oil and liquids category; Financial Management • Replaced 2011 annual production by 230%; • Improved our proved and probable reserve life index to 12.2 years from 12.0 years in 2010; We believe the preservation of financial strength is crucial in today’s volatile commodity price environment. Bonavista is committed to maintaining a conservative capital structure with an appropriate balance between debt and equity. Supporting our $173.9 million acquisition of two private companies, 2011 ANNUAL REPORT 05 BONAVISTA the we preserved our financial flexibility by raising $192.0 million through an issue of seven million common shares. Additionally, we completed issue of US $150 million, 4.25%, 10 year senior unsecured notes bringing our total term debt to US$550 million, with an average term of approximately eight years. In the third quarter of 2011, we completed the extension to September 2015, of our $1 billion bank credit facility at lower borrowing rates. As at December 31, 2011, Bonavista had approximately $475 million of unused borrowing capacity. Subsequent to 2011, we initiated a dividend reinvestment program that has exhibited strong shareholder acceptance with a current 35% participation rate, and when coupled with our expected cash flow, will finance our 2012 capital budget and dividend requirements. Bonavista continuously strives to maintain balance sheet strength and long term sustainability through the alignment of our cash requirements with projected cash flow. Inventory Notwithstanding our considerable drilling activity, Bonavista’s inventory of future opportunities continues to improve both in quantity and quality. We currently own 3.0 million net acres of developed and undeveloped land on which we have identified “Bonavista completed an active capital program, drilling 143 wells with a remarkable 100% success rate… ” approximately 1,400 drilling locations. Driven by the efforts of our employees, Bonavista’s inventory of future drilling prospects has more than doubled over the past three years, and at the current pace of development, represents more than 10 years of 06 BONAVISTA 2011 ANNUAL REPORT drilling inventory. This inventory offers attractive economics in today’s commodity price environment with approximately 90% targeting high impact, unconventional resource prospects with a focus on light oil and liquids rich natural gas. As a result of our focus on profitability and the widening differential between natural gas and liquids pricing, we have designed our program whereby 100% of our drilling initiatives in 2012 will target oil or liquids rich prospects. Outlook Since our inception in 1997, we have witnessed many fluctuations in our business environment including significant commodity price volatility, a global credit crisis and economic recession and changes to our taxation and royalty regimes. Throughout this instability, Bonavista has continuously and purposefully adjusted to the environment while continuing to apply the same core strategies that have proven to add shareholder value over the long term. The pillar of these strategies is to continually exercise cost discipline and a high level of capital spending efficiency in pursuit of low to medium risk drilling prospects. Additionally we strive to identify and negotiate timely and strategic acquisition opportunities to complement our exploration and development program. In light of the continued erosion in natural gas prices, we have trimmed our 2012 capital budget resulting in expenditures of between of $340 to $360 million, net of $60 million in budgeted property dispositions. In addition to the properties sold to date in 2012, we have identified an additional $100 to $150 million of non-core assets that are presently being marketed for divestment. We have also reallocated the drilling program in favour of oil prospects given the significant disparity between crude oil and natural gas prices. The revised program will incorporate an increase in crude oil directed capital spending to approximately 45% of total drilling expenditures, which is an increase from our previous budget of 33%. We anticipate drilling between 125 and 135 wells, 100% of which will target oil and our highest return liquids rich natural gas prospects. Further, it is expected that any 2012 acquisition activity will be largely offset by a continuation of our disposition program of non-core assets. This capital program is expected to result in 2012 production volumes of between 73,000 and 75,000 boe per day and an increase in our year end 2012 oil and liquids weighting to 42% compared to 39% at the end of 2011. Overall, our long term business strategy will remain intact in 2012 with a commitment to deliver a balance of growth and income through our regular monthly dividend. Bonavista expects to finance its 2012 capital program and dividend with projected cash flow after considering the impact of our recently announced dividend reinvestment program, thus delivering on our sustainability objectives. As in years past, we will be attentive to changes in commodity prices and the business environment and will maintain flexibility with in order our capital expenditure plans to maximize shareholder value. to our exploration and In addition development program, our focus will be on complementary acquisition opportunities that offer accretive growth potential and enhance the operational efficiency of our core assets. We would like to thank our employees for their continued success in the execution of an efficient capital expenditure program in 2011. Our core philosophy and key operating strategies have proven to work well throughout all phases of the business cycle and we look forward to continually creating is very long-term value for our shareholders. Our team committed to this vision. Keith A. MacPhail Chairman and Chief Executive Officer Jason E. Skehar President and Chief Operating Officer March 26, 2012 “We believe the preservation of financial strength is crucial in today’s volatile commodity price environment.” 2011 ANNUAL REPORT 07 BONAVISTA Asset Base Overview Characteristics • Large contiguous land base offering year round access, close proximity to service providers and multi-zone opportunities. • Geologically diverse and geographically focused assets offering operational efficiencies. • Robust and balanced inventory of 1,400 future drilling locations, of which approximately 90% will be drilled horizontally. • Control of operations with an average working interest of 75%, and over 85% of production is operated by Bonavista. • Low cost structure with current operating costs of approximately $9.00 per boe and general and administrative expenses of $0.90 per boe. • Modest base decline rate of approximately 23% with an attractive proved plus probable reserve life index of 12.2 years. Key Plays BLUEBERRY MONTNEY PINE CREEK/ROSEVEAR MULTIZONE WEST CENTRAL CARDIUM HOADLEY GLAUCONITE 08 BONAVISTA 2011 ANNUAL REPORT 2012 Development Program • Remain sustainable at low natural gas prices - Divest non-core properties - Initiate dividend re-investment program • Maximize profitability and cash flow - Maximize capital allocation to drilling activities - Reallocate capital to oil development - Enhance natural gas liquids recoveries • Maintain flexibility as industry adjusts - Remain agile with changing commodity prices and cost structure environment - Potential to offset E&D expenditures with acquisition opportunities Inventory Type Hoadley Glauconite Liquids Rich Natural Gas West Central Cardium Light Oil Pine Creek/Rosevear Multi-zone Liquids Rich Natural Gas Blueberry Montney Liquids Rich Natural Gas Emerging Resource Plays Conventional/Heavy Oil Locations 2012 Drilling Program (wells) 380 100 95 60 595 170 35 - 40 27 - 30 7 - 9 2 - 4 38 - 40 14 TOTAL 1,400 125 - 135 $400M- 420M EXPLORATION AND DEVELOPMENT EXPENDITURES ($60M) ACQUISITION AND DIVESTITURE EXPENDITURES $340M- 360MNET CAPITAL BUDGET PRODUCTION GROWTH 73,000 - 75,000 100,000 87,500 75,000 62,500 50,000 ‘07 ‘08 ‘09 ‘10 boe/d ‘11 boe/d (5% growth) ‘12 ‘13 ‘14 ‘15 ‘16 ‘17 boe/d (7% growth) 2011 ANNUAL REPORT 09 BONAVISTA Key Play Highlights Hoadley Glauconite Liquids Rich Natural Gas Bonavista drilled 43 operated horizontal wells and participated in seven additional non-operated horizontal wells on the highly prospective Hoadley Glauconite trend. Our 2011 drilling program was largely focused on the south western region of the trend in an attempt to advance our understanding of the play’s geological scope and economic potential. In addition to our exploration and development initiatives, Bonavista continued to increase its prospective acreage in this industry leading liquids rich natural gas play. Through both asset and Crown land acquisitions, Bonavista added 29 sections of prospective Glauconite rights resulting in the addition of 57 drilling locations. Our drilling inventory has grown 27% over the past year to 380 horizontal locations despite our robust drilling activity in 2011. Bonavista invested approximately $45 million in facility and infrastructure assets in 2011 across the trend adding 70 mmcf per day of gathering and compression capacity to accommodate the anticipated growth from the area and enhance the full cycle economics of the play. These investments have improved the efficiency of our operations resulting in current operating costs of approximately $3.00 per boe and has led to a 17% increase in the average natural gas liquids yield to 70 bbls per mmcf, thereby improving the single well economics associated with our future development program. Resulting from the increase in average natural gas in production results, our estimated ultimate recovery per Glauconite location has increased from 440 mboe at year end 2010 to 480 mboe at year end 2011 resulting in an approximate 25% increase to the net present value at current strip prices. liquids yield and continued predictability Even with today’s low natural gas prices, single well economics remain competitive within our asset portfolio owing to the predictable results, attractive natural gas liquids yield, low operating costs and strong capital efficiencies associated with this play. Generating a 40 - 45% rate of return at current strip natural gas pricing, Bonavista’s Glauconite development program remains a key growth platform in 2012, with a forecasted drilling program of 35 to 40 horizontal wells. HOADLEY GLAUCONITE RESERVOIR 10 BONAVISTA 2011 ANNUAL REPORT GLAUCONITE PRODUCTION GROWTH boe/d 18,000 16,200 14,400 12,600 10,800 9,000 7,200 5,400 3,600 1,800 0 2008 2009 2010 2011 2012 125 miles West Central Cardium Light Oil Bonavista participated in the drilling of 27 horizontal wells targeting the unconventional Cardium light oil trend in the west central area of Alberta. Our operated development program in 2011 was focused in the Ferrier/Willesden Green area with three horizontal wells drilled delivering an average three month production rate of 415 boe per day per well including 300 bbls per day of oil and liquids. Bonavista further enhanced capital efficiencies in our Cardium development program in 2011 through a commitment to water- based completion techniques resulting in capital cost savings of approximately $400,000 per well. Bonavista has now drilled 54 horizontal Cardium wells since commencing our unconventional Cardium development program in the fourth quarter of 2009. Initial production rates and our estimate of recoverable reserves per well have increased meaningfully over this time frame by focusing our efforts in areas of greater reservoir quality and refining our drilling and completion techniques. To date, we have identified 100 horizontal locations across our land base of approximately 300 net sections of Cardium rights in central Alberta with the expectation this level will continue to grow as our understanding of the play increases. With the improvement in production results and strengthening oil prices, Bonavista has recently increased its 2012 Cardium capital program by 38% to $90 million, with a budget to drill between 27 and 30 horizontal wells. We will continue to focus our efforts in the Ferrier/Willesden Green area where we plan to drill 21 horizontal wells in pursuit of top quartile production results. We will also prudently test several other emerging opportunities on our land base in the Harmattan and Lochend areas. WEST CENTRAL CARDIUM TRENDS Pembina Ferrier/Willesden Green IMPROVING PRODUCTION RATES (BOE/d) 700 350 0 0 2012 TYPE CURVE 2011 2010 2009 1 2 3 4 5 6 7 8 9 10 11 12 110 miles Harmattan Lochend 2011 ANNUAL REPORT 11 BONAVISTA coupled with the low cost operating structure of this production stream offers attractive single well economics with rates of return of 45 - 50% at current strip pricing. We will continue to monitor the production performance of our 2011 program as we delineate our Rock Creek land base with two to four additional horizontal wells in 2012. Bonavista’s initial activities in this multi-zone area of the deep basin, characterized by our attractive land and infrastructure footprint in the Bluesky and Rock Creek plays, has offered an opportunity to gain operational experience and begin the evaluation of additional emerging plays. Over the past 18 months, Bonavista has assembled a 26 section land position at Fir which is prospective for liquids rich natural gas in the Montney formation. We anticipate drilling one horizontal well in 2012 to begin the delineation of this land position where offsetting competitor activity has demonstrated robust productivity. Pine Creek/Rosevear Multi-zone Liquids Rich Natural Gas Bonavista’s activities in the deep basin include the pursuit of liquids rich natural gas prospects primarily in the Bluesky formation at Pine Creek and the Rock Creek formation at Rosevear. The results of these development programs in 2011 delivered initial production rates that met or exceeded internal type curve estimates. Our first three horizontal Bluesky wells drilled at Pine Creek are on track to average 375 boe per day per well in their first year of production, generating 40 bbls per mmcf of natural gas liquids of which 40% is condensate. We have initiated our budgeted 2012 five well drilling program with production growth in our Pine Creek field to coincide with take-away capacity expansions scheduled for completion by the end of the first quarter in 2012. Liquid recovery enhancements undertaken at our Rosevear processing facility in 2011, coupled with a higher quality production stream has increased the natural gas liquids recovery rates in our Rock Creek program to 50 bbls per mmcf of which 55% is condensate. The associated revenue enhancement FIR MONTNEY PINE CREEK BLUESKY ROSEVEAR ROCK CREEK 115 miles 12 BONAVISTA 2011 ANNUAL REPORT BLUEBERRY MONTNEY Industry horizontal drilling activity Blueberry Montney Liquids Rich Natural Gas Throughout 2011, Bonavista gained significant confidence with the technical and economic merits of this emerging resource play. To the end of 2011, Bonavista has drilled four horizontal Montney wells at Blueberry, three of which are currently on production from the Upper Montney horizon. Average three month production rates of 420 boe per day include an average natural gas liquids yield of 100 bbls per mmcf, of which 50% is free condensate. Early in 2012, Bonavista drilled two additional Montney horizontal wells delineating our southern Blueberry acreage in both the Upper and Lower Montney horizons. Drilling operations were completed as planned and completion activities are currently underway. Bonavista holds 55 contiguous net sections of Montney rights in the Blueberry area, of which 100% are prospective for unconventional resource development in the Upper Montney horizon. Additionally, based on our technical work conducted to date and encouraging offsetting industry results, we consider the Lower Montney horizon to be prospective across approximately 65% of our land base. We are encouraged by the quality and profitability of this liquids rich Montney resource and anticipate drilling between two and four horizontal wells in 2012 to further delineate and evaluate this large resource play in its progression towards full scale development. 30 miles Additional Emerging Opportunities Bonavista drilled its first vertical Duvernay test in the fourth quarter of 2011. Thirty-three meters of the formation were cored and are currently being analyzed for geological and petrophysical parameters, organic richness and geomechanical properties. These results in conjunction with industry activities in the area will advance our understanding of this resource towards commercial development. Our exposure to the play in the greater Willesden Green area is over 400 net sections of which 75 are interpreted to be in the liquids rich natural gas fairway. In addition to the Duvernay formation, our technical teams continue to identify and evaluate additional emerging resource opportunities with a focus on tight sand and source rock prospects on, or in close proximity to, our extensive land base. We will be advancing some of these opportunities in 2012 with an initial focus on light oil or liquids rich natural gas in the Mannville, Viking, Second White Specks and Banff formations. 2011 ANNUAL REPORT 13 BONAVISTA Our Team At Work Brian Abt Michael Allardyce Andrew Auriat Jodi Batty John Bell Connie Black Daniel Boutin Komaljit Brar Gillian Brown Connie Browning Shad Busche Lisa Cambridge Amber Casey Stacey Chene Michelle Coish Thomas Cowan William Deagle Jevon Desautels Tyra Dolemo Hailey Doney Daniel Duriez Doug English Rochelle Estep Amber Forsythe Peggy Franke Jay Garcia Daniel Gaultier Harold Gold Cynthia Gray Brent Griffin Monty Guy Glenn Hamilton Mark Heddema Kari Herman Leonard Ho Kevin Howes Miles Hughes Bruce Jensen Scott Johnston Nimet Kanji Carla Kells Pam Knoll Jason Kube Don Lambert Brandon Leitch Wade Lillico Angela Longson Linda Mackow Faye Mak Diana Massot Andrew McCarrick Mike McLeod Collin Merritt Robert Moncrieff Robert Abofsky Kurt Albiez Kelly Ashdown Cheryl Barclay Robert Befus Chris Birt Cory Borle Amy Brandl Kenneth Brogan Duncan Browne Wendy Burlock John Cacka Brian Campbell Arnel Chavez Avery Clay David Cowan Clark Damer Caitlyn Depper Neil Dixon Bill Donaldson Ashley Duncan Duane Elliott Kendell Esau Barbara Foran Allen Fothergill Linda Gallot Robert Garnier Will Glass Nelson Gramlich Myrna Griffin Marina Gurieva Bryce Hames Lavonne Hartzler Colin Hennel Cory Hipkiss Scott Hogg Marty Hughes Jeffrey James Gayle Johnson Chris Kamphius Edward Katrusik Chris Kirby Breanne Kraft Jesse Lamb David Leeper Neil Liknes Rob Logan Donna MacKenna Glen Mak Ryan Mason Angus McCallum Stephen McKenzie Wayne Merkel Rick Moir Michelle Moore-Salisbury Barbara Moss Jeff Myers Barbara Niddrie Sean Padley Grant Paulsen Cheryl Piper Arzina Premji Carrie Ranger Darren Reid Ashley Roy Ronald Sather Donna Schuler George Seagrave Sarah Sellmann Jason Sherriffs Trevor Sieben Tony Smith Hank Spence Margaret Stafford Cory Stewart Holly Strong Darrell Talpash Tony Thomson Josh Toews Tam Tran Chris Turpin Kelly Vinnish Safia Wainse Jaret Wieler Tyler Winward Stanley Woo Byron Yip Martin Naundorf Donna Orbeck Gordon Parent Andy Pausch Theodore Plunkett Janelle Price Colin Ranger Lynda Robinson Angela Roy Derek Savage Joey Schwartz Sharon Seaman Megan Semark Angela Shewchuk Melissa Siqueira Todd Smith Christina Spence Bob Staniforth Carter Stickel Dan Sutherland Johannes Thiessen Jeff Tiessen Heather Toft Maggie Trinh Cathy Tyssen Eleanor Vokes Heather Walker Scott Wilhelm Craig Wisse Brent Woods Susan Yuen 14 BONAVISTA 2011 ANNUAL REPORT Sean Adair Larry Anderson Greg Balderston Donna Bauman Bonnie Bell Pam Bochulak Ernie Bradley Michael Breen Ryan Brown Fiona Buchholz Nicole Byrtus Scott Cameron Tod Cavalier Angelina Choo Sandi Cole Marilyn Crawford Cameron Deller Suhani Deshpande Bruce Donald Alex Donkin Markus Ebner Bernadette Enos Adam Fellows Darren Foster Cori Freeman Kerri Garcia Scott Gerber Rocky Good Ann Green Anita Gross Jen Haase Scott Hanson Deborah Helman Daniel Herman Craig Hoffman Sherry Huang Stephen Hughes Andrea Jensen Terry Jones Angela Karvelson Pamela Kelly Dean Kobelka Stacey Kurek Darren Larsen Dan Lem Mark Loades Kim Loupelle Angie MacLean Kenneth Maloney Jeff Mazurak David McDonald Garry McLeod Ellen Metzinger Tony Monteith Tom Mullane Fikerte Neguisse Randy Ostiguy Erik Parker Glen Perry Ronald Poelzer Cecilia Price-Jones William Rasmussen Donald Rodger Lonni Saken Erin Schira Bernie Schwindt Lucinda Sebbelov Kelly Sheppard Scott Shimek Jason Skehar Jessina Smith Brent Spice Mark Staples Kailee Stobart Shane Sypher Lisa Thompson Tara Timmer Stephanie Toft Charles Truchon-Fehler Catherine Underhill Greg Volk Erin Walter Tammy Willmer Rodney Wold Jason Wright Melanie Zesko Mona Ahmed Gloria Ang Stephen Banister Kent Beakley Linden Bennett Lindy Borggard James Brake Kristle Britton Peggy Brown Terry Burge Craig Byrtus Dustin Cameron Carrie Charlton David Christensen Darrel Cooper Georgina Crump Karen Demers Lyle Dietrich Shawna Donaldson Melanie Duan Yvonne Elias Sarah Erb Marc Fonteyne Tara Foster Brenda Gabel Louise Garneau Derek Gilliatt Sharmila Goswami Mark Grierson Dwayne Gullason Adrian Haggis Melissa Hartwell Mark Hendriks Shilo Hernandez Carolyn Hofstra Colleen Hughes Keith Ingstrup Maria Joaquin Audra Jones Sara Kast Kevin Kelts Stacey Kotelniski Diane Kyle Tyler Lawrence Wade Leonard Barb Logan Paige Luong Keith MacPhail Bill Marshall Mark McAuley Peter McIntosh Robert McNicol Stephen Michalsky Greg Moody Kevin Mullie John Nelson Wes Owen Steve Paul Ross Pickett Chantel Pottruff Peter Ranada Karlene Read Isabelle Rosen Tiffany Salat Dennis Schubert Jack Scown Greg Seefried Colby Sheppard Amro Shmoury Andrea Slabosz Shannon Spear-Kunetsky Darren Springinatic Leah Steffensen Renee Stokes Arnold Tacey Gerard Thompson Murray Tluchak Nicole Topic Joanna Tsui Kiley Vasilakos Dennis Wagstaff Arlene Wickham Joanne Winfield Tracey Woo Katie Yeung “We have strong and ethical leaders, a focused and talented staff, and a great environment in which to work.” “We are given as many opportunities as we desire to learn and grow, have great mentorship, and I have an amazing group of co-workers.” Highlights Financial ($thousands, except per share) Production revenues Funds from operations(1) Per share(1) (2) Dividends declared Per share Percentage of funds from operations(1) Net income (loss) Per share(3) Adjusted net income(4) Per share(3) Total assets Long-term debt, net of working capital(5) Long-term debt, net of adjusted working capital(4)(5) Shareholders’ equity Capital expenditures: Exploration and development Acquisitions, net Weighted average outstanding equivalent shares: (thousands)(3) Basic Diluted Operating (boe conversion – 6:1 basis) Production: Natural gas (mmcf/day) Natural gas liquids (bbls/day) Oil (bbls/day)(9) Total oil equivalent (boe/day) Product prices:(6) Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl)(9) Operating expenses ($/boe) General and administrative expenses ($/boe) Cash costs ($/boe)(7) Operating netback ($/boe)(8) Three months ended December 31, 2010 2011 % Change Years ended December 31, 2010 2011 % Change 285,167 150,843 0.91 51,850 0.36 34% (3,321) (0.02) 16,994 0.10 234,706 127,258 0.81 64,242 0.48 50% (66,784) (0.50) (51,028) (0.38) 21% 19% 12% (19%) (25%) (16%) 95% 96% 133% 126% 1,044,414 553,303 3.44 200,032 1.44 36% 137,184 0.85 139,383 0.87 3,924,160 1,131,715 938,726 526,987 3.44 252,298 1.92 48% 82,288 0.63 79,599 0.61 3,444,555 1,021,836 1,123,001 2,001,802 1,020,318 1,841,422 81,035 67,120 94,031 (39,801) (14%) 269% 453,550 163,521 348,062 220,514 165,355 165,355 133,783 133,783 24% 24% 160,712 161,787 131,075 131,493 268 14,628 14,110 73,373 3.69 58.78 89.36 9.26 0.95 13.16 24.75 250 12,387 14,304 68,307 4.08 45.15 71.85 7.88 0.87 12.30 22.98 7% 18% (1%) 7% (10%) 30% 24% 18% 9% 7% 8% 255 12,890 13,868 69,332 4.06 55.09 81.91 9.05 0.95 13.27 24.53 240 11,562 14,620 66,259 4.50 45.01 69.28 8.05 0.86 11.76 23.85 11% 5% - (21%) (25%) (12%) 67% 35% 75% 43% 14% 11% 10% 9% 30% (26%) 23% 23% 6% 11% (5%) 5% (10%) 22% 18% 12% 10% 13% 3% 2011 ANNUAL REPORT 15 BONAVISTA Highlights (cont’d) Drilling (gross wells): Natural gas Oil Average success rate Land: Undeveloped (net acres) Total (net acres) Reserves: (10) Proved: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) Proved and probable: Natural gas (bcf) Oil and natural gas liquids (mbbls) Total oil equivalent (mboe) % Proved producing % Proved % Probable Net present value of future cash flow before income taxes ($millions): 0% discount rate 5% discount rate 10% discount rate Reserve life index (years): Proved Proved and probable Finding, development and acquisition costs – proved and probable ($/boe): Including changes in future development expenditures Excluding changes in future development expenditures Recycle ratio – proved and probable: (11) Including changes in future development expenditures Excluding changes in future development expenditures December 31, 2011 143 67 76 100% December 31, 2010 140 77 61 99% 1,474,080 3,078,418 1,522,867 3,003,411 851.0 92,235 234,075 1,264.0 133,992 344,660 42% 68% 32% 9,766 6,184 4,472 8.8 12.2 13.39 10.61 1.8 2.3 840.4 83,695 223,756 1,177.4 115,578 311,811 45% 72% 28% 9,947 6,283 4,537 9.1 12.0 13.19 8.97 1.8 2.7 % Change 2% (13%) 25% 1% (3%) 2% 1% 10% 5% 7% 16% 11% (3%) (4%) 4% (2%) (2%) (1%) (3%) 2% 2% 18% - (15%) 16 BONAVISTA 2011 ANNUAL REPORT Share Trading Statistics ($per share, except volume) High Low Close Average Daily Volume – Shares Three months ended December 31, 2011 September 30, 2011 June 30, 2011 March 31, 2011 27.48 19.88 26.07 392,532 29.98 20.08 23.56 370,453 30.36 27.13 28.57 345,427 32.00 25.12 30.00 561,706 NOTES: (1) Management uses funds from operations to analyze operating performance, dividend coverage and leverage. Funds from operations as presented do not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculations of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Funds from operations per share is calculated based on the weighted average number of shares outstanding consistent with the calculation of net income per share. (2) Basic funds from operations per share calculations include exchangeable shares which are convertible to common shares on certain terms and conditions. For the comparative periods, exchangeable shares are included in the basic funds from operations per share calculation. (3) Basic net income per share calculations include exchangeable shares which are convertible to common shares on certain terms and conditions. For the comparative periods under the trust structure, exchangeable shares are excluded from the basic per share calculations in accordance with International Financial Reporting Standards. (4) Amounts have been adjusted to exclude unrealized gains or losses on financial instrument commodity contracts. (5) Amounts exclude convertible debentures, exchangeable shares and share-based compensation. (6) Product prices include realized gains or losses on financial instrument commodity contracts. (7) Cash costs equal the total of transportation, operating, general and administrative, and financing expenses. (8) Operating netback equals production revenues including realized gains or losses on financial instrument commodity contracts, less royalties, transportation and operating expenses, calculated on a boe basis. (9) Oil includes both conventional and heavy oil. (10) Company interest reserves are gross reserves prior to deduction of royalties and includes any royalty interests of Bonavista. (11) Recycle ratio is calculated using operating netback per boe divided by finding, development and acquisition costs per boe. 2011 ANNUAL REPORT 17 BONAVISTA Management’s Discussion and Analysis 18 BONAVISTA 2011 ANNUAL REPORT 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, 2011. The following MD&A of the financial condition and results of operations was prepared at, and is dated March 26, 2012. Basis of Presentation – The financial data presented below has been prepared in accordance with both the International Accounting Standards Board (“IASB”) and 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) expected royalty rate; (vi) anticipated operating and service costs; (vii) our financial strength; (viii) incremental development opportunities; (ix) reserve life index; (x) total shareholder return; (xi) growth prospects; (xii) asset disposition plans; (xiii) sources of funding, which are provided to allow investors to better understand our business. By their nature, forward-looking statements are subject to numerous risks and uncertainties; some of which are beyond Bonavista’s control, including the impact of general economic conditions, industry conditions, volatility of commodity prices, currency fluctuations, imprecision of reserve estimates, environmental risks, changes in environmental tax and royalty legislation, competition from other industry participants, the lack of availability of qualified personnel or management, stock market volatility and ability to access sufficient capital from internal and external sources. Readers are cautioned that the assumptions used in the preparation of such information, although considered reasonable at the time of preparation, may prove to be imprecise and, as such, undue reliance should not be placed on forward-looking statements. Bonavista’s actual results, performance or achievement could differ materially from those expressed in, or implied by, these forward-looking statements or if any of them do so, what benefits that Bonavista will derive there from. Bonavista disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as required by law. Non-IFRS Measurements – Within Management’s discussion and analysis, references are made to terms commonly used in the oil and natural gas industry. Management uses “funds from operations” and the “ratio of debt to funds from operations” to analyze operating performance and leverage. Funds from operations as presented does not have any standardized meaning prescribed by IFRS and therefore it may not be comparable with the calculation of similar measures for other entities. Funds from operations as presented is not intended to represent operating cash flow or operating profits for the period nor should it be viewed as an alternative to cash flow from operating activities, net income or other measures of financial performance calculated in accordance with IFRS. All references to funds from operations throughout this report are based on cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and interest expense. Basic funds from operations per share is calculated based on the weighted average number of common shares outstanding in accordance with International Financial Reporting Standards. For the comparative periods under the trust structure, exchangeable shares have been included in the basic funds from operations per share calculation. Operating netbacks equal production revenue and realized gains or losses on financial instrument commodity contracts, less royalties, transportation and operating expenses calculated on a boe basis. Total boe is calculated by multiplying the daily production by the number of days in the period. Management uses these terms to analyze operating performance and leverage. Operations – Bonavista’s exploration and development program for the year ended December 31, 2011 led to the drilling of 143 wells within our core regions with a success rate of 100%. This program resulted in 67 natural gas wells and 76 oil wells. Profitability continues to guide our exploration and development program which remains flexible to changes in commodity price, development risk and deliverability upside. Despite incurring cost pressures throughout the year due to a steady increase in industry activity, our exploration and development operations throughout the year and in the fourth quarter have resulted in favorable capital efficiencies driving strong production performance, healthy reserve additions and solid rates of return reinforcing our confidence in the predictability and repeatability of our extensive drilling inventory. 2011 ANNUAL REPORT 19 BONAVISTA Reserves – Reserve estimates have been calculated in compliance with the National Instrument 51-101 Standards of Disclosure (“NI 51-101”). Under NI 51-101, proved reserves are defined as reserves that can be estimated with a high degree of certainty to be recoverable with a target of a 90% probability that the actual reserves recovered over time will equal or exceed proved reserve estimates, while probable reserves are defined as having an equal (50%) probability that the actual reserves recovered will equal or exceed the proved and probable reserve estimates. In accordance with NI 51-101, proved undeveloped reserves have been recognized in cases where plans are in place to bring the reserves on production within a short, well defined time-frame. Proved undeveloped reserves often involve infill drilling into existing pools. Of the net present value of the Corporation’s reserves, 85% were evaluated by independent third party engineers, GLJ Petroleum Consultants Ltd. (“GLJ”) and Ryder Scott Company Canada (“Ryder Scott”) in their reports dated February 23, 2012 and February 24, 2012, respectively. The balance of approximately 15% of proved and probable net present value reserves were evaluated internally and reviewed by GLJ. The reserve estimates contained in the following tables represent Bonavista’s gross reserves as at December 31, 2011 and are defined under NI51-101, as our interest before deduction of royalties and without including any of our royalty interests. Reserves:(1)(4) Proved: Proved producing Proved non-producing Proved undeveloped Total proved Probable Total proved and probable Proved reserve life index, years(3) Proved and probable reserve life index, years(3) Natural Gas (MMcf) Light and Medium Oil (Mbbls) Heavy Oil (Mbbls) Natural Gas Liquids (Mbbls) Total Reserves(2) (Mboe) 516,623 26,911 294,962 838,496 407,658 1,246,155 24,208 849 7,284 32,341 10,815 43,156 4,882 904 431 6,217 2,580 8,797 29,927 1,228 22,298 53,453 28,291 81,744 145,122 7,466 79,173 231,760 109,629 341,390 8.8 12.1 (1) Bonavista’s gross reserves are based on the GLJ and Ryder Scott reserve reports dated February 23, 2012 and February 24, 2012 respectively, GLJ and Ryder Scott reserve estimates based on forecast prices and costs as of January 1, 2012. (2) 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. (3) Calculated based on the amount for the relevant reserve category divided by the 2012 production forecast. (4) Amounts may not add due to rounding. Reserve Reconciliation: Balance, December 31, 2010 Extensions and improved recovery Technical revisions Acquisitions Dispositions Economic factors Production Balance, December 31, 2011 Proved (Mboe) 222,921 18,674 3,073 13,809 (1,012) (642) (25,063) 231,760 Probable (Mboe) 87,828 14,993 (2,677) 9,744 (139) (119) - 109,629 Proved and Probable (Mboe) 310,749 33,667 396 23,553 (1,151) (761) (25,063) 341,390 Bonavista’s 2011 year-end proved reserves totalled 231.8 mmboe, a 4% increase compared to the 222.9 mmboe at year-end 2010. Furthermore, Bonavista’s proved and probable reserves increased by 10% to 341.4 mmboe when compared to the 310.7 mmboe at year-end 2010. Bonavista had proved positive reserve revisions of 3.1 mmboe which were primarily related enhanced liquid recoveries in our Hoadley Glauconite development. 20 BONAVISTA 2011 ANNUAL REPORT The following tables highlight both our proved and probable finding and development (“F&D”) costs and our proved and probable finding, development and acquisition (“FD&A”) costs: Proved and probable reserves (Mboe): Opening balance Discoveries and extensions Acquisitions and dispositions Revisions and economic factors Production Closing balance Finding and development costs: Total F&D expenditures ($ millions) Total F&D expenditures plus change in forecast future development costs ($ millions) Proved and probable F&D costs ($/boe) (1) Proved and probable three-year F&D costs ($/boe) (1) Finding, development and acquisition costs: Total FD&A expenditures ($ millions) Total FD&A expenditures plus change in forecast future development costs ($ millions) Proved and probable FD&A costs ($/boe) (1) Proved and probable three-year FD&A costs ($/boe) (1) (1) Amounts are calculated including the change in future development costs. 2011 2010 2009 310,749 33,667 22,402 (365) (25,063) 341,390 453.6 480.5 14.43 13.32 617.1 778.7 13.98 12.86 271,913 32,583 25,555 4,861 (24,163) 310,749 348.1 474.4 12.67 14.39 568.6 836.2 13.27 13.55 190,240 21,799 84,087 (4,061) (20,152) 271,913 202.7 223.5 12.60 16.57 832.7 1,220.7 11.99 14.09 Finding, development and acquisition costs in 2011, including changes in future capital expenditures, amounted to $19.15 per boe ($18.20 per boe before changes in future capital expenditures) on a proved basis and $13.98 per boe ($11.08 per boe before changes in future capital expenditures) on a proved and probable basis. Capital Efficiency: Operating netback ($/boe) (1) Total changes in capital expenditures: (excluding changes in future development costs) Proved and probable F&D costs ($/boe) (2) Recycle ratio (3) Proved and probable FD&A costs ($/boe) (2) Recycle ratio (3) Total changes in capital expenditures: (including changes in future development costs) Proved and probable F&D costs ($/boe) (2) Recycle ratio (3) Proved and probable FD&A costs ($/boe) (2) Recycle ratio (3) 2011 24.53 2010 23.85 13.62 1.8 11.08 2.2 14.43 1.7 13.98 1.8 9.30 2.6 9.03 2.6 12.67 1.9 13.27 1.8 2009 23.77 11.43 2.1 8.18 2.9 12.60 1.9 11.99 2.0 Three-Year Average 24.05 11.35 2.1 9.15 2.6 13.32 1.8 12.86 1.9 (1) Operating netback is calculated using production revenues including realized gains or losses on financial instruments commodity contracts less royalties, transportation and operating costs calculated on a per barrel of oil equivalent basis. (2) 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). (3) 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 generated an attractive recycle ratio of 1.8:1 for proved and probable reserves and 1.3:1 for proved reserves which includes revisions and changes in future development expenditures; excluding changes in future development expenditures, the proved and probable recycle ratio improved to 2.2:1 and the proved recycle ratio remained at 1.3:1. Additional reserves disclosure tables, as required under NI 51-101, are contained in Bonavista’s Annual Information Form that will be filed on SEDAR. 2011 ANNUAL REPORT 21 BONAVISTA Financial and operating highlights – The following is a summary of key financial and operating results for the respective periods noted: Three months ended December 31, Years ended December 31, 2011 2010 2011 2010 ($thousands, except per boe and share amounts where noted) Product prices: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Production: Natural gas (mmcf/d) Natural gas liquids (bbls/d) Oil (bbls/d) Total production (boe/d) Production revenues per boe Royalties per boe % of Production revenues Operating expenses per boe Transportation expenses per boe General and administrative expenses per boe Share-based compensation per boe Depreciation, depletion, amortization and impairment per boe Net finance costs per boe Deferred income taxes (recovery) per boe Net income (loss) per boe per share – basic Dividends declared per share Funds from operations per boe per share – basic 3.69 58.78 89.36 268 14,628 14,110 73,373 285,167 42.25 44,902 6.65 15.7% 62,486 9.26 11,488 1.70 6,392 0.95 6,402 0.95 100,967 14.96 8,892 1.32 5,446 0.81 (3,321) (0.49) (0.02) 51,850 0.36 150,843 22.56 0.91 4.08 45.15 71.85 250 12,387 14,304 68,307 234,706 37.35 35,071 5.58 14.9% 49,494 7.88 10,677 1.70 5,441 0.87 10,841 1.73 70,559 11.23 125,617 19.99 (24,747) (3.94) (66,784) (10.63) (0.50) 64,242 0.48 127,258 20.25 0.81 4.06 55.09 81.91 255 12,890 13,868 69,332 1,044,414 41.27 161,742 6.39 15.5% 229,072 9.05 40,581 1.60 24,146 0.95 17,282 0.68 313,475 12.39 60,419 2.39 57,149 2.26 137,184 5.42 0.85 200,032 1.44 553,303 21.92 3.44 4.50 45.01 69.28 240 11,562 14,620 66,259 938,726 38.82 143,507 5.93 15.3% 194,755 8.05 39,652 1.64 20,897 0.86 20,862 0.86 271,346 11.22 212,889 8.80 (11,253) (0.47) 82,288 3.40 0.63 252,298 1.92 526,987 21.79 3.44 Production – For the year ended December 31, 2011, total production increased 5% to 69,332 boe per day when compared to 66,259 boe per day for the same period a year ago, despite experiencing a loss of approximately 1,250 boe per day for the year related to turnaround activities. Natural gas production increased 6% to 255 mmcf per day in 2011 from 240 mmcf per day for the same period a year ago, while natural gas liquids production increased 11% to 12,890 bbls per day in 2011 from 11,562 bbls per day for the same period in 2010. Oil production decreased 5% to 13,868 bbls per day in 2011 from 14,620 bbls per day for the same period in 2010 largely due to the disposition of approximately 600 bbls per day late in the fourth quarter of 2010. For the fourth quarter of 2011, production increased 7% to 73,373 boe per day when compared to 68,307 boe per day for the same period a year ago. Natural gas production increased 7% to 268 mmcf per day in the fourth quarter of 2011 from 250 mmcf per day for the same period a year ago, while natural gas liquids production increased 18% to 14,628 bbls per day in the fourth quarter of 2011 from 12,387 bbls per day for the same period in 2010. Oil production decreased 1% to 14,110 bbls per day in the fourth quarter of 2011 from 14,304 bbls per day for the same period in 2010 despite the disposition of an oil weighted property as described above. 22 BONAVISTA 2011 ANNUAL REPORT 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, 2011 268 14,628 14,110 73,373 2010 250 12,387 14,304 68,307 2011 255 12,890 13,868 69,332 2010 240 11,562 14,620 66,259 Bonavista’s balanced commodity investment approach minimizes our dependence on any one product and has generated consistent results in the quarter. Our current production is approximately 73,000 boe per day, consisting of 60% natural gas, 20% natural gas liquids and 20% oil and our reserve life index (“RLI”) has been maintained at approximately 12 years. Production revenues – Production revenues for the year ended December 31, 2011 increased 11% to $1,044.4 million when compared to $938.7 million for the same period a year ago, largely due to higher realized oil and natural gas liquids pricing. For the year ended December 31, 2011, natural gas prices decreased 10% to $4.06 per mcf, when compared to $4.50 per mcf realized in the same period in 2010. Natural gas liquids price increased 22% to $55.09 per bbl for year ended December 31, 2011 from $45.01 per bbl for the same period in 2010. For the year ended December 31, 2011, oil price increased 18% to $81.91 per bbl, compared to $69.28 per bbl for the same period a year ago. For the fourth quarter of 2011, production revenues increased 21% to $285.2 million when compared to $234.7 million for the same period a year ago. This increase was due in part to a 7% increase in production volumes and a 13% increase in overall product pricing in the fourth quarter of 2011 as compared to the same period in 2010. In the fourth quarter of 2011, natural gas prices decreased 10% to $3.69 per mcf, when compared to $4.08 per mcf realized in the same period in 2010. Natural gas liquids price increased 30% to $58.78 per bbl from $45.15 per bbl for the same period in 2010. In the fourth quarter of 2011, oil price increased 24% to $89.36 per bbl, compared to $71.85 per bbl for the same period a year ago. The following table highlights Bonavista’s realized commodity pricing for the three months and years ended December 31: Natural gas ($/mcf): Production revenues Realized gains 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 on financial instrument commodity contracts Three months ended December 31, Years ended December 31, 2011 $3.57 0.12 3.69 58.78 58.78 90.96 (1.60) 89.36 42.25 0.12 $42.37 2010 $3.86 0.22 4.08 45.15 45.15 71.83 0.02 71.85 37.35 0.78 $38.13 2011 $3.91 0.15 4.06 55.09 55.09 83.19 (1.28) 81.91 41.27 0.31 $41.58 2010 $4.33 0.17 4.50 45.01 45.01 69.17 0.11 69.28 38.82 0.66 $39.48 Risk management activities – As part of our financial management strategy, Bonavista has adopted a disciplined commodity price risk management program. The purpose of this program is to stabilize funds from operations against volatile commodity prices and protect acquisition economics. Bonavista’s Board of Directors has approved a commodity price risk management limit of 60% of forecast production, net of royalties, primarily using costless collars. Our strategy of using costless collars limits Bonavista’s exposure to downturns in commodity prices, while allowing for participation in commodity price increases. 2011 ANNUAL REPORT 23 BONAVISTA For the year ended December 31, 2011, our risk management program on financial instrument commodity contracts resulted in a net gain of $4.8 million, consisting of a realized gain of $7.8 million and an unrealized loss of $2.9 million. The realized gain of $7.8 million consisted of a $14.3 million gain on natural gas commodity contracts and a $6.5 million loss on oil commodity contracts. For the same period in 2010, our risk management program on financial instrument commodity contracts resulted in a gain of $19.8 million, consisting of a realized gain of $16.1 million and an unrealized gain of $3.7 million. The realized gain of $16.1 million consisted of a $15.5 million gain on natural gas commodity contracts and a $600,000 gain on oil commodity contracts. For the fourth quarter of 2011, our risk management program on financial instrument commodity contracts resulted in a net loss of $26.3 million, consisting of a realized gain of $812,000 and an unrealized loss of $27.1 million. The realized gain of $812,000 consisted of a $2.9 million gain on natural gas commodity contracts and a $2.1 million loss on oil commodity contracts. For the same period in 2010, our risk management program on financial instrument commodity contracts resulted in a net loss of $16.1 million, consisting of a realized gain of $4.9 million and an unrealized loss of $21.0 million. The realized gain of $4.9 million is related entirely to a gain on natural gas commodity contracts. Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand but also by the relationship between the Canadian and United States dollar. Bonavista has attempted to mitigate a portion of its commodity price risk through the use of various financial instrument commodity contracts and physical delivery sales contracts. i) Financial instrument commodity contracts: As at December 31, 2011, Bonavista entered into the following costless collars to sell natural gas and oil as follows: Volume 20,000 gjs/d 11,000 bbls/d 11,000 bbls/d Average Price CDN$3.71 – CDN$4.48 – AECO CDN$83.41 – CDN$108.16 – WTI CDN$83.64 – CDN$108.66 – WTI Term April 1, 2012 – October 31, 2012 January 1, 2012 – June 30, 2012 July 1, 2012 – December 31, 2012 Subsequent to December 31, 2011, Bonavista entered into the following costless collar to sell oil as follows: Volume 500 bbls/d 1,500 bbls/d 1,500 bbls/d 1,000 bbls/d Average Price CDN$90.00 – CDN$115.90 – WTI CDN$90.83 – CDN$113.57 – WTI CDN$93.33 – CDN$113.50 – WTI CDN$92.50 – CDN$112.75 – WTI Term February 1, 2012 – December 31, 2012 March 1, 2012 – December 31, 2012 January 1, 2013 – June 30, 2013 July 1, 2013 – December 31, 2013 As at December 31, 2011, Bonavista entered into the following option contracts to manage its overall commodity exposure: Volume 25,000 mmbtu/d 1,000 bbls/d Price (US$0.41) CDN$105.00 Contract Term Basis Swap – NYMEX Sold Call – WTI January 1, 2012 – December 31, 2012 January 1, 2012 – December 31, 2012 Subsequent to December 31, 2011, Bonavista entered into the following options contracts to manage its overall commodity and electrical consumption exposure: Volume 10,000 mmbtu/d 1 mw/h Price US$2.94 – NYMEX CDN$68.00 – AESO Term April 1, 2012 – October 31, 2012 March 1, 2012 – December 31, 2012 24 BONAVISTA 2011 ANNUAL REPORT Financial instrument commodity contracts are recorded in the consolidated statements of financial position at fair value at each reporting period with the change in fair value being recognized as an unrealized gain or loss on the consolidated statements of income and comprehensive income. As at December 31, 2011, the fair market value recorded on the consolidated statement of financial position for these financial instrument commodity contracts was a net liability of $8.7 million, compared to a net liability of $5.8 million as at December 31, 2010. These financial instrument commodity contracts had the following gains and losses reflected in the consolidated statements of income and comprehensive income: Realized gains on financial instrument commodity contracts Unrealized gains (losses) on financial instrument commodity contracts 2011 $812 (27,109) $(26,297) 2010 $4,927 (21,024) $(16,097) 2011 $7,766 (2,935) $4,831 2010 $16,080 3,764 $19,844 Three months ended December 31, Years ended December 31, A $0.10 change in the price per thousand cubic feet of natural gas – AECO would have an impact of approximately $2.5 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2011. A $1.00 change in the price per barrel of oil – WTI would have an impact of approximately $1.8 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2011. ii) Physical purchase and sale contracts: As at December 31, 2011, Bonavista entered into the following physical contracts to sell natural gas as follows: Volume Average Price Term 5,000 mmbtu/d (US$0.45) – Basis Swap NYMEX January 1, 2012 – December 31, 2012 As at December 31, 2011, Bonavista entered into the following contracts to purchase electricity as follows: Volume 2 mw/h Average Price CDN$64.50 – AESO Term January 1, 2012 – December 31, 2012 Physical purchase and sale contracts are being accounted for as they are settled. Royalties – For the year ended December 31, 2011, royalties increased by 13% to $161.7 million from $143.5 million for the same period a year ago, largely attributable to higher oil and natural gas liquids royalties as a result of a 22% increase in oil pricing and an 18% increase in natural gas liquids pricing. In addition, royalties as a percentage of revenues (including realized gains and losses on financial instrument commodity contracts) for year ended December 31, 2011 increased to 15.4% compared to 15.0% in same period in 2010. The increase in royalty rates is largely due to the reasons indicated above. For the three months ended December 31, 2011, royalties increased by 28% to $44.9 million from $35.1 million for the same period a year ago, largely due to a significant increase in oil and natural gas liquids royalties offset by lower natural gas royalties the result of a 10% decrease in natural gas pricing. In addition, royalties as a percentage of revenues (including realized gains and losses on financial instrument commodity contracts) for the fourth quarter of 2011 increased to 15.7% compared to 14.6% realized in the same period in 2010 largely due to the reasons indicated above. 2011 ANNUAL REPORT 25 BONAVISTA The following table highlights Bonavista’s royalties by product for the three months and years ended December 31: Natural gas ($/mcf): Royalties % of revenues (1) Natural gas liquids ($/bbl): Royalties % of revenues (1) Oil ($/bbl): Royalties % of revenues (1) Three months ended December 31, Years ended December 31, 2011 0.31 8.5% 13.19 22.4% 14.95 16.7% 2010 0.37 9.0% 11.81 26.2% 10.05 14.0% 2011 0.31 7.7% 12.89 23.4% 14.25 17.4% 2010 0.44 9.7% 10.74 23.9% 11.21 16.2% (1) % of revenues include realized gains and losses on financial instrument commodity contracts. Operating expenses – Operating expenses for the year ended December 31, 2011 increased 18% to $229.1 million compared to $194.8 million for the same period a year ago, and on a per boe basis increased 12% to $9.05 per boe, from $8.05 per boe in the comparable period in 2010. Absolute and per unit operating costs have increased throughout 2011 as a result of significant turnaround activity and a continued increase in the demand for services. Furthermore, electricity costs have increased 50% in comparison to the same period in 2010 largely as a result of unexpected reduction in electrical generation capacity within Alberta. For the three months ended December 31, 2011 operating costs increased 26% to $62.5 million compared to $49.5 million for the same period a year ago and on a per boe basis increased 18% to $9.26 per boe, from $7.88 per boe in the comparable period in 2010 for similar reasons as stated above. The following table highlights Bonavista’s operating expenses by product for the three months and years ended December 31: Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) Three months ended December 31, Years ended December 31, 2011 $1.28 10.76 12.72 $9.26 2010 $1.10 9.03 10.67 $7.88 2011 $1.29 10.24 12.01 $9.05 2010 $1.13 9.05 10.82 $8.05 Transportation expenses – For the year ended December 31, 2011, transportation expenses increased 2% to $40.6 million compared to $39.7 million for the same period in 2010, and on a per boe basis decreased 3% to $1.60 per boe compared to $1.64 per boe. The decrease in transportation costs on a per boe basis is largely due to cost savings realized by entering into longer term natural gas transportation commitments, offset by higher costs associated with handling oil and natural gas liquids volumes. For the three months ended December 31, 2011, transportation expenses increased 8% to $11.5 million from $10.7 million in the same period of 2010 due largely to an 8% increase in oil and natural gas liquids volumes in addition to higher costs associated with handling these oil and natural gas liquids volumes. The following table highlights Bonavista’s transportation costs by product for the three months and years ended December 31: Three months ended December 31, Years ended December 31, 2011 $0.29 1.01 2.31 $1.70 2010 $0.33 0.55 1.90 $1.70 2011 $0.29 0.86 1.91 $1.60 2010 $0.31 0.54 1.88 $1.64 Natural gas ($/mcf) Natural gas liquids ($/bbl) Oil ($/bbl) Total ($/boe) 26 BONAVISTA 2011 ANNUAL REPORT General and administrative expenses – General and administrative expenses, after overhead recoveries, increased 16% to $24.1 million for the year ended December 31, 2011 from $20.9 million in the same period in 2010 and increased 17% to $6.4 million for the three months ended December 31, 2011 from $5.4 million in the same period in 2010. On a per boe basis, general and administrative expenses increased 10% for the year ended December 31, 2011 to $0.95 per boe from $0.86 per boe in the same period in 2010 and increased 9% to $0.95 per boe for the three months ended December 31, 2011 from $0.87 per boe in the same period in 2010. These increases are largely due to higher costs of personnel and head office premises required to manage our growing operations and our restructuring from a trust to a corporate entity. Our current rate of general and administrative expenses on a per boe basis remains among the lowest in our sector. In connection with its stock option and common share rights incentive plan and restricted share award and restricted common share incentive plan, Bonavista recorded a share-based compensation charge of $6.4 million and $17.3 million for the three months and year ended December 31, 2011, respectively, compared to $10.8 million and $20.9 million for the same periods in 2010. Depletion, depreciation, amortization and impairment expenses – Depletion, depreciation, amortization and impairment expenses increased 16% to $313.5 million which includes a $16.0 million impairment charge recorded in two natural gas weighted cash generating units for the year ended December 31, 2011 from $271.3 million for the same period in 2010. The increase in depletion, depreciation, amortization and impairment expense year over year is related to the impairment charge as described above and an increase in production volumes of which depletion is based upon. For the three months ended December 31, 2011, depreciation, depletion, amortization and impairment expenses increased 43% to $101.0 million from $70.6 million for the same period in 2010 largely due to the reasons described above. For the year ended December 31, 2011, the average charge increased 10% to $12.39 per boe ($11.75 per boe excluding impairment) from $11.22 per boe for the same period in 2010 and for the three months ended December 31, 2011, the average charge increased 33% to $14.96 per boe ($12.59 per boe excluding impairment) from $11.23 per boe for the same period a year ago. For the three months and year ended December 31, 2011, there was a goodwill impairment charge of $20.1 million related to two cash generating units which are natural gas weighted. For the three months and year ended December 31, 2010, there was a goodwill impairment charge of $10.0 million related to one cash generating unit which is natural gas weighted. Net finance costs – Net finance costs decreased 72% to $60.4 million for the year ended December 31, 2011 from $212.9 million for the same period in 2010. The decrease in net finance costs for 2011 compared to the same period in 2010 is largely attributed to a reclassification of the exchangeable shares to shareholders’ equity on conversion to a corporation on December 31, 2010. Net finance costs decreased 93% to $8.9 million for the three months ended December 31, 2011 from $125.6 million for the same period in 2010. This decrease occurred in the fourth quarter of 2011 for the same reasons as discussed above. As part of our financial management program, Bonavista mitigates its currency risk associated with its repayment of its US senior unsecured notes by utilizing foreign exchange forward contracts. In the third quarter of 2011, Bonavista entered into the following foreign exchange forward contracts to manage its currency risk associated with its repayment of its US senior unsecured notes: Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US$purchased forward US$purchased forward US$purchased forward Notional US$ $30,000,000 $53,300,000 $16,500,000 CDN$/US$ 0.995 0.995 0.995 A $0.01 change in CDN$/US$exchange rate would have an impact of approximately $619,000 on net income for those foreign exchange forward contracts in place as at December 31, 2011. Deferred income taxes – The provision for deferred income taxes increased to $57.1 million for the year ended December 31, 2011 from an income tax recovery of $11.3 million during the same period in 2010. For the three months ended December 31, 2011, the provision for deferred income taxes was $5.4 million compared to a recovery of $24.7 million for the same period in 2010. Under the previous Trust structure, the distributions made by the Trust were deductible in determining the Trust’s taxable income and accordingly reduced the overall provision for deferred income taxes for the three months and year ended December 31, 2010. The deferred income tax provision for 2011 is higher than the provision calculated using the expected rate as a result of the income tax treatment of foreign currency translation losses on long-term debt and non-deductible goodwill impairment. Bonavista made no cash payments on tax installments for the three months and year ended December 31, 2011 or for the comparative periods in 2010. 2011 ANNUAL REPORT 27 BONAVISTA Funds from operations, net income and comprehensive income – For the year ended December 31, 2011, Bonavista experienced a 5% increase in funds from operations to $553.3 million ($3.44 per share, basic) from $527.0 million ($3.44 per share, basic) for the same period in 2010. For the three months ended December 31, 2011, Bonavista experienced a 19% increase in funds from operations to $150.8 million ($0.91 per unit, basic) from $127.3 million ($0.81 per share, basic) for the same period in 2010. Funds from operations increased for the three months and year ended December 31, 2011 due to an increase in production volumes and higher oil and natural gas liquids prices. Net income and comprehensive income for the year ended December 31, 2011, increased 67% to $137.2 million ($0.85 per share, basic) from $82.3 million ($0.63 per share, basic) for the same period in 2010, largely due to the changes in the unrealized gains and losses on financial instrument commodity contracts and the treatment in accordance with IFRS of exchangeable shares under a trust structure. Net income and comprehensive income for the three months ended December 31, 2011, decreased 95% to a loss of $3.3 million ($0.02 loss per share, basic) from a loss of $66.8 million ($0.50 loss per share, basic) for the same period in 2010, largely due an increase in deferred income taxes as a result of our conversion from a trust to a corporation. The following table is a reconciliation of a non-IFRS measure, funds from operations, to its nearest measure prescribed by IFRS: Calculation of Funds From Operations: (thousands) Cash flow from operating activities Interest expense Decommissioning expenditures Changes in non-cash working capital Funds from operations Three months ended December 31, Years ended December 31, 2011 2010 2011 2010 $145,150 (8,454) 5,973 8,174 $150,843 $126,697 (10,956) 7,012 4,505 $127,258 $567,166 (41,922) 21,136 6,923 $553,303 $542,436 (28,272) 15,831 (3,008) $526,987 Capital expenditures – Capital expenditures for the year ended December 31, 2011 were $627.4 million, consisting of $453.6 million spent on exploration and development activities, $193.9 million spent on acquisitions, including the purchase of two private oil and natural gas companies, property dispositions of $30.4 million and $10.4 million spent on head office expenditures. For the same period in 2010, capital expenditures were $570.0 million, consisting of $348.1 million spent on exploration and development activities, $286.1 million spent on property acquisitions and property dispositions of $65.6 million. Capital expenditures for the three months ended December 31, 2011 were $148.4 million, consisting of $81.0 million spent on exploration and development activities, $80.0 million spent on property acquisitions including the purchase of a private oil and natural gas company, property dispositions of $12.9 million and head office expenditures of $211,000. For the same period in 2010 capital expenditures were $54.6 million, consisting of $94.0 million spent on exploration and development activities, property acquisitions of $381,000, property dispositions of $40.2 million and head office expenditures of $363,000. A significant increase in the demand for drilling and completion services has resulted in an overall increase in costs year over year, most notably in the fourth quarter of 2011. We will continue to monitor the situation carefully, making adjustments where appropriate, and will rely heavily on our relationships with our key service providers, that we have cultivated over the past 14 years. 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 Acquisitions Dispositions Head office expenditures Net capital expenditures 28 BONAVISTA 2011 ANNUAL REPORT Three months ended December 31, Years ended December 31, 2011 2010 2011 2010 $3,906 2,007 55,754 19,368 $81,035 80,004 (12,884) 211 $148,366 $2,113 2,251 70,456 19,211 $94,031 381 (40,182) 363 $54,593 $34,900 13,390 274,440 130,820 $453,550 193,878 (30,357) 10,361 $627,432 $71,444 11,898 199,669 65,051 $348,062 286,084 (65,570) 1,419 $569,995 Liquidity and capital resources – As at December 31, 2011, long-term debt including working capital (excluding associated assets and liabilities from financial instrument commodity contracts) was $1.1 billion with a debt to fourth quarter 2011 annualized funds from operations ratio of 1.9:1. Bonavista has significant flexibility to finance future expansions of its capital programs, through the use of its current funds generated from operations and its debt facilities. As at December 31, 2011, Bonavista had approximately $471.0 million of unused borrowing capacity from its $1.0 billion bank credit facility. On October 25, 2011, Bonavista and its syndicate of 11 domestic and international banks agreed to extend Bonavista’s bank credit facility to September 10, 2015, with no principal repayments required until then. The bank loan facility is a four year revolving facility and may at the request of Bonavista and the consent of the lenders, be extended on an annual basis beyond the existing term. In addition, the lenders may approve to increase the bank loan facility by $250 million on the participation of any existing or additional lenders. Under the terms of the 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 shareholders’ equity of the Corporation, in all cases calculated based on a rolling prior four quarters. In addition, on October 25, 2011, Bonavista issued US$150 million senior unsecured notes. These notes have a coupon rate of 4.25% and a term of 10 years and rank equally with Bonavista’s obligations under its bank credit facility and existing senior unsecured notes. In 2012, Bonavista has forecast a net capital program of between $340 and $360 million within its core regions. Bonavista intends on financing this capital program with a combination of funds from operations, it’s recently announced dividend reinvestment program and to the extent required, its existing bank credit facility. Our capital program is approximately 75% discretionary, providing us with the ability to make adjustments as required to maintain both our financial flexibility and a prudent level of debt. Shareholders’ equity - As at December 31, 2011, Bonavista had 165.4 million equivalent common shares outstanding. This includes 20.3 million exchangeable shares, which are exchangeable into 21.3 million common shares. The exchange ratio in effect at December 31, 2011 for exchangeable shares was 1.04906:1. As at March 26, 2012, Bonavista had 166.7 million equivalent common shares outstanding. This includes 20.1 million exchangeable shares, which are exchangeable into 21.4 million common shares. The exchange ratio in effect at March 26, 2012 for exchangeable shares was 1.06499:1. In addition, Bonavista has 5.9 million stock option and common share incentive rights outstanding at March 26, 2012, with an average exercise price of $25.33 per common share. Dividends – For the year ended December 31, 2011, Bonavista declared dividends of $200.0 million ($1.44 per share) compared to $252.3 million ($1.92 per share) in the same period in 2010. For the three months ended December 31, 2011, Bonavista declared dividends of $51.9 million ($0.36 per share) compared to $64.2 million ($0.48 per share) in the same period in 2010. Bonavista’s dividend policy is constantly monitored and is dependent upon its forecasted production, commodity prices, funds from operations, debt levels and capital expenditures. Within a dividend paying corporate structure, Bonavista is well positioned to provide our shareholders a combination of sustainable growth and meaningful income. While the proven underlying operating strategies of Bonavista will remain intact, our business model has been designed to deliver a minimum long-term total shareholder return of 10% per annum. Bonavista announces its dividend policy on a quarterly basis and confirms its dividend payment on a monthly basis. Dividends are determined 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. Our long-term objective is to distribute between 25% and 35% of funds from operations, which allows us to withhold sufficient funds to finance capital expenditures required to modestly grow our production base at current pricing. Our current dividend rate of $0.12 per share per month places us within this targeted level for the year assuming current strip prices are realized and current dividend reinvestment participation rates of approximately 35% are maintained. On December 13, 2011, Bonavista announced that it had adopted a dividend reinvestment plan (the “DRIP”). The DRIP allows eligible shareholders of Bonavista the option to reinvest their cash dividends into additional common shares of Bonavista, issued either from treasury at a five percent discount to the prevailing average market price or acquired through the facilities of the Toronto Stock 2011 ANNUAL REPORT 29 BONAVISTA Exchange at prevailing market rates with no discount. The implementation of the DRIP began in January 2012. Annual financial information – The following table highlights selected annual financial information for each of the three years ended December 31, 2011, 2010 and 2009: Years ended December 31, (thousands, except per share amounts) Consolidated Statement of Operations Information: Production revenues, net of royalties Funds from operations Per share – basic Per share – diluted Net income Per share – basic Per share – diluted Consolidated Balance Sheet Information: Total capital expenditures Total assets Working capital deficiency Long-term debt Shareholders’ equity Dividends declared 2011 2010 2009(1) $882,672 553,303 3.44 3.42 137,184 0.85 0.85 $627,432 3,924,160 (51,110) 1,080,605 2,001,802 200,032 $795,219 526,987 3.44 3.40 82,288 0.63 0.63 $569,995 3,444,555 (70,393) 951,443 1,841,422 252,298 $642,206 447,743 3.46 3.43 106,606 0.82 0.81 $833,844 3,092,129 (87,124) 832,138 1,723,583 217,965 (1) The comparative amounts for 2009 are representative of Canadian Generally Accepted Accounting Principles. Quarterly financial information – The following table highlights Bonavista’s performance for the eight quarterly periods ending on March 31, 2010 to December 31, 2011: Production revenues Net income (loss) Basic Diluted 2011 2010 Dec. 31 285,167 (3,321) (0.02) (0.02) Sept. 30 264,349 31,166 0.19 0.19 Jun. 30 256,100 77,318 0.49 0.49 Mar. 31 238,798 32,021 0.20 0.20 Dec. 31 234,706 (66,784) (0.50) (0.50) Sept. 30 222,656 24,695 0.18 0.18 Jun. 30 227,732 67,779 0.51 0.43 Mar. 31 253,632 56,598 0.45 0.45 Production revenues over the past eight quarters have fluctuated largely due to the volatility of commodity prices and increasing production volumes. Net income in the past eight quarters has fluctuated from a deficit of $66.8 million in the fourth quarter of 2010 to a high of $77.3 million in the second quarter of 2011. These fluctuations are primarily influenced by production volumes, commodity prices, realized and unrealized gains and losses on financial instrument contracts and marketable securities; gains and losses on foreign exchange; fluctuations due to the fair market value of exchangeable shares and share-based compensation; and future income tax recoveries associated with the reduction in corporate income tax rates. On December 31, 2010, Bonavista completed its conversion from an energy trust to a corporation, thus eliminating the fluctuations in net income due to changes in the fair market value of exchangeable shares and share-based compensation. 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 year end filings, that Bonavista’s disclosure controls and procedures are appropriately designed and operating effectively to provide reasonable assurance that material information relating to the issuer is made known to them by others within the Corporation. Internal control over financial reporting – Internal control over financial reporting is a process designed to provide reasonable assurance that all assets are safeguarded, transactions are appropriately authorized and to facilitate the preparation of relevant, reliable and timely information. A control system, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system is met. Management has assessed the effectiveness of Bonavista’s internal control over financial reporting as defined by National Instrument 52 109, Certification of Disclosure in Issuers’ Annual and Filings. Management has concluded that their internal control over financial reporting was effective as of December 31, 2011. There 30 BONAVISTA 2011 ANNUAL REPORT were no material changes to the internal controls over financial reporting during the year ended December 31, 2011. Adoption of International Financial Reporting Standards (“IFRS”) – These consolidated financial statements have been prepared in accordance with IFRS. An explanation of how the transition to IFRS has affected the reported consolidated financial position, financial performance and cash flows of the Corporation is provided in note 17. This note includes reconciliations of equity and total comprehensive income for comparative periods reported under Canadian GAAP (previous GAAP) to those reported for those periods, along with details of the IFRS 1 exemptions taken. The adoption of IFRS does not impact the underlying economics of Bonavista’s operations or its cash flows. New accounting standards – Bonavista has reviewed the new and revised accounting standards issued by the International Accounting Standard Board (“IASB”) as at December 31, 2011, but not yet effective for financial statements for annual periods beginning on or after January 1, 2011. The first standard IFRS 9, “Financial Instruments” is to be adopted for fiscal years beginning January 1, 2015 with the remaining standards to be adopted for fiscal years beginning January 1, 2013 with earlier adoption permitted. • • • • • IFRS 9, “Financial Instruments” – replaces the guidance in IAS 39 “Financial Instruments: Recognition and Measurement.” This standard eliminates the existing IAS 39 categories of held to maturity, available-for-sale and loans and receivables. IFRS 9 will require financial assets to be classified into two categories: amortized cost and fair value. IFRS 10, “Consolidated Financial Statements” supersedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities. IFRS 11, “Joint Arrangements” are classified into two types, either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting. IFRS 12, “Disclosure of Interest in Other Entities” combines the disclosure requirements for entities that have interest in subsidiaries, joint arrangements, associates as well as unconsolidated structured entities. 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. Bonavista does not plan to adopt these standards early and the extent of the impact on its consolidated financial statements have not been determined. Critical accounting estimates – The consolidated financial statements have been prepared in accordance with IFRS. A summary of the significant accounting policies are presented in note 2 of the Notes to the Consolidated Financial Statements. Certain Accounting policies are critical to understanding the financial condition and results of operations of Bonavista. a) b) Proved and probable oil and natural gas reserves – Reserve estimates are based on engineering data, estimated future prices, expected future rates of production and the timing of future capital expenditures, all of which are subject to interpretation and uncertainty. Bonavista expects that over time its reserve estimates will be revised either upward or downward depending upon the factors as stated above. These reserve estimates can have a significant impact on net income, as it is a key component in the calculation of depletion, depreciation and amortization, and also for the determination of potential asset impairments. Depreciation, depletion and amortization – Property, plant and equipment is measured at cost less accumulated depreciation, depletion and amortization. Bonavista’s oil and natural gas properties are depleted using the unit-of-production method over proved and probable reserves for each cash-generating unit (CGU). The unit-of-production method takes into account capital expenditures incurred to date along with future development capital required to develop both proved and probable reserves. 2011 ANNUAL REPORT 31 BONAVISTA c) d) e) Impairment – Bonavista assesses its property, plant and equipment for impairment when events or circumstances indicate that the carrying value of its assets may not be recoverable. If any indication of impairment exists, Bonavista performs an impairment test on the CGU which is the lowest at which there are identifiable cash flows. The determination of fair value at the CGU level again requires the use of judgements and estimates that include quantities of reserves and future production, future commodity pricing, development costs, operating costs and royalty obligations. Any changes in these items may have an impact on the fair value of the assets. Decommissioning liabilities – Bonavista estimates its decommissioning liabilities based upon existing laws, contracts or other policies. The estimated present value of our decommissioning obligations are recognized as a liability in the period in which they occur. The provision is calculated by discounting the expected future cash flows to settle the obligations at the risk-free interest rate. The liability is adjusted each reporting period to reflect the passage of time, with accretion charged to net income, any other changes whether it be changes in interest rates or changes in estimated future cash flows are capitalized to property, plant and equipment. Income taxes – The determination of Bonavista’s income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded. 32 BONAVISTA 2011 ANNUAL REPORT Management’s Report The Consolidated Financial Statements of Bonavista Energy Corporation and related financial information were prepared by, and are the responsibility of Management. The Consolidated Financial Statements have been prepared in accordance with International Financial Reporting Standards. The Consolidated Financial Statements and related financial information reflect amounts which must of necessity be based upon informed estimates and judgments of Management with appropriate consideration to materiality. The Corporation has developed and maintains systems of controls, policies and procedures in order to provide reasonable assurance that assets are properly safeguarded, and that the financial records and systems are appropriately designed and maintained, and provide relevant, timely and reliable financial information to Management. KPMG LLP are the external auditors appointed by the shareholders, and they have conducted an independent examination of the corporate and accounting records in order to express an Auditors’ Opinion on these Consolidated Financial Statements. The Board of Directors has established an Audit Committee. The Audit Committee reviews with Management and the external auditors any significant financial reporting issues, the Consolidated Financial Statements, and any other matters of relevance to the parties. The Audit Committee meets quarterly to review and approve the 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. Keith A. MacPhail Chairman and Chief Executive Officer Glenn A. Hamilton Senior Vice President and Chief Financial Officer Calgary, Alberta March 26, 2012 2011 ANNUAL REPORT 33 BONAVISTA 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, 2011, December 31, 2010 and January 1, 2010, the consolidated statements of income and comprehensive income, changes in equity and cash flows for the years ended December 31, 2011 and December 31, 2010, 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, 2011, December 31, 2010 and January 1, 2010, and its consolidated financial performance and its consolidated cash flows for the years ended December 31, 2011 and December 31, 2010 in accordance with International Financial Reporting Standards. Chartered Accountants Calgary, Canada March 26, 2012 34 BONAVISTA 2011 ANNUAL REPORT Consolidated Statements of Financial Position (thousands) Assets: Current assets: Accounts receivable Prepaid expenses Marketable securities Financial instrument commodity contracts Other assets Financial instrument contracts Property, plant and equipment Exploration and evaluation assets Goodwill Liabilities and Shareholders’ Equity: Current liabilities: Accounts payable and accrued liabilities Dividends payable Financial instrument commodity contracts Convertible debentures Exchangeable shares Share-based compensation Long-term debt Decommissioning liabilities Deferred income taxes Financial instrument commodity contracts Share-based compensation Shareholders’ equity: Shareholders’ capital Exchangeable shares Contributed surplus Deficit Commitments Notes December 31, 2011 December 31, 2010 January 1, 2010 $133,324 9,660 - 5,203 8,655 156,842 3,604 3,518,847 233,642 11,225 $3,924,160 $176,743 17,292 13,917 - - - 207,952 1,080,605 444,132 189,669 - - 1,446,804 585,754 32,092 (62,848) 2,001,802 $114,430 14,510 - 11,413 10,068 150,421 - 3,043,223 219,590 31,321 $3,444,555 $186,447 21,436 12,931 - - - 220,814 951,443 319,096 107,519 4,261 - 1,162,680 650,668 28,074 - 1,841,422 $104,912 16,912 6,322 5,626 6,539 140,311 - 2,726,326 179,747 41,321 $3,087,705 $157,019 19,937 15,169 38,856 479,136 8,468 718,585 832,138 294,635 117,784 - 4,577 1,533,919 - 123 (414,056) 1,119,986 $3,924,160 $3,444,555 $3,087,705 (4) (4) (8) (9) (9) (4) (12) (13) (14) (4) (11) (15) See accompanying notes to the consolidated financial statements. Approved on behalf of the Board of Directors of Bonavista Energy Corporation: Ian S. Brown Director Michael M. Kanovsky Director 2011 ANNUAL REPORT 35 BONAVISTA Consolidated Statements of Income and Comprehensive Income Years ended December 31, (thousands, except per share amounts) Revenues: Production Royalties Realized gains on financial instrument commodity contracts Unrealized gains (losses) on financial instrument commodity contracts Expenses: Operating Transportation General and administrative Restructuring costs Goodwill impairment Share-based compensation Gains on dispositions of property, plant and equipment Depletion, depreciation, amortization and impairment Income from operating activities Finance costs Finance income Net finance costs Income before taxes Deferred income taxes (recovery) Net income and comprehensive income Net income per share – basic Net income per share – diluted See accompanying notes to the consolidated financial statements. Notes 2011 2010 $1,044,414 (161,742) 882,672 7,766 (2,935) 4,831 887,503 229,072 40,581 24,146 - 20,096 17,282 (11,901) 313,475 632,751 254,752 86,171 (25,752) 60,419 194,333 57,149 $137,184 $0.85 $0.85 $938,726 (143,507) 795,219 16,080 3,764 19,844 815,063 194,755 39,652 20,897 736 10,000 20,862 (27,109) 271,346 531,139 283,924 228,008 (15,119) 212,889 71,035 (11,253) $82,288 $0.63 $0.63 (4) (4) (9) (8) (6) (6) (14) (11) (11) 36 BONAVISTA 2011 ANNUAL REPORT Consolidated Statements of Changes in Equity For the years ended December 31 (thousands) Balance as at January 1, 2010 Net income Issuance of equity, net of issue costs Issued on property acquisition Issued for cash on exercise of common share incentive rights Exercise of common share incentive rights Conversion of restricted share awards Exchangeable shares exchanged for common shares Dividends declared Reclassification of deficit Reclassification of share-based compensation Exchangeable shares issued pursuant to the Arrangement Balance as at December 31, 2010 (thousands) Balance as at December 31, 2010 Net income Issuance of equity, net of issue costs Issued on business acquisition Issued for cash on exercise of common share incentive rights Exercise of common share incentive rights Conversion of restricted share awards Share-based compensation expense Share-based compensation capitalized Exchangeable shares exchanged for common shares Dividends declared Balance as at December 31, 2011 Shareholders’ capital $1,533,919 - 166,661 675 20,395 6,049 2,397 16,650 - (584,066) - - $1,162,680 Exchangeable shares $- - - - - - - - - - - 650,668 $650,668 Shareholders’ capital $1,162,680 - 193,597 939 12,521 7,794 4,359 - - 64,914 - $1,446,804 Exchangeable shares $650,668 - - - - - - - - (64,914) - $585,754 Contributed surplus $123 - - - - - - - - - 27,951 - $28,074 Contributed surplus $28,074 - - - - (7,794) (4,359) 13,411 2,760 - - $32,092 Total Shareholders’ equity $1,119,986 82,288 166,661 675 20,395 6,049 2,397 16,650 (252,298) - 27,951 650,668 $1,841,422 Deficit $(414,056) 82,288 - - - - - - (252,298) 584,066 - - $- Total Shareholders’ equity Deficit $1,841,422 $- 137,184 137,184 193,597 - 939 - 12,521 - - - - - 13,411 - 2,760 - - - (200,032) (200,032) $(62,848) $2,001,802 See accompanying notes to the consolidated financial statements. 2011 ANNUAL REPORT 37 BONAVISTA Consolidated Statements of Cash Flows Notes 2011 2010 $137,184 $82,288 (8) (9) (7) (10) (7) 313,475 15,868 2,935 (11,901) 20,096 60,419 57,149 (21,136) (6,923) 567,166 191,506 152,214 - 12,521 (204,176) (41,182) 88,579 (116,605) 82,857 (172,944) (453,550) (19,806) 30,357 (10,361) - (23,719) (650,023) - - $- 271,346 20,862 (3,764) (27,109) 10,000 212,889 (11,253) (15,831) 3,008 542,436 167,648 409,301 (38,567) 20,395 (250,799) (27,193) 132,511 (409,301) 3,995 (229,721) (348,062) (55,688) 65,570 (1,419) 8,193 14,696 (546,431) - - $- Years ended December 31, (thousands) Cash provided by (used in): Operating Activities: Net income Adjustments for: Depletion, depreciation, amortization and impairment Share-based compensation Unrealized (gains) losses on financial instrument commodity contracts Gains on dispositions of property, plant and equipment Goodwill impairment Net finance costs Deferred income taxes (recovery) Decommissioning expenditures Changes in non-cash working capital items Financing Activities: Issuance of equity, net of issue costs Issuance of senior notes Repayment of convertible debentures 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 acquisitions Property dispositions Office equipment and leasehold improvements Proceeds on sale of marketable securities Changes in non-cash working capital items Change in cash Cash, beginning of year Cash, end of year See accompanying notes to the consolidated financial statements. 38 BONAVISTA 2011 ANNUAL REPORT Notes to the Consolidated Financial Statements For the year ended December 31, 2011 and 2010 and January 1, 2010 Structure of the Corporation and Basis of Presentation: The principal undertakings of Bonavista Energy Corporation, its predecessor Bonavista Energy Trust (the “Trust”) and its subsidiaries, (“Bonavista” or the “Corporation”), are to carry on the business of acquiring, developing and holding interests in oil and natural gas properties and assets. On December 31, 2010, the Trust effectively completed its conversion from a trust to a corporation pursuant to a plan of arrangement (the “Arrangement”) under Section 193 of the Business Corporations Act (Alberta) that was approved by securityholders at the Joint Special Meeting of Securityholders of the Trust and Bonavista Petroleum Ltd. on December 14, 2010. On December 31, 2010, the Trust and Bonavista Petroleum Ltd. were merged into the Corporation. Unitholders of the Trust received one common share of the Corporation for each trust unit held, in addition, exchangeable shareholders of Bonavista Petroleum Ltd. received 2.40917 exchangeable shares of the Corporation for each exchangeable share held. The Board of Directors and senior management of the Trust continued as the Board of Directors and senior management of the Corporation. In connection with the Arrangement, Bonavista assumed all of the obligations of the Trust in respect of the trust unit rights incentive plan (amended to the common share rights incentive plan) and the restricted trust unit incentive plan (amended to the restricted common share incentive plan). The Arrangement did not result in the acceleration of vesting of any such awards. Upon vesting, holders of these rights are entitled to receive common shares on the same terms and conditions that existed prior to the Arrangement. No new incentive awards will be granted in the amended plans. The stock option plan and restricted share award incentive plan of Bonavista were established for new stock options and incentive rights under the Corporation. These plans are functionally similar to their predecessor plans. The incentive plans are further outlined in note 11 of the notes to the consolidated financial statements of the Corporation. The Arrangement has been accounted for as a continuity of interests and accordingly, the consolidated financial statements for periods prior to the effective date of the Arrangement reflect the financial position, income and cash flows as if the Corporation had always carried on the business formerly conducted by the Trust. In these and future consolidated financial statements, Bonavista will refer to “common shares”, “shareholders”, “dividends” and “per share” which were formerly referred to as “trust units”, “unitholders”, “distributions” and “per unit” under the trust structure. Comparative amounts in these and future consolidated financial statements will reflect the history of the Trust. The consolidated financial statements of the Corporation as at, and for, the year ended December 31, 2010, which were prepared under Canadian generally accepted accounting principles (“GAAP”), are available through our filings on SEDAR at www.sedar.com or can be obtained from Bonavista’s website at www.bonavistaenergy.com. Bonavista’s principal place of business is located at 1500, 525 - 8th Avenue SW, Calgary, Alberta, Canada T2P 1G1. 1. Basis of preparation: a) Statement of compliance: The consolidated financial statements for the year ended December 31, 2011 and 2010 and the opening statement of financial position at January 1, 2010 have been prepared in accordance with International Financial Reporting Standards (“IFRS”). These are the Corporations first consolidated financial statements prepared in accordance with IFRS and IFRS 1 First-time Adoption of International Financial Reporting Standard has been applied. An explanation of how the transition to IFRS has affected the reported consolidated financial position, financial performance and cash flows of the Corporation is provided in note 17. The consolidated financial statements were authorized for issue by the Board of Directors of the Corporation on March 26, 2012. 2011 ANNUAL REPORT 39 BONAVISTA 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; ii) available-for-sale financial assets are measured at fair value; iii) liabilities for cash-settled share-based compensation are measured at fair market value; and iv) liabilities for exchangeable shares are measured at fair market value, prior to the conversion from a trust to a corporation. c) Functional and presentation currency: These consolidated financial statements are presented in Canadian dollars, which is the Corporation’s functional currency. d) Use of estimates and management judgements: The preparation of the consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingencies, if any, as at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the period. By their nature, 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. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected. Specifically, amounts recorded for depletion, depreciation, amortization and impairment, accretion, decommissioning liabilities, fair value measurements, share-based compensation, deferred income taxes, and amounts used in impairment tests for goodwill, inventory, exploration and evaluation assets, and property, plant and equipment are based on estimates. These estimates include oil and natural gas reserves, future oil, natural gas and natural gas liquids prices, future interest rates and future costs required to develop those reserves as well as other fair value assumptions. 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: Acquisitions on or after January 1, 2010 For acquisitions on or after January 1, 2010, the Corporation measures goodwill at the acquisition date as the fair value of the consideration transferred including the recognized amount of any non-controlling interests in the acquiree, less the net recognized amount (generally fair value) of the identifiable assets acquired and liabilities assumed, all measured as of the acquisition date. When the excess is negative, a bargain purchase gain is recognized immediately in profit or loss. The Corporation elects on a transaction-by-transaction basis whether to measure non-controlling interests at fair value, or at their proportionate share of the recognized amount of the identifiable net assets, at the acquisition date. Transaction costs, other than those associated with the issue of debt or equity securities, that the Corporation incurs in connection with a business combination are expensed as incurred. 40 BONAVISTA 2011 ANNUAL REPORT Acquisitions prior to January 1, 2010 As part of its transition to IFRS, the Corporation elected to restate only those business combinations that occurred on or after January 1, 2010. In respect of acquisitions prior to January 1, 2010, goodwill represents the amount recognized under the Corporation’s previous accounting framework of Canadian GAAP. i) Subsidiaries: Subsidiaries are entities controlled by the Corporation. 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. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated statements of financial position from the date that control commences until the date that control ceases. ii) Jointly controlled operations and jointly controlled assets: 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. iii) Transactions eliminated on consolidation: Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements. b) Foreign currency: Transactions in foreign currencies are translated to Canadian dollars at exchange rates at the dates of the transactions. 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 and receivables and deposits on the date that they are originated. All other financial assets (including assets designated at fair value through profit or loss) are recognized initially on the trade date at which the Corporation becomes a party to the contractual provisions of the instrument. The Corporation derecognizes a financial asset when the contractual rights to the cash flows from the asset expire, or it transfers the rights to receive the contractual cash flows on the financial asset in a transaction in which substantially all the risks and rewards of ownership of the financial asset are transferred. Any interest in transferred financial assets that is created or retained by the Corporation is recognized as a separate asset or liability. Financial assets and liabilities are offset and the net amount presented in the statement of consolidated financial position when, and only when, the Corporation has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously. The Corporation classifies non-derivative financial assets into the following categories: financial assets at fair value through profit or loss, held-to-maturity financial assets, loans and receivables and available-for-sale financial assets. Financial assets at fair value through profit or loss A financial asset is classified at fair value through profit or loss if it is classified as held for trading or is designated as such upon initial recognition. Financial assets are designated at fair value through profit or loss if the Corporation manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Corporation’s documented risk management or investment strategy. Attributable transaction costs are recognized in profit or loss as incurred. Financial assets at fair value through profit or loss are measured at fair value, and changes therein are recognized in the consolidated statement of income. 2011 ANNUAL REPORT 41 BONAVISTA 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. Financial assets and liabilities are offset and the net amount presented in the statement of consolidated financial position when, and only when, the Corporation has a legal right to offset the amounts and intends either to settle on a net basis or to realize the asset and settle the liability simultaneously. The Corporation classifies non-derivative financial liabilities into the other financial liabilities category. Such financial liabilities are recognized initially at fair value plus any directly attributable transaction costs. Subsequent to initial recognition, these financial liabilities are measured at amortized cost using the effective interest method. Other financial liabilities comprise loans and borrowings, bank overdrafts, and trade and other payables. Bank overdrafts that are repayable on demand and form an integral part of the Corporation’s cash management are included as a component of cash and cash equivalents for the purpose of the statement of cash flows. iii) Derivative financial instruments: The Corporation has entered into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices and foreign exchange rates. These instruments are not used for trading or speculative purposes. The Corporation has not designated its financial derivative contracts as effective accounting hedges, and thus not applied hedge accounting, even though the Corporation considers all commodity contracts and foreign exchange contracts to be economic hedges. Derivatives are recognized initially at fair value and are 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 exchange contracts. loss comprise of interest rate swaps and forward 42 BONAVISTA 2011 ANNUAL REPORT iv) Shareholders’ capital and Exchangeable shares: Common shares and exchangeable shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects. d) Exploration and evaluation assets and property, plant and equipment: i) Recognition and measurement: Pre-licence costs are recognized in the consolidated statement of income as incurred. Exploration and evaluation expenditures: Exploration and evaluation (“E&E”) costs, including the costs of acquiring licences and directly attributable general and administrative costs, initially are capitalized as either tangible or intangible E&E assets according to the nature of the assets acquired. The costs are accumulated in cost centres by well, field or exploration area pending determination of technical feasibility and commercial viability. E&E assets are assessed for impairment if: (i) sufficient data exists to determine technical feasibility and commercial viability; and (ii) 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 (“CGU”) for impairment testing. The cost of property, plant and equipment at January 1, 2010, the date of transition to IFRS, was determined by reference to geological locations and product split. When significant parts of an item of property, plant and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components). Gains and losses on dispositions of property, plant and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant and equipment and are recognized net within “gains (losses) on disposition of property, plant and equipment” in the consolidated statement of income. ii) Subsequent costs: Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. All other expenditures are recognized in profit or loss as incurred. Such capitalized oil and natural gas interests generally represent costs incurred in developing proved or proved plus probable reserves and bringing in or enhancing production from such reserves, and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant and equipment are recognized in the consolidated statement of income as incurred. iii) Depletion, depreciation and amortization: The net carrying amount of development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the year to the related proved and probable reserves, taking into account estimated future development costs necessary to bring those reserves into production. Future development costs are estimated taking into account the level of development required to produce the reserves. These estimates are reviewed by independent reserve engineers at least annually. Proved and probable reserves are estimated using independent reserve engineer reports and represent the estimated quantities of oil, natural gas and natural gas liquids, which geological, geophysical and engineering data demonstrate with a 2011 ANNUAL REPORT 43 BONAVISTA specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as proved and probable and a 50% statistical probability that it will be less. The equivalent statistical probabilities for the proven component of proved and probable reserves are 90% and 10%, respectively. Such reserves may be considered commercially producible if management has the intention of developing and producing them and such intention is based upon: a reasonable assessment of the future economics of such production; a reasonable expectation that there is a market for all or substantially all the expected oil and natural gas production; and evidence that the necessary production, transmission and transportation facilities are available or can be made available. Reserves may only be considered total proved plus probable if producibility is supported by either actual production or conclusive formation test. The area of reservoir considered proved includes (a) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, or both, and (b) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geophysical, geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of oil and natural gas controls the lower proved limit of the reservoir. Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are only included in the proved and probable classification when successful testing by a pilot project, the operation of an installed program in the reservoir, or other reasonable evidence (such as, experience of the same techniques on similar reservoirs or reservoir simulation studies) provides support for the engineering analysis on which the project or program was based. 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. Acquisitions prior to January 1, 2010: As part of its transition to IFRS, the Corporation elected to restate only those business combinations that occurred on or after January 1, 2010. In respect of acquisitions prior to January 1, 2010, goodwill represents the amount recognized under the Corporation’s previous accounting framework, Canadian GAAP. 44 BONAVISTA 2011 ANNUAL REPORT Acquisitions on or after January 1, 2010: For acquisitions on or after January 1, 2010, goodwill represents the excess of the cost of the acquisition over the net fair value of the identifiable assets, liabilities and contingent liabilities of the acquiree. When the excess is negative, it is recognized immediately in the consolidated statement of income. ii) Exploration and evaluation assets: Other intangible assets that are acquired by the Corporation, which have finite useful lives, are measured at cost less accumulated amortization and accumulated impairment losses. Subsequent expenditure is capitalized only when it increases the future economic benefits embodied in the specific asset to which it relates. Amortization is recognized in profit or loss on a straight-line basis over the estimated useful lives of other intangible assets, other than goodwill, from the date they were available for use. f) Impairment: i) Non-derivative financial assets: A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate. Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in the consolidated statement of income. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost the reversal is recognized in the consolidated statement of income. ii) Non-financial assets: The carrying amounts of the Corporation’s non-financial assets, other than E&E assets and deferred income tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. For goodwill and other intangible assets that have indefinite lives or that are not yet available for use an impairment test is completed each year. E&E assets are assessed for impairment when they are reclassified to property, plant and equipment, as oil and natural gas interests, and also if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets, the CGU. The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset. Value in use is generally computed by reference to the present value of the future cash flows expected to be derived from production of proved and probable reserves. The goodwill acquired in a business combination, for the purpose of impairment testing, is allocated to the CGUs that are expected to benefit from the synergies of the combination. 2011 ANNUAL REPORT 45 BONAVISTA An impairment loss is recognized if the carrying amount of an asset or its CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated first to reduce the carrying amount of any goodwill allocated to the units and then to reduce the carrying amounts of the other assets in the unit (group of units) on a pro rata basis. An impairment loss in respect of goodwill is not reversed. In respect of other assets, impairment losses recognized in prior years are assessed at each reporting date for any indications that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation or amortization, if no impairment loss had been recognized. g) Employee benefits: i) Share-based compensation: Long-term incentives are granted to officers, directors, employees and certain consultants in accordance with the Corporation’s stock option and restricted share award plans. The fair value of stock options is assessed on the grant date using the Black-Scholes option pricing model. The fair value is subsequently recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. Upon exercise of the options, consideration paid by the stock option holders and the value in contributed surplus pertaining to the exercised options are recorded as shareholders’ capital. The fair value of restricted share awards is assessed on the grant date factoring in the weighted average trading price of the five days preceding the grant date and forecasted dividends. This fair value is recognized as compensation expense over the vesting period with a corresponding increase in contributed surplus. Upon the forced vest of the restricted share awards into common shares on the predetermined dates, the value in contributed surplus pertaining to the share awards is recorded as shareholders’ capital. Under both incentive plans, forfeiture rates are assigned in the determination of fair value. Upon vest, the difference between estimated and actual forfeitures is adjusted through share-based compensation. ii) Short-term employee benefits: Short-term employee benefit obligations are measured on an undiscounted basis and 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. 46 BONAVISTA 2011 ANNUAL REPORT 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, 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; temporary differences related to investments in subsidiaries to the extent that it is probable that they will not reverse in the foreseeable future; and • taxable temporary differences arising on the initial recognition of goodwill. Deferred income taxes are measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred income tax assets and liabilities are offset if there is a legally enforceable right to offset current tax liabilities and assets, and they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis or their tax assets and liabilities will be realized simultaneously. 2011 ANNUAL REPORT 47 BONAVISTA A deferred income tax asset is recognized for unused tax losses, tax credits and deductible temporary differences, to the extent that it is probable that future taxable profits will be available against which they can be utilized. Deferred income tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized. n) Net income per share: Basic net income per share is calculated by dividing the profit or loss attributable to common shareholders of the Corporation by the weighted average number of common shares outstanding during the period. Diluted net income per share is determined by adjusting the profit or loss attributable to common shareholders and the weighted average number of common shares outstanding for the effects of dilutive instruments such as options granted to employees. 3. New accounting standards: Bonavista has reviewed the new and revised accounting standards issued by the International Accounting Standard Board (“IASB”) as at December 31, 2011, but not yet effective for financial statements for annual periods beginning on or after January 1, 2011. The first standard IFRS 9, “Financial Instruments” is to be adopted for fiscal years beginning January 1, 2015 with the remaining standards to be adopted for fiscal years beginning January 1, 2013 with earlier adoption permitted. • • • • • IFRS 9, “Financial Instruments” – replaces the guidance in IAS 39 “Financial Instruments: Recognition and Measurement.” This standard eliminates the existing IAS 39 categories of held to maturity, available-for-sale and loans and receivables. IFRS 9 will require financial assets to be classified into two categories: amortized cost and fair value. IFRS 10, “Consolidated Financial Statements” supersedes IAS 27 “Consolidation and Separate Financial Statements” and SIC-12 “Consolidation – Special Purpose Entities”. This standard provides a single model to be applied in control analysis for all investees including special purpose entities. IFRS 11, “Joint Arrangements” are classified into two types, either joint operations or joint ventures, each with their own accounting treatment. All joint arrangements are required to be reassessed on transition to IFRS 11 to determine their type to apply the appropriate accounting. IFRS 12, “Disclosure of Interest in Other Entities” combines the disclosure requirements for entities that have interest in subsidiaries, joint arrangements, associates as well as unconsolidated structured entities. 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. Bonavista does not plan to adopt these standards early and the extent of the impact on its Consolidated Financial Statements has not been determined. 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. 48 BONAVISTA 2011 ANNUAL REPORT The Corporation’s accounts receivable are with customers and joint venture partners in the oil and natural gas business and are subject to normal credit risks. Concentration of credit risk is mitigated by marketing production to numerous purchasers under normal industry sale and payment terms. The Corporation routinely assesses the financial strength of its customers. The Corporation may be exposed to certain losses in the events of non-performance by counterparties to financial instrument contracts. The Corporation mitigates this risk by entering into transactions with highly rated financial institutions. The carrying amount of accounts receivable represents the maximum credit exposure. As at December 31, 2011 Bonavista’s receivables consisted of $91.2 million of receivables from oil and natural gas marketers which has substantially been collected subsequent to December 31, 2011 and $39.6 million from joint venture partners of which $13.7 million has been subsequently collected. As at December 31, 2011 Bonavista has $11.6 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, 2011 and did not provide for any doubtful accounts during the year ended December 31, 2011. b) Liquidity risk: Liquidity risk is the risk that Bonavista will encounter difficulty in meeting obligations associated with the financial liabilities. The Corporation’s financial liabilities consist of accounts payable and accrued liabilities, dividends payable, financial instruments contracts, bank debt, and senior unsecured notes. Accounts payable consists of invoices payable to trade suppliers for office, field operating activities, and capital expenditures. Bonavista processes invoices within a normal payment period. Accounts payable and accrued liabilities have contractual maturities of less than one year. Dividends payable are declared on a monthly basis and are dependent upon a number of factors including current and future commodity prices, foreign exchange rates, our commodity hedging program, current operations and future investment opportunities. Financial instrument contracts have contractual maturities of less than two years on all commodity contracts and range from five to eleven years on foreign exchange hedge contracts. Bonavista’s four year revolving credit facility, as outlined in note 12, may at the request of the Corporation with the consent of the lenders, be extended on an annual basis beyond the existing term. The Corporation also has a series of senior unsecured notes outstanding, as outlined in note 12, which range in maturities from June 4, 2016 to November 2, 2022. The Corporation also maintains and monitors a certain level of cash flow, which is used to partially finance all operating, investing and capital expenditures. c) Commodity price risk: Commodity price risk is the risk that the fair value of future cash flows will fluctuate as a result of changes in commodity prices. Commodity prices for oil and natural gas are impacted not only by global economic events that dictate the levels of supply and demand but also by the relationship between the Canadian and United States dollar. Bonavista has attempted to mitigate a portion of the commodity price risk through the use of various financial instrument contracts and physical delivery sales contracts. The Corporation’s policy is to enter into commodity price contracts when considered appropriate to a maximum of 60% of net after royalty, forecasted production volumes, or in the case of electricity, 60% of Bonavista’s net consumption. 2011 ANNUAL REPORT 49 BONAVISTA i) Financial instrument contracts: As at December 31, 2011, Bonavista entered into the following costless collars to sell natural gas and oil as follows: Volume 20,000 gjs/d 11,000 bbls/d 11,000 bbls/d Average Price CDN$3.71 – CDN$4.48 – AECO CDN$83.41 – CDN$108.16 – WTI CDN$83.64 – CDN$108.66 – WTI Term April 1, 2012 – October 31, 2012 January 1, 2012 – June 30, 2012 July 1, 2012 – December 31, 2012 Subsequent to December 31, 2011, Bonavista entered into the following costless collar to sell oil as follows: Volume 500 bbls/d 1,500 bbls/d 1,500 bbls/d 1,000 bbls/d Average Price CDN$90.00 – CDN$115.90 – WTI CDN$90.83 – CDN$113.57 – WTI CDN$93.33 – CDN$113.50 – WTI CDN$92.50 – CDN$112.75 – WTI Term February 1, 2012 – December 31, 2012 March 1, 2012 – December 31, 2012 January 1, 2013 – June 30, 2013 July 1, 2013 – December 31, 2013 As at December 31, 2011, Bonavista entered into the following option contracts to manage its overall commodity exposure: Volume 25,000 mmbtu/d 1,000 bbls/d Price (US$0.41) CDN$105.00 Contract Term Basis Swap – NYMEX Sold Call – WTI January 1, 2012 – December 31, 2012 January 1, 2012 – December 31, 2012 Subsequent to December 31, 2011, Bonavista entered into the following options contracts to manage its overall commodity and electrical consumption exposure: Volume 10,000 mmbtu/d 1 mw/h Price US$2.94 – NYMEX CDN$68.00 – AESO Term April 1, 2012 – October 31, 2012 March 1, 2012 – December 31, 2012 Bonavista mitigates its risk associated with fluctuations in commodity prices by utilizing financial instrument commodity contracts. 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 $2.5 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2011. A $1.00 change in the price per barrel of oil – WTI would have an impact of approximately $1.8 million on net income for those financial instrument commodity contracts that were in place as at December 31, 2011. ii) Physical purchase and sale contracts: As at December 31, 2011, Bonavista entered into the following physical contracts to sell natural gas as follows: Volume Average Price Term 5,000 mmbtu/d (US$0.45) – Basis Swap NYMEX January 1, 2012 – December 31, 2012 As at December 31, 2011, Bonavista entered into the following contracts to purchase electricity as follows: Volume 2 mw/h Average Price CDN$64.50 – AESO Term January 1, 2012 – December 31, 2012 Physical purchase and sale contracts are being accounted for as they are settled. 50 BONAVISTA 2011 ANNUAL REPORT d) Foreign exchange risk: Commodity prices are largely denominated in US dollars and as a result the prices that Canadian producers receive is determined by the relationship between the US and Canadian dollar. In addition, Bonavista also has US denominated debt and interest obligations of which future cash payments are directly impacted by the exchange rate in effect on the due date. On July 21, 2011, Bonavista entered into an agreement with three financial intermediaries to purchase the following US dollars that coincide with Bonavista’s note repayment commitments: Forward date November 2, 2017 November 2, 2020 November 2, 2022 Contract US$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 $619,000 on net income for those foreign exchange forward contracts in place as at December 31, 2011. 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, 2011 would decrease by $4.6 million. Fair value of financial instruments: The fair value of the financial instruments carried on Bonavista’s consolidated balance sheet is classified according to the following hierarchy based on the amount of observable inputs used to value the 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 and convertible debentures have been classified as Level 1, financial instrument contracts, bank debt and senior unsecured notes are classified as Level 2. 2011 ANNUAL REPORT 51 BONAVISTA 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 contract(2) Current liabilities: Financial instrument commodity contract(2) Convertible debentures(1) Long-term liability: Financial instrument commodity contract(2) Net liabilities (1) Level 1 (2) Level 2 December 31, 2011 December 31, 2010 January 1, 2010 $- 5,203 3,604 13,917 - - $5,110 $- 11,413 - 12,931 - 4,261 $5,779 $6,322 5,626 - 15,169 38,856 - $42,077 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, 2011 is approximately $573.9 million (2010 - $383.0 million), compared to a carrying amount of $558.5 million (2010 - $398.1 million). 5. Capital management: The Corporation’s objective when managing capital is to maintain a flexible capital structure which allows it to execute its growth strategy through strategic acquisitions and expenditures on exploration and development activities while maintaining a strong financial position that provides our shareholders with stable dividends and rates of return. The Corporation considers its capital structure to include working capital (excluding associated assets and liabilities from financial instrument contracts), bank debt, senior unsecured notes and shareholders’ equity. Bonavista monitors capital based on the ratio of net debt to annualized funds from operations. The ratio represents the time period it would take to pay off the debt if no further capital expenditures were incurred and if funds from operations remained constant. This ratio is calculated as net debt, defined as outstanding bank debt, senior unsecured notes and working capital, divided by funds from operations for the most recent calendar quarter, annualized (multiplied by four). The Corporation’s strategy is to maintain a ratio of less than 2.0 to 1. This strategy is more restrictive than the existing financial covenants on both the Corporation’s bank credit facility and senior unsecured notes. This ratio may increase at certain times as a result of acquisitions or low commodity prices. As at December 31, 2011, Bonavista’s ratio of net debt to fourth quarter annualized funds from operations was 1.9 to 1 (2010 - 2.0 to 1), which is within the range established by the Corporation. The following table reconciles funds from operations to its nearest measured prescribed by IFRS, cashflow 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 52 BONAVISTA 2011 ANNUAL REPORT Three Months ended December 31, 2010 2011 $145,150 (8,454) 5,973 8,174 $150,843 $603,372 $126,697 (10,956) 7,012 4,505 $127,258 $509,032 In order to facilitate the management of this ratio, the Corporation prepares annual funds from operations and capital expenditure budgets, which are updated as necessary, and are reviewed and periodically approved by Bonavista’s Board of Directors. The Corporation manages its capital structure and makes adjustments by continually monitoring its business conditions, including: the current economic conditions; the risk characteristics of Bonavista’s oil and natural gas assets; the depth of its investment opportunities; current and forecasted net debt levels; current and forecasted commodity prices; and other factors that influence commodity prices and funds from operations, such as quality and basis differentials, royalties, operating costs and transportation costs. In order to maintain or adjust the capital structure, Bonavista will consider: its forecasted ratio of net debt to forecasted funds from operations while attempting to finance an acceptable capital expenditure program including acquisition opportunities; the current level of bank credit available from the Corporation’s lenders; the availability of other sources of debt with different characteristics than the existing bank debt; the sale of assets; limiting the size of the capital expenditure program; issuance of new equity if available on favourable terms; and its level of dividends payable to its shareholders. The Corporation’s shareholders’ capital is not subject to external restrictions, however, the Corporation’s bank credit facility and senior unsecured notes do contain financial covenants that are outlined in note 12 of the consolidated financial statements. 6. Finance costs and income: a) Finance costs: Finance costs: Interest on bank debt Interest on notes payable Interest on convertible debentures Accretion of decommissioning liabilities Foreign exchange loss Net change in fair value of financial derivatives Net change in fair market value of exchangeable shares Unrealized loss on financial instrument contracts Finance costs b) Finance income: Finance income: Gain on marketable securities Foreign exchange gain Unrealized gain on financial instrument contracts Finance income Years ended December 31, 2010 2011 $26,629 18,098 - 12,206 26,110 - - 3,128 $86,171 $23,205 3,807 1,302 11,801 - (289) 188,182 - $228,008 Years ended December 31, 2010 2011 $- (19,020) (6,732) $(25,752) $(1,871) (13,248) - $(15,119) The Corporation’s effective interest rate for the period ending December 31, 2011 was approximately 3.0% (2010 – 4.3%). 2011 ANNUAL REPORT 53 BONAVISTA 7. Supplemented cash flow information: Changes in non-cash working capital is comprised of: Source/(use) of cash: Accounts receivable Prepaid expenses Other assets Accounts payable and accrued liabilities, net of interest accrual Related to: Operating activities Investing activities 8. Property, plant and equipment: Years ended December 31, 2010 2011 $(5,714) 500 1,413 (26,841) $(30,642) $(6,923) (23,719) $(30,642) $(9,519) 2,402 (3,528) 28,349 $17,704 $3,008 14,696 $17,704 Costs: Balance as at January 1, 2010 Additions Acquisitions Transfers from exploration and evaluation Changes in decommissioning liabilities Disposals Balance as at December 31, 2010 Additions Acquisitions Transfers from exploration and evaluation Changes in decommissioning liabilities Disposals Balance as at December 31, 2011 Depletion, depreciation, amortization and impairment: Balance at January 1, 2010 Depletion, depreciation and amortization Disposals Balance as at December 31, 2010 Depletion, depreciation, amortization and impairment Disposals Balance as at December 31, 2011 Net book value as at December 31, 2011 Net book value as at December 31, 2010 Net book value as at January 1, 2010 Oil and natural gas properties Facilities Other assets Total $2,360,798 268,831 220,885 37,085 28,490 (35,192) $2,880,897 392,153 188,714 25,843 131,184 (30,344) $3,588,447 $- (249,203) 2,777 $(246,426) (288,489) 2,488 $(532,427) $3,056,020 $2,634,471 $2,360,798 $362,240 10,287 59,099 - - (5,695) $425,931 29,258 47,700 - - (8,757) $494,132 $- (21,202) 257 $(20,945) (22,741) 499 $(43,187) $450,945 $404,986 $362,240 $3,288 1,419 - - - - $4,707 10,361 - - - - $15,068 $- (941) - $(941) (2,245) - $(3,186) $11,882 $3,766 $3,288 $2,726,326 280,537 279,984 37,085 28,490 (40,887) $3,311,535 431,772 236,414 25,843 131,184 (39,101) $4,097,647 $- (271,346) 3,034 $(268,312) (313,475) 2,987 $(578,800) $3,518,847 $3,043,223 $2,726,326 For the year ended December 31, 2011, Bonavista capitalized $7.9 million (2010 – $7.4 million) of direct general and administrative expenses. For the year ended December 31, 2011, Bonavista recorded an impairment charge of $16.0 million (2010 – nil). The impairment charges have been recorded in three natural gas weighted CGU’s as a result of a weakening of the forward price curve for natural gas at January 1, 2012 as compared to January 1, 2011, as prepared by GLJ Petroleum Consultants. 54 BONAVISTA 2011 ANNUAL REPORT Year 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Remainder (1) WTI Oil (US$/bbl) AECO Gas (Cdn$/mmbtu) Cdn$/US$Exchange Rates 97.00 100.00 100.00 100.00 100.00 100.00 101.35 103.38 105.45 107.56 2.0% 3.49 4.13 4.59 5.05 5.51 5.97 6.21 6.33 6.46 6.58 2.0% 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 0.98 (1) Percentage change represents the change in each year after 2021 to the end of the reserve life. The recoverable amount was estimated based on discounted cashflows using proved plus probable reserves and discounted using a pre-tax discount rate of 10% (2010 – 10%). If an 8% pre-tax discount rate was used in estimating discounted cashflows, Bonavista would have recorded an impairment charge of nil (2010 – nil). If a 12% pre-tax discount rate was used in estimated discounted cashflows, Bonavista would have recorded an impairment charge of approximately $18.1 million (2010 – nil). 9. Goodwill and exploration and evaluation assets : (thousands) Cost: Balance as at January 1, 2010 Additions Acquisitions Dispositions Transfers to property, plant and equipment Impairment Balance as at December 31, 2010 Additions Acquisitions Dispositions Transfers to property, plant and equipment Impairment Balance as at December 31, 2011 Goodwill Exploration and evaluation assets $41,321 - - - - (10,000) $31,321 - - - - (20,096) $11,225 $179,747 71,444 6,092 (608) (37,085) - $219,590 34,900 7,499 (2,504) (25,843) - $233,642 E&E assets consist of the Corporation’s exploration projects which are pending the determination of proved or probable reserves. Additions represent the Corporation’s share of costs incurred on E&E assets during the year. For the year ended December 31, 2011, Bonavista recorded a goodwill impairment charge of $20.1 million (2010 – $10.0 million). The goodwill impairment charges have been recorded in two natural gas weighted CGU’s as a result of a weakening of the forward price curve for natural gas at January 1, 2012 as compared to January 1, 2011, as prepared by GLJ Petroleum Consultants. The recoverable amount was estimated based on discounted cashflows using proved plus probable reserves and discounted using a pre-tax discount rate of 10% (2010 – 10%). 2011 ANNUAL REPORT 55 BONAVISTA If an 8% pre-tax discount rate was used in estimating discounted cashflows, Bonavista would have recorded a goodwill impairment charge of approximately $14.0 million (2010 – $5.0 million). If a 12% pre-tax discount rate was used in estimating discounted cashflows, Bonavista would have recorded a goodwill impairment charge of $20.1 million (2010 – $14.0 million). 10. Acquisitions: a) On August 10, 2011, Bonavista acquired all of the issued and outstanding shares of a private oil and natural gas company in consideration for cash and common shares. In connection with the acquisition, Bonavista also received approximately $54.0 million of income tax attributes. Details of the acquisition are as follows: (thousands) Net assets acquired: Oil and natural gas properties Working capital Decommissioning liabilities Deferred income taxes Net assets acquired (thousands) Purchase consideration: Cash Common shares Total purchase consideration Amount $111,562 9,398 (2,125) (13,865) $104,970 $104,031 939 $104,970 In the period from August 10, 2011 to December 31, 2011 the acquisition contributed revenues of $14.9 million and net income of $8.0 million which are included in the consolidated statement of income for the year ended December 31, 2011. If the acquisition had occurred on January 1, 2011, management estimates that revenues would have increased by $39.3 million and net income would have increased by $21.0 million for the year ended December 31, 2011. b) On October 3, 2011, Bonavista acquired all the issued and outstanding shares of a private oil and natural gas company in consideration for cash. In connection with the acquisition, Bonavista also received approximately $38.9 million of income tax attributes. Details of the acquisition are as follows: (thousands) Net assets acquired: Oil and natural gas properties Working capital Decommissioning liabilities Deferred income taxes Net assets acquired (thousands) Purchase consideration: Cash Total purchase consideration Amount $92,384 (9,587) (657) (13,227) $68,913 $68,913 $68,913 In the period from October 3, 2011 to December 31, 2011 the acquisition contributed revenues of $3.7 million and net income of $2.1 million which are included in the consolidated statement of income for the year ended December 31, 2011. If the acquisition had occurred on January 1, 2011, management estimates that revenues would have increased by $18.0 million and net income would have increased by $10.3 million for the year ended December 31, 2011. 56 BONAVISTA 2011 ANNUAL REPORT c) On May 31, 2010, the Corporation acquired certain long-life natural gas weighted properties located in west central Alberta for a cash purchase price of $229.7 million. 11. Shareholders’ capital: The Corporation is authorized to issue an unlimited number of common shares without nominal or par value, an unlimited number of exchangeable shares without nominal or par value and 10,000,000 preferred shares, issuable in series. The holders of common shares are entitled to receive dividends as declared by the Corporation and are entitled to one vote per share. Dividends declared for the year ended December 31, 2011 was $1.44 per share (2010 - $1.92 per share). On December 13, 2011, Bonavista announced that it had adopted a dividend reinvestment plan (“DRIP”) that provides 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. The implementation of the DRIP began in January 2012. The exchangeable shares of Bonavista are exchangeable into common shares of the Corporation based on the exchange ratio, which is adjusted monthly, to reflect dividends paid on common shares. As a result, dividends are not paid on exchangeable shares. The holders of exchangeable shares are entitled to one vote times the exchange ratio for each exchangeable share. a) Issued and outstanding: (i) Common shares: (thousands) Balance as at January 1, 2010 Issued for cash Issued on property acquisition Issued on conversion of exchangeable shares Issued upon exercise of common share incentive rights Conversion of restricted share awards Issue costs, net of future tax benefit Share-based compensation Reduction of capital for reclassification of deficit Balance as at December 31, 2010 Issued for cash Issued on business acquisition Issued on conversion of exchangeable shares Issued upon exercise of common shares incentive rights Share-based compensation Issue costs, net of future tax benefit Conversion of restricted share awards Balance as at December 31, 2011 Number of Shares Amount 124,604 7,500 28 741 1,021 81 - - - 133,975 7,000 32 2,288 725 - - 78 144,098 $1,533,919 177,000 675 16,650 20,395 - (10,339) 8,446 (584,066) $1,162,680 199,850 939 64,914 12,521 12,153 (6,253) - $1,446,804 2011 ANNUAL REPORT 57 BONAVISTA (ii) Exchangeable shares: (thousands) Balance, beginning of year Exchanged for common shares Exchangeable shares issued pursuant to the Arrangement Balance, end of year Exchange ratio, end of year Common shares issuable on exchange Years ended December 31, 2011 2010 Number Amount Number Amount 22,593 (2,254) - 20,339 1.04906 21,337 $650,668 (64,914) - $585,754 - $585,754 - - 22,593 22,593 1.00000 22,593 $- - 650,668 $650,668 - $650,668 The holders of the Corporation’s exchangeable shares shall be entitled to notice of, to attend at, and to that number of votes equal to the number of exchangeable shares held multiplied by the exchange ratio in effect at the meeting record date at any meeting of the shareholders of Bonavista. In accordance with the provisions of the Corporation’s exchangeable shares, Bonavista may require, at any time, the exchange of that number of the Corporation’s exchangeable shares as determined by the Board of Directors on the basis of the exchange ratio in effect on the date set by Bonavista (the “Compulsory Exchange Date”). On and after the applicable Compulsory Exchange Date, the holders of the Corporation’s exchangeable shares called for exchange shall cease to be holders of such Corporation’s exchangeable shares and shall not be entitled to exercise any of the rights of holders in respect thereof, other than; (i) the right to receive their proportionate part of the common shares; and (ii) the right to receive any declared and unpaid dividends on such common shares. b) Share-based compensation: Bonavista has option and restricted share award programs that entitle officers, directors, employees and certain consultants to purchase and receive shares in the Corporation. The number of common shares awarded under all long-term incentive plans shall be limited to 8% of the aggregate number of issued and outstanding equivalent shares of the Corporation. (i) Stock option and common share incentive rights plans: Upon conversion to a corporation, the stock option plan of the Corporation was established and the common share rights incentive plan (formerly the trust unit rights incentive plan of the Trust) was amended. The amended plan provided that all rights to acquire trust units became rights to acquire common shares. The amended plan will remain in place until such time as all rights granted have been exercised or expired. The exercise price per common share is calculated by deducting from the grant price the aggregate of all dividends on a per common share basis made by the Corporation after the grant date. All new rights granted after December 31, 2010 are granted under the stock option plan. The incentive rights granted under the stock option plan vest over a three year period and expire three years after each vesting date, whereas rights granted under the amended common share rights incentive plan vest over a four year period and expire two years after each vesting date. 58 BONAVISTA 2011 ANNUAL REPORT The following tables summarize the stock option and common share incentive rights outstanding and exercisable under the plans at December 31, 2011: Balance as at January 1, 2010 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2010 Granted Exercised Expired and forfeited Reduction in exercise price Balance as at December 31, 2011 Exercisable as at December 31, 2011 Number of Common Share Incentive Rights 3,816,242 1,563,840 (1,021,017) (402,337) - 3,956,728 2,456,616 (725,197) (392,669) - 5,295,478 1,228,418 Weighted Average Exercise Price $21.28 23.13 (19.93) (20.86) (1.85) $20.28 27.53 (17.25) (25.81) (1.02) $22.65 $19.74 As at December 31, 2011 there are 2.3 million stock options outstanding (2010 – nil) with nil exercisable (2010 – nil) and 3.0 million common share incentive rights outstanding (2010 – 4.0 million) with 1.2 million exercisable (2010 – 952,000). The range of exercise prices of the outstanding stock option and common share incentive rights plans is as follows: Range of exercise prices $10.87 – 20.91 20.92 – 27.23 27.24 – 35.99 $10.87 – 35.99 Stock Options/Common Share Incentive Rights Outstanding Stock Options/Common Share Incentive Rights Exercisable Number outstanding 1,777,016 1,780,057 1,738,405 5,295,478 Weighted average remaining contractual life (years) 2.1 3.9 3.4 Weighted average exercise price $15.26 23.93 28.87 Number exercisable 700,424 184,128 343,866 Weighted average exercise price $14.78 21.38 28.96 3.2 $22.65 1,228,418 $19.74 (ii) Restricted share award incentive plan and restricted common share incentive plan: Upon the Trust’s conversion to a corporation, the Restricted Share Award Incentive Plan was established and the restricted common share incentive plan (formerly the restricted trust unit rights incentive plan of the Trust) was amended. The amended plan provided that all rights to acquire Trust Units became rights to acquire common shares. The amended plan will remain in place until such time as all rights granted have vested or been cancelled. All new rights granted after December 31, 2010 are granted under the Restricted Share Award Plan. Vesting arrangements are within the discretion of Bonavista’s Board of Directors, but all awards will vest within three years from the date of grant. On the vesting date, the holder will receive equivalent common shares for each share award, including dividends made on the common shares from the date of the grant to and including the vesting date, net of the statutory withholding tax. The fair value of restricted share awards is assessed on the grant date factoring in the weighted average trading price of the five days preceding the grant date and forecasted dividends. This fair value is recognized as share-based compensation expense over the vesting period with a corresponding increase to contributed surplus. Upon the forced vest of these awards, the fair value is moved from contributed surplus into shareholders’ capital. 2011 ANNUAL REPORT 59 BONAVISTA The following table summarizes the restricted share award incentive and restricted common share incentive plans outstanding at December 31, 2011: Balance as at January 1, 2010 Granted Exercised Forfeited Balance as at December 31, 2010 Granted Exercised Forfeited Balance as at December 31, 2011 197,896 163,855 (81,261) (31,938) 248,552 414,714 (135,578) (40,204) 487,484 As at December 31, 2011, there were 98,952 restricted common share rights outstanding (2010 – 248,552) and 388,532 restricted share awards outstanding (2010 – nil). As at December 31, 2011, the balance of contributed surplus attributable to the share-based compensation awards was $32.1 million (2010 – $28.0 million). Share-based compensation expense recognized in the year ended December 31, 2011 was $17.3 million(2010 – $20.9 million). 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 Convertible debentures Stock option and common share incentive rights Restricted share award incentive plan and restricted common share incentive rights Diluted equivalent shares Years ended December 31, 2010 2011 138,476 22,236 160,712 - 716 359 161,787 131,075 - 131,075 - 214 204 131,493 For the year ended December 31, 2010 the diluted equivalent shares excluded 435,000 common shares that would have been issued on the conversion of the convertible debentures as they are anti-dilutive. 60 BONAVISTA 2011 ANNUAL REPORT 12. Long-term debt: (thousands) Bank credit facility Senior unsecured notes Balance, end of year a) Bank credit facility: December 31, 2011 December 31, 2010 January 1, 2010 $524,963 555,642 $1,080,605 $555,348 396,095 $951,443 $832,138 - $832,138 On September 10, 2010, Bonavista combined and renewed its bank credit facilities into a single facility of $1.4 billion provided by a syndicate of 12 domestic and international banks with a maturity date of September 10, 2013. On March 3, 2011, Bonavista elected to reduce the committed amount of its bank credit facility by $400 million from $1.4 billion to $1.0 billion. On October 25, 2011, Bonavista renewed its bank credit facility of $1.0 billion provided by a syndicate of 11 domestic and international banks with a maturity date of September 10, 2015. This facility is an unsecured, covenant based, extendible revolving facility and includes a $50 million working capital facility. This facility provides that advances may be made by way of prime rate loans, bankers’ acceptances and/or US dollar LIBOR advances. These advances bear interest at the banks’ prime rate and/or at money market rates plus a stamping fee. This facility is a four year revolving credit and may, at the request of the 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. The weighted average interest rate under the bank credit facility was 3.4% for the year ended December 31, 2011 (2010 2.2%). 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 shareholders’ equity of the Corporation, in all cases calculated based on a rolling prior four quarters. b) Senior unsecured notes issued under a master shelf agreement: In the second quarter of 2010, the Corporation entered into an uncommitted master shelf agreement that allows for an aggregate draw of up to US$125 million in notes at a rate equal to the related US treasury rate corresponding to the term of the notes plus an appropriate credit risk adjustment at the time of issuance. On June 4, 2010 the Corporation drew down US$50 million on the master shelf agreement with a coupon rate of 4.86% with US$25 million maturing on June 4, 2016 and the remaining US$25 million maturing on June 4, 2017. Under the terms of the master shelf agreement, Bonavista has provided similar significant covenants that exist under the bank credit facility. 2011 ANNUAL REPORT 61 BONAVISTA c) Senior unsecured notes not subject to the master shelf agreement: On November 2, 2010 and October 25, 2011, Bonavista issued the following senior unsecured notes by way of a private placement. The significant covenants of the senior unsecured notes are the same as those under the bank credit facility. The terms and coupon rates of the notes are summarized below: Issued Date November 2, 2010 November 2, 2010 November 2, 2010 November 2, 2010 October 25, 2011 Principal CDN$50.0 million US $90.0 million US $160.0 million US $50.0 million US $150.0 million Coupon Rate 3.79% 3.66% 4.37% 4.47% 4.25% Maturity Date November 2, 2015 November 2, 2017 November 2, 2020 November 2, 2022 October 25, 2021 As at December 31, 2011, Bonavista is in compliance with all the covenants under its credit facilities. 13. Decommissioning liabilities: Bonavista’s decommissioning liabilities results from net ownership interests in oil and natural gas assets including well sites, gathering systems and processing facilities. The Corporation estimates the total undiscounted amount of expenditures required to settle its decommissioning liability is approximately $772.2 million (2010 – $776.0 million) which will be incurred over the next 30 years. A risk-free rate of approximately 2.5% (2010 – 4.1%) was used to discount this amount. 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 Balance, end of year Years ended December 31, 2010 2011 $319,096 12,206 16,202 3,717 (4,544) (21,136) 118,591 $444,132 $294,635 11,802 16,330 15,971 (7,972) (15,831) 4,161 $319,096 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 (loss) before taxes Current statutory income tax rate Income tax expense (benefit) at current statutory rate Loss on exchangeable shares Goodwill impairment Distributions to unitholders Effect of tax rate changes and rate variance Other Deferred income taxes (recovery) 62 BONAVISTA 2011 ANNUAL REPORT Years ended December 31, 2010 2011 $194,333 26.6% 51,693 - 5,337 - (3,942) 4,061 $57,149 $71,035 28.1% 19,961 52,890 2,811 (70,911) (19,893) 3,889 $(11,253) The net deferred income tax liability is comprised of the following: Deferred income tax liabilities: Capital assets in excess of tax value Partnership deferral Foreign exchange on long-term debt Deferred income tax assets: Decommissioning liabilities Non-capital losses Financial instruments contracts Debt issue costs Share issue costs Share-based compensation Marketable securities Deferred income tax liability December 31, 2011 December 31, 2010 January 1, 2010 $271,029 137,069 772 (111,300) (99,720) (1,732) 32 (5,865) (616) - $189,669 $185,092 91,998 1,660 (79,966) (83,580) (1,448) (11) (6,226) - - $107,519 $173,637 107,951 - (81,710) (69,973) (2,514) (113) (9,318) - (176) $117,784 A continuity of the net deferred income tax liability is detailed in the following tables: Balance January 1, 2010 (Asset)/Liability Recognized in profit and loss (Asset)/Liability Recognized in equity (Asset)/Liability Acquired in business combinations (Asset)/Liability Recognized in property, plant and equipment (Asset)/Liability Balance Dec. 31, 2010 (Asset)/Liability (thousands) Property, plant and equipment Decommissioning liabilities Non-capital losses Partnership deferral Financial instruments contracts Foreign exchange Debt issue costs Share issue costs Marketable securities (thousands) Property, plant and equipment Decommissioning liabilities Non-capital losses Partnership deferral Financial instruments contracts Foreign exchange Debt issue costs Share issue costs Share-based compensation $173,637 (81,710) (69,973) 107,951 (2,514) - (113) (9,318) (176) $117,784 $11,455 1,744 (13,607) (15,953) 1,066 1,660 102 2,104 176 $(11,253) $- - - - - - - 988 - $988 $- - - - - - - - - $- $- - - - - - - - - $- $185,092 (79,966) (83,580) 91,998 (1,448) 1,660 (11) (6,226) - $107,519 Balance Dec. 31, 2010 (Asset)/Liability Recognized in profit and loss (Asset)/Liability Recognized in equity (Asset)/Liability Acquired in business combinations (Asset)/Liability Recognized in property, plant and equipment (Asset)/Liability Balance Dec. 31, 2011 (Asset)/Liability $185,092 (79,966) (83,580) 91,998 (1,448) 1,660 (11) (6,226) - $107,519 $53,618 (30,637) (11,680) 45,071 (284) (888) 43 2,522 (616) $57,149 $- - - - - - - (2,091) - $(2,091) $32,319 (697) (4,460) - - - - (70) - $27,092 $- - - - - - - - - $- $271,029 (111,300) (99,720) 137,069 (1,732) 772 32 (5,865) (616) $189,669 2011 ANNUAL REPORT 63 BONAVISTA The following is a summary of Bonavista’s estimated tax pools: Canadian oil and gas property expense Canadian development expense Canadian exploration expense Undepreciated capital cost Non-capital losses Other Total December 31, 2011 $1,170,107 549,441 - 478,889 318,112 26,140 $2,542,689 December 31, 2010 $1,255,043 428,981 46,460 430,421 326,958 26,881 $2,514,744 January 1, 2010 $1,107,712 374,880 13,274 446,900 226,626 23,893 $2,193,285 Non-capital losses carry forward of $318.1 million (2010 – $327.0 million) expire in years 2027 through 2031. For the year ended December 31, 2011 and 2010 Bonavista paid no tax installments. 15. Commitments: The following is a summary of Bonavista’s commitments as at December 31, 2011: Payments Due by Year (thousands) Long-term debt repayments (1)(3) Interest payments (2)(3) Transportation expenses Office lease (4) Total contractual obligations Total 2012 2013 2014 2015 $1,074,963 187,061 52,060 52,849 $- 23,221 17,879 5,829 $- 23,221 14,693 5,829 $- 23,221 9,855 5,929 $524,963 22,910 4,185 6,068 2016 and thereafter $550,000 94,488 5,448 29,194 $1,366,933 $46,929 $43,743 $39,005 $558,126 $679,130 (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 2015. (2) Fixed interest payments on senior unsecured notes. (3) US dollars payments are converted using the exchange rate of $1.00 US/Canadian dollar. (4) Office lease expires July 31, 2020. 16. Supplemental disclosure a) Income Statement Presentation Bonavista’s statement of income is prepared primarily by nature of expense, with the exception of employee compensation costs which are included in both the operating and general and administrative expense line items. The following table details the amount of total employee compensation costs included in the operating and general and administrative expense line items in the statement of income. (thousands) Operating General and administrative Total employee compensation costs 64 BONAVISTA 2011 ANNUAL REPORT Years ended December 31, 2010 2011 $5,563 24,955 $30,518 $4,540 19,609 $24,149 b) Compensation of key management personnel: The remuneration of key management personnel of the Corporation during the year ended December 31 is as follows: (thousands) Short-term employee benefits Post-employment benefits Share-based payments Years ended December 31, 2010 2011 $2,277 756 2,230 $5,263 $2,092 17 2,440 $4,549 17. First time adoption of International Financial Reporting Standards: As stated in note 1 (a) these are the Corporations first consolidated financial statements prepared in accordance with IFRS. The accounting policies set out in note 2 have been applied in preparing the financial statements for the years ended December 31, 2011 and 2010 and in the preparation of our opening IFRS statements of financial position at January 1, 2010 the Corporations date of transition. In preparing its opening IFRS statements of financial position, the Corporation has adjusted amounts reported previously in financial statements prepared in accordance with Canadian GAAP. An explanation of how the transition from Canadian GAAP to IFRS has affected the Corporation’s financial position and financial performance is set out in the following tables and the notes that accompany the tables. The transition from Canadian GAAP to IFRS has not affected the Corporation’s cashflows. IFRS 1 First-time Adoption of International Financial Reporting Standards sets forth guidance for the initial adoption of IFRS. Under IFRS 1 the standards are applied retrospectively at the transitional balance sheet date with all adjustments to assets and liabilities recognized in retained earnings unless certain exemptions are applied. The Corporation has applied the following optional exemptions to its opening balance sheet dated January 1, 2010. • Certain oil and natural gas assets in property, plant and equipment on the statement of financial position were recognized and measured on a full cost basis in accordance with Canadian GAAP. The Corporation has elected to measure its properties at the amount determined under Canadian GAAP as at January 1, 2010. Costs included in the full cost pool on January 1, 2010 were allocated on a pro rata basis to the underlying assets on the basis of total proved plus probable reserve values as at January 1, 2010. Decommissioning liabilities were measured using a risk-free rate, with a corresponding adjustment recorded to opening retained earnings. • IFRS 3, “Business Combinations” has not been applied to acquisitions of subsidiaries or interests in joint ventures that occurred before January 1, 2010. 2011 ANNUAL REPORT 65 BONAVISTA Reconciliation of equity from Canadian GAAP to IFRS at the date of IFRS transition – January 1, 2010: Notes Canadian GAAP Effect of transition to IFRS IFRS $104,912 16,912 6,322 5,626 4,424 6,539 144,735 2,906,073 - 41,321 $3,092,129 $157,019 19,937 15,169 38,093 - - 1,641 231,859 832,138 160,314 144,235 - 1,531,299 59,295 13,319 119,670 1,723,583 $3,092,129 $- - - - (4,424) - (4,424) (179,747) 179,747 - $(4,424) $- - - 763 479,136 8,468 (1,641) 486,726 - 134,321 (26,451) 4,577 $104,912 16,912 6,322 5,626 - 6,539 140,311 2,726,326 179,747 41,321 $3,087,705 $157,019 19,937 15,169 38,856 479,136 8,468 - 718,585 832,138 294,635 117,784 4,577 2,620 (59,295) (13,196) (533,726) (603,597) $(4,424) 1,533,919 - 123 (414,056) 1,119,986 $3,087,705 (h) (a) (b) (f) (g) (h) (e) (h) (g) (k) (f) (l) (m) (thousands) Assets: Current assets: Accounts receivable Prepaid expenses Marketable securities Financial instrument commodity contracts Deferred income tax asset Other assets Property, plant and equipment Exploration and evaluation assets Goodwill Liabilities and Shareholders’ Equity: Current liabilities: Accounts payable and accrued liabilities Dividends payable Financial instrument commodity contracts Convertible debentures Exchangeable shares Share-based compensation Deferred income taxes Long-term debt Decommissioning liabilities Deferred income taxes Share-based compensation Shareholders’ equity: Shareholders’ capital Exchangeable shares Contributed surplus Retained earnings (Deficit) 66 BONAVISTA 2011 ANNUAL REPORT Reconciliation of equity from Canadian GAAP to IFRS as at December 31, 2010: (thousands) Assets: Current assets: Accounts receivable Prepaid expenses Financial instrument commodity contracts Other assets Deferred income tax asset Property, plant and equipment Exploration and evaluation assets Goodwill Liabilities and Shareholders’ Equity: Current liabilities: Accounts payable and accrued liabilities Dividends payable Financial instrument commodity contracts Deferred income taxes Long-term debt Decommissioning liabilities Deferred income taxes Financial instrument commodity contracts Shareholders’ equity; Shareholders’ capital Exchangeable shares Contributed surplus Retained earnings (Deficit) Notes Canadian GAAP Effect of transition to IFRS IFRS $114,430 14,510 11,413 10,068 3,241 153,662 3,148,005 - 41,321 $3,342,988 $186,447 21,436 12,931 2,860 223,674 951,443 168,423 117,579 4,261 1,737,077 57,286 14,292 68,953 1,877,608 $3,342,988 $- - - - (3,241) (3,241) (104,782) 219,590 (10,000) $101,567 $- - - (2,860) (2,860) - 150,673 (10,060) - (574,397) 593,382 13,782 (68,953) (36,186) $101,567 $114,430 14,510 11,413 10,068 - 150,421 3,043,223 219,590 31,321 $3,444,555 $186,447 21,436 12,931 - 220,814 951,443 319,096 107,519 4,261 1,162,680 650,668 28,074 - 1,841,422 $3,444,555 (h) (a) (b) (i) (h) (e) (h) (k) (f) (l) (m) 2011 ANNUAL REPORT 67 BONAVISTA Reconciliation of total comprehensive income for the year ended December 31, 2010: Notes Canadian GAAP Effect of transition to IFRS (thousands) Revenues: Production Royalties Realized gains on financial instrument commodity contracts Unrealized gains on financial instrument commodity contracts Expenses: Operating Transportation General and administrative Restructuring costs Goodwill impairment Share-based compensation Gains on disposition of property, plant and equipment Depletion, depreciation and amortization Income from operating activities Finance costs Finance income Net finance costs Income before income taxes Deferred income taxes (recovery) Net income and comprehensive income Net income per share – basic Net income per share – diluted $938,726 (143,507) 795,219 16,080 3,764 19,844 815,063 194,755 39,652 20,897 736 - 11,584 - 342,336 609,960 205,103 40,529 (15,119) 25,410 179,693 (21,888) $201,581 $1.32 $1.30 $- - - - - - - - - - - 10,000 9,278 (27,109) (70,990) (78,821) 78,821 187,479 - 187,479 (108,658) 10,635 $(119,293) $(0.69) $(0.67) (i) (g) (a) (c) (e)(f)(j) (h) IFRS $938,726 (143,507) 795,219 16,080 3,764 19,844 815,063 194,755 39,652 20,897 736 10,000 20,862 (27,109) 271,346 531,139 283,924 228,008 (15,119) 212,889 71,035 (11,253) $82,288 $0.63 $0.63 68 BONAVISTA 2011 ANNUAL REPORT Notes to Reconciliation: a) Property, Plant and Equipment (“PP&E”) – Bonavista’s PP&E assets were allocated to its CGUs unlike under Canadian GAAP where all oil and natural gas assets are accumulated into one cost centre. The deemed cost of Bonavista’s oil and natural gas assets were allocated to its defined CGUs based on Bonavista’s total proved plus probable reserve values as at January 1, 2010. These CGUs were aligned within the major geographic regions in which Bonavista operates and could change in the future as a result of significant acquisition and disposition activity. The following tables highlight the changes in property, plant and equipment and the impact on the consolidated statement of income and comprehensive income as a result of its transition from Canadian GAAP to IFRS. Consolidated statement of financial position (thousands) Decrease due to transfer of exploration and evaluation assets Adjustment required for recorded gains on disposition of property, plant and equipment Increase due to adjustment in depletion, depreciation and amortization Change in decommissioning liabilities Capitalization of share-based compensation Change in property, plant and equipment Consolidated statement of income and comprehensive income (thousands) Gain on disposition of property, plant and equipment Increase in retained earnings (deficit) As at January 1, 2010 As at December 31, 2010 $(179,747) - - - - $(179,747) $(219,590) 27,109 70,990 16,292 417 $(104,782) Year ended December 31, 2010 $(27,109) $27,109 b) Exploration and Evaluation (“E&E”) expenditures – Upon transition to IFRS, Bonavista reclassified all E&E expenditures that were included in the PP&E balance on the consolidated statement of financial position. This consisted of the carrying amount for Bonavista’s undeveloped land that related directly to exploration properties. E&E assets are not depleted and are assessed for impairment when indicators of impairment exist. Management identified and reclassified the following amounts from PP&E to E&E in the consolidated statement of financial position prepared under IFRS: Consolidated statement of financial position (thousands) Increase in exploration and evaluation assets As at January 1, 2010 As at December 31, 2010 $179,747 $219,590 c) Depletion expense – Bonavista has chosen to calculate its depletion using a reserve base of total proved plus probable reserves, as compared to using only proved reserves under Canadian GAAP. As a result, the depletion expense decreased as compared to its current calculation under Canadian GAAP. Consolidated statement of income and comprehensive income Year ended December 31, 2010 (thousands) Decrease in depletion, depreciation and amortization Increase in retained earnings (deficit) $(70,990) $70,990 The consolidated financial statements for the year ended December 31, 2010 includes an increase in depletion, depreciation and amortization in the amount of $22.1 million from that previously disclosed in the condensed consolidated interim financial statements for the three months ended March 31, 2011. 2011 ANNUAL REPORT 69 BONAVISTA d) e) Impairment of PP&E assets – Under IFRS, an impairment test of PP&E is performed at the CGU level as opposed to the entire PP&E balance, which was required under Canadian GAAP through the full cost ceiling test. Bonavista is required to recognize an impairment loss if the carrying amount of a CGU exceeds the higher of its fair value less cost to sell and value in use. Under Canadian GAAP, estimated future cash flows used to assess whether an impairment has occurred are not discounted. Decommissioning liabilities – Under IFRS, Bonavista remeasured its liability for asset retirement obligations using the risk- free rate of interest. IFRS requires that decommissioning liabilities be re-measured each reporting period for changes in the discount rate with a corresponding adjustment to the cost of property, plant and equipment. At December 31, 2010, Bonavista’s total of its decommissioning liabilities increased by $150.3 million to $321.5 million as the liability was revalued to reflect the estimated risk free rate of interest of 4.1% as compared to the credit adjusted risk-free rate of 7.5% used previously under Canadian GAAP. Consolidated statement of financial position (thousands) Increase in decommissioning liabilities Decrease in retained earnings (deficit) Change in decommissioning liabilities Consolidated statement of income and comprehensive income (thousands) Increase in finance costs As at January 1, 2010 As at December 31, 2010 $134,321 (134,321) $- $150,673 (134,381) $16,292 Year ended December 31, 2010 $60 f) Exchangeable shares – Under IFRS, exchangeable shares are considered to be a puttable financial instrument and are classified as a financial liability. They were recorded on the opening statement of financial position at their fair value. As at December 31, 2010, Bonavista’s liability associated with Bonavista Petroleum Ltd. exchangeable shares under IFRS was $493.6 million. On December 31, 2010 Bonavista completed its conversion from an energy trust to a corporation resulting in exchangeable shares being classified as equity under IFRS. Consolidated statement of financial position (thousands) Increase in fair market value of exchangeable shares-liability Increase in shareholders capital Changes in exchangeable shares – equity Decrease in retained earnings (deficit) As at January 1, 2010 As at December 31, 2010 $479,136 - (59,295) $(419,841) $- 14,640 593,382 $(608,022) Consolidated statement of income and comprehensive income Year ended December 31, 2010 (thousands) Increase in finance costs $188,182 70 BONAVISTA 2011 ANNUAL REPORT g) Share-based compensation – Under IFRS, Bonavista’s common share incentive rights and restricted common share incentive rights were considered to be cash-settled awards and were classified as a liability. The liability is measured at fair value with subsequent changes in the fair value recognized in the statement of comprehensive income. As at December 31, 2010, Bonavista’s liability associated with common share-based compensation under IFRS was $19.3 million. On December 31, 2010, Bonavista completed its conversion from an energy trust to a corporation resulting in share-based awards to be classified as equity under IFRS. Consolidated statement of financial position (thousands) Increase in fair market value of share-based compensation – current liability Increase in fair market value of share-based compensation – long-term liability Decrease in shareholders’ capital Changes in contributed surplus Changes in retained earnings (deficit) Capitalization of share-based compensation Consolidated statement of income and comprehensive income (thousands) Increase in fair market value of share-based compensation As at January 1, 2010 As at December 31, 2010 $8,468 $4,577 $- $(13,196) $151 $- $- $- $(5,046) $14,590 $(9,127) $417 Year ended December 31, 2010 $9,278 h) Deferred income taxes – Under IFRS, the Trust was required to calculate deferred income taxes using the undistributed profits rate of 39%. Under Canadian GAAP, the Trust was required to use the expected average tax rate for distributed profits of 25%. In addition, under IFRS, changes in net tax position arising from changes in tax rates are recorded outside of profit and loss if the original deferred income tax position was recorded outside of profit and loss. Under Canadian GAAP, all changes in net tax position arising from changes in tax rates are reflected in profit and loss. As at December 31, 2010 Bonavista recorded an overall decrease of $9.7 million to its deferred income tax liability upon transition to IFRS with the offset to accumulated earnings of $9.6 million and shareholder’s capital of $75,000. The overall decrease in deferred income tax liability is due to the adjustments to the opening balances of property, plant and equipment and decommissioning liabilities on transition to IFRS. Consolidated statement of financial position (thousands) Decrease in deferred income tax asset Decrease in deferred income taxes – current liability Decrease in deferred income taxes – long-term liability Increase in shareholders’ capital Increase in retained earnings As at January 1, 2010 As at December 31, 2010 $(4,424) $(1,641) $(26,451) $3,428 $20,240 $(3,241) $(2,860) $(10,060) $75 $9,604 Consolidated statement of income and comprehensive income Year ended December 31, 2010 (thousands) Increase in deferred income taxes $10,635 i) Goodwill – Under IFRS, goodwill is assigned to the appropriate CGU’s in which it was originally derived from. Goodwill is determined as the excess of the purchase price paid over the fair value of net assets acquired. Since goodwill results from the culmination of purchase accounting it is inherently imprecise and requires judgement in the determination of the fair value of assets and liabilities. Goodwill is tested for impairment annually and when circumstances indicate that the carrying value may be impaired. As such at December 31, 2010, Bonavista conducted an impairment test on its CGU’s after receiving its reserve report and it was determined that there was an impairment of $10.0 million on one of its CGU’s. 2011 ANNUAL REPORT 71 BONAVISTA Consolidated statement of financial position (thousands) Decrease in goodwill Consolidated statement of income and comprehensive income (thousands) Goodwill impairment Decrease in retained earnings (deficit) As at January 1, 2010 As at December 31, 2010 $- $(10,000) Year ended December 31, 2010 $10,000 $(10,000) j) Convertible debentures – Under Canadian GAAP, the convertible debentures issued in 2004 and redeemed in 2010, were treated as a compound instrument with a debt and equity component. The debt component of the debentures has been recorded net of the fair value of the conversion feature and issue costs. The fair value of the conversion feature of the debentures included in equity at the date of issue was $4.7 million. The issue costs are amortized to net income over the term of the obligation and the debt component of the obligation is adjusted for the amortization as well as for the portion of issue costs relating to conversions. The debt portion is accreted over the term of the obligation to the principal value on maturity with a corresponding charge to the consolidated statement of income. Under IFRS the convertible debenture is accounted for as a derivative instrument. A derivative is measured at fair value at each reporting date with changes in value being recorded in the consolidated statement of income. Consolidated statement of financial position (thousands) Changes in fair market value of convertible debentures – liability Decrease in shareholders’ capital Decrease in contributed surplus Changes in retained earnings As at January 1, 2010 As at December 31, 2010 $763 (808) - 45 $- $- - (808) 808 $- Consolidated statement of income and comprehensive income Year ended December 31, 2010 (thousands) Decrease in finance costs k) Shareholders’ capital Consolidated statement of financial position (thousands) Share-based compensation Deferred income taxes Exchangeable shares Convertible debentures Reduction of capital for reclassification of deficit $(763) As at January 1, 2010 As at December 31, 2010 $- 3,428 - (808) - $2,620 $(5,046) 75 14,640 - (584,066) $(574,397) 72 BONAVISTA 2011 ANNUAL REPORT l) Contributed surplus Consolidated statement of financial position (thousands) Share-based compensation Convertible debentures m) Retained earnings Consolidated statement of financial position (thousands) Share-based compensation Adjustment to depletion, depreciation and amortization Gains on disposition of property, plant and equipment Deferred income taxes Decommissioning liabilities Exchangeable shares Goodwill impairment Convertible debentures Reclassification of deficit As at January 1, 2010 As at December 31, 2010 $(13,196) - $(13,196) $14,590 (808) $13,782 As at January 1, 2010 As at December 31, 2010 $151 - - 20,240 (134,321) (419,841) - 45 - $(533,726) $(9,127) 70,990 27,109 9,604 (134,381) (608,022) (10,000) 808 584,066 $(68,953) 2011 ANNUAL REPORT 73 BONAVISTA This page left intentionally blank. Directors Keith A. MacPhail, Chairman and CEO Bruce W. Jensen, Vice President, Engineering Ian S. Brown, Independent Businessman Dean M. Kobelka, Vice President, Finance Michael M. Kanovsky, Sky Energy Corporation Wayne E. Merkel, Vice President, Exploration Engineering Consultants GLJ Petroleum Consultants Ltd. Ryder Scott Company Canada Calgary, Alberta Legal Counsel Burnet, Duckworth & Palmer LLP Calgary, Alberta Registrar and Transfer Agent Lynda J. Robinson, Vice President, Human Resources and Administration Hank R. Spence, Vice President, Operations Valiant Trust Company Calgary, Alberta Stock Exchange Listing Toronto Stock Exchange Trading Symbol “BNP” AGM Meeting Thursday, May 3, 2012, 3:00 pm, Calgary Petroleum Club – McMurray Room Grant A. Zawalsky, Corporate Secretary Auditors KPMG LLP, Chartered Accountants Calgary, Alberta Bankers Canadian Imperial Bank of Commerce The Toronto-Dominion Bank Bank of Montreal Royal Bank of Canada The Bank of Nova Scotia National Bank of Canada Alberta Treasury Branches HSBC Bank Canada Union Bank of California, N.A. (Canada Branch) Citibank, N.A. (Canadian Branch) Sumitomo Mitsui Banking Corporation of Canada Calgary, Alberta 1500, 525 – 8th Avenue SW, Calgary, Alberta T2P 1G1 Telephone: (403) 213-4300 Fax: (403) 262-5184 www.bonavistaenergy.com Harry L. Knutson, Nova Bancorp Inc. Margaret A. McKenzie, Range Royalty Management Ltd. Ronald J. Poelzer, Executive Vice President and Vice Chairman Christopher P. Slubicki, Independent Businessman Walter C. Yeates, Independent Businessman Officers Keith A. MacPhail, Chairman and CEO Jason E. Skehar, President and COO Ronald J. Poelzer, Executive Vice President and Vice Chairman Glenn A. Hamilton, Senior Vice President and CFO Thomas J. Mullane, Senior Vice President Johannes H. Thiessen, Senior Vice President Scott H. Hanson, Vice President, Production