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Press release from Marketwire

Crocotta Energy Inc. Year End 2011 Financial and Operating Results

Wednesday, March 28, 2012

Crocotta Energy Inc. Year End 2011 Financial and Operating Results06:00 EDT Wednesday, March 28, 2012CALGARY, ALBERTA--(Marketwire - March 28, 2012) - CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the year ended December 31, 2011, including consolidated financial statements, notes to the consolidated financial statements, and Management's Discussion and Analysis. All dollar figures are Canadian dollars unless otherwise noted.HIGHLIGHTSIncreased production 150% to 5,771 boepd in Q4 2011 from 2,307 boepd in Q4 2010 Decreased production expenses 25% to $7.05/boe in Q4 2011 from $9.44/boe in Q4 2010 Increased proved plus probable reserves 83% to 29.6 Mmboe in 2011 from 16.2 Mmboe in 2010 Drilled 11.7 net Bluesky wells at Edson, AB at a 100% success rate Increased funds from operations 116% to $30.6 million in 2011 from $14.2 million in 2010 Increased bank credit facility to $80.0 million from $55.0 million Raised gross proceeds of $61.0 million through two equity financings Reduced net debt during the year to $27.7 million from $35.2 million FINANCIAL RESULTS (1)Three Months Ended December 31Year Ended December 31($000s, except per share amounts)20112010% Change20112010% ChangeOil and natural gas sales20,3917,27418054,97434,53059Funds from operations (2)12,1154,20118830,60814,174116Per share - basic0.150.061500.390.2277Per share - diluted0.140.061330.380.2273Net earnings (loss)(7,052)655(1,177)(5,592)(5,328)5Per share - basic and diluted(0.09)0.01(1,000)(0.07)(0.08)(13)Capital expenditures36,80614,51115494,78628,634231Property dispositions(4,541)(28,532)(84)(14,552)(50,630)(71)Net debt (3)27,73635,200(21)Common shares outstanding (000s)Weighted average - basic81,73765,1422578,80465,12921Weighted average - diluted84,69965,5952981,16665,41224End of period - basic88,09565,14235End of period - diluted99,55872,54037(1) On January 1, 2011, the Company adopted International Financial Reporting Standards ("IFRS") for financial reporting purposes, using a transition date of January 1, 2010. Previously, the Company's financial statements were prepared under Canadian generally accepted accounting principles. As such, 2010 comparative results have been adjusted to conform to IFRS. Refer to note 22 of the consolidated financial statements for reconciliations of the impact of the change to IFRS.(2) Funds from operations and funds from operations per share do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details and the Funds from Operations section in the MD&A for a reconciliation from cash flow from operating activities.(3) Net debt includes current liabilities (including the revolving credit facility and excluding the current portion of decommissioning obligations) less current assets (excluding property, plant, and equipment, held for sale and risk management contracts). Net debt does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details.OPERATING RESULTS (1)Three Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeDaily productionOil and NGLs (bbls/d)1,8796471901,21474663Natural gas (mcf/d)23,3549,95813515,36710,48547Oil equivalent (boe/d)5,7712,3071503,7752,49451RevenueOil and NGLs ($/bbl)74.6061.042274.6962.7919Natural gas ($/mcf)3.493.97(12)3.904.56(14)Oil equivalent ($/boe)38.4034.271239.9037.945RoyaltiesOil and NGLs ($/bbl)9.3416.04(42)12.7017.47(27)Natural gas ($/mcf)0.11(0.15)1730.090.17(47)Oil equivalent ($/boe)3.493.83(9)4.465.93(25)Production expensesOil and NGLs ($/bbl)6.679.59(30)7.129.61(26)Natural gas ($/mcf)1.211.56(22)1.371.46(6)Oil equivalent ($/boe)7.059.44(25)7.859.01(13)Transportation expensesOil and NGLs ($/bbl)0.611.12(46)0.741.23(40)Natural gas ($/mcf)0.190.20(5)0.180.18-Oil equivalent ($/boe)0.971.18(18)0.951.13(16)Operating netback (2)Oil and NGLs ($/bbl)57.9834.296954.1334.4857Natural gas ($/mcf)1.982.36(16)2.262.75(18)Oil equivalent ($/boe)26.8919.823626.6421.8722Depletion and depreciation ($/boe)(14.87)(13.80)8(15.04)(14.39)5Asset impairment ($/boe)(25.79)(1.93)1,236(12.07)(7.85)54General and administrative expenses ($/boe)(3.60)(3.70)(3)(3.90)(3.97)(2)Share based compensation ($/boe)(1.87)(1.05)78(2.29)(1.04)120Finance expenses ($/boe)(0.83)(3.39)(76)(1.06)(3.77)(72)Finance income ($/boe)-5.99(100)0.101.50(93)Gain (loss) on sale of assets ($/boe)(7.32)(1.69)333(1.87)0.63(397)Deferred tax reduction ($/boe)14.103.093565.430.72654Realized gain (loss) on risk management contracts ($/boe)-0.10(100)-(0.69)(100)Unrealized gain (loss) on risk management contracts ($/boe)-(0.35)(100)-1.15(100)Net earnings (loss) ($/boe)(13.29)3.09(530)(4.06)(5.84)(30)(1) On January 1, 2011, the Company adopted International Financial Reporting Standards ("IFRS") for financial reporting purposes, using a transition date of January 1, 2010. Previously, the Company's financial statements were prepared under Canadian generally accepted accounting principles. As such, 2010 comparative results have been adjusted to conform to IFRS. Refer to note 22 of the consolidated financial statements for reconciliations of the impact of the change to IFRS. (2) Operating netback does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details. PRESIDENT'S MESSAGEAfter completing a transformation from conventional to unconventional, 2011 was a year of pure growth for Crocotta from all aspects of the business. Raising additional capital of over $60 million and spending over $80 million on capital programs resulted in a 282% increase in production from opening to exit, an 83% increase in reserves, and a reserve replacement of over 1,000%.Crocotta also focused on expanding its opportunity base with key farm-ins at Edson to secure additional Bluesky locations, starting to prove up the Cardium oil prospect on its large land base at Edson, and accumulating over 40 sections of land prospective for new light oil plays. In the Montney, Crocotta drilled a horizontal well that tested 14 mmcf/d and helped prove up the Dawson North area with 80 potential horizontal locations.Crocotta entered 2012 with strong production (6,500 boepd), significant financial flexibility, and several material projects to choose from. In Q1 2012, Crocotta has reacted to rapidly deteriorating natural gas prices by reducing capital allocated to gas projects and will focus its growth for Q2 2012 through Q3 2012 on the emerging Cardium oil play at Edson and on new plays developed over the previous 18 months. By expanding the emerging Cardium oil play at Edson and proving up new oil plays, Crocotta will not only significantly expand its overall development drilling inventory, but also significantly increase the oil weighting of that inventory. Natural gas prices and the fundamentals of the current market from a supply-demand perspective will be closely monitored through the summer to make capital decisions for Q4 2012 and beyond.Crocotta's current guidance calls for an average 7,350 boepd for the year. While we believe overall production guidance is achievable, the deterioration in natural gas prices and Crocotta's shift to oilier projects may result in a higher liquids percentage in our overall commodity mix than as released in our guidance.We look forward to updating our shareholders on all projects as they develop through 2012.MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")March 26, 2012The MD&A should be read in conjunction with the audited consolidated financial statements and related notes for the years ended December 31, 2011 and 2010. The audited consolidated financial statements and financial data contained in the MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") in Canadian currency (except where noted as being in another currency).DESCRIPTION OF BUSINESSCrocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in Western Canada. The Company trades on the Toronto Stock Exchange under the symbol "CTA".FREQUENTLY RECURRING TERMSThe Company uses the following frequently recurring industry terms in the MD&A: "bbls" refers to barrels, "mcf" refers to thousand cubic feet, and "boe" refers to barrel of oil equivalent. Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the MD&A. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.NON-GAAP MEASURESThis MD&A refers to certain financial measures that are not determined in accordance with IFRS (or "GAAP"). This MD&A contains the terms "funds from operations", "funds from operations per share", "net debt", and "operating netback" which do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. The Company uses these measures to help evaluate its performance.Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-GAAP measure and has been defined by the Company as net earnings (loss) plus non-cash items (depletion and depreciation, asset impairments, share based compensation, non-cash finance expenses, gains and losses on asset sales, deferred income taxes, and unrealized gains and losses on risk management contracts) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of earnings per share. Funds from operations is reconciled from cash flow from operating activities under the heading "Funds from Operations".Management uses net debt as a measure to assess the Company's financial position. Net debt includes current liabilities (including the revolving credit facility and excluding the current portion of decommissioning obligations) less current assets (excluding property, plant, and equipment, held for sale and risk management contracts).Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback, which is calculated as average unit sales price less royalties, production expenses, and transportation expenses, represents the cash margin for every barrel of oil equivalent sold. Operating netback per boe is reconciled to net earnings (loss) per boe under the heading "Operating Netback".2011 HIGHLIGHTSIncreased production 150% to 5,771 boepd in Q4 2011 from 2,307 boepd in Q4 2010 Decreased production expenses 25% to $7.05/boe in Q4 2011 from $9.44/boe in Q4 2010 Increased proved plus probable reserves 83% to 29.6 Mmboe in 2011 from 16.2 Mmboe in 2010 Drilled 11.7 net Bluesky wells at Edson, AB at a 100% success rate Increased funds from operations 116% to $30.6 million in 2011 from $14.2 million in 2010 Increased bank credit facility to $80.0 million from $55.0 million Raised gross proceeds of $61.0 million through two equity financings Reduced net debt during the year to $27.7 million from $35.2 million SUMMARY OF FINANCIAL RESULTS (1)Three Months Ended December 31Year Ended December 31($000s, except per share amounts)201120102009201120102009Oil and natural gas sales20,3917,27412,13054,97434,53034,199Funds from operations12,1154,2013,97230,60814,1749,325Per share - basic0.150.060.060.390.220.18Per share - diluted0.140.060.060.380.220.18Net earnings (loss)(7,052)6553,276(5,592)(5,328)(7,141)Per share - basic and diluted(0.09)0.010.05(0.07)(0.08)(0.14)Total assets239,554185,528254,156Total long-term liabilities20,06314,03510,084Net debt27,73635,20070,656(1) On January 1, 2011, the Company adopted IFRS for financial reporting purposes, using a transition date of January 1, 2010. Previously, the Company's financial statements were prepared under Canadian generally accepted accounting principles. As such, 2010 comparative results have been adjusted to conform to IFRS while 2009 results have not been adjusted and reflect the results in accordance with Canadian generally accepted accounting principles. Refer to note 22 of the consolidated financial statements for reconciliations of the impact of the change to IFRS. The Company has experienced significant growth in oil and natural gas sales and funds from operations as well as a significant decrease in net debt over the past three years. Successful capital activity during the latter half of 2010 and throughout 2011, mainly at Edson, AB, resulted in a significant increase in production which, combined with higher oil and NGLs commodity prices, resulted in increased revenue and funds from operations. Net debt has been drastically reduced since 2009 due to several factors, including two equity financings in 2011 that raised gross proceeds of $61.0 million, non-core property dispositions during 2010 and 2011 that totaled $65.2 million, and funds flow from operations generated in 2010 and 2011 that totaled $44.8 million, which were offset by significant capital expenditures that totaled $123.4 million in 2010 and 2011.PRODUCTIONThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeAverage Daily ProductionOil and NGLs (bbls/d)1,8796471901,21474663Natural gas (mcf/d)23,3549,95813515,36710,48547Combined (boe/d)5,7712,3071503,7752,49451Daily production for the three months ended December 31, 2011 increased 150% to 5,771 boe/d compared to 2,307 boe/d for the comparative period in 2010. For the year, daily production increased 51% to 3,775 boe/d in 2011 from 2,494 boe/d in 2010. The significant increase in production was due to successful drilling activity at Edson, AB which saw 14 gross (11.7 net) wells drilled during 2011 at a 100% success rate. Compared to the previous quarter, daily production increased 44% in Q4 2011 from 4,002 boe/d in Q3 2011 as an additional 4 gross (2.5 net) wells at Edson, AB were brought on production.Crocotta's production profile for 2011 was comprised of 68% natural gas and 32% oil and NGLs, consistent with the production profile for 2010, which was comprised of 70% natural gas and 30% oil and NGLs.REVENUEThree Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeOil and NGLs12,8953,63625533,09117,09794Natural gas7,4963,63810621,88317,43326Total20,3917,27418054,97434,53059Average Sales PriceOil and NGLs ($/bbl)74.6061.042274.6962.7919Natural gas ($/mcf)3.493.97(12)3.904.56(14)Combined ($/boe)38.4034.271239.9037.945Revenue totaled $20.4 million for the fourth quarter of 2011, up 180% from $7.3 million in the comparative period. For the year, revenue increased 59% to $55.0 million in 2011 from $34.5 million in 2010. The increase in revenue was mainly due to significant increases in production and oil and NGLs commodity prices.The following table outlines the Company's realized wellhead prices and industry benchmarks:Commodity PricingThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeOil and NGLsCorporate price ($CDN/bbl)74.6061.042274.6962.7919Edmonton par ($CDN/bbl)97.8780.712195.1677.8022West Texas Intermediate ($US/bbl)94.1785.081195.0079.4320Natural gasCorporate price ($CDN/mcf)3.493.97(12)3.904.56(14)AECO price ($CDN/mcf)3.293.59(8)3.654.12(11)Exchange rateCDN/US dollar average exchange rate0.97990.9875(1)1.01230.97114Differences between corporate and benchmark prices can be the result of quality differences (higher or lower API oil and higher or lower heat content natural gas), sour content, NGLs included in reporting, and various other factors. Crocotta's differences are mainly the result of lower priced NGLs included in oil price reporting and higher heat content natural gas production that is priced higher than AECO reference prices. The Company's corporate average oil and NGLs prices were 76.2% and 78.5% of Edmonton Par price for the three months and year ended December 31, 2011, consistent with 75.6% and 80.7% for the comparative periods in 2010. Corporate average natural gas prices were 106.1% and 106.8% of AECO prices for the three months and year ended December 31, 2011, consistent with the comparative period results of 110.6% and 110.7%.ROYALTIESThree Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeOil and NGLs1,615955695,6254,75718Natural gas236(142)266521640(19)Total1,8518131286,1465,39714Average Royalty Rate (% of sales)Oil and NGLs12.526.3(52)17.027.8(39)Natural gas3.2(3.9)1822.43.7(35)Combined9.111.2(19)11.215.6(28)The Company pays royalties to provincial governments (Crown), freeholders, which may be individuals or companies, and other oil and gas companies that own surface or mineral rights. Crown royalties are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to commodity price fluctuations and changes in production volumes on a well-by-well basis, subject to a minimum and maximum rate restriction ascribed by the Crown. The provincial government has also enacted various royalty incentive programs that are available for wells that meet certain criteria, such as natural gas deep drilling, which can result in fluctuations in royalty rates.For the three months ended December 31, 2011, oil, NGLs, and natural gas royalties increased 128% to $1.9 million from $0.8 million in the comparative period. This increase stemmed from a significant increase in oil, NGLs, and natural gas revenue in the fourth quarter of 2011 compared to the fourth quarter of 2010. For the year ended December 31, 2011, oil, NGLs, and natural gas royalties increased to $6.1 million from $5.4 million in 2010. The increase was mainly the result of higher oil and NGLs royalties due to a significant increase in oil and NGLs revenue.The overall effective royalty rate was 9.1% for the three months ended December 31, 2011 compared to 11.2% for the three months ended December 31, 2010. For the year, the overall effective royalty rate was 11.2% in 2011 compared to 15.6% in 2010. The effective oil and NGLs royalty rate decreased significantly as a result of royalty incentive rates received on the successful Edson wells brought on production during the year. The effective natural gas royalty rate decreased from the comparative period due to royalty incentive rates received on the successful Edson wells brought on production during the year combined with a decline in natural gas commodity prices. The effective natural gas royalty rate was negative during the fourth quarter of 2010 as the monthly capital cost allowance deductions exceeded the natural gas royalties.PRODUCTION EXPENSESThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeOil and NGLs ($/bbl)6.679.59(30)7.129.61(26)Natural gas ($/mcf)1.211.56(22)1.371.46(6)Combined ($/boe)7.059.44(25)7.859.01(13)Per unit production expenses for the three months ended December 31, 2011 were $7.05/boe, down significantly from $9.44/boe for the comparative period ended December 31, 2010. For the year ended December 31, 2011, per unit production expenses decreased 13% to $7.85/boe from $9.01/boe for the year ended December 31, 2010. Compared to the previous quarter, per unit production expenses in Q4 2011 were consistent with per unit production expenses of $7.06/boe in Q3 2011.The decrease in per unit production expenses in 2011 compared to 2010 was mainly due to a significant increase in quarter-over-quarter and year-over-year production due to successful drilling activities at Edson, AB during 2011. The Company continues to focus on opportunities that will improve operational efficiencies and reduce per boe production expenses to enhance operating netbacks.TRANSPORTATION EXPENSESThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeOil and NGLs ($/bbl)0.611.12(46)0.741.23(40)Natural gas ($/mcf)0.190.20(5)0.180.18-Combined ($/boe)0.971.18(18)0.951.13(16)Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended December 31, 2011 compared to the quarter ended December 31, 2010, transportation expenses decreased 18% to $0.97/boe from $1.18/boe. For the year, transportation expenses decreased to $0.95/boe in 2011 from $1.13/boe in 2010. The decrease in transportation expenses was due to a significant decrease in oil and NGLs transportation expenses. During the latter half of 2010, the Company changed its sales point and marketer for a significant portion of NGLs volumes produced which, combined with a significant increase in NGLs production in 2011, resulted in the decrease in transportation expenses.OPERATING NETBACKThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeOil and NGLs ($/bbl)Revenue74.6061.042274.6962.7919Royalties9.3416.04(42)12.7017.47(27)Production expenses6.679.59(30)7.129.61(26)Transportation expenses0.611.12(46)0.741.23(40)Operating netback57.9834.296954.1334.4857Natural gas ($/mcf)Revenue3.493.97(12)3.904.56(14)Royalties0.11(0.15)1730.090.17(47)Production expenses1.211.56(22)1.371.46(6)Transportation expenses0.190.20(5)0.180.18-Operating netback1.982.36(16)2.262.75(18)Combined ($/boe)Revenue38.4034.271239.9037.945Royalties3.493.83(9)4.465.93(25)Production expenses7.059.44(25)7.859.01(13)Transportation expenses0.971.18(18)0.951.13(16)Operating netback26.8919.823626.6421.8722During the fourth quarter of 2011, Crocotta generated an operating netback of $26.89/boe, up 36% from $19.82/boe for the fourth quarter of 2010. For the year ended December 31, 2011, Crocotta generated an operating netback of $26.64/boe compared to $21.87/boe in the comparative period. These increases were mainly due to an increase in oil and NGLs commodity prices and a decrease in royalties, operating costs, and transportation expenses in 2011 compared to 2010. Operating netbacks in Q4 2011 were down marginally from operating netbacks of $28.63/boe in Q3 2011 due to a decline in natural gas commodity prices.The following is a reconciliation of operating netback per boe to net earnings (loss) per boe for the periods noted:Three Months Ended December 31Year Ended December 31($/boe)20112010% Change20112010% ChangeOperating netback26.8919.823626.6421.8722Depletion and depreciation(14.87)(13.80)8(15.04)(14.39)5Asset impairment(25.79)(1.93)1,236(12.07)(7.85)54General and administrative expenses(3.60)(3.70)(3)(3.90)(3.97)(2)Share based compensation(1.87)(1.05)78(2.29)(1.04)120Finance expenses(0.83)(3.39)(76)(1.06)(3.77)(72)Finance income-5.99(100)0.101.50(93)Gain (loss) on sale of assets(7.32)(1.69)333(1.87)0.63(397)Deferred tax reduction14.103.093565.430.72654Realized gain (loss) on risk management contracts-0.10(100)-(0.69)(100)Unrealized gain (loss) on risk management contracts-(0.35)(100)-1.15(100)Net earnings (loss)(13.29)3.09(530)(4.06)(5.84)(30)DEPLETION AND DEPRECIATIONThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeDepletion and depreciation ($000s)7,8962,92917020,72913,09958Depletion and depreciation ($/boe)14.8713.80815.0414.395Under IFRS, the Company calculates depletion on property, plant, and equipment based on proved plus probable reserves. Plant turnarounds and major overhauls are depreciated over three or four years, depending on each facility. Depletion and depreciation for the three months ended December 31, 2011 was $14.87/boe compared to $13.80/boe in the comparative period. For the year, depletion and depreciation was $15.04/boe in 2011 compared to $14.39/boe in 2010. The marginal increase in depletion and depreciation per boe was due to a significant increase in the carrying value of property, plant, and equipment and future capital costs in 2011 compared to 2010, partially offset with significantly higher reserves.ASSET IMPAIRMENTThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeAsset impairment ($000s)13,6954113,23216,6277,143133Asset impairment ($/boe)25.791.931,23612.077.8554Under IFRS, exploration and evaluation assets and property, plant, and equipment are grouped into cash generating units ("CGU" - see "International Financial Reporting Standards" section below) for purposes of impairment testing. Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For property, plant, and equipment, an impairment is recognized if the carrying value of a CGU exceeds the greater of its fair value less costs to sell or value in use.For the year ended December 31, 2011, total exploration and evaluation asset impairments of $13.7 million were recognized. Asset impairments of $12.5 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGUs - Miscellaneous AB and Saskatchewan). Of this $12.5 impairment, $12.2 million related to unsuccessful exploration drilling activities in Southern Alberta during the year. Additional exploration and evaluation impairments of $1.2 million were recognized in 2011 relating to the expiry of undeveloped land rights (CGUs - Northeast BC, Ferrier AB and Miscellaneous AB). For the year ended December 31, 2010, the Company recognized exploration and evaluation asset impairments of $2.4 million due to the expiry of undeveloped land rights (CGUs - Ferrier AB and Miscellaneous AB).For the year ended December 31, 2011, the Company recorded property, plant, and equipment impairments of $3.0 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices at December 31, 2011 compared to December 31, 2010.For the year ended December 31, 2010, the Company recognized net property, plant, and equipment impairments of $4.7 million relating to Lookout Butte AB, Ferrier AB, and Miscellaneous AB CGUs.GENERAL AND ADMINISTRATIVEThree Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeG&A expenses (gross)2,8321,2641247,3884,87352G&A capitalized(277)(55)404(535)(187)186G&A recoveries(642)(424)51(1,482)(1,069)39G&A expenses (net)1,9137851445,3713,61748G&A expenses ($/boe)3.603.70(3)3.903.97(2)General and administrative expenses ("G&A") decreased to $3.60/boe for the fourth quarter of 2011 compared to $3.70/boe for the fourth quarter of 2010. Year-to-date, G&A expenses of $3.90/boe in 2011 were down marginally from G&A expenses of $3.97/boe in 2010. An overall increase in net G&A expenses in 2011 compared to 2010, due mainly to increased employment costs, was offset by a significant increase in production, resulting in consistent quarter-over-quarter and year-over-year G&A per boe amounts.SHARE BASED COMPENSATIONThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeShare based compensation ($000s)9922213493,156945234Share based compensation ($/boe)1.871.05782.291.04120The Company grants stock options to officers, directors, employees and consultants and calculates the related share based compensation using the Black-Scholes-Merton option pricing model. Under IFRS, the Company recognizes the expense over the individual vesting periods for the graded vesting awards and estimates a forfeiture rate at the date of grant and updates it throughout the vesting period. Share based compensation expense increased to $1.87/boe and $2.29/boe, respectively, for the three months and year ended December 31, 2011 from $1.05/boe and $1.04/boe in the comparative periods, respectively. During 2011, the Company granted 4.2 million options (2010 - 1.2 million), resulting in the increase in share based compensation expense in 2011 compared to 2010.FINANCE EXPENSESThree Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeInterest expense256513(50)8612,846(70)Accretion of decommissioning obligations184119555165023Realized loss on investments-88(100)7988(10)Finance expenses440720(39)1,4563,436(58)Finance expenses ($/boe)0.833.39(76)1.063.77(72)Interest expense relates mainly to interest incurred on amounts drawn from the Company's credit facility. In 2010, interest expense also included interest incurred on a secured bridge facility acquired in conjunction with the acquisition of Salvo Energy Corporation in August 2009, which was repaid in full during the first quarter of 2010. The decrease in interest expense in 2011 compared to 2010 relates to the repayment of the secured bridge facility in 2010 combined with a significant decrease in the amount drawn on the revolving credit facility (December 31, 2011 - $5.2 million; December 31, 2010 - $35.4 million). The decrease in the amount drawn on the revolving credit facility was the result of payments made during the latter half of 2010 and throughout 2011, stemming from the disposition of certain oil and natural gas assets in the fourth quarter of 2010 and throughout 2011 and two separate equity financings in 2011. In February 2011, the Company issued approximately 15.6 million common shares for gross proceeds of approximately $36.0 million. In December 2011, the Company issued approximately 7.2 million common shares for gross proceeds of approximately $25.0 million. Under the December issuance, approximately 6.0 million common shares were issued at a price of $3.35 per share and approximately 1.2 million common shares were issued on a flow-through basis at a price of $4.00 per share. The asset dispositions and equity financings were offset by capital expenditures during 2011.Investments included 875,000 warrants of Hyperion Exploration Corp. ("Hyperion") at an exercise price of $2.00 per warrant. Each warrant was convertible into one common share of Hyperion and expired unexercised on November 7, 2011. The warrants were obtained as partial consideration for the sale of certain oil and natural gas assets to Hyperion in the fourth quarter of 2010. The investment was measured at fair value each reporting period using the Black-Scholes-Merton option pricing model. A realized loss was recognized during the year upon expiry of the warrants.FINANCE INCOMEThree Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeFinance income-1,271(100)1321,361(90)Finance income ($/boe)-5.99(100)0.101.50(93)Finance income during 2011 related mainly to the sale of a licensed copy of proprietary seismic. During 2010, $1.0 million of finance income related to an assignment agreement entered into by Crocotta and an unrelated party whereby Crocotta was allocated drilling credits from the unrelated party in order to maximize Crocotta's Alberta Crown royalty deduction. The remaining finance income in 2010 arose from interest income generated on the sale of certain non-core oil and natural gas assets during the year.GAIN (LOSS) ON SALE OF ASSETSThree Months Ended December 31Year Ended December 3120112010% Change20112010% ChangeGain (loss) on sale of assets ($000s)(3,885)(360)979(2,578)576(548)Gain (loss) on sale of assets ($/boe)(7.32)(1.69)333(1.87)0.63(397)During 2011, the Company recognized a net loss on sale of assets of $2.6 million. A loss on sale of assets of $3.9 million was recognized during the fourth quarter relating to the disposition of certain non-core oil and natural gas assets located in the Ferrier AB CGU while additional losses of $1.5 million were recognized during the first half of 2011 on the disposition of certain non-producing assets in the Northeast BC CGU. These losses were offset by a gain on sale of assets of $2.8 million during the third quarter relating to dispositions of non-core oil and natural gas assets in Smoky AB, Ferrier AB, and Miscellaneous AB CGUs. During 2010, the Company recognized a net gain on sale of assets of $0.6 million. A gain on sale of assets of $1.0 million was recognized relating mainly to the sale of undeveloped land in the Miscellaneous AB CGU, which was offset by a $0.1 million loss on sale of assets in the first quarter of 2010 relating to a land exchange agreement whereby the Company exchanged interests in undeveloped land with an unrelated party and a $0.3 million loss on sale of certain non-core assets in Niton AB during the fourth quarter of 2010.DEFERRED INCOME TAX REDUCTIONDeferred income tax reduction on the loss before taxes was $7.5 million in 2011 (2010 - $0.7 million). This was larger than expected by applying the statutory tax rate to the loss before taxes due to a recognition of previously unrecognized tax assets resulting from increased current estimates of future taxable income from proved reserves.Estimated tax pools at December 31, 2011 total approximately $251.0 million.FUNDS FROM OPERATIONSFunds from operations for the three months and year ended December 31, 2011 were $12.1 million ($0.14 per diluted share) and $30.6 million ($0.38 per diluted share), respectively, compared to $4.2 million ($0.06 per diluted share) and $14.2 million ($0.22 per diluted share) for the three months and year ended December 31, 2010, respectively. The increase was mainly due to an increase in oil and NGLs commodity prices in 2011 combined with a significant increase in production.The following is a reconciliation of cash flow from operating activities to funds from operations for the periods noted:Three Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeCash flow from operating activities (GAAP)12,8253,75324229,29112,563133Add back:Decommissioning expenditures187204(8)363868(58)Change in non-cash working capital(897)24446895474328Funds from operations (non-GAAP)12,1154,20118830,60814,174116NET EARNINGS (LOSS)The Company had a net loss of $7.1 million ($0.09 per diluted share) for the three months ended December 31, 2011 compared to net earnings of $0.7 million ($0.01 per diluted share) for the three months ended December 31, 2010. For the year, the Company had a net loss of $5.6 million ($0.07 per diluted share) in 2011 compared to a net loss of $5.3 million ($0.08 per diluted share) in 2010. The net loss in 2011 was consistent with 2010 as increases in revenue stemming from higher production and oil and NGLs commodity prices in 2011 were offset by higher expenses, including increased asset impairments due to weakening natural gas prices at the end of 2011 and the determination of certain exploration and evaluation activities to be uneconomical.CAPITAL EXPENDITURESThree Months Ended December 31Year Ended December 31($000s)20112010% Change20112010% ChangeLand1,9001,362403,1612,9318Drilling, completions, and workovers27,77510,93215473,61119,266282Equipment6,0691,92221614,3025,621154Geological and geophysical1,0542952571,939816138Property acquisitions8-1001,704-100Other---69-100Exploration and development36,80614,51115494,78628,634231Property dispositions(4,541)(28,532)(84)(14,552)(50,630)(71)Net capital expenditures (dispositions)32,265(14,021)33080,234(21,996)465For the three months ended December 31, 2011, the Company had net capital expenditures of $32.3 million compared to net capital dispositions of $14.0 million for the three months ended December 31, 2010. For the year ended December 31, 2011, the Company had net capital expenditures of $80.2 million compared to net capital dispositions of $22.0 million for the comparative period in 2010. The increase in exploration and development expenditures in 2011 was due mainly to a significant increase in capital activity in the Company's core Edson, AB area. During 2011, Crocotta drilled a total of 20 (15.9 net) wells, which resulted in 4.0 (3.0 net) oil wells, 13 (10.9 net) liquids-rich natural gas wells, and 3 (2.0 net) uneconomic wells.During 2011, the Company sold certain non-core oil and natural gas assets from the Smoky AB, Northeast BC, Ferrier AB, and Miscellaneous AB CGUs for cash proceeds of $14.6 million. During 2010, the Company sold certain non-core oil and natural gas assets from the Miscellaneous AB CGU and Niton AB for cash proceeds of approximately $50.6 million. The sale of these properties in 2011 and 2010 allowed the Company to reduce net debt and focus capital spending on its two core areas, Edson Bluesky and Dawson Montney.LIQUIDITY AND CAPITAL RESOURCESThe Company had net debt of $27.7 million at December 31, 2011 compared to net debt of $35.2 million at December 31, 2010. The decrease of $7.5 million was mainly due to gross proceeds of $61.0 million from two separate equity financings, $14.6 million in net property dispositions, and funds from operations of $30.6 million, offset by $94.8 million used for the purchase and development of oil and natural gas properties and equipment, $0.4 million for decommissioning expenditures, and share issue costs of $3.5 million.At December 31, 2011, the Company had total credit facilities of $80.0 million, consisting of an $80.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At December 31, 2011, $5.2 million (December 31, 2010 - $35.4 million) had been drawn on the revolving credit facility. In addition, at December 31, 2011, the Company had outstanding letters of guarantee of approximately $1.0 million (December 31, 2010 - $0.2 million). The next review of the revolving credit facility by the bank is scheduled on or before May 31, 2012.In February 2011, the Company issued approximately 15.6 million common shares at a price of $2.30 per share for gross proceeds of approximately $36.0 million. In December 2011, the Company issued approximately 7.2 million common shares for gross proceeds of approximately $25.0 million. Under the December issuance, approximately 6.0 million common shares were issued at a price of $3.35 per share and approximately 1.2 million common shares were issued on a flow-through basis at a price of $4.00 per share. The proceeds are being used to fund Crocotta's Edson Bluesky and Dawson Montney developments, other capital projects, and for general corporate purposes.During 2011, the Company sold certain non-core oil and natural gas properties for cash proceeds of approximately $14.6 million. The proceeds of the dispositions were mainly used as additional funding for the Company's Edson Bluesky development.The ongoing global economic conditions have continued to impact the liquidity in financial and capital markets, restrict access to financing, and cause significant volatility in commodity prices. Downward trends in natural gas commodity prices have resulted in the Company experiencing reduced operating netbacks and funds from operations. Continued pressure on commodity prices would result in the Company experiencing reduced operating netbacks and funds from operations in future periods. Despite the economic downturn and financial market volatility, the Company continued to have access to both debt and equity markets in 2011. As noted above, the Company raised gross proceeds of approximately $61.0 million from the issuance of common shares during the first and fourth quarters of 2011 and during the fourth quarter, the Company obtained an increase to its revolving credit facility to $80.0 million. Management anticipates that the Company will continue to have adequate liquidity to fund budgeted capital investments through a combination of cash flow, equity, and debt. Crocotta's capital program is flexible and can be adjusted as needed based upon the current economic environment. The Company will continue to monitor the economic environment and the possible impact on its business and strategy and will make adjustments as necessary.CONTRACTUAL OBLIGATIONSThe following is a summary of the Company's contractual obligations and commitments at December 31, 2011:Less thanOne toAfter($000s)TotalOne YearThree YearsThree YearsAccounts payable and accrued liabilities34,69234,692--Revolving credit facility5,1825,182--Decommissioning obligations19,2506118719,002Office leases1,423574849-Field equipment leases3,2991,5731,726-Drilling rig2,4892,489--Firm transportation agreements79245729540Capital processing agreements200--200Total contractual obligations67,32745,0283,05719,242In addition to the above commitments, as a result of the issuance of flow-through shares in December 2011, the Company is committed to expend $5.0 million on qualifying exploration expenditures prior to December 31, 2012. As at December 31, 2011, the Company had not incurred any amounts in connection with this flow-through share commitment.Under the terms of a farm-in agreement, the Company is also committed to drill one Edson Bluesky horizontal well prior to July 1, 2012. The estimated cost to drill the well is $3.1 million.OUTSTANDING SHARE DATAThe Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, and Class B preferred shares, issuable in series. The voting common shares of the Company commenced trading on the TSX on October 17, 2007 under the symbol "CTA". The following table summarizes the common shares outstanding and the number of shares exercisable into common shares from options, warrants, and other instruments:(000s)December 31, 2011March 26, 2012Voting common shares88,09588,095Stock options7,9428,640Warrants3,5213,521Total99,558100,256SUMMARY OF QUARTERLY RESULTS (1)Q4 2011Q3 2011Q2 2011Q1 2011Q4 2010Q3 2010Q2 2010Q1 2010Average Daily ProductionOil and NGLs (bbls/d)1,8791,3361,039586647862665810Natural gas (mcf/d)23,35415,99611,84310,1249,95810,53010,69810,763Combined (boe/d)5,7714,0023,0122,2742,3072,6172,4482,604($000s, except per share amounts)Oil and natural gas sales20,39114,81412,2897,4807,2748,5747,72010,962Funds from operations12,1159,5516,9272,0144,2003,4772,4934,004Per share - basic0.150.120.090.030.060.050.040.06Per share - diluted0.140.110.080.030.060.050.040.06Net earnings (loss)(7,052)5,535374(4,449)656(2,071)(1,347)(2,566)Per share - basic and diluted(0.09)0.07-(0.06)0.01(0.03)(0.02)(0.04)(1) 2010 quarterly results have been adjusted to conform to IFRS.A significant increase in oil and NGLs commodity prices combined with a significant increase in production stemming from successful drilling activity during 2011 resulted in an increase in funds from operations in Q2 2011, Q3 2011, and Q4 2011 compared to prior quarters. The Company recognized a net loss in Q4 2011 resulting from asset impairments of $13.7 million due to weakening natural gas prices at the end of 2011 and the determination of certain exploration and evaluation activities to be uneconomical.2012 OUTLOOKThe information below represents Crocotta's guidance for 2012, publicly released on February 9, 2012, based on management's best estimates and the assumptions noted below. Note that natural gas prices have deteriorated materially since the release date and the Company is modifying its product mix in the context of overall guidance.Estimated Average Daily ProductionGuidance 2012Oil and NGLs (bbls/d)2,205Natural gas (mcf/d)30,870Total (boe/d)7,350Estimated Financial ResultsGuidance 2012Oil and natural gas sales ($000s)110,000Funds from operations ($000s)70,000$ per share - basic (1)0.79$ per share - diluted (2)0.70Capital expenditures ($000s)86,800West Texas Intermediate ($US/bbl)97.00AECO Daily Spot Price ($CDN/mcf)3.49US/CDN Dollar Average Exchange Rate0.98(1) Based on 88.1 million common shares outstanding at March 26, 2012 (2) Based on 88.1 million common shares, 8.6 million options, and 3.5 million warrants outstanding at March 26, 2012 Sensitivity AnalysisThe outlook is based on estimates of key external market factors. Crocotta's actual results will be affected by fluctuations in commodity prices as well as the U.S./Canadian dollar exchange rate. The following table provides a summary of estimates for 2012 of the sensitivity of Crocotta's funds from operations to changes in commodity prices and the U.S./Canadian dollar exchange rate.Guidance 2012Variance in FactorFunds from OperationsWest Texas Intermediate ($US/bbl)97.001.00625,000AECO Daily Spot Price ($CDN/mcf)3.490.101,161,000US/CDN Dollar Average Exchange Rate0.980.01618,0002011 OUTLOOKThe information below represents Crocotta's initial guidance for 2011, publicly released on January 17, 2011, and a comparison to actual results for 2011:Estimated Average Daily ProductionGuidance 2011Actual 2011% ChangeOil and NGLs (bbls/d)1,2351,214(2)Natural gas (mcf/d)13,00015,36718Total (boe/d)3,4003,77511Exit production (boe/d)4,5006,50044Estimated Financial ResultsGuidance 2011Actual 2011% ChangeOil and natural gas sales ($000s)53,70054,9742Funds from operations ($000s)25,10030,60822$ per share - basic (1)0.310.3926$ per share - diluted (2)0.280.3836Capital expenditures ($000s)50,10080,23460(1) Based on 80.9 million common shares outstanding at March 21, 2011 (2) Based on 80.9 million common shares, 6.3 million options, and 3.5 million warrants outstanding at March 21, 2011 During 2011, the Company's actual results exceeded guidance as a result of successful operations and capital activity at its core Edson, AB area. Due to the Company's successful capital program, Crocotta revised its net capital expenditures guidance to $79.0 million in October 2011, which is consistent with actual net capital expenditures of $80.2 million. Further, as a result of successful capital activity, actual average daily production in 2011 was 3,775 boe/d, 11% above guidance of 3,400 boe/d and actual exit production in 2011 was 6,500 boe/d, 44% above guidance of 4,500 boe/d. Oil and natural gas sales and funds from operations were higher than guidance, mainly as a result of higher than estimated total production and oil and NGLs commodity prices, which were partially offset by lower than estimated natural gas commodity prices.INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)On January 1, 2011, the Company adopted International Financial Reporting Standards ("IFRS") for financial reporting purposes, using a transition date of January 1, 2010. Previously, the Company prepared its financial statements in accordance with Canadian generally accepted accounting principles ("previous GAAP"). As such, certain 2010 comparative results included in this MD&A have been adjusted to conform to IFRS. The adoption of IFRS has not had an impact on the Company's operations, strategic decisions, or overall cash flows. The reporting and measurement currency of the Company is the Canadian dollar.Upon transition to IFRS on January 1, 2010, the Company used certain exemptions allowed under IFRS 1, First Time Adoption of International Reporting Standards. The exemptions used were as follows:Full cost accountingIFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at the time of adoption of IFRS, to measure oil and natural gas assets in the development and production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets on a pro rata basis using reserve volumes or reserve values as of that date. The Company has used reserve values at January 1, 2010 to allocate the cost of development and production assets.Business combinationsIFRS 1 allows an entity to use the IFRS rules for business combinations on a prospective basis rather than restating all business combinations prior to transition to IFRS that were accounted for under previous GAAP.Share based compensationIFRS 1 allows an entity an exemption on IFRS 2, Share-Based Payments, with respect to equity instruments which vested before the transition date to IFRS.Decommissioning obligationsAs the Company elected to use the full cost accounting exemption for oil and gas, a decommissioning obligation exemption was also used that allows for the adjustment of decommissioning obligations on transition to IFRS to be offset to the Company's opening deficit on the statement of financial position on the transition date.The most significant changes under IFRS relate to the Company's accounting policies on property, plant, and equipment, decommissioning obligations, and share based compensation. The following is a summary of the significant differences.Property, plant, and equipmentDepletion and depreciationUnder previous GAAP, depletion was calculated on the full cost oil and gas pool using the unit of production method based on total proved reserves. Under IFRS, significant parts of an item of property, plant, and equipment, including oil and natural gas interests, are accounted for as separate items or major components and depleted or depreciated separately. Depletion is calculated on oil and natural gas development and production assets using the unit of production method based on total proved plus probable reserves. Depreciation is calculated on major components of property, plant, and equipment on a straight-line basis over the useful life of the assets. The use of proved plus probable reserves in the calculation of depletion resulted in a $9.3 million decrease to depletion and depreciation expense in 2010 under IFRS as compared to previous GAAP.Impairment testingUnder previous GAAP, an impairment was recognized if the carrying value of the full cost oil and gas pool exceeded the undiscounted future cash flows from proved reserves. Under IFRS, property, plant, and equipment is grouped into cash generating units ("CGU") based on their ability to generate largely independent cash flows. An impairment is recognized if the carrying value of a CGU exceeds the greater of its fair value less costs to sell or value in use. As CGUs are smaller groups of assets and the impairment test uses discounted cash flows, or fair value, impairments are expected to be recognized more frequently under IFRS. Upon transition to IFRS on January 1, 2010, the Company recognized impairments of $35.8 million relating to certain of the Company's CGUs. During 2010, net impairments of $7.1 million were recognized.Decommissioning obligationsUnder previous GAAP, decommissioning obligations were estimated using a credit adjusted risk free discount rate. Under IFRS, the Company estimates its decommissioning obligations using a risk free rate and changes in the discount rate are treated as a change in estimate. Accordingly, more frequent revisions to the decommissioning obligation are expected due to the fluctuations in the risk free rate. Upon transition to IFRS on January 1, 2010, the impact of this change was a $5.0 million increase in the decommissioning obligation. At December 31, 2010, the decommissioning obligation was $5.6 million higher than under previous GAAP.Additionally, under previous GAAP, accretion of the discount was included in depletion and depreciation expense. Under IFRS, accretion is included in finance expenses.Share based compensationUnder previous GAAP, the Company recognized an expense related to share based compensation on a straight-line basis through the date of full vesting and did not incorporate a forfeiture rate at the grant date. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimate a forfeiture rate at the date of grant and update it throughout the vesting period. The impact on transition to IFRS was an increase to contributed surplus of $0.8 million. During 2010, share based compensation expense was $0.1 million lower under IFRS than under previous GAAP as a result of the changes.The Company's IFRS accounting policies are provided in note 3 to the consolidated financial statements. In addition, note 22 to the consolidated financial statements provides reconciliations between the Company's 2010 previous GAAP results and its 2010 IFRS results. The reconciliations include the statements of financial position at January 1, 2010 and December 31, 2010, the statement of operations and comprehensive loss for the year ended December 31, 2010, and the statement of cash flows for the year ended December 31, 2010.CRITICAL ACCOUNTING ESTIMATESManagement is required to make estimates, judgments, and assumptions in the application of IFRS that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. Certain of these estimates may change from period to period resulting in a material impact on the Company's results from operations, financial position, and change in financial position. The following summarizes the Company's significant critical accounting estimates.Oil and natural gas reservesThe Company engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the amount of the Company's oil and natural gas reserves at least annually. Reserves form the basis for the calculation of depletion and assessment of impairment of oil and natural gas assets. Reserves are estimated using the definitions of reserves prescribed by National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook.Proved plus probable reserves are defined as the estimated quantities of crude oil, natural gas liquids including condensate, and natural gas that geological and engineering data demonstrate a 50 percent probability of being recovered at the reported level. Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates of reserves are inherently imprecise, require the application of judgment, and are subject to change as additional information becomes available. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance, or changes in the Company's plans.Impairment testingExploration and evaluation assetsExploration and evaluation 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. For purposes of impairment testing, exploration and evaluation assets are allocated to CGUs. Impairment tests by their nature involve estimates and judgment, which for exploration and evaluation assets include estimates of proved and probable reserves found, the market value of undeveloped land, and future development plans. Crocotta allocated its exploration and evaluation assets to specific CGUs for the purpose of impairment testing.Property, plant, and equipmentFor the purpose of impairment testing, items of property, plant, and equipment, which includes oil and natural gas development and production 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 (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. The Company uses fair value less costs to sell for its impairment tests which is determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted by an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU. The significant estimates and judgments include proved plus probable reserves, the estimated value of those reserves, including future commodity prices, the discount rate used to present value the estimated future cash flows, and what may be considered assumptions that an independent market participant may take into account, in which case acquisition metrics of recent transactions for similar assets would be considered.Decommissioning obligationsDecommissioning obligations are estimated based on existing laws, contracts, or other policies. Decommissioning obligations are measured at the present value of management's best estimate of the expenditure required to settle the present obligation as at the reporting date. Subsequent to the initial measurement, the obligation is adjusted at the end of each reporting 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 accretion whereas increases or decreases due to changes in the estimated future cash flows or changes in the discount rate are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.Share based compensationMeasurement of compensation cost attributable to the Company's share based compensation plan is subject to the estimation of fair value using the Black-Scholes-Merton option pricing model. The valuation is based on significant assumptions including the estimated forfeiture rate, the expected volatility (based on the weighted average historic volatility adjusted for changes expected due to publicly available information), the weighted average expected life of the instrument (based on historical experience and general information), the expected dividends, and the risk free interest rate (based on government bonds).Deferred income taxesThe determination of the Company's income taxes requires interpretation of complex laws and regulations. Tax interpretations, regulations, and legislation in the various jurisdictions in which the Company operates are subject to change. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.FUTURE CHANGES IN ACCOUNTING POLICIESIn May 2011, the IASB issued four new standards and two amendments. Five of these items related to consolidation, while the remaining one addresses fair value measurement. All of the new standards are effective for annual periods beginning on or after January 1, 2013. Early adoption is permitted.IFRS 10, Consolidated Financial Statements replaces IAS 27, Consolidated Separate Financial Statements. It introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.IFRS 11, Joint Arrangements replaces IAS 31, Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A "joint operation" continues to be accounted for using proportionate consolidation, whereas a "joint venture" must be accounted for using equity accounting. This differs from IAS 31, where there was the choice to use proportionate consolidation or equity accounting for joint ventures. A "joint operation" is defined as the joint operators having rights to the assets, and obligations for the liabilities, relating to the arrangement. In a "joint venture", the joint venture partners have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity.IFRS 12, Disclosure of Interests in Other Entities is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.IFRS 13, Fair Value Measurement is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.IAS 27, Separate Financial Statements has been amended to focus solely on accounting and disclosure requirements when an entity presents separate financial statements, due to the issuance of the new IFRS 10 which is specific to consolidated financial statements.IAS 28, Investments in Associates and Joint Ventures has been amended as a result of the issuance of IFRS 11 and the withdrawal of IAS 31. The amended standard sets out the requirements for the application of the equity method when accounting for interest in joint ventures, in addition to interests in associates.In November 2009, the IASB published IFRS 9, Financial Instruments, which covers the classification and measurement of financial assets as part of its project to replace IAS 39, Financial Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company's own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively.The Company is currently evaluating the impact of adopting all of the newly issued and amended standards.RISK ASSESSMENTThe acquisition, exploration, and development of oil and natural gas properties involves many risks common to all participants in the oil and natural gas industry. Crocotta's exploration and development activities are subject to various business risks such as unstable commodity prices, interest rate and foreign exchange fluctuations, the uncertainty of replacing production and reserves on an economic basis, government regulations, taxes, and safety and environmental concerns. While management realizes these risks cannot be eliminated, they are committed to monitoring and mitigating these risks.Reserves and reserve replacementThe recovery and reserve estimates on Crocotta's properties are estimates only and the actual reserves may be materially different from that estimated. The estimates of reserve values are based on a number of variables including price forecasts, projected production volumes and future production and capital costs. All of these factors may cause estimates to vary from actual results.Crocotta's future oil and natural gas reserves, production, and funds from operations to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in Crocotta's reserves will depend on its abilities to acquire suitable prospects or properties and discover new reserves.To mitigate this risk, Crocotta has assembled a team of experienced technical professionals who have expertise operating and exploring in areas the Company has identified as being the most prospective for increasing reserves on an economic basis. To further mitigate reserve replacement risk, Crocotta has targeted a majority of its prospects in areas which have multi-zone potential, year-round access, and lower drilling costs and employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.Operational risksCrocotta's operations are subject to the risks normally incidental to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells. Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property.Market riskMarket risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign currency risk, interest rate risk, and other price risk, such as commodity price risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns. The Company may use financial derivatives or physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.Foreign exchange riskThe prices received by the Company for the production of crude oil, natural gas, and NGLs are primarily determined in reference to US dollars, but are settled with the Company in Canadian dollars. The Company's cash flow from commodity sales will therefore be impacted by fluctuations in foreign exchange rates. The Company currently does not have any foreign exchange contracts in place.Interest rate riskThe Company is exposed to interest rate risk as it borrows funds at floating interest rates. In addition, the Company may at times issue shares on a flow-through basis. This results in the Company being exposed to interest rate risk to the Canada Revenue Agency for interest on unexpended funds on the Company's flow-through share obligations. The Company currently does not use interest rate hedges or fixed interest rate contracts to manage the Company's exposure to interest rate fluctuations.Commodity price riskOil and natural gas prices are impacted by not only the relationship between the Canadian and US dollar but also by world economic events that dictate the levels of supply and demand. The Company's oil, natural gas, and NGLs production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company's cash flow from product sales will therefore be impacted by fluctuations in commodity prices. The Company currently does not have any commodity price contracts in place.Safety and Environmental RisksThe oil and natural gas business is subject to extensive regulation pursuant to various municipal, provincial, national, and international conventions and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with oil and natural gas operations. Crocotta is committed to meeting and exceeding its environmental and safety responsibilities. Crocotta has implemented an environmental and safety policy that is designed, at a minimum, to comply with current governmental regulations set for the oil and natural gas industry. Changes to governmental regulations are monitored to ensure compliance. Environmental reviews are completed as part of the due diligence process when evaluating acquisitions. Environmental and safety updates are presented and discussed at each Board of Directors meeting. Crocotta maintains adequate insurance commensurate with industry standards to cover reasonable risks and potential liabilities associated with its activities as well as insurance coverage for officers and directors executing their corporate duties. To the knowledge of management, there are no legal proceedings to which Crocotta is a party or of which any of its property is the subject matter, nor are any such proceedings known to Crocotta to be contemplated.DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTINGThe Company's President and Chief Executive Officer ("CEO") and Vice President Finance and Chief Financial Officer ("CFO") are responsible for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting as defined in Multilateral Instrument 52-109 of the Canadian Securities Administrators.Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. The Company evaluated its disclosure controls and procedures for the year ended December 31, 2011. The Company's CEO and CFO have concluded that, based on their evaluation, the Company's disclosure controls and procedures are effective to provide reasonable assurance that all material or potentially material information related to the Company is made known to them and is disclosed in a timely manner if required.Internal controls over financial reporting have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Company's internal controls over financial reporting include those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures of assets are being made only in accordance with authorizations of management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the financial statements.The Company evaluated the effectiveness of its internal controls over financial reporting as of December 31, 2011. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on their evaluation, the Company's CEO and CFO have identified weaknesses over segregation of duties. Specifically, due to the limited number of finance and accounting personnel at the Company, it is not feasible to achieve complete segregation of duties with regards to certain complex and non-routine accounting transactions that may arise. This weakness is considered to be a common deficiency for many smaller listed companies in Canada. Notwithstanding the weaknesses identified with regards to segregation of duties, the Company concluded that all other of its internal controls over financial reporting were effective as of December 31, 2011. No material changes in the Company's internal controls over financial reporting were identified during the most recent reporting period that have materially affected, or are likely to material affect, the Company's internal controls over financial reporting.Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors, or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control systems are met. As a result of the weaknesses identified in the Company's internal controls over financial reporting, there is a greater likelihood that a material misstatement would not be prevented or detected. To mitigate the risk of such material misstatement in financial reporting, the CEO and CFO oversee all material and complex transactions of the Company and the financial statements are reviewed and approved by the Board of Directors each quarter. In addition, the Company will seek the advice of external parties, such as the Company's external auditors, in regards to the appropriate accounting treatment for any complex and non-routine transactions that may arise.FORWARD-LOOKING INFORMATIONThis document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.More particularly and without limitation, this MD&A contains forward looking statements and information relating to the Company's risk management program, oil, NGLs, and natural gas production, capital programs, oil, NGLs, and natural gas commodity prices, and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services.Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.ADDITIONAL INFORMATIONAdditional information related to the Company, including the Company's Annual Information Form (AIF), may be found on the SEDAR website at www.sedar.com.MANAGEMENT'S RESPONSIBILITY FOR FINANCIAL STATEMENTSThe Management of Crocotta Energy Inc. is responsible for the preparation of the consolidated financial statements. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards and include certain estimates that reflect Management's best estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects.Management is responsible for the integrity of the consolidated financial statements. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.KPMG LLP were appointed by the Company's shareholders to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with International Financial Reporting Standards.The Board of Directors is responsible for ensuring that Management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our oil and natural gas reserves. The Audit Committee meets regularly with Management and the Auditors to ensure that Management's responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of KPMG LLP and reviews their fees. The Auditors have access to the Audit Committee without the presence of Management.signed "Rob Zakresky"signed "Nolan Chicoine"Rob ZakreskyNolan ChicoinePresident, Chief Executive Officer and DirectorVice President, Finance and Chief Financial OfficerCalgary, CanadaMarch 26, 2012INDEPENDENT AUDITORS' REPORTTo the Shareholders of Crocotta Energy Inc.We have audited the accompanying consolidated financial statements of Crocotta Energy Inc., which comprise the consolidated statements of financial position as at December 31, 2011, December 31, 2010, and January 1, 2010, the consolidated statements of operations and comprehensive loss, shareholders' 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 StatementsManagement 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' ResponsibilityOur 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.OpinionIn our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Crocotta Energy Inc. 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.signed "KPMG LLP"Chartered AccountantsMarch 26, 2012 Calgary, CanadaCrocotta Energy Inc.Consolidated Statements of Financial PositionDecember 31December 31January 1($000s)Note201120102010(note 22)(note 22)AssetsCurrent assetsCash and cash equivalents--1,854Accounts receivable11,29810,1595,042Prepaid expenses and deposits8408781,443Investments-79-Property, plant, and equipment, held for sale(7)-2,02021,88012,13813,13630,219Property, plant, and equipment(6)192,332134,915151,443Exploration and evaluation assets(5)20,64131,40536,398Deferred income taxes(15)14,4436,0725,415227,416172,392193,256239,554185,528223,475LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities34,69210,9306,397Revolving credit facility(8)5,18235,38652,355Secured bridge facility--20,243Risk management contracts--1,042Decommissioning obligations, held for sale(9)-1,0641,70539,87447,38081,742Flow-through share premium(10)813--Decommissioning obligations(9)19,25014,03513,40859,93761,41595,150Shareholders' EquityShareholders' capital(10)225,848168,164168,038Contributed surplus8,9275,5154,525Deficit(55,158)(49,566)(44,238)179,617124,113128,325Subsequent event(11)239,554185,528223,475The accompanying notes are an integral part of these consolidated financial statements.Approved on behalf of the Board of DirectorsDirector, "signed" Rob Zakresky Director, "signed" Larry MoellerCrocotta Energy Inc.Consolidated Statements of Operations and Comprehensive LossYear Ended December 31($000s, except per share amounts)Note20112010(note 22)RevenueOil and natual gas sales54,97434,530Royalties(6,146)(5,397)48,82829,133Realized loss on risk management contracts-(628)Unrealized gain on risk management contracts-1,04248,82829,547ExpensesProduction10,8118,203Transportation1,3091,026Depletion and depreciation(6)20,72913,099Asset impairment(5,6)16,6277,143General and administrative5,3713,617Share based compensation(11)3,15694558,00334,033Operating loss(9,175)(4,486)Other Expenses (Income)Finance expense(14)1,4563,436Finance income(132)(1,361)Loss (gain) on sale of assets2,578(576)3,9021,499Loss before taxes(13,077)(5,985)TaxesDeferred income tax reduction(15)(7,485)(657)Net loss and comprehensive loss(5,592)(5,328)Net loss per shareBasic and diluted(0.07)(0.08)The accompanying notes are an integral part of these consolidated financial statements.Crocotta Energy Inc.Consolidated Statements of Shareholders' EquityYear Ended December 31($000s)20112010(note 22)Shareholders' CapitalBalance, beginning of year168,164168,038Issue of shares (net of share issue costs and flow-through share premium)57,491-Issued on exercise of stock options11475Share based compensation - exercised7951Balance, end of year225,848168,164Contributed SurplusBalance, beginning of year5,5154,525Share based compensation - expensed3,156945Share based compensation - capitalized33596Share based compensation - exercised(79)(51)Balance, end of year8,9275,515DeficitBalance, beginning of year(49,566)(44,238)Net loss(5,592)(5,328)Balance, end of year(55,158)(49,566)Total Shareholders' Equity179,617124,113The accompanying notes are an integral part of these consolidated financial statements.Crocotta Energy Inc.Consolidated Statements of Cash FlowsYear Ended December 31($000s)Note20112010(note 22)Operating ActivitiesNet loss(5,592)(5,328)Depletion and depreciation(6)20,72913,099Asset impairment(5,6)16,6277,143Share based compensation(11)3,156945Finance expense(14)1,4563,436Interest paid(861)(2,846)Loss (gain) on sale of assets2,578(576)Deferred income tax reduction(15)(7,485)(657)Unrealized gain on risk management contracts-(1,042)Decommissioning expenditures(363)(868)Change in non-cash working capital(20)(954)(743)29,29112,563Financing ActivitiesIssuance of shares(10)61,07775Share issue costs(10)(3,545)-Revolving credit facility(8)(30,204)(16,969)Secured bridge facility-(20,243)27,328(37,137)Investing ActivitiesCapital expenditures - property, plant, and equipment(6)(63,567)(15,115)Capital expenditures - exploration and evaluation assets(5)(31,219)(13,519)Asset dispositions14,55250,630Change in non-cash working capital(20)23,615724(56,619)22,720Change in cash and cash equivalents-(1,854)Cash and cash equivalents, beginning of year-1,854Cash and cash equivalents, end of year--The accompanying notes are an integral part of these consolidated financial statements.Crocotta Energy Inc. Notes to the Consolidated Financial StatementsYear Ended December 31, 2011 (Tabular amounts in 000s, unless otherwise stated)1. REPORTING ENTITYCrocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in Western Canada. The Company conducts many of its activities jointly with others and these consolidated financial statements reflect only the Company's proportionate interest in such activities. The Company currently has one wholly-owned subsidiary.The Company's place of business is located at 700, 639 - 5th Avenue SW, Calgary, Alberta, Canada, T2P 0M9.2. BASIS OF PRESENTATION(a) Statement of complianceThese consolidated financial statements have been prepared in accordance with International Financial Reporting Standards ("IFRS"). These are Crocotta's first annual consolidated financial statements prepared in accordance with IFRS and IFRS 1, First-time Adoption of International Financial Reporting Standards has been applied. Prior to 2011, Crocotta prepared its financial statements in accordance with Canadian Generally Accepted Accounting Principles ("previous GAAP"). Crocotta's significant accounting policies under IFRS are presented in note 3. These policies have been retrospectively and consistently applied except where specific exemptions permitted an alternative treatment upon transition to IFRS in accordance with IFRS 1. The impact of the new standards, including reconciliations presenting the change from previous GAAP to IFRS as at December 31, 2010 and January 1, 2010 and for the year ended December 31, 2010, is presented in note 22.The consolidated financial statements were authorized for issuance by the Board of Directors on March 26, 2012.(b) Basis of measurementThe consolidated financial statements have been prepared on the historical cost basis except for held for trading financial assets, which are measured at fair value with changes in fair value recorded in earnings. (c) Functional and presentation currencyThese consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency.(d) Use of estimates and judgmentsThe preparation of the consolidated financial statements in conformity with IFRS requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities as at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future periods could require a material change in the consolidated financial statements. Accordingly, actual results may differ from the estimated amounts as future confirming events occur. Significant estimates and judgments made by management in the preparation of these consolidated financial statements are as follows: Recoverability of asset carrying values The recoverability of development and production asset carrying values are assessed at a cash generating unit ("CGU") level. Determination of what constitutes a CGU is subject to management judgments. The asset composition of a CGU can directly impact the recoverability of the assets included therein. The key estimates used in the determination of cash flows from oil and natural gas reserves include the following:(i) Reserves - Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs, or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated. (ii) Oil and natural gas prices - Forward price estimates are used in the cash flow model. Commodity prices can fluctuate for a variety of reasons including supply and demand fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors. (iii) Discount rate - The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate.The key assumptions used in the impairment tests are described in note 6. Depletion and depreciation Amounts recorded for depletion and depreciation and amounts used for impairment calculations are based on estimates of total proved and probable oil and natural gas reserves and future development capital. By their nature, the estimates of reserves, including the estimates of future prices, costs, and future cash flows, are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material. Decommissioning obligations Amounts recorded for decommissioning obligations and the related accretion expense requires the use of estimates with respect to the amount and timing of decommissioning expenditures. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology. Other provisions are recognized in the period when it becomes probable that there will be a future cash outflow.Share based compensation Compensation costs recognized for share based compensation plans are subject to the estimation of what the ultimate payout will be using pricing models such as the Black-Scholes-Merton model, which is based on significant assumptions such as volatility, expected term, and forfeiture rate.Deferred taxes Tax interpretations, regulations, and legislation in the various jurisdictions in which the Company operates are subject to change. As such, income taxes are subject to measurement uncertainty. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.3. SIGNIFICANT ACCOUNTING POLICIESThe accounting policies set out below have been applied consistently by the Company and its subsidiary to all periods presented in these consolidated financial statements. In addition to the quantitative adjustments from previous GAAP to IFRS, certain comparative amounts have been reclassified to conform to the current year's presentation, as presented in note 22.(a) Basis of consolidationSubsidiariesSubsidiaries are entities controlled by the Company. Control exists when the Company 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 financial statements from the date that control commences until the date that control ceases.Jointly controlled operations and jointly controlled assetsMany of the Company's oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Company's share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs.Transactions eliminated on consolidationIntercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.(b) Financial instrumentsNon-derivative financial instrumentsNon-derivative financial instruments comprise cash and cash equivalents, accounts receivable, investments, accounts payable and accrued liabilities, and credit facilities. Non-derivative financial instruments are recognized initially at fair value net of any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below. Cash and cash equivalents Cash and cash equivalents comprise cash on hand, term deposits held with banks, and other short-term highly liquid investments with original maturities of three months or less, measured at amortized cost. Financial assets at fair value through profit or loss An instrument is classified at fair value through profit or loss if it is held for trading or is designated as such upon initial recognition. Financial instruments are designated at fair value through profit or loss if the Company manages such investments and makes purchase and sale decisions based on their fair value in accordance with the Company's risk management or investment strategy. Upon initial recognition, attributable transaction costs are recognized in profit or loss when incurred. Financial instruments at fair value through profit or loss are measured at fair value, and changes therein are recognized in profit or loss. The Company has designated investments at fair value through profit or loss.Other Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, and credit facilities, are measured at amortized cost using the effective interest method, less any impairment losses.Derivative financial instrumentsFrom time to time, the Company may enter into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.Share capitalCommon shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects.(c) Property, plant, and equipment and exploration and evaluation assetsRecognition and measurementExploration and evaluation expenditures Pre-license costs are recognized in profit or loss as incurred.Exploration and evaluation costs, including the costs of acquiring undeveloped land and drilling costs, are initially capitalized until the drilling of the well is complete and the results have been evaluated. The costs are accumulated in cost centers by well, field, or exploration area pending determination of technical feasibility and commercial viability. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proved or probable reserves are determined to exist. If proved or probable reserves are found, the accumulated costs and associated undeveloped land are transferred to property, plant, and equipment after assessing estimated fair value and recognizing any impairment loss.Exploration and evaluation 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. For purposes of impairment testing, exploration and evaluation assets are allocated to CGUs.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. The cost of development and production assets includes: transfers from exploration and evaluation assets, which generally include the cost to drill the well and the cost of the associated land upon determination of technical feasibility and commercial viability; the cost to complete and tie-in the well; facility costs; the cost of recognizing provisions for future restoration and decommissioning obligations; geological and geophysical costs; and directly attributable overhead. Development and production assets are grouped into CGUs for impairment testing. The Company has grouped its development and production assets into the following seven CGUs: (i) Edson AB (ii) Smoky AB (iii) Northeast BC (iv) Lookout Butte AB (v) Ferrier AB (vi) Miscellaneous AB, and (vii) Saskatchewan. 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). The Company capitalizes the cost of major plant turnarounds and overhauls and depreciates these costs over their estimated useful life of three or four years, depending on each plant.Gains and losses on disposal of an item 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 in profit or loss.Subsequent costsCosts 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. Capitalized oil and natural gas interests generally represent costs incurred in developing proved or 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 operating expenses as incurred.Non-monetary asset swapsExchanges or swaps of non-monetary assets are measured at fair value unless the exchange transaction lacks commercial substance or neither the fair value of the assets given up nor the assets received can be reliably estimated. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the asset given up. Any gain or loss on derecognition of the asset given up is included in profit or loss.Depletion and depreciationThe net carrying value of development and production assets is depleted using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account the estimated future development costs necessary to bring those reserves into production and the estimated salvage value of the assets at the end of their useful lives. Future development costs are estimated taking into account the level of development required to produce the reserves. Proved plus probable reserves are estimated at least annually by independent qualified reserve evaluators and represent the estimated quantities of oil, natural gas, and natural gas liquids which geological, geophysical, and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.The Company has determined the estimated useful lives for gas processing plants, pipeline facilities, and compression facilities to be consistent with the reserve lives of the areas for which they serve. As such, the Company includes the cost of these assets within their associated CGU for the purpose of depletion using the unit of production method. For plant turnarounds and overhauls, the Company has estimated an average useful life of three or four years, depending on each plant, before further work must be performed and depreciates these costs using the straight-line method over the corresponding useful life.The cost of office and other equipment is depreciated using the straight-line method over the estimated useful life of three years.Depreciation methods, useful lives, and residual values are reviewed at each reporting date. Leased assetsLeases wherein the Company assumes substantially all the risks and rewards of ownership are classified as finance leases, when applicable. Upon initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expenses and the reduction of the outstanding liability. The finance expenses are allocated to each year during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability. Other leases are classified as operating leases, which are not recognized on the Company's statement of financial position. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. The Company's presently outstanding leases have been determined to be operating leases.(d) ImpairmentFinancial assetsA 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 profit or loss. 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 profit or loss. Non-financial assetsThe carrying amounts of the Company's non-financial assets, other than exploration and evaluation assets and deferred 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. Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or 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 generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (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. Fair value less costs to sell is determined as the amount that would be obtained from the sale of a CGU in an arm's length transaction between knowledgeable and willing parties. The fair value less costs to sell of oil and natural gas assets is generally determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion projects and its eventual disposal, using assumptions that an independent market participant may take into account. The cash flows are discounted using an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU. Consideration is given to acquisition metrics of recent transactions completed on similar assets to those contained within the relevant CGU.Value in use is determined as the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. Value in use is determined by applying assumptions specific to the Company's continued use and can only take into account approved future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management's forecasts of commodity prices and expected production volumes. The latter takes into account assessments of field reservoir performance and includes expectations about proved and unproved volumes, which are risk-weighted using geological, production, recovery, and economic projections.An impairment loss is recognized if the carrying amount of a CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated to the assets in the CGUs on a pro rata basis. Impairment losses recognized in prior periods are assessed each reporting date if facts or circumstances indicate 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, if no impairment loss had been recognized.(e) Share based compensationThe Company has a share based compensation plan, which is described in note 11. The Company uses the fair value method for valuing share based compensation. Under this method, the compensation cost attributed to stock options is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Upon the settlement of the stock options, the previously recognized value in contributed surplus is recorded as an increase to share capital.(f) ProvisionsA provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.Decommissioning obligations The Company's activities give rise to dismantling, decommissioning, and site disturbance remediation activities. A provision is made for the estimated cost of abandonment and site restoration and capitalized in the relevant asset category. The capitalized amount is depreciated on a unit of production basis over the life of the associated proved plus probable reserves. Decommissioning obligations are measured at the present value of management's best estimate of the expenditure required to settle the present obligation at the reporting 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 accretion (within finance expenses) whereas increases or decreases due to changes in the estimated future cash flows or changes in the discount rate are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established.(g) RevenueRevenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product are transferred to the buyer which is usually when legal title passes to the external party. (h) Finance income and expensesFinance income and expenses comprises interest expense, including interest on credit facilities, accretion on decommissioning obligations, unrealized gains and losses on investments, and interest income. (i) Income taxIncome tax expense is comprised of current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is 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 tax assets and liabilities are offset if there is a legally enforceable right to offset, they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis, or their tax assets and liabilities will be realized simultaneously. A deferred tax asset is recognized to the extent that it is probable that future taxable earnings will be available against which the temporary difference can be utilized. Deferred 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.(j) Flow-through sharesThe Company, from time to time, issues flow-through shares to finance a portion of its exploration capital expenditure program. Pursuant to the terms of the flow-through share agreements, the tax deductions associated with the exploration expenditures are renounced to the subscribers. On issuance of flow-through shares, the premium received on such shares, being the difference between the fair value ascribed to flow-through shares issued and the fair value that would have been received for common shares at the date of issuance of the flow-through shares, is recognized as a liability on the statement of financial position. When the exploration expenditures are incurred, the liability is drawn down, a deferred tax liability is recorded equal to the estimated amount of deferred income tax payable by the Company as a result of the foregone tax benefits, and the difference is recognized in profit or loss.(k) Earnings per shareBasic earnings per share is calculated by dividing the net earnings or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the weighted average number of common shares outstanding during the period for the effects of dilutive instruments such as stock options granted.(l) New standards and interpretations not yet adoptedIn May 2011, the IASB issued four new standards and two amendments. Five of these items related to consolidation, while the remaining one addresses fair value measurement. All of the new standards are effective for annual periods beginning on or after January 1, 2013. Early adoption is permitted.IFRS 10, Consolidated Financial Statements replaces IAS 27, Consolidated Separate Financial Statements. It introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.IFRS 11, Joint Arrangements replaces IAS 31, Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A "joint operation" continues to be accounted for using proportionate consolidation, whereas a "joint venture" must be accounted for using equity accounting. This differs from IAS 31, where there was the choice to use proportionate consolidation or equity accounting for joint ventures. A "joint operation" is defined as the joint operators having rights to the assets, and obligations for the liabilities, relating to the arrangement. In a "joint venture", the joint venture partners have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity.IFRS 12, Disclosure of Interests in Other Entities is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.IFRS 13, Fair Value Measurement is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.IAS 27, Separate Financial Statements has been amended to focus solely on accounting and disclosure requirements when an entity presents separate financial statements, due to the issuance of the new IFRS 10 which is specific to consolidated financial statements.IAS 28, Investments in Associates and Joint Ventures has been amended as a result of the issuance of IFRS 11 and the withdrawal of IAS 31. The amended standard sets out the requirements for the application of the equity method when accounting for interest in joint ventures, in addition to interests in associates.In November 2009, the IASB published IFRS 9, Financial Instruments, which covers the classification and measurement of financial assets as part of its project to replace IAS 39, Financial Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company's own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively.The Company is currently evaluating the impact of adopting all of the newly issued and amended standards.4. DETERMINATION OF FAIR VALUESA number of the Company's accounting policies and disclosures require the determination of fair value, for both financial and non-financial assets and liabilities. Fair values have been determined for measurement and disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.Property, plant, and equipment and exploration and evaluation assetsThe fair value of property, plant, and equipment and exploration and evaluation assets recognized in a business combination, is based on market values. The market value of property, plant, and equipment and exploration and evaluation assets is the estimated amount for which the assets could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm's length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently, and without compulsion. The market value of property, plant, and equipment and exploration and evaluation assets is estimated with reference to the discounted cash flows expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate used to discount the expected cash flows is specific to the asset with reference to general market conditions.The market value of other items of property, plant, and equipment is based on the quoted market prices for similar items.Stock optionsThe fair value of stock options is measured using a Black-Scholes-Merton option pricing model. Measurement inputs include the share price on the measurement date, exercise price of the instrument, estimated forfeiture rate, expected volatility (based on the weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instrument (based on historical experience and general information), expected dividends, and the risk free interest rate (based on government bonds).5. EXPLORATION AND EVALUATION ASSETSTotalBalance, January 1, 201036,398Additions13,519Transfer to property, plant, and equipment(8,770)Transfer to property, plant, and equipment, held for sale(6,909)Dispositions(395)Impairment(2,438)Balance, December 31, 201031,405Additions31,644Transfer to property, plant, and equipment(24,153)Transfer to property, plant, and equipment, held for sale(479)Dispositions(4,109)Impairment(13,667)Balance, December 31, 201120,641Exploration and evaluation assets consist of the Company's exploration projects which are pending the determination of proved or probable reserves. Additions represent the Company's share of costs incurred on exploration and evaluation assets during the year, consisting primarily of undeveloped land and drilling costs until the drilling of the well is complete and the results have been evaluated. Included in the $31.6 million in additions during the year ended December 31, 2011 were additions of $17.8 million related to the Edson AB CGU, $11.3 million related to the Miscellaneous AB CGU, and $1.8 million related to the Northeast BC CGU. Transfers to property, plant, and equipment during the year ended December 31, 2011 included $17.8 million from the Edson AB CGU and $6.3 million from the Northeast BC CGU as a result of successful capital activity in the Company's core areas.Included in the $13.5 million in additions during the year ended December 31, 2010 were additions of $5.3 million related to the Northeast BC CGU, $3.2 million related to the Miscellaneous AB CGU, $2.4 million related to the Edson AB CGU, and $2.4 million related to the Company's Pembina property which was sold during the fourth quarter of 2010. Transfers to property, plant, and equipment during the year ended December 31, 2010 included $5.5 million from the Northeast BC CGU, $2.5 million from the Edson AB CGU, and $0.8 million related to the Pembina property as a result of successful capital activity in these areas during the year.ImpairmentsExploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the year ended December 31, 2011, total exploration and evaluation asset impairments of $13.7 million were recognized. Asset impairments of $12.5 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGUs - Miscellaneous AB and Saskatchewan). Of this $12.5 impairment, $12.2 million related to unsuccessful exploration drilling activities in Southern Alberta during the year. Additional exploration and evaluation impairments of $1.2 million were recognized in 2011 relating to the expiry of undeveloped land rights (CGUs - Northeast BC, Ferrier AB and Miscellaneous AB). For the year ended December 31, 2010, the Company recognized exploration and evaluation asset impairments of $2.4 million due to the expiry of undeveloped land rights (CGUs - Ferrier AB and Miscellaneous AB). 6. PROPERTY, PLANT, AND EQUIPMENTCost or Deemed CostTotalBalance, January 1, 2010176,396Additions15,115Transfer from exploration and evaluation assets8,770Transfer to property, plant, and equipment, held for sale(37,932)Dispositions(92)Derecognition of plant overhauls(57)Change in decommissioning obligation estimates2,164Capitalized share based compensation95Balance, December 31, 2010164,459Additions63,567Transfer from exploration and evaluation assets24,153Transfer from property, plant, and equipment, held for sale1,879Transfer to property, plant, and equipment, held for sale(1,076)Dispositions(21,410)Change in decommissioning obligation estimates4,939Capitalized share based compensation335Balance, December 31, 2011236,846Accumulated Depletion, Depreciation, and ImpairmentTotalOpening balance, January 1, 2010287Impairment, January 1, 201024,666Balance, January 1, 201024,953Depletion and depreciation13,099Impairment4,705Transfer to property, plant, and equipment, held for sale(13,156)Derecognition of plant overhauls(57)Balance, December 31, 201029,544Depletion and depreciation20,729Impairment2,960Transfer to property, plant, and equipment, held for sale(441)Dispositions(8,278)Balance, December 31, 201144,514Net Book ValueTotalJanuary 1, 2010151,443December 31, 2010134,915December 31, 2011192,332During the year ended December 31, 2011, approximately $0.8 million (2010 - $0.5 million) of directly attributable general and administrative costs were capitalized as expenditures on property, plant, and equipment.Depletion and depreciationThe calculation of depletion and depreciation expense for the year ended December 31, 2011 included an estimated $202.6 million (2010 - $95.4 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $7.8 million (2010 - $7.7 million) for the estimated salvage value of production equipment and facilities. ImpairmentsImpairment tests were carried out at December 31, 2011 and were based on fair value less costs to sell calculations using the following commodity price estimates of the Company's independent reserve evaluators:West TexasIntermediate OilForeign ExchangeEdmonton Oil Par PriceAECO Gas PriceYear($US/bbl)Rate$(CDN/bbl)$(CDN/mmbtu)201297.000.98097.963.492013100.000.980101.024.132014100.000.980101.024.592015100.000.980101.025.052016100.000.980101.025.512017100.000.980101.025.972018101.350.980102.406.212019103.380.980104.476.332020105.450.980106.586.462021107.560.980108.736.58EscalateThereafter2.0% per year2.0% per year2.0% per yearThe impairment tests at December 31, 2011 were primarily based on the net present value of cash flows from oil and natural gas reserves of each CGU at discount rates of 10 percent to 20 percent. Consideration was also given to acquisition metrics of recent transactions on similar assets. For the year ended December 31, 2011, the Company recorded an impairment charge of $3.0 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices at December 31, 2011 compared to December 31, 2010. As well, the Company had limited capital expenditures in these CGUs to maintain their reserve values.For the year ended December 31, 2010, the Company recognized net impairments of $4.7 million, comprised of impairments of $5.8 million, relating to Lookout Butte AB, Ferrier AB, and Miscellaneous AB CGUs and impairment reversals of $1.1 million, relating to Smoky AB. The impairments were based on the difference between the period end net book value of the CGUs and the recoverable amount. The recoverable amount was determined using fair value less costs to sell based on discounted cash flows of proved plus probable reserves using discount rates of 10% to 20%. Impairment reversals were made during the fourth quarter of 2010 mainly as a result of successful capital activity which led to an increase in proved plus probable reserves.7. PROPERTY, PLANT, AND EQUIPMENT, HELD FOR SALEProperty, Plant,Exploration andand EquipmentEvaluation AssetsTotalBalance, January 1, 201021,880-21,880Transfer from exploration and evaluation assets-6,9096,909Transfer from property, plant, and equipment24,776-24,776Dispositions(44,799)(6,746)(51,545)Balance, December 31, 20101,8571632,020Transfer from exploration and evaluation assets-479479Transfer from property, plant, and equipment635-635Transfer to property, plant, and equipment(1,879)-(1,879)Dispositions(613)(642)(1,255)Balance, December 31, 2011---At December 31, 2010, the Company had property, plant, and equipment, held for sale of $2.0 million, which consisted of oil and natural gas assets located in Saskatchewan. The assets were initially classified as held for sale upon transition to IFRS on January 1, 2010. The Company had an agreement in place to sell the assets during the first quarter of 2010; however, the purchaser was unable to secure financing to close the sale. The Company received deposits totaling approximately $0.3 million during the second quarter of 2010 relating to the sale and recognized the full amount as a gain. In the fourth quarter of 2011, the Company discontinued actively marketing the assets for sale and as such, transferred the assets to property, plant, and equipment.8. CREDIT FACILITIESAt December 31, 2011, the Company had total credit facilities of $80.0 million, consisting of an $80.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At December 31, 2011, $5.2 million (December 31, 2010 - $35.4 million) had been drawn on the revolving credit facility. In addition, at December 31, 2011, the Company had outstanding letters of guarantee of approximately $1.0 million (December 31, 2010 - $0.2 million). The next review of the revolving credit facility by the bank is scheduled on or before May 31, 2012. 9. PROVISIONS - DECOMMISSIONING OBLIGATIONSThe Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and facilities, and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation at 2% per year) required to settle the decommissioning obligations is approximately $28.4 million which is estimated to be incurred between 2012 and 2041. At December 31, 2011, a risk-free rate of 2.4% (December 31, 2010 - 3.5%) was used to calculate the net present value of the decommissioning obligations. Year EndedYear EndedDecember 31, 2011December 31, 2010Balance, beginning of period15,09915,113Provisions incurred1,534302Provisions disposed(941)(1,812)Provisions settled(363)(868)Revisions3,4051,862Accretion516502Balance, end of period19,25015,099Provisions, held for sale-1,064Provisions19,25014,03519,25015,09910. SHAREHOLDERS' CAPITALThe Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, and Class B preferred shares, issuable in series. No non-voting common shares or preferred shares have been issued.Voting Common SharesNumberAmountBalance, January 1, 201065,084168,038Exercise of stock options58126Balance, December 31, 201065,142168,164Exercise of stock options97193Share issuances22,85660,963Share issue costs, net of future tax effect of $0.9 million(2,659)Flow-through share premium(813)Balance, December 31, 201188,095225,848On February 23, 2011, the Company issued approximately 15.6 million common shares at a price of $2.30 per share for gross proceeds of approximately $36.0 million. On December 21, 2011, the Company issued approximately 7.2 million common shares for gross proceeds of approximately $25.0 million. Under the issuance, approximately 6.0 million common shares were issued at a price of $3.35 per share and approximately 1.2 million common shares were issued on a flow-through basis at a price of $4.00 per share. Under the terms of the flow-through share agreement, the Company is committed to spend 100% of the gross proceeds on qualifying exploration expenditures prior to December 31, 2012. Upon issuance, the premium received on the flow-through shares, being the difference between the fair value of the flow-through shares issued and the fair value that would have been received for common shares at the date of issuance, was recognized as a liability. A reconciliation of the flow-through share premium is as follows:AmountBalance, January 1, 2010 and December 31, 2010-Premium on flow-through shares issued813Balance, December 31, 2011813Proceeds from the share issuances are being used to fund the Company's Edson Bluesky and Dawson Montney developments, other capital projects, and general corporate purposes. 11. SHARE BASED COMPENSATION PLANSStock optionsThe Company has authorized and reserved for issuance 8.8 million common shares under a stock option plan enabling certain officers, directors, employees, and consultants to purchase common shares. The Company will not issue options exceeding 10% of the shares outstanding at the time of the option grants. Under the plan, the exercise price of each option equals the market price of the Company's shares on the date of the grant. The options vest over a period of three years and an option's maximum term is 5 years. At December 31, 2011, 7.9 million options are outstanding at exercise prices ranging from $1.10 to $3.00 per share.The number and weighted average exercise price of stock options are as follows:Weighted AverageNumber of OptionsExercise Price ($)Balance, January 1, 20106,0722.08Granted1,2351.48Exercised(58)1.31Forfeited(773)2.19Cancelled(2,599)3.01Balance, December 31, 20103,8771.26Granted4,1972.60Exercised(97)1.18Forfeited(35)1.53Cancelled--Balance, December 31, 20117,9421.97Exercisable at December 31, 20112,1561.24Subsequent to December 31, 2011, the Company granted 0.7 million options at an exercise price of $3.46 per share.The following table summarizes the stock options outstanding and exercisable at December 31, 2011:Options OutstandingOptions ExercisableWeighted AverageWeighted AverageWeighted AverageExercise PriceNumberRemaining LifeExercise PriceNumberExercise Price$1.10 to $1.993,6452.91.242,0561.20$2.00 to $3.004,2974.32.591002.107,9423.61.972,1561.24WarrantsThe Company has an arrangement that allows warrants to be issued to directors, officers, and employees. The maximum number of common shares that may be issued, and that have been reserved for issuance under this arrangement, is 2.4 million. Warrants granted under this arrangement vest over three years and have exercise prices ranging from $3.75 per share to $6.75 per share. During the year ended December 31, 2007, the Company issued 2.4 million warrants under this arrangement. The fair value of the warrants granted under this arrangement at the date of issue was determined to be $nil using the minimum value method as they were issued prior to the Company becoming publicly traded. During 2009, approval was obtained to extend the expiry date of the warrants to December 23, 2012. On October 29, 2009, the Company issued an additional 1.2 million warrants at an exercise price of $1.40 per share in conjunction with a private placement share issuance. The warrants vested immediately and have an expiry date of October 29, 2012. The number and weighted average exercise price of warrants are as follows:Number ofWeighted AverageWarrantsExercise PriceBalance, January 1, 20103,6043.67Forfeited(83)4.75Balance, December 31, 2010 and December 31, 20113,5213.64Exercisable at December 31, 20113,5213.64The following table summarizes the warrants outstanding and exercisable at December 31, 2011:Warrants Outstanding and ExercisableWeighted AverageWeighted AverageExercise PriceNumberRemaining LifeExercise Price$1.401,2000.81.40$3.75 to $4.057401.03.76$4.50 to $5.258071.04.55$6.00 to $6.757741.06.053,5210.93.64Share based compensationThe Company accounts for its share based compensation plans using the fair value method. Under this method, compensation cost is charged to earnings over the vesting period for stock options and warrants granted to officers, directors, employees, and consultants with a corresponding increase to contributed surplus. The fair value of the stock options granted were estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions: December 31, 2011December 31, 2010Risk-free interest rate (%)2.32.0Expected life (years)4.04.0Expected volatility (%)82.899.3Expected dividend yield (%)--Forfeiture rate (%)9.48.7Weighted average fair value of options granted ($ per option)1.590.8012. PER SHARE AMOUNTSThe following table summarizes the weighted average number of shares used in the basic and diluted net loss per share calculations:December 31, 2011December 31, 2010Weighted average number of shares - basic and diluted78,80465,129For the years ended December 31, 2011 and 2010, the stock options and warrants outstanding were anti-dilutive and were not included in the diluted loss per share calculation.13. KEY MANAGEMENT PERSONNELThe Company considers its directors and executives to be key management personnel. The key management personnel compensation is comprised of the following:Year EndedYear EndedDecember 31, 2011December 31, 2010Short-term wages and benefits2,8271,227Share based compensation (1)2,610964Total (2) (3)5,4372,191(1) Represents the amortization of share based compensation expense associated with the Company's share based compensation plans granted to key management personnel. (2) Balances outstanding and payable at December 31, 2011 were $1.0 million (2010 - $nil). (3) At December 31, 2011 and 2010, key management personnel included 16 individuals. 14. FINANCE EXPENSESFinance expenses include the following:December 31, 2011December 31, 2010Interest expense (note 8)8612,846Accretion of decommissioning obligations (note 9)516502Realized loss on investments7988Finance expenses1,4563,43615. INCOME TAXES(a) The provision for income taxes in the consolidated statement of operations and comprehensive loss reflects an effective tax rate which differs from the expected statutory tax rate. The differences were accounted for as follows: December 31, 2011December 31, 2010Loss before taxes(13,077)(5,985)Statutory income tax rate26.5%28.0%Expected income tax reduction(3,465)(1,676)Increase (decrease) in income taxes resulting from:Share based compensation and other non-deductible amounts837304Rate reduction and other181(77)Recognition of previously unrecognized tax assets(5,038)792(7,485)(657)The decrease in the statutory tax rate from 2010 to 2011 was due to a reduction in the 2011 Canadian corporate tax rate as part of a series of corporate rate reductions previously enacted by the Canadian government. The Company has recognized a net deferred tax asset based on the independently evaluated reserve report as cash flows are expected to be sufficient to realize the deferred tax asset.(b) Recognized deferred tax balances for the years ended December 31, 2011 and 2010 are as follows: 2011Balance January 1, 2011Recognized in Earnings or LossRecognized in EquityBalance December 31, 2011Deferred income tax assets (liabilities):Oil and natural gas properties and equipment(435)1,555-1,120Decommissioning obligations3,7751,037-4,812Share issue costs119(260)886745Non-capital losses2,6135,153-7,766Net deferred income tax asset6,0727,48588614,4432010Balance January 1, 2010Recognized in Earnings or LossRecognized in EquityBalance December 31, 2010Deferred income tax assets (liabilities):Oil and natural gas properties and equipment(1,694)1,259-(435)Decommissioning obligations3,778(3)-3,775Risk management contracts261(261)--Share issue costs401(282)-119Non-capital losses2,669(56)-2,613Net deferred income tax asset5,415657-6,072At December 31, 2011, the Company has estimated federal tax pools of $251.0 million (2010 - $198.2 million) available for deduction against future taxable income.The Company has accumulated non-capital losses for income tax purposes of approximately $31.1 million (2010 - $31.4 million), which can be used to offset income in future periods. These losses are as follows:Year of expiryAmount2029248202890320278,12120266,74420258,06620242,20920234,77231,063(c) Deferred tax assets have not been recognized in respect of the following items: 20112010Deductible temporary differences7,6176,857Capital losses1,79722,7079,41429,564The tax losses expire up to 2029. The deductible temporary differences do not expire under current tax legislation. Deferred tax assets have not been recognized in respect of these items because it is not probable that future taxable profits will be available against which the Company can utilize the benefits.In 2011, $5.1 million of previously unrecognized tax losses were recognized as a result of changes in estimates of future results from operating activities.16. FAIR VALUE OF FINANCIAL INSTRUMENTSCash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, credit facilitiesThe fair value of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and credit facilities at December 31, 2011 approximated their carrying value due to their short term to maturity.InvestmentsThe Company is required to classify fair value measurements using a hierarchy that reflects the significance of the inputs used in making the measurements. The fair value hierarchy is as follows:Level 1 - quoted prices in active markets for identical assets or liabilities Level 2 - inputs other than quoted prices included in Level 1 that are observable for the asset or liability, either directly or indirectly Level 3 - inputs for the asset or liability that are not based on observable market data The fair value of investments is considered to be level 2. At December 31, 2010, investments include 875,000 warrants of Hyperion Exploration Corp. ("Hyperion") at an exercise price of $2.00 per warrant. Each warrant was convertible into one common share of Hyperion and expired unexercised on November 7, 2011. The warrants were obtained as partial consideration for the sale of certain oil and natural gas assets to Hyperion in the fourth quarter of 2010. The investment was classified as held for trading and was measured at fair value through profit or loss each reporting period using the Black-Scholes-Merton option pricing model. 17. FINANCIAL RISK MANAGEMENTThe Company's activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities. The Company employs risk management strategies and policies to ensure that any exposure to risk is in compliance with the Company's business objectives and risk tolerance levels. Risk management is ultimately established by the Board of Directors and is implemented by management.Market riskMarket risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign currency risk, interest rate risk, and other price risk, such as commodity price risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns. The Company may use financial derivatives or physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.Foreign exchange risk The prices received by the Company for the production of oil, natural gas, and NGLs are primarily determined in reference to US dollars, but are settled with the Company in Canadian dollars. The Company's cash flow from commodity sales will therefore be impacted by fluctuations in foreign exchange rates. Assuming that all other variables remain constant, a $0.01 increase or decrease in the Canadian/US dollar exchange rate would have impacted net loss and other comprehensive loss by approximately $0.4 million for the year ended December 31, 2011 (2010 - $0.2 million).Interest rate risk The Company is exposed to interest rate risk as it borrows funds at floating interest rates (note 8). In addition, the Company may at times issue shares on a flow-through basis (note 10). This results in the Company being exposed to interest rate risk to the Canada Revenue Agency for interest on unexpended funds on the Company's flow-through share obligations. The Company currently does not use interest rate hedges or fixed interest rate contracts to manage the Company's exposure to interest rate fluctuations. A 100 basis point increase or decrease in interest rates would have impacted net loss and other comprehensive loss by approximately $0.2 million for the year ended December 31, 2011 (2010 - $0.4 million).Commodity price risk Oil and natural gas prices are impacted by not only the relationship between the Canadian and US dollar but also by world economic events that dictate the levels of supply and demand. The Company's oil, natural gas, and NGLs production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company's cash flow from product sales will therefore be impacted by fluctuations in commodity prices. A $1.00/boe increase or decrease in commodity prices would have impacted net loss and other comprehensive loss by approximately $0.9 million for the year ended December 31, 2011 (2010 - $0.6 million).Credit riskCredit risk represents the financial loss that the Company would suffer if the Company's counterparties to a financial instrument, in owing an amount to the Company, fail to meet or discharge their obligation to the Company. A substantial portion of the Company's accounts receivable and deposits are with customers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally grants unsecured credit but routinely assesses the financial strength of its customers and joint venture partners.The Company sells the majority of its production to three petroleum and natural gas marketers and therefore is subject to concentration risk. Historically, the Company has not experienced any collection issues with its oil and natural gas marketers. Joint venture receivables are typically collected within one to three months of the joint venture invoice being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval for significant capital expenditures prior to the expenditure being incurred. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, in certain circumstances, the Company may cash call a partner in advance of expenditures being incurred.The maximum exposure to credit risk is represented by the carrying amount on the statement of financial position. At December 31, 2011, $10.2 million or 90.6% of the Company's outstanding accounts receivable were current while $0.5 million or 4.4% were outstanding over 90 days. At December 31, 2011, the allowance for doubtful accounts was $0.1 million.Liquidity riskLiquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company's processes for managing liquidity risk include ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual, quarterly, and monthly capital expenditure budgets, which are monitored and updated as required, and requires authorizations for expenditures on projects to assist with the management of capital. In managing liquidity risk, the Company ensures that it has access to additional financing, including potential equity issuances and additional debt financing. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.The following are the contractual maturities of financial liabilities at December 31, 2011:CarryingContractualLess thanOne toMore thanAmountCash FlowsOne YearTwo YearsTwo YearsNon-derivative financial liabilitiesAccounts payable and accrued liabilities34,69234,69234,692--Revolving credit facility5,1825,1825,182--39,87439,87439,874--18. CAPITAL MANAGEMENTThe Company's objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at an acceptable risk, and to maintain investor, creditor, and market confidence to sustain future development of the business.The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include shareholders' equity and net debt (current liabilities, including the revolving credit facility and excluding the current portion of decommissioning obligations, less current assets, excluding property, plant, and equipment, held for sale). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt, or adjust its capital spending to manage its current and projected debt levels.December 31, 2011December 31, 2010Shareholders' equity179,617124,113Net debt27,73635,200In addition, management prepares annual, quarterly, and monthly budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment. The Company's share capital is not subject to external restrictions; however, the Company's revolving operating demand loan credit facility includes a covenant requiring the Company to maintain a working capital ratio of not less than one-to-one. The working capital ratio, as defined by its creditor, is calculated as current assets plus any undrawn amounts available on its credit facilities less current liabilities excluding any current portion drawn on the credit facility. The Company was fully compliant with this covenant at December 31, 2011.There were no changes in the Company's approach to capital management from the previous year.19. SUPPLEMENTAL DISCLOSURESPresentation of expensesThe Company's statement of operations is prepared primarily by nature of expense, with the exception of employee compensation costs which are included in both production and general and administrative expenses. Included in production and general and administrative expenses for the year ended December 31, 2011 are $0.1 million and $4.7 million of wages and benefits, respectively (2010 - $0.1 million and $2.7 million, respectively).20. SUPPLEMENTAL CASH FLOW INFORMATIONDecember 31, 2011December 31, 2010Accounts receivable(1,139)(5,117)Prepaid expenses and deposits38565Accounts payable and accrued liabilities23,7624,533Change in non-cash working capital22,661(19)Relating to:Investing23,615724Operating(954)(743)Change in non-cash working capital22,661(19)21. COMMITMENTSThe following is a summary of the Company's contractual obligations and commitments at December 31, 2011: 20122013201420152016ThereafterTotalOffice leases574484365---1,423Field equipment leases1,5731,276450---3,299Drilling rig2,489-----2,489Firm transportation agreements45717811728102792Capital processing agreements----200-2005,0931,9389322821028,203In addition to the above commitments, as a result of the issuance of flow-through shares in December 2011 (see note 10), the Company is committed to expend $5.0 million on qualifying exploration expenditures prior to December 31, 2012. As at December 31, 2011, the Company had not incurred any amounts in connection with this flow-through share commitment.Under the terms of a farm-in agreement, the Company is also committed to drill one Edson Bluesky horizontal well prior to July 1, 2012. The estimated cost to drill the well is $3.1 million.22. TRANSITION TO IFRSThe Company's accounting policies under IFRS, as described in note 3, differ from those followed under previous GAAP. These accounting policies have been applied for the year ended December 31, 2011, as well as to the opening statement of financial position on the transition date, January 1, 2010 and the comparative information for the year ended December 31, 2010.The adjustments arising from the application of IFRS to amounts on the statement of financial position on the transition date and on transactions prior to that date were recognized as an adjustment to the Company's opening deficit on the statement of financial position when appropriate. On transition to IFRS on January 1, 2010, the Company used certain exemptions allowed under IFRS 1, First Time Adoption of International Reporting Standards. The exemptions used were as follows:Full cost accounting IFRS 1 allows an entity that used full cost accounting under its previous GAAP to elect, at the time of adoption of IFRS, to measure oil and natural gas assets in the development and production phases by allocating the amount determined under the entity's previous GAAP for those assets to the underlying assets on a pro rata basis using reserve volumes or reserve values as of that date. The Company has used reserve values at January 1, 2010 to allocate the cost of development and production assets to CGUs.Business combinations IFRS 1 allows an entity to use the IFRS rules for business combinations on a prospective basis rather than restating all business combinations prior to transition to IFRS that were accounted for under previous GAAP.Share based compensation IFRS 1 allows an entity an exemption on IFRS 2, Share-Based Payments, with respect to equity instruments which vested before the transition date to IFRS.Decommissioning obligations As the Company elected to use the full cost accounting exemption for oil and gas, a decommissioning obligation exemption was also used that allows for the adjustment of decommissioning obligations on transition to IFRS to be offset to the Company's opening deficit on the statement of financial position on the transition date.IFRS Opening Statement of Financial Position - As at January 1, 2010Effect ofPreviousTransition to($000s)NoteGAAPIFRSIFRSAssetsCurrent assetsCash and cash equivalents1,854-1,854Accounts receivable5,042-5,042Prepaid expenses and deposits1,443-1,443Property, plant, and equipment, held for sale(a)-21,88021,8808,33921,88030,219Property, plant, and equipment(a,b)245,562(94,119)151,443Exploration and evaluation assets(a)-36,39836,398Deferred income taxes(g)2555,1605,415245,817(52,561)193,256254,156(30,681)223,475LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities6,397-6,397Revolving credit facility52,355-52,355Secured bridge facility20,243-20,243Risk management contracts1,042-1,042Decommissioning obligations, held for sale(c)-1,7051,70580,0371,70581,742Decommissioning obligations(c)10,0843,32413,40890,1215,02995,150Shareholders' EquityShareholders' capital(k)166,6321,406168,038Contributed surplus(d)3,7148114,525Deficit(b,c,d,g,k)(6,311)(37,927)(44,238)164,035(35,710)128,325254,156(30,681)223,475IFRS Statement of Financial Position - As at December 31, 2010Effect ofPreviousTransition to($000s)NoteGAAPIFRSIFRSAssetsCurrent assetsCash and cash equivalents10,159-10,159Accounts receivable878-878Prepaid expenses and deposits79-79Property, plant, and equipment, held for sale(a)-2,0202,02011,1162,02013,136Property, plant, and equipment(a,b,e,i,j)201,018(66,103)134,915Exploration and evaluation assets(a,b)-31,40531,405Deferred income taxes(g)1,6824,3906,072202,700(30,308)172,392213,816(28,288)185,528LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities10,930-10,930Revolving credit facility35,386-35,386Decommissioning obligations, held for sale(c)-1,0641,06446,3161,06447,380Decommissioning obligations(c)9,5334,50214,03555,8495,56661,415Shareholders' EquityShareholders' capital(k)166,7581,406168,164Contributed surplus(d)4,9345815,515Deficit(b,c,d,e,f,g,i,j,k)(13,725)(35,841)(49,566)157,967(33,854)124,113213,816(28,288)185,528IFRS Statement of Operations and Comprehensive Loss - Year Ended December 31, 2010($000s, except per share amounts)NotePrevious GAAPEffect of Transition to IFRSIFRSRevenueOil and natual gas sales34,530-34,530Royalties(5,397)-(5,397)29,133-29,133Realized loss on risk management contracts(628)-(628)Unrealized gain on risk management contracts1,042-1,04229,547-29,547ExpensesProduction(i)8,483(280)8,203Transportation1,026-1,026Depletion and depreciation(c,e)23,024(9,925)13,099Asset impairment(b)-7,1437,143General and administrative(j)3,2573603,617Share based compensation(d)1,086(141)945Interest(h)2,494(2,494)-Unrealized loss on investments(h)88(88)-39,458(5,425)34,033Operating loss(9,911)5,425(4,486)Other Expenses (Income)Finance expense(c,h)-3,4363,436Finance income(h)-(1,361)(1,361)Other income(h)(1,009)1,009-Gain on sale of assets(f)-(576)(576)(1,009)2,5081,499Loss before taxes(8,902)2,917(5,985)TaxesDeferred income tax reduction(g)1,488(831)657Net loss and comprehensive loss(7,414)2,086(5,328)IFRS Statement of Cash Flows - Year Ended December 31, 2010Effect ofPreviousTransition to($000s)NoteGAAPIFRSIFRSOperating ActivitiesNet earnings (loss)(7,414)2,086(5,328)Depletion and depreciation(c,e)23,024(9,925)13,099Asset impairment(b)-7,1437,143Share based compensation(d)1,086(141)945Finance expense(c,h)-3,4363,436Interest paid(h)-(2,846)(2,846)Gain on sale of assets(f)-(576)(576)Deferred income tax reduction(g)(1,488)831(657)Unrealized loss on investments(h)88(88)-Unrealized gain on risk management contracts(1,042)-(1,042)14,254(80)14,174Decommissioning expenditures(868)-(868)Change in non-cash working capital(743)-(743)12,643(80)12,563Financing ActivitiesIssuance of shares75-75Share issue costs---Revolving credit facility(16,969)-(16,969)Secured bridge facility(20,243)-(20,243)(37,137)-(37,137)Investing ActivitiesCapital expenditures - property, plant, and equipment(a)(28,714)13,599(15,115)Capital expenditures - exploration and evaluation assets(a)-(13,519)(13,519)Asset dispositions50,630-50,630Change in non-cash working capital724-72422,6408022,720Change in cash and cash equivalents(1,854)-(1,854)Cash and cash equivalents, beginning of period1,854-1,854Cash and cash equivalents, end of period---Notes to reconciliations(a) IFRS 1 election for full cost oil and gas entities The Company elected to use an IFRS 1 exemption whereby the previous GAAP full cost oil and gas pool was used to measure exploration and evaluation assets and development and production assets on transition to IFRS as follows:(i) exploration and evaluation assets were reclassified from the full cost pool to intangible exploration assets at the amount that was recorded under previous GAAP (ii) the remaining full cost pool was allocated to development and production assets and components pro rata using reserve values This resulted in a transfer of $36.4 million to exploration and evaluation assets and a corresponding decrease to property, plant, and equipment on transition to IFRS. In addition, on transition to IFRS the Company reclassified $21.9 million of property, plant, and equipment to property, plant, and equipment, held for sale, consisting of certain oil and natural gas assets located in Niton, Alberta and Saskatchewan.(b) Impairment of property, plant, and equipment and exploration and evaluation assetsIn accordance with IFRS, impairment tests of property, plant, and equipment must be performed at the CGU level as opposed to the entire property, plant, and equipment balance which was required under previous GAAP through the full cost ceiling test. An impairment is recognized if the carrying value exceeds the recoverable amount for a CGU. For the Company, the recoverable amount is determined using fair value less costs to sell based on discounted future cash flows of proved plus probable reserves using forecast prices and costs. Property, plant, and equipment impairments can be reversed in future periods if the recoverable amount increases.Upon transition to IFRS on January 1, 2010, the Company recognized an impairment of $35.8 million relating to various CGUs. Of this impairment, $11.2 million related to property, plant, and equipment reclassified to property, plant, and equipment, held for sale (see note (a) above). For the year ended December 31, 2010, the Company recognized net impairments of $4.7 million, comprised of impairments of $5.8 million, relating to Lookout Butte AB, Ferrier AB, and Miscellaneous AB CGUs and impairment reversals of $1.1 million, relating to Smoky AB. The impairments were based on the difference between the period end net book value of the CGUs and the recoverable amount. The recoverable amount was determined using fair value less costs to sell based on discounted cash flows of proved plus probable reserves using discount rates of 10% to 20%. Impairment reversals were made during the fourth quarter of 2010 mainly as a result of successful capital activity which led to an increase in proved plus probable reserves.Exploration and evaluation assets are assessed for impairment when they are reclassified to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the year ended December 31, 2010, the Company recognized impairments of $2.4 million due to the expiry of undeveloped land rights.(c) Decommissioning obligationsUnder previous GAAP, decommissioning obligations were discounted at a credit adjusted risk free rate of seven percent. Under IFRS, the estimated cash flows to abandon and reclaim the wells and facilities has been risk adjusted, therefore the provision is discounted at the risk free rate in effect at the end of each reporting period. The change in the decommissioning obligations each period as a result of changes in the discount rate will result in an offsetting charge to property, plant, and equipment. Upon transition to IFRS, decommissioning obligations were discounted at a risk free rate of 4.08%. The impact of this change was a $5.0 million increase in the decommissioning obligations with a corresponding increase to the deficit in the statement of financial position. Of this increase, $1.7 million related to property, plant, and equipment reclassified to property, plant, and equipment, held for sale upon transition to IFRS (see note (a) above). As at December 31, 2010, decommissioning obligations were discounted at a risk free rate of 3.48%. As a result, the decommissioning obligations were $5.6 million higher at December 31, 2010 than under previous GAAP due to the change in discount rate and its impact on the liabilities incurred or acquired during 2010.As a result of the change in the discount rate, the decommissioning obligation accretion expense decreased by $0.2 million during the year ended December 31, 2010 as the lower discount rate more than offset the impact of the higher obligation. In addition, under previous GAAP accretion of the discount was included in depletion and depreciation expense. Under IFRS, accretion is included in finance expenses.(d) Share based compensationUnder previous GAAP, the Company recognized an expense related to share based compensation on a straight-line basis through the date of full vesting and did not incorporate a forfeiture rate at the grant date. Under IFRS, the Company is required to recognize the expense over the individual vesting periods for the graded vesting awards and estimate a forfeiture rate at the date of grant and update it throughout the vesting period. The impact on transition was an increase to contributed surplus of $0.8 million with an offsetting increase to the opening deficit. For the year ended December 31, 2010, the result was a decrease of $0.1 million in share based compensation expense with a corresponding decrease to contributed surplus.(e) Depletion and depreciationUpon transition to IFRS, the Company adopted a policy of depleting oil and natural gas interests on a unit of production basis over proved plus probable reserves. The depletion policy under previous GAAP was based on a unit of production method over proved reserves. In addition, depletion was calculated on the full cost pool under previous GAAP. IFRS requires depletion and depreciation to be calculated based on CGUs and separate components of property, plant, and equipment. There was no impact of this difference on adoption of IFRS at January 1, 2010 as a result of the IFRS 1 election as discussed in note (a) above. For the year ended December 31, 2010, depletion and depreciation decreased by $9.3 million as a result of the change in the depletion calculation.(f) Gains and losses on dispositions Under previous GAAP, proceeds from dispositions were deducted from the full cost pool without recognition of a gain or loss unless the deduction resulted in a change in the depletion rate of 20 percent or greater. Under IFRS, gains and losses are recorded on dispositions and are calculated as the difference between the proceeds on disposition and the net book value of the assets disposed. For the year ended December 31, 2010, the Company recognized a $0.6 million gain on dispositions under IFRS compared to $nil under previous GAAP.(g) Deferred income taxesUnder IFRS there is no requirement to separate the portion of deferred income taxes related to current assets or liabilities. Adjustments to deferred income taxes have been made in regards to the adjustments noted above that resulted in a change to the temporary difference between tax values and accounting values. Deferred income tax assets are only recognized to the extent that it is probable that future taxable profits will be available against which unused tax losses and unused tax credits can be utilized.(h) Finance expenses and finance incomeUnder IFRS, separate line items are required in the statement of operations and comprehensive income for finance expenses and finance income. The items under previous GAAP that were reclassified to finance expenses were interest expense, accretion of decommissioning obligations, and unrealized losses on investments. The items under previous GAAP that were reclassified to finance income were interest income and other income.(i) Major turnaround and overhaul expensesUnder IFRS, the Company capitalizes the cost of major plant turnarounds and overhauls and depreciates these costs over their useful life. Previously these costs were charged to operating expenses.(j) General and administrative expensesUnder IFRS, only directly attributable costs can be capitalized to property, plant, and equipment. For the year ended December 31, 2010, the impact was a $0.4 million increase to general and administrative expenses due to the reversal of certain costs deemed not directly attributable to property, plant, and equipment under IFRS.(k) Flow-through sharesUnder previous GAAP, the deferred tax impact on renouncement of flow-through shares was recorded against shareholders' capital. Under IFRS, a premium liability is recorded on the issuance of flow-through shares, which is relieved upon renouncement, with the difference recognized as deferred tax expense.CORPORATE INFORMATIONOFFICERS AND DIRECTORSRobert J. Zakresky, CAPresident, CEO & DirectorBANKNational Bank of Canada2700, 530 - 8th Avenue SWNolan Chicoine, MPAcc, CAVP Finance & CFOCalgary, Alberta T2P 3S8Terry L. Trudeau, P.Eng.VP Operations & COO TRANSFER AGENTValiant Trust CompanyWeldon Dueck, BSc., P.Eng.VP Business Development310, 606 - 4th Street SW Calgary, Alberta T2P 1T1R.D. (Rick) Sereda, M.Sc., P.Geol.VP ExplorationLEGAL COUNSELHelmut R. Eckert, P.LandVP LandGowling Lafleur Henderson LLP 1400, 700 - 2nd Street SWCalgary, Alberta T2P 4V5Kevin KeithVP ProductionLarry G. Moeller, CA, CBVChairman of the BoardAUDITORS KPMG LLP2700, 205 - 5th Avenue SWDaryl H. Gilbert, P.Eng. DirectorCalgary, Alberta T2P 4B9Don Cowie DirectorINDEPENDENT ENGINEERSGLJ Petroleum Consultants Ltd.Brian Krausert Director4100, 400 - 3rd Avenue SW Calgary, Alberta T2P 4H2Gary W. BurnsDirectorDon D. Copeland, P.Eng. DirectorBrian BoulangerDirectorPatricia PhillipsDirectorFor further information, please visit our website at www.crocotta.ca.FOR FURTHER INFORMATION PLEASE CONTACT: Robert J. ZakreskyCrocotta Energy Inc.President & CEO(403) 538-3736ORNolan ChicoineCrocotta Energy Inc.VP Finance & CFO(403) 538-3738ORSuite 700, 639 - 5th Avenue SWCrocotta Energy Inc.Calgary, Alberta T2P 0M9(403) 538-3737(403) 538-3735 (FAX)www.crocotta.ca