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Press release from Marketwire

Crocotta Energy Inc.: Q3 2011 Financial and Operating Results

Wednesday, November 09, 2011

Crocotta Energy Inc.: Q3 2011 Financial and Operating Results06:00 EST Wednesday, November 09, 2011CALGARY, ALBERTA--(Marketwire - Nov. 9, 2011) - CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2011, including financial statements, notes to the financial statements, and Management's Discussion and Analysis. All dollar figures are Canadian dollars unless otherwise noted.HIGHLIGHTSIncreased average production 33% in Q3 2011 to 4,002 boe/d from 3,012 boe/d in Q2 2011 as a result of successful drilling activity at Edson, AB Increased funds from operations 38% in Q3 2011 to $9.6 million from $6.9 million in Q2 2011 Reduced operating costs 20% in Q3 2011 to $7.06/boe from $8.87/boe in Q2 2011 Drilled 3 (2.2 net) horizontal wells and 2 (2.0 net) vertical delineation wells at Edson, AB Sold non-core properties for proceeds of $5.8 million Subsequent to September 30, 2011, increased bank credit facility to $80.0 million from $55.0 million Increased 2011 exit guidance from 4,500 boe/d to a range of 5,500 to 6,100 boe/d FINANCIAL RESULTS (1)Three Months Ended September 30Nine Months Ended September 30($000s, except per share amounts)20112010% Change20112010% ChangeOil and natural gas sales14,8148,5747334,58327,25627Funds from operations (2)9,5513,47717518,4929,97385Per share - basic0.120.051400.240.1560Per share - diluted0.110.051200.230.1553Net earnings (loss)5,535(2,071)(367)1,460(5,983)(124)Per share - basic and diluted0.07(0.03)(333)0.02(0.09)(122)Capital expenditures26,9952,89983156,28414,123299Property acquisitions696-1001,696-100Property dispositions(5,758)(1,400)311(10,011)(22,098)(55)Net debt (3)30,97353,296(42)Common shares outstanding (000s)Weighted average - basic80,87465,1402477,81565,12419Weighted average - diluted83,36065,4882779,81365,25422End of period - basic80,87465,14224End of period - diluted92,33774,21924(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. (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 to cash flow from operating activities. (3) Net debt includes current liabilities (including the revolving credit facility and excluding the current portion of provisions) 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 September 30Nine Months Ended September 3020112010% Change20112010% ChangeDaily productionOil and NGLs (bbls/d)1,3368625599077927Natural gas (mcf/d)15,99610,5305212,67610,66319Oil equivalent (boe/d)4,0022,617533,1022,55621RevenueOil and NGLs ($/bbl)72.3857.572674.7563.2818Natural gas ($/mcf)4.024.14(3)4.164.74(12)Oil equivalent ($/boe)40.2435.611340.8339.055RoyaltiesOil and NGLs ($/bbl)10.9914.72(25)14.8417.88(17)Natural gas ($/mcf)(0.01)0.01(200)0.080.27(70)Oil equivalent ($/boe)3.644.87(25)5.076.57(23)Production expensesOil and NGLs ($/bbl)5.588.60(35)7.419.61(23)Natural gas ($/mcf)1.301.43(9)1.461.432Oil equivalent ($/boe)7.068.58(18)8.358.88(6)Transportation expensesOil and NGLs ($/bbl)0.740.87(15)0.821.26(35)Natural gas ($/mcf)0.170.17-0.170.17-Oil equivalent ($/boe)0.910.96(5)0.941.11(15)Operating netback (2)Oil and NGLs ($/bbl)55.0733.386551.6834.5350Natural gas ($/mcf)2.562.5312.452.87(15)Oil equivalent ($/boe)28.6321.203526.4722.4918Depletion and depreciation ($/boe)(15.20)(13.30)14(15.15)(14.57)4Asset impairment ($/boe)(0.27)(10.18)(97)(3.46)(9.65)(64)General and administrative expenses ($/boe)(2.42)(3.59)(33)(4.08)(4.06)0Share based compensation ($/boe)(2.69)(1.04)159(2.56)(1.04)146Finance expenses ($/boe)(0.58)(3.36)(83)(1.20)(3.89)(69)Finance income ($/boe)0.03(0.01)(400)0.160.1323Gain on sale of assets ($/boe)7.53-1001.541.3415Realized loss on risk managementcontracts ($/boe)-(0.27)(100)-(0.93)(100)Unrealized gain on risk managementcontracts ($/boe)-1.95(100)-1.60(100)Net earnings (loss) ($/boe)15.03(8.60)(275)1.72(8.58)(120)(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. (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. OPERATIONS UPDATEDuring the third quarter, Crocotta continued to drill its Edson property targeting liquids-rich gas and oil in the Bluesky formation. A total of 4 (3.2 net) Bluesky horizontal wells were drilled and completed resulting in 3 (2.2 net) horizontal Bluesky liquids-rich gas wells and 1 (1.0 net) horizontal Bluesky oil well. In addition to the horizontal wells, Crocotta drilled 2 (2.0 net) successful vertical delineation wells to extend the known boundaries of the Bluesky pool and also de-risk the corresponding Bluesky horizontal locations. The vertical wells also encountered pay in the liquids-rich Notikewin formation and the light oil Cardium formation that are present throughout the Edson property.While Crocotta continues to target the Bluesky formation, it continues to prove up the Notikewin and Cardium formations. To date, Crocotta has successfully recompleted 3 Notikewin vertical wells on its lands and has identified approximately 15-20 possible horizontal locations. In the Cardium, Crocotta has farmed out a total of 2 sections of land to a competitor that will drill and complete a Cardium horizontal well to earn 60% of Crocotta's interest in one section of land and has an option to drill and earn a second section. Crocotta will be able to gain valuable insight into the viability of Cardium horizontals in the area while retaining Cardium rights on over 70 sections of land in the area.Due to better than expected drilling results, Crocotta recently increased its exit production guidance to approximately 6,000 boepd from the previously estimated 4,500 boepd in addition to increasing the 2011 capital budget from $50 million to $80 million.In the fourth quarter, Crocotta will focus its capital expenditures primarily at Edson where it continues to drill horizontal Bluesky wells and is expanding its battery facility and gathering system to accommodate the volumes from the better than expected drilling results. The majority of the remaining capital will be spent drilling and completing a Montney horizontal well at Sunrise where recent competitor wells have tested at sustained rates of up to 15 mmcf/d. Crocotta previously completed the upper and lower Montney formation in a successful vertical well that tested at rates up to 700 mcf/d with some condensate. The horizontal well is currently drilled and awaiting completion scheduled for early December. If successful, Crocotta would have over 100 net horizontal locations on its land in the Sunrise-Dawson area.Current estimated production is over 5,500 boepd with at least 500 boepd to come on when the facility expansion and optimization is completed in early December.MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")November 8, 2011The MD&A should be read in conjunction with the unaudited financial statements and related notes for the three and nine months ended September 30, 2011 and 2010 and the audited financial statements and related notes for the year ended December 31, 2010.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".Additional information related to the Company, including the Company's Annual Information Form (AIF), may be found on the SEDAR website at www.sedar.com.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 to 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".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.SUMMARY OF FINANCIAL RESULTSThree Months Ended September 30Nine Months Ended September 30($000s, except per share amounts)20112010% Change20112010% ChangeOil and natural gas sales14,8148,5747334,58327,25627Funds from operations9,5513,47717518,4929,97385Per share - basic0.120.051400.240.1560Per share - diluted0.110.051200.230.1553Net earnings (loss)5,535(2,071)(367)1,460(5,983)(124)Per share - basic and diluted0.07(0.03)(333)0.02(0.09)(122)Total assets223,576199,97812Total long-term liabilities16,07614,28413Net debt30,97353,296(42)PRODUCTIONThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeAverage Daily ProductionOil and NGLs (bbls/d)1,3368625599077927Natural gas (mcf/d)15,99610,5305212,67610,66319Combined (boe/d)4,0022,617533,1022,55621Daily production for the three months ended September 30, 2011 increased 53% to 4,002 boe/d compared to 2,617 boe/d for the comparative period in 2010. Year-to-date, daily production increased 21% to 3,102 boe/d in 2011 from 2,556 boe/d for the nine months ended September 30, 2010. Compared to the previous quarter, daily production increased 33% in Q3 2011 from 3,012 boe/d in Q2 2011. The significant increase in production during the third quarter was due to successful drilling activity at Edson, AB which saw two additional 100% working interest wells come on production during the quarter.Crocotta's production profile for the first nine months of 2011 was comprised of 68% natural gas and 32% oil and NGLs, consistent with the production profile for the year ended December 31, 2010, which was comprised of 70% natural gas and 30% oil and NGLs.REVENUEThree Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeOil and NGLs8,8964,5659520,19613,46150Natural gas5,9184,0094814,38713,7954Total14,8148,5747334,58327,25627Average Sales PriceOil and NGLs ($/bbl)72.3857.572674.7563.2818Natural gas ($/mcf)4.024.14(3)4.164.74(12)Combined ($/boe)40.2435.611340.8339.055Revenue totaled $14.8 million for the third quarter of 2011, up 73% from $8.6 million in the comparative period. Year-to-date, revenue increased 27% to $34.6 million from $27.3 million in 2010. The increase in revenue was mainly due to significant increases in production and oil and NGLs commodity prices.The following table outlines the Company's realized wellhead prices and industry benchmarks:Commodity PricingThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeOil and NGLsCorporate price ($CDN/bbl)72.3857.572674.7563.2818Edmonton par ($CDN/bbl)92.4574.442494.3276.7323West texas intermediate ($US/bbl)89.4076.061895.3177.5423Natural gasCorporate price ($CDN/mcf)4.024.14(3)4.164.74(12)AECO price ($CDN/mcf)3.633.74(3)3.774.31(13)Exchange rateCDN/US dollar average exchange rate1.02180.962661.02330.96576Differences 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 78.3% and 79.3% of Edmonton Par price for the three and nine months ended September 30, 2011, consistent with 77.3% and 82.5% for the comparative period in 2010. Corporate average natural gas prices were 110.7% and 110.3% of AECO prices for the three and nine months ended September 30, 2011, consistent with the comparative period results of 110.7% and 110.0%.ROYALTIESThree Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeOil and NGLs1,3501,167164,0103,8025Natural gas(11)6(283)285782(64)Total1,3391,173144,2954,584(6)Average Royalty Rate (% of sales)Oil and NGLs15.225.6(41)19.928.2(29)Natural gas(0.2)0.1(300)2.05.7(65)Combined9.013.7(34)12.416.8(26)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 September 30, 2011, oil, NGLs, and natural gas royalties increased 14% to $1.3 million from $1.2 million in the comparative period. This increase was due to an increase in oil and NGLs royalties which stemmed from a significant increase in oil and NGLs revenue. For the nine months ended September 30, 2011, oil, NGLs, and natural gas royalties decreased to $4.3 million from $4.6 million in 2010. The decrease was the result of a decline in natural gas royalties due mainly to a decrease in natural gas commodity prices combined with royalty incentives received on new natural gas wells brought on production during the year.The overall effective royalty rate was 9.0% for the three months ended September 30, 2011 compared to 13.7% for the three months ended September 30, 2010. Year-to-date, the overall effective royalty rate was 12.4% in 2011 compared to 16.8% in 2010. The effective oil and NGLs royalty rate decreased as a result of royalty incentive rates received on the successful Edson wells brought on production during the quarter combined with the disposition of certain oil weighted assets during the first quarter of 2010 that had higher associated royalty rates. The effective natural gas royalty rate decreased from the comparative period due to royalty incentive rates received on the successful Edson wells brought on production during the quarter combined with a decline in natural gas commodity prices. The effective natural gas royalty rate was negative during the third quarter of 2011 as the monthly capital cost allowance deductions exceeded the natural gas royalties.PRODUCTION EXPENSESThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeOil and NGLs ($/bbl)5.588.60(35)7.419.61(23)Natural gas ($/mcf)1.301.43(9)1.461.432Combined ($/boe)7.068.58(18)8.358.88(6)Per unit production expenses for the three months ended September 30, 2011 were $7.06/boe, down from $8.58/boe for the comparative period ended September 30, 2010. For the nine months ended September 30, 2011, per unit production expenses decreased 6% to $8.35/boe from $8.88/boe for the nine months ended September 30, 2010. Compared to the previous quarter, per unit production expenses decreased 20% in Q3 2011 from $8.87/boe in Q2 2011. The decrease in per unit production expenses from Q2 2011 to Q3 2011 was due to a significant increase in production stemming from two successful Edson wells being brought onstream during the third quarter. The Company continues to focus on opportunities that will improve operational efficiencies and reduce per boe production expenses to enhance operating netbacks.TRANSPORTATION EXPENSESThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeOil and NGLs ($/bbl)0.740.87(15)0.821.26(35)Natural gas ($/mcf)0.170.17-0.170.17-Combined ($/boe)0.910.96(5)0.941.11(15)Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended September 30, 2011 compared to the quarter ended September 30, 2010, transportation expenses decreased 5% to $0.91/boe from $0.96/boe. Year-to-date, transportation expenses decreased to $0.94/boe in 2011 from $1.11/boe in 2010. The decrease in transportation expenses was due to a significant decrease in oil and NGLs transportation expenses. During the third quarter of 2010, the Company changed its sales point and marketer for a significant portion of NGLs volumes produced. This, combined with the sale of certain oil weighted assets during 2010, resulted in the decrease in period-over-period transportation expenses.OPERATING NETBACKThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeOil and NGLs ($/bbl)Revenue72.3857.572674.7563.2818Royalties10.9914.72(25)14.8417.88(17)Production expenses5.588.60(35)7.419.61(23)Transportation expenses0.740.87(15)0.821.26(35)Operating netback55.0733.386551.6834.5350Natural gas ($/mcf)Revenue4.024.14(3)4.164.74(12)Royalties(0.01)0.01(200)0.080.27(70)Production expenses1.301.43(9)1.461.432Transportation expenses0.170.17-0.170.17-Operating netback2.562.5312.452.87(15)Combined ($/boe)Revenue40.2435.611340.8339.055Royalties3.644.87(25)5.076.57(23)Production expenses7.068.58(18)8.358.88(6)Transportation expenses0.910.96(5)0.941.11(15)Operating netback28.6321.203526.4722.4918During the third quarter of 2011, Crocotta generated an operating netback of $28.63/boe, up 35% from $21.20/boe for the third quarter of 2010. During the first nine months of 2011, Crocotta generated an operating netback of $26.47/boe compared to $22.49/boe in the comparative period. These increases were mainly due to an increase in oil and NGLs commodity prices and a decrease in royalties and operating costs in 2011 compared to 2010. Operating netbacks in Q3 2011 were consistent with operating netbacks of $28.92/boe in Q2 2011.The following is a reconciliation of operating netback per boe to net earnings (loss) per boe for the periods noted:Three Months Ended September 30Nine Months Ended September 30($/boe)20112010% Change20112010% ChangeOperating netback28.6321.203526.4722.4918Depletion and depreciation(15.20)(13.30)14(15.15)(14.57)4Asset impairment(0.27)(10.18)(97)(3.46)(9.65)(64)General and administrative expenses(2.42)(3.59)(33)(4.08)(4.06)0Share based compensation(2.69)(1.04)159(2.56)(1.04)146Finance expenses(0.58)(3.36)(83)(1.20)(3.89)(69)Finance income0.03(0.01)(400)0.160.1323Gain on sale of assets7.53-1001.541.3415Realized loss on risk management contracts-(0.27)(100)-(0.93)(100)Unrealized gain on risk management contracts-1.95(100)-1.60(100)Net earnings (loss)15.03(8.60)(275)1.72(8.58)(120)DEPLETION AND DEPRECIATIONThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeDepletion and depreciation ($000s)5,5963,2027512,83310,17026Depletion and depreciation ($/boe)15.2013.301415.1514.574Under 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 September 30, 2011 was $15.20/boe compared to $13.30/boe in the comparative period. Year-to-date, depletion and depreciation was $15.15/boe compared to $14.57/boe for the nine months ended September 30, 2010. The increase in depletion and depreciation was due to a significant increase in production, mainly during the second and third quarters of 2011.ASSET IMPAIRMENTThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeAsset impairment ($000s)982,451(96)2,9326,732(56)Asset impairment ($/boe)0.2710.18(97)3.469.65(64)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. For the nine months ended September 30, 2011, the Company recognized impairments of $2.9 million relating to the expiry of undeveloped land rights and the determination of certain exploration and evaluation assets to be uneconomical. For the nine months ended September 30, 2010, as a result of continued decreases in natural gas prices, the Company recognized impairments of $5.2 million relating to various development and production assets. In addition, the Company recognized impairments of $1.5 million relating to the expiry of undeveloped land.GENERAL AND ADMINISTRATIVEThree Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeG&A expenses (gross)1,1921,09794,5563,60926G&A capitalized(80)(33)142(258)(132)95G&A recoveries(222)(199)12(840)(645)30G&A expenses (net)89086533,4582,83222G&A expenses ($/boe)2.423.59(33)4.084.06-General and administrative expenses ("G&A") decreased to $2.42/boe for the third quarter of 2011 compared to $3.59/boe for the third quarter of 2010. The decrease was mainly due to a significant increase in production. Year-to-date, G&A expenses of $4.08/boe in 2011 were consistent with G&A expenses of $4.06/boe in 2010.SHARE BASED COMPENSATIONThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeShare based compensation ($000s)9902502962,164724199Share based compensation ($/boe)2.691.041592.561.04146The Company grants stock options to officers, directors, employees and consultants and calculates the related share based compensation using the Black-Scholes 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 $2.69/boe and $2.56/boe, respectively, for the three and nine months ended September 30, 2011 from $1.04/boe in the comparative periods. During the first nine months of 2011, the Company granted 4.2 million options (2010 – 0.2 million), resulting in the increase in share based compensation expense in 2011 compared to 2010.FINANCE EXPENSESThree Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeInterest expense109694(84)6052,333(74)Accretion of decommissioning obligations105114(8)332383(13)Unrealized loss on investments--10079-100Finance expenses214808(74)1,0162,716(63)Finance expenses ($/boe)0.583.36(83)1.203.89(69)Interest expense amounts relate 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 the first nine months of 2011 compared to the first nine months of 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 (September 30, 2011 - $18.6 million; September 30, 2010 - $51.9 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 the first quarter of 2011 stemming from the disposition of certain oil and natural gas assets in the fourth quarter of 2010 and the issuance of approximately 15.6 million common shares for gross proceeds of approximately $36.0 million in the first quarter of 2011, offset by capital expenditures in the fourth quarter of 2010 and the first half of 2011.Investments include 875,000 warrants of Hyperion Exploration Corp. ("Hyperion") at an exercise price of $2.00 per warrant. Each warrant is convertible into one common share of Hyperion and expires 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 is measured at fair value each reporting period using the Black-Scholes option pricing model. An unrealized loss was recognized during the year on the revaluation of warrants.FINANCE INCOMEThree Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeFinance income11(2)(650)1329047Finance income ($/boe)0.03(0.01)(400)0.160.1323GAIN ON SALE OF ASSETSThree Months Ended September 30Nine Months Ended September 3020112010% Change20112010% ChangeGain on sale of assets ($000s)2,772-1001,30793640Gain on sale of assets ($/boe)7.53-1001.541.3415During the first nine months of 2011, the Company recognized a net gain on sale of assets of $1.3 million. A gain on sale of assets of $2.8 million was recognized during the third quarter relating to dispositions of non-core oil and natural gas assets, which was offset by a loss on sale of assets during the first half of 2011 on the disposition of certain non-producing assets. During the first nine months of 2010, the Company recognized a net gain on sale of assets of $0.9 million. A gain on sale of assets of $1.0 million was recognized relating mainly to the sale of undeveloped land, 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.DEFERRED INCOME TAX EXPENSEDeferred income tax expense on the earnings before taxes has been offset by the realization of future benefits of tax deductions based on current estimates of future taxable income from proved reserves. The net result is no change in the deferred income tax asset.FUNDS FROM OPERATIONSFunds from operations for the three and nine months ended September 30, 2011 were $9.6 million ($0.11 per diluted share) and $18.5 million ($0.23 per diluted share), respectively, compared to $3.5 million ($0.05 per diluted share) and $10.0 million ($0.15 per diluted share) for the three and nine months ended September 30, 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 funds from operations to cash flow from operating activities for the periods noted:Three Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeFunds from operations (non-GAAP)9,5513,47717518,4929,97385Decommissioning expenditures(176)(308)(43)(176)(664)(73)Change in non-cash working capital(340)263(229)(1,851)(499)271Cash flow from operating activities (GAAP)9,0353,43216316,4658,81087NET EARNINGS (LOSS)The Company had net earnings of $5.5 million ($0.07 per diluted share) for the three months ended September 30, 2011 compared to a net loss of $2.1 million ($0.03 per diluted share) for the three months ended September 30, 2010. Year-to-date, the Company had net earnings of $1.5 million ($0.02 per diluted share) in 2011, compared to a net loss of $6.0 million ($0.09 per diluted share) in 2010. The increase in net earnings was due to an increase in oil and NGLs commodity prices combined with a significant increase in production as well as a significant gain on sale of assets recognized during the third quarter of 2011.CAPITAL EXPENDITURESThree Months Ended September 30Nine Months Ended September 30($000s)20112010% Change20112010% ChangeLand344472(27)1,2611,569(20)Drilling, completions, and workovers23,3822,29591945,8368,334450Equipment2,948319,4108,2333,699123Geological and geophysical27610117388552170Other45-10069-100Exploration and development26,9952,89983156,28414,123299Property acquisitions696-1001,696-100Property dispositions(5,758)(1,400)311(10,011)(22,098)(55)Net property dispositions(5,062)(1,400)262(8,315)(22,098)(62)Total capital expenditures (dispositions)21,9331,4991,36347,969(7,975)(701)For the three months ended September 30, 2011, the Company had net capital expenditures of $21.9 million compared to net capital expenditures of $1.5 million for the three months ended September 30, 2010. For the nine months ended September 30, 2011, the Company had net capital expenditures of $48.0 million compared to net capital dispositions of $8.0 million for the comparative period in 2010. The increase in exploration and development expenditures in the first nine months of 2011 was due mainly to a significant increase in capital activity in the Company's core Edson, AB area. During the first nine months of 2011, Crocotta drilled 11 (8.4 net) wells, which resulted in 1 (1.0 net) oil well, 9 (7.3 net) liquids-rich natural gas wells, and 1 (0.1 net) uneconomic well.LIQUIDITY AND CAPITAL RESOURCESThe Company had net debt of $31.0 million at September 30, 2011 compared to net debt of $35.2 million at December 31, 2010. The decrease of $4.2 million was mainly due to gross proceeds of $36.0 million on the issuance of 15.6 million common shares, $10.0 million in net property dispositions, and funds from operations of $18.5 million, offset by $58.0 million used for the purchase and development of oil and natural gas properties and equipment, $0.2 million for decommissioning expenditures, and share issue costs of $2.1 million.At September 30, 2011, the Company had total credit facilities of $55.0 million, consisting of a $55.0 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 $235 million fixed and floating charge debenture on the assets of the Company. At September 30, 2011, $18.6 million (December 31, 2010 – $35.4 million) had been drawn on the revolving credit facility. Subsequent to September 30, 2011, the Company signed an agreement to increase the revolving credit facility to $80.0 million. The next review of the revolving credit facility by the bank is scheduled on or before May 31, 2012.During the first quarter of 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. The proceeds are being used to fund Crocotta's Edson Bluesky and Dawson Montney developments, other capital projects, and for general corporate purposes.During the first nine months of 2011, the Company sold certain non-core oil and natural gas properties for approximately $10.0 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 $36.0 million from the issuance of common shares during the first quarter and subsequent to September 30, 2011, 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. The Company is also pursuing further asset dispositions to support future capital programs. 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 September 30, 2011:($000s)TotalLess than One YearOne to Three YearsAfter Three YearsAccounts payable and accrued liabilities25,95525,955--Revolving credit facility18,58818,588--Office leases1,58359095637Field equipment leases1,655863792-Firm transportation agreements91246437969Drilling rig4,3664,366--Capital processing agreements368--368Total contractual obligations53,42750,8262,127474OUTSTANDING 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)September 30, 2011November 8, 2011Voting common shares80,87480,874Stock options7,9427,942Warrants3,5213,521Total92,33792,337SUMMARY OF QUARTERLY RESULTS (1)Q3 2011Q2 2011Q1 2011Q4 2010Q3 2010Q2 2010Q1 2010Q4 2009Average Daily ProductionOil and NGLs (bbls/d)1,3361,0395866478626658101,140Natural gas (mcf/d)15,99611,84310,1249,95810,53010,69810,76312,157Combined (boe/d)4,0023,0122,2742,3072,6172,4482,6043,166($000s, except per share amounts)Oil and natural gas sales14,81412,2897,4807,2748,5747,72010,96212,130Funds from operations9,5516,9272,0144,2003,4772,4934,0043,972Per share - basic0.120.090.030.060.050.040.060.06Per share - diluted0.110.080.030.060.050.040.060.06Net earnings (loss) before extraordinary items5,535374(4,449)656(2,071)(1,347)(2,566)(4,155)Per share - basic and diluted0.07-(0.06)0.01(0.03)(0.02)(0.04)(0.06)Net earnings (loss)5,535374(4,449)656(2,071)(1,347)(2,566)3,276Per share - basic and diluted0.07-(0.06)0.01(0.03)(0.02)(0.04)0.05(1) 2010 quarterly results have been adjusted to conform to IFRS. 2009 quarterly results have not been adjusted and reflect the results in accordance with previous GAAP.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 and net earnings in Q3 2011 compared to prior quarters.OPERATIONS UPDATEDuring the third quarter, Crocotta continued to drill its Edson property targeting liquids-rich gas and oil in the Bluesky formation. A total of 4 (3.2 net) Bluesky horizontal wells were drilled and completed resulting in 3 (2.2 net) horizontal Bluesky liquids-rich gas wells and 1 (1.0 net) horizontal Bluesky oil well. In addition to the horizontal wells, Crocotta drilled 2 (2.0 net) successful vertical delineation wells to extend the known boundaries of the Bluesky pool and also de-risk the corresponding Bluesky horizontal locations. The vertical wells also encountered pay in the liquids-rich Notikewin formation and the light oil Cardium formation that are present throughout the Edson property.While Crocotta continues to target the Bluesky formation, it continues to prove up the Notikewin and Cardium formations. To date, Crocotta has successfully recompleted 3 Notikewin vertical wells on its lands and has identified approximately 15-20 possible horizontal locations. In the Cardium, Crocotta has farmed out a total of 2 sections of land to a competitor that will drill and complete a Cardium horizontal well to earn 60% of Crocotta's interest in one section of land and has an option to drill and earn a second section. Crocotta will be able to gain valuable insight into the viability of Cardium horizontals in the area while retaining Cardium rights on over 70 sections of land in the area.Due to better than expected drilling results, Crocotta recently increased its exit production guidance to approximately 6,000 boepd from the previously estimated 4,500 boepd in addition to increasing the 2011 capital budget from $50 million to $80 million.In the fourth quarter, Crocotta will focus its capital expenditures primarily at Edson where it continues to drill horizontal Bluesky wells and is expanding its battery facility and gathering system to accommodate the volumes from the better than expected drilling results. The majority of the remaining capital will be spent drilling and completing a Montney horizontal well at Sunrise where recent competitor wells have tested at sustained rates of up to 15 mmcf/d. Crocotta previously completed the upper and lower Montney formation in a successful vertical well that tested at rates up to 700 mcf/d with some condensate. The horizontal well is currently drilled and awaiting completion scheduled for early December. If successful, Crocotta would have over 100 net horizontal locations on its land in the Sunrise-Dawson area.Current estimated production is over 5,500 boepd with at least 500 boepd to come on when the facility expansion and optimization is completed in early December.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. The interim financial statements for the three and nine months ended September 30, 2011 and related notes have been prepared under IFRS in accordance with International Accounting Standard ("IAS") 34, Interim Financial Reporting. Previously, the Company prepared its interim and annual financial statements in accordance with Canadian generally accepted accounting principles ("previous GAAP"). As such, 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.The impact of the transition to IFRS is disclosed in the interim financial statements of the Company for the three months ended March 31, 2011. Note 14 to the interim financial statements for the three and nine months ended September 30, 2011 provides reconciliations between the Company's 2010 previous GAAP results and its 2010 IFRS results.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 testingThe impairment testing of property, plant, and equipment is based on estimates of proved plus probable reserves, production rates, oil and natural gas future prices, future costs, and other relevant assumptions. By their nature, these measurements are subject to measurement uncertainty and may impact the financial statements of future periods.Decommissioning obligationsThe Company estimates obligations under environmental regulations in respect of decommissioning and site restoration of its oil and natural gas assets. These obligations are determined based on the present value of estimated expenditures required to abandon wells, dismantle production facilities, and restore producing areas in accordance with relevant legislation, discounted from the date when the costs are expected to be incurred. Most of the decommissioning expenditures of the Company are estimated to take place far into the future. Changes in the estimated timing and costs of performing decommissioning work, which are subject to uncertainty and interpretation, would have a significant effect on the carrying amount of the decommissioning obligation.Deferred income taxesTax 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 October 2010, the International Accounting Standards Board (IASB) published IFRS 9, Financial Instruments, as part of its project to replace IAS 39, Financial Instruments: Recognition and Measurement. This first phase of the project outlines a single approach in determining if a financial asset or liability is measured at amortized cost or fair value and a single impairment method, replacing the multiple classifications and methods in IAS 39. The effective date for IFRS 9 is January 1, 2013. The Company is currently evaluating the impact of adopting IFRS 9.In May 2011, the IASB issued IFRS 10, Consolidated Financial Statements. IFRS 10 establishes principles for the presentation and preparation of consolidated financial statements when an entity controls one or more other entities. IFRS 10 builds on existing principles by identifying the concept of control as the determining factor in whether an entity should be included within the consolidated financial statements of the parent company. The standard provides additional guidance in the determination of control where this is difficult to assess. The effective date for IFRS 10 is January 1, 2013. This standard will not have an impact on the Company's financial statements.In May 2011, the IASB issued IFRS 11, Joint Arrangements. IFRS 11 provides for a more realistic reflection of joint arrangements by focusing on the rights and obligations of the arrangement rather that its legal form, as is currently the case. The standard addresses inconsistencies in the reporting of joint arrangements by requiring a single method (equity method) to account for interests in jointly controlled entities. The effective date for IFRS 11 is January 1, 2013. This standard will not have an impact on the Company's financial statements.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, 2010. 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 includes 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, 2010. 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, 2010. 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.Crocotta Energy Inc.Condensed Statements of Financial Position(unaudited)September 30December 31($000s)Note20112010AssetsCurrent assetsAccounts receivable12,80910,159Prepaid expenses and deposits761878Investments-79Property, plant, and equipment, held for sale(6)2,6842,02016,25413,136Property, plant, and equipment(5)172,951134,915Exploration and evaluation assets(4)28,29931,405Deferred income taxes6,0726,072207,322172,392223,576185,528LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities25,95510,930Revolving credit facility(7)18,58835,386Decommissioning obligations, held for sale(8)1,0731,06445,61647,380Decommissioning obligations(8)16,07614,03561,69261,415Shareholders' EquityShareholders' capital(9)202,201168,164Contributed surplus7,7895,515Deficit(48,106)(49,566)161,884124,113Subsequent events(6, 7)223,576185,528The accompanying notes are an integral part of these condensed interim financial statements.Crocotta Energy Inc.Condensed Statements of Operations and Comprehensive Income (Loss)(unaudited)Three Months Ended September 30Nine Months Ended September 30($000s, except per share amounts)Note2011201020112010RevenueOil and natual gas sales14,8148,57434,58327,256Royalties(1,339)(1,173)(4,295)(4,584)13,4757,40130,28822,672Realized loss on risk management contracts-(66)-(649)Unrealized gain on risk management contracts-469-1,11713,4757,80430,28823,140ExpensesProduction2,5992,0677,0686,200Transportation336230796775Depletion and depreciation(5)5,5963,20212,83310,170Asset impairment(4)982,4512,9326,732General and administrative8908653,4582,832Share based compensation(10)9902502,16472410,5099,06529,25127,433Operating income (loss)2,966(1,261)1,037(4,293)Other Expenses (Income)Finance expense(12)2148081,0162,716Finance income(11)2(132)(90)Gain on sale of assets(2,772)-(1,307)(936)(2,569)810(423)1,690Earnings (loss) before taxes5,535(2,071)1,460(5,983)TaxesDeferred income tax expense----Net earnings (loss) and comprehensive earnings (loss)5,535(2,071)1,460(5,983)Net earnings (loss) per shareBasic and diluted0.07(0.03)0.02(0.09)The accompanying notes are an integral part of these condensed interim financial statements.Crocotta Energy Inc.Condensed Statements of Shareholders' Equity(unaudited) Nine Months Ended September 30($000s)20112010Shareholders' CapitalBalance, beginning of period168,164168,038Issue of shares (net of share issue costs)33,844-Issued on exercise of stock options11475Share based compensation - settlements7951Balance, end of period202,201168,164Contributed SurplusBalance, beginning of period5,5154,525Share based compensation - expensed2,164724Share based compensation - capitalized18966Share based compensation - settlements(79)(51)Balance, end of period7,7895,264DeficitBalance, beginning of period(49,566)(44,238)Net earnings (loss)1,460(5,983)Balance, end of period(48,106)(50,221)Total Shareholders' Equity161,884123,207The accompanying notes are an integral part of these condensed interim financial statements.Crocotta Energy Inc.Condensed Statements of Cash Flows(unaudited)Three Months Ended September 30Nine Months Ended September 30($000s)Note2011201020112010Operating ActivitiesNet earnings (loss)5,535(2,071)1,460(5,983)Depletion and depreciation5,5963,20212,83310,170Asset impairment982,4512,9326,732Share based compensation9902502,164724Finance expense2148081,0162,716Interest paid(109)(694)(605)(2,333)Gain on sale of assets(2,772)-(1,307)(936)Unrealized gain on risk management contracts-(469)-(1,117)9,5523,47718,4939,973Decommissioning expenditures(176)(308)(176)(664)Change in non-cash working capital(13)(340)263(1,851)(499)9,0363,43216,4668,810Financing ActivitiesIssuance of shares-1036,07475Share issue costs--(2,116)-Revolving credit facility4,871(1,431)(16,798)(416)Secured bridge facility---(20,243)4,871(1,421)17,160(20,584)Investing ActivitiesCapital expenditures - property, plant, and equipment(5)(22,174)(616)(50,512)(7,819)Capital expenditures - exploration and evaluation assets(4)(5,517)(2,283)(7,468)(6,304)Asset dispositions5,7581,40010,01122,098Change in non-cash working capital(13)8,026(876)14,3431,945(13,907)(2,375)(33,626)9,920Change in cash and cash equivalents-(364)-(1,854)Cash and cash equivalents, beginning of period-364-1,854Cash and cash equivalents, end of period----The accompanying notes are an integral part of these condensed interim financial statements.Crocotta Energy Inc.Notes to the Condensed Interim Financial Statements Three and Nine Months Ended September 30, 2011 (unaudited)(Tabular amounts in 000s, unless otherwise stated)1. REPORTING ENTITY Crocotta 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 financial statements reflect only the Company's proportionate interest in such activities. 2. BASIS OF PRESENTATION(a) Statement of compliance These condensed interim financial statements have been prepared in accordance with International Accounting Standard ("IAS") 34, Interim Financial Reporting and accordingly do not include all of the information required in the preparation of annual financial statements. These are Crocotta's third condensed interim financial statements prepared under International Financial Reporting Standards ("IFRS") for part of the period covered by the first IFRS annual financial statements. Accordingly, the guidelines under IFRS 1, First-time Adoption of International Financial Reporting Standards have been applied. Prior to 2011, Crocotta prepared its interim and annual financial statements in accordance with Canadian Generally Accepted Accounting Principles ("previous GAAP"). The impact of the new standards, including reconciliations presenting the change from previous GAAP to IFRS as at and for the three and nine months ended September 30, 2010, is presented in note 14. The condensed interim financial statements should be read in conjunction with the interim financial statements and notes thereto for the three months ended March 31, 2011 and the audited financial statements and notes thereto for the year ended December 31, 2010. The condensed interim financial statements were authorized for issue by the Board of Directors on November 8, 2011. (b) Basis of measurement The 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 currency These financial statements are presented in Canadian dollars, which is the Company's functional currency. (d) Use of estimates and judgments The preparation of financial statements requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities at the date of the interim financial statements and the reported amounts of revenue and expenses during the period. By their nature, estimates are subject to measurement uncertainty and accordingly, actual results may differ from the estimated amounts. Estimates and the underlying assumptions are reviewed by management on an ongoing basis and revisions to such estimates are recognized in the period in which the estimates are revised and in any future periods affected. Significant estimates and judgments made by management in the preparation of these interim financial statements are as follows: Amounts recorded for depletion and depreciation and amounts used for impairment calculations are based on estimates of petroleum and natural gas reserves. By their nature, the estimates of reserves, including the estimates of future prices, costs, discount rates, and the related future cash flows, are subject to measurement uncertainty. 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. Other provisions are recognized in the period when it becomes probable that there will be a future cash outflow. Compensation costs recognized for share based compensation plans are calculated using pricing models such as the Black- Scholes model, which is based on significant assumptions such as volatility, expected term, and forfeiture rate. 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 each reporting period to determine the likelihood that they will be realized from future taxable earnings. 3. SIGNIFICANT ACCOUNTING POLICIESThe interim financial statements have been prepared following the same accounting policies as the unaudited interim financial statements for the three months ended March 31, 2011. The accounting policies have been applied consistently by the Company to all periods presented in these interim financial statements. In addition to the quantitative adjustments from previous GAAP to IFRS, certain comparative amounts have been reclassified to conform to the current period's presentation.4.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, 201031,405Additions7,893Transfer to property, plant, and equipment(3,318)Transfer to property, plant, and equipment, held for sale(801)Dispositions(3,948)Impairment(2,932)Balance, September 30, 201128,299Exploration 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 period. ImpairmentsExploration 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 nine months ended September 30, 2011, impairments of $2.9 million were recognized relating to the expiry of undeveloped land rights (CGUs – Ferrier AB and Miscellaneous AB) and the determination of certain exploration and evaluation activities to be uneconomical (CGUs – Miscellaneous AB and Saskatchewan). For the year ended December 31, 2010, the Company recognized impairments of $2.4 million due to the expiry of undeveloped land rights (CGUs – Ferrier AB and Miscellaneous AB).5. 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, 2010164,459Additions50,512Transfer from exploration and evaluation assets3,318Transfer to property, plant, and equipment, held for sale(1,076)Dispositions(6,331)Change in decommissioning obligation estimates2,519Capitalized share based compensation189Balance, September 30, 2011213,590Accumulated 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 depreciation12,833Transfer to property, plant, and equipment, held for sale(441)Dispositions(1,297)Balance, September 30, 201140,639Net Book ValueTotalDecember 31, 2010134,915September 30, 2011172,951During the three and nine months ended September 30, 2011, approximately $0.1 million (2010 – $0.1 million) and $0.4 million (2010 - $0.3 million), respectively, of directly attributable general and administrative costs were capitalized as expenditures on property, plant, and equipment.6. PROPERTY, PLANT, AND EQUIPMENT, HELD FOR SALEProperty, Plant, and EquipmentExploration and Evaluation 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-801801Transfer from property, plant, and equipment635-635Dispositions(130)(642)(772)Balance, September 30, 20112,3623222,684At September 30, 2011, the Company had property, plant, and equipment, held for sale of $2.7 million, which consisted of oil and natural gas assets located in Saskatchewan and Ferrier AB. The Saskatchewan 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. The assets continue to be marketed for sale and therefore remained in held for sale at September 30, 2011. The Ferrier AB assets were sold subsequent to September 30, 2011 for proceeds of $0.5 million.7. CREDIT FACILITIES At September 30, 2011, the Company had total credit facilities of $55.0 million, consisting of a $55.0 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 $235 million fixed and floating charge debenture on the assets of the Company. At September 30, 2011, $18.6 million (December 31, 2010 – $35.4 million) had been drawn on the revolving credit facility. Subsequent to September 30, 2011, the Company signed an agreement to increase the revolving credit facility to $80.0 million. The next review of the revolving credit facility by the bank is scheduled on or before May 31, 2012. 8. PROVISIONS – DECOMMISSIONING OBLIGATIONS The 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 $26.3 million which is estimated to be incurred between 2011 and 2041. At September 30, 2011, a risk-free rate of 2.7% (December 31, 2010 – 3.5%) was used to calculate the net present value of the decommissioning obligations. Nine Months EndedYear EndedSeptember 30, 2011December 31, 2010Balance, beginning of period15,09915,113Provisions incurred808302Provisions disposed(625)(1,811)Provisions settled(176)(868)Revisions1,7111,862Accretion332501Balance, end of period17,14915,099Provisions, held for sale1,0731,064Provisions16,07614,03517,14915,0999. SHARE CAPITAL The 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 issuance15,63535,961Share issue costs(2,117)Balance, September 30, 201180,874202,201On 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. Proceeds from the share issuance are being used to fund the Company's Edson Bluesky and Dawson Montney developments, other capital projects, and general corporate purposes.10. SHARE BASED COMPENSATION PLANS Stock options The Company has authorized and reserved for issuance 8.1 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 September 30, 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--Cancelled(35)1.53Balance, September 30, 20117,9421.97Exercisable at September 30, 20111,7881.18The following table summarizes the stock options outstanding and exercisable at September 30, 2011:Options OutstandingOptions ExercisableWeighted AverageWeighted AverageWeighted AverageExercise PriceNumberRemaining LifeExercise PriceNumberExercise Price$1.10 to $1.993,6453.11.241,7211.15$2.00 to $3.004,2974.52.59672.107,9423.91.971,7881.18WarrantsThe 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 of WarrantsWeighted Average Exercise PriceBalance, January 1, 20103,6043.67Forfeited(83)4.75Balance, December 31, 2010 and September 30, 20113,5213.64Exercisable at September 30, 20113,5213.64The following table summarizes the warrants outstanding and exercisable at September 30, 2011:Warrants Outstanding and ExercisableWeighted AverageWeighted AverageExercise PriceNumberRemaining LifeExercise Price$1.401,2001.11.40$3.75 to $4.057401.33.76$4.50 to $5.258071.34.55$6.00 to $6.757741.36.053,5211.23.64Share based compensationThe Company accounts for its share based compensation plans using the fair value method. Under this method, compensation cost is charged to earnings over the vesting period for stock options and warrants granted to officers, directors, employees, and consultants with a corresponding increase to contributed surplus.The fair value of the stock options granted during the three and nine months ended September 30, 2011 were estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions:Three Months EndedNine Months EndedSeptember 30, 2011September 30, 2011Risk-free interest rate (%)1.92.3Expected life (years)4.04.0Expected volatility (%)80.682.8Expected dividend yield (%)--Forfeiture rate (%)8.89.4Weighted average fair value of options granted ($ per option)1.781.5911. PER SHARE AMOUNTSThe following table reconciles the weighted average number of shares used in the basic and diluted net earnings (loss) per share calculations:Three Months EndedNine Months EndedSeptember 30, 2011September 30, 2011Weighted average number of shares - basic80,87477,815Dilutive effect of share based compensation plans2,4861,998Weighted average number of shares - diluted83,36079,81312. FINANCE EXPENSESFinance expenses for the three and nine months ended September 30, 2011 include the following:Three Months EndedNine Months EndedSeptember 30, 2011September 30, 2011Interest expense (note 7)109605Accretion of decommissioning obligations (note 8)105332Unrealized loss on investments-79Finance expenses2141,01613. SUPPLEMENTAL CASH FLOW INFORMATIONThree Months EndedNine Months EndedSeptember 30, 2011September 30, 2011Accounts receivable(4,866)(2,650)Prepaid expenses and deposits93117Accounts payable and accrued liabilities12,45915,025Change in non-cash working capital7,68612,492Relating to:Investing8,02614,343Operating(340)(1,851)Change in non-cash working capital7,68612,49214. 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 three and nine months ended September 30, 2011, as well as to the opening statement of financial position on the transition date, January 1, 2010 and the comparative information for the three and nine months ended September 30, 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 are described in the interim financial statements for the three months ended March 31, 2011. IFRS Statement of Financial Position - As at September 30, 2010(unaudited)Effect ofPreviousTransition to($000s)NoteGAAPIFRSIFRSAssetsCurrent assetsAccounts receivable6,158-6,158Prepaid expenses and deposits811-811Risk management contracts75-75Property, plant, and equipment, held for sale(a)-32,15832,1587,04432,15839,202Property, plant, and equipment(a,b)220,281(95,248)125,033Exploration and evaluation assets(a,b)-30,32830,328Deferred income taxes(g)1,8413,5745,415222,122(61,346)160,776229,166(29,188)199,978LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities8,326-8,326Revolving credit facility51,939-51,939Decommissioning obligations, held for sale(c)-2,2222,22260,2652,22262,487Decommissioning obligations(c)10,1024,18214,28470,3676,40476,771Shareholders' EquityShareholders' capital(k)166,7581,406168,164Contributed surplus(d)4,6266385,264Deficit(b,c,d,e,f,g)(12,585)(37,636)(50,221)158,799(35,592)123,207229,166(29,188)199,978IFRS Statement of Operations and Comprehensive Loss - Three Months Ended September 30, 2010(unaudited)($000s, except per share amounts)NotePrevious GAAPEffect of Transition to IFRSIFRSRevenueOil and natual gas sales8,574-8,574Royalties(1,173)-(1,173)7,401-7,401Realized loss on risk management contracts(66)-(66)Unrealized gain on risk management contracts469-4697,804-7,804ExpensesProduction2,347(280)2,067Transportation230-230Depletion and depreciation(c,e)6,224(3,022)3,202Asset impairment(b)-2,4512,451General and administrative(j)78382865Share based compensation(d)282(32)250Interest(h)696(696)-10,562(1,497)9,065Operating loss(2,758)1,497(1,261)Other Expenses (Income)Finance expense(c,h)-808808Finance income(h)-22-810810Loss before taxes(2,758)687(2,071)TaxesDeferred income tax reduction(g)(281)281-Net loss and comprehensive loss(2,477)406(2,071)IFRS Statement of Operations and Comprehensive Loss - Nine Months Ended September 30, 2010(unaudited)($000s, except per share amounts)NotePrevious GAAPEffect of Transition to IFRSIFRSRevenueOil and natual gas sales27,256-27,256Royalties(4,584)-(4,584)22,672-22,672Realized loss on risk management contracts(649)-(649)Unrealized gain on risk management contracts1,117-1,11723,140-23,140ExpensesProduction(i)6,480(280)6,200Transportation775-775Depletion and depreciation(c,e)18,193(8,023)10,170Asset impairment(b)-6,7326,732General and administrative(j)2,5293032,832Share based compensation(d)825(101)724Interest(h)2,243(2,243)-31,045(3,612)27,433Operating loss(7,905)3,612(4,293)Other Expenses (Income)Finance expense(c,h)-2,7162,716Finance income(h)-(90)(90)Gain on sale of assets(f)-(936)(936)-1,6901,690Loss before taxes(7,905)1,922(5,983)TaxesDeferred income tax reduction(g)(1,631)1,631-Net loss and comprehensive loss(6,274)291(5,983)Notes to reconciliations(a) IFRS 1 election for full cost oil and gas entitiesThe 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. For the third quarter of 2010, as a result of continued decreases in natural gas commodity prices, the Company recognized an impairment of $2.2 million, relating to Lookout Butte AB, Ferrier AB, and Miscellaneous AB CGUs. For the nine months ended September 30, 2010, the Company recognized an impairment of $5.2 million, relating to Smoky AB, Lookout Butte AB, Ferrier AB, and Miscellaneous AB CGUs. 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%. 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 three and nine months ended September 30, 2010, the Company recognized impairments of $0.3 million and $1.5 million, respectively, on exploration and evaluation assets resulting from the expiry of undeveloped land during the period. (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, 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 above). As at September 30, 2010 the decommissioning obligations were $6.4 million higher 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 $0.1 million during the three and nine months ended September 30, 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. (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 three and nine months ended September 30, 2010, depleting the oil and natural gas interests over proved plus probable reserves resulted in a decrease to depletion and depreciation of $2.9 million and $7.5 million, respectively.(f) Gains and losses on dispositionsUnder 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 nine months ended September 30, 2010, the Company recognized a gain on disposition of $0.9 million, 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. (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, CABANKPresident, CEO & DirectorNational Bank of Canada2700, 530 - 8th Avenue SWNolan Chicoine, MPAcc, CACalgary, Alberta T2P 3S8VP Finance & CFOTerry L. Trudeau, P.Eng.VP Operations & COOTRANSFER AGENTValiant Trust CompanyWeldon Dueck, BSc., P.Eng.310, 606 - 4th Street SWVP Business DevelopmentCalgary, Alberta T2P 1T1R.D. (Rick) Sereda, M.Sc., P.Geol.VP ExplorationLEGAL COUNSELHelmut R. Eckert, P.LandGowling Lafleur Henderson LLPVP Land1400, 700 – 2nd Street SWCalgary, Alberta T2P 4V5Kevin KeithVP ProductionLarry G. Moeller, CA, CBVAUDITORSChairman of the BoardKPMG LLP2700, 205 - 5th Avenue SWDaryl H. Gilbert, P.Eng.Calgary, Alberta T2P 4B9DirectorDon CowieDirectorINDEPENDENT ENGINEERSGLJ Petroleum Consultants Ltd.Brian Krausert4100, 400 - 3rd Avenue SWDirectorCalgary, Alberta T2P 4H2Gary W. BurnsDirectorDon D. Copeland, P.Eng.DirectorBrian BoulangerDirectorPatricia PhillipsDirectorFOR 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