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Press release from Marketwire

Crocotta Energy Inc.: Q3 2012 Financial and Operating Results

Wednesday, November 07, 2012

Crocotta Energy Inc.: Q3 2012 Financial and Operating Results06:00 EST Wednesday, November 07, 2012CALGARY, ALBERTA--(Marketwire - Nov. 7, 2012) -CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2012, including consolidated financial statements, notes to the consolidated financial statements, and Management's Discussion and Analysis. All dollar figures are Canadian dollars unless otherwise noted.HIGHLIGHTSIncreased production 74% in Q3 2012 to 6,945 boe/d from 4,002 boe/d in Q3 2011 Reduced operating costs 19% in Q3 2012 to $5.72/boe from $7.06/boe in Q3 2011 Continued successful drilling of Crocotta's Cardium oil pool at Edson Maintained conservative balance sheet with net debt at less than 55% of bank credit facility Continued to maintain a low debt to cash flow ratio (1.25 based on Q3 annualized cash flow and Q3 exit net debt) FINANCIAL RESULTSThree Months Ended September 30Nine Months Ended September 30($000s, except per share amounts)20122011% Change20122011% ChangeOil and natural gas sales17,92214,8142155,58034,58361Funds from operations (1)10,8889,5511436,13718,49295Per share - basic0.120.12-0.410.2471Per share - diluted0.120.1190.400.2374Net earnings (loss)(3,944)5,535(171)(3,172)1,460(317)Per share - basic and diluted(0.04)0.07(157)(0.04)0.02(300)Capital expenditures23,54026,995(13)62,22856,28411Property acquisitions-696(100)-1,696(100)Property dispositions-(5,758)(100)-(10,011)(100)Net debt (2)54,43630,97376Common shares outstanding (000s)Weighted average - basic88,10380,874988,09777,81513Weighted average - diluted90,58683,360990,91579,81314End of period - basic88,10480,8749End of period - diluted100,22992,3379(1)Funds from operations and funds from operations per share do not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details and the Funds from Operations section in the MD&A for a reconciliation from cash flow from operating activities. (2)Net debt includes current liabilities less current assets (excluding the risk management contracts). Net debt does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details.OPERATING RESULTSThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeDaily productionOil and NGLs (bbls/d)2,1031,336572,144990117Natural gas (mcf/d)29,05315,9968227,74312,676119Oil equivalent (boe/d)6,9454,002746,7683,102118RevenueOil and NGLs ($/bbl)56.7872.38(22)63.7574.75(15)Natural gas ($/mcf)2.604.02(35)2.394.16(43)Oil equivalent ($/boe)28.0540.24(30)29.9740.83(27)RoyaltiesOil and NGLs ($/bbl)11.9710.9999.9614.84(33)Natural gas ($/mcf)0.12(0.01)1,3000.130.0863Oil equivalent ($/boe)4.133.64133.695.07(27)Production expensesOil and NGLs ($/bbl)5.005.58(10)5.067.41(32)Natural gas ($/mcf)1.001.30(23)0.981.46(33)Oil equivalent ($/boe)5.727.06(19)5.628.35(33)Transportation expensesOil and NGLs ($/bbl)0.510.74(31)0.840.822Natural gas ($/mcf)0.190.17120.180.176Oil equivalent ($/boe)0.930.9121.010.947Operating netback (1)Oil and NGLs ($/bbl)39.3055.07(29)47.8951.68(7)Natural gas ($/mcf)1.292.56(50)1.102.45(55)Oil equivalent ($/boe)17.2728.63(40)19.6526.47(26)Depletion and depreciation ($/boe)(15.14)(15.20)-(14.87)(15.15)(2)Asset impairment ($/boe)(3.77)(0.27)1,296(3.07)(3.46)(11)General and administrative expenses ($/boe)(1.29)(2.42)(47)(1.55)(4.08)(62)Share based compensation ($/boe)(1.17)(2.69)(57)(1.52)(2.56)(41)Finance expenses ($/boe)(0.72)(0.58)24(0.72)(1.20)(40)Finance income ($/boe)-0.03(100)-0.16(100)Gain on sale of assets ($/boe)-7.53(100)-1.54(100)Deferred tax reduction (expense) ($/boe)1.40-100(0.26)-100Realized gain on risk management contracts ($/boe)1.60-1001.92-100Unrealized loss on risk management contracts ($/boe)(4.36)-100(1.29)-100Net earnings (loss) ($/boe)(6.18)15.03(141)(1.71)1.72(199)(1)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 UPDATEIn Q3/12, Crocotta anticipated reduced revenue and cash flow due to decreasing natural gas prices and increased differentials on a portion of its natural gas liquids (propane and butane). Due to uncertainty in the timing and extent of price recovery for the gas market, Crocotta focused its limited budget towards its new cardium oil project at Edson.The Edson Cardium project was first successfully drilled in late 2011 with very strong initial results. Crocotta started step-out drilling in June of 2012 and now has a total of 8 successful wells (out of 8 drills) into the project. During the quarter, Crocotta drilled 4 (2.9 net) wells and completed 3 (1.5 net) wells of which 3 were farm-in wells where Crocotta paid for the full cost of the well to earn additional lands. On a go-forward basis, Crocotta is continuing to drill Cardium wells in order to add oil volumes as well as prove up additional lands for future development drilling.The Bluesky and Montney projects were slowed due to capital allocations to the Cardium with 2 (1.6 net) previously drilled Bluesky wells being completed and 1 (1.0 net) Montney well being partially drilled by late September. Capital was also spent on purchasing choke plant equipment and preparing to install pipelines at Dawson-Sunrise for the 2013 expansion of its Montney project. The installation of a choke plant, combined with a meter station, will allow Crocotta to extract significantly more natural gas liquids and materially reduce operating costs. Completion of the project is anticipated by the end of March, 2013.In Q4/12, Crocotta recommenced drilling Bluesky wells at Edson to complement the Cardium program and will monitor the timing of the meter station at Dawson in order to determine the timing of additional Montney drilling in 2013.Since the end of Q3/12, natural gas and natural gas liquids prices have materially increased. Crocotta estimates average liquids net revenue on a go forward basis to be approximately 71% of WTI versus the 61% received in Q3/12. In addition, Crocotta's overall liquid as a percentage of total production has recovered back to 33% from the 31% in Q3/12. The lower Q3/12 liquids recovery was a direct result of plant disruptions at Edson and Dawson. The effect of the liquids, combined with AECO natural gas prices increasing to a current price of $3.20 per mcf versus $2.60 for Q3/12, will increase our net cash flow by an estimated 30% on a go forward basis.Crocotta is on track to meet its exit guidance of 8,500 boepd while maintaining a conservative balance sheet with Q3/12 net debt at less than 55% of its bank credit facility. Such flexibility will allow Crocotta to continue to pursue acquisition and farm-in opportunities or increase capital expenditures on its current lands.MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")November 5, 2012The MD&A should be read in conjunction with the unaudited interim consolidated financial statements and related notes for the three and nine months ended September 30, 2012 and the audited consolidated financial statements and related notes for the year ended December 31, 2011. The unaudited interim consolidated financial statements and financial data contained in the MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") in Canadian currency (except where noted as being in another currency).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.DESCRIPTION OF BUSINESSCrocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in Western Canada. The Company trades on the Toronto Stock Exchange under the symbol "CTA". FREQUENTLY RECURRING TERMSThe Company uses the following frequently recurring industry terms in the MD&A: "bbls" refers to barrels, "mcf" refers to thousand cubic feet, "GJ" refers to gigajoule, 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. Given that the value ratio based on the current price of oil as compared to natural gas is significantly different from the energy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.NON-GAAP MEASURESThis MD&A refers to certain financial measures that are not determined in accordance with IFRS (or "GAAP"). This MD&A contains the terms "funds from operations", "funds from operations per share", "net debt", and "operating netback" which do not have any standardized meaning prescribed by GAAP and therefore may not be comparable to similar measures used by other companies. The Company uses these measures to help evaluate its performance. Management uses funds from operations to analyze performance and considers it a key measure as it demonstrates the Company's ability to generate the cash necessary to fund future capital investments and to repay debt. Funds from operations is a non-GAAP measure and has been defined by the Company as net earnings (loss) plus non-cash items (depletion and depreciation, asset impairments, share based compensation, non-cash finance expenses, gains and losses on asset sales, deferred income taxes, and unrealized gains and losses on risk management contracts) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of earnings per share. Funds from operations is reconciled from cash flow from operating activities under the heading "Funds from Operations". Management uses net debt as a measure to assess the Company's financial position. Net debt includes current liabilities less current assets (excluding the 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".Q3 2012 HIGHLIGHTSIncreased production 74% in Q3 2012 to 6,945 boe/d from 4,002 boe/d in Q3 2011 Reduced operating costs 19% in Q3 2012 to $5.72/boe from $7.06/boe in Q3 2011 Continued successful drilling of Crocotta's Cardium oil pool at Edson Maintained conservative balance sheet with net debt at less than 55% of bank credit facility Continued to maintain a low debt to cash flow ratio (1.25 based on Q3 annualized cash flow and Q3 exit net debt) SUMMARY OF FINANCIAL RESULTSThree Months Ended September 30Nine Months Ended September 30($000s, except per share amounts)20122011% Change20122011% ChangeOil and natural gas sales17,92214,8142155,58034,58361Funds from operations10,8889,5511436,13718,49295Per share - basic0.120.12-0.410.2471Per share - diluted0.120.1190.400.2374Net earnings (loss)(3,944)5,535(171)(3,172)1,460(317)Per share - basic and diluted(0.04)0.07(157)(0.04)0.02(300)Total assets268,434223,57620Total long-term liabilities20,80416,07629Net debt54,43630,97376The Company has experienced significant growth in oil and natural gas sales and funds from operations over the past year. Successful capital activity during the previous two years, mainly at Edson, AB, resulted in a significant increase in production which resulted in increased revenue and funds from operations. PRODUCTIONThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeAverage Daily ProductionOil and NGLs (bbls/d)2,1031,336572,144990117Natural gas (mcf/d)29,05315,9968227,74312,676119Combined (boe/d)6,9454,002746,7683,102118Daily production for the three months ended September 30, 2012 increased 74% to 6,945 boe/d compared to 4,002 boe/d for the comparative period in 2011. Year-to-date, daily production increased 118% to 6,768 boe/d in 2012 compared to 3,102 boe/d in 2011. The significant increase in production was mainly due to successful drilling activity at Edson, AB during 2011 and the first nine months of 2012 which saw 23 gross (18.1 net) wells drilled at a 100% success rate. Compared to the previous quarter, daily production increased in Q3 2012 to 6,945 boe/d from 6,604 boe/d in Q2 2012 due to successful drilling activity and unexpected downtime during Q2 2012 at the third party gas plant that processes the Company's production at Edson, AB. Crocotta's production profile for the first nine months of 2012 was comprised of 68% natural gas and 32% oil and NGLs, consistent with the production profile for 2011.REVENUEThree Months Ended September 30Nine Months Ended September 30($000s)20122011% Change20122011% ChangeOil and NGLs10,9858,8962337,45020,19685Natural gas6,9375,9181718,13014,38726Total17,92214,8142155,58034,58361Average Sales PriceOil and NGLs ($/bbl)56.7872.38(22)63.7574.75(15)Natural gas ($/mcf)2.604.02(35)2.394.16(43)Combined ($/boe)28.0540.24(30)29.9740.83(27)Revenue totaled $17.9 million for the third quarter of 2012, up 21% from $14.8 million in the comparative period. For the nine months ended September 30, 2012, revenue totaled $55.6 million, an increase of 61% from $34.6 million for the nine months ended September 30, 2011. The increase in revenue was due to significant increases in production, partially offset by a significant decrease in oil and natural gas commodity prices. The following table outlines the Company's realized wellhead prices and industry benchmarks:Commodity PricingThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeOil and NGLsCorporate price ($CDN/bbl)56.7872.38(22)63.7574.75(15)Edmonton par ($CDN/bbl)84.7992.45(8)87.2994.32(7)West Texas Intermediate ($US/bbl)92.1889.40396.1695.311Natural gasCorporate price ($CDN/mcf)2.604.02(35)2.394.16(43)AECO price ($CDN/mcf)2.283.63(37)2.123.77(44)Exchange rateCDN/US dollar average exchange rate1.00531.0218(2)0.99811.0233(2)Differences 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 67.0% and 73.0% of Edmonton Par price for the three and nine months ended September 30, 2012, down from 78.3% and 79.3% for the comparative period in 2011. As a higher percentage of the Company's oil and NGLs production is comprised of NGLs, the decrease was mainly due to an increase in the differential between oil and NGLs commodity prices during Q2 and Q3 2012. Subsequent to September 30, 2012, the differential between oil and NGLs commodity prices has decreased. Corporate average natural gas prices were 114.0% and 112.7% of AECO prices for the three and nine months ended September 30, 2012, up slightly from 110.7% and 110.3% in the comparative period. Future prices received from the sale of the products may fluctuate as a result of market factors. Other than noted below, the Company did not hedge any of its oil, NGLs or natural gas production in 2012. The Company has entered into the following commodity price contracts:CommodityPeriodType of ContractQuantity ContractedContract PriceOilMay 1, 2012 - September 30, 2012Financial - Swap800 bbls/dWTI US $104.38/bblNatural GasJuly 1, 2012 - December 31, 2012Financial - Swap5,000 GJ/dAECO CDN $2.400/GJNatural GasAugust 1, 2012 - October 31, 2012Financial - Swap5,000 GJ/dAECO CDN $2.300/GJNatural GasJanuary 1, 2013 - December 31, 2013Financial - Swap10,000 GJ/dAECO CDN $2.705/GJNatural GasJanuary 1, 2013 - December 31, 2013Financial - Call10,000 GJ/dAECO CDN $4.000/GJFor the three months ended September 30, 2012, the realized gain on the oil contract was $0.8 million and the realized gain on the gas contracts was $0.2 million. For the nine months ended September 30, 2012, the realized gain on the risk management contracts was $3.6 million, comprised of a gain of $3.4 million on the oil contract and $0.2 million on the gas contracts. During the second quarter, the Company settled a portion of the original oil contract for the period from October 1, 2012 through December 31, 2012 for cash proceeds of $1.7 million, which was included in the realized gain. The fair value of the risk management contracts at September 30, 2012 were allocated to current and non-current liabilities on a contract by contract basis.ROYALTIESThree Months Ended September 30Nine Months Ended September 30($000s)20122011% Change20122011% ChangeOil and NGLs2,3171,350725,8494,01046Natural gas321(11)3,018991285248Total2,6381,339976,8404,29559Average Royalty Rate (% of sales)Oil and NGLs21.115.23915.619.9(22)Natural gas4.6(0.2)2,4005.52.0175Combined14.79.06312.312.4(1)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, 2012, oil, NGLs, and natural gas royalties increased 97% to $2.6 million from $1.3 million in the comparative period. For the nine months ended September 30, 2012, oil, NGLs, and natural gas royalties increased 59% to $6.8 million from $4.3 million in 2011. These increases stemmed from a significant increase in revenue in 2012 compared to 2011 due to a significant increase in production. The overall effective royalty rate was 14.7% for the three months ended September 30, 2012 compared to 9.0% for the three months ended September 30, 2011. The royalty rate increased as several of the Edson wells brought on production during the previous year came off royalty incentive rates during the quarter. Year-to-date, the overall effective royalty rate was 12.3% in 2012 compared to 12.4% in 2011. The effective oil and NGLs royalty rate decreased as royalty incentive rates were received on several new wells during the majority of the nine months ended September 30, 2012 compared to only a portion of the nine months ended September 30, 2011. The effective natural gas royalty rate increased as a result of a prior period adjustment to the annual capital cost and processing fee deductions combined with a relative decrease in the monthly capital cost allowance reduction. The overall effective royalty rate for the third quarter of 2012 was up marginally from the second quarter of 2012 which had an overall rate of 11.2%.PRODUCTION EXPENSESThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeOil and NGLs ($/bbl)5.005.58(10)5.067.41(32)Natural gas ($/mcf)1.001.30(23)0.981.46(33)Combined ($/boe)5.727.06(19)5.628.35(33)Per unit production expenses for the three and nine months ended September 30, 2012 were $5.72/boe and $5.62/boe, respectively, down significantly from $7.06/boe and $8.35/boe for the comparative periods ended September 30, 2011. The Company has realized significant decreases in production expenses per boe due to operations at its core Edson, AB area. The Company is the operator and has ownership of the infrastructure at Edson, enabling it to exercise control over operating costs. Control of operations and ownership of the infrastructure combined with significant increases in production over the previous year, as a result of successful drilling activities, have allowed the Company to realize lower production expenses through economies of scale. Compared to the previous quarter, per unit production expenses decreased to $5.72/boe in the third quarter of 2012 from $5.96/boe in the second quarter of 2012. The Company continues to focus on opportunities to maintain operational efficiencies to enhance operating netbacks.TRANSPORTATION EXPENSESThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeOil and NGLs ($/bbl)0.510.74(31)0.840.822Natural gas ($/mcf)0.190.17120.180.176Combined ($/boe)0.930.9121.010.947Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended September 30, 2012 compared to the quarter ended September 30, 2011, transportation expenses increased 2% to $0.93/boe from $0.91/boe. Year-to-date, transportation expenses increased 7% to $1.01/boe in 2012 from $0.94/boe in 2011. The increase in natural gas transportation expenses was a result of the Company's successful Sunrise, BC well coming on stream during the latter half of the second quarter of 2012. OPERATING NETBACKThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeOil and NGLs ($/bbl)Revenue56.7872.38(22)63.7574.75(15)Royalties11.9710.9999.9614.84(33)Production expenses5.005.58(10)5.067.41(32)Transportation expenses0.510.74(31)0.840.822Operating netback39.3055.07(29)47.8951.68(7)Natural gas ($/mcf)Revenue2.604.02(35)2.394.16(43)Royalties0.12(0.01)1,3000.130.0863Production expenses1.001.30(23)0.981.46(33)Transportation expenses0.190.17120.180.176Operating netback1.292.56(50)1.102.45(55)Combined ($/boe)Revenue28.0540.24(30)29.9740.83(27)Royalties4.133.64133.695.07(27)Production expenses5.727.06(19)5.628.35(33)Transportation expenses0.930.9121.010.947Operating netback17.2728.63(40)19.6526.47(26)During the third quarter of 2012, Crocotta generated an operating netback of $17.27/boe, down 40% from $28.63/boe for the third quarter of 2011. During the nine months ended September 30, 2012, Crocotta generated an operating netback of $19.65/boe compared to $26.47/boe in the comparative period. The decrease was mainly due to significant decreases in oil, NGLs, and natural gas commodity prices in 2012 compared to 2011, partially offset by declines in oil and NGLs royalties and overall production expenses. Operating netbacks in Q3 2012 were down from operating netbacks of $18.64/boe in Q2 2012 due mainly to a decline in oil and NGLs commodity prices. The following is a reconciliation of operating netback per boe to net earnings (loss) per boe for the periods noted:Three Months Ended September 30Nine Months Ended September 30($/boe)20122011% Change20122011% ChangeOperating netback17.2728.63(40)19.6526.47(26)Depletion and depreciation(15.14)(15.20)-(14.87)(15.15)(2)Asset impairment(3.77)(0.27)1,296(3.07)(3.46)(11)General and administrative expenses(1.29)(2.42)(47)(1.55)(4.08)(62)Share based compensation(1.17)(2.69)(57)(1.52)(2.56)(41)Finance expenses(0.72)(0.58)24(0.72)(1.20)(40)Finance income-0.03(100)-0.16(100)Loss on sale of assets-7.53(100)-1.54(100)Deferred tax reduction (expense)1.40-100(0.26)-100Realized gain on risk management contracts1.60-1001.92-100Unrealized loss on risk management contracts(4.36)-100(1.29)-100Net earnings (loss)(6.18)15.03(141)(1.71)1.72(199)DEPLETION AND DEPRECIATIONThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeDepletion and depreciation ($000s)9,6755,5967327,57812,833115Depletion and depreciation ($/boe)15.1415.20-14.8715.15(2)Depletion and depreciation for the three and nine months ended September 30, 2012 was $15.14/boe and $14.87/boe, respectively, consistent with depletion and depreciation of $15.20/boe and $15.15/boe for the comparative periods ended September 30, 2011. Depletion and depreciation for the third quarter of 2012 was also consistent with depletion and depreciation of $14.56/boe for the previous quarter ended June 30, 2012.ASSET IMPAIRMENTThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeAsset impairment ($000s)2,412982,3615,6962,93294Asset impairment ($/boe)3.770.271,2963.073.46(11)Exploration and evaluation assets and property, plant, and equipment are grouped into cash generating units ("CGU") for purposes of impairment testing. Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For property, plant, and equipment, an impairment is recognized if the carrying value of a CGU exceeds the greater of its fair value less costs to sell or value in use. For the nine months ended September 30, 2012, total exploration and evaluation asset impairments of $3.9 million were recognized. Asset impairments of $2.3 million were recognized relating to the determination of certain exploration and evaluation activities in non-core areas to be uneconomical (CGU - Miscellaneous AB). Additional exploration and evaluation impairments of $1.6 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan). For the comparative period ended September 30, 2011, total exploration and evaluation asset impairments of $2.9 million were recognized. Asset impairments of $2.2 million were recognized relating to the determination of certain exploration and evaluation activities in southern Alberta to be uneconomical (CGU - Miscellaneous AB). Additional exploration and evaluation impairments of $0.7 million were recognized relating to the expiry of undeveloped land rights (CGUs - Ferrier AB and Miscellaneous AB). For the three months ended September 30, 2012, asset impairments of $1.8 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGU - Miscellaneous AB) and asset impairments of $0.5 million were recognized relating to expiry of undeveloped land rights (CGUs - Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan). For the three months ended September 30, 2011, asset impairments of $0.1 million were recognized relating to the expiry of undeveloped land rights (CGU -Miscellaneous AB).For the nine months ended September 30, 2012, the Company recorded property, plant, and equipment impairments of $1.8 million during the first quarter relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices. No property, plant, and equipment impairments were recognized during the second and third quarters of 2012 or the nine months ended September 30, 2011.GENERAL AND ADMINISTRATIVEThree Months Ended September 30Nine Months Ended September 30($000s)20122011% Change20122011% ChangeG&A expenses (gross)1,1591,192(3)3,9444,556(13)G&A capitalized(94)(80)18(240)(258)(7)G&A recoveries(241)(222)9(826)(840)(2)G&A expenses (net)824890(7)2,8783,458(17)G&A expenses ($/boe)1.292.42(47)1.554.08(62)General and administrative expenses ("G&A") decreased significantly to $1.29/boe and $1.55/boe for the three and nine months ended September 30, 2012, respectively, compared to $2.42/boe and $4.08/boe for the three and nine months ended September 30, 2011. The decrease was mainly due to a significant increase in production and a reduction in various administrative costs. SHARE BASED COMPENSATIONThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeShare based compensation ($000s)745990(25)2,8282,16431Share based compensation ($/boe)1.172.69(57)1.522.56(41)The Company grants stock options to officers, directors, employees and consultants and calculates the related share based compensation using the Black-Scholes-Merton option pricing model. 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 decreased to $1.17/boe for the three months ended September 30, 2012 from $2.69/boe in the comparative period. Year-to-date, share based compensation expense decreased to $1.52/boe in 2012 from $2.56/boe in 2011. The decrease was a result of a significant increase in production in 2012 compared to 2011. During the first nine months of 2012, the Company granted 0.7 million options (2011 - 4.2 million). FINANCE EXPENSESThree Months Ended September 30Nine Months Ended September 30($000s)20122011% Change20122011% ChangeInterest expense34910922099760565Accretion of decommissioning obligations1111056333332-Unrealized loss on investments----79(100)Finance expenses4602141151,3301,01631Finance expenses ($/boe)0.720.58240.721.20(40)Interest expense relates to interest incurred on amounts drawn from the Company's credit facility. At September 30, 2012, $42.6 million (2011 - $13.7 million) had been drawn on the Company's credit facility. GAIN ON SALE OF ASSETSThree Months Ended September 30Nine Months Ended September 3020122011% Change20122011% ChangeGain on sale of assets ($000s)-2,772(100)-1,307(100)Gain on sale of assets ($/boe)-7.53(100)-1.54(100)During 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.DEFERRED INCOME TAXESDeferred income tax reduction on the loss before taxes for the three months ended September 30, 2012 was $0.9 million (2011 - $nil). This was marginally lower than expected by applying the statutory tax rate to the loss before taxes due to non-deductible items such as share based compensation as well as renouncing flow-through shares. Deferred income tax expense on the loss before taxes for the nine months ended September 30, 2012 was $0.5 million (2011 - $nil). This was larger than expected by applying the statutory tax rate to the loss before taxes due to non-deductible items such as share based compensation as well as renouncing flow-through shares. Estimated tax pools at September 30, 2012 total approximately $272.7 million.FUNDS FROM OPERATIONS Funds from operations for the three and nine months ended September 30, 2012 were $10.9 million ($0.12 per diluted share) and $36.1 million ($0.40 per diluted share), respectively, compared to $9.6 million ($0.11 per diluted share) and $18.5 million ($0.23 per diluted share) for the three and nine months ended September 30, 2011. The increase was mainly due to a significant increase in production which resulted in a significant increase in revenue. Of note, included in funds from operations for the three and nine months ended September 30, 2012 were $1.0 million and $3.6 million, respectively, in realized gains on risk management contracts.The following is a reconciliation of cash flow from operating activities to funds from operations for the periods noted:Three Months Ended September 30Nine Months Ended September 30($000s)20122011% Change20122011% ChangeCash flow from operating activities (GAAP)9,6869,035735,35316,465115Add back:Decommissioning expenditures27117654621176253Change in non-cash working capital9313401741631,851(91)Funds from operations (non-GAAP)10,8889,5511436,13718,49295NET EARNINGS (LOSS)The Company had a net loss of $3.9 million ($0.04 per diluted share) for the three months ended September 30, 2012 compared to net earnings of $5.5 million ($0.07 per diluted share) for the three months ended September 30, 2011. Year-to-date, the Company had a net loss of $3.2 million ($0.04 per diluted share) in 2012 compared to net earnings of $1.5 million ($0.02 per diluted share) in 2011. The loss for the three and nine months ended September 30, 2012 arose mainly due to exploration and evaluation asset impairments in non-core areas and unrealized losses on risk management contracts.CAPITAL EXPENDITURESThree Months Ended September 30Nine Months Ended September 30($000s)20122011% Change20122011% ChangeLand1,3263442854,4061,261249Drilling, completions, and workovers19,12123,382(18)47,15945,8363Equipment3,0162,948210,1688,23324Geological and geophysical77276(72)495885(44)Other-45(100)-69(100)Exploration and development23,54026,995(13)62,22856,28411Property acquisitions-696(100)-1,696(100)Property dispositions-(5,758)(100)-(10,011)(100)Net property dispositions-(5,062)(100)-(8,315)(100)Net capital expenditures23,54021,933762,22847,96930For the three months ended September 30, 2012, the Company had net capital expenditures of $23.5 million compared to net capital expenditures of $21.9 million for the three months ended September 30, 2011. For the nine months ended September 30, 2012, the Company had net capital expenditures of $62.2 million compared to $48.0 million for the comparative period in 2011. The increase in exploration and development expenditures in the first nine months of 2012 was due mainly to an increase in capital expenditures in the Company's core areas of Edson, AB and northeast BC. During the first nine months of 2012, the Company drilled a total of 11 (8.4 net) wells, which resulted in 5 (2.8 net) oil wells, 4 (3.6 net) liquids-rich natural gas wells, and 2 (2.0 net) exploratory wells in non-core areas that were uneconomic.LIQUIDITY AND CAPITAL RESOURCESThe Company had net debt of $54.4 million at September 30, 2012 compared to net debt of $27.7 million at December 31, 2011. The increase of $26.7 million was mainly due to $62.2 million used for the purchase and development of oil and natural gas properties and equipment and $0.6 million for decommissioning expenditures, offset by funds from operations of $36.1 million.At September 30, 2012, the Company had a $100.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At September 30, 2012, $42.6 million (December 31, 2011 - $5.2 million) had been drawn on the revolving credit facility. In addition, at September 30, 2012, the Company had outstanding letters of guarantee of approximately $1.6 million (December 31, 2011 - $1.0 million) which reduce the amount that can be borrowed under the credit facility. The next review of the revolving credit facility by the bank is scheduled on or before December 1, 2012. 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. Despite the economic downturn and financial market volatility, the Company continued to have access to both debt and equity markets recently. The Company raised gross proceeds of approximately $61.0 million from the issuance of common shares during 2011 and during the second quarter of 2012 the Company obtained an increase to its revolving credit facility from $80.0 million to $100.0 million. The Company has also maintained a very successful drilling program which has resulted in significant increases in production and funds flow from operations in recent quarters in spite of downward trends and continued pressure on oil and natural gas commodity prices. Management anticipates that the Company will continue to have adequate liquidity to fund budgeted capital investments through a combination of cash flow, equity, and debt. Crocotta's capital program is flexible and can be adjusted as needed based upon the current economic environment. The Company will continue to monitor the economic environment and the possible impact on its business and strategy and will make adjustments as necessary.CONTRACTUAL OBLIGATIONSThe following is a summary of the Company's contractual obligations and commitments at September 30, 2012: Less thanOne toAfter($000s)TotalOne YearThree YearsThree YearsAccounts payable and accrued liabilities23,66723,667--Revolving credit facility42,59042,590--Risk management contracts2,3861,834552-Decommissioning obligations20,252364920,167Office leases993506487-Field equipment leases2,1421,373769-Firm transportation agreements40422516118Capital processing agreements200--200Total contractual obligations92,63470,2312,01820,385As a result of the issuance of flow-through shares in December 2011, the Company is committed to expend $5.0 million on qualifying exploration expenditures prior to December 31, 2012. At September 30, 2012, the Company had fulfilled the flow-through share commitment.The Company has entered into a farm-in agreement to drill and complete one Edson Cardium well. Under the terms of the farm-in agreement, the Company is committed to spud the well prior to December 2012. The estimated cost to drill and complete the well is $3.5 million. The Company has also entered into fixed price financial contracts for future natural gas production as outlined above (see "Revenue" section).OUTSTANDING SHARE DATAThe Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, and Class B preferred shares, issuable in series. The voting common shares of the Company commenced trading on the TSX on October 17, 2007 under the symbol "CTA". The following table summarizes the common shares outstanding and the number of shares exercisable into common shares from options, warrants, and other instruments: (000s)September 30, 2012November 5, 2012Voting common shares88,10489,308Stock options8,6048,599Warrants3,5212,321Total100,229100,228SUMMARY OF QUARTERLY RESULTS(1)Q3 2012Q2 2012Q1 2012Q4 2011Q3 2011Q2 2011Q1 2011Q4 2010Average Daily ProductionOil and NGLs (bbls/d)2,1032,0532,2771,8791,3361,039586647Natural gas (mcf/d)29,05327,30926,85223,35415,99611,84310,1249,958Combined (boe/d)6,9456,6046,7525,7714,0023,0122,2742,307($000s, except per share amounts)Oil and natural gas sales17,92217,51820,14020,39114,81412,2897,4807,274Funds from operations10,88812,27512,97412,1159,5516,9272,0144,200Per share - basic0.120.140.150.150.120.090.030.06Per share - diluted0.120.140.140.140.110.080.030.06Net earnings (loss)(3,944)1,065(293)(7,052)5,535374(4,449)656Per share - basic and diluted(0.04)0.01-(0.09)0.07-(0.06)0.01(1)2010 quarterly results have been adjusted to conform to IFRS.A significant increase in production stemming from successful drilling activity during the previous two years resulted in substantial increases in revenue and funds from operations in Q4 2011 through Q3 2012 compared to prior quarters. The Company had a net loss in three of the four previous quarters mainly as a result of asset impairments recognized in each quarter on non-core properties.OPERATIONS UPDATEIn Q3/12, Crocotta anticipated reduced revenue and cash flow due to decreasing natural gas prices and increased differentials on a portion of its natural gas liquids (propane and butane). Due to uncertainty in the timing and extent of price recovery for the gas market, Crocotta focused its limited budget towards its new cardium oil project at Edson.The Edson Cardium project was first successfully drilled in late 2011 with very strong initial results. Crocotta started step-out drilling in June of 2012 and now has a total of 8 successful wells (out of 8 drills) into the project. During the quarter, Crocotta drilled 4 (2.9 net) wells and completed 3 (1.5 net) wells of which 3 were farm-in wells where Crocotta paid for the full cost of the well to earn additional lands. On a go-forward basis, Crocotta is continuing to drill Cardium wells in order to add oil volumes as well as prove up additional lands for future development drilling.The Bluesky and Montney projects were slowed due to capital allocations to the Cardium with 2 (1.6 net) previously drilled Bluesky wells being completed and 1 (1.0 net) Montney well being partially drilled by late September. Capital was also spent on purchasing choke plant equipment and preparing to install pipelines at Dawson-Sunrise for the 2013 expansion of its Montney project. The installation of a choke plant, combined with a meter station, will allow Crocotta to extract significantly more natural gas liquids and materially reduce operating costs. Completion of the project is anticipated by the end of March, 2013.In Q4/12, Crocotta recommenced drilling Bluesky wells at Edson to complement the Cardium program and will monitor the timing of the meter station at Dawson in order to determine the timing of additional Montney drilling in 2013.Since the end of Q3/12, natural gas and natural gas liquids prices have materially increased. Crocotta estimates average liquids net revenue on a go forward basis to be approximately 71% of WTI versus the 61% received in Q3/12. In addition, Crocotta's overall liquid as a percentage of total production has recovered back to 33% from the 31% in Q3/12. The lower Q3/12 liquids recovery was a direct result of plant disruptions at Edson and Dawson. The effect of the liquids, combined with AECO natural gas prices increasing to a current price of $3.20 per mcf versus $2.60 for Q3/12, will increase our net cash flow by an estimated 30% on a go forward basis.Crocotta is on track to meet its exit guidance of 8,500 boepd while maintaining a conservative balance sheet with Q3/12 net debt at less than 55% of its bank credit facility. Such flexibility will allow Crocotta to continue to pursue acquisition and farm-in opportunities or increase capital expenditures on its current lands.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 Company's significant critical accounting estimates have not changed from the year ended December 31, 2011.FUTURE CHANGES IN ACCOUNTING POLICIESIn May 2011, the IASB issued four new standards and two amendments. Five of these items related to consolidation, while the remaining one addresses fair value measurement. All of the new standards are effective for annual periods beginning on or after January 1, 2013. Early adoption is permitted. The Company is currently evaluating the impact of adopting all of the newly issued and amended standards but does not anticipate a material impact to 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 risk The 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 risk The 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 risk Oil and natural gas prices are impacted by not only the relationship between the Canadian and US dollar but also by world economic events that dictate the levels of supply and demand. The Company's oil, natural gas, and NGLs production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company's cash flow from product sales will therefore be impacted by fluctuations in commodity prices. The Company has entered into the following commodity price contracts:CommodityPeriodType of ContractQuantity ContractedContract PriceOilMay 1, 2012 - September 30, 2012Financial - Swap800 bbls/dWTI US $104.38/bblNatural GasJuly 1, 2012 - December 31, 2012Financial - Swap5,000 GJ/dAECO CDN $2.400/GJNatural GasAugust 1, 2012 - October 31, 2012Financial - Swap5,000 GJ/dAECO CDN $2.300/GJNatural GasJanuary 1, 2013 - December 31, 2013Financial - Swap10,000 GJ/dAECO CDN $2.705/GJNatural GasJanuary 1, 2013 - December 31, 2013Financial - Call10,000 GJ/dAECO CDN $4.000/GJSafety 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 President and Chief Executive Officer ("CEO") and the Vice President Finance and Chief Financial Officer ("CFO") have designed, or caused to be designed under their supervision, disclosure controls and procedures ("DC&P) and internal controls over financial reporting ("ICOFR") as defined in National Instrument 52-109 Certification of Disclosure in Issuer's Annual and Interim Filings in order to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the financial statements for external purposes in accordance with IFRS.The DC&P have been designed to provide reasonable assurance that material information relating to the Company is made known to the CEO and CFO by others and that information required to be disclosed by the Company in its annual filings, interim filings or other reports filed or submitted by the Company under securities legislation is recorded, processed, summarized and reported within the time periods specified in securities legislation. The Company's CEO and CFO have concluded based on their evaluation as of the end of the period covered by the interim filings that the Company's disclosure controls and procedures are effective to provide reasonable assurance that material information related to the issuer is made known to them by others within the Company.The CEO and CFO are required to cause the Company to disclose any change in the Company's ICOFR that occurred during the most recent interim period that has materially affected, or is reasonably likely to materially affect, the Company's ICOFR. No changes in ICOFR were identified during such period that have materially affected or are reasonably likely to materially affect, the Company's ICOFR. There were no changes to ICOFR as a result of the transition to IFRS.It should be noted a control system, including the Company's DC&P and ICOFR, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objective of the control system will be met and it should not be expected that DC&P and ICOFR will prevent all errors or fraud.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.Crocotta Energy Inc.Condensed Consolidated Statements of Financial Position(unaudited)September 30December 31($000s)Note20122011AssetsCurrent assetsAccounts receivable10,99511,298Prepaid expenses and deposits82684011,82112,138Property, plant, and equipment(5)211,350192,332Exploration and evaluation assets(4)32,12120,641Deferred income taxes13,14214,443268,434239,554LiabilitiesCurrent liabilitiesAccounts payable and accrued liabilities23,66734,692Revolving credit facility(6)42,5905,182Risk management contracts(10)1,834-68,09139,874Decommissioning obligations(7)20,25219,250Risk management contracts(10)552-Flow-through share premium-81388,89559,937Shareholders' EquityShareholders' capital225,860225,848Contributed surplus12,0098,927Deficit(58,330)(55,158)179,539179,617268,434239,554The accompanying notes are an integral part of these condensed interim consolidated financial statements.Crocotta Energy Inc.Condensed Consolidated Statements of Operations and Comprehensive Earnings (Loss)(unaudited)Three Months Ended September 30Nine Months Ended September 30($000s, except per share amounts)Note2012201120122011RevenueOil and natual gas sales17,92214,81455,58034,583Royalties(2,638)(1,339)(6,840)(4,295)15,28413,47548,74030,288Realized gain on risk management contracts(10)1,024-3,560-Unrealized loss on risk management contracts(10)(2,786)-(2,386)-13,52213,47549,91430,288ExpensesProduction3,6532,59910,4187,068Transportation5943361,870796Depletion and depreciation(5)9,6755,59627,57812,833Asset impairment(4,5)2,412985,6962,932General and administrative8248902,8783,458Share based compensation(8)7459902,8282,16417,90310,50951,26829,251Operating earnings (loss)(4,381)2,966(1,354)1,037Other expenses (income)Finance expense4602141,3301,016Finance income-(11)-(132)Gain on sale of assets-(2,772)-(1,307)460(2,569)1,330(423)Earnings (loss) before taxes(4,841)5,535(2,684)1,460TaxesDeferred income tax expense (reduction)(897)-488-Net earnings (loss) and comprehensive earnings (loss)(3,944)5,535(3,172)1,460Net earnings (loss) per shareBasic and diluted(0.04)0.07(0.04)0.02The accompanying notes are an integral part of these condensed interim consolidated financial statements.Crocotta Energy Inc.Condensed Consolidated Statements of Shareholders' Equity(unaudited)Nine Months Ended September 30($000s)20122011Shareholders' CapitalBalance, beginning of period225,848168,164Issue of shares (net of share issue costs and flow-through share premium)-33,844Issued on exercise of stock options12114Share based compensation - exercised-79Balance, end of period225,860202,201Contributed SurplusBalance, beginning of period8,9275,515Share based compensation - expensed2,8282,164Share based compensation - capitalized254189Share based compensation - exercised-(79)Balance, end of period12,0097,789DeficitBalance, beginning of period(55,158)(49,566)Net earnings (loss)(3,172)1,460Balance, end of period(58,330)(48,106)Total Shareholders' Equity179,539161,884The accompanying notes are an integral part of these condensed interim consolidated financial statements.Crocotta Energy Inc.Condensed Consolidated Statements of Cash Flows(unaudited)Three Months Ended September 30Nine Months Ended September 30($000s)Note2012201120122011Operating ActivitiesNet earnings (loss)(3,944)5,535(3,172)1,460Depletion and depreciation(5)9,6755,59627,57812,833Asset impairment(4,5)2,412985,6962,932Share based compensation(8)7459902,8282,164Finance expense4602141,3301,016Interest paid(349)(109)(997)(605)Gain on sale of assets-(2,772)-(1,307)Deferred income tax expense (reduction)(897)-488-Unrealized loss on risk management contracts(10)2,786-2,386-Decommissioning expenditures(7)(271)(176)(621)(176)Change in non-cash working capital(931)(340)(163)(1,851)9,6869,03635,35316,466Financing ActivitiesRevolving credit facility(6)2,9124,87137,408(16,798)Issuance of shares12-1236,074Share issue costs---(2,116)2,9244,87137,42017,160Investing ActivitiesCapital expenditures - property, plant, and equipment(5)(7,796)(22,174)(37,278)(50,512)Capital expenditures - exploration and evaluation assets(4)(15,744)(5,517)(24,950)(7,468)Asset dispositions-5,758-10,011Change in non-cash working capital10,9308,026(10,545)14,343(12,610)(13,907)(72,773)(33,626)Change in cash and cash equivalents----Cash and cash equivalents, beginning of period----Cash and cash equivalents, end of period----The accompanying notes are an integral part of these condensed interim consolidated financial statements.Crocotta Energy Inc.Notes to the Condensed Interim Consolidated Financial StatementsThree and Nine Months Ended September 30, 2012(Tabular amounts in 000s, unless otherwise stated)1. REPORTING ENTITYCrocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in Western Canada. The Company conducts many of its activities jointly with others and these condensed interim consolidated financial statements reflect only the Company's proportionate interest in such activities. The Company currently has one wholly-owned subsidiary.The Company's place of business is located at 700, 639 - 5th Avenue SW, Calgary, Alberta, Canada, T2P 0M9.2. BASIS OF PRESENTATION(a) Statement of complianceThese condensed interim consolidated 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 consolidated financial statements. The condensed interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes for the year ended December 31, 2011.The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on November 5, 2012.(b) Basis of measurementThe condensed interim consolidated financial statements have been prepared on the historical cost basis except for held for trading financial assets, which are measured at fair value with changes in fair value recorded in earnings, and derivative financial instruments, which are measured at their estimated fair value (note 10). (c) Functional and presentation currencyThe condensed interim consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency.(d) Use of estimates and judgmentsThe preparation of the condensed interim consolidated financial statements in conformity with IFRS requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities as at the date of the interim consolidated financial statements and the reported amounts of revenues and expenses during the period. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future periods could require a material change in the interim consolidated financial statements. Accordingly, actual results may differ from the estimated amounts as future confirming events occur. The significant estimates and judgments made by management in the preparation of these condensed interim consolidated financial statements were consistent with those applied to the consolidated financial statements as at and for the year ended December 31, 2011. 3. SIGNIFICANT ACCOUNTING POLICIESThe condensed interim consolidated financial statements have been prepared following the same accounting policies as the audited consolidated financial statements for the year ended December 31, 2011. The accounting policies have been applied consistently by the Company to all periods presented in these interim consolidated financial statements.4. EXPLORATION AND EVALUATION ASSETSTotalBalance, December 31, 201120,641Additions24,950Transfer to property, plant, and equipment(9,614)Impairment(3,856)Balance, September 30, 201232,121Exploration 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, consisting primarily of undeveloped land and drilling costs until the drilling of the well is complete and the results have been evaluated. Included in the $25.0 million of additions during the nine months ended September 30, 2012 were additions of $14.9 million related to the Edson AB CGU, $7.3 million related to the Miscellaneous AB CGU, and $2.5 million related to the Northeast BC CGU.ImpairmentsExploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the nine months ended September 30, 2012, total exploration and evaluation asset impairments of $3.9 million were recognized. Asset impairments of $2.3 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGU - Miscellaneous AB). Additional exploration and evaluation impairments of $1.6 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan).5. PROPERTY, PLANT, AND EQUIPMENTCostTotalBalance, December 31, 2011236,846Additions37,278Transfer from exploration and evaluation assets9,614Change in decommissioning obligation estimates1,290Capitalized share based compensation254Balance, September 30, 2012285,282Accumulated Depletion, Depreciation, and ImpairmentTotalBalance, December 31, 201144,514Depletion and depreciation27,578Impairment1,840Balance, September 30, 201273,932Net Book ValueTotalDecember 31, 2011192,332September 30, 2012211,350During the three and nine months ended September 30, 2012, approximately $0.1 million (2011 - $0.1 million) and $0.2 million (2011 - $0.3 million), respectively, of directly attributable general and administrative costs were capitalized as expenditures on property, plant, and equipment.Depletion and depreciationThe calculation of depletion and depreciation expense for the three months ended September 30, 2012 included an estimated $174.3 million (2011 - $49.3 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $10.6 million (2011 - $7.7 million) for the estimated salvage value of production equipment and facilities. ImpairmentsAn impairment test was not performed at September 30, 2012 as there were no indicators of impairment. For the nine months ended September 30, 2012, the Company recorded property, plant, and equipment impairments of $1.8 million during the first quarter relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices. 6. CREDIT FACILITYAt September 30, 2012, the Company had a $100.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At September 30, 2012, $42.6 million (December 31, 2011 - $5.2 million) had been drawn on the revolving credit facility. In addition, at September 30, 2012, the Company had outstanding letters of guarantee of approximately $1.6 million (December 31, 2011 - $1.0 million) which reduce the amount that can be borrowed under the credit facility. The next review of the revolving credit facility by the bank is scheduled on or before December 1, 2012. 7. PROVISIONS - DECOMMISSIONING OBLIGATIONSThe Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and facilities, and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation at 2% per year) required to settle the decommissioning obligations is approximately $27.3 million which is estimated to be incurred between 2012 and 2041. At September 30, 2012, a risk-free rate of 2.2% (December 31, 2011 - 2.4%) was used to calculate the net present value of the decommissioning obligations. Nine Months EndedSeptember 30, 2012Balance, beginning of period19,250Provisions incurred578Provisions disposed-Provisions settled(621)Revisions712Accretion333Balance, end of period20,2528. SHARE BASED COMPENSATION PLANSStock optionsThe Company has authorized and reserved for issuance 8.8 million common shares under a stock option plan enabling certain officers, directors, employees, and consultants to purchase common shares. The Company will not issue options exceeding 10% of the shares outstanding at the time of the option grants. Under the plan, the exercise price of each option equals the market price of the Company's shares on the date of the grant. The options vest over a period of three years and an option's maximum term is 5 years. At September 30, 2012, 8.6 million options are outstanding at exercise prices ranging from $1.10 to $3.46 per share.The number and weighted average exercise price of stock options are as follows:Number ofWeighted AverageOptionsExercise Price ($)Balance, December 31, 20117,9421.97Granted7133.43Exercised(10)1.24Forfeited(41)2.51Balance, September 30, 20128,6042.09The following table summarizes the stock options outstanding and exercisable at September 30, 2012:Options OutstandingOptions ExercisableWeighted AverageWeighted AverageWeighted AverageExercise PriceNumberRemaining LifeExercise PriceNumberExercise Price$1.10 to $2.003,6452.11.242,9571.18$2.01 to $3.004,2643.52.591,4882.57$3.01 to $3.466954.43.46--8,6043.02.094,4451.65Share based compensationThe Company accounts for its share based compensation plans using the fair value method. Under this method, compensation cost is charged to earnings over the vesting period for stock options and warrants granted to officers, directors, employees, and consultants with a corresponding increase to contributed surplus. The fair value of the stock options granted was estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions: Nine Months EndedSeptember 30, 2012Risk-free interest rate (%)1.3Expected life (years)4.0Expected volatility (%)77.2Expected dividend yield (%)-Forfeiture rate (%)7.4Weighted average fair value of options granted ($ per option)1.96WarrantsAt September 30, 2012, 3.5 million warrants were outstanding at a weighted average exercise price of $3.64 per warrant. At the annual and special meeting of shareholders held on May 2, 2012, approval was obtained to extend the expiry date of 2.3 million warrants issued in 2007 priced between $3.75 and $6.75 to December 23, 2013. The resulting compensation cost charged to earnings in relation to the extension of the warrants was $0.2 million during the three months ended June 30, 2012. Subsequent to September 30, 2012, 1.2 million warrants were exercised at a price of $1.40 per warrant.9. PER SHARE AMOUNTSThe following table summarizes the weighted average number of shares used in the basic and diluted net loss per share calculations:Three Months EndedNine Months EndedSeptember 30, 2012September 30, 2012Weighted average number of shares - basic88,10388,097Dilutive effect of share based compensation plans2,4832,818Weighted average number of shares - diluted90,58690,91510. FINANCIAL INSTRUMENTSThe fair value of the risk management contracts at September 30, 2012 are measured using significant observable inputs, other than quoted market prices (level 2). There were no transfers between level 1, level 2, and level 3 classified assets and liabilities during the nine month period ended September 30, 2012.Risk management contracts are recorded on the statement of financial position at fair value each reporting period with the change in fair value being recorded as an unrealized gain or loss in earnings or loss. The estimated fair value of the financial contracts has been determined on the amounts that the Company would receive or pay to terminate the contracts. The fair value of risk management contracts is determined by discounting the difference between the contracted price and published forward curves as at the statement of financial position date, using the remaining contracted volumes.The Company has entered into the following commodity price contracts:CommodityPeriodType of ContractQuantity ContractedContract PriceOilMay 1, 2012 - September 30, 2012Financial - Swap800 bbls/dWTI US $104.38/bblNatural GasJuly 1, 2012 - December 31, 2012Financial - Swap5,000 GJ/dAECO CDN $2.400/GJNatural GasAugust 1, 2012 - October 31, 2012Financial - Swap5,000 GJ/dAECO CDN $2.300/GJNatural GasJanuary 1, 2013 - December 31, 2013Financial - Swap10,000 GJ/dAECO CDN $2.705/GJNatural GasJanuary 1, 2013 - December 31, 2013Financial - Call10,000 GJ/dAECO CDN $4.000/GJFor the three months ended September 30, 2012, the realized gain on the oil contract was $0.8 million and the realized gain on the gas contracts was $0.2 million. For the nine months ended September 30, 2012, the realized gain on the risk management contracts was $3.6 million, comprised of a gain of $3.4 million on the oil contract and $0.2 million on the gas contracts. During the second quarter, the Company settled a portion of the original oil contract for the period from October 1, 2012 through December 31, 2012 for cash proceeds of $1.7 million, which was included in the realized gain. The fair value of the risk management contracts at September 30, 2012 was allocated to current and non-current liabilities on a contract by contract basis.11. COMMITMENTSAs a result of the issuance of flow-through shares in December 2011, the Company is committed to expend $5.0 million on qualifying exploration expenditures prior to December 31, 2012. At September 30, 2012, the Company had fulfilled the flow-through share commitment.The Company has entered into a farm-in agreement to drill and complete one Edson Cardium well. Under the terms of the farm-in agreement, the Company is committed to spud the well prior to December 2012. The estimated cost to drill and complete the well is $3.5 million. The Company has also entered into fixed price financial contracts for future natural gas production as outlined in note 10.FOR FURTHER INFORMATION PLEASE CONTACT: Contact Information: Crocotta Energy Inc.Robert J. ZakreskyPresident & CEO(403) 538-3736Crocotta Energy Inc.Nolan ChicoineVP Finance & CFO(403) 538-3738Crocotta Energy Inc.Suite 700, 639 - 5th Avenue SWCalgary, Alberta T2P 0M9(403) 538-3737(403) 538-3735 (FAX)www.crocotta.ca