Crocotta Energy Inc.
TSX : CTA

Crocotta Energy Inc.

August 09, 2012 06:00 ET

Crocotta Energy Announces Q2 2012 Financial and Operating Results

CALGARY, ALBERTA--(Marketwire - Aug. 9, 2012) - CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the three and six months ended June 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.

HIGHLIGHTS
  • Increased production 119% to 6,604 boepd in Q2 2012 from 3,012 boepd in Q2 2011 despite an unscheduled plant disruption at Edson, AB that affected the quarter by 600 boepd
  • Increased funds from operations 77% to $12.3 million in Q2 2012 from $6.9 million in Q2 2011
  • Reduced production expenses 33% to $5.96/boe in Q2 2012 from $8.87/boe in Q2 2011
  • Increased bank credit facility to $100.0 million from $80.0 million
  • Commenced its 5 (2.7 net) horizontal Cardium drilling program
FINANCIAL RESULTS
Three Months Ended June 30 Six Months Ended June 30
($000s, except per share amounts) 2012 2011 % Change 2012 2011 % Change
Oil and natural gas sales 17,518 12,289 43 37,658 19,769 90
Funds from operations (1) 12,275 6,927 77 25,249 8,941 182
Per share - basic 0.14 0.09 56 0.29 0.12 142
Per share - diluted 0.14 0.08 75 0.28 0.11 155
Net earnings (loss) 1,065 374 185 772 (4,075 ) 119
Per share - basic and diluted 0.01 - 100 0.01 (0.05 ) 120
Capital expenditures 11,049 11,111 (1 ) 38,688 29,289 32
Property acquisitions - 1,000 (100 ) - 1,000 (100 )
Property dispositions - 4,387 (100 ) - 4,253 (100 )
Net debt (2) 41,525 18,416 125
Common shares outstanding (000s)
Weighted average - basic 88,095 80,874 9 88,095 76,260 16
Weighted average - diluted 90,234 82,644 9 91,000 77,922 17
End of period - basic 88,095 80,874 9
End of period - diluted 100,271 90,744 10
(1) Funds from operations and funds from operations per share do not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details and the Funds from Operations section in the MD&A for a reconciliation from cash flow from operating activities.
(2) Net debt includes current liabilities less current assets (excluding the risk management contracts). Net debt does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details.
OPERATING RESULTS Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Daily production
Oil and NGLs (bbls/d) 2,053 1,039 98 2,165 814 166
Natural gas (mcf/d) 27,309 11,843 131 27,081 10,988 146
Oil equivalent (boe/d) 6,604 3,012 119 6,678 2,645 152
Revenue
Oil and NGLs ($/bbl) 64.77 81.22 (20 ) 67.17 76.72 (12 )
Natural gas ($/mcf) 2.18 4.28 (49 ) 2.27 4.26 (47 )
Oil equivalent ($/boe) 29.15 44.83 (35 ) 30.98 41.29 (25 )
Royalties
Oil and NGLs ($/bbl) 8.72 17.11 (49 ) 8.97 18.06 (50 )
Natural gas ($/mcf) 0.20 0.05 300 0.14 0.15 (7 )
Oil equivalent ($/boe) 3.55 6.09 (42 ) 3.46 6.17 (44 )
Production expenses
Oil and NGLs ($/bbl) 5.39 8.09 (33 ) 5.09 8.93 (43 )
Natural gas ($/mcf) 1.04 1.55 (33 ) 0.97 1.59 (39 )
Oil equivalent ($/boe) 5.96 8.87 (33 ) 5.57 9.33 (40 )
Transportation expenses
Oil and NGLs ($/bbl) 0.87 0.89 (2 ) 1.00 0.88 14
Natural gas ($/mcf) 0.18 0.16 13 0.18 0.17 6
Oil equivalent ($/boe) 1.00 0.95 5 1.05 0.96 9
Operating netback(1)
Oil and NGLs ($/bbl) 49.79 55.13 (10 ) 52.11 48.85 7
Natural gas ($/mcf) 0.76 2.52 (70 ) 0.98 2.35 (58 )
Oil equivalent ($/boe) 18.64 28.92 (36 ) 20.90 24.83 (16 )
Depletion and depreciation ($/boe) (14.56 ) (15.35 ) (5 ) (14.73 ) (15.12 ) (3 )
Asset impairment ($/boe) (0.96 ) (0.67 ) 43 (2.70 ) (5.92 ) (54 )
General and administrative expenses ($/boe) (1.62 ) (3.30 ) (51 ) (1.69 ) (5.36 ) (68 )
Share based compensation ($/boe) (1.87 ) (2.62 ) (29 ) (1.71 ) (2.45 ) (30 )
Finance expenses ($/boe) (0.98 ) (1.20 ) (18 ) (0.72 ) (1.67 ) (57 )
Finance income ($/boe) - 0.44 (100 ) - 0.25 (100 )
Loss on sale of assets ($/boe) - (4.86 ) (100 ) - (3.06 ) (100 )
Deferred tax expense ($/boe) (1.77 ) - 100 (1.14 ) - 100
Realized gain on risk management contracts ($/boe) 4.22 - 100 2.09 - 100
Unrealized gain on risk management contracts ($/boe) 0.67 - 100 0.33 - 100
Net earnings (loss) ($/boe) 1.77 1.36 30 0.63 (8.50 ) 107
(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 UPDATE

In Q2 2012, Crocotta continued its cautious approach given lower pricing for both oil and gas and increased volatility and uncertainty in the markets. Crocotta spent less than cash flow in the quarter and is focused primarily on proving up additional lands to add to its drilling inventory.

Production

Production for Q2 2012 was reported at 6,604 boepd (69% gas; 31% light oil and natural gas liquids) despite having nine days of lost production (approximately 54,000 boes) during late June due to an unscheduled plant disruption at Edson. Production would have averaged over 7,200 boepd if the disruption had not occurred.

The disruption did cause some additional operating downtime in July but Crocotta is now operating close to full capability into the plant. In the event that there are no further interruptions, we anticipate Q3 production to be 7,200 to 7,400 boepd.

Current capability is over 8,000 boepd with additional Cardium wells currently being drilled and completed. As such, Crocotta reaffirms previous exit guidance at 8,500 boepd while maintaining debt at less than 1:1 debt to cash flow.

Capital Projects

Cardium

In Q2 2012, Crocotta started its summer drilling program with 1 (0.5 net) Cardium horizontal well at Edson. Wet weather has delayed progress in the 5 well (2.7 net) Cardium horizontal program, but as of early August, Crocotta has drilled one additional well (0.6 net) and is starting to drill the third well of the program. All wells on production to date have met or exceeded its type curve for the area.

The program, if successful, will add approximately 30 net unbooked locations to its drilling inventory and increase the prospectivity of its other Cardium lands in the area (over 30 net sections). Crocotta also plans to start drilling 100% working interest sections in Q4 2012 assuming continued success in the remainder of the summer drilling program.

Bluesky

In Q2 2012, Crocotta drilled 1 (1.0 net) Bluesky horizontal well. In Q3 2012, Crocotta will complete the Q2 2012 well and 1 (0.6 net) well that was drilled in Q1 2012. Crocotta has a large inventory (over 40 net locations) that has been largely proved up over the last two years.

Montney

Crocotta placed its Sunrise horizontal Montney well on production at a restricted rate of approximately 5 mmcf/d in Q2 2012. The well has exceeded its type curve for the area and Crocotta is working to put its Montney production into the Alliance Pipeline system and receive the benefit of some of the natural gas liquids it is currently not extracting.

Crocotta anticipates to have its plans finalized by late 2012 and drilling additional wells in Q4 2012 and/or Q1 2013.

Financial

Crocotta has maintained net debt at less than 1:1 ratio relative to cash flow and had over $58 million of undrawn credit as of the end of Q2 2012 ($41.5 million net debt compared to $100 million credit facility). Crocotta will continue to be conservative in its capital program that will focus primarily on proving up additional drilling inventory while evaluating various farm-in and acquisition opportunities that could enhance future shareholder value.

MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD&A")

August 7, 2012

The MD&A should be read in conjunction with the unaudited interim consolidated financial statements and related notes for the three and six months ended June 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).

DESCRIPTION OF BUSINESS

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 trades on the Toronto Stock Exchange under the symbol "CTA".

FREQUENTLY RECURRING TERMS

The 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 MEASURES

This 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".

Q2 2012 HIGHLIGHTS
  • Increased production 119% to 6,604 boepd in Q2 2012 from 3,012 boepd in Q2 2011 despite an unscheduled plant disruption at Edson, AB that affected the quarter by 600 boepd
  • Increased funds from operations 77% to $12.3 million in Q2 2012 from $6.9 million in Q2 2011
  • Reduced production expenses 33% to $5.96/boe in Q2 2012 from $8.87/boe in Q2 2011
  • Increased bank credit facility to $100.0 million from $80.0 million
  • Commenced its 5 (2.7 net) horizontal Cardium drilling program
SUMMARY OF FINANCIAL RESULTS
Three Months Ended June 30 Six Months Ended June 30
($000s, except per share amounts) 2012 2011 % Change 2012 2011 % Change
Oil and natural gas sales 17,518 12,289 43 37,658 19,769 90
Funds from operations 12,275 6,927 77 25,249 8,941 182
Per share - basic 0.14 0.09 56 0.29 0.12 142
Per share - diluted 0.14 0.08 75 0.28 0.11 155
Net earnings (loss) 1,065 374 185 772 (4,075 ) 119
Per share - basic and diluted 0.01 - 100 0.01 (0.05 ) 120
Total assets 255,954 198,140 29
Total long-term liabilities 21,181 14,322 48
Net debt 41,525 18,416 125
The 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.
PRODUCTION Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Average Daily Production
Oil and NGLs (bbls/d) 2,053 1,039 98 2,165 814 166
Natural gas (mcf/d) 27,309 11,843 131 27,081 10,988 146
Combined (boe/d) 6,604 3,012 119 6,678 2,645 152

Daily production for the three months ended June 30, 2012 increased 119% to 6,604 boe/d compared to 3,012 boe/d for the comparative period in 2011. Year-to-date, daily production increased 152% to 6,678 boe/d in 2012 compared to 2,645 boe/d in 2011. The significant increase in production was mainly due to successful drilling activity at Edson, AB during 2011 and the first half of 2012 which saw 20 gross (16.2 net) wells drilled at a 100% success rate. Compared to the previous quarter, daily production decreased marginally in Q2 2012 to 6,604 boe/d from 6,752 boe/d in Q1 2012 due to unexpected downtime at the third party gas plant that processes the Company's production at Edson, AB. The plant was down for nine days during June that accounted for lost production of approximately 54,000 boe (600 boe/d over the quarter). Had the plant downtime not occurred, average production for the second quarter would have been approximately 7,200 boe/d. The plant was back up by the end of the second quarter although full restoration of production was not achieved until late July.

Crocotta's production profile for the first half of 2012 was comprised of 68% natural gas and 32% oil and NGLs, consistent with the production profile for 2011, which was comprised of 68% natural gas and 32% oil and NGLs.

REVENUE Three Months Ended June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
Oil and NGLs 12,098 7,677 58 26,465 11,300 134
Natural gas 5,420 4,612 18 11,193 8,469 32
Total 17,518 12,289 43 37,658 19,769 90
Average Sales Price
Oil and NGLs ($/bbl) 64.77 81.22 (20 ) 67.17 76.72 (12 )
Natural gas ($/mcf) 2.18 4.28 (49 ) 2.27 4.26 (47 )
Combined ($/boe) 29.15 44.83 (35 ) 30.98 41.29 (25 )

Revenue totaled $17.5 million for the second quarter of 2012, up 43% from $12.3 million in the comparative period. For the six months ended June 30, 2012, revenue totaled $37.7 million, an increase of 90% from $19.8 million for the six months ended June 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 Pricing Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Oil and NGLs
Corporate price ($CDN/bbl) 64.77 81.22 (20 ) 67.17 76.72 (12 )
Edmonton par ($CDN/bbl) 84.39 102.63 (18 ) 88.54 95.57 (7 )
West Texas Intermediate ($US/bbl) 93.51 102.56 (9 ) 98.15 98.27 -
Natural gas
Corporate price ($CDN/mcf) 2.18 4.28 (49 ) 2.27 4.26 (47 )
AECO price ($CDN/mcf) 1.90 3.97 (52 ) 2.03 3.84 (47 )
Exchange rate
CDN/US dollar average exchange rate 0.9906 1.0365 (4 ) 0.9946 1.0254 (3 )

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 76.8% and 75.9% of Edmonton Par price for the three and six months ended June 30, 2012, down marginally from 79.1% and 80.3% for the comparative period in 2011. Corporate average natural gas prices were 114.7% and 111.8% of AECO prices for the three and six months ended June 30, 2012, up slightly from 107.8% and 110.9% 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:

Commodity Period Type of Contract Quantity Contracted Contract Price
Oil May 1, 2012 - September 30, 2012 Financial - Swap 800 bbls/d WTI US $104.38/bbl
Natural Gas July 1, 2012 - December 31, 2012 Financial - Swap 5,000 GJ/d AECO CDN $2.400/GJ
Natural Gas August 1, 2012 - October 31, 2012 Financial - Swap 5,000 GJ/d AECO CDN $2.300/GJ
Natural Gas January 1, 2013 - December 31, 2013 Financial - Swap 10,000 GJ/d AECO CDN $2.705/GJ
Natural Gas January 1, 2013 - December 31, 2013 Financial - Call 10,000 GJ/d AECO CDN $4.000/GJ

For the three months ended June 30, 2012, the realized gain on the oil contract was $2.5 million. 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. As a result of the settlement, the Company received cash proceeds of $1.7 million, which was included in the realized gain. The fair value of the risk management contracts at June 30, 2012 were allocated to current and non-current assets and liabilities on a contract by contract basis as summarized below:

Oil Natural Gas Total
Current asset (liability) 1,977 (803 ) 1,174
Non-current asset (liability) - (774 ) (774 )
Net asset (liability) 1,977 (1,577 ) 400
ROYALTIES Three Months Ended June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
Oil and NGLs 1,628 1,617 1 3,532 2,660 33
Natural gas 503 52 867 670 296 126
Total 2,131 1,669 28 4,202 2,956 42
Average Royalty Rate (% of sales)
Oil and NGLs 13.5 21.1 (36 ) 13.3 23.5 (43 )
Natural gas 9.3 1.1 745 6.0 3.5 71
Combined 12.2 13.6 (10 ) 11.2 15.0 (25 )

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 June 30, 2012, oil, NGLs, and natural gas royalties increased 28% to $2.1 million from $1.7 million in the comparative period. For the six months ended June 30, 2012, oil, NGLs, and natural gas royalties increased 42% to $4.2 million from $3.0 million in 2011. This increase stemmed from a significant increase in revenue in the first half of 2012 compared to the first half of 2011 mainly due to a significant increase in production. Of note, natural gas royalties increased to $0.5 million during the second quarter of 2012 compared to $0.2 million in the first quarter of 2012 due mainly to a prior period adjustment to the annual capital cost and processing fee deductions.

The overall effective royalty rate was 12.2% for the three months ended June 30, 2012 compared to 13.6% for the three months ended June 30, 2011. Year-to-date, the overall effective royalty rate was 11.2% in 2012 compared to 15.0% in 2011. The effective oil and NGLs royalty rate decreased significantly as a result of royalty incentive rates received on the successful Edson wells brought on production during the previous and current year. The effective natural gas royalty rate increased as a result of a prior period adjustment to the annual capital costs and processing fee deductions. The overall effective royalty rate for the second quarter of 2012 was up marginally from the first quarter of 2012 which had an overall rate of 10.3%.

PRODUCTION EXPENSES Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Oil and NGLs ($/bbl) 5.39 8.09 (33 ) 5.09 8.93 (43 )
Natural gas ($/mcf) 1.04 1.55 (33 ) 0.97 1.59 (39 )
Combined ($/boe) 5.96 8.87 (33 ) 5.57 9.33 (40 )

Per unit production expenses for the three and six months ended June 30, 2012 were $5.96/boe and $5.57/boe, respectively, down significantly from $8.87/boe and $9.33/boe for the comparative periods ended June 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 increased 15% to $5.96/boe in the second quarter of 2012 from $5.18/boe in the first quarter of 2012. The increase was mainly due to property taxes being incurred during the second quarter, which amounted to $0.63/boe for the three months ended June 30, 2012, combined with the nine day disruption at Edson, AB. The Company continues to focus on opportunities to maintain operational efficiencies to enhance operating netbacks.

TRANSPORTATION EXPENSES Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Oil and NGLs ($/bbl) 0.87 0.89 (2 ) 1.00 0.88 14
Natural gas ($/mcf) 0.18 0.16 13 0.18 0.17 6
Combined ($/boe) 1.00 0.95 5 1.05 0.96 9

Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended June 30, 2012 compared to the quarter ended June 30, 2011, transportation expenses increased 5% to $1.00/boe from $0.95/boe. Year-to-date, transportation expenses increased 9% to $1.05/boe in 2012 from $0.96/boe in 2011. The year-to-date increase in transportation expenses was due to an increase in oil and NGLs transportation expenses resulting from a prior period adjustment for NGL transportation costs. The costs were incurred as a result of restrictions at the third party Edson gas plant where the majority of the Company's production is processed. The restrictions resulted in the plant operator diverting volumes from the plant which resulted in additional unanticipated transportation costs.

OPERATING NETBACK Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Oil and NGLs ($/bbl)
Revenue 64.77 81.22 (20 ) 67.17 76.72 (12 )
Royalties 8.72 17.11 (49 ) 8.97 18.06 (50 )
Production expenses 5.39 8.09 (33 ) 5.09 8.93 (43 )
Transportation expenses 0.87 0.89 (2 ) 1.00 0.88 14
Operating netback 49.79 55.13 (10 ) 52.11 48.85 7
Natural gas ($/mcf)
Revenue 2.18 4.28 (49 ) 2.27 4.26 (47 )
Royalties 0.20 0.05 300 0.14 0.15 (7 )
Production expenses 1.04 1.55 (33 ) 0.97 1.59 (39 )
Transportation expenses 0.18 0.16 13 0.18 0.17 6
Operating netback 0.76 2.52 (70 ) 0.98 2.35 (58 )
Combined ($/boe)
Revenue 29.15 44.83 (35 ) 30.98 41.29 (25 )
Royalties 3.55 6.09 (42 ) 3.46 6.17 (44 )
Production expenses 5.96 8.87 (33 ) 5.57 9.33 (40 )
Transportation expenses 1.00 0.95 5 1.05 0.96 9
Operating netback 18.64 28.92 (36 ) 20.90 24.83 (16 )

During the second quarter of 2012, Crocotta generated an operating netback of $18.64/boe, down 36% from $28.92/boe for the second quarter of 2011. During the first half of 2012, Crocotta generated an operating netback of $20.90/boe compared to $24.83/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 royalties and production expenses. Operating netbacks in Q2 2012 were down from operating netbacks of $23.13/boe in Q1 2012 due mainly to a decline in oil, NGLs, and natural gas commodity prices.

The following is a reconciliation of operating netback per boe to net earnings (loss) per boe for the periods noted:

Three Months Ended June 30 Six Months Ended June 30
($/boe) 2012 2011 % Change 2012 2011 % Change
Operating netback 18.64 28.92 (36 ) 20.90 24.83 (16 )
Depletion and depreciation (14.56 ) (15.35 ) (5 ) (14.73 ) (15.12 ) (3 )
Asset impairment (0.96 ) (0.67 ) 43 (2.70 ) (5.92 ) (54 )
General and administrative expenses (1.62 ) (3.30 ) (51 ) (1.69 ) (5.36 ) (68 )
Share based compensation (1.87 ) (2.62 ) (29 ) (1.71 ) (2.45 ) (30 )
Finance expenses (0.98 ) (1.20 ) (18 ) (0.72 ) (1.67 ) (57 )
Finance income - 0.44 (100 ) - 0.25 (100 )
Loss on sale of assets - (4.86 ) (100 ) - (3.06 ) (100 )
Deferred tax expense (1.77 ) - 100 (1.14 ) - 100
Realized gain on risk management contracts 4.22 - 100 2.09 - 100
Unrealized gain on risk management contracts 0.67 - 100 0.33 - 100
Net earnings (loss) 1.77 1.36 30 0.63 (8.50 ) 107
DEPLETION AND DEPRECIATION Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Depletion and depreciation ($000s) 8,748 4,208 108 17,903 7,237 147
Depletion and depreciation ($/boe) 14.56 15.35 (5 ) 14.73 15.12 (3 )
Depletion and depreciation for the three and six months ended June 30, 2012 was $14.56/boe and $14.73/boe, respectively, consistent with depletion and depreciation of $15.35/boe and $15.12/boe for the comparative periods ended June 30, 2011. Depletion and depreciation for the second quarter of 2012 was also consistent with depletion and depreciation of $14.90/boe for the previous quarter ended March 31, 2012.
ASSET IMPAIRMENT Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Asset impairment ($000s) 579 185 213 3,284 2,834 16
Asset impairment ($/boe) 0.96 0.67 43 2.70 5.92 (54 )

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 six months ended June 30, 2012, total exploration and evaluation asset impairments of $1.4 million were recognized. Asset impairments of $0.4 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 $1.0 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB and Miscellaneous AB). For the comparative period ended June 30, 2011, total exploration and evaluation asset impairments of $2.8 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 $0.6 million were recognized relating to the expiry of undeveloped land rights (CGUs - Ferrier AB and Miscellaneous AB). For the three months ended June 30, 2012, asset impairments of $0.6 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB, Miscellaneous AB, and Saskatchewan). For the three months ended June 30, 2011, asset impairments of $0.2 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB and Miscellaneous AB).

For the six months ended June 30, 2012, the Company recorded property, plant, and equipment impairments of $1.8 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices during the first quarter. No property, plant, and equipment impairments were recorded for the three months ended June 30, 2012 and June 30, 2011.

GENERAL AND ADMINISTRATIVE Three Months Ended June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
G&A expenses (gross) 1,301 1,235 5 2,785 3,364 (17 )
G&A capitalized (69 ) (70 ) (1 ) (146 ) (178 ) (18 )
G&A recoveries (256 ) (259 ) (1 ) (585 ) (618 ) (5 )
G&A expenses (net) 976 906 8 2,054 2,568 (20 )
G&A expenses ($/boe) 1.62 3.30 (51 ) 1.69 5.36 (68 )
General and administrative expenses ("G&A") decreased significantly to $1.62/boe and $1.69/boe for the three and six months ended June 30, 2012, respectively, compared to $3.30/boe and $5.36/boe for the three and six months ended June 30, 2011. The decrease was mainly due to a significant increase in production and a reduction in various administrative costs.
SHARE BASED COMPENSATION Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Share based compensation ($000s) 1,123 717 57 2,083 1,174 77
Share based compensation ($/boe) 1.87 2.62 (29 ) 1.71 2.45 (30 )

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 $1.87/boe for the three months ended June 30, 2012 from $2.62/boe in the comparative period. Year-to-date, share based compensation expense decreased to $1.71/boe in 2012 from $2.45/boe in 2011. The decrease was a result of a significant increase in production in 2012 compared to 2011. During the first half of 2012, the Company granted 0.7 million options (2011 - 2.6 million).

FINANCE EXPENSES Three Months Ended June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
Interest expense 492 216 128 648 496 31
Accretion of decommissioning obligations 99 103 (4 ) 222 227 (2 )
Unrealized loss on investments - 9 (100 ) - 79 (100 )
Finance expenses 591 328 80 870 802 8
Finance expenses ($/boe) 0.98 1.20 (18 ) 0.72 1.67 (57 )
Interest expense relates to interest incurred on amounts drawn from the Company's credit facility. At June 30, 2012, $39.7 million (2011 - $13.7 million) had been drawn on the Company's credit facility.
FINANCE INCOME Three Months Ended June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
Finance income - 121 (100 ) - 121 (100 )
Finance income ($/boe) - 0.44 (100 ) - 0.25 (100 )
LOSS ON SALE OF ASSETS Three Months Ended June 30 Six Months Ended June 30
2012 2011 % Change 2012 2011 % Change
Loss on sale of assets ($000s) - 1,331 (100 ) - 1,465 (100 )
Loss on sale of assets ($/boe) - 4.86 (100 ) - 3.06 (100 )

During the first half of 2011, the Company recognized a loss on sale of assets of $1.5 million relating mainly to the disposition of certain non-core oil and natural gas assets.

DEFERRED INCOME TAXES

Deferred income tax expense on the earnings before taxes for the three and six months ended June 30, 2012 were $1.1 million and $1.4 million, respectively (2011 - $nil). This was larger than expected by applying the statutory tax rate to the earnings before taxes due to non-deductible items such as share based compensation as well as renouncing flow-through shares.

Estimated tax pools at June 30, 2012 total approximately $261.1 million.

FUNDS FROM OPERATIONS

Funds from operations for the three and six months ended June 30, 2012 were $12.3 million ($0.14 per diluted share) and $25.2 million ($0.28 per diluted share), respectively, compared to $6.9 million ($0.08 per diluted share) and $8.9 million ($0.11 per diluted share) for the three and six months ended June 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 six months ended June 30, 2012 was $2.5 million 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 June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
Cash flow from operating activities (GAAP) 13,178 5,087 159 25,667 7,430 245
Add back:
Decommissioning expenditures 163 - 100 350 - 100
Change in non-cash working capital (1,066 ) 1,840 (158 ) (768 ) 1,511 (151 )
Funds from operations (non-GAAP) 12,275 6,927 77 25,249 8,941 182

NET EARNINGS (LOSS)

The Company had net earnings of $1.1 million ($0.01 per diluted share) for the three months ended June 30, 2012 compared to net earnings of $0.4 million ($nil per diluted share) for the three months ended June 30, 2011. Year-to-date, the Company had net earnings of $0.8 million ($0.01 per diluted share) in 2012 compared to a net loss of $4.1 million ($0.05 per diluted share) in 2011. Net earnings for the three and six months ended June 30, 2012 arose mainly due to a significant increase in production which led to an increase in revenue combined with realized and unrealized gains on risk management contracts.

CAPITAL EXPENDITURES Three Months Ended June 30 Six Months Ended June 30
($000s) 2012 2011 % Change 2012 2011 % Change
Land 1,430 414 245 3,080 917 236
Drilling, completions, and workovers 8,495 8,972 (5 ) 28,038 22,454 25
Equipment 826 1,427 (42 ) 7,152 5,285 35
Geological and geophysical 298 274 9 418 609 (31 )
Other - 24 (100 ) - 24 (100 )
Exploration and development 11,049 11,111 (1 ) 38,688 29,289 32
Property acquisitions - 1,000 (100 ) - 1,000 (100 )
Property dispositions - (4,387 ) (100 ) - (4,253 ) (100 )
Net property dispositions - (3,387 ) (100 ) - (3,253 ) (100 )
Net capital expenditures 11,049 7,724 43 38,688 26,036 49

For the three months ended June 30, 2012, the Company had net capital expenditures of $11.0 million compared to net capital expenditures of $7.7 million for the three months ended June 30, 2011. For the six months ended June 30, 2012, the Company had net capital expenditures of $38.7 million compared to $26.0 million for the comparative period in 2011. The increase in exploration and development expenditures in the first half of 2012 was due mainly to an increase in capital activity in the Company's core areas of Edson, AB and northeast BC. During the first six months of 2012, the Company drilled a total of 8 (6.5 net) wells, which resulted in 2.0 (0.9 net) oil wells, 2 (2.0 net) liquids-rich natural gas wells, and 4 (3.6 net) wells that will be completed in the second half of 2012.

LIQUIDITY AND CAPITAL RESOURCES

The Company had net debt of $41.5 million at June 30, 2012 compared to net debt of $27.7 million at December 31, 2011. The increase of $13.8 million was mainly due to $38.7 million used for the purchase and development of oil and natural gas properties and equipment and $0.4 million for decommissioning expenditures, offset by funds from operations of $25.2 million.

At June 30, 2012, the Company had total credit facilities of $100.0 million, consisting of 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 June 30, 2012, $39.7 million (December 31, 2011 - $5.2 million) had been drawn on the revolving credit facility. In addition, at June 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 September 30, 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 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 OBLIGATIONS
The following is a summary of the Company's contractual obligations and commitments at June 30, 2012:
Less than One to After
($000s) Total One Year Three Years Three Years
Accounts payable and accrued liabilities 12,454 12,454 - -
Revolving credit facility 39,678 39,678 - -
Decommissioning obligations 20,180 36 81 20,063
Office leases 1,136 529 607 -
Field equipment leases 2,558 1,470 1,088 -
Drilling rig 245 245 - -
Firm transportation agreements 512 293 193 26
Capital processing agreements 200 - - 200
Total contractual obligations 76,963 54,705 1,969 20,289

In addition to the above commitments, as a result of the issuance of flow-through shares in December 2011, the Company is committed to expend $5.0 million on qualifying exploration expenditures prior to December 31, 2012. As at June 30, 2012, the Company had incurred $3.6 million in connection with this flow-through share commitment.

The Company has entered into farm-in agreements to drill and complete three Edson Bluesky wells and four Edson Cardium wells. Under the terms of the farm-in agreements, the Company is committed to drill the wells at dates all prior to the end of Q3 2012. The estimated cost to drill and complete the wells in total is $15.0 million.

The Company has also entered into fixed price financial contracts for future oil and natural gas production as outlined above (see "Revenue" section).

OUTSTANDING SHARE DATA

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. 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) June 30, 2012 August 7, 2012
Voting common shares 88,095 88,095
Stock options 8,655 8,604
Warrants 3,521 3,521
Total 100,271 100,220
SUMMARY OF QUARTERLY RESULTS (1)
Q2 2012 Q1 2012 Q4 2011 Q3 2011 Q2 2011 Q1 2011 Q4 2010 Q3 2010
Average Daily Production
Oil and NGLs (bbls/d) 2,053 2,277 1,879 1,336 1,039 586 647 862
Natural gas (mcf/d) 27,309 26,852 23,354 15,996 11,843 10,124 9,958 10,530
Combined (boe/d) 6,604 6,752 5,771 4,002 3,012 2,274 2,307 2,617
($000s, except per share amounts)
Oil and natural gas sales 17,518 20,140 20,391 14,814 12,289 7,480 7,274 8,574
Funds from operations 12,275 12,974 12,115 9,551 6,927 2,014 4,200 3,477
Per share - basic 0.14 0.15 0.15 0.12 0.09 0.03 0.06 0.05
Per share - diluted 0.14 0.14 0.14 0.11 0.08 0.03 0.06 0.05
Net earnings (loss) 1,065 (293 ) (7,052 ) 5,535 374 (4,449 ) 656 (2,071 )
Per share - basic and diluted 0.01 - (0.09 ) 0.07 - (0.06 ) 0.01 (0.03 )
(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 an increase in funds from operations in Q2 2011 through Q2 2012 compared to prior quarters. The Company had a net loss in Q1 2012 and Q4 2011 mainly as a result of asset impairments recognized in each quarter.

OPERATIONS UPDATE

In Q2 2012, Crocotta continued its cautious approach given lower pricing for both oil and gas and increased volatility and uncertainty in the markets. Crocotta spent less than cash flow in the quarter and is focused primarily on proving up additional lands to add to its drilling inventory.

Production

Production for Q2 2012 was reported at 6,604 boepd (69% gas; 31% light oil and natural gas liquids) despite having nine days of lost production (approximately 54,000 boes) during late June due to an unscheduled plant disruption at Edson. Production would have averaged over 7,200 boepd if the disruption had not occurred.

The disruption did cause some additional operating downtime in July but Crocotta is now operating close to full capability into the plant. In the event that there are no further interruptions, we anticipate Q3 production to be 7,200 to 7,400 boepd.

Current capability is over 8,000 boepd with additional Cardium wells currently being drilled and completed. As such, Crocotta reaffirms previous exit guidance at 8,500 boepd while maintaining debt at less than 1:1 debt to cash flow.

Capital Projects

Cardium

In Q2 2012, Crocotta started its summer drilling program with 1 (0.5 net) Cardium horizontal well at Edson. Wet weather has delayed progress in the 5 well (2.7 net) Cardium horizontal program, but as of early August, Crocotta has drilled one additional well (0.6 net) and is starting to drill the third well of the program. All wells on production to date have met or exceeded its type curve for the area.

The program, if successful, will add approximately 30 net unbooked locations to its drilling inventory and increase the prospectivity of its other Cardium lands in the area (over 30 net sections). Crocotta also plans to start drilling 100% working interest sections in Q4 2012 assuming continued success in the remainder of the summer drilling program.

Bluesky

In Q2 2012, Crocotta drilled 1 (1.0 net) Bluesky horizontal well. In Q3 2012, Crocotta will complete the Q2 2012 well and 1 (0.6 net) well that was drilled in Q1 2012. Crocotta has a large inventory (over 40 net locations) that has been largely proved up over the last two years.

Montney

Crocotta placed its Sunrise horizontal Montney well on production at a restricted rate of approximately 5 mmcf/d in Q2 2012. The well has exceeded its type curve for the area and Crocotta is working to put its Montney production into the Alliance Pipeline system and receive the benefit of some of the natural gas liquids it is currently not extracting.

Crocotta anticipates to have its plans finalized by late 2012 and drilling additional wells in Q4 2012 and/or Q1 2013.

Financial

Crocotta has maintained net debt at less than 1:1 ratio relative to cash flow and had over $58 million of undrawn credit as of the end of Q2 2012 ($41.5 million net debt compared to $100 million credit facility). Crocotta will continue to be conservative in its capital program that will focus primarily on proving up additional drilling inventory while evaluating various farm-in and acquisition opportunities that could enhance future shareholder value.

CRITICAL ACCOUNTING ESTIMATES

Management 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 POLICIES

In 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 ASSESSMENT

The 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 replacement

The 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 risks

Crocotta'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 risk

Market 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:

Commodity Period Type of Contract Quantity Contracted Contract Price
Oil May 1, 2012 - September 30, 2012 Financial - Swap 800 bbls/d WTI US $104.38/bbl
Natural Gas July 1, 2012 - December 31, 2012 Financial - Swap 5,000 GJ/d AECO CDN $2.400/GJ
Natural Gas August 1, 2012 - October 31, 2012 Financial - Swap 5,000 GJ/d AECO CDN $2.300/GJ
Natural Gas January 1, 2013 - December 31, 2013 Financial - Swap 10,000 GJ/d AECO CDN $2.705/GJ
Natural Gas January 1, 2013 - December 31, 2013 Financial - Call 10,000 GJ/d AECO CDN $4.000/GJ

Safety and Environmental Risks

The 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 REPORTING

The 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 INFORMATION

This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "may", "will", "should", "believe", "intends", "forecast", "plans", "guidance" and similar expressions are intended to identify forward-looking statements or information.

More particularly and without limitation, this MD&A contains forward looking statements and information relating to the Company's risk management program, oil, NGLs, and natural gas production, capital programs, oil, NGLs, and natural gas commodity prices, and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services.

Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company's expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

ADDITIONAL INFORMATION

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.

Crocotta Energy Inc.
Condensed Consolidated Statements of Financial Position
(unaudited)
June 30 December 31
($000s) Note 2012 2011
Assets
Current assets
Accounts receivable 9,743 11,298
Prepaid expenses and deposits 864 840
Risk management contracts (10 ) 1,174 -
11,781 12,138
Property, plant, and equipment (5 ) 203,298 192,332
Exploration and evaluation assets (4 ) 28,403 20,641
Deferred income taxes 12,472 14,443
255,954 239,554
Liabilities
Current liabilities
Accounts payable and accrued liabilities 12,454 34,692
Revolving credit facility (6 ) 39,678 5,182
52,132 39,874
Flow-through share premium 227 813
Decommissioning obligations (7 ) 20,180 19,250
Risk management contracts (10 ) 774 -
73,313 59,937
Shareholders' Equity
Shareholders' capital 225,848 225,848
Contributed surplus 11,179 8,927
Deficit (54,386 ) (55,158 )
182,641 179,617
255,954 239,554
The 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 June 30 Six Months Ended June 30
($000s, except per share amounts) Note 2012 2011 2012 2011
Revenue
Oil and natual gas sales 17,518 12,289 37,658 19,769
Royalties (2,131 ) (1,669 ) (4,202 ) (2,956 )
15,387 10,620 33,456 16,813
Realized gain on risk management contracts (10 ) 2,536 - 2,536 -
Unrealized gain on risk management contracts (10 ) 400 - 400 -
18,323 10,620 36,392 16,813
Expenses
Production 3,579 2,432 6,765 4,469
Transportation 601 260 1,276 460
Depletion and depreciation (5 ) 8,748 4,208 17,903 7,237
Asset impairment (4,5 ) 579 185 3,284 2,834
General and administrative 976 906 2,054 2,568
Share based compensation (8 ) 1,123 717 2,083 1,174
15,606 8,708 33,365 18,742
Operating earnings (loss) 2,717 1,912 3,027 (1,929 )
Other Expenses
Finance expense 591 328 870 802
Finance income - (121 ) - (121 )
Loss on sale of assets - 1,331 - 1,465
591 1,538 870 2,146
Earnings (loss) before taxes 2,126 374 2,157 (4,075 )
Taxes
Deferred income tax expense 1,061 - 1,385 -
Net earnings (loss) and comprehensive earnings (loss) 1,065 374 772 (4,075 )
Net earnings (loss) per share
Basic and diluted 0.01 - 0.01 (0.05 )
The accompanying notes are an integral part of these condensed interim consolidated financial statements.
Crocotta Energy Inc.
Condensed Consolidated Statements of Shareholders' Equity
(unaudited)
Six Months Ended June 30
($000s) 2012 2011
Shareholders' Capital
Balance, beginning of period 225,848 168,164
Issue of shares (net of share issue costs and flow-through share premium) - 33,844
Issued on exercise of stock options - 114
Share based compensation - exercised - 79
Balance, end of period 225,848 202,201
Contributed Surplus
Balance, beginning of period 8,927 5,515
Share based compensation - expensed 2,083 1,174
Share based compensation - capitalized 169 91
Share based compensation - exercised - (79 )
Balance, end of period 11,179 6,701
Deficit
Balance, beginning of period (55,158 ) (49,566 )
Net earnings (loss) 772 (4,075 )
Balance, end of period (54,386 ) (53,641 )
Total Shareholders' Equity 182,641 155,261
The 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 June 30 Six Months Ended June 30
($000s) Note 2012 2011 2012 2011
Operating Activities
Net earnings (loss) 1,065 374 772 (4,075 )
Depletion and depreciation (5 ) 8,748 4,208 17,903 7,237
Asset impairment (4,5 ) 579 185 3,284 2,834
Share based compensation (8 ) 1,123 717 2,083 1,174
Finance expense 591 328 870 802
Interest paid (492 ) (216 ) (648 ) (496 )
Loss on sale of assets - 1,331 - 1,465
Deferred income tax expense 1,061 - 1,385 -
Unrealized gain on risk management contracts (10 ) (400 ) - (400 ) -
Decommissioning expenditures (7 ) (163 ) - (350 ) -
Change in non-cash working capital 1,066 (1,840 ) 768 (1,511 )
13,178 5,087 25,667 7,430
Financing Activities
Revolving credit facility (6 ) 5,615 2,553 34,496 (21,669 )
Issuance of shares - - - 36,074
Share issue costs - - - (2,116 )
5,615 2,553 34,496 12,289
Investing Activities
Capital expenditures - property, plant, and equipment (5 ) (4,934 ) (11,313 ) (29,482 ) (28,338 )
Capital expenditures - exploration and evaluation assets (4 ) (6,115 ) (798 ) (9,206 ) (1,951 )
Asset dispositions - 4,387 - 4,253
Change in non-cash working capital (7,744 ) 84 (21,475 ) 6,317
(18,793 ) (7,640 ) (60,163 ) (19,719 )
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 Statements

Three and Six Months Ended June 30, 2012

(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 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 compliance

These 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 August 7, 2012.

(b) Basis of measurement

The 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 currency

The condensed interim consolidated financial statements are presented in Canadian dollars, which is the Company's functional currency.

(d) Use of estimates and judgments

The 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 POLICIES

The 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 ASSETS

Total
Balance, December 31, 2011 20,641
Additions 9,206
Impairment (1,444 )
Balance, June 30, 2012 28,403

Exploration 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 $9.2 million of additions during the six months ended June 30, 2012 were additions of $2.8 million related to the Edson AB CGU and $5.9 million related to the Miscellaneous AB CGU.

Impairments

Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the six months ended June 30, 2012, total exploration and evaluation asset impairments of $1.4 million were recognized. Asset impairments of $0.4 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 $1.0 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB and Miscellaneous AB).

5. PROPERTY, PLANT, AND EQUIPMENT
Cost Total
Balance, December 31, 2011 236,846
Additions 29,482
Change in decommissioning obligation estimates 1,058
Capitalized share based compensation 169
Balance, June 30, 2012 267,555
Accumulated Depletion, Depreciation, and Impairment Total
Balance, December 31, 2011 44,514
Depletion and depreciation 17,903
Impairment 1,840
Balance, June 30, 2012 64,257
Net Book Value Total
December 31, 2011 192,332
June 30, 2012 203,298

During the three and six months ended June 30, 2012, approximately $0.1 million (2011 - $0.1 million) and $0.1 million (2011 - $0.2 million), respectively, of directly attributable general and administrative costs were capitalized as expenditures on property, plant, and equipment.

Depletion and depreciation

The calculation of depletion and depreciation expense for the three months ended June 30, 2012 included an estimated $177.4 million (2011 - $60.8 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $9.0 million (2011 - $7.8 million) for the estimated salvage value of production equipment and facilities.

Impairments

An impairment test was not performed at June 30, 2012 as there were no indicators of impairment. For the six months ended June 30, 2012, the Company recorded property, plant, and equipment impairments of $1.8 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices during the first quarter.

6. CREDIT FACILITIES

At June 30, 2012, the Company had total credit facilities of $100.0 million, consisting of 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 June 30, 2012, $39.7 million (December 31, 2011 - $5.2 million) had been drawn on the revolving credit facility. In addition, at June 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 September 30, 2012.

7. 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 $27.6 million which is estimated to be incurred between 2012 and 2041. At June 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.

Six Months Ended
June 30, 2012
Balance, beginning of period 19,250
Provisions incurred 402
Provisions disposed -
Provisions settled (350 )
Revisions 656
Accretion 222
Balance, end of period 20,180

8. SHARE BASED COMPENSATION PLANS

Stock options

The 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 June 30, 2012, 8.7 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 of
Options

Weighted Average
Exercise Price ($

)
Balance, December 31, 2011 7,942 1.97
Granted 713 3.43
Balance, June 30, 2012 8,655 2.09
Exercisable at June 30, 2012 3,314 1.54
The following table summarizes the stock options outstanding and exercisable at June 30, 2012:
Options Outstanding Options Exercisable
Exercise Price
Number
Weighted Average
Remaining Life
Weighted Average
Exercise Price

Number
Weighted Average
Exercise Price
$1.10 to $2.00 3,660 2.4 1.24 2,346 1.21
$2.01 to $3.00 4,297 3.7 2.59 968 2.34
$3.01 to $3.46 698 4.6 3.46 - -
8,655 3.2 2.09 3,314 1.54

Share based compensation

The Company accounts for its share based compensation plans using the fair value method. Under this method, compensation cost is charged to earnings over the vesting period for stock options and warrants granted to officers, directors, employees, and consultants with a corresponding increase to contributed surplus.

The fair value of the stock options granted were estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions:

Three Months Ended Six Months Ended
June 30, 2012 June 30, 2012
Risk-free interest rate (%) 1.1 1.3
Expected life (years) 4.0 4.0
Expected volatility (%) 77.5 77.2
Expected dividend yield (%) - -
Forfeiture rate (%) 6.8 7.4
Weighted average fair value of options granted ($ per option) 1.13 1.96

Warrants

At June 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.

The fair value of each warrant extended during the period was estimated using the Black-Scholes-Merton option pricing model with the following weighted average assumptions:

Three Months Ended Six Months Ended
June 30, 2012 June 30, 2012
Risk-free interest rate (%) 1.3 1.3
Expected life (years) 1.0 1.0
Expected volatility (%) 54.4 54.4
Expected dividend yield (%) - -
Forfeiture rate (%) - -
Weighted average fair value of warrants extended ($ per warrant) 0.09 0.09
9. PER SHARE AMOUNTS
The following table summarizes the weighted average number of shares used in the basic and diluted net loss per share calculations:
Three Months Ended Six Months Ended
June 30, 2012 June 30, 2012
Weighted average number of shares - basic 88,095 88,095
Dilutive effect of share based compensation plans 2,139 2,905
Weighted average number of shares - diluted 90,234 91,000

10. FINANCIAL INSTRUMENTS

The fair value of the risk management contracts at June 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 six months period ended June 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:
Commodity Period Type of Contract Quantity Contracted Contract Price
Oil May 1, 2012 - September 30, 2012 Financial - Swap 800 bbls/d WTI US $104.38/bbl
Natural Gas July 1, 2012 - December 31, 2012 Financial - Swap 5,000 GJ/d AECO CDN $2.400/GJ
Natural Gas August 1, 2012 - October 31, 2012 Financial - Swap 5,000 GJ/d AECO CDN $2.300/GJ
Natural Gas January 1, 2013 - December 31, 2013 Financial - Swap 10,000 GJ/d AECO CDN $2.705/GJ
Natural Gas January 1, 2013 - December 31, 2013 Financial - Call 10,000 GJ/d AECO CDN $4.000/GJ

For the three months ended June 30, 2012, the realized gain on the oil contract was $2.5 million. 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. As a result of the settlement, the Company received cash proceeds of $1.7 million, which was included in the realized gain. The fair value of the risk management contracts at June 30, 2012 were allocated to current and non-current assets and liabilities on a contract by contract basis as summarized below:

Oil Natural Gas Total
Current asset (liability) 1,977 (803 ) 1,174
Non-current asset (liability) - (774 ) (774 )
Total asset (liability) 1,977 (1,577 ) 400

11. COMMITMENTS

As a result of the issuance of flow-through shares in December 2011, the Company is committed to expend $5.0 million on qualifying exploration expenditures prior to December 31, 2012. As at June 30, 2012, the Company had incurred $3.6 million in connection with this flow-through share commitment.

The Company has entered into farm-in agreements to drill and complete three Edson Bluesky wells and four Edson Cardium wells. Under the terms of the farm-in agreements, the Company is committed to drill the wells at dates all prior to the end of Q3 2012. The estimated cost to drill and complete the wells is $15.0 million.

The Company has also entered into fixed price financial contracts for future oil and natural gas production as outlined in note 10.

CORPORATE INFORMATION
OFFICERS AND DIRECTORS
Robert J. Zakresky, CA
President, CEO & Director
BANK
National Bank of Canada
1800, 311 - 6th Avenue SW
Nolan Chicoine, MPAcc, CA
VP Finance & CFO
Calgary, Alberta T2P 3H2
Terry L. Trudeau, P.Eng.
VP Operations & COO

TRANSFER AGENT
Valiant Trust Company
Weldon Dueck, BSc., P.Eng.
VP Business Development
310, 606 - 4th Street SW
Calgary, Alberta T2P 1T1
R.D. (Rick) Sereda, M.Sc., P.Geol.
VP Exploration
LEGAL COUNSEL
Helmut R. Eckert, P.Land
VP Land
Gowling Lafleur Henderson LLP
1400, 700 - 2nd Street SW
Calgary, Alberta T2P 4V5
Kevin Keith
VP Production
Larry G. Moeller, CA, CBV
Chairman of the Board
AUDITORS
KPMG LLP
2700, 205 - 5th Avenue SW
Daryl H. Gilbert, P.Eng.
Director
Calgary, Alberta T2P 4B9
Don Cowie
Director

INDEPENDENT ENGINEERS
GLJ Petroleum Consultants Ltd.
Brian Krausert
Director
4100, 400 - 3rd Avenue SW
Calgary, Alberta T2P 4H2
Gary W. Burns
Director
Don D. Copeland, P.Eng.
Director
Brian Boulanger
Director
Patricia Phillips
Director

Contact Information

  • Crocotta Energy Inc.
    Robert J. Zakresky
    President & CEO
    (403) 538-3736

    Crocotta Energy Inc.
    Nolan Chicoine
    VP Finance & CFO
    (403) 538-3738

    Crocotta Energy Inc.
    Suite 700, 639 - 5th Avenue SW
    Calgary, Alberta T2P 0M9
    (403) 538-3737
    (403) 538-3735 (FAX)
    www.crocotta.ca