Crocotta Energy Inc.: Q2 2013 Financial and Operating Results

August 13, 2013 6:17 AM

CALGARY, ALBERTA–(Marketwired – Aug. 13, 2013) – CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the three and six months ended June 30, 2013, including condensed interim consolidated financial statements, notes to the condensed interim consolidated financial statements, and Management’s Discussion and Analysis. All dollar figures are Canadian dollars unless otherwise noted.

HIGHLIGHTS

Entered into rich gas premium agreements which are anticipated to increase net revenues and reduce costs
Drilled Cardium step-out wells and acquired additional lands to increase Cardium horizontal inventory to 71 gross (50 net) from 30 net at year-end
Increased funds from operations 16% to $14.3 million in Q2 2013 from $12.3 million in Q2 2012
Raised gross proceeds of $22.0 million through the issuance of 6.0 million common shares on a flow-through basis
Subsequent to Q2 2013, entered into a $145 million syndicated credit facility

FINANCIAL RESULTS
		Three Months Ended June 30			Six Months Ended June 30
($000s, except per share amounts)		2013	2012	% Change	2013	2012	% Change

Oil and natural gas sales		25,152	17,518	44	53,419	37,658	42
Funds from operations ⁽¹⁾		14,280	12,275	16	31,404	25,249	24
	Per share – basic	0.16	0.14	14	0.35	0.29	21
	Per share – diluted	0.15	0.14	7	0.34	0.28	21

Net earnings		3,604	1,065	238	6,208	772	704
	Per share – basic and diluted	0.04	0.01	300	0.07	0.01	600

Capital expenditures		14,182	11,049	28	45,700	38,688	18

Net debt ⁽²⁾					73,473	41,525	77

Common shares outstanding (000s)
	Weighted average – basic	90,549	88,095	3	89,909	88,095	2
	Weighted average – diluted	93,299	90,234	3	92,451	91,000	2

	End of period – basic				95,448	88,095	8
	End of period – diluted				106,276	100,271	6


(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 (including the revolving credit facility and excluding risk management contracts) less current assets. 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
		2013		2012		% Change		2013		2012		% Change

Daily production
	Oil and NGLs (bbls/d)	2,158		2,053		5		2,423		2,165		12
	Natural gas (mcf/d)	36,412		27,309		33		36,639		27,081		35
	Oil equivalent (boe/d)	8,227		6,604		25		8,529		6,678		28

Revenue
	Oil and NGLs ($/bbl)	63.16		64.77		(2	)	65.76		67.17		(2	)
	Natural gas ($/mcf)	3.85		2.18		77		3.71		2.27		63
	Oil equivalent ($/boe)	33.60		29.15		15		34.60		30.98		12

Royalties
	Oil and NGLs ($/bbl)	8.51		8.72		(2	)	8.87		8.97		(1	)
	Natural gas ($/mcf)	0.03		0.20		(85	)	0.12		0.14		(14	)
	Oil equivalent ($/boe)	2.35		3.55		(34	)	3.04		3.46		(12	)

Production expenses
	Oil and NGLs ($/bbl)	6.62		5.39		23		5.86		5.09		15
	Natural gas ($/mcf)	1.18		1.04		13		1.14		0.97		18
	Oil equivalent ($/boe)	6.97		5.96		17		6.54		5.57		17

Transportation expenses
	Oil and NGLs ($/bbl)	1.23		0.87		41		1.05		1.00		5
	Natural gas ($/mcf)	0.10		0.18		(44	)	0.10		0.18		(44	)
	Oil equivalent ($/boe)	0.76		1.00		(24	)	0.74		1.05		(30	)

Operating netback ⁽¹⁾
	Oil and NGLs ($/bbl)	46.80		49.79		(6	)	49.98		52.11		(4	)
	Natural gas ($/mcf)	2.54		0.76		234		2.35		0.98		140
	Oil equivalent ($/boe)	23.52		18.64		26		24.28		20.90		16

Depletion and depreciation ($/boe)		(13.74	)	(14.56	)	(6	)	(13.59	)	(14.73	)	(8	)
Asset impairment ($/boe)		(0.17	)	(0.96	)	(82	)	(0.21	)	(2.70	)	(92	)
General and administrative expenses ($/boe)		(2.18	)	(1.62	)	35		(2.05	)	(1.69	)	21
Share based compensation ($/boe)		(0.60	)	(1.87	)	(68	)	(0.62	)	(1.71	)	(64	)
Finance expenses ($/boe)		(1.26	)	(0.98	)	29		(1.19	)	(0.72	)	65
Deferred tax expense ($/boe)		(2.56	)	(1.77	)	45		(1.92	)	(1.14	)	68
Realized gain (loss) on risk management contracts ($/boe)		(1.20	)	4.22		(128	)	(0.88	)	2.09		(142	)
Unrealized gain on risk management contracts ($/boe)		3.01		0.67		349		0.20		0.33		(39	)
Net earnings ($/boe)		4.82		1.77		172		4.02		0.63		538


(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 2013, Crocotta focused its efforts on completing its rich-gas premium agreements with Aux Sable and interconnection agreement with Alliance to provide access to premium liquids markets in the United States. There were a number of benefits which included superior pricing and reduced downtime. As of June 1^st, the Edson plant was fully operational and Crocotta started delivery of its liquids- rich Edson gas into the Alliance pipeline. Since start-up, Crocotta has not experienced any production disruptions or downtime on the Edson volumes producing through the facility.

The wet weather in late May and early June contributed to delays in getting two new wells on production as well as pushing back the start of the summer drilling program into late June. Since the end of Q2 2013, Crocotta has added a second rig at Edson and is on schedule to meet its production exit target of 10,500 boepd.

Operating costs at Edson continued to be very competitive ($5.50/boe) while Dawson/Sunrise remained very high ($11.00/boe) due to third party processing and throughput charges. Crocotta anticipates the Dawson/Sunrise costs to reduce to approximately $6.00/boe once the newly constructed plant is operational in late August.

Further area specific data is outlined below:

Edson, Alberta

Crocotta has been very active in the Cardium formation where it has signed various farm-in agreements and purchased lands in the immediate vicinity. A significant step-out well was drilled as part of a farm-in that has added approximately 12 gross (8.0 net) locations to inventory and 2.5 net sections were purchased that added 11 (8.2 net) Cardium locations. This increases Crocotta’s undrilled Cardium inventory to 50 net locations as at the end of Q2 2013.

We currently have two rigs drilling in the Cardium at Edson and anticipate having 8 gross (6.8 net) wells drilled in Q3 2013.

In the Bluesky, we have 1 (0.6 net) wells scheduled to be drilled and on-stream in Q3 2013.

Dawson/Sunrise, NEBC

Crocotta’s operations for Q3 2013 include completion of a gas plant, delivery of liquids-rich gas into the Alliance system, and drilling three 100% working interest wells. The wells include two wells into the upper Montney and one exploratory well into the lower Montney. If successful, the three wells will help prove up between 80 and 100 locations in the upper and lower Montney. The Dawson/Sunrise property has many valuable qualities including high liquids content, good accessibility to drill, and Crocotta-owned facilities.

Exploration Initiatives

Crocotta is drilling two oil exploration properties in 2013. In the Stoddart area of northeast British Columbia, one horizontal well has been drilled and is waiting on completion. In the Red Earth area of Alberta, Crocotta is planning one vertical oil test well in late Q4 2013.

MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)

August 9, 2013

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, 2013 and the audited consolidated financial statements and related notes for the year ended December 31, 2012. 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

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, and “boe” refers to barrel of oil equivalent. Disclosure provided herein in respect of a boe may be misleading, particularly if used in isolation. A boe conversion rate of six thousand cubic feet of natural gas to one barrel of oil equivalent has been used for the calculation of boe amounts in the MD&A. This boe conversion rate is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

NON-GAAP 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, unrealized gains and losses on risk management contracts, and deferred income taxes) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of earnings per share. Funds from operations is reconciled from cash flow from operating activities under the heading “Funds from Operations”.

Management uses net debt as a measure to assess the Company’s financial position. Net debt includes current liabilities (including the revolving credit facility and excluding risk management contracts) less current assets.

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 2013 HIGHLIGHTS

Entered into rich gas premium agreements which are anticipated to increase net revenues and reduce costs
Drilled Cardium step-out wells and acquired additional lands to increase Cardium horizontal inventory to 71 gross (50 net) from 30 net at year-end
Increased funds from operations 16% to $14.3 million in Q2 2013 from $12.3 million in Q2 2012
Raised gross proceeds of $22.0 million through the issuance of 6.0 million common shares on a flow-through basis
Subsequent to Q2 2013, entered into a $145 million syndicated credit facility

SUMMARY OF FINANCIAL RESULTS
		Three Months Ended June 30			Six Months Ended June 30
($000s, except per share amounts)		2013	2012	% Change	2013	2012	% Change

Oil and natural gas sales		25,152	17,518	44	53,419	37,658	42

Funds from operations		14,280	12,275	16	31,404	25,249	24
	Per share – basic	0.16	0.14	14	0.35	0.29	21
	Per share – diluted	0.15	0.14	7	0.34	0.28	21

Net earnings		3,604	1,065	238	6,208	772	704
	Per share – basic and diluted	0.04	0.01	300	0.07	0.01	600

Total assets					315,945	255,954	23

Total long-term liabilities					22,712	21,181	7

Net debt					73,473	41,525	77

The Company has experienced significant growth in oil and natural gas sales and funds from operations during the first six months of 2013 compared to the first half of 2012. Successful capital activity during the past year, at Edson, AB and Northeast BC, resulted in a significant increase in production which, combined with higher period-over-period natural gas commodity prices, led to increased revenue and funds from operations.

PRODUCTION	Three Months Ended June 30			Six Months Ended June 30
	2013	2012	% Change	2013	2012	% Change
Average Daily Production
Oil and NGLs (bbls/d)	2,158	2,053	5	2,423	2,165	12
Natural gas (mcf/d)	36,412	27,309	33	36,639	27,081	35
Combined (boe/d)	8,227	6,604	25	8,529	6,678	28

Daily production for the three months ended June 30, 2013 increased 25% to 8,227 boe/d compared to 6,604 boe/d for the comparative period in 2012. Year-to-date, daily production increased 28% to 8,529 boe/d in 2013 compared to 6,678 boe/d in 2012. The significant increase in production was mainly due to successful drilling activity at Edson, AB and Northeast BC during the past year. Compared to the previous quarter, daily production decreased in Q2 2013 to 8,227 boe/d from 8,836 boe/d in Q1 2013 due to natural declines and decreased capital activity due to breakup. The Company expects production to increase in Q3 2013.

Crocotta’s production profile for the first half of 2013 was comprised of 72% natural gas and 28% oil and NGLs compared with the production profile for 2012 which was comprised of 68% natural gas and 32% oil and NGLs. The increase in gas weighting is due to a higher percentage of total production coming from Northeast BC in 2013 compared to 2012.

REVENUE	Three Months Ended June 30				Six Months Ended June 30
($000s)	2013	2012	% Change		2013	2012	% Change
Oil and NGLs	12,403	12,098	3		28,841	26,465	9
Natural gas	12,749	5,420	135		24,578	11,193	120
Total	25,152	17,518	44		53,419	37,658	42

Average Sales Price
Oil and NGLs ($/bbl)	63.16	64.77	(2	)	65.76	67.17	(2	)
Natural gas ($/mcf)	3.85	2.18	77		3.71	2.27	63
Combined ($/boe)	33.60	29.15	15		34.60	30.98	12

Revenue totaled $25.2 million for the second quarter of 2013, up 44% from $17.5 million in the comparative period. For the six months ended June 30, 2013, revenue totaled $53.4 million, an increase of 42% from $37.7 million for the six months ended June 30, 2012. The increase in revenue was due to significant increases in production combined with significant increases in 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
	2013	2012	% Change		2013	2012	% Change

Oil and NGLs
Corporate price ($CDN/bbl)	63.16	64.77	(2	)	65.76	67.17	(2	)
Edmonton par ($CDN/bbl)	92.94	84.39	10		90.77	88.54	3
West Texas Intermediate ($US/bbl)	94.29	93.51	1		94.32	98.15	(4	)

Natural gas
Corporate price ($CDN/mcf)	3.85	2.18	77		3.71	2.27	63
AECO price ($CDN/mcf)	3.45	1.90	82		3.32	2.03	64

Exchange rate
CDN/US dollar average exchange rate	0.9774	0.9906	(1	)	0.9846	0.9946	(1	)

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 68.0% and 72.4% of Edmonton Par price for the three and six months ended June 30, 2013, down from 76.8% and 75.9% for the comparative period in 2012. The Company experienced a decline in realized NGLs prices during the second quarter of 2013 due to a temporary shift in marketers. The shift was for a bridge period in April and May as the Company transitioned to selling a significant portion of its Edson, AB NGLs volumes under a new marketing arrangement in June 2013. Corporate average natural gas prices were 111.6% and 111.7% of AECO prices for the three and six months ended June 30, 2013, consistent with 114.7% and 111.8% 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 2013. During 2013, the Company had entered into the following commodity price contracts:

Commodity	Period	Type of Contract	Quantity Contracted	Contract Price
Oil	February 1, 2013 – December 31, 2013	Financial – Swap	1,000 bbls/d	WTI US $94.72/bbl
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
Natural Gas	April 1, 2013 – October 31, 2013	Financial – Put	15,000 GJ/d	AECO CDN $3.000/GJ

For the three months ended June 30, 2013, the realized loss on the contracts was $0.9 million and the unrealized gain on the contracts was $2.3 million. For the six months ended June 30, 2013, the realized loss on the contracts was $1.4 million and the unrealized gain on the contracts was $0.3 million.

ROYALTIES	Three Months Ended June 30				Six Months Ended June 30
($000s)	2013	2012	% Change		2013	2012	% Change
Oil and NGLs	1,671	1,628	3		3,889	3,532	10
Natural gas	87	503	(83	)	799	670	19
Total	1,758	2,131	(18	)	4,688	4,202	12

Average Royalty Rate (% of sales)
Oil and NGLs	13.5	13.5	–		13.5	13.3	2
Natural gas	0.7	9.3	(92	)	3.2	6.0	(47	)
Combined	7.0	12.2	(43	)	8.8	11.2	(21	)

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, 2013, oil, NGLs, and natural gas royalties decreased 18% to $1.8 million from $2.1 million in the comparative period. For the six months ended June 30, 2013, oil, NGLs, and natural gas royalties increased 12% to $4.7 million from $4.2 million in 2012. Oil and NGLs royalties in 2013 increased from the comparative periods as a result of higher revenue which stemmed from an increase in production. Natural gas royalties were significantly lower in Q2 2013 compared to Q2 2012 as a result of a favourable prior period adjustment to the annual capital cost and processing fee deductions and an increase in the monthly capital cost and processing fee deductions.

The overall effective royalty rate was 7.0% for the three months ended June 30, 2013 compared to 12.2% for the three months ended June 30, 2012. Year-to-date, the overall effective royalty rate was 8.8% in 2013 compared to 11.2% in 2012. The effective oil and NGLs royalty rates in 2013 were consistent with the comparative periods. The effective natural gas royalty rates in 2013 decreased from the comparative periods as a result of a favourable prior period adjustment to the annual capital cost and processing fee deductions and an increase in the monthly capital cost and processing fee deductions.

PRODUCTION EXPENSES	Three Months Ended June 30			Six Months Ended June 30
	2013	2012	% Change	2013	2012	% Change
Oil and NGLs ($/bbl)	6.62	5.39	23	5.86	5.09	15
Natural gas ($/mcf)	1.18	1.04	13	1.14	0.97	18
Combined ($/boe)	6.97	5.96	17	6.54	5.57	17

Per unit production expenses for the three and six months ended June 30, 2013 were $6.97/boe and $6.54/boe, respectively, compared to $5.96/boe and $5.57/boe for the comparative periods ended June 30, 2012. The increase in production expenses is mainly due to higher costs associated with wells brought on production in Northeast BC during the latter part of 2012. Production expenses in this area were approximately $11.00/boe due mainly to third party processing and throughput charges. The Company is currently expanding its infrastructure in this area and anticipates production expenses in Northeast BC to decrease to approximately $6.00/boe once completed in late August 2013. Production expenses in Edson, AB continued to be very competitive at approximately $5.50/boe during the second quarter.

Compared to the previous quarter ended March 31, 2013, per unit production expenses increased 14% from $6.13/boe. The increase from the previous quarter was due to property taxes of $0.75/boe being incurred during the second quarter. On an annualized basis, property taxes are anticipated to be approximately $0.17/boe of total production expenses. 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
	2013	2012	% Change		2013	2012	% Change
Oil and NGLs ($/bbl)	1.23	0.87	41		1.05	1.00	5
Natural gas ($/mcf)	0.10	0.18	(44	)	0.10	0.18	(44	)
Combined ($/boe)	0.76	1.00	(24	)	0.74	1.05	(30	)

Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended June 30, 2013 compared to the quarter ended June 30, 2012, transportation expenses decreased 24% to $0.76/boe from $1.00/boe. Year-to-date, transportation expenses decreased 30% to $0.74/boe in 2012 from $1.05/boe in 2012. Oil and NGLs transportation expenses were higher in Q2 2013 as a result of the Company’s production in Northeast BC being diverted to a different processing facility to obtain credit for NGLs volumes that were not being extracted previously. The decrease in natural gas transportation expenses per boe is due to obtaining a lower contracted transportation fee in the fourth quarter of 2012 on the majority of the Company’s natural gas production. The lower contracted transportation fee is in effect until the fourth quarter of 2013.

OPERATING NETBACK	Three Months Ended June 30				Six Months Ended June 30
	2013	2012	% Change		2013	2012	% Change
Oil and NGLs ($/bbl)
Revenue	63.16	64.77	(2	)	65.76	67.17	(2	)
Royalties	8.51	8.72	(2	)	8.87	8.97	(1	)
Production expenses	6.62	5.39	23		5.86	5.09	15
Transportation expenses	1.23	0.87	41		1.05	1.00	5
Operating netback	46.80	49.79	(6	)	49.98	52.11	(4	)

Natural gas ($/mcf)
Revenue	3.85	2.18	77		3.71	2.27	63
Royalties	0.03	0.20	(85	)	0.12	0.14	(14	)
Production expenses	1.18	1.04	13		1.14	0.97	18
Transportation expenses	0.10	0.18	(44	)	0.10	0.18	(44	)
Operating netback	2.54	0.76	234		2.35	0.98	140

Combined ($/boe)
Revenue	33.60	29.15	15		34.60	30.98	12
Royalties	2.35	3.55	(34	)	3.04	3.46	(12	)
Production expenses	6.97	5.96	17		6.54	5.57	17
Transportation expenses	0.76	1.00	(24	)	0.74	1.05	(30	)
Operating netback	23.52	18.64	26		24.28	20.90	16

During the second quarter of 2013, Crocotta generated an operating netback of $23.52/boe, up 26% from $18.64/boe for the second quarter of 2012. During the first half of 2013, Crocotta generated an operating netback of $24.28/boe compared to $20.90/boe in the comparative period. The increases were due to significant increases in natural gas commodity prices combined with decreases in natural gas royalties and transportation expenses, partially offset by increases in operating expenses. Operating netbacks in Q2 2013 were down slightly from operating netbacks of $25.01/boe in Q1 2013 due mainly to lower oil and NGLs realized prices and higher operating expenses.

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

	Three Months Ended June 30						Six Months Ended June 30
($/boe)	2013		2012		% Change		2013		2012		% Change
Operating netback	23.52		18.64		26		24.28		20.90		16
Depletion and depreciation	(13.74	)	(14.56	)	(6	)	(13.59	)	(14.73	)	(8	)
Asset impairment	(0.17	)	(0.96	)	(82	)	(0.21	)	(2.70	)	(92	)
General and administrative expenses	(2.18	)	(1.62	)	35		(2.05	)	(1.69	)	21
Share based compensation	(0.60	)	(1.87	)	(68	)	(0.62	)	(1.71	)	(64	)
Finance expenses	(1.26	)	(0.98	)	29		(1.19	)	(0.72	)	65
Deferred tax expense	(2.56	)	(1.77	)	45		(1.92	)	(1.14	)	68
Realized gain (loss) on risk management contracts	(1.20	)	4.22		(128	)	(0.88	)	2.09		(142	)
Unrealized gain on risk management contracts	3.01		0.67		349		0.20		0.33		(39	)
Net earnings	4.82		1.77		172		4.02		0.63		538

DEPLETION AND DEPRECIATION	Three Months Ended June 30				Six Months Ended June 30
	2013	2012	% Change		2013	2012	% Change
Depletion and depreciation ($000s)	10,285	8,748	18		20,985	17,903	17
Depletion and depreciation ($/boe)	13.74	14.56	(6	)	13.59	14.73	(8	)

Depletion and depreciation for the three months ended June 30, 2013 was $13.74/boe, down 6% from $14.56/boe for the comparative period ended June 30, 2012. Year-to-date, depletion and depreciation was down 8% to 13.59/boe in 2013 from $14.73/boe in 2012. The decrease is due to a significant increase in proved and probable reserves stemming from successful drilling activities during 2012. Depletion and depreciation of $13.74/boe in Q2 2013 was consistent with depletion and depreciation of $13.46/boe for the previous quarter ended March 31, 2013.

ASSET IMPAIRMENT	Three Months Ended June 30				Six Months Ended June 30
	2013	2012	% Change		2013	2012	% Change
Asset impairment ($000s)	128	579	(78	)	327	3,284	(90	)
Asset impairment ($/boe)	0.17	0.96	(82	)	0.21	2.70	(92	)

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, 2013, total exploration and evaluation asset impairments of $0.3 million were recognized relating to the expiry of undeveloped land rights (CGUs – Miscellaneous AB and Saskatchewan). For the comparative period 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 three months ended June 30, 2013, asset impairments of $0.1 million were recognized relating to the expiry of undeveloped land rights (CGUs – Miscellaneous AB and Saskatchewan). 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 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 of 2012. No property, plant, and equipment impairments were recorded for the three and six months ended June 30, 2013.

GENERAL AND ADMINISTRATIVE	Three Months Ended June 30						Six Months Ended June 30
($000s)	2013		2012		% Change		2013		2012		% Change
G&A expenses (gross)	1,887		1,301		45		3,896		2,785		40
G&A capitalized	(68	)	(69	)	(1	)	(255	)	(146	)	75
G&A recoveries	(189	)	(256	)	(26	)	(479	)	(585	)	(18	)
G&A expenses (net)	1,630		976		67		3,162		2,054		54
G&A expenses ($/boe)	2.18		1.62		35		2.05		1.69		21

General and administrative expenses (“G&A”) increased to $2.18/boe and $2.05/boe for the three and six months ended June 30, 2013, respectively, compared to $1.62/boe and $1.69/boe for the three and six months ended June 30, 2012. The increases were mainly due to an increase in employment costs.

SHARE BASED COMPENSATION	Three Months Ended June 30				Six Months Ended June 30
	2013	2012	% Change		2013	2012	% Change
Share based compensation ($000s)	445	1,123	(60	)	960	2,083	(54	)
Share based compensation ($/boe)	0.60	1.87	(68	)	0.62	1.71	(64	)

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 $0.60/boe for the three months ended June 30, 2013 from $1.87/boe in the comparative period. Year-to-date, share based compensation expense decreased to $0.62/boe in 2013 from $1.71/boe in 2012. The decrease was a result of a decrease in options issued in 2013 combined with a significant increase in production in the first half of 2013 compared to 2012. During the first half of 2013, the Company granted 0.1 million options (2012 – 0.7 million).

FINANCE EXPENSES	Three Months Ended June 30			Six Months Ended June 30
($000s)	2013	2012	% Change	2013	2012	% Change
Interest expense	796	492	62	1,567	648	142
Accretion of decommissioning obligations	147	99	48	270	222	22
Finance expenses	943	591	60	1,837	870	111
Finance expenses ($/boe)	1.26	0.98	29	1.19	0.72	65

Interest expense relates to interest incurred on amounts drawn from the Company’s credit facility. The increase in interest expense is a result of higher amounts being drawn on the Company’s credit facility in the first half of 2013 compared to the first half of 2012. At June 30, 2013, $63.8 million (June 30, 2012 – $39.7 million) had been drawn on the Company’s credit facility.

DEFERRED INCOME TAXES

Deferred income tax expense on the earnings before taxes for the three and six months ended June 30, 2013 were $1.9 million and $3.0 million, respectively, compared to $1.1 million and $1.4 million for the comparative periods. This was slightly 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 tax deductions related to flow-through shares.

Estimated tax pools at June 30, 2013 total approximately $312.6 million (December 31, 2012 – $299.6 million).

FUNDS FROM OPERATIONS

Funds from operations for the three and six months ended June 30, 2013 were $14.3 million ($0.15 per diluted share) and $31.4 million ($0.34 per diluted share), respectively, compared to $12.3 million ($0.14 per diluted share) and $25.2 million ($0.28 per diluted share) for the three and six months ended June 30, 2012. The increase was mainly due to a significant increase in revenue which resulted from significant increases in production and natural gas prices. Of note, included in funds from operations for the three and six months ended June 30, 2013 were realized losses on risk management contracts of $0.9 million and $1.4 million, respectively, compared to realized gains on risk management contracts of $2.5 million for both the three and six months ended June 30, 2012.

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)		2013		2012		% Change	2013		2012		% Change
Cash flow from operating activities (GAAP)		18,882		13,178		43	36,277		25,667		41
Add back:
	Decommissioning expenditures	163		163		–	247		350		(29	)
	Change in non-cash working capital	(4,765	)	(1,066	)	347	(5,120	)	(768	)	567
Funds from operations (non-GAAP)		14,280		12,275		16	31,404		25,249		24

NET EARNINGS

The Company had net earnings of $3.6 million ($0.04 per diluted share) for the three months ended June 30, 2013 compared to net earnings of $1.1 million ($0.01 per diluted share) for the three months ended June 30, 2012. Year-to-date, the Company had net earnings of $6.2 million ($0.07 per diluted share) in 2013 compared to net earnings of $0.8 million ($0.01 per diluted share) in 2012. Net earnings for the three and six months ended June 30, 2013 arose mainly due to a significant increase in revenue which resulted from significant increases in production and natural gas prices.

CAPITAL EXPENDITURES	Three Months Ended June 30				Six Months Ended June 30
($000s)	2013	2012	% Change		2013	2012	% Change
Land	449	1,430	(69	)	1,669	3,080	(46	)
Drilling, completions, and workovers	9,840	8,495	16		29,925	28,038	7
Equipment	3,589	826	335		13,335	7,152	86
Geological and geophysical	304	298	2		771	418	84
Capital expenditures	14,182	11,049	28		45,700	38,688	18

For the three months ended June 30, 2013, the Company had net capital expenditures of $14.2 million compared to net capital expenditures of $11.0 million for the three months ended June 30, 2012. For the six months ended June 30, 2013, the Company had net capital expenditures of $45.7 million compared to $38.7 million for the comparative period in 2012. The increase in exploration and development expenditures in the first half of 2013 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 2013, Crocotta drilled a total of 7 (6.0 net) wells, which resulted in 5 (4.4 net) oil wells and 2 (1.6 net) liquids-rich natural gas wells.

LIQUIDITY AND CAPITAL RESOURCES

The Company had net debt of $73.5 million at June 30, 2013 compared to net debt of $80.1 million at December 31, 2012. The decrease of $6.6 million was mainly due to gross proceeds of $22.0 million from an equity financing in June 2013 and funds from operations of $31.4 million, offset by $45.7 million used for the purchase and development of oil and natural gas properties and equipment, $1.0 million in share issue costs, and $0.2 million in decommissioning expenditures.

At June 30, 2013, the Company had a $140.0 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, 2013, $63.8 million (December 31, 2012 – $68.5 million) had been drawn on the revolving credit facility. In addition, at June 30, 2013, the Company had outstanding letters of guarantee of approximately $2.5 million (December 31, 2012 – $1.5 million) which reduce the amount that can be borrowed under the credit facility.

Subsequent to June 30, 2013, the Company entered into a syndicated credit facility with a syndicate of three Canadian chartered banks. The syndicated credit facility replaces the Company’s previous revolving operating demand loan credit facility. The syndicated facility has a borrowing base of $145 million, consisting of a $135 million revolving line of credit and a $10 million operating line of credit. The syndicated facility revolves for a 364 day period and will be subject to its next 364 day extension by July 11, 2014. If not extended, the syndicated facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date.

Advances under the syndicated facility are available by way of prime rate loans, with interest rates between 1.00% and 2.50% over the Canadian prime lending rate, and bankers’ acceptances and LIBOR loans, which are subject to stamping fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash flow ratio of the Company. Standby fees are charged on the undrawn syndicated facility at rates ranging from 0.50% to 0.875%. The next scheduled borrowing base review of the syndicated facility is scheduled on or before November 1, 2013.

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 $22.0 million from the issuance of common shares during the second quarter of 2013 and subsequent to June 30, 2013, the Company entered into a $145 million syndicated credit facility which replaced the previous $140 million operating demand loan credit facility. 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 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, 2013:

($000s)	Total	Less than One Year	One to Three Years	After Three Years
Accounts payable and accrued liabilities	21,619	21,619	–	–
Revolving credit facility	63,786	63,786	–	–
Risk management contracts	1,279	1,279	–	–
Decommissioning obligations	20,867	49	189	20,629
Office leases	585	402	183	–
Field equipment leases	1,049	959	90	–
Firm transportation agreements	199	110	84	5
Total contractual obligations	109,384	88,204	546	20,634

In addition to the above commitments, as a result of the issuance of flow-through shares in June 2013, the Company is committed to spend approximately $22.0 million on qualifying exploration and development expenditures prior to December 31, 2014. As at June 30, 2013, the Company had spent $2.5 million in connection with this flow-through share commitment.

Under the terms of a farm-in agreement, the Company is also committed to drill and complete one Edson Cardium well. Under the terms of the agreement, the Company is committed to spud the well prior to August 2013. The well was spudded subsequent to June 30, 2013 and the estimated total cost to drill and complete the well is approximately $3.5 million.

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, 2013	August 9, 2013
Voting common shares	95,448	96,098
Stock options	8,507	7,857
Warrants	2,321	2,321
Total	106,276	106,276

SUMMARY OF QUARTERLY RESULTS

		Q2 2013	Q1 2013	Q4 2012		Q3 2012		Q2 2012	Q1 2012		Q4 2011		Q3 2011
Average Daily Production
Oil and NGLs (bbls/d)		2,158	2,691	2,476		2,103		2,053	2,277		1,879		1,336
Natural gas (mcf/d)		36,412	36,869	29,160		29,053		27,309	26,852		23,354		15,996
Combined (boe/d)		8,227	8,836	7,336		6,945		6,604	6,752		5,771		4,002

($000s, except per share amounts)
Oil and natural gas sales		25,152	28,267	24,938		17,922		17,518	20,140		20,391		14,814

Funds from operations		14,280	17,124	14,478		10,888		12,275	12,974		12,115		9,551
	Per share – basic	0.16	0.19	0.16		0.12		0.14	0.15		0.15		0.12
	Per share – diluted	0.15	0.19	0.16		0.12		0.14	0.14		0.14		0.11

Net earnings (loss)		3,604	2,604	(2,082	)	(3,944	)	1,065	(293	)	(7,052	)	5,535
	Per share – basic and diluted	0.04	0.03	(0.02	)	(0.04	)	0.01	–		(0.09	)	0.07

Significant increases in production stemming from successful drilling activities during the past two years has resulted in increasing oil and natural gas sales and funds from operations over the same period. The Company had a net loss in four of the eight previous quarters mainly as a result of asset impairments recognized in each quarter on non-core properties.

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, 2012.

CHANGES IN ACCOUNTING POLICIES

On January 1, 2013, the Company adopted new standards with respect to consolidations (IFRS 10), joint arrangements (IFRS 11), disclosure of interests in other entities (IFRS 12), fair value measurements (IFRS 13), and amendments to financial statement disclosures (IFRS 7). The adoption of these standards had no impact on the amounts recorded in the consolidated 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.

Financial instruments

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. During 2013, the Company had entered into the following commodity price contracts:

Commodity	Period	Type of Contract	Quantity Contracted	Contract Price
Oil	February 1, 2013 – December 31, 2013	Financial – Swap	1,000 bbls/d	WTI US $94.72/bbl
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
Natural Gas	April 1, 2013 – October 31, 2013	Financial – Put	15,000 GJ/d	AECO CDN $3.000/GJ

Credit risk

Credit risk represents the financial loss that the Company would suffer if the Company’s counterparties to a financial instrument, in owing an amount to the Company, fail to meet or discharge their obligation to the Company. A substantial portion of the Company’s accounts receivable and deposits are with customers and joint venture partners in the oil and natural gas industry and are subject to normal industry credit risks. The Company generally grants unsecured credit but routinely assesses the financial strength of its customers and joint venture partners.

The Company sells the majority of its production to three petroleum and natural gas marketers and therefore is subject to concentration risk. Historically, the Company has not experienced any collection issues with its oil and natural gas marketers. Joint venture receivables are typically collected within one to three months of the joint venture invoice being issued to the partner. The Company attempts to mitigate the risk from joint venture receivables by obtaining partner approval for significant capital expenditures prior to the expenditure being incurred. The Company does not typically obtain collateral from petroleum and natural gas marketers or joint venture partners; however, in certain circumstances, the Company may cash call a partner in advance of expenditures being incurred.

The maximum exposure to credit risk is represented by the carrying amount on the statement of financial position. At June 30, 2013, $8.6 million or 87.0% of the Company’s outstanding accounts receivable were current while $1.3 million or 13.0% were outstanding over 90 days but not impaired. During the six months ended June 30, 2013, the Company did not deem any outstanding accounts receivable to be uncollectable.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company’s processes for managing liquidity risk include ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual, quarterly, and monthly capital expenditure budgets, which are monitored and updated as required, and requires authorizations for expenditures on projects to assist with the management of capital. In managing liquidity risk, the Company ensures that it has access to additional financing, including potential equity issuances and additional debt financing. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.

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 Company’s President and Chief Executive Officer (“CEO”) and Vice President Finance and Chief Financial Officer (“CFO”) are responsible for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting as defined in Multilateral Instrument 52-109 of the Canadian Securities Administrators.

Disclosure controls and procedures have been designed to ensure that information required to be disclosed by the Company is accumulated and communicated to management as appropriate to allow timely decisions regarding required disclosure. The Company evaluated its disclosure controls and procedures for the year ended December 31, 2012. The Company’s CEO and CFO have concluded that, based on their evaluation, the Company’s disclosure controls and procedures are effective to provide reasonable assurance that all material or potentially material information related to the Company is made known to them and is disclosed in a timely manner if required.

Internal controls over financial reporting have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with IFRS. The Company’s internal controls over financial reporting include those policies and procedures that: pertain to the maintenance of records that in reasonable detail accurately and fairly reflect transactions and disposition of the assets; provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles and that receipts and expenditures are being made only in accordance with authorizations of management and directors; and provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of assets that could have a material effect on the annual financial statements or interim financial statements.

The Company evaluated the effectiveness of its internal controls over financial reporting as of December 31, 2012. In making this evaluation, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework. Based on their evaluation, the Company’s CEO and CFO have identified weaknesses over segregation of duties. Specifically, due to the limited number of finance and accounting personnel at the Company, it is not feasible to achieve complete segregation of duties with regards to certain complex and non-routine accounting transactions that may arise. This weakness is considered to be a common deficiency for many smaller listed companies in Canada. Notwithstanding the weaknesses identified with regards to segregation of duties, the Company concluded that all other of its internal controls over financial reporting were effective as of December 31, 2012. No material changes in the Company’s internal controls over financial reporting were identified during the most recent reporting period that have materially affected, or are likely to material affect, the Company’s internal controls over financial reporting.

Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors, or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control systems are met. As a result of the weaknesses identified in the Company’s internal controls over financial reporting, there is a greater likelihood that a material misstatement would not be prevented or detected. To mitigate the risk of such material misstatement in financial reporting, the CEO and CFO oversee all material and complex transactions of the Company and the financial statements are reviewed and approved by the Board of Directors each quarter. In addition, the Company will seek the advice of external parties, such as the Company’s external auditors, in regards to the appropriate accounting treatment for any complex and non-routine transactions that may arise.

FORWARD-LOOKING 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		2013		2012

Assets
Current assets
	Accounts receivable			9,902		15,983
	Prepaid expenses and deposits			2,030		1,550
				11,932		17,533

Property, plant, and equipment		(5	)	263,957		241,703
Exploration and evaluation assets		(4	)	29,529		28,302
Deferred income taxes				10,527		13,442
				304,013		283,447

				315,945		300,980

Liabilities
Current liabilities
	Accounts payable and accrued liabilities			21,619		29,165
	Revolving credit facility	(6	)	63,786		68,480
	Risk management contracts			1,279		1,592
				86,684		99,237

Decommissioning obligations		(7	)	20,867		21,852
Flow-through share premium		(8	)	2,157		–
				109,708		121,089

Shareholders’ Equity
	Shareholders’ capital	(8	)	247,469		228,277
	Contributed surplus			12,972		12,026
	Deficit			(54,204	)	(60,412	)
				206,237		179,891

Subsequent events		(6,9	)
				315,945		300,980

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
(unaudited)
				Three Months Ended June 30				Six Months Ended June 30
($000s, except per share amounts)		Note		2013		2012		2013		2012

Revenue
	Oil and natural gas sales			25,152		17,518		53,419		37,658
	Royalties			(1,758	)	(2,131	)	(4,688	)	(4,202	)
				23,394		15,387		48,731		33,456
	Realized gain (loss) on risk management contracts			(900	)	2,536		(1,358	)	2,536
	Unrealized gain on risk management contracts			2,250		400		313		400
				24,744		18,323		47,686		36,392

Expenses
	Production			5,219		3,579		10,098		6,765
	Transportation			569		601		1,142		1,276
	Depletion and depreciation	(5	)	10,285		8,748		20,985		17,903
	Asset impairment	(4,5	)	128		579		327		3,284
	General and administrative			1,630		976		3,162		2,054
	Share based compensation	(9	)	445		1,123		960		2,083
				18,276		15,606		36,674		33,365

Operating earnings				6,468		2,717		11,012		3,027

Other Expenses
	Finance expense			943		591		1,837		870
Earnings before taxes				5,525		2,126		9,175		2,157

Taxes
	Deferred income tax expense			1,921		1,061		2,967		1,385


Net earnings and comprehensive earnings				3,604		1,065		6,208		772


Net earnings per share
	Basic and diluted	(10	)	0.04		0.01		0.07		0.01

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)	2013		2012

Shareholders’ Capital
Balance, beginning of period	228,277		225,848
Issue of shares (net of share issue costs and flow-through share premium)	18,911		–
Issued on exercise of stock options	166		–
Share based compensation – exercised	115		–
Balance, end of period	247,469		225,848

Contributed Surplus
Balance, beginning of period	12,026		8,927
Share based compensation – expensed	960		2,083
Share based compensation – capitalized	101		169
Share based compensation – exercised	(115	)	–
Balance, end of period	12,972		11,179

Deficit
Balance, beginning of period	(60,412	)	(55,158	)
Net earnings	6,208		772
Balance, end of period	(54,204	)	(54,386	)


Total Shareholders’ Equity	206,237		182,641

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		2013		2012		2013		2012

Operating Activities
	Net earnings			3,604		1,065		6,208		772
	Depletion and depreciation	(5	)	10,285		8,748		20,985		17,903
	Asset impairment	(4,5	)	128		579		327		3,284
	Share based compensation	(9	)	445		1,123		960		2,083
	Finance expense	(11	)	943		591		1,837		870
	Interest paid			(796	)	(492	)	(1,567	)	(648	)
	Deferred income tax expense			1,921		1,061		2,967		1,385
	Unrealized gain on risk management contracts			(2,250	)	(400	)	(313	)	(400	)
	Decommissioning expenditures	(7	)	(163	)	(163	)	(247	)	(350	)
	Change in non-cash working capital	(13	)	4,765		1,066		5,120		768
				18,882		13,178		36,277		25,667

Financing Activities
	Revolving credit facility	(6	)	(24,675	)	5,615		(4,694	)	34,496
	Issuance of shares	(8	)	22,149		–		22,149		–
	Share issue costs	(8	)	(967	)	–		(967	)	–
				(3,493	)	5,615		16,488		34,496

Investing Activities
	Capital expenditures – property, plant, and equipment	(5	)	(7,847	)	(4,934	)	(36,024	)	(29,482	)
	Capital expenditures – exploration and evaluation assets	(4	)	(6,335	)	(6,115	)	(9,676	)	(9,206	)
	Change in non-cash working capital	(13	)	(1,207	)	(7,744	)	(7,065	)	(21,475	)
				(15,389	)	(18,793	)	(52,765	)	(60,163	)

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, 2013

(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 – 5^thAvenue 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, 2012.

The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on August 9, 2013.

(b) Basis of measurement

The condensed interim consolidated financial statements have been prepared on the historical cost basis except for risk management contracts, which are measured at fair value.

(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, 2012.

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, 2012. The accounting policies have been applied consistently by the Company to all periods presented in these condensed interim consolidated financial statements.

4. EXPLORATION AND EVALUATION ASSETS

		Total
Balance, December 31, 2011		20,641
	Additions	49,198
	Transfer to property, plant, and equipment	(36,838	)
	Impairment	(4,699	)
Balance, December 31, 2012		28,302
	Additions	9,676
	Transfer to property, plant, and equipment	(8,122	)
	Impairment	(327	)
Balance, June 30, 2013		29,529

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 $9.7 million of additions during the six months ended June 30, 2013 were additions of $9.0 million related to the Edson AB CGU and $0.5 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, 2013, total exploration and evaluation asset impairments of $0.3 million were recognized relating to the expiry of undeveloped land rights (CGUs – Miscellaneous AB and Saskatchewan).

5. PROPERTY, PLANT, AND EQUIPMENT

Cost		Total
Balance, December 31, 2011		236,846
	Additions	54,756
	Transfer from exploration and evaluation assets	36,838
	Change in decommissioning obligation estimates	2,883
	Capitalized share based compensation	319
Balance, December 31, 2012		331,642
	Additions	36,024
	Transfer from exploration and evaluation assets	8,122
	Change in decommissioning obligation estimates	(1,008	)
	Capitalized share based compensation	101
Balance, June 30, 2013		374,881

Accumulated Depletion, Depreciation, and Impairment		Total
Balance, December 31, 2011		44,514
	Depletion and depreciation	36,685
	Impairment	8,740
Balance, December 31, 2012		89,939
	Depletion and depreciation	20,985
Balance, June 30, 2013		110,924

Net Book Value		Total
December 31, 2011		192,332
December 31, 2012		241,703
June 30, 2013		263,957

During the three and six months ended June 30, 2013, approximately $nil (2012 – $0.1 million) and $0.1 million (2012 – $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, 2013 included an estimated $215.2 million (2012 – $177.4 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $13.6 million (2012 – $9.0 million) for the estimated salvage value of production equipment and facilities.

6. CREDIT FACILITY

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 $30.4 million which is estimated to be incurred over the next 28 years. At June 30, 2013, a risk-free rate of 2.9% (December 31, 2012 – 2.3%) was used to calculate the net present value of the decommissioning obligations.

		Six Months Ended		Year Ended
		June 30, 2013		December 31, 2012
Balance, beginning of period		21,852		19,250
	Provisions incurred	615		2,208
	Provisions settled	(247	)	(734	)
	Revisions	(1,623	)	675
	Accretion	270		453
Balance, end of period		20,867		21,852

8. SHAREHOLDERS’ CAPITAL

Voting Common Shares		Number	Amount
Balance, December 31, 2012		89,261	228,277
	Exercise of stock options	145	281
	Share issuances	6,042	21,983
	Share issue costs, net of future tax effect of $0.2 million		(725	)
	Flow-through share premium		(2,347	)
Balance, June 30, 2013		95,448	247,469

In June 2013, the Company issued approximately 6.0 million common shares on a flow-through basis for gross proceeds of approximately $22.0 million. Approximately 4.2 million shares were issued at a price of $3.70 per share in respect of Canadian exploration expenses (“CEE”) and approximately 1.8 million shares were issued at a price of $3.50 per share in respect of Canadian development expenses (“CDE”). Upon issuance, the premium received on the flow-through shares, being the difference between the fair value of the flow-through shares issued and the fair value that would have been received for common shares at the date of the announcement of the financing, was recognized as a liability. Under the terms of the flow-through share agreements, the Company is committed to spend approximately $22.0 million on qualifying exploration and development expenditures prior to December 31, 2014. As at June 30, 2013, the Company had spent $2.5 million in connection with this flow- through share commitment.

9. SHARE BASED COMPENSATION PLANS

Stock options

The Company has authorized and reserved for issuance 9.5 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, 2013, 8.5 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		Weighted Average
		Options		Exercise Price ($)
Balance, December 31, 2012		8,601		2.09
	Granted	53		3.06
	Exercised	(145	)	1.14
	Forfeited	(2	)	3.46
Balance, June 30, 2013		8,507		2.11

The following table summarizes the stock options outstanding and exercisable at June 30, 2013:

	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	3,497	1.4	1.24	3,154	1.22
$2.01 to $3.00	4,269	2.7	2.59	2,349	2.50
$3.01 to $3.46	741	3.7	3.44	231	3.46
	8,507	2.3	2.11	5,734	1.83

Subsequent to June 30, 2013, 0.7 million options at an exercise price of $1.26 per share were exercised. The options have an expiry date of January 15, 2014.

Warrants

The Company has an arrangement that allows warrants to be issued to directors, officers, and employees. The maximum number of common shares that may be issued, and that have been reserved for issuance under this arrangement, is 2.4 million. Warrants granted under this arrangement vest over three years and have exercise prices ranging from $3.75 per share to $6.75 per share. During the year ended December 31, 2007, the Company issued 2.4 million warrants under this arrangement. The fair value of the warrants granted under this arrangement at the date of issue was determined to be $nil using the minimum value method as they were issued prior to the Company becoming publicly traded. During 2012, approval was obtained to extend the expiry date of the warrants to December 23, 2013. The resulting compensation cost charged to earnings during 2012 in relation to the extension of the warrants was $0.2 million.

On October 29, 2009, the Company issued an additional 1.2 million warrants at an exercise price of $1.40 per share in conjunction with a private placement share issuance. The warrants vested immediately and had an expiry date of October 29, 2012. The warrants were exercised during 2012.

The number and weighted average exercise price of warrants are as follows:

	Number of	Weighted Average
	Warrants	Exercise Price
Balance, December 31, 2012 and June 30, 2013	2,321	4.80

The following table summarizes the warrants outstanding and exercisable at June 30, 2013:


		Warrants Outstanding and Exercisable
Exercise Price	Number	Weighted Average Remaining Life	Weighted Average Exercise Price
$3.75 to $4.05	740	0.50	3.76
$4.50 to $5.25	807	0.50	4.55
$6.00 to $6.75	774	0.50	6.05
	2,321	0.50	4.80

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, 2013	June 30, 2013
Risk-free interest rate (%)	1.1	1.1
Expected life (years)	4.0	4.0
Expected volatility (%)	57.3	57.8
Expected dividend yield (%)	–	–
Forfeiture rate (%)	6.2	6.2
Weighted average fair value of options granted ($ per option)	1.38	1.38

10. PER SHARE AMOUNTS

The following table summarizes the weighted average number of shares used in the basic and diluted net earnings per share calculations:

	Three Months Ended	Six Months Ended
	June 30, 2013	June 30, 2013
Weighted average number of shares – basic	90,549	89,909
Dilutive effect of share based compensation plans	2,750	2,542
Weighted average number of shares – diluted	93,299	92,451

For the three months ended June 30, 2013, 2.3 million stock options (2012 – 4.9 million) and 2.3 million warrants (2012 – 2.3 million) were anti-dilutive and were not included in the diluted earnings per share calculation. For the six months ended June 30, 2013, 2.3 million stock options (2012 – 2.3 million) and 2.3 million warrants (2012 – 2.3 million) were anti-dilutive and were not included in the diluted earnings per share calculation.

11. FINANCE EXPENSES

Finance expenses include the following:

	Three Months Ended	Six Months Ended
	June 30, 2013	June 30, 2013
Interest expense (note 6)	796	1,567
Accretion of decommissioning obligations (note 7)	147	270
Finance expenses	943	1,837

12. FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivatives

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 and a risk-free interest rate (based on published government rates).

The Company classified the fair value of its financial instruments at fair value according to the following hierarchy based on the amount of observable inputs used to value the instrument:

Level 1 – observable inputs, such as quoted market prices in active markets
Level 2 – inputs, other that the quoted market prices in active markets, which are observable, either directly or indirectly
Level 3 – unobservable inputs for the asset or liability in which little or no market data exists, therefore requiring an entity to develop its own assumptions

The fair value of derivative contracts used for risk management as shown in the statement of financial position as at June 30, 2013 is measured using level 2. During the six months ended June 30, 2013, there were no transfers between level 1, level 2, and level 3 classified assets and liabilities.

12. SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended		Six Months Ended
		June 30, 2013		June 30, 2013
Accounts receivable		7,483		6,081
Prepaid expenses and deposits		(653	)	(480	)
Accounts payable and accrued liabilities		(3,272	)	(7,546	)
Change in non-cash working capital		3,558		(1,945	)

Relating to:
	Investing	(1,207	)	(7,065	)
	Operating	4,765		5,120
Change in non-cash working capital		3,558		(1,945	)


CORPORATE INFORMATION

OFFICERS AND DIRECTORS

Robert J. Zakresky, CA		BANK
President, CEO & Director		National Bank of Canada
		1800, 311 – 6th Avenue SW
Nolan Chicoine, MPAcc, CA		Calgary, Alberta T2P 3H2
VP Finance & CFO

Terry L. Trudeau, P.Eng.
VP Operations & COO		TRANSFER AGENT
		Valiant Trust Company
Weldon Dueck, BSc., P.Eng.		310, 606 – 4th Street SW
VP Business Development		Calgary, Alberta T2P 1T1

R.D. (Rick) Sereda, M.Sc., P.Geol.
VP Exploration
		LEGAL COUNSEL
Helmut R. Eckert, P.Land		Gowling Lafleur Henderson LLP
VP Land		1400, 700 – 2nd Street SW
		Calgary, Alberta T2P 4V5
Kevin Keith
VP Production

Larry G. Moeller, CA, CBV		AUDITORS
Chairman of the Board		KPMG LLP
		2700, 205 – 5th Avenue SW
Daryl H. Gilbert, P.Eng.		Calgary, Alberta T2P 4B9
Director

Don Cowie
Director		INDEPENDENT ENGINEERS
		GLJ Petroleum Consultants Ltd.
Brian Krausert		4100, 400 – 3rd Avenue SW
Director		Calgary, Alberta T2P 4H2

Gary W. Burns
Director

Don D. Copeland, P.Eng.
Director

Brian Boulanger
Director

Patricia Phillips
Director

Crocotta Energy Inc.
Robert J. Zakresky
President & CEO
(403) 538-3736
(403) 538-3735 (FAX)

Crocotta Energy Inc.
Nolan Chicoine
VP Finance & CFO
(403) 538-3738
(403) 538-3735 (FAX)

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

Crocotta Energy Inc.: Q2 2013 Financial and Operating Results

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