Crocotta Energy Inc.: Year End 2012 Financial and Operating Results

CALGARY, ALBERTA–(Marketwire – Mar 27, 2013) – CROCOTTA ENERGY INC. (CTA.TO) is pleased to announce its financial and operating results for the year ended December 31, 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 average production 83% to 6,911 boepd in 2012 from 3,775 boepd in 2011
• Achieved 2012 exit guidance of 8,500 boepd
• Increased proved plus probable reserves 29% to 38.1 Mmboe in 2012 from 29.6 Mmboe in 2011
• Increased funds from operations 65% to $50.6 million in 2012 from $30.6 million in 2011
• Decreased production expenses 26% to $5.83/boe in 2012 from $7.85/boe in 2011
• Drilled 13.4 net Bluesky and Cardium wells at Edson, AB at a 100% success rate
• Subsequent to December 31, 2012, increased bank credit facility to $140.0 million

FINANCIAL RESULTS
		Three Months Ended December 31						Year Ended December 31
($000s, except per share amounts)		2012		2011		% Change		2012		2011		% Change
Oil and natural gas sales		24,938		20,391		22		80,518		54,974		46
Funds from operations (1)		14,478		12,115		20		50,615		30,608		65
	Per share – basic	0.16		0.15		7		0.57		0.39		46
	Per share – diluted	0.16		0.14		14		0.56		0.38		47
Net loss		(2,082	)	(7,052	)	(70	)	(5,254	)	(5,592	)	(6	)
	Per share – basic and diluted	(0.02	)	(0.09	)	(78	)	(0.06	)	(0.07	)	(14	)
Capital expenditures		36,320		36,806		(1	)	98,548		93,082		6
Property acquisitions		5,406		–		100		5,406		1,704		217
Property dispositions		–		(4,541	)	(100	)	–		(14,552	)	(100	)
Net debt (2)								80,112		27,736		189
Common shares outstanding (000s)
	Weighted average – basic	88,980		81,737		9		88,319		78,804		12
	Weighted average – diluted	91,522		84,699		8		90,705		81,166		12
	End of period – basic							89,261		88,095		1
	End of period – diluted							100,183		99,558		1

(1)	Funds from operations and funds from operations per share do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details and the Funds from Operations section in the MD&A for a reconciliation from cash flow from operating activities.
(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 December 31						Year Ended December 31
		2012		2011		% Change		2012		2011		% Change
Daily production
	Oil and NGLs (bbls/d)	2,476		1,879		32		2,227		1,214		83
	Natural gas (mcf/d)	29,160		23,354		25		28,099		15,367		83
	Oil equivalent (boe/d)	7,336		5,771		27		6,911		3,775		83
Revenue
	Oil and NGLs ($/bbl)	67.55		74.60		(9	)	64.81		74.69		(13	)
	Natural gas ($/mcf)	3.56		3.49		2		2.69		3.90		(31	)
	Oil equivalent ($/boe)	36.95		38.40		(4	)	31.83		39.90		(20	)
Royalties
	Oil and NGLs ($/bbl)	7.14		9.34		(24	)	9.17		12.70		(28	)
	Natural gas ($/mcf)	0.17		0.11		55		0.14		0.09		56
	Oil equivalent ($/boe)	3.07		3.49		(12	)	3.52		4.46		(21	)
Production expenses
	Oil and NGLs ($/bbl)	5.96		6.67		(11	)	5.31		7.12		(25	)
	Natural gas ($/mcf)	1.11		1.21		(8	)	1.01		1.37		(26	)
	Oil equivalent ($/boe)	6.41		7.05		(9	)	5.83		7.85		(26	)
Transportation expenses
	Oil and NGLs ($/bbl)	0.95		0.61		56		0.87		0.74		18
	Natural gas ($/mcf)	0.15		0.19		(21	)	0.17		0.18		(6	)
	Oil equivalent ($/boe)	0.90		0.97		(7	)	0.98		0.95		3
Operating netback (1)
	Oil and NGLs ($/bbl)	53.50		57.98		(8	)	49.46		54.13		(9	)
	Natural gas ($/mcf)	2.13		1.98		8		1.37		2.26		(39	)
	Oil equivalent ($/boe)	26.57		26.89		(1	)	21.50		26.64		(19	)
Depletion and depreciation ($/boe)		(13.49	)	(14.87	)	(9	)	(14.50	)	(15.04	)	(4	)
Asset impairment ($/boe)		(11.47	)	(25.79	)	(56	)	(5.31	)	(12.07	)	(56	)
General and administrative expenses ($/boe)		(3.87	)	(3.60	)	8		(2.17	)	(3.90	)	(44	)
Share based compensation ($/boe)		(1.01	)	(1.87	)	(46	)	(1.39	)	(2.29	)	(39	)
Finance expenses ($/boe)		(0.85	)	(0.83	)	2		(0.75	)	(1.06	)	(29	)
Finance income ($/boe)		–		–		–		–		0.10		(100	)
Loss on sale of assets ($/boe)		–		(7.32	)	(100	)	–		(1.87	)	(100	)
Deferred tax reduction (expense) ($/boe)		0.44		14.10		(97	)	(0.07	)	5.43		(101	)
Realized gain (loss) on risk management contracts ($/boe)		(0.59	)	–		100		1.25		–		100
Unrealized gain (loss) on risk management contracts ($/boe)		1.18		–		100		(0.63	)	–		100
Net loss ($/boe)		(3.09	)	(13.29	)	(77	)	(2.07	)	(4.06	)	(49	)

(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.

PRESIDENT’S MESSAGE

Crocotta had a highly successful 2012 with respect to many aspects of the business. Great strides were made in building long term value by proving up material inventory in the Cardium at Edson, starting to build infrastructure for liquids recovery at Sunrise-Dawson in the Montney, and reducing operating costs to below $6 per boe.

The Cardium opened the year with one successful horizontal oil well producing at Edson and ended with 11 wells onstream and 35 additional net locations added to the drilling inventory.

Successful well tests in the Montney proved up a liquids-rich play at Sunrise-Dawson that will provide high growth and large returns for Crocotta in 2013 and beyond. Crocotta signed an agreement with a third party entity and will be constructing facilities in Q213 to extract a large portion of the natural gas liquids while materially reducing operating costs. This play, given liquids yield and high initial rates, will rival most liquids-rich plays in North America.

The last but certainly not the least play is the Bluesky at Edson. The 22 horizontal Bluesky wells drilled by Crocotta over the last two and half years provided a large portion of the growth from 2,200 boepd in 2010 to the 2012 exit rate of 8,500 boepd. While significantly delineated and de-risked, the Bluesky still has very material production upside with over 40 net locations in drilling inventory.

In 2013, Crocotta expects to further all three of its major plays which will contribute to our budgeted exit rate of 10,500 boepd. Crocotta also intends to drill two oil exploration plays and continues to pursue acquisitions in its core areas.

We look forward to updating our shareholders throughout the year as we execute our plan for 2013.

Rob Zakresky, President & Chief Executive Officer

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

March 25, 2013

The MD&A should be read in conjunction with the audited consolidated financial statements and related notes for the years ended December 31, 2012 and 2011. The audited consolidated financial statements and financial data contained in the MD&A have been prepared in accordance with International Financial Reporting Standards (“IFRS”) in Canadian currency (except where noted as being in another currency).

DESCRIPTION OF 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, 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 loss plus non-cash items (depletion and depreciation, asset impairments, share based compensation, non-cash finance expenses, gains and losses on asset sales, deferred income taxes, and unrealized gains and losses on risk management contracts) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of earnings per share. Funds from operations is reconciled from cash flow from operating activities under the heading “Funds from Operations”.

Management uses net debt as a measure to assess the Company’s financial position. Net debt includes current liabilities (including the revolving credit facility and excluding 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 loss per boe under the heading “Operating Netback”.

2012 HIGHLIGHTS

• Increased average production 83% to 6,911 boepd in 2012 from 3,775 boepd in 2011
• Achieved 2012 exit guidance of 8,500 boepd
• Increased proved plus probable reserves 29% to 38.1 Mmboe in 2012 from 29.6 Mmboe in 2011
• Increased funds from operations 65% to $50.6 million in 2012 from $30.6 million in 2011
• Decreased production expenses 26% to $5.83/boe in 2012 from $7.85/boe in 2011
• Drilled 13.4 net Bluesky and Cardium wells at Edson, AB at a 100% success rate
• Subsequent to December 31, 2012, increased bank credit facility to $140.0 million

SUMMARY OF FINANCIAL RESULTS
		Three Months Ended December 31					Year Ended December 31
($000s, except per share amounts)		2012		2011		2010	2012		2011		2010
Oil and natural gas sales		24,938		20,391		7,274	80,518		54,974		34,530
Funds from operations		14,478		12,115		4,201	50,615		30,608		14,174
	Per share – basic	0.16		0.15		0.06	0.57		0.39		0.22
	Per share – diluted	0.16		0.14		0.06	0.56		0.38		0.22
Net earnings (loss)		(2,082	)	(7,052	)	655	(5,254	)	(5,592	)	(5,328	)
	Per share – basic and diluted	(0.02	)	(0.09	)	0.01	(0.06	)	(0.07	)	(0.08	)
Total assets							300,980		239,554		185,528
Total long-term liabilities							21,852		20,063		14,035
Net debt							80,112		27,736		35,200

The Company has experienced significant growth in oil and natural gas sales and funds from operations over the past three years. Successful capital activity during the latter half of 2010 and throughout 2011 and 2012, mainly at Edson, AB, led to a significant increase in production which resulted in increased revenue and funds from operations. The Company had a net loss the past three years mainly due to asset impairments recorded on non-core properties in each year due to declines in commodity prices and limited capital activity in these non-core areas to increase reserves. Net debt increased significantly in 2012 due to significant capital expenditures of $104.0 million during the year. Net debt in 2011 and 2010 was lower as a result of several factors, including two equity financings in 2011 that raised gross proceeds of $61.0 million, non-core property dispositions during 2010 and 2011 that totaled $65.2 million, and funds flow from operations generated in 2010 and 2011 that totaled $44.8 million, which were offset by significant capital expenditures that totaled $123.4 million in 2010 and 2011.

PRODUCTION	Three Months Ended December 31				Year Ended December 31
	2012	2011		% Change	2012	2011		% Change
Average Daily Production
Oil and NGLs (bbls/d)	2,476	1,879		32	2,227	1,214		83
Natural gas (mcf/d)	29,160	23,354		25	28,099	15,367		83
Combined (boe/d)	7,336	5,771		27	6,911	3,775		83

Daily production for the three months ended December 31, 2012 increased 27% to 7,336 boe/d compared to 5,771 boe/d for the comparative period in 2011. For the year, daily production increased 83% to 6,911 boe/d in 2012 from 3,775 boe/d in 2011. The significant increase in production was due to successful drilling activity at Edson, AB which saw 18.0 gross (13.4 net) wells drilled during 2012 at a 100% success rate. During 2011, 14 gross (11.7 net) wells were drilled at Edson, AB at a 100% success rate. Compared to the previous quarter, daily production increased 6% in Q4 2012 from 6,945 boe/d in Q3 2012.

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

REVENUE	Three Months Ended December 31					Year Ended December 31
($000s)	2012	2011		% Change		2012	2011		% Change
Oil and NGLs	15,389	12,895		19		52,839	33,091		60
Natural gas	9,549	7,496		27		27,679	21,883		26
Total	24,938	20,391		22		80,518	54,974		46
Average Sales Price
Oil and NGLs ($/bbl)	67.55	74.60		(9	)	64.81	74.69		(13	)
Natural gas ($/mcf)	3.56	3.49		2		2.69	3.90		(31	)
Combined ($/boe)	36.95	38.40		(4	)	31.83	39.90		(20	)

Revenue totaled $24.9 million for the fourth quarter of 2012, up 22% from $20.4 million in the comparative period. For the year, revenue increased 46% to $80.5 million in 2012 from $55.0 million in 2011. The increase in revenue was due to significant increases in production, offset by declines in commodity prices.

The following table outlines the Company’s realized wellhead prices and industry benchmarks:

Commodity Pricing	Three Months Ended December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Oil and NGLs
Corporate price ($CDN/bbl)	67.55	74.60		(9	)	64.81	74.69		(13	)
Edmonton par ($CDN/bbl)	84.43	97.87		(14	)	86.57	95.16		(9	)
West Texas Intermediate ($US/bbl)	88.30	94.17		(6	)	94.19	95.00		(1	)
Natural gas
Corporate price ($CDN/mcf)	3.56	3.49		2		2.69	3.90		(31	)
AECO price ($CDN/mcf)	3.22	3.29		(2	)	2.39	3.65		(35	)
Exchange rate
CDN/US dollar average exchange rate	1.0093	0.9799		3		1.0009	1.0123		(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 80.0% and 74.9% of Edmonton Par price for the three months and year ended December 31, 2012, consistent with 76.2% and 78.5% for the comparative periods in 2011. Corporate average natural gas prices were 110.6% and 112.6% of AECO prices for the three months and year ended December 31, 2012, consistent with the comparative period results of 106.1% and 106.8%.

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. During 2012, the Company had 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 year ended December 31, 2012, the realized gain on the oil contract was $3.4 million and the realized loss on the gas contracts was $0.2 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 for cash proceeds of $1.7 million, which was included in the realized gain. For the year ended December 31, 2012, the unrealized loss on the gas contracts was $1.6 million.

Subsequent to December 31, 2012, the Company 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		April 1, 2013 – October 31, 2013		Financial – Put		15,000 GJ/d		AECO CDN $3.000/GJ

ROYALTIES	Three Months Ended December 31					Year Ended December 31
($000s)	2012	2011		% Change		2012	2011		% Change
Oil and NGLs	1,627	1,615		1		7,476	5,625		33
Natural gas	444	236		88		1,435	521		175
Total	2,071	1,851		12		8,911	6,146		45
Average Royalty Rate (% of sales)
Oil and NGLs	10.6	12.5		(15	)	14.1	17.0		(17	)
Natural gas	4.6	3.2		44		5.2	2.4		117
Combined	8.3	9.1		(9	)	11.1	11.2		(1	)

The Company pays royalties to provincial governments (Crown), freeholders, which may be individuals or companies, and other oil and gas companies that own surface or mineral rights. Crown royalties are calculated on a sliding scale based on commodity prices and individual well production rates. Royalty rates can change due to commodity price fluctuations and changes in production volumes on a well-by-well basis, subject to a minimum and maximum rate restriction ascribed by the Crown. The provincial government has also enacted various royalty incentive programs that are available for wells that meet certain criteria, such as natural gas deep drilling, which can result in fluctuations in royalty rates.

For the three months ended December 31, 2012, oil, NGLs, and natural gas royalties increased 12% to $2.1 million from $1.9 million in the comparative period. For the year ended December 31, 2012, oil, NGLs, and natural gas royalties increased to $8.9 million from $6.1 million in 2011. These increases were the result of significant increases in oil, natural gas, and NGLs revenue stemming from increases in production.

The overall effective royalty rate was 8.3% for the three months ended December 31, 2012 compared to 9.1% for the three months ended December 31, 2011. For the year, the overall effective royalty rate was 11.1% in 2012 compared to 11.2% in 2011. The effective oil and NGLs royalty rate decreased as a result of royalty incentive rates received on the successful Edson, AB wells brought on production during the year. The effective natural gas royalty rate increased in 2012 compared to 2011 due mainly to a decrease in the monthly capital cost allowance deductions which effectively reduce gas Crown royalties.

PRODUCTION EXPENSES	Three Months Ended December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Oil and NGLs ($/bbl)	5.96	6.67		(11	)	5.31	7.12		(25	)
Natural gas ($/mcf)	1.11	1.21		(8	)	1.01	1.37		(26	)
Combined ($/boe)	6.41	7.05		(9	)	5.83	7.85		(26	)

Per unit production expenses for the three months ended December 31, 2012 were $6.41/boe, down from $7.05/boe for the comparative period ended December 31, 2011. For the year ended December 31, 2012, per unit production expenses decreased 26% to $5.83/boe from $7.85/boe for the year ended December 31, 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, AB, 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, have allowed the Company to realize lower production expenses through economies of scale. The Company continues to focus on opportunities that will improve operational efficiencies and reduce per boe production expenses to enhance operating netbacks.

TRANSPORTATION EXPENSES	Three Months Ended December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Oil and NGLs ($/bbl)	0.95	0.61		56		0.87	0.74		18
Natural gas ($/mcf)	0.15	0.19		(21	)	0.17	0.18		(6	)
Combined ($/boe)	0.90	0.97		(7	)	0.98	0.95		3

Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended December 31, 2012 compared to the quarter ended December 31, 2011, transportation expenses decreased 7% to $0.90/boe from $0.97/boe. For the year, transportation expenses increased to $0.98/boe in 2012 from $0.95/boe in 2011. The increase in oil and NGLs transportation expenses per boe was due to higher oil transportation expenses. In order to maximize the realized price on oil production, net of transportation expenses, the Company delivered an increased volume of oil to sales points with higher transportation expenses and higher net prices. 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 December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Oil and NGLs ($/bbl)
Revenue	67.55	74.60		(9	)	64.81	74.69		(13	)
Royalties	7.14	9.34		(24	)	9.17	12.70		(28	)
Production expenses	5.96	6.67		(11	)	5.31	7.12		(25	)
Transportation expenses	0.95	0.61		56		0.87	0.74		18
Operating netback	53.50	57.98		(8	)	49.46	54.13		(9	)
Natural gas ($/mcf)
Revenue	3.56	3.49		2		2.69	3.90		(31	)
Royalties	0.17	0.11		55		0.14	0.09		56
Production expenses	1.11	1.21		(8	)	1.01	1.37		(26	)
Transportation expenses	0.15	0.19		(21	)	0.17	0.18		(6	)
Operating netback	2.13	1.98		8		1.37	2.26		(39	)
Combined ($/boe)
Revenue	36.95	38.40		(4	)	31.83	39.90		(20	)
Royalties	3.07	3.49		(12	)	3.52	4.46		(21	)
Production expenses	6.41	7.05		(9	)	5.83	7.85		(26	)
Transportation expenses	0.90	0.97		(7	)	0.98	0.95		3
Operating netback	26.57	26.89		(1	)	21.50	26.64		(19	)

During the fourth quarter of 2012, Crocotta generated an operating netback of $26.57/boe, consistent with an operating netback of $26.89/boe for the fourth quarter of 2011. For the year ended December 31, 2012, Crocotta generated an operating netback of $21.50/boe compared to $26.64/boe in the comparative period. The decrease was mainly due to declines in oil, natural gas, and NGLs commodity prices, offset by a decrease in royalties and operating costs in 2012 compared to 2011. Operating netbacks in Q4 2012 increased from operating netbacks of $17.27/boe in Q3 2012 due to an increase in oil, natural gas, and NGLs commodity prices.

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

	Three Months Ended December 31							Year Ended December 31
($/boe)	2012		2011			% Change		2012		2011			% Change
Operating netback	26.57		26.89			(1	)	21.50		26.64			(19	)
Depletion and depreciation	(13.49	)	(14.87	)		(9	)	(14.50	)	(15.04	)		(4	)
Asset impairment	(11.47	)	(25.79	)		(56	)	(5.31	)	(12.07	)		(56	)
General and administrative expenses	(3.87	)	(3.60	)		8		(2.17	)	(3.90	)		(44	)
Share based compensation	(1.01	)	(1.87	)		(46	)	(1.39	)	(2.29	)		(39	)
Finance expenses	(0.85	)	(0.83	)		2		(0.75	)	(1.06	)		(29	)
Finance income	–		–			–		–		0.10			(100	)
Loss on sale of assets	–		(7.32	)		(100	)	–		(1.87	)		(100	)
Deferred tax reduction (expense)	0.44		14.10			(97	)	(0.07	)	5.43			(101	)
Realized gain (loss) on risk management contracts	(0.59	)	–			100		1.25		–			100
Unrealized gain (loss) on risk management contracts	1.18		–			100		(0.63	)	–			100
Net loss	(3.09	)	(13.29	)		(77	)	(2.07	)	(4.06	)		(49	)
DEPLETION AND DEPRECIATION	Three Months Ended December 31							Year Ended December 31
	2012		2011			% Change		2012		2011			% Change
Depletion and depreciation ($000s)	9,107		7,896			15		36,685		20,729			77
Depletion and depreciation ($/boe)	13.49		14.87			(9	)	14.50		15.04			(4	)

The Company calculates depletion on property, plant, and equipment based on proved plus probable reserves. Plant turnarounds and major overhauls are depreciated over three or four years, depending on each facility. Depletion and depreciation for the three months ended December 31, 2012 was $13.49/boe compared to $14.87/boe in the comparative period. For the year, depletion and depreciation was $14.50/boe in 2012 compared to $15.04/boe in 2011. The decrease in depletion and depreciation per boe was due to a significant increase in reserves as a result of successful capital activity during 2012.

ASSET IMPAIRMENT	Three Months Ended December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Asset impairment ($000s)	7,743	13,695		(43	)	13,439	16,627		(19	)
Asset impairment ($/boe)	11.47	25.79		(56	)	5.31	12.07		(56	)

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 year ended December 31, 2012, total exploration and evaluation asset impairments of $4.7 million were recognized. Asset impairments of $2.4 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGU – Miscellaneous AB). Additional exploration and evaluation impairments of $2.3 million were recognized in 2012 relating to the expiry of undeveloped land rights (CGUs – Lookout Butte AB, Miscellaneous AB, and Saskatchewan).

For the year ended December 31, 2011, total exploration and evaluation asset impairments of $13.7 million were recognized. Asset impairments of $12.5 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGUs – Miscellaneous AB and Saskatchewan). Of this $12.5 million impairment, $12.2 million related to unsuccessful exploration drilling activities in Southern Alberta during the year. Additional exploration and evaluation impairments of $1.2 million were recognized in 2011 relating to the expiry of undeveloped land rights (CGUs – Northeast BC and Miscellaneous AB).

For the year ended December 31, 2012, the Company recorded property, plant, and equipment impairments of $8.7 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices and limited capital expenditures in these CGUs to maintain their reserve values.

For the year ended December 31, 2011, the Company recorded an impairment charge of $3.0 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices at December 31, 2011. As well, the Company had limited capital expenditures in these CGUs to maintain their reserve values.

GENERAL AND ADMINISTRATIVE	Three Months Ended December 31							Year Ended December 31
($000s)	2012		2011			% Change		2012		2011			% Change
G&A expenses (gross)	3,076		2,832			9		7,020		7,388			(5	)
G&A capitalized	(195	)	(277	)		(30	)	(435	)	(535	)		(19	)
G&A recoveries	(272	)	(642	)		(58	)	(1,098	)	(1,482	)		(26	)
G&A expenses (net)	2,609		1,913			36		5,487		5,371			2
G&A expenses ($/boe)	3.87		3.60			8		2.17		3.90			(44	)

General and administrative expenses (“G&A”) increased to $3.87/boe for the fourth quarter of 2012 compared to $3.60/boe for the fourth quarter of 2011. The increase was mainly due to a decline in G&A recoveries in the fourth quarter of 2012 compared to the fourth quarter of 2011. For the year, net G&A expenses in 2012 were consistent with 2011. On a boe basis, G&A expenses of $2.17/boe in 2012 were down significantly from G&A expenses of $3.90/boe in 2011 as a result of a significant increase in production.

SHARE BASED COMPENSATION	Three Months Ended December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Share based compensation ($000s)	684	992		(31	)	3,512	3,156		11
Share based compensation ($/boe)	1.01	1.87		(46	)	1.39	2.29		(39	)

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 $1.01/boe and $1.39/boe, respectively, for the three months and year ended December 31, 2012 from $1.87/boe and $2.29/boe in the comparative periods, respectively. During 2012, the Company granted 0.7 million options (2011 – 4.2 million). The decrease in share based compensation per boe is a result of a significant increase in production.

FINANCE EXPENSES	Three Months Ended December 31					Year Ended December 31
($000s)	2012	2011		% Change		2012	2011		% Change
Interest expense	452	256		77		1,449	861		68
Accretion of decommissioning obligations	120	184		(35	)	453	516		(12	)
Realized loss on investments	–	–		–		–	79		(100	)
Finance expenses	572	440		30		1,902	1,456		31
Finance expenses ($/boe)	0.85	0.83		2		0.75	1.06		(29	)

Interest expense relates mainly 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 2012 compared to 2011. At December 31, 2012, $68.5 million (2011 – $5.2 million) had been drawn on the Company’s credit facility.

Investments included 875,000 warrants of Hyperion Exploration Corp. (“Hyperion”) at an exercise price of $2.00 per warrant. Each warrant was convertible into one common share of Hyperion and expired unexercised on November 7, 2011. The warrants were obtained as partial consideration for the sale of certain oil and natural gas assets to Hyperion in the fourth quarter of 2010. The investment was measured at fair value each reporting period using the Black-Scholes-Merton option pricing model. A realized loss was recognized in 2011 upon expiry of the warrants.

LOSS ON SALE OF ASSETS	Three Months Ended December 31					Year Ended December 31
	2012	2011		% Change		2012	2011		% Change
Loss on sale of assets ($000s)	–	3,885		(100	)	–	2,578		(100	)
Loss on sale of assets ($/boe)	–	7.32		(100	)	–	1.87		(100	)

During 2011, the Company recognized a net loss on sale of assets of $2.6 million. A loss on sale of assets of $3.9 million was recognized during the fourth quarter relating to the disposition of certain non-core oil and natural gas assets located in the Miscellaneous AB CGU while additional losses of $1.5 million were recognized during the first half of 2011 on the disposition of certain non-producing assets in the Northeast BC CGU. These losses were offset by a gain on sale of assets of $2.8 million during the third quarter relating to dispositions of non-core oil and natural gas assets in Smoky AB and Miscellaneous AB CGUs.

DEFERRED INCOME TAX EXPENSE

Deferred income tax expense on the loss before taxes was $0.2 million in 2012 (2011 – $7.5 million income tax reduction). This was larger than expected by applying the statutory tax rate to the loss before taxes due mainly to flow-through shares and share based compensation and other non-deductible amounts.

Estimated tax pools at December 31, 2012 total approximately $299.6 million (2011 – $251.0 million).

FUNDS FROM OPERATIONS

Funds from operations for the three months and year ended December 31, 2012 were $14.5 million ($0.16 per diluted share) and $50.6 million ($0.56 per diluted share), respectively, compared to $12.1 million ($0.14 per diluted share) and $30.6 million ($0.38 per diluted share) for the three months and year ended December 31, 2011, respectively. The increase was mainly due to an increase in revenue in 2012 as a result of a significant increase in production.

The following is a reconciliation of cash flow from operating activities to funds from operations for the periods noted:

		Three Months Ended December 31						Year Ended December 31
($000s)		2012	2011			% Change		2012	2011		% Change
Cash flow from operating activities (GAAP)		12,096	12,825			(6	)	47,449	29,291		62
Add back:
	Decommissioning expenditures	113	187			(40	)	734	363		102
	Change in non-cash working capital	2,269	(897	)		353		2,432	954		155
Funds from operations (non-GAAP)		14,478	12,115			20		50,615	30,608		65

NET LOSS

The Company had a net loss of $2.1 million ($0.02 per diluted share) for the three months ended December 31, 2012 compared to a net loss of $7.1 million ($0.09 per diluted share) for the three months ended December 31, 2011. For the year, the Company had a net loss of $5.3 million ($0.06 per diluted share) in 2012 compared to a net loss of $5.6 million ($0.07 per diluted share) in 2011. The net loss in 2012 and 2011 arose mainly due to asset impairments recorded on non-core properties due to declines in commodity prices, limited capital activity in these non-core areas to maintain reserve values, and exploration and evaluation activities determined to be uneconomical.

CAPITAL EXPENDITURES	Three Months Ended December 31						Year Ended December 31
($000s)	2012	2011			% Change		2012	2011			% Change
Land	2,701	1,908			42		7,107	3,161			125
Drilling, completions, and workovers	27,504	27,775			(1	)	74,663	73,611			1
Equipment	5,781	6,069			(5	)	15,949	14,302			12
Geological and geophysical	334	1,054			(68	)	829	1,939			(57	)
Property acquisitions	5,406	–			100		5,406	1,704			217
Other	–	–			–		–	69			(100	)
Exploration and development	41,726	36,806			13		103,954	94,786			10
Property dispositions	–	(4,541	)		(100	)	–	(14,552	)		(100	)
Net capital expenditures (dispositions)	41,726	32,265			29		103,954	80,234			30

For the three months ended December 31, 2012, the Company had net capital expenditures of $41.7 million compared to net capital expenditures of $32.3 million for the three months ended December 31, 2011. For the year ended December 31, 2012, the Company had net capital expenditures of $104.0 million compared to net capital expenditures of $80.2 million for the comparative period in 2011. The increase in exploration and development expenditures in 2012 was due mainly to an increase in capital activity in the Company’s core Edson, AB area. During 2012, Crocotta drilled a total of 21 (16.0 net) wells, which resulted in 12 (7.8 net) oil wells, 8 (7.2 net) liquids-rich natural gas wells, and 1 (1.0 net) exploratory well in a non-core area that was uneconomic. During 2011, Crocotta drilled a total of 20 (15.9 net) wells, which resulted in 4 (3.0 net) oil wells, 13 (10.9 net) liquids-rich natural gas wells, and 3 (2.0 net) exploratory wells in non-core areas that were uneconomic.

During 2011, the Company sold certain non-core oil and natural gas assets from the Smoky AB, Northeast BC, and Miscellaneous AB CGUs for cash proceeds of $14.6 million. The sale of these properties in 2011 allowed the Company to reduce net debt and focus capital spending on its two core areas, Edson Bluesky/Cardium and Dawson Montney.

LIQUIDITY AND CAPITAL RESOURCES

The Company had net debt of $80.1 million at December 31, 2012 compared to net debt of $27.7 million at December 31, 2011. The increase of $52.4 million was mainly due to $104.0 million used for the purchase and development of oil and natural gas properties and equipment and $0.7 million for decommissioning expenditures, offset by funds from operations of $50.6 million and share issuances of $1.7 million on the exercise of stock options and warrants during 2012.

At December 31, 2012, the Company had a $100.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At December 31, 2012, $68.5 million (December 31, 2011 – $5.2 million) had been drawn on the revolving credit facility. In addition, at December 31, 2012, the Company had outstanding letters of guarantee of approximately $1.5 million (December 31, 2011 – $1.0 million) which reduce the amount that can be borrowed under the credit facility. Subsequent to December 31, 2012, the Company signed an agreement to increase the revolving credit facility to $140.0 million. The next review of the revolving credit facility by the bank is scheduled on or before June 1, 2013.

In February 2011, the Company issued approximately 15.6 million common shares at a price of $2.30 per share for gross proceeds of approximately $36.0 million. In December 2011, the Company issued approximately 7.2 million common shares for gross proceeds of approximately $25.0 million. Under the December issuance, approximately 6.0 million common shares were issued at a price of $3.35 per share and approximately 1.2 million common shares were issued on a flow-through basis at a price of $4.00 per share. The proceeds were used to fund Crocotta’s Edson Bluesky/Cardium and Dawson Montney developments, other capital projects, and for general corporate purposes.

During 2011, the Company sold certain non-core oil and natural gas properties for cash proceeds of approximately $14.6 million. The proceeds of the dispositions were mainly used to reduce net debt and focus capital spending on its two core areas, Edson Bluesky/Cardium and Dawson Montney.

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, during the second quarter of 2012 the Company obtained an increase to its revolving credit facility from $80.0 million to $100.0 million, and subsequent to December 31, 2012, the Company obtained an increase to its revolving credit facility from $100.0 million to $140.0 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 December 31, 2012:

($000s)	Total		Less than One Year		One to Three Years		After Three Years
Accounts payable and accrued liabilities	29,165		29,165		–		–
Revolving credit facility	68,480		68,480		–		–
Risk management contracts	1,592		1,592		–		–
Decommissioning obligations	21,852		49		138		21,665
Office leases	850		484		366		–
Field equipment leases	1,726		1,276		450		–
Firm transportation agreements	298		158		129		11
Total contractual obligations	123,963		101,204		1,083		21,676

Subsequent to December 31, 2012, the Company entered into farm-in agreements to drill and complete three Edson Cardium wells. Under the terms of the farm-in agreements, the Company is committed to spud one well prior to April 2013 and the remaining two wells prior to August 2013. The estimated total cost to drill and complete the wells is approximately $9.5 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)	December 31, 2012	March 25, 2013
Voting common shares	89,261	89,261
Stock options	8,601	8,606
Warrants	2,321	2,321
Total	100,183	100,188

SUMMARY OF QUARTERLY RESULTS
		Q4 2012		Q3 2012		Q2 2012	Q1 2012		Q4 2011		Q3 2011	Q2 2011	Q1 2011
Average Daily Production
Oil and NGLs (bbls/d)		2,476		2,103		2,053	2,277		1,879		1,336	1,039	586
Natural gas (mcf/d)		29,160		29,053		27,309	26,852		23,354		15,996	11,843	10,124
Combined (boe/d)		7,336		6,945		6,604	6,752		5,771		4,002	3,012	2,274
($000s, except per share amounts)
Oil and natural gas sales		24,938		17,922		17,518	20,140		20,391		14,814	12,289	7,480
Funds from operations		14,478		10,888		12,275	12,974		12,115		9,551	6,927	2,014
	Per share – basic	0.16		0.12		0.14	0.15		0.15		0.12	0.09	0.03
	Per share – diluted	0.16		0.12		0.14	0.14		0.14		0.11	0.08	0.03
Net earnings (loss)		(2,082	)	(3,944	)	1,065	(293	)	(7,052	)	5,535	374	(4,449	)
	Per share – basic and diluted	(0.02	)	(0.04	)	0.01	–		(0.09	)	0.07	–	(0.06	)

A significant increase in production stemming from successful drilling activity during the previous two years resulted in substantial increases in revenue and funds from operations in Q4 2011 through Q4 2012 compared to prior quarters. The Company had a net loss in four of the five previous quarters mainly as a result of asset impairments recognized in each quarter on non-core properties.

2013 OUTLOOK

The information below represents Crocotta’s guidance for 2013, publicly released on January 31, 2013, based on management’s best estimates and the assumptions noted below.

Estimated Average Daily Production		Guidance 2013
Oil and NGLs (bbls/d)		3,100
Natural gas (mcf/d)		37,300
Total (boe/d)		9,300
Exit production (boe/d)		10,500
Estimated Financial Results		Guidance 2013
Oil and natural gas sales ($000s)		120,000
Funds from operations ($000s)		70,500
	$ per share – basic (1)	0.79
	$ per share – diluted (2)	0.70
Capital expenditures ($000s)		100,000
West Texas Intermediate ($US/bbl)		90.00
AECO Daily Spot Price ($CDN/mcf)		3.38
US/CDN Dollar Average Exchange Rate		1.00

(1)	Based on 89.3 million common shares outstanding
(2)	Based on 89.3 million common shares, 8.6 million options, and 2.3 million warrants outstanding

Sensitivity Analysis

The outlook is based on estimates of key external market factors. Crocotta’s actual results will be affected by fluctuations in commodity prices as well as the U.S./Canadian dollar exchange rate. The following table provides a summary of estimates for 2013 of the sensitivity of Crocotta’s funds from operations to changes in commodity prices and the U.S./Canadian dollar exchange rate.

	Guidance 2013	Variance in Factor	Funds from Operations
West Texas Intermediate ($US/bbl)	90.00	1.00	350,000
AECO Daily Spot Price ($CDN/mcf)	3.38	0.10	990,000
US/CDN Dollar Average Exchange Rate	1.00	0.01	615,000

2012 OUTLOOK

The information below represents Crocotta’s guidance for 2012, publicly released on February 9, 2012, and a comparison to actual results for 2012:

Estimated Average Daily Production	Guidance 2012	Actual 2012	% Change
Oil and NGLs (bbls/d)	2,205	2,227	1
Natural gas (mcf/d)	30,870	28,099	(9	)
Total (boe/d)	7,350	6,911	(6	)
Exit production (boe/d)	8,500	8,500	–

Estimated Financial Results		Guidance 2012	Actual 2012	% Change
Oil and natural gas sales ($000s)		110,000	80,518	(27	)
Funds from operations ($000s)		70,000	50,615	(28	)
	$ per share – basic (1)	0.79	0.57	(28	)
	$ per share – diluted (2)	0.70	0.56	(20	)
Capital expenditures ($000s)		86,800	103,954	20
West Texas Intermediate ($US/bbl)		97.00	94.19	(3	)
AECO Daily Spot Price ($CDN/mcf)		3.49	2.39	(32	)
US/CDN Dollar Average Exchange Rate		0.98	1.00	2

(1)	Guidance based on 88.1 million common shares outstanding
(2)	Guidance based on 88.1 million common shares, 8.6 million options, and 3.5 million warrants outstanding

During 2012, actual oil, NGLs, and natural gas commodity prices were significantly lower than the Company’s guidance. This resulted in actual revenue and funds from operations in 2012 being lower than guidance. Due to lower commodity prices during the middle half of 2012, the Company shifted gas-weighted capital projects to the fourth quarter. This shift resulted in a lower average daily production compared to guidance and also contributed to actual revenue and funds from operations being lower than guidance. Exit guidance of 8,500 boe/d was successfully achieved. Actual capital expenditures in 2012 exceeded budget as a result of property acquisitions, land acquisitions, and new farm-in opportunities as a result of the success of the Edson Cardium.

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 following summarizes the Company’s significant critical accounting estimates.

Oil and natural gas reserves

The Company engages a qualified, independent oil and gas reserves evaluator to perform an estimation of the amount of the Company’s oil and natural gas reserves at least annually. Reserves form the basis for the calculation of depletion and assessment of impairment of oil and natural gas assets. Reserves are estimated using the definitions of reserves prescribed by National Instrument 51-101 and the Canadian Oil and Gas Evaluation Handbook.

Proved plus probable reserves are defined as the estimated quantities of crude oil, natural gas liquids including condensate, and natural gas that geological and engineering data demonstrate a 50 percent probability of being recovered at the reported level. Due to the inherent uncertainties and the necessarily limited nature of reservoir data, estimates of reserves are inherently imprecise, require the application of judgment, and are subject to change as additional information becomes available. The estimates are made using all available geological and reservoir data as well as historical production data. Estimates are reviewed and revised as appropriate. Revisions occur as a result of changes in prices, costs, fiscal regimes, reservoir performance, or changes in the Company’s plans.

Impairment testing

Exploration and evaluation assets

Exploration and evaluation assets are assessed for impairment (i) if sufficient data exists to determine technical feasibility and commercial viability, (ii) if facts and circumstances suggest that the carrying amount exceeds the recoverable amount, and (iii) upon transfer to property, plant, and equipment. For purposes of impairment testing, exploration and evaluation assets are allocated to CGUs. Impairment tests by their nature involve estimates and judgment, which for exploration and evaluation assets include estimates of proved and probable reserves found, the market value of undeveloped land, and future development plans. Crocotta allocated its exploration and evaluation assets to specific CGUs for the purpose of impairment testing.

Property, plant, and equipment

For the purpose of impairment testing, items of property, plant, and equipment, which includes oil and natural gas development and production assets, are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (CGU). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell. The Company uses fair value less costs to sell for its impairment tests which is determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion prospects, and its eventual disposal, using assumptions that an independent market participant may take into account. These cash flows are discounted by an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU. The significant estimates and judgments include proved plus probable reserves, the estimated value of those reserves, including future commodity prices, the discount rate used to present value the estimated future cash flows, and other assumptions that an independent market participant may take into account, including acquisition metrics of recent transactions for similar assets.

Decommissioning obligations

Decommissioning obligations are estimated based on existing laws, contracts, or other policies. Decommissioning obligations are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation as at the reporting date. Subsequent to the initial measurement, the obligation is adjusted at the end of each reporting period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as accretion whereas increases or decreases due to changes in the estimated future cash flows or changes in the discount rate are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

Share based compensation

Measurement of compensation cost attributable to the Company’s share based compensation plan is subject to the estimation of fair value using the Black-Scholes-Merton option pricing model. The valuation is based on significant assumptions including the estimated forfeiture rate, the expected volatility (based on the weighted average historic volatility adjusted for changes expected due to publicly available information), the weighted average expected life of the instrument (based on historical experience and general information), the expected dividends, and the risk free interest rate (based on government bonds).

Deferred income taxes

The determination of the Company’s income taxes requires interpretation of complex laws and regulations. Tax interpretations, regulations, and legislation in the various jurisdictions in which the Company operates are subject to change. Deferred income tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.

FUTURE CHANGES IN ACCOUNTING 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. The adoption of these standards is not expected to have a significant impact on the amounts recorded in the Company’s consolidated financial statements.

IFRS 10, Consolidated Financial Statements replaces IAS 27, Consolidated Separate Financial Statements. It introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.

IFRS 11, Joint Arrangements replaces IAS 31, Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A “joint operation” continues to be accounted for using proportionate consolidation, whereas a “joint venture” must be accounted for using equity accounting. This differs from IAS 31, where there was the choice to use proportionate consolidation or equity accounting for joint ventures. A “joint operation” is defined as the joint operators having rights to the assets, and obligations for the liabilities, relating to the arrangement. In a “joint venture”, the joint venture partners have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity.

IFRS 12, Disclosure of Interests in Other Entities is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.

IFRS 13, Fair Value Measurement is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.

IAS 27, Separate Financial Statements has been amended to focus solely on accounting and disclosure requirements when an entity presents separate financial statements, due to the issuance of the new IFRS 10 which is specific to consolidated financial statements.

IAS 28, Investments in Associates and Joint Ventures has been amended as a result of the issuance of IFRS 11 and the withdrawal of IAS 31. The amended standard sets out the requirements for the application of the equity method when accounting for interest in joint ventures, in addition to interests in associates.

In November 2009, the IASB published IFRS 9, Financial Instruments, which covers the classification and measurement of financial assets as part of its project to replace IAS 39, Financial Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company’s own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively. The Company does not anticipate this standard to have a material impact on 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 2012, the Company had 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 year ended December 31, 2012, the realized gain on the oil contract was $3.4 million and the realized loss on the gas contracts was $0.2 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 for cash proceeds of $1.7 million, which was included in the realized gain. For the year ended December 31, 2012, the unrealized loss on the gas contracts was $1.6 million.

Subsequent to December 31, 2012, the Company entered into the following commodity price contract:

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		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 December 31, 2012, $14.0 million or 87.3% of the Company’s outstanding accounts receivable were current while $2.0 million or 12.7% were outstanding over 90 days but not impaired. During the year ended December 31, 2012, the Company expensed $0.3 million in outstanding accounts receivable deemed 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.

MANAGEMENT’S RESPONSIBILITY FOR FINANCIAL STATEMENTS

The Management of Crocotta Energy Inc. is responsible for the preparation of the consolidated financial statements. The consolidated financial statements have been prepared in accordance with International Financial Reporting Standards and include certain estimates that reflect Management’s best estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the consolidated financial statements are presented fairly in all material respects.

Management is responsible for the integrity of the consolidated financial statements. Internal control systems are designed and maintained to provide reasonable assurance that assets are safeguarded from loss or unauthorized use and to produce reliable accounting records for financial reporting purposes.

KPMG LLP were appointed by the Company’s shareholders to express an audit opinion on the consolidated financial statements. Their examination included such tests and procedures, as they considered necessary, to provide a reasonable assurance that the consolidated financial statements are presented fairly in accordance with International Financial Reporting Standards.

The Board of Directors is responsible for ensuring that Management fulfills its responsibilities for financial reporting and internal control. The Board of Directors exercises this responsibility through the Audit Committee, with assistance from the Reserves Committee regarding the annual review of our oil and natural gas reserves. The Audit Committee meets regularly with Management and the Auditors to ensure that Management’s responsibilities are properly discharged, to review the consolidated financial statements and recommend that the consolidated financial statements be presented to the Board of Directors for approval. The Audit Committee also considers the independence of KPMG LLP and reviews their fees. The Auditors have access to the Audit Committee without the presence of Management.

Rob Zakresky

President, Chief Executive Officer and Director

Nolan Chicoine

Vice President, Finance and Chief Financial Officer

Calgary, Canada

March 25, 2013

INDEPENDENT AUDITORS’ REPORT

To the Shareholders of Crocotta Energy Inc.

We have audited the accompanying consolidated financial statements of Crocotta Energy Inc., which comprise the consolidated statements of financial position as at December 31, 2012 and December 31, 2011, the consolidated statements of operations and comprehensive loss, shareholders’ equity and cash flows for the years then ended, and notes, comprising a summary of significant accounting policies and other explanatory information.

Management’s Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with International Financial Reporting Standards and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors’ Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we comply with ethical requirements and plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on our judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, we consider internal control relevant to the entity’s preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained in our audits is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of Crocotta Energy Inc. as at December 31, 2012 and December 31, 2011, and its consolidated financial performance and its consolidated cash flows for the years then ended in accordance with International Financial Reporting Standards.

signed “KPMG LLP”

Chartered Accountants

March 25, 2013

Calgary, Canada

Crocotta Energy Inc.
Consolidated Statements of Financial Position
($000s)		Note		December 31 2012		December 31 2011
Assets
Current assets
	Accounts receivable			15,983		11,298
	Prepaid expenses and deposits			1,550		840
				17,533		12,138
Property, plant, and equipment		(6	)	241,703		192,332
Exploration and evaluation assets		(5	)	28,302		20,641
Deferred income taxes		(14	)	13,442		14,443
				283,447		227,416
				300,980		239,554
Liabilities
Current liabilities
	Accounts payable and accrued liabilities			29,165		34,692
	Revolving credit facility	(7	)	68,480		5,182
	Risk management contracts	(16	)	1,592		–
				99,237		39,874
Decommissioning obligations		(8	)	21,852		19,250
Flow-through share premium		(9	)	–		813
				121,089		59,937
Shareholders’ Equity
	Shareholders’ capital	(9	)	228,277		225,848
	Contributed surplus			12,026		8,927
	Deficit			(60,412	)	(55,158	)
				179,891		179,617
Subsequent events		(7,16,20	)
				300,980		239,554

The accompanying notes are an integral part of these consolidated financial statements.

Approved on behalf of the Board of Directors

Director, Rob Zakresky

Director, Larry Moeller

Crocotta Energy Inc.
Consolidated Statements of Operations and Comprehensive Loss
				Year Ended December 31
($000s, except per share amounts)		Note		2012		2011
Revenue
	Oil and natural gas sales			80,518		54,974
	Royalties			(8,911	)	(6,146	)
				71,607		48,828
	Realized gain on risk management contracts	(16	)	3,166		–
	Unrealized loss on risk management contracts	(16	)	(1,592	)	–
				73,181		48,828
Expenses
	Production			14,743		10,811
	Transportation			2,479		1,309
	Depletion and depreciation	(6	)	36,685		20,729
	Asset impairment	(5,6	)	13,439		16,627
	General and administrative			5,487		5,371
	Share based compensation	(10	)	3,512		3,156
				76,345		58,003
Operating loss				(3,164	)	(9,175	)
Other Expenses (Income)
	Finance expense	(13	)	1,902		1,456
	Finance income			–		(132	)
	Loss on sale of assets			–		2,578
				1,902		3,902
Loss before taxes				(5,066	)	(13,077	)
Taxes
	Deferred income tax expense (reduction)	(14	)	188		(7,485	)
Net loss and comprehensive loss				(5,254	)	(5,592	)
Net loss per share
	Basic and diluted			(0.06	)	(0.07	)

The accompanying notes are an integral part of these consolidated financial statements.

Crocotta Energy Inc.
Consolidated Statements of Shareholders’ Equity
			Year Ended December 31
($000s)	Note		2012		2011
Shareholders’ Capital
Balance, beginning of year			225,848		168,164
Issue of shares (net of share issue costs and flow-through share premium)			–		57,491
Issued on exercise of stock options	(9	)	17		114
Issued on exercise of warrants	(9	)	1,680		–
Share based compensation – exercised	(9	)	732		79
Balance, end of year			228,277		225,848
Contributed Surplus
Balance, beginning of year			8,927		5,515
Share based compensation – expensed			3,512		3,156
Share based compensation – capitalized			319		335
Share based compensation – exercised			(732	)	(79	)
Balance, end of year			12,026		8,927
Deficit
Balance, beginning of year			(55,158	)	(49,566	)
Net loss			(5,254	)	(5,592	)
Balance, end of year			(60,412	)	(55,158	)
Total Shareholders’ Equity			179,891		179,617

The accompanying notes are an integral part of these consolidated financial statements.

Crocotta Energy Inc.
Consolidated Statements of Cash Flows
				Year Ended December 31
($000s)		Note		2012		2011
Operating Activities
	Net loss			(5,254	)	(5,592	)
	Depletion and depreciation	(6	)	36,685		20,729
	Asset impairment	(5,6	)	13,439		16,627
	Share based compensation	(10	)	3,512		3,156
	Finance expense	(13	)	1,902		1,456
	Interest paid			(1,449	)	(861	)
	Loss on sale of assets			–		2,578
	Deferred income tax expense (reduction)	(14	)	188		(7,485	)
	Unrealized loss on risk management contracts	(16	)	1,592		–
	Decommissioning expenditures	(8	)	(734	)	(363	)
	Change in non-cash working capital	(19	)	(2,432	)	(954	)
				47,449		29,291
Financing Activities
	Issuance of shares	(9	)	1,697		61,077
	Share issue costs	(9	)	–		(3,545	)
	Revolving credit facility	(7	)	63,298		(30,204	)
				64,995		27,328
Investing Activities
	Capital expenditures – property, plant, and equipment	(6	)	(54,756	)	(63,567	)
	Capital expenditures – exploration and evaluation assets	(5	)	(49,198	)	(31,219	)
	Asset dispositions			–		14,552
	Change in non-cash working capital	(19	)	(8,490	)	23,615
				(112,444	)	(56,619	)
Change in cash and cash equivalents				–		–
Cash and cash equivalents, beginning of year				–		–
Cash and cash equivalents, end of year				–		–

The accompanying notes are an integral part of these consolidated financial statements.

Crocotta Energy Inc.

Notes to the Consolidated Financial Statements Year Ended December 31, 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 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^th Avenue SW, Calgary, Alberta, Canada, T2P 0M9.

2. BASIS OF PRESENTATION

(a) Statement of compliance

These consolidated financial statements have been prepared in accordance with International Financial Reporting Standards (“IFRS”).

The consolidated financial statements were authorized for issuance by the Board of Directors on March 25, 2013.

(b) Basis of measurement

The consolidated financial statements have been prepared on the historical cost basis except for risk management contracts, which are measured at fair value. The methods used to measure fair value are discussed in note 4.

(c) Functional and presentation currency

These 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 consolidated financial statements in conformity with IFRS requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities as at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the year. These judgments, estimates, and assumptions are based on current trends and all relevant information available to the Company at the time of preparation of the consolidated financial statements. As the effect of future events cannot be determined with certainty, the actual results may differ from the estimated amounts.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognized in the period in which the estimates are revised and in any future periods affected.

Significant estimates and judgments made by management in the preparation of these consolidated financial statements are outlined below.

Critical accounting judgments

The following are critical judgments that the Company has made in the process of applying accounting policies and that have the most significant effect on the amounts recognized in the consolidated financial statements.

Cash generating units (“CGU”)

The Company’s assets are aggregated into CGUs for the purposes of calculating depletion and depreciation and impairment. CGUs are determined based on the smallest group of assets that generate cash flows independent of other assets or groups of assets. Determination of the CGUs is subject to the Company’s judgment and is based on geographical proximity, shared infrastructure, similar exposure to market risk, and materiality.

Impairment

Judgments are required to assess when impairment indicators exist and impairment testing is required. In determining the recoverable amount of assets, in the absence of quoted market prices, impairment tests are based on estimates of reserves, production rates, future oil and natural gas prices, future costs, discount rates, market value of land, and other relevant assumptions.

Exploration and evaluation assets

The application of the Company’s accounting policy for exploration and evaluation assets requires the Company to make certain judgments as to future events and circumstances as to whether economic quantities of reserves will be found so as to assess if technical feasibility and commercial viability has been achieved.

Deferred taxes

Judgments are made by the Company to determine the likelihood of whether deferred income tax assets at the end of the reporting period will be realized from future taxable earnings.

Significant estimates

The following are key estimates and assumptions made by the Company affecting the measurement of balances and transactions in the consolidated financial statements.

Recoverability of asset carrying values

The recoverability of development and production asset carrying values is assessed at a CGU level. The key estimates used in the determination of cash flows from oil and natural gas reserves include the following:

(i)	Reserves – Assumptions that are valid at the time of reserve estimation may change significantly when new information becomes available. Changes in forward price estimates, production costs, or recovery rates may change the economic status of reserves and may ultimately result in reserves being restated.
(ii)	Oil and natural gas prices – Forward price estimates are used in the cash flow model. Commodity prices can fluctuate for a variety of reasons including supply and demand fundamentals, inventory levels, exchange rates, weather, and economic and geopolitical factors.
(iii)	Discount rate – The discount rate used to calculate the net present value of cash flows is based on estimates of an approximate industry peer group weighted average cost of capital. Changes in the general economic environment could result in significant changes to this estimate.

The key assumptions used in the impairment tests are described in note 6.

Depletion and depreciation

Amounts recorded for depletion and depreciation and amounts used for impairment calculations are based on estimates of total proved and probable oil and natural gas reserves and future development capital. By their nature, the estimates of reserves, including the estimates of future prices, costs, and future cash flows, are subject to measurement uncertainty. Accordingly, the impact to the consolidated financial statements in future periods could be material.

Decommissioning obligations

Amounts recorded for decommissioning obligations and the related accretion expense requires the use of estimates with respect to the amount and timing of decommissioning expenditures. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations, market conditions, discovery and analysis of site conditions and changes in technology. Other provisions are recognized in the period when it becomes probable that there will be a future cash outflow.

Share based compensation

Compensation costs recognized for share based compensation plans are subject to the estimation of what the ultimate value will be using pricing models such as the Black-Scholes-Merton model, which is based on significant assumptions such as volatility, expected term, and forfeiture rate.

Derivatives

The Company’s estimate of the fair value of derivative financial instruments is dependent on estimated forward prices and volatility in those prices.

Deferred taxes

Deferred taxes are based on estimates as to the timing of the reversal of temporary differences, substantively enacted tax rates, and the likelihood of assets being realized. Tax interpretations, regulations, and legislation in the various jurisdictions in which the Company operates are subject to change. As such, income taxes are subject to measurement uncertainty.

3. SIGNIFICANT ACCOUNTING POLICIES

The accounting policies set out below have been applied consistently by the Company and its subsidiary to all periods presented in these consolidated financial statements.

(a) Basis of consolidation

Subsidiaries

Subsidiaries are entities controlled by the Company. Control exists when the Company has the power to govern the financial and operating policies of an entity so as to obtain benefits from its activities. In assessing control, potential voting rights that currently are exercisable are taken into account. The financial statements of subsidiaries are included in the consolidated financial statements from the date that control commences until the date that control ceases.

Jointly controlled operations and jointly controlled assets

Many of the Company’s oil and natural gas activities involve jointly controlled assets. The consolidated financial statements include the Company’s share of these jointly controlled assets and a proportionate share of the relevant revenue and related costs.

Transactions eliminated on consolidation

Intercompany balances and transactions, and any unrealized income and expenses arising from intercompany transactions, are eliminated in preparing the consolidated financial statements.

(b) Financial instruments Non-derivative financial instruments

Non-derivative financial instruments comprise cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, and credit facility. Non-derivative financial instruments are recognized initially at fair value net of any directly attributable transaction costs. Subsequent to initial recognition, non-derivative financial instruments are measured as described below.

Cash and cash equivalents

Cash and cash equivalents comprise cash on hand, term deposits held with banks, and other short-term highly liquid investments with original maturities of three months or less, measured at amortized cost.

Other

Other non-derivative financial instruments, such as accounts receivable, accounts payable and accrued liabilities, and credit facility, are measured at amortized cost using the effective interest method, less any impairment losses.

Derivative financial instruments

From time to time, the Company may enter into certain financial derivative contracts in order to manage the exposure to market risks from fluctuations in commodity prices. These instruments are not used for trading or speculative purposes. The Company does not designate financial derivative contracts as effective accounting hedges, and thus does not apply hedge accounting, even though the Company considers all commodity contracts to be economic hedges. As a result, all financial derivative contracts are classified as fair value through profit or loss and are recorded on the statement of financial position at fair value. Transaction costs are recognized in profit or loss when incurred.

Share capital

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares are recognized as a deduction from equity, net of any tax effects.

(c) Property, plant, and equipment and exploration and evaluation assets

Recognition and measurement

Exploration and evaluation expenditures

Pre-license costs are recognized in profit or loss as incurred.

Exploration and evaluation costs, including the costs of acquiring undeveloped land and drilling costs, are initially capitalized until the drilling of the well is complete and the results have been evaluated. The costs are accumulated in cost centers by well, field, or exploration area pending determination of technical feasibility and commercial viability. The technical feasibility and commercial viability of extracting a mineral resource is considered to be determinable when proved or probable reserves are determined to exist. If proved or probable reserves are found, the accumulated costs and associated undeveloped land are transferred to property, plant, and equipment after assessing estimated fair value and recognizing any impairment loss.

Exploration and evaluation assets are assessed for impairment if (i) sufficient data exists to determine technical feasibility and commercial viability, and (ii) facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For purposes of impairment testing, exploration and evaluation assets are allocated to CGUs.

Development and production costs

Items of property, plant, and equipment, which include oil and natural gas development and production assets, are measured at cost less accumulated depletion and depreciation and accumulated impairment losses. The cost of development and production assets includes: transfers from exploration and evaluation assets, which generally include the cost to drill the well and the cost of the associated land upon determination of technical feasibility and commercial viability; the cost to complete and tie-in the well; facility costs; the cost of recognizing provisions for future restoration and decommissioning obligations; geological and geophysical costs; and directly attributable overhead.

Development and production assets are grouped into CGUs for impairment testing. The Company has grouped its development and production assets into the following six CGUs: (i) Edson AB (ii) Smoky AB (iii) Northeast BC (iv) Lookout Butte AB (v) Miscellaneous AB, and (vi) Saskatchewan.

When significant parts of an item of property, plant, and equipment, including oil and natural gas interests, have different useful lives, they are accounted for as separate items (major components). The Company capitalizes the cost of major plant turnarounds and overhauls and depreciates these costs over their estimated useful life of three or four years, depending on each plant.

Gains and losses on disposal of an item of property, plant, and equipment, including oil and natural gas interests, are determined by comparing the proceeds from disposal with the carrying amount of property, plant, and equipment and are recognized in profit or loss.

Subsequent costs

Costs incurred subsequent to the determination of technical feasibility and commercial viability and the costs of replacing parts of property, plant, and equipment are recognized as oil and natural gas interests only when they increase the future economic benefits embodied in the specific asset to which they relate. Capitalized oil and natural gas interests generally represent costs incurred in developing proved or probable reserves and bringing in or enhancing production from such reserves and are accumulated on a field or geotechnical area basis. The carrying amount of any replaced or sold component is derecognized. The costs of the day-to-day servicing of property, plant, and equipment are recognized in operating expenses as incurred.

Non-monetary asset swaps

Exchanges or swaps of property, plant, and equipment are measured at fair value unless the exchange transaction lacks commercial substance or neither the fair value of the assets given up nor the assets received can be reliably estimated. The cost of the acquired asset is measured at the fair value of the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is measured at the carrying amount of the asset given up. Any gain or loss on derecognition of the asset given up is included in profit or loss.

Exchanges or parts of exchanges that involve principally exploration and evaluation assets are measured at the carrying amount of the asset exchanged, reduced by the amount of any cash consideration received. No gain or loss is recognized unless the cash consideration received exceeds the carrying value of the asset held.

Depletion and depreciation

The net carrying value of development and production assets is depleted using the unit of production method by reference to the ratio of production in the period to the related proved plus probable reserves, taking into account the estimated future development costs necessary to bring those reserves into production and the estimated salvage value of the assets at the end of their useful lives. Future development costs are estimated taking into account the level of development required to produce the reserves.

Proved plus probable reserves are estimated at least annually by independent qualified reserve evaluators and represent the estimated quantities of oil, natural gas, and natural gas liquids which geological, geophysical, and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible.

The Company has determined the estimated useful lives for gas processing plants, pipeline facilities, and compression facilities to be consistent with the reserve lives of the areas for which they serve. As such, the Company includes the cost of these assets within their associated CGU for the purpose of depletion using the unit of production method. For plant turnarounds and overhauls, the Company has estimated an average useful life of three or four years, depending on each plant, before further work must be performed and depreciates these costs using the straight-line method over the corresponding useful life.

The cost of office and other equipment is depreciated using the straight-line method over the estimated useful life of three years.

Depreciation methods, useful lives, and residual values are reviewed at each reporting date.

Leased assets

Leases wherein the Company assumes substantially all the risks and rewards of ownership are classified as finance leases, when applicable. Upon initial recognition, the leased asset is measured at an amount equal to the lower of its fair value and the present value of the minimum lease payments. Subsequent to initial recognition, the asset is accounted for in accordance with the accounting policy applicable to that asset. Minimum lease payments made under finance leases are apportioned between the finance expenses and the reduction of the outstanding liability. The finance expenses are allocated to each year during the lease term so as to produce a constant periodic rate of interest on the remaining balance of the liability. Other leases are classified as operating leases, which are not recognized on the Company’s statement of financial position. Payments made under operating leases are recognized in profit or loss on a straight-line basis over the term of the lease. The Company’s presently outstanding leases have been determined to be operating leases.

(d) Impairment

Financial assets

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimated future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortized cost is calculated as the difference between its carrying amount and the present value of the estimated future cash flows discounted at the original effective interest rate.

Individually significant financial assets are tested for impairment on an individual basis. The remaining financial assets are assessed collectively in groups that share similar credit risk characteristics. All impairment losses are recognized in profit or loss. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognized. For financial assets measured at amortized cost, the reversal is recognized in profit or loss.

Non-financial assets

The carrying amounts of the Company’s non-financial assets, other than exploration and evaluation assets and deferred tax assets, are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists, then the asset’s recoverable amount is estimated. Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount.

For the purpose of impairment testing, assets are grouped together into the smallest group of assets that generate cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (CGU). The recoverable amount of an asset or a CGU is the greater of its value in use and its fair value less costs to sell.

Fair value less costs to sell is determined as the amount that would be obtained from the sale of a CGU in an arm’s length transaction between knowledgeable and willing parties. The fair value less costs to sell of oil and natural gas assets is generally determined as the net present value of the estimated future cash flows expected to arise from the continued use of the CGU, including any expansion projects and its eventual disposal, using assumptions that an independent market participant may take into account. The cash flows are discounted using an appropriate discount rate which would be applied by such a market participant to arrive at a net present value of the CGU. Consideration is given to acquisition metrics of recent transactions completed on similar assets to those contained within the relevant CGU.

Value in use is determined as the net present value of the estimated future cash flows expected to arise from the continued use of the asset in its present form and its eventual disposal. Value in use is determined by applying assumptions specific to the Company’s continued use and can only take into account approved future development costs. Estimates of future cash flows used in the evaluation of impairment of assets are made using management’s forecasts of commodity prices and expected production volumes. The latter takes into account assessments of field reservoir performance and includes expectations about proved and unproved volumes, which are risk-weighted using geological, production, recovery, and economic projections.

An impairment loss is recognized if the carrying amount of a CGU exceeds its estimated recoverable amount. Impairment losses are recognized in profit or loss. Impairment losses recognized in respect of CGUs are allocated to the assets in the CGUs on a pro rata basis. Impairment losses recognized in prior periods are assessed each reporting date if facts or circumstances indicate that the loss has decreased or no longer exists. An impairment loss is reversed if there has been a change in the estimates used to determine the recoverable amount. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depletion and depreciation, if no impairment loss had been recognized.

(e) Share based compensation

The Company has a share based compensation plan, which is described in note 10. The Company uses the fair value method for valuing share based compensation. Under this method, the compensation cost attributed to stock options is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus. A forfeiture rate is estimated on the grant date and is adjusted to reflect the actual number of options that vest. Upon the settlement of the stock options, the previously recognized value in contributed surplus is recorded as an increase to share capital.

(f) Provisions

A provision is recognized if, as a result of a past event, the Company has a present legal or constructive obligation that can be estimated reliably, and it is probable that an outflow of economic benefits will be required to settle the obligation. Provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability. Provisions are not recognized for future operating losses.

Decommissioning obligations

The Company’s activities give rise to dismantling, decommissioning, and site disturbance remediation activities. A provision is made for the estimated cost of abandonment and site restoration and capitalized in the relevant asset category. The capitalized amount is depreciated on a unit of production basis over the life of the associated proved plus probable reserves. Decommissioning obligations are measured at the present value of management’s best estimate of the expenditure required to settle the present obligation at the reporting date. Subsequent to the initial measurement, the obligation is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the obligation. The increase in the provision due to the passage of time is recognized as accretion (within finance expenses) whereas increases or decreases due to changes in the estimated future cash flows or changes in the discount rate are capitalized. Actual costs incurred upon settlement of the decommissioning obligations are charged against the provision to the extent the provision was established.

(g) Revenue

Revenue from the sale of oil and natural gas is recorded when the significant risks and rewards of ownership of the product are transferred to the buyer which is usually when legal title passes to the external party.

(h) Finance income and expenses

Finance income and expenses comprises interest expense, including interest on credit facility, accretion on decommissioning obligations, realized gains and losses on investments, and interest income.

(i) Income tax

Income tax expense is comprised of current and deferred tax. Income tax expense is recognized in profit or loss except to the extent that it relates to items recognized directly in equity, in which case it is recognized in equity.

Current tax is the expected tax payable on the taxable income for the year, using tax rates enacted or substantively enacted at the reporting date, and any adjustment to tax payable in respect of previous years.

Deferred tax is recognized on the temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. Deferred tax is not recognized on the initial recognition of assets or liabilities in a transaction that is not a business combination. In addition, deferred tax is not recognized for taxable temporary differences arising on the initial recognition of goodwill. Deferred tax is measured at the tax rates that are expected to be applied to temporary differences when they reverse, based on the laws that have been enacted or substantively enacted by the reporting date. Deferred tax assets and liabilities are offset if there is a legally enforceable right to offset, they relate to income taxes levied by the same tax authority on the same taxable entity, or on different tax entities, but they intend to settle current tax liabilities and assets on a net basis, or their tax assets and liabilities will be realized simultaneously.

A deferred tax asset is recognized to the extent that it is probable that future taxable earnings will be available against which the temporary difference can be utilized. Deferred tax assets are reviewed at each reporting date and are reduced to the extent that it is no longer probable that the related tax benefit will be realized.

(j) Flow-through shares

The Company, from time to time, issues flow-through shares to finance a portion of its exploration capital expenditure program. Pursuant to the terms of the flow-through share agreements, the tax deductions associated with the exploration expenditures are renounced to the subscribers. On issuance of flow-through shares, the premium received on such shares, being the difference between the fair value ascribed to flow-through shares issued and the fair value that would have been received for common shares at the date of issuance of the flow-through shares, is recognized as a liability on the statement of financial position. When the exploration expenditures are incurred, the liability is drawn down, a deferred tax liability is recorded equal to the estimated amount of deferred income tax payable by the Company as a result of the foregone tax benefits, and the difference is recognized in profit or loss.

(k) Earnings per share

Basic earnings per share is calculated by dividing the net earnings or loss attributable to common shareholders of the Company by the weighted average number of common shares outstanding during the period. Diluted earnings per share is determined by adjusting the weighted average number of common shares outstanding during the period for the effects of dilutive instruments such as stock options granted.

(l) New standards and interpretations not yet adopted

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. The adoption of these standards is not expected to have a significant impact on the amounts recorded in the Company’s consolidated financial statements.

IFRS 10, Consolidated Financial Statements replaces IAS 27, Consolidated Separate Financial Statements. It introduces a new principle-based definition of control, applicable to all investees to determine the scope of consolidation. The standard provides the framework for consolidated financial statements and their preparation based on the principle of control.

IFRS 11, Joint Arrangements replaces IAS 31, Interests in Joint Ventures. IFRS 11 divides joint arrangements into two types, each having its own accounting model. A “joint operation” continues to be accounted for using proportionate consolidation, whereas a “joint venture” must be accounted for using equity accounting. This differs from IAS 31, where there was the choice to use proportionate consolidation or equity accounting for joint ventures. A “joint operation” is defined as the joint operators having rights to the assets, and obligations for the liabilities, relating to the arrangement. In a “joint venture”, the joint venture partners have rights to the net assets of the arrangement, typically through their investment in a separate joint venture entity.

IFRS 12, Disclosure of Interests in Other Entities is a new standard, which combines all of the disclosure requirements for subsidiaries, associates and joint arrangements, as well as unconsolidated structured entities.

IFRS 13, Fair Value Measurement is a new standard meant to clarify the definition of fair value, provide guidance on measuring fair value and improve disclosure requirements related to fair value measurement.

IAS 27, Separate Financial Statements has been amended to focus solely on accounting and disclosure requirements when an entity presents separate financial statements, due to the issuance of the new IFRS 10 which is specific to consolidated financial statements.

IAS 28, Investments in Associates and Joint Ventures has been amended as a result of the issuance of IFRS 11 and the withdrawal of IAS 31. The amended standard sets out the requirements for the application of the equity method when accounting for interest in joint ventures, in addition to interests in associates.

In November 2009, the IASB published IFRS 9, Financial Instruments, which covers the classification and measurement of financial assets as part of its project to replace IAS 39, Financial Instruments: Recognition and Measurement. In October 2010, the requirements for classifying and measuring financial liabilities were added to IFRS 9. Under this guidance, entities have the option to recognize financial liabilities at fair value through earnings. If this option is elected, entities would be required to reverse the portion of the fair value change due to a company’s own credit risk out of earnings and recognize the change in other comprehensive income. IFRS 9 is effective for the Company on January 1, 2015. Early adoption is permitted and the standard is required to be applied retrospectively. The Company does not anticipate this standard to have a material impact on the consolidated financial statements.

4. DETERMINATION OF FAIR VALUES

A number of the Company’s accounting policies and disclosures require the determination of fair value, for both financial and non- financial assets and liabilities. Fair values have been determined for measurement and disclosure purposes based on the following methods. When applicable, further information about the assumptions made in determining fair values is disclosed in the notes specific to that asset or liability.

Property, plant, and equipment and exploration and evaluation assets

The fair value of property, plant, and equipment and exploration and evaluation assets recognized in a business combination, is based on market values. The market value of property, plant, and equipment and exploration and evaluation assets is the estimated amount for which the assets could be exchanged on the acquisition date between a willing buyer and a willing seller in an arm’s length transaction after proper marketing wherein the parties had each acted knowledgeably, prudently, and without compulsion. The market value of property, plant, and equipment is estimated with reference to the discounted cash flows expected to be derived from oil and natural gas production based on externally prepared reserve reports. The risk-adjusted discount rate used to discount the expected cash flows is specific to the asset with reference to general market conditions.

The market value of other items of property, plant, and equipment is based on the quoted market prices for similar items.

Stock options

The fair value of stock options is measured using a Black-Scholes-Merton option pricing model. Measurement inputs include the share price on the measurement date, exercise price of the instrument, estimated forfeiture rate, expected volatility (based on the weighted average historic volatility adjusted for changes expected due to publicly available information), weighted average expected life of the instrument (based on historical experience and general information), expected dividends, and the risk free interest rate (based on government bonds).

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).

5. EXPLORATION AND EVALUATION ASSETS

		Total
Balance, December 31, 2010		31,405
	Additions	31,644
	Transfer to property, plant, and equipment	(24,153	)
	Transfer to property, plant, and equipment, held for sale	(479	)
	Dispositions	(4,109	)
	Impairment	(13,667	)
Balance, December 31, 2011		20,641
	Additions	49,198
	Transfer to property, plant, and equipment	(36,838	)
	Impairment	(4,699	)
Balance, December 31, 2012		28,302

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 year, consisting primarily of undeveloped land and drilling costs until the drilling of the well is complete and the results have been evaluated. Included in the $49.2 million in additions during the year ended December 31, 2012 were additions of $33.1 million related to the Edson AB CGU, $9.4 million related to the Miscellaneous AB CGU, and $6.4 million related to the Northeast BC CGU. Transfers to property, plant, and equipment during the year ended December 31, 2012 included $31.9 million from the Edson AB CGU and $4.9 million from the Northeast BC CGU as a result of successful capital activity in the Company’s core areas.

Included in the $31.6 million in additions during the year ended December 31, 2011 were additions of $17.8 million related to the Edson AB CGU, $11.3 million related to the Miscellaneous AB CGU, and $1.8 million related to the Northeast BC CGU. Transfers to property, plant, and equipment during the year ended December 31, 2011 included $17.8 million from the Edson AB CGU and $6.3 million from the Northeast BC CGU as a result of successful capital activity in the Company’s core areas.

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 year ended December 31, 2012, total exploration and evaluation asset impairments of $4.7 million were recognized. Asset impairments of $2.4 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGU – Miscellaneous AB). Additional exploration and evaluation impairments of $2.3 million were recognized in 2012 relating to the expiry of undeveloped land rights (CGUs – Lookout Butte AB, Miscellaneous AB, and Saskatchewan).

 

For the year ended December 31, 2011, total exploration and evaluation asset impairments of $13.7 million were recognized. Asset impairments of $12.5 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGUs – Miscellaneous AB and Saskatchewan). Of this $12.5 million impairment, $12.2 million related to unsuccessful exploration drilling activities in Southern Alberta during the year. Additional exploration and evaluation impairments of $1.2 million were recognized in 2011 relating to the expiry of undeveloped land rights (CGUs – Northeast BC and Miscellaneous AB).

 

6. PROPERTY, PLANT, AND EQUIPMENT

Cost		Total
Balance, December 31, 2010		164,459
	Additions	63,567
	Transfer from exploration and evaluation assets	24,153
	Transfer from property, plant, and equipment, held for sale	1,879
	Transfer to property, plant, and equipment, held for sale	(1,076	)
	Dispositions	(21,410	)
	Change in decommissioning obligation estimates	4,939
	Capitalized share based compensation	335
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
Accumulated Depletion, Depreciation, and Impairment		Total
Balance, December 31, 2010		29,544
	Depletion and depreciation	20,729
	Impairment	2,960
	Transfer to property, plant, and equipment, held for sale	(441	)
	Dispositions	(8,278	)
Balance, December 31, 2011		44,514
	Depletion and depreciation	36,685
	Impairment	8,740
Balance, December 31, 2012		89,939
Net Book Value		Total
December 31, 2010		134,915
December 31, 2011		192,332
December 31, 2012		241,703

During the year ended December 31, 2012, approximately $0.4 million (2011 – $0.8 million) 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 year ended December 31, 2012 included an estimated $231.8 million (2011 – $202.6 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $11.4 million (2011 – $7.8 million) for the estimated salvage value of production equipment and facilities.

Impairments

Impairment tests were carried out at December 31, 2012 and were based on fair value less costs to sell calculations using the
following commodity price estimates of the Company’s independent reserve evaluators:

Year	West Texas Intermediate Oil ($US/bbl	)		Foreign Exchange Rate		Edmonton Oil Par Price ($CDN/bbl	)		AECO Gas Price ($CDN/mmbtu	)
2013	90.00			1.000		85.00			3.38
2014	92.50			1.000		91.50			3.83
2015	95.00			1.000		94.00			4.28
2016	97.50			1.000		96.50			4.72
2017	97.50			1.000		96.50			4.95
2018	97.50			1.000		96.50			5.22
2019	98.54			1.000		97.54			5.32
2020	100.51			1.000		99.51			5.43
2021	102.52			1.000		101.52			5.54
2022	104.57			1.000		103.57			5.64
Escalate
Thereafter	2.0% per year					2.0% per year			2.0% per year

The impairment tests at December 31, 2012 were primarily based on the net present value of cash flows from oil and natural gas reserves of each CGU at discount rates of 10 percent to 20 percent. Consideration was also given to acquisition metrics of recent transactions on similar assets. For the year ended December 31, 2012, the Company recorded property, plant, and equipment impairments of $8.7 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices and limited capital expenditures in these CGUs to maintain their reserve values.

For the year ended December 31, 2011, the Company recorded an impairment charge of $3.0 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices at December 31, 2011. As well, the Company had limited capital expenditures in these CGUs to maintain their reserve values.

7. CREDIT FACILITY

At December 31, 2012, the Company had a $100.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At December 31, 2012, $68.5 million (December 31, 2011 – $5.2 million) had been drawn on the revolving credit facility. In addition, at December 31, 2012, the Company had outstanding letters of guarantee of approximately $1.5 million (December 31, 2011 – $1.0 million) which reduce the amount that can be borrowed under the credit facility. Subsequent to December 31, 2012, the Company signed an agreement to increase the revolving credit facility to $140.0 million. The next review of the revolving credit facility by the bank is scheduled on or before June 1, 2013.

8. PROVISIONS – DECOMMISSIONING OBLIGATIONS

The Company’s decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company’s net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and facilities, and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation at 2% per year) required to settle the decommissioning obligations is approximately $29.6 million which is estimated to be incurred over the next 28 years. At December 31, 2012, a risk-free rate of 2.3% (December 31, 2011 – 2.4%) was used to calculate the net present value of the decommissioning obligations.

		Year Ended December 31, 2012		Year Ended December 31, 2011
Balance, beginning of year		19,250		15,099
	Provisions incurred	2,208		1,534
	Provisions disposed	–		(941	)
	Provisions settled	(734	)	(363	)
	Revisions	675		3,405
	Accretion	453		516
Balance, end of year		21,852		19,250

9. SHAREHOLDERS’ CAPITAL

The Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, and Class B preferred shares, issuable in series. No non-voting common shares or preferred shares have been issued.

Voting Common Shares		Number		Amount
Balance, December 31, 2010		65,142		168,164
	Exercise of stock options	97		193
	Share issuances	22,856		60,963
	Share issue costs, net of future tax effect of $0.9 million			(2,659	)
	Flow-through share premium			(813	)
Balance, December 31, 2011		88,095		225,848
	Exercise of stock options	13		29
	Exercise of warrants	1,200		2,400
	Expiry of sunset clauses	(47	)	–
Balance, December 31, 2012		89,261		228,277

On February 23, 2011, the Company issued approximately 15.6 million common shares at a price of $2.30 per share for gross proceeds of approximately $36.0 million.

On December 21, 2011, the Company issued approximately 7.2 million common shares for gross proceeds of approximately $25.0 million. Under the issuance, approximately 6.0 million common shares were issued at a price of $3.35 per share and approximately 1.2 million common shares were issued on a flow-through basis at a price of $4.00 per share. Under the terms of the flow-through share agreement, the Company was committed to spend 100% of the gross proceeds on qualifying exploration expenditures prior to December 31, 2012. Upon issuance, the premium received on the flow-through shares, being the difference between the fair value of the flow-through shares issued and the fair value that would have been received for common shares at the date of issuance, was recognized as a liability. The Company fulfilled the flow-through share commitment during 2012.

Proceeds from the share issuances were used to fund the Company’s Edson Bluesky and Dawson Montney developments, other capital projects, and general corporate purposes.

10. SHARE BASED COMPENSATION PLANS

Stock options

The Company has authorized and reserved for issuance 8.9 million common shares under a stock option plan enabling certain officers, directors, employees, and consultants to purchase common shares. The Company will not issue options exceeding 10% of the shares outstanding at the time of the option grants. Under the plan, the exercise price of each option equals the market price of the Company’s shares on the date of the grant. The options vest over a period of three years and an option’s maximum term is 5 years. At December 31, 2012, 8.6 million options are outstanding at exercise prices ranging from $1.10 to $3.46 per share.

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

		Number of Options		Weighted Average Exercise Price ($	)
Balance, December 31, 2010		3,877		1.26
	Granted	4,197		2.60
	Exercised	(97	)	1.18
	Forfeited	(35	)	1.53
Balance, December 31, 2011		7,942		1.97
	Granted	713		3.43
	Exercised	(13	)	1.30
	Forfeited	(41	)	2.51
Balance, December 31, 2012		8,601		2.09

The following table summarizes the stock options outstanding and exercisable at December 31, 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	3,642	1.9	1.24	3,286	1.21
$2.01 to $3.00	4,264	3.2	2.59	1,488	2.57
$3.01 to $3.46	695	4.1	3.46	–	–
	8,601	2.7	2.09	4,774	1.64

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 Warrants		Weighted Average Exercise Price
Balance, December 31, 2010 and December 31, 2011		3,521		3.64
	Exercised	(1,200	)	1.40
Balance, December 31, 2012		2,321		4.80

The following table summarizes the warrants outstanding and exercisable at December 31, 2012:

		Warrants Outstanding and Exercisable
Exercise Price	Number	Weighted Average Remaining Life	Weighted Average Exercise Price
$3.75 to $4.05	740	1.0	3.76
$4.50 to $5.25	807	1.0	4.55
$6.00 to $6.75	774	1.0	6.05
	2,321	1.0	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 was estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions:

	December 31, 2012	December 31, 2011
Risk-free interest rate (%)	1.3	2.3
Expected life (years)	4.0	4.0
Expected volatility (%)	77.2	82.8
Expected dividend yield (%)	–	–
Forfeiture rate (%)	7.4	9.4
Weighted average fair value of options granted ($ per option)	1.96	1.59

11. PER SHARE AMOUNTS

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

	December 31, 2012	December 31, 2011
Weighted average number of shares – basic and diluted	88,319	78,804

For the years ended December 31, 2012 and 2011, the stock options and warrants outstanding were anti-dilutive and were not included in the diluted loss per share calculation.

12. KEY MANAGEMENT PERSONNEL

The Company considers its directors and executives to be key management personnel. The key management personnel compensation is comprised of the following:

	Year Ended	Year Ended
	December 31, 2012	December 31, 2011
Short-term wages and benefits	2,511	2,827
Share based compensation (1)	2,645	2,610
Total (2) (3)	5,156	5,437

(1)	Represents the amortization of share based compensation expense associated with the Company’s share based compensation plans granted to key management personnel.
(2)	Balances outstanding and payable at December 31, 2012 were $0.5 million (2011 – $1.0 million).
(3)	At December 31, 2012 and 2011, key management personnel included 16 individuals.

13. FINANCE EXPENSES

Finance expenses include the following:

	December 31, 2012	December 31, 2011
Interest expense (note 7)	1,449	861
Accretion of decommissioning obligations (note 8)	453	516
Realized loss on investments	–	79
Finance expenses	1,902	1,456

14. INCOME TAXES

(a) The provision for income taxes in the consolidated statement of operations and comprehensive loss reflects an effective tax rate which differs from the expected statutory tax rate. The differences were accounted for as follows:

		December 31, 2012		December 31, 2011
Loss before taxes		(5,066	)	(13,077	)
Statutory income tax rate		25.0	%	26.5	%
Expected income tax reduction		(1,267	)	(3,465	)
Increase (decrease) in income taxes resulting from:
	Share based compensation and other non-deductible amounts	878		837
	Flow-through shares	1,250		–
	Rate reduction and other	19		181
	Recognition (derecognition) of previously unrecognized (recognized) tax assets	121		(5,038	)
		1,001		(7,485	)
	Flow-through share premium	(813	)	–
		188		(7,485	)

The decrease in the statutory tax rate from 2011 to 2012 was due to a reduction in the 2012 Canadian corporate tax rate as part of a series of corporate rate reductions previously enacted by the Canadian government. The Company has recognized a net deferred tax asset based on the independently evaluated reserve report as cash flows are expected to be sufficient to realize the deferred tax asset.

(b) Recognized deferred tax balances for the years ended December 31, 2012 and 2011 are as follows:

2012		Balance January 1, 2012		Recognized in Earnings or Loss			Recognized in Equity		Balance December 31, 2012
Deferred income tax assets (liabilities):
	Oil and natural gas properties and equipment	1,120		(1,839	)		–		(719	)
	Decommissioning obligations	4,812		651			–		5,463
	Risk management contracts	–		398			–		398
	Share issue costs	745		(211	)		–		534
	Non-capital losses	7,766		–			–		7,766
Net deferred income tax asset		14,443		(1,001	)		–		13,442

2011		Balance January 1, 2011			Recognized in Earnings or Loss			Recognized in Equity		Balance December 31, 2011
Deferred income tax assets (liabilities):
	Oil and natural gas properties and equipment	(435	)		1,555			–		1,120
	Decommissioning obligations	3,775			1,037			–		4,812
	Share issue costs	119			(260	)		886		745
	Non-capital losses	2,613			5,153			–		7,766
Net deferred income tax asset		6,072			7,485			886		14,443

At December 31, 2012, the Company has estimated federal tax pools of $299.6 million (2011 – $251.0 million) available for deduction against future taxable income.

The Company has accumulated non-capital losses for income tax purposes of approximately $31.1 million (2011 – $31.1 million), which can be used to offset income in future periods. These losses are as follows:

Year of expiry		Amount
2029		248
2028		903
2027		8,121
2026		6,744
2025		8,066
2024		2,209
2023		4,772
		31,063
(c) Deferred tax assets have not been recognized in respect of the following items:
	2012	2011
Deductible temporary differences	8,100	7,617
Capital losses	1,797	1,797
	9,897	9,414

The capital losses and the deductible temporary differences do not expire under current tax legislation. Deferred tax assets have not been recognized in respect of these items because it is not probable that future taxable profits will be available against which the Company can utilize the benefits.

In 2012, $0.1 million of previously recognized tax losses were derecognized as a result of changes in estimates of future results from operating activities. In 2011, $5.0 million of previously unrecognized tax losses were recognized as a result of changes in estimates of future results from operating activities.

15. FAIR VALUE OF FINANCIAL INSTRUMENTS

Cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, credit facility

The fair value of cash and cash equivalents, accounts receivable, and accounts payable and accrued liabilities at December 31, 2012 approximated their carrying value due to their short term to maturity.

The fair value of the revolving credit facility approximates its carrying value as it bears interest at floating rates and the premium charged is indicative of the Company’s current credit spreads.

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 December 31, 2012 is measured using level 2. During the year ended December 31, 2012, there were no transfers between level 1, level 2, and level 3 classified assets and liabilities.

16. FINANCIAL RISK MANAGEMENT

The Company’s activities expose it to a variety of financial risks that arise as a result of its exploration, development, production, and financing activities. The Company employs risk management strategies and policies to ensure that any exposure to risk is in compliance with the Company’s business objectives and risk tolerance levels. Risk management is ultimately established by the Board of Directors and is implemented by management.

Market 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 oil, natural gas, and NGLs are primarily determined in reference to US dollars, but are settled with the Company in Canadian dollars. The Company’s cash flow from commodity sales will therefore be impacted by fluctuations in foreign exchange rates. Assuming that all other variables remain constant, a $0.01 increase or decrease in the Canadian/US dollar exchange rate would have impacted net loss and comprehensive loss by approximately $0.5 million for the year ended December 31, 2012 (2011 – $0.4 million).

Interest rate risk

The Company is exposed to interest rate risk as it borrows funds at floating interest rates (note 7). In addition, the Company may at times issue shares on a flow-through basis (note 9). This results in the Company being exposed to interest rate risk to the Canada Revenue Agency for interest on unexpended funds on the Company’s flow-through share obligations. The Company currently does not use interest rate hedges or fixed interest rate contracts to manage the Company’s exposure to interest rate fluctuations. A 100 basis point increase or decrease in interest rates would have impacted net loss and comprehensive loss by approximately $0.4 million for the year ended December 31, 2012 (2011 – $0.2 million).

Commodity price risk

Oil and natural gas prices are impacted by not only the relationship between the Canadian and US dollar but also by world economic events that dictate the levels of supply and demand. The Company’s oil, natural gas, and NGLs production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company’s cash flow from product sales will therefore be impacted by fluctuations in commodity prices. A $1.00/boe increase or decrease in commodity prices would have impacted net loss and comprehensive loss by approximately $1.7 million for the year ended December 31, 2012 (2011 – $0.9 million).

During 2012, the Company had 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 year ended December 31, 2012, the realized gain on the oil contract was $3.4 million and the realized loss on the gas contracts was $0.2 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 for cash proceeds of $1.7 million, which was included in the realized gain. For the year ended December 31, 2012, the unrealized loss on the gas contracts was $1.6 million.

Subsequent to December 31, 2012, the Company entered into the following commodity price contract:

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		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 December 31, 2012, $14.0 million or 87.3% of the Company’s outstanding accounts receivable were current while $2.0 million or 12.7% were outstanding over 90 days but not impaired. During the year ended December 31, 2012, the Company expensed $0.3 million in outstanding accounts receivable deemed 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.

The following are the contractual maturities of financial liabilities at December 31, 2012:

		Carrying Amount		Contractual Cash Flows	Less than One Year	One to Two Years	More than Two Years
Non-derivative financial liabilities
	Accounts payable and accrued liabilities	29,165		29,165	29,165	–	–
	Revolving credit facility	68,480		68,480	68,480	–	–
Derivative financial liabilities
	Risk management contracts	1,592		1,592	1,592	–	–
		99,237		99,237	99,237	–	–

17. CAPITAL MANAGEMENT

The Company’s objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at an acceptable risk, and to maintain investor, creditor, and market confidence to sustain future development of the business.

The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include shareholders’ equity and net debt (current liabilities, including the revolving credit facility and excluding risk management contracts, less current assets). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt, or adjust its capital spending to manage its current and projected debt levels.

	December 31, 2012	December 31, 2011
Shareholders’ equity	179,891	179,617
Net debt	80,112	27,736

In addition, management prepares annual, quarterly, and monthly budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment.

The Company’s share capital is not subject to external restrictions; however, the Company’s revolving operating demand loan credit facility includes a covenant requiring the Company to maintain a working capital ratio of not less than one-to-one. The working capital ratio, as defined by its creditor, is calculated as current assets plus any undrawn amounts available on its credit facility less current liabilities excluding any current portion drawn on the credit facility. The Company was fully compliant with this covenant at December 31, 2012.

There were no changes in the Company’s approach to capital management from the previous year.

18. SUPPLEMENTAL DISCLOSURES

Presentation of expenses

The Company’s statement of operations is prepared primarily by nature of expense, with the exception of employee compensation costs which are included in both production and general and administrative expenses. Included in production and general and administrative expenses for the year ended December 31, 2012 are $0.1 million and $4.3 million of wages and benefits, respectively (2011 – $0.1 million and $4.7 million, respectively).

18. SUPPLEMENTAL CASH FLOW INFORMATION

		December 31, 2012		December 31, 2011
Accounts receivable		(4,685	)	(1,139	)
Prepaid expenses and deposits		(710	)	38
Accounts payable and accrued liabilities		(5,527	)	23,762
Change in non-cash working capital		(10,922	)	22,661
Relating to:
	Investing	(8,490	)	23,615
	Operating	(2,432	)	(954	)
Change in non-cash working capital		(10,922	)	22,661

20. COMMITMENTS

The following is a summary of the Company’s contractual obligations and commitments at December 31, 2012:

	2013		2014		2015		2016		2017		Thereafter		Total
Office leases	484		366		–		–		–		–		850
Field equipment leases	1,276		450		–		–		–		–		1,726
Firm transportation agreements	158		101		28		10		1		–		298
Risk management contracts	1,592		–		–		–		–		–		1,592
	3,510		917		28		10		1		–		4,466

Subsequent to December 31, 2012, the Company entered into farm-in agreements to drill and complete three Edson Cardium wells. Under the terms of the farm-in agreements, the Company is committed to spud one well prior to April 2013 and the remaining two wells prior to August 2013. The estimated total cost to drill and complete the wells is approximately $9.5 million.

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
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
www.crocotta.ca