Crocotta Energy Inc.: Q3 2013 Financial and Operating Results

CALGARY, ALBERTA--(Marketwired - Nov. 13, 2013) - CROCOTTA ENERGY INC. ( CTA.TO ) is pleased to announce its financial and operating results for the three and nine months ended September 30, 2013, including condensed interim consolidated financial statements, notes to the condensed interim consolidated financial statements, and Management's Discussion and Analysis. All dollar figures are Canadian dollars unless otherwise noted.

HIGHLIGHTS

• Increased production 24% to 8,596 boe/d in Q3 2013 from 6,945 boe/d in Q3 2012

• Increased funds from operations 48% to $16.1 million in Q3 2013 from $10.9 million in Q3 2012

• Entered into a $145 million syndicated credit facility

FINANCIAL RESULTS
		Three Months Ended September 30						Nine Months Ended September 30
($000s, except per share amounts)		2013		2012		% Change		2013		2012		% Change
Oil and natural gas sales		26,950		17,922		50		80,369		55,580		45
Funds from operations (1)		16,102		10,888		48		47,506		36,137		31
	Per share - basic	0.17		0.12		42		0.52		0.41		27
	Per share - diluted	0.16		0.12		33		0.50		0.40		25
Net earnings (loss)		975		(3,944	)	125		7,183		(3,172	)	326
	Per share - basic and diluted	0.01		(0.04	)	125		0.08		(0.04	)	300
Capital expenditures		48,911		23,540		108		94,611		62,228		52
Net debt (2)								105,518		54,436		94
Common shares outstanding (000s)
	Weighted average - basic	95,978		88,103		9		91,954		88,097		4
	Weighted average - diluted	97,969		90,586		8		94,114		90,915		4
	End of period - basic							96,098		88,104		9
	End of period - diluted							107,919		100,229		8

(1)	Funds from operations and funds from operations per share do not have any standardized meaning prescribed by International Financial Reporting Standards ("IFRS") and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details and the Funds from Operations section in the MD&A for a reconciliation from cash flow from operating activities.
(2)	Net debt includes current liabilities (excluding risk management contracts) and the credit facility 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 September 30						Nine Months Ended September 30
		2013		2012		% Change		2013		2012		% Change
Daily production
	Oil and NGLs (bbls/d)	2,497		2,103		19		2,448		2,144		14
	Natural gas (mcf/d)	36,593		29,053		26		36,624		27,743		32
	Oil equivalent (boe/d)	8,596		6,945		24		8,552		6,768		26
Revenue
	Oil and NGLs ($/bbl)	79.85		56.78		41		70.61		63.75		11
	Natural gas ($/mcf)	2.56		2.60		(2	)	3.32		2.39		39
	Oil equivalent ($/boe)	34.08		28.05		21		34.42		29.97		15
Royalties
	Oil and NGLs ($/bbl)	6.89		11.97		(42	)	8.19		9.96		(18	)
	Natural gas ($/mcf)	0.04		0.12		(67	)	0.09		0.13		(31	)
	Oil equivalent ($/boe)	2.18		4.13		(47	)	2.75		3.69		(25	)
Production expenses
	Oil and NGLs ($/bbl)	6.03		5.00		21		5.92		5.06		17
	Natural gas ($/mcf)	1.12		1.00		12		1.13		0.98		15
	Oil equivalent ($/boe)	6.51		5.72		14		6.53		5.62		16
Transportation expenses
	Oil and NGLs ($/bbl)	1.93		0.51		278		1.35		0.84		61
	Natural gas ($/mcf)	0.18		0.19		(5	)	0.13		0.18		(28	)
	Oil equivalent ($/boe)	1.31		0.93		41		0.93		1.01		(8	)
Operating netback (1)
	Oil and NGLs ($/bbl)	65.00		39.30		65		55.15		47.89		15
	Natural gas ($/mcf)	1.22		1.29		(5	)	1.97		1.10		79
	Oil equivalent ($/boe)	24.08		17.27		39		24.21		19.65		23
Depletion and depreciation ($/boe)		(14.13	)	(15.14	)	(7	)	(13.78	)	(14.87	)	(7	)
Asset impairment ($/boe)		(0.28	)	(3.77	)	(93	)	(0.23	)	(3.07	)	(93	)
General and administrative expenses ($/boe)		(1.41	)	(1.29	)	9		(1.83	)	(1.55	)	18
Share based compensation ($/boe)		(0.56	)	(1.17	)	(52	)	(0.60	)	(1.52	)	(61	)
Finance expenses ($/boe)		(1.76	)	(0.72	)	144		(1.38	)	(0.72	)	92
Deferred tax reduction (expense) ($/boe)		(4.31	)	1.40		(408	)	(2.73	)	(0.26	)	950
Realized gain (loss) on risk management contracts ($/boe)		(0.74	)	1.60		(146	)	(0.83	)	1.92		(143	)
Unrealized gain (loss) on risk management contracts ($/boe)		0.34		(4.36	)	108		0.25		(1.29	)	119
Net earnings (loss) ($/boe)		1.23		(6.18	)	120		3.08		(1.71	)	280

(1)	Operating netback does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details.

OPERATIONS UPDATE

In Q3 2013, Crocotta continued its focus in improving netbacks, expanding its footprint in core areas, and driving production growth towards its year-end target of 10,500 boepd.

At Edson, it was the first full quarter under its new operated facility and payoff was significant with improved netbacks of approximately $2.50 per boe. After factoring in 98% on-time for the facility, the impact was even greater on a relative basis.

Drilling was focused on Cardium horizontal wells in Q3 2013 but will shift to a blend of Cardium and Bluesky on a go-forward basis. Production has increased from 800 boepd in mid-2009 to over 8,000 boepd currently with an inventory of over 100 net locations identified for future development. Free cash flow from the property continues to increase as decline rates have started to moderate on the base production.

Crocotta's Montney project at Dawson also took a significant step forward with the commissioning of a new 100% owned gas plant connected to the Alliance Pipeline. The plant, which became operational in mid-September, allows Crocotta to receive significant liquid volume not previously received and also materially reduce operating costs. Two successful Crocotta wells drilled in Q3 2013 also provided increased confidence that this play will become a second major producing property for Crocotta. The measured approach taken at Dawson including construction of facilities to minimize costs and maximize returns mirror steps taken at Edson and are typical of Crocotta's operating philosophy.

Capital is also being invested in land and drilling new concepts in order to hopefully move the plays from concept to development over the next 12-24 months. If successful, Crocotta would take the same approach to maximizing returns by focusing on infrastructure and scale.

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

November 7, 2013

The MD&A should be read in conjunction with the unaudited interim consolidated financial statements and related notes for the three and nine months ended September 30, 2013 and the audited consolidated financial statements and related notes for the year ended December 31, 2012. The unaudited interim consolidated financial statements and financial data contained in the MD&A have been prepared in accordance with International Financial Reporting Standards ("IFRS") in Canadian currency (except where noted as being in another currency).

DESCRIPTION OF BUSINESS

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

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

Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback, which is calculated as average unit sales price less royalties, production expenses, and transportation expenses, represents the cash margin for every barrel of oil equivalent sold. Operating netback per boe is reconciled to net earnings (loss) per boe under the heading "Operating Netback".

Q3 2013 HIGHLIGHTS

• Increased production 24% to 8,596 boe/d in Q3 2013 from 6,945 boe/d in Q3 2012

• Increased funds from operations 48% to $16.1 million in Q3 2013 from $10.9 million in Q3 2012

• Entered into a $145 million syndicated credit facility

SUMMARY OF FINANCIAL RESULTS
		Three Months Ended September 30						Nine Months Ended September 30
($000s, except per share amounts)		2013		2012		% Change		2013		2012		% Change
Oil and natural gas sales		26,950		17,922		50		80,369		55,580		45
Funds from operations		16,102		10,888		48		47,506		36,137		31
	Per share - basic	0.17		0.12		42		0.52		0.41		27
	Per share - diluted	0.16		0.12		33		0.50		0.40		25
Net earnings (loss)		975		(3,944	)	125		7,183		(3,172	)	326
	Per share - basic and diluted	0.01		(0.04	)	125		0.08		(0.04	)	300
Total assets								353,309		268,434		32
Total long-term liabilities								116,511		20,804		460
Net debt								105,518		54,436		94

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

PRODUCTION	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Average Daily Production
Oil and NGLs (bbls/d)	2,497		2,103		19		2,448		2,144		14
Natural gas (mcf/d)	36,593		29,053		26		36,624		27,743		32
Combined (boe/d)	8,596		6,945		24		8,552		6,768		26

Daily production for the three months ended September 30, 2013 increased 24% to 8,596 boe/d compared to 6,945 boe/d for the comparative period in 2012. Year-to-date, daily production increased 26% to 8,552 boe/d in 2013 compared to 6,768 boe/d in 2012. The significant increase in production was mainly due to successful drilling activity at Edson, AB and Northeast BC during the past year. Compared to the previous quarter, daily production increased in Q3 2013 to 8,596 boe/d from 8,227 boe/d in Q2 2013. The Company expects production to increase in Q4 2013.

Crocotta's production profile for the first nine months of 2013 was comprised of 71% natural gas and 29% oil and NGLs compared with the production profile for 2012 which was comprised of 68% natural gas and 32% oil and NGLs. The increase in gas weighting is due to a higher percentage of total production coming from Northeast BC in 2013 compared to 2012.

REVENUE	Three Months Ended September 30						Nine Months Ended September 30
($000s)	2013		2012		% Change		2013		2012		% Change
Oil and NGLs	18,347		10,985		67		47,188		37,450		26
Natural gas	8,603		6,937		24		33,181		18,130		83
Total	26,950		17,922		50		80,369		55,580		45
Average Sales Price
Oil and NGLs ($/bbl)	79.85		56.78		41		70.61		63.75		11
Natural gas ($/mcf)	2.56		2.60		(2	)	3.32		2.39		39
Combined ($/boe)	34.08		28.05		21		34.42		29.97		15

Revenue totaled $27.0 million for the third quarter of 2013, up 50% from $17.9 million in the comparative period. For the nine months ended September 30, 2013, revenue totaled $80.4 million, an increase of 45% from $55.6 million for the nine months ended September 30, 2012. The increase in revenue was due to significant increases in production combined with increases in oil, NGLs, and natural gas commodity prices.

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

Commodity Pricing	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Oil and NGLs
Corporate price ($CDN/bbl)	79.85		56.78		41		70.61		63.75		11
Edmonton par ($CDN/bbl)	105.17		84.79		24		95.57		87.29		9
West Texas Intermediate ($US/bbl)	105.82		92.18		15		98.15		96.16		2
Natural gas
Corporate price ($CDN/mcf)	2.56		2.60		(2	)	3.32		2.39		39
AECO price ($CDN/mcf)	2.43		2.28		7		3.00		2.12		42
Exchange rate
CDN/US dollar average exchange rate	0.9629		1.0053		(4	)	0.9773		0.9981		(2	)

Differences between corporate and benchmark prices can be the result of quality differences (higher or lower API oil and higher or lower heat content natural gas), sour content, NGLs included in reporting, and various other factors. Crocotta's differences are mainly the result of lower priced NGLs included in oil price reporting and higher heat content natural gas production that is priced higher than AECO reference prices. The Company's corporate average oil and NGLs prices were 75.9% and 73.9% of Edmonton Par price for the three and nine months ended September 30, 2013, respectively, up from 67.0% and 73.0% for the respective comparative periods in 2012. The Company experienced an increase in realized NGLs prices for a significant portion of its NGLs volumes at Edson, AB as they were transitioned to new marketing arrangements in June 2013 which allowed the Company to access higher propane and butane prices in the United States. Corporate average natural gas prices were 105.3% and 110.7% of AECO prices for the three and nine months ended September 30, 2013, respectively, down slightly from 114.0% and 112.7% in the respective comparative periods.

Future prices received from the sale of the products may fluctuate as a result of market factors. Other than noted below, the Company did not hedge any of its oil, NGLs or natural gas production in 2013. During 2013, the Company had entered into the following commodity price contracts:

Commodity	Period		Type of Contract		Quantity Contracted		Contract Price
Oil	February 1, 2013 - December 31, 2013		Financial - Swap		1,000 bbls/d		WTI US $94.72/bbl
Natural Gas	January 1, 2013 - December 31, 2013		Financial - Swap		10,000 GJ/d		AECO CDN $2.705/GJ
Natural Gas	January 1, 2013 - December 31, 2013		Financial - Call		10,000 GJ/d		AECO CDN $4.000/GJ
Natural Gas	April 1, 2013 - October 31, 2013		Financial - Put		15,000 GJ/d		AECO CDN $3.000/GJ

For the three months ended September 30, 2013, the realized loss on the contracts was $0.6 million and the unrealized gain on the contracts was $0.3 million. For the nine months ended September 30, 2013, the realized loss on the contracts was $1.9 million and the unrealized gain on the contracts was $0.6 million.

ROYALTIES	Three Months Ended September 30						Nine Months Ended September 30
($000s)	2013		2012		% Change		2013		2012		% Change
Oil and NGLs	1,584		2,317		(32	)	5,473		5,849		(6	)
Natural gas	140		321		(56	)	939		991		(5	)
Total	1,724		2,638		(35	)	6,412		6,840		(6	)
Average Royalty Rate (% of sales)
Oil and NGLs	8.6		21.1		(59	)	11.6		15.6		(26	)
Natural gas	1.6		4.6		(65	)	2.8		5.5		(49	)
Combined	6.4		14.7		(56	)	8.0		12.3		(35	)

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

For the three months ended September 30, 2013, oil, NGLs, and natural gas royalties decreased 35% to $1.7 million from $2.6 million in the comparative period. For the nine months ended September 30, 2013, oil, NGLs, and natural gas royalties decreased 6% to $6.4 million from $6.8 million in 2012. Oil and NGLs royalties in Q3 2013 decreased significantly in the third quarter from the comparative period as a result of royalty incentives received on new wells brought on production. Natural gas royalties were lower in Q3 2013 compared to Q2 2013 due to an increase in the monthly capital cost and processing fee deductions.

The overall effective royalty rate was 6.4% for the three months ended September 30, 2013 compared to 14.7% for the three months ended September 30, 2012. Year-to-date, the overall effective royalty rate was 8.0% in 2013 compared to 12.3% in 2012. The effective oil and NGLs royalty rates in 2013 decreased from the comparative periods as a result of royalty incentives received on new wells brought on production. The effective natural gas royalty rates in 2013 decreased from the comparative periods as a result of royalty holidays received on the Company's production in Northeast BC, a favourable prior period adjustment to the annual capital cost and processing fee deductions, and an increase in the monthly capital cost and processing fee deductions.

PRODUCTION EXPENSES	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Oil and NGLs ($/bbl)	6.03		5.00		21		5.92		5.06		17
Natural gas ($/mcf)	1.12		1.00		12		1.13		0.98		15
Combined ($/boe)	6.51		5.72		14		6.53		5.62		16

Per unit production expenses for the three and nine months ended September 30, 2013 were $6.51/boe and $6.53/boe, respectively, compared to $5.72/boe and $5.62/boe for the comparative periods ended September 30, 2012. The increase in production expenses is mainly due to higher costs associated with wells brought on production in Northeast BC during the past year. Production expenses in this area were approximately $10.00/boe due mainly to third party processing and throughput charges. During the latter part of the third quarter, the Company completed the expansion of its infrastructure in this area and as a result, anticipates production expenses in Northeast BC to decrease to approximately $6.00/boe going forward. Year-to-date, production expenses in Edson, AB continued to be very competitive at approximately $5.50/boe. The Company continues to focus on opportunities to maintain operational efficiencies to enhance operating netbacks.

TRANSPORTATION EXPENSES	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Oil and NGLs ($/bbl)	1.93		0.51		278		1.35		0.84		61
Natural gas ($/mcf)	0.18		0.19		(5	)	0.13		0.18		(28	)
Combined ($/boe)	1.31		0.93		41		0.93		1.01		(8	)

Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended September 30, 2013 compared to the quarter ended September 30, 2012, transportation expenses increased 41% to $1.31/boe from $0.93/boe. Year-to-date, transportation expenses decreased 8% to $0.93/boe in 2013 from $1.01/boe in 2012. Oil and NGLs transportation expenses were higher for both the three and nine months ended September 30, 2013 as a result of the Company's production in Northeast BC being diverted to a different processing facility during the second quarter to obtain credit for NGLs volumes that were not being extracted previously. The decrease in natural gas transportation expenses per boe is due to obtaining a lower contracted transportation fee in the fourth quarter of 2012 on the majority of the Company's natural gas production. The lower contracted transportation fee is in effect until November 2013.

OPERATING NETBACK	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Oil and NGLs ($/bbl)
Revenue	79.85		56.78		41		70.61		63.75		11
Royalties	(6.89	)	(11.97	)	(42	)	(8.19	)	(9.96	)	(18	)
Production expenses	(6.03	)	(5.00	)	21		(5.92	)	(5.06	)	17
Transportation expenses	(1.93	)	(0.51	)	278		(1.35	)	(0.84	)	61
Operating netback	65.00		39.30		65		55.15		47.89		15
Natural gas ($/mcf)
Revenue	2.56		2.60		(2	)	3.32		2.39		39
Royalties	(0.04	)	(0.12	)	(67	)	(0.09	)	(0.13	)	(31	)
Production expenses	(1.12	)	(1.00	)	12		(1.13	)	(0.98	)	15
Transportation expenses	(0.18	)	(0.19	)	(5	)	(0.13	)	(0.18	)	(28	)
Operating netback	1.22		1.29		(5	)	1.97		1.10		79
Combined ($/boe)
Revenue	34.08		28.05		21		34.42		29.97		15
Royalties	(2.18	)	(4.13	)	(47	)	(2.75	)	(3.69	)	(25	)
Production expenses	(6.51	)	(5.72	)	14		(6.53	)	(5.62	)	16
Transportation expenses	(1.31	)	(0.93	)	41		(0.93	)	(1.01	)	(8	)
Operating netback	24.08		17.27		39		24.21		19.65		23

During the third quarter of 2013, Crocotta generated an operating netback of $24.08/boe, up 39% from $17.27/boe for the third quarter of 2012. During the first nine months of 2013, Crocotta generated an operating netback of $24.21/boe compared to $19.65/boe in the comparative period. The increases were due to increases in oil, NGLs, and natural gas commodity prices combined with significant decreases in royalties, partially offset by increases in operating expenses. Operating netbacks in Q3 2013 were consistent with operating netbacks of $23.52/boe in Q2 2013.

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

	Three Months Ended September 30						Nine Months Ended September 30
($/boe)	2013		2012		% Change		2013		2012		% Change
Operating netback	24.08		17.27		39		24.21		19.65		23
Depletion and depreciation	(14.13	)	(15.14	)	(7	)	(13.78	)	(14.87	)	(7	)
Asset impairment	(0.28	)	(3.77	)	(93	)	(0.23	)	(3.07	)	(93	)
General and administrative expenses	(1.41	)	(1.29	)	9		(1.83	)	(1.55	)	18
Share based compensation	(0.56	)	(1.17	)	(52	)	(0.60	)	(1.52	)	(61	)
Finance expenses	(1.76	)	(0.72	)	144		(1.38	)	(0.72	)	92
Deferred tax reduction (expense)	(4.31	)	1.40		(408	)	(2.73	)	(0.26	)	950
Realized gain (loss) on risk management contracts	(0.74	)	1.60		(146	)	(0.83	)	1.92		(143	)
Unrealized gain (loss) on risk management contracts	0.34		(4.36	)	108		0.25		(1.29	)	119
Net earnings (loss)	1.23		(6.18	)	120		3.08		(1.71	)	280

DEPLETION AND DEPRECIATION	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Depletion and depreciation ($000s)	11,177		9,675		16		32,162		27,578		17
Depletion and depreciation ($/boe)	14.13		15.14		(7	)	13.78		14.87		(7	)

Depletion and depreciation for the three months ended September 30, 2013 was $14.13/boe, down 7% from $15.14/boe for the comparative period ended September 30, 2012. Year-to-date, depletion and depreciation was down 7% to $13.78/boe in 2013 from $14.87 /boe in 2012. The decrease is due to a significant increase in proved and probable reserves stemming from successful drilling activities during 2012 and 2013. Depletion and depreciation of $14.13/boe in Q3 2013 was consistent with depletion and depreciation of $13.74/boe for the previous quarter ended June 30, 2013.

ASSET IMPAIRMENT	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Asset impairment ($000s)	219		2,412		(91	)	546		5,696		(90	)
Asset impairment ($/boe)	0.28		3.77		(93	)	0.23		3.07		(93	)

Exploration and evaluation assets and property, plant, and equipment are grouped into cash generating units ("CGU") for purposes of impairment testing. Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For property, plant, and equipment, an impairment is recognized if the carrying value of a CGU exceeds the greater of its fair value less costs to sell or value in use.

For the nine months ended September 30, 2013, total exploration and evaluation asset impairments of $0.5 million were recognized relating to the expiry of undeveloped land rights (CGUs - Miscellaneous AB and Saskatchewan). For the comparative period ended September 30, 2012, total exploration and evaluation asset impairments of $3.9 million were recognized. Asset impairments of $2.3 million were recognized relating to the determination of certain exploration and evaluation activities in non-core areas to be uneconomical (CGU - Miscellaneous AB). Additional exploration and evaluation impairments of $1.6 million were recognized relating to the expiry of undeveloped land rights (CGUs - Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan). For the three months ended September 30, 2013, asset impairments of $0.2 million were recognized relating to the expiry of undeveloped land rights (CGUs - Miscellaneous AB and Saskatchewan). For the three months ended September 30, 2012, asset impairments of $1.8 million were recognized relating to the determination of certain exploration and evaluation activities to be uneconomical (CGU - Miscellaneous AB) and asset impairments of $0.5 million were recognized relating to expiry of undeveloped land rights (CGUs - Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan).

For the nine months ended September 30, 2012, the Company recorded property, plant, and equipment impairments of $1.8 million during the first quarter relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices. No property, plant, and equipment impairments were recorded for the three and nine months ended September 30, 2013.

GENERAL AND ADMINISTRATIVE	Three Months Ended September 30						Nine Months Ended September 30
($000s)	2013		2012		% Change		2013		2012		% Change
G&A expenses (gross)	1,683		1,159		45		5,579		3,944		41
G&A capitalized	(167	)	(94	)	78		(422	)	(240	)	76
G&A recoveries	(399	)	(241	)	66		(878	)	(826	)	6
G&A expenses (net)	1,117		824		36		4,279		2,878		49
G&A expenses ($/boe)	1.41		1.29		9		1.83		1.55		18

General and administrative expenses ("G&A") increased slightly to $1.41/boe and $1.83/boe for the three and nine months ended September 30, 2013, respectively, compared to $1.29/boe and $1.55/boe for the three and nine months ended September 30, 2012. The increases were mainly due to an increase in employment costs.

SHARE BASED COMPENSATION	Three Months Ended September 30						Nine Months Ended September 30
	2013		2012		% Change		2013		2012		% Change
Share based compensation ($000s)	443		745		(41	)	1,403		2,828		(50	)
Share based compensation ($/boe)	0.56		1.17		(52	)	0.60		1.52		(61	)

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. The decrease in share based compensation expense for both the three and nine months ended September 30, 2013 is attributable to the graded vesting methodology used to calculate the expense and the timing of previous option issuances.

On a boe basis, share based compensation expense decreased to $0.56/boe for the three months ended September 30, 2013 from $1.17/boe in the comparative period. Year-to-date, share based compensation expense decreased to $0.60/boe in 2013 from $1.52/boe in 2012. These decreases were due to lower share based compensation expense amounts recognized in 2013 combined with significant increases in production. During the first nine months of 2013, the Company granted 1.7 million options (2012 - 0.7 million).

FINANCE EXPENSES	Three Months Ended September 30						Nine Months Ended September 30
($000s)	2013		2012		% Change		2013		2012		% Change
Interest expense	1,241		349		256		2,808		997		182
Accretion of decommissioning obligations	153		111		38		423		333		27
Finance expenses	1,394		460		203		3,231		1,330		143
Finance expenses ($/boe)	1.76		0.72		144		1.38		0.72		92

Interest expense relates to interest incurred on amounts drawn from the Company's credit facility. The increase in interest expense is a result of higher amounts being drawn on the Company's credit facility in the first nine months of 2013 compared to the first nine months of 2012. At September 30, 2013, $93.8 million (September 30, 2012 - $42.6 million) had been drawn on the Company's credit facility.

DEFERRED INCOME TAXES

Deferred income tax expense on the earnings before taxes for the three months ended September 30, 2013 was $3.4 million compared to a deferred income tax reduction of $0.9 million for the three months ended September 30, 2012. For the nine months ended September 30, 2013, deferred income tax expense was $6.4 million compared to $0.5 million for the nine months ended September 30, 2012. This was larger than expected by applying the statutory tax rate to the earnings before taxes due to non-deductible items such as share based compensation as well as renouncing tax deductions related to flow-through shares.

Estimated tax pools at September 30, 2013 total approximately $330.1 million (December 31, 2012 - $299.6 million).

FUNDS FROM OPERATIONS

Funds from operations for the three and nine months ended September 30, 2013 were $16.1 million ($0.16 per diluted share) and $47.5 million ($0.50 per diluted share), respectively, compared to $10.9 million ($0.12 per diluted share) and $36.1 million ($0.40 per diluted share) for the three and nine months ended September 30, 2012. The increase was mainly due to a significant increase in revenue which resulted from significant increases in production and oil, NGLs, and natural gas prices. Of note, included in funds from operations for the three and nine months ended September 30, 2013 were realized losses on risk management contracts of $0.6 million and $1.9 million, respectively, compared to realized gains on risk management contracts of $1.0 million and $3.6 million, respectively, for the three and nine months ended September 30, 2012.

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

	Three Months Ended September 30						Nine Months Ended September 30
($000s)	2013		2012		% Change		2013		2012		% Change
Cash flow from operating activities (GAAP)	9,440		9,686		(3	)	45,717		35,353		29
Add back:
Decommissioning expenditures	23		271		(92	)	270		621		(57	)
Change in non-cash working capital	6,639		931		613		1,519		163		832
Funds from operations (non-GAAP)	16,102		10,888		48		47,506		36,137		31

NET EARNINGS (LOSS)

The Company had net earnings of $1.0 million ($0.01 per diluted share) for the three months ended September 30, 2013 compared to a net loss of $3.9 million ($0.04 per diluted share) for the three months ended September 30, 2012. Year-to-date, the Company had net earnings of $7.2 million ($0.08 per diluted share) in 2013 compared to a net loss of $3.2 million ($0.04 per diluted share) in 2012. Net earnings for the three and nine months ended September 30, 2013 arose mainly due to a significant increase in revenue which resulted from significant increases in production and oil, NGLs, and natural gas prices. The net loss for the three and nine months ended September 30, 2012 arose mainly due to exploration and evaluation impairments in non-core areas and unrealized losses on risk management contracts.

CAPITAL EXPENDITURES	Three Months Ended September 30						Nine Months Ended September 30
($000s)	2013		2012		% Change		2013		2012		% Change
Land	1,526		1,326		15		3,195		4,406		(27	)
Drilling, completions, and workovers	39,358		19,121		106		69,283		47,159		47
Equipment	7,608		3,016		152		20,943		10,168		106
Geological and geophysical	419		77		444		1,190		495

140 Capital expenditures 48,911 23,540 108 94,611 62,228 52

For the three months ended September 30, 2013, the Company had capital expenditures of $48.9 million compared to capital expenditures of $23.5 million for the three months ended September 30, 2012. For the nine months ended September 30, 2013, the Company had capital expenditures of $94.6 million compared to $62.2 million for the comparative period in 2012. The increase in exploration and development expenditures in 2013 was due mainly to an increase in capital activity in the Company's core areas of Edson, AB and Northeast BC. During the first nine months of 2013, Crocotta drilled a total of 17 (15.2 net) wells, which resulted in 12 (10.6 net) oil wells, 4 (3.6 net) liquids-rich natural gas wells, and 1 (1.0 net) well to be completed during the fourth quarter.

LIQUIDITY AND CAPITAL RESOURCES

The Company had net debt of $105.5 million at September 30, 2013 compared to net debt of $80.1 million at December 31, 2012. The increase of $25.4 million was mainly due to $94.6 million used for the purchase and development of oil and natural gas properties and equipment, $1.0 million in share issue costs, and $0.3 million in decommissioning expenditures, offset by gross proceeds of $22.0 million from an equity financing in June 2013, funds from operations of $47.5 million, and $1.0 million from the exercise of stock options.

In June 2013, the Company issued approximately 6.0 million common shares on a flow-through basis for gross proceeds of approximately $22.0 million. Approximately 4.2 million shares were issued at a price of $3.70 per share in respect of Canadian exploration expenses ("CEE") and approximately 1.8 million shares were issued at a price of $3.50 per share in respect of Canadian development expenses ("CDE"). The proceeds will be used by the Company to fund eligible CEE and CDE projects.

During the third quarter, the Company entered into a syndicated credit facility with three Canadian chartered banks. The syndicated credit facility replaces the Company's previous $140 million revolving operating demand loan credit facility. The syndicated facility has a borrowing base of $145 million, consisting of a $135 million revolving line of credit and a $10 million operating line of credit. The syndicated facility revolves for a 364 day period and will be subject to its next 364 day extension by July 11, 2014. If not extended, the syndicated facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date.

Advances under the syndicated facility are available by way of prime rate loans, with interest rates between 1.00% and 2.50% over the Canadian prime lending rate, and bankers' acceptances and LIBOR loans, which are subject to stamping fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash flow ratio of the Company. Standby fees are charged on the undrawn syndicated facility at rates ranging from 0.50% to 0.875%. At September 30, 2013, $93.8 million (December 31, 2012 - $68.5 million) had been drawn on the credit facility. In addition, at September 30, 2013, the Company had outstanding letters of guarantee of approximately $2.5 million (December 31, 2012 - $1.5 million) which reduce the amount that can be borrowed under the credit facility. The next scheduled borrowing base review of the syndicated facility is scheduled on or before December 1, 2013.

The ongoing global economic conditions have continued to impact the liquidity in financial and capital markets, restrict access to financing, and cause significant volatility in commodity prices. Despite the economic downturn and financial market volatility, the Company continued to have access to both debt and equity markets recently. The Company raised gross proceeds of approximately $22.0 million from the issuance of common shares during the second quarter of 2013 and during the third quarter, the Company entered into a $145 million syndicated credit facility which replaced the previous $140 million operating demand loan credit facility. The Company has also maintained a very successful drilling program which has resulted in significant increases in production and funds flow from operations in recent quarters in spite of continued pressure on oil and natural gas commodity prices. Management anticipates that the Company will continue to have adequate liquidity to fund budgeted capital investments through a combination of cash flow, equity, and debt. Crocotta's capital program is flexible and can be adjusted as needed based upon the current economic environment. The Company will continue to monitor the economic environment and the possible impact on its business and strategy and will make adjustments as necessary.

CONTRACTUAL OBLIGATIONS

The following is a summary of the Company's contractual obligations and commitments at September 30, 2013:

			Less than		One to		After
($000s)	Total		One Year		Three Years		Three Years
Accounts payable and accrued liabilities	27,283		27,283		-		-
Credit facility	93,804		-		93,804		-
Risk management contracts	1,009		1,009		-		-
Decommissioning obligations	22,202		50		1,025		21,127
Office leases	475		439		36		-
Field equipment leases	711		711		-		-
Firm transportation agreements	170		114		53		3
Total contractual obligations	145,654		29,606		94,918		21,130

In addition to the above commitments, as a result of the issuance of flow-through shares in June 2013, the Company is committed to spend approximately $22.0 million on qualifying exploration and development expenditures prior to December 31, 2014. As at September 30, 2013, the Company had spent $17.8 million in connection with this flow-through share commitment.

Under the terms of a farm-in agreement, the Company is also committed to drill and complete one Edson Cardium well. Under the terms of the agreement, the Company is committed to spud the well prior to November 15, 2013. The estimated total cost to drill and complete the well is approximately $3.5 million.

OUTSTANDING SHARE DATA

The Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, and Class B preferred shares, issuable in series. The voting common shares of the Company commenced trading on the TSX on October 17, 2007 under the symbol "CTA". The following table summarizes the common shares outstanding and the number of shares exercisable into common shares from options, warrants, and other instruments:

(000s)	September 30, 2013		November 7, 2013
Voting common shares	96,098		96,206
Stock options	9,500		9,400
Warrants	2,321		2,321
Total	107,919		107,927

SUMMARY OF QUARTERLY RESULTS

		Q3 2013		Q2 2013		Q1 2013		Q4 2012		Q3 2012		Q2 2012		Q1 2012		Q4 2011
Average Daily Production
Oil and NGLs (bbls/d)		2,497		2,158		2,691		2,476		2,103		2,053		2,277		1,879
Natural gas (mcf/d)		36,593		36,412		36,869		29,160		29,053		27,309		26,852		23,354
Combined (boe/d)		8,596		8,227		8,836		7,336		6,945		6,604		6,752		5,771
($000s, except per share amounts)
Oil and natural gas sales		26,950		25,152		28,267		24,938		17,922		17,518		20,140		20,391
Funds from operations		16,102		14,280		17,124		14,478		10,888		12,275		12,974		12,115
	Per share - basic	0.17		0.16		0.19		0.16		0.12		0.14		0.15		0.15
	Per share - diluted	0.16		0.15		0.19		0.16		0.12		0.14		0.14		0.14
Net earnings (loss)		975		3,604		2,604		(2,082	)	(3,944	)	1,065		(293	)	(7,052	)
	Per share - basic and diluted	0.01		0.04		0.03		(0.02	)	(0.04	)	0.01		-		(0.09	)

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

CRITICAL ACCOUNTING ESTIMATES

Management is required to make estimates, judgments, and assumptions in the application of IFRS that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. Certain of these estimates may change from period to period resulting in a material impact on the Company's results from operations, financial position, and change in financial position. The Company's significant critical accounting estimates have not changed from the year ended December 31, 2012.

CHANGES IN ACCOUNTING POLICIES

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

RISK ASSESSMENT

The acquisition, exploration, and development of oil and natural gas properties involves many risks common to all participants in the oil and natural gas industry. Crocotta's exploration and development activities are subject to various business risks such as unstable commodity prices, interest rate and foreign exchange fluctuations, the uncertainty of replacing production and reserves on an economic basis, government regulations, taxes, and safety and environmental concerns. While management realizes these risks cannot be eliminated, they are committed to monitoring and mitigating these risks.

Reserves and reserve replacement

The recovery and reserve estimates on Crocotta's properties are estimates only and the actual reserves may be materially different from that estimated. The estimates of reserve values are based on a number of variables including price forecasts, projected production volumes and future production and capital costs. All of these factors may cause estimates to vary from actual results.

Crocotta's future oil and natural gas reserves, production, and funds from operations to be derived therefrom are highly dependent on the Company successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves the Company may have at any particular time and the production therefrom will decline over time as such existing reserves are exploited. A future increase in Crocotta's reserves will depend on its abilities to acquire suitable prospects or properties and discover new reserves.

To mitigate this risk, Crocotta has assembled a team of experienced technical professionals who have expertise operating and exploring in areas the Company has identified as being the most prospective for increasing reserves on an economic basis. To further mitigate reserve replacement risk, Crocotta has targeted a majority of its prospects in areas which have multi-zone potential, year-round access, and lower drilling costs and employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.

Operational risks

Crocotta's operations are subject to the risks normally incidental to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells. Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property.

Financial instruments

Market risk

Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign currency risk, interest rate risk, and other price risk, such as commodity price risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns. The Company may use financial derivatives or physical delivery sales contracts to manage market risks. All such transactions are conducted within risk management tolerances that are reviewed by the Board of Directors.

Foreign exchange risk

The prices received by the Company for the production of crude oil, natural gas, and NGLs are primarily determined in reference to US dollars, but are settled with the Company in Canadian dollars. The Company's cash flow from commodity sales will therefore be impacted by fluctuations in foreign exchange rates. The Company currently does not have any foreign exchange contracts in place.

Interest rate risk

The Company is exposed to interest rate risk as it borrows funds at floating interest rates. In addition, the Company may at times issue shares on a flow-through basis. This results in the Company being exposed to interest rate risk to the Canada Revenue Agency for interest on unexpended funds on the Company's flow-through share obligations. The Company currently does not use interest rate hedges or fixed interest rate contracts to manage the Company's exposure to interest rate fluctuations.

Commodity price risk

Oil and natural gas prices are impacted by not only the relationship between the Canadian and US dollar but also by world economic events that dictate the levels of supply and demand. The Company's oil, natural gas, and NGLs production is marketed and sold on the spot market to area aggregators based on daily spot prices that are adjusted for product quality and transportation costs. The Company's cash flow from product sales will therefore be impacted by fluctuations in commodity prices. During 2013, the Company had entered into the following commodity price contracts:

Commodity	Period		Type of Contract		Quantity Contracted		Contract Price
Oil	February 1, 2013 - December 31, 2013		Financial - Swap		1,000 bbls/d		WTI US $94.72/bbl
Natural Gas	January 1, 2013 - December 31, 2013		Financial - Swap		10,000 GJ/d		AECO CDN $2.705/GJ
Natural Gas	January 1, 2013 - December 31, 2013		Financial - Call		10,000 GJ/d		AECO CDN $4.000/GJ
Natural Gas	April 1, 2013 - October 31, 2013		Financial - Put		15,000 GJ/d		AECO CDN $3.000/GJ

For the three months ended September 30, 2013, the realized loss on the contracts was $0.6 million and the unrealized gain on the contracts was $0.3 million. For the nine months ended September 30, 2013, the realized loss on the contracts was $1.9 million and the unrealized gain on the contracts was $0.6 million.

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 September 30, 2013, $13.4 million or 95.5% of the Company's outstanding accounts receivable were current while $0.7 million or 4.5% were outstanding over 90 days but not impaired. During the nine months ended September 30, 2013, the Company did not deem any outstanding accounts receivable to be uncollectable.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company's processes for managing liquidity risk include ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual, quarterly, and monthly capital expenditure and cash flow 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 (1992). Based on their evaluation, the Company's CEO and CFO have identified weaknesses over segregation of duties. Specifically, due to the limited number of finance and accounting personnel at the Company, it is not feasible to achieve complete segregation of duties with regards to certain complex and non-routine accounting transactions that may arise. This weakness is considered to be a common deficiency for many smaller listed companies in Canada. Notwithstanding the weaknesses identified with regards to segregation of duties, the Company concluded that all other of its internal controls over financial reporting were effective as of December 31, 2012. No material changes in the Company's internal controls over financial reporting were identified during the most recent reporting period that have materially affected, or are likely to material affect, the Company's internal controls over financial reporting.

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

FORWARD-LOOKING INFORMATION

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

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

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

ADDITIONAL INFORMATION

Additional information related to the Company, including the Company's Annual Information Form (AIF), may be found on the SEDAR website at www.sedar.com.

Crocotta Energy Inc.
Condensed Consolidated Statements of Financial Position
(unaudited)
				September 30		December 31
($000s)		Note		2013		2012
Assets
Current assets
	Accounts receivable			14,051		15,983
	Prepaid expenses and deposits			1,518		1,550
				15,569		17,533
Property, plant, and equipment		(5	)	304,714		241,703
Exploration and evaluation assets		(4	)	27,548		28,302
Deferred income taxes				5,478		13,442
				337,740		283,447
				353,309		300,980
Liabilities
Current liabilities
	Accounts payable and accrued liabilities			27,283		29,165
	Risk management contracts			1,009		1,592
	Revolving credit facility	(6	)	-		68,480
				28,292		99,237
Credit facility		(6	)	93,804		-
Decommissioning obligations		(7	)	22,202		21,852
Flow-through share premium		(8	)	505		-
				144,803		121,089
Shareholders' Equity
	Shareholders' capital	(8	)	248,818		228,277
	Contributed surplus			12,917		12,026
	Deficit			(53,229	)	(60,412	)
				208,506		179,891
				353,309		300,980
The accompanying notes are an integral part of these condensed interim consolidated financial statements.

Crocotta Energy Inc.
Condensed Consolidated Statements of Operations and Comprehensive Earnings (Loss)
(unaudited)
				Three Months Ended September 30				Nine Months Ended September 30
($000s, except per share amounts)		Note		2013		2012		2013		2012
Revenue
	Oil and natual gas sales			26,950		17,922		80,369		55,580
	Royalties			(1,724	)	(2,638	)	(6,412	)	(6,840	)
				25,226		15,284		73,957		48,740
Realized gain (loss) on risk management contracts				(582	)	1,024		(1,940	)	3,560
Unrealized gain (loss) on risk management contracts				270		(2,786	)	583		(2,386	)
				24,914		13,522		72,600		49,914
Expenses
	Production			5,151		3,653		15,249		10,418
	Transportation			1,033		594		2,175		1,870
	Depletion and depreciation	(5	)	11,177		9,675		32,162		27,578
	Asset impairment	(4,5	)	219		2,412		546		5,696
	General and administrative			1,117		824		4,279		2,878
	Share based compensation	(9	)	443		745		1,403		2,828
				19,140		17,903		55,814		51,268
Operating earnings (loss)				5,774		(4,381	)	16,786		(1,354	)
Other Expenses
	Finance expense	(11	)	1,394		460		3,231		1,330
Earnings (loss) before taxes				4,380		(4,841	)	13,555		(2,684	)
Taxes
Deferred income tax expense (reduction)				3,405		(897	)	6,372		488
Net earnings (loss) and comprehensive earnings (loss)				975		(3,944	)	7,183		(3,172	)
Net earnings (loss) per share
	Basic and diluted	(10	)	0.01		(0.04	)	0.08		(0.04	)
The accompanying notes are an integral part of these condensed interim consolidated financial statements.

Crocotta Energy Inc.
Condensed Consolidated Statements of Shareholders' Equity
(unaudited)
	Nine Months Ended September 30
($000s)	2013		2012
Shareholders' Capital
Balance, beginning of period	228,277		225,848
Issue of shares (net of share issue costs and flow-through share premium)	18,887		-
Issued on exercise of stock options	985		12
Share based compensation - exercised	669		-
Balance, end of period	248,818		225,860
Contributed Surplus
Balance, beginning of period	12,026		8,927
Share based compensation - expensed	1,403		2,828
Share based compensation - capitalized	157		254
Share based compensation - exercised	(669	)	-
Balance, end of period	12,917		12,009
Deficit
Balance, beginning of period	(60,412	)	(55,158	)
Net earnings (loss)	7,183		(3,172	)
Balance, end of period	(53,229	)	(58,330	)
Total Shareholders' Equity	208,506		179,539
The accompanying notes are an integral part of these condensed interim consolidated financial statements.

Crocotta Energy Inc.
Condensed Consolidated Statements of Cash Flows
(unaudited)
				Three Months Ended September 30				Nine Months Ended September 30
($000s)		Note		2013		2012		2013		2012
Operating Activities
	Net earnings (loss)			975		(3,944	)	7,183		(3,172	)
	Depletion and depreciation	(5	)	11,177		9,675		32,162		27,578
	Asset impairment	(4,5	)	219		2,412		546		5,696
	Share based compensation	(9	)	443		745		1,403		2,828
	Finance expense	(11	)	1,394		460		3,231		1,330
	Interest paid	(11	)	(1,241	)	(349	)	(2,808	)	(997	)
	Deferred income tax expense (reduction)			3,405		(897	)	6,372		488
	Unrealized loss (gain) on risk management contracts			(270	)	2,786		(583	)	2,386
	Decommissioning expenditures	(7	)	(23	)	(271	)	(270	)	(621	)
	Change in non-cash working capital	(13	)	(6,639	)	(931	)	(1,519	)	(163	)
				9,440		9,686		45,717		35,353
Financing Activities
	Credit facility	(6	)	30,018		2,912		25,324		37,408
	Issuance of shares	(8	)	819		12		22,968		12
	Share issue costs	(8	)	(32	)	-		(999	)	-
				30,805		2,924		47,293		37,420
Investing Activities
	Capital expenditures - property, plant, and equipment	(5	)	(23,972	)	(7,796	)	(59,996	)	(37,278	)
	Capital expenditures - exploration and evaluation assets	(4	)	(24,939	)	(15,744	)	(34,615	)	(24,950	)
	Change in non-cash working capital	(13	)	8,666		10,930		1,601		(10,545	)
				(40,245	)	(12,610	)	(93,010	)	(72,773	)
Change in cash and cash equivalents				-		-		-		-
Cash and cash equivalents, beginning of period				-		-		-		-
Cash and cash equivalents, end of period				-		-		-		-
The accompanying notes are an integral part of these condensed interim consolidated financial statements.

Crocotta Energy Inc.

Notes to the Condensed Interim Consolidated Financial Statements

Three and Nine Months Ended September 30, 2013

(Tabular amounts in 000s, unless otherwise stated)

1. REPORTING ENTITY

Crocotta Energy Inc. ("Crocotta" or the "Company") is an oil and natural gas company, actively engaged in the acquisition, development, exploration, and production of oil and natural gas reserves in Western Canada. The Company conducts many of its activities jointly with others and these condensed interim consolidated financial statements reflect only the Company's proportionate interest in such activities. The Company currently has one wholly-owned subsidiary.

The Company's place of business is located at 700, 639 - 5^th Avenue SW, Calgary, Alberta, Canada, T2P 0M9.

2. BASIS OF PRESENTATION

(a) Statement of compliance

These condensed interim consolidated financial statements have been prepared in accordance with International Accounting Standard ("IAS") 34, Interim Financial Reporting and accordingly do not include all of the information required in the preparation of annual consolidated financial statements. The condensed interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes for the year ended December 31, 2012.

The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on November 7, 2013.

(b) Basis of measurement

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

(c) Functional and presentation currency

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

(d) Use of estimates and judgments

The preparation of the condensed interim consolidated financial statements in conformity with IFRS requires management to make estimates and use judgment regarding the reported amounts of assets and liabilities as at the date of the interim consolidated financial statements and the reported amounts of revenues and expenses during the period. By their nature, estimates are subject to measurement uncertainty and changes in such estimates in future periods could require a material change in the interim consolidated financial statements. Accordingly, actual results may differ from the estimated amounts as future confirming events occur. The significant estimates and judgments made by management in the preparation of these condensed interim consolidated financial statements were consistent with those applied to the consolidated financial statements as at and for the year ended December 31, 2012.

3. SIGNIFICANT ACCOUNTING POLICIES

The condensed interim consolidated financial statements have been prepared following the same accounting policies as the audited consolidated financial statements for the year ended December 31, 2012. The accounting policies have been applied consistently by the Company to all periods presented in these condensed interim consolidated financial statements.

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

4. EXPLORATION AND EVALUATION ASSETS

		Total
Balance, December 31, 2011		20,641
	Additions	49,198
	Transfer to property, plant, and equipment	(36,838	)
	Impairment	(4,699	)
Balance, December 31, 2012		28,302
	Additions	34,615
	Transfer to property, plant, and equipment	(34,823	)
	Impairment	(546	)
Balance, September 30, 2013		27,548

Exploration and evaluation assets consist of the Company's exploration projects which are pending the determination of proved or probable reserves. Additions represent the Company's share of costs incurred on exploration and evaluation assets during the period, consisting primarily of undeveloped land and drilling costs until the drilling of the well is complete and the results have been evaluated. Included in the $34.6 million of additions during the nine months ended September 30, 2013 were additions of $28.4 million related to the Edson AB CGU and $5.8 million related to the Miscellaneous AB CGU.

Impairments

Exploration and evaluation assets are assessed for impairment when they are transferred to property, plant, and equipment or if facts and circumstances suggest that the carrying amount exceeds the recoverable amount. For the nine months ended September 30, 2013, total exploration and evaluation asset impairments of $0.5 million were recognized relating to the expiry of undeveloped land rights (CGUs - Miscellaneous AB and Saskatchewan).

5. PROPERTY, PLANT, AND EQUIPMENT

Cost		Total
Balance, December 31, 2011		236,846
	Additions	54,756
	Transfer from exploration and evaluation assets	36,838
	Change in decommissioning obligation estimates	2,883
	Capitalized share based compensation	319
Balance, December 31, 2012		331,642
	Additions	59,996
	Transfer from exploration and evaluation assets	34,823
	Change in decommissioning obligation estimates	197
	Capitalized share based compensation	157
Balance, September 30, 2013		426,815
Accumulated Depletion, Depreciation, and Impairment		Total
Balance, December 31, 2011		44,514
	Depletion and depreciation	36,685
	Impairment	8,740
Balance, December 31, 2012		89,939
	Depletion and depreciation	32,162
Balance, September 30, 2013		122,101
Net Book Value		Total
December 31, 2012		241,703
September 30, 2013		304,714

During the three and nine months ended September 30, 2013, approximately $0.3 million (2012 - $0.1 million) and $0.4 million (2012 - $0.3 million), respectively, of directly attributable general and administrative costs were capitalized as expenditures on property, plant, and equipment.

Depletion and depreciation

The calculation of depletion and depreciation expense for the three months ended September 30, 2013 included an estimated $197.6 million (2012 - $174.3 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $14.0 million (2012 - $10.6 million) for the estimated salvage value of production equipment and facilities.

6. CREDIT FACILITY

During the third quarter, the Company entered into a syndicated credit facility with three Canadian chartered banks. The syndicated credit facility replaces the Company's previous $140 million revolving operating demand loan credit facility. The syndicated facility has a borrowing base of $145 million, consisting of a $135 million revolving line of credit and a $10 million operating line of credit. The syndicated facility revolves for a 364 day period and will be subject to its next 364 day extension by July 11, 2014. If not extended, the syndicated facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date.

Advances under the syndicated facility are available by way of prime rate loans, with interest rates between 1.00% and 2.50% over the Canadian prime lending rate, and bankers' acceptances and LIBOR loans, which are subject to stamping fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash flow ratio of the Company. Standby fees are charged on the undrawn syndicated facility at rates ranging from 0.50% to 0.875%. At September 30, 2013, $93.8 million (December 31, 2012 - $68.5 million) had been drawn on the credit facility. In addition, at September 30, 2013, the Company had outstanding letters of guarantee of approximately $2.5 million (December 31, 2012 - $1.5 million) which reduce the amount that can be borrowed under the credit facility. The next scheduled borrowing base review of the syndicated facility is scheduled on or before December 1, 2013.

7. PROVISIONS - DECOMMISSIONING OBLIGATIONS

The Company's decommissioning obligations result from its ownership interest in oil and natural gas assets including well sites and gathering systems. The total decommissioning obligation is estimated based on the Company's net ownership interest in all wells and facilities, estimated costs to abandon and reclaim the wells and facilities, and the estimated timing of the costs to be incurred in future periods. The total undiscounted amount of the estimated cash flows (adjusted for inflation at 2% per year) required to settle the decommissioning obligations is approximately $33.1 million which is estimated to be incurred over the next 28 years. At September 30, 2013, a risk-free rate of 3.0% (December 31, 2012 - 2.3%) was used to calculate the net present value of the decommissioning obligations.

		Nine Months Ended		Year Ended
		September 30, 2013		December 31, 2012
Balance, beginning of period		21,852		19,250
	Provisions incurred	2,052		2,208
	Provisions settled	(270	)	(734	)
	Revisions	(1,855	)	675
	Accretion	423		453
Balance, end of period		22,202		21,852

8. 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, 2012		89,261		228,277
	Exercise of stock options	795		1,654
	Share issuances	6,042		21,983
	Share issue costs, net of future tax effect of $0.2 million			(749	)
	Flow-through share premium			(2,347	)
Balance, September 30, 2013		96,098		248,818

In June 2013, the Company issued approximately 6.0 million common shares on a flow-through basis for gross proceeds of approximately $22.0 million. Approximately 4.2 million shares were issued at a price of $3.70 per share in respect of Canadian exploration expenses ("CEE") and approximately 1.8 million shares were issued at a price of $3.50 per share in respect of Canadian development expenses ("CDE"). Upon issuance, the premium received on the flow-through shares, being the difference between the fair value of the flow-through shares issued and the fair value that would have been received for common shares at the date of the announcement of the financing, was recognized as a liability. Under the terms of the flow-through share agreements, the Company is committed to spend approximately $22.0 million on qualifying exploration and development expenditures prior to December 31, 2014. As at September 30, 2013, the Company had spent $17.8 million in connection with this flow-through share commitment.

9. SHARE BASED COMPENSATION PLANS

Stock options

The Company has authorized and reserved for issuance 9.6 million common shares under a stock option plan enabling certain officers, directors, employees, and consultants to purchase common shares. The Company will not issue options exceeding 10% of the shares outstanding at the time of the option grants. Under the plan, the exercise price of each option equals the market price of the Company's shares on the date of the grant. The options vest over a period of three years and an option's maximum term is 5 years. At September 30, 2013, 9.5 million options are outstanding at exercise prices ranging from $1.10 to $3.46 per share.

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

		Number of Options		Weighted Average Exercise Price ($	)
Balance, December 31, 2012		8,601		2.09
	Granted	1,696		2.77
	Exercised	(795	)	1.24
	Forfeited	(2	)	3.46
Balance, September 30, 2013		9,500		2.28

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

	Options Outstanding						Options Exercisable
			Weighted Average		Weighted Average				Weighted Average
Exercise Price	Number		Remaining Life		Exercise Price		Number		Exercise Price
$1.10 to $2.00	2,847		1.4		1.24		2,504		1.21
$2.01 to $3.00	5,912		3.2		2.64		2,876		2.59
$3.01 to $3.46	741		3.5		3.44		231		3.46
	9,500		2.6		2.28		5,611		2.01

Warrants

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

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

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

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

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

	Warrants Outstanding and Exercisable
			Weighted Average		Weighted Average
Exercise Price	Number		Remaining Life		Exercise Price
$3.75 to $4.05	740		0.3		3.76
$4.50 to $5.25	807		0.3		4.55
$6.00 to $6.75	774		0.3		6.05
	2,321		0.3		4.80

Share based compensation

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

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

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Risk-free interest rate (%)	1.6		1.6
Expected life (years)	4.0		4.0
Expected volatility (%)	51.4		51.6
Expected dividend yield (%)	-		-
Forfeiture rate (%)	5.9		5.9
Weighted average fair value of options granted ($ per option)	1.14		1.15

10. PER SHARE AMOUNTS

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

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Weighted average number of shares - basic	95,978		91,954
Dilutive effect of share based compensation plans	1,991		2,160
Weighted average number of shares - diluted	97,969		94,114

For the three months ended September 30, 2013, 3.9 million stock options (2012 - 4.9 million) and 2.3 million warrants (2012 - 2.3 million) were anti-dilutive and were not included in the diluted earnings per share calculation. For the nine months ended September 30, 2013, 3.9 million stock options (2012 - 2.3 million) and 2.3 million warrants (2012 - 2.3 million) were anti-dilutive and were not included in the diluted earnings per share calculation.

11. FINANCE EXPENSES

Finance expenses include the following:

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Interest expense (note 6)	1,241		2,808
Accretion of decommissioning obligations (note 7)	153		423
Finance expenses	1,394		3,231

12. FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivatives

The fair value of risk management contracts is determined by discounting the difference between the contracted price and published forward curves as at the statement of financial position date using the remaining contracted volumes and a risk-free interest rate (based on published government rates).

The Company classified the fair value of its financial instruments carried 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 September 30, 2013 is measured using level 2. During the nine months ended September 30, 2013, there were no transfers between level 1, level 2, and level 3 classified assets and liabilities.

13. SUPPLEMENTAL CASH FLOW INFORMATION

		Three Months Ended		Nine Months Ended
		September 30, 2013		September 30, 2013
Accounts receivable		(4,149	)	1,932
Prepaid expenses and deposits		512		32
Accounts payable and accrued liabilities		5,664		(1,882	)
Change in non-cash working capital		2,027		82
Relating to:
	Investing	8,666		1,601
	Operating	(6,639	)	(1,519	)
Change in non-cash working capital		2,027		82

CORPORATE INFORMATION
OFFICERS AND DIRECTORS
Robert J. Zakresky, CA President, CEO & Director		BANK National Bank of Canada
		1800, 311 - 6th Avenue SW
Nolan Chicoine, MPAcc, CA VP Finance & CFO		Calgary, Alberta T2P 3H2
Terry L. Trudeau, P.Eng. VP Operations & COO		TRANSFER AGENT
		Valiant Trust Company
Weldon Dueck, BSc., P.Eng. VP Business Development		310, 606 - 4th Street SW Calgary, Alberta T2P 1T1
R.D. (Rick) Sereda, M.Sc., P.Geol. VP Exploration
		LEGAL COUNSEL
Helmut R. Eckert, P.Land VP Land		Gowling Lafleur Henderson LLP 1400, 700 - 2nd Street SW
		Calgary, Alberta T2P 4V5
Kevin Keith VP Production
Larry G. Moeller, CA, CBV Chairman of the Board		AUDITORS KPMG LLP
		2700, 205 - 5th Avenue SW
Daryl H. Gilbert, P.Eng. Director		Calgary, Alberta T2P 4B9
Don Cowie Director		INDEPENDENT ENGINEERS
		GLJ Petroleum Consultants Ltd.
Brian Krausert Director		4100, 400 - 3rd Avenue SW Calgary, Alberta T2P 4H2
Gary W. Burns Director
Don D. Copeland, P.Eng. Director
Brian Boulanger Director
Patricia Phillips Director