Crocotta Energy Inc.: Q1 2013 Financial and Operating Results

CALGARY, ALBERTA–(Marketwired – May 9, 2013) –CROCOTTA ENERGY INC. (CTA.TO) is pleased to announce its financial and operating results for the three months ended March 31, 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 31% to 8,836 boe/d in Q1 2013 from 6,752 boe/d in Q1 2012
• Increased funds from operations 32% to $17.1 million in Q1 2013 from $13.0 million in Q1 2012
• Increased bank credit facility to $140.0 million from $100.0 million
• Completed an additional 6.4 net successful wells at Edson, AB
• Subsequent to Q1 2013, signed agreements with Alliance and Aux Sable which will enhance netbacks at Edson, AB

OPERATIONS UPDATE

In Q1 2013, Crocotta spent $32 million of its 2013 capital budget of $100 million that included completing1.6 net liquids-rich Bluesky horizontal wells and 4.8 net Cardium horizontal oil wells and construction of certain infrastructure projects at Edson and Dawson. Crocotta will continue its Edson drilling program after break-up and then commence liquids-rich Montney drilling at Dawson-Sunrise in mid to late Q3 2013.

Subsequent to quarter end, Crocotta also signed pipeline and marketing agreements with Alliance Pipeline Limited Partnership (“Alliance”) and Aux Sable Canada LP (“Aux Sable”) to move its natural gas and corresponding propane and butane at Edson out of the Alberta market in order to capture better pricing and reduce downtime.

We have summarized the effect of the new agreements as well as provided more detailed information of our ongoing operations below:

Edson Pipeline and Marketing Agreements

Crocotta has entered into rich gas premium agreements with Aux Sable and an interconnection agreement with Alliance providing access to premium markets in the United States.

Under the agreements, Crocotta will deliver approximately 6,000 boepd of liquids-rich gas into the Alliance pipeline. The liquids-rich gas will be processed and fractionated at Aux Sable Liquid Product’s Channahon facility in Illinois.

The agreements are effective immediately and Crocotta estimates it will be fully operational by June 1, 2013. Crocotta will continue to truck and deliver its oil and condensate from Edson into the Alberta market.

The expected benefits of such arrangement are as follows:

• Increased cash flow of over $6.5 million annually (based on 6,000 boepd) that results from enhanced pricing, lower operating costs and lower royalties. This equates to an increase of approximately $3 per boe for volumes delivered.
• Reduced or eliminated downtime due to partner and third party disruptions in facilities and pipelines. The Edson partner facility and third party pipelines experienced several disruptions in 2012 that led to approximately 22 days of unscheduled production interruption and downtime. Aux Sable’s 99% operating efficiency will allow Crocotta to avoid scheduled and unscheduled partner and third party pipeline infrastructure downtime estimated at a minimum of 10 days for the balance of 2013 and an expected minimum of 21 days in 2014.
• Access to United States markets for propane and butane that are larger and more competitive than in Alberta. Crocotta will also avoid the potential oversupply of propane and butane in Alberta that may push local prices even lower.
• Crocotta will also avoid recent and projected cost increases for fractionation of natural gas liquids in Alberta.

Edson Cardium

Crocotta has drilled or participated in drilling a total of 15 Cardium horizontal oil wells in the Edson area since late 2011. Results to date from the 11 wells that have been on production for more than 90 days is as follows:

In Q1 2013, Crocotta signed farm-in agreements covering approximately 10 sections of highly prospective Cardium lands and based on internal mapping has added approximately 21 gross (16 net) Cardium horizontal oil locations to its drilling inventory. As at the end of Q1 2013, the total number of high graded Cardium locations (net of Q1 2013 drilling) has increased to 46 net locations.

Based on current on-stream costs of approximately $3.35 million per well, and Crocotta’s internally generated type curve, the Edson Cardium wells will have an average rate of return of over 100% and a payback of less than one year.

Dawson/Sunrise Facility

Crocotta has received approval to install its gas plant facility at Dawson that will allow it to produce into the Alliance pipeline. Once completed, Crocotta will sell liquids-rich gas in conjunction with its Aux Sable agreement. In Q1 2013, Crocotta completed all required pipelines and will proceed to construct the facility in early Q3 2013. Once completed, the following benefits will be realized on Crocotta’s current production (900 boepd) and future drilling:

• Increase in netback of approximately $11 per boe as a result of revenue from NGLs and lower operating costs. This equates to an annualized increase of $3.6 million excluding drilling budgeted to commence in Q3 2013.
• Increase in realized liquids yield from nil to approximately 35 bbls per mmcf
• Reduction in operating costs from $11 per boe to approximately $6 per boe

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

May 7, 2013

The MD&A should be read in conjunction with the unaudited interim consolidated financial statements and related notes for the three months ended March 31, 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 (including the revolving credit facility and excluding risk management contracts) less current assets.

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

Q1 2013 HIGHLIGHTS

• Increased production 31% to 8,836 boe/d in Q1 2013 from 6,752 boe/d in Q1 2012
• Increased funds from operations 32% to $17.1 million in Q1 2013 from $13.0 million in Q1 2012
• Increased bank credit facility to $140.0 million from $100.0 million
• Completed an additional 6.4 net successful wells at Edson, AB
• Subsequent to Q1 2013, signed agreements with Alliance and Aux Sable which will enhance netbacks at Edson, AB

The Company has experienced significant growth in oil and natural gas sales and funds from operations in Q1 2013 compared to Q1 2012. Successful capital activity during the past year, mainly at Edson, AB, resulted in a significant increase in production which, combined with higher quarter-over-quarter natural gas commodity prices, led to increased revenue and funds from operations.

Daily production for the three months ended March 31, 2013 increased 31% to 8,836 boe/d from 6,752 boe/d for the comparative period in 2012. The significant increase in production was mainly due to successful drilling activity at Edson, AB during the past 12 months, which saw 19 gross (14.4 net) wells drilled at a 100% success rate. Compared to the previous quarter, daily production increased 20% in Q1 2013 from 7,336 boe/d in Q4 2012 as a result of successful drilling activity.

Crocotta’s production profile for the first quarter of 2013 was comprised of 70% natural gas and 30% oil and NGLs, consistent with the production profile for 2012 which was comprised of 68% natural gas and 32% oil and NGLs.

Revenue totaled $28.3 million for the first quarter of 2013, up 40% from $20.1 million in the comparative period. The increase in revenue was mainly due to significant increases in production and natural gas commodity prices.

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

Differences between corporate and benchmark prices can be the result of quality differences (higher or lower API oil and higher or lower heat content natural gas), sour content, NGLs included in reporting, and various other factors. Crocotta’s differences are mainly the result of lower priced NGLs included in oil price reporting and higher heat content natural gas production that is priced higher than AECO reference prices. The Company’s corporate average oil and NGLs prices were 76.6% of Edmonton Par price for the three months ended March 31, 2013, consistent with 74.7% for the comparative period in 2012. Corporate average natural gas prices were 111.3% of AECO prices for the three months ended March 31, 2013, consistent with the comparative period results of 108.8%.

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

For the three months ended March 31, 2013, the realized gain on the oil contract was $0.1 million and the realized loss on the gas contracts was $0.5 million. For the three months ended March 31, 2013, the unrealized loss on the oil contract was $0.5 million and the unrealized loss on the gas contracts was $1.4 million.

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 March 31, 2013, oil, NGLs, and natural gas royalties increased 41% to $2.9 million from $2.1 million in the comparative period. This increase stemmed from a significant increase in revenue in the first quarter of 2013 compared to the first quarter of 2012 mainly due to significant increases in production and natural gas commodity prices.

The overall effective royalty rate was 10.4% for the three months ended March 31, 2013 compared to 10.3% for the three months ended March 31, 2012. The effective natural gas royalty rate increased from the comparative period due to significant increases in natural gas production and commodity prices.

Per unit production expenses for the three months ended March 31, 2013 were $6.13/boe, up from $5.18/boe for the comparative period ended March 31, 2012. The increase in production expenses is mainly due to higher costs associated with wells brought on production in Northeast BC during the latter part of 2012. The Company is currently expanding its infrastructure in this area and anticipates production expenses in this area to decrease once completed. Compared to the previous quarter ended December 31, 2012, per unit production expenses decreased 4% from $6.41/boe. The Company continues to focus on opportunities to maintain operational efficiencies to enhance operating netbacks.

Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended March 31, 2013 compared to the quarter ended March 31, 2012, transportation expenses decreased 35% to $0.72/boe from $1.10/boe. Oil and NGLs transportation expenses were higher in Q1 2012 as a result of a prior period adjustment for NGL transportation costs. The costs were incurred as a result of restrictions at the Edson gas plant where the majority of the Company’s production is processed. The restrictions resulted in the plant operator diverting volumes from the plant which resulted in additional unanticipated transportation costs. 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.

During the first quarter of 2013, Crocotta generated an operating netback of $25.01/boe, up 8% from $23.13/boe for the first quarter of 2012. The increase was mainly due to significant increases in natural gas commodity prices, partially offset by increases in royalties and operating costs. Operating netbacks in Q1 2013 were down slightly from operating netbacks of $26.57/boe in Q4 2012 due mainly to a marginal increase in the Company’s gas weighting due to production brought on during Q4 2012 in Northeast BC.

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

Depletion and depreciation for the three months ended March 31, 2013 was $13.46/boe, down 10% from $14.90/boe for the comparative period ended March 31, 2012. The decrease is due to a significant increase in proved and probable reserves stemming from successful drilling activities during 2012. Depletion and depreciation of $13.46/boe in Q1 2013 was consistent with depletion and depreciation of $13.49/boe for the previous quarter ended December 31, 2012.

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 three months ended March 31, 2013, total exploration and evaluation asset impairments of $0.2 million were recognized relating to the expiry of undeveloped land rights (CGU – Miscellaneous AB).

For the three months ended March 31, 2012, total exploration and evaluation asset impairments of $0.9 million were recognized. Asset impairments of $0.4 million were recognized relating to the determination of certain exploration and evaluation activities in southern Alberta to be uneconomical (CGU – Miscellaneous AB). Additional exploration and evaluation impairments of $0.5 million were recognized relating to the expiry of undeveloped land rights (CGU – Miscellaneous AB).

For the three months ended March 31, 2012, the Company recorded property, plant, and equipment impairments of $1.8 million relating to Smoky AB, Lookout Butte AB, Miscellaneous AB, and Saskatchewan CGUs mainly as a result of weakening natural gas prices at March 31, 2012.

General and administrative expenses (“G&A”) increased 10% to $1.93/boe for the first quarter of 2013 compared to $1.76/boe for the first quarter of 2012 due mainly to an increase in employment costs.

The Company grants stock options to officers, directors, employees and consultants and calculates the related share based compensation using the Black-Scholes-Merton option pricing model. The Company recognizes the expense over the individual vesting periods for the graded vesting awards and estimates a forfeiture rate at the date of grant and updates it throughout the vesting period. Share based compensation expense decreased to $0.65/boe for the three months ended March 31, 2013 from $1.56/boe in the comparative period due to a significant increase in production and the timing of the issuance of stock options. During the first quarter of 2013, the Company granted a minimal number of options (2012 – 0.7 million).

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 quarter of 2013 compared to the first quarter of 2012. At March 31, 2013, $88.5 million (2012 – $34.1 million) had been drawn on the Company’s credit facility.

DEFERRED INCOME TAXES

Deferred income tax expense on the earnings before taxes was $1.0 million in the first quarter of 2013 (2012 – $0.3 million). This was slightly larger than expected by applying the statutory tax rate to the earnings before taxes due to non-deductible items such as share based compensation.

Estimated tax pools at March 31, 2013 total approximately $314.0 million (December 31, 2012 – $299.6 million).

FUNDS FROM OPERATIONS

Funds from operations for the three months ended March 31, 2013 was $17.1 million ($0.19 per diluted share) compared to $13.0 million ($0.14 per diluted share) for the three months ended March 31, 2012. The increase was mainly due to a significant increase in production and natural gas commodity prices which resulted in a significant increase in revenue.

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

NET EARNINGS (LOSS)

The Company had net earnings of $2.6 million ($0.03 per diluted share) for the three months ended March 31, 2013 compared to a net loss of $0.3 million ($nil per diluted share) for the three months ended March 31, 2012. Net earnings arose in Q1 2013 as a result of a significant increase in revenue stemming from higher production and natural gas commodity prices.

For the three months ended March 31, 2013, the Company had capital expenditures of $31.5 million compared to capital expenditures of $27.6 million for the three months ended March 31, 2012. During the first quarter of 2013, Crocotta drilled a total of 5 (4.4 net) wells, which resulted in 3 (2.8 net) oil wells and 2 (1.6 net) liquids-rich natural gas wells.

LIQUIDITY AND CAPITAL RESOURCES

The Company had net debt of $94.6 million at March 31, 2013 compared to net debt of $80.1 million at December 31, 2012. The increase of $14.5 million was mainly due to $31.5 million used for the purchase and development of oil and natural gas properties and equipment and $0.1 million for decommissioning expenditures, offset by funds from operations of $17.1 million.

At March 31, 2013, the Company had a $140.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At March 31, 2013, $88.5 million (December 31, 2012 – $68.5 million) had been drawn on the revolving credit facility. In addition, at March 31, 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 review of the revolving credit facility by the bank is scheduled on or before June 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 $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 during the first quarter of 2013 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 March 31, 2013:

The Company has entered into a farm-in agreement to drill and complete two Edson Cardium wells. Under the terms of the farm-in agreement, the Company is committed to spud two wells prior to August 2013. The estimated total cost to drill and complete the wells is approximately $6.5 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:

A significant increase in production stemming from successful drilling activity 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 six previous quarters mainly as a result of asset impairments recognized in each quarter on non-core properties.

OPERATIONS UPDATE

In Q1 2013, Crocotta spent $32 million of its 2013 capital budget of $100 million that included completing1.6 net liquids-rich Bluesky horizontal wells and 4.8 net Cardium horizontal oil wells and construction of certain infrastructure projects at Edson and Dawson. Crocotta will continue its Edson drilling program after break-up and then commence liquids-rich Montney drilling at Dawson-Sunrise in mid to late Q3 2013.

Subsequent to quarter end, Crocotta also signed pipeline and marketing agreements with Alliance Pipeline Limited Partnership (“Alliance”) and Aux Sable Canada LP (“Aux Sable”) to move its natural gas and corresponding propane and butane at Edson out of the Alberta market in order to capture better pricing and reduce downtime.

We have summarized the effect of the new agreements as well as provided more detailed information of our ongoing operations below:

Edson Pipeline and Marketing Agreements

Crocotta has entered into rich gas premium agreements with Aux Sable and an interconnection agreement with Alliance providing access to premium markets in the United States.

Under the agreements, Crocotta will deliver approximately 6,000 boepd of liquids-rich gas into the Alliance pipeline. The liquids-rich gas will be processed and fractionated at Aux Sable Liquid Product’s Channahon facility in Illinois.

The agreements are effective immediately and Crocotta estimates it will be fully operational by June 1, 2013. Crocotta will continue to truck and deliver its oil and condensate from Edson into the Alberta market.

The expected benefits of such arrangement are as follows:

• Increased cash flow of over $6.5 million annually (based on 6,000 boepd) that results from enhanced pricing, lower operating costs and lower royalties. This equates to an increase of approximately $3 per boe for volumes delivered.
• Reduced or eliminated downtime due to partner and third party disruptions in facilities and pipelines. The Edson partner facility and third party pipelines experienced several disruptions in 2012 that led to approximately 22 days of unscheduled production interruption and downtime. Aux Sable’s 99% operating efficiency will allow Crocotta to avoid scheduled and unscheduled partner and third party pipeline infrastructure downtime estimated at a minimum of 10 days for the balance of 2013 and an expected minimum of 21 days in 2014.
• Access to United States markets for propane and butane that are larger and more competitive than in Alberta. Crocotta will also avoid the potential oversupply of propane and butane in Alberta that may push local prices even lower.
• Crocotta will also avoid recent and projected cost increases for fractionation of natural gas liquids in Alberta.

Edson Cardium

Crocotta has drilled or participated in drilling a total of 15 Cardium horizontal oil wells in the Edson area since late 2011. Results to date from the 11 wells that have been on production for more than 90 days is as follows:

In Q1 2013, Crocotta signed farm-in agreements covering approximately 10 sections of highly prospective Cardium lands and based on internal mapping has added approximately 21 gross (16 net) Cardium horizontal oil locations to its drilling inventory. As at the end of Q1 2013, the total number of high graded Cardium locations (net of Q1 2013 drilling) has increased to 46 net locations.

Based on current on-stream costs of approximately $3.35 million per well, and Crocotta’s internally generated type curve, the Edson Cardium wells will have an average rate of return of over 100% and a payback of less than one year.

Dawson/Sunrise Facility

Crocotta has received approval to install its gas plant facility at Dawson that will allow it to produce into the Alliance pipeline. Once completed, Crocotta will sell liquids-rich gas in conjunction with its Aux Sable agreement. In Q1 2013, Crocotta completed all required pipelines and will proceed to construct the facility in early Q3 2013. Once completed, the following benefits will be realized on Crocotta’s current production (900 boepd) and future drilling:

• Increase in netback of approximately $11 per boe as a result of revenue from NGLs and lower operating costs. This equates to an annualized increase of $3.6 million excluding drilling budgeted to commence in Q3 2013.
• Increase in realized liquids yield from nil to approximately 35 bbls per mmcf
• Reduction in operating costs from $11 per boe to approximately $6 per boe

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:

For the three months ended March 31, 2013, the realized gain on the oil contract was $0.1 million and the realized loss on the gas contracts was $0.5 million. For the three months ended March 31, 2013, the unrealized loss on the oil contract was $0.5 million and the unrealized loss on the gas contracts was $1.4 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 March 31, 2013, $14.8 million or 84.8% of the Company’s outstanding accounts receivable were current while $2.6 million or 15.2% were outstanding over 90 days but not impaired. During the three months ended March 31, 2013, the Company did not deem any outstanding accounts receivable to be uncollectable.

Liquidity risk

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

Safety and Environmental Risks

The oil and natural gas business is subject to extensive regulation pursuant to various municipal, provincial, national, and international conventions and regulations. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases, or emissions of various substances produced in association with oil and natural gas operations. Crocotta is committed to meeting and exceeding its environmental and safety responsibilities. Crocotta has implemented an environmental and safety policy that is designed, at a minimum, to comply with current governmental regulations set for the oil and natural gas industry. Changes to governmental regulations are monitored to ensure compliance. Environmental reviews are completed as part of the due diligence process when evaluating acquisitions. Environmental and safety updates are presented and discussed at each Board of Directors meeting. Crocotta maintains adequate insurance commensurate with industry standards to cover reasonable risks and potential liabilities associated with its activities as well as insurance coverage for officers and directors executing their corporate duties. To the knowledge of management, there are no legal proceedings to which Crocotta is a party or of which any of its property is the subject matter, nor are any such proceedings known to Crocotta to be contemplated.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROLS OVER FINANCIAL REPORTING

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

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

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

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

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

FORWARD-LOOKING INFORMATION

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

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

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

ADDITIONAL INFORMATION

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

Crocotta Energy Inc.

Notes to the Condensed Interim Consolidated Financial Statements

Three Months Ended March 31, 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 Financial Reporting Standards (“IFRS”).

The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on May 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

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 $3.3 million of additions during the three months ended March 31, 2013 were additions of $2.9 million related to the Edson AB CGU, $0.2 million related to the Northeast BC CGU, and $0.2 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 three months ended March 31, 2013, total exploration and evaluation asset impairments of $0.2 million were recognized relating to the expiry of undeveloped land rights (CGU – Miscellaneous AB).

5. PROPERTY, PLANT, AND EQUIPMENT

During the three months ended March 31, 2013, approximately $0.2 million (2012 – $0.1 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 three months ended March 31, 2013 included an estimated $215.3 million (2012 – $185.0 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $13.4 million (2012 – $8.2 million) for the estimated salvage value of production equipment and facilities.

6. CREDIT FACILITY

At March 31, 2013, the Company had a $140.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The revolving credit facility bears interest at prime plus a range of 0.50% to 2.50% and is secured by a $125 million fixed and floating charge debenture on the assets of the Company. At March 31, 2013, $88.5 million (December 31, 2012 – $68.5 million) had been drawn on the revolving credit facility. In addition, at March 31, 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 review of the revolving credit facility by the bank is scheduled on or before June 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 $29.9 million which is estimated to be incurred over the next 28 years. At March 31, 2013, a risk-free rate of 2.3% (December 31, 2012 – 2.3%) was used to calculate the net present value of the decommissioning obligations.

8. SHARE BASED COMPENSATION PLANS

Stock options

The Company has authorized and reserved for issuance 8.8 million common shares under a stock option plan enabling certain officers, directors, employees, and consultants to purchase common shares. The Company will not issue options exceeding 10% of the shares outstanding at the time of the option grants. Under the plan, the exercise price of each option equals the market price of the Company’s shares on the date of the grant. The options vest over a period of three years and an option’s maximum term is 5 years. At March 31, 2013, 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:

The following table summarizes the stock options outstanding and exercisable at March 31, 2013:

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:

The following table summarizes the warrants outstanding and exercisable at March 31, 2013:

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:

9. PER SHARE AMOUNTS

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

For the three months ended March 31, 2013, 2.3 million stock options (2012 – 8.6 million) and 2.3 million warrants (2012 – 3.5 million) were anti-dilutive and were not included in the diluted earnings per share calculation.

10. FINANCE EXPENSES

Finance expenses include the following:

11. FAIR VALUE OF FINANCIAL INSTRUMENTS

Derivatives

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

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

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

The fair value of derivative contracts used for risk management as shown in the statement of financial position as at March 31, 2013 is measured using level 2. During the three months ended March 31, 2013, there were no transfers between level 1, level 2, and level 3 classified assets and liabilities.

12. SUPPLEMENTAL CASH FLOW INFORMATION

For further information, please visit our website at www.crocotta.ca or contact:

Crocotta Energy Inc. Robert J. Zakresky, President & CEO
Suite 700, 639 – 5th Avenue SW Phone: (403) 538-3736
Calgary, Alberta T2P 0M9
Phone: (403) 538-3737 Nolan Chicoine, VP Finance & CFO
Fax: (403) 538-3735 Phone: (403) 538-3738