CALGARY, ALBERTA--(Marketwire - Aug. 5, 2010) - CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the three and six months ended June 30, 2010, including financial statements, notes to the financial statements, and Management's Discussion and Analysis. All dollar figures are Canadian dollars unless otherwise noted.
/T/
Three Months Ended Six Months Ended
June 30 June 30
% %
FINANCIAL 2010 2009 Change 2010 2009 Change
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($000s, except per share
amounts)
Oil and natural gas sales 7,720 6,358 21 18,682 13,420 39
Funds from operations (1) 2,597 1,884 38 6,717 3,601 87
per share - basic and
diluted 0.04 0.04 - 0.10 0.08 25
Net loss (2,935) (3,193) (8) (3,797) (6,498) (42)
per share - basic and
diluted (0.05) (0.07) (29) (0.06) (0.15) (60)
Capital expenditures 5,840 2,246 160 11,445 10,263 12
Property acquisitions - - - - 2,442 (100)
Property dispositions (1,360) (170) 700 (20,698) (170) 12,075
Net debt (2) 54,977 29,878 84
Common shares outstanding (000s)
weighted average - basic 65,126 43,985 48 65,116 43,985 48
weighted average - diluted 65,281 43,985 48 65,221 43,985 48
end of period - basic 65,133 43,985 48
end of period - diluted 74,560 50,466 48
(1) Funds from operations and funds from operations per share do not have
any standardized meaning prescribed by Canadian GAAP 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 to
cash flow from operating activities.
(2) Net debt includes current liabilities (including the revolving credit
facility and secured bridge facility and excluding the risk management
contracts) less current assets. Net debt does not have any standardized
meaning prescribed by Canadian GAAP 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.
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Three Months Ended Six Months Ended
June 30 June 30
% %
OPERATING 2010 2009 Change 2010 2009 Change
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Number of producing days 91 91 181 181
Daily production
Oil and liquids - (bbls/d) 665 722 (8) 737 751 (2)
Natural gas - (mcf/d) 10,698 7,706 39 10,731 7,792 38
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Oil equivalent-(boe/d @ 6:1) 2,448 2,006 22 2,526 2,050 23
Revenue
Oil and liquids - ($/bbl) 60.91 55.62 10 66.68 51.08 31
Natural gas - ($/mcf) 4.14 3.86 7 5.04 4.59 10
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Oil equivalent-(boe/d @ 6:1) 34.66 34.82 - 40.87 36.17 13
Royalties
Oil and liquids - ($/bbl) 16.35 18.91 (14) 19.75 15.54 27
Natural gas - ($/mcf) 0.16 (0.81) 120 0.40 0.15 167
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Oil equivalent-(boe/d @ 6:1) 5.14 3.69 39 7.46 6.26 19
Production expenses
Oil and liquids - ($/bbl) 10.87 8.32 31 10.21 8.55 19
Natural gas - ($/mcf) 1.53 2.28 (33) 1.43 2.17 (34)
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Oil equivalent-(boe/d @ 6:1) 9.64 11.76 (18) 9.04 11.40 (21)
Transportation expenses
Oil and liquids - ($/bbl) 1.30 2.43 (47) 1.49 1.95 (24)
Natural gas - ($/mcf) 0.18 0.20 (10) 0.18 0.18 -
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Oil equivalent-(boe/d @ 6:1) 1.15 1.65 (30) 1.19 1.40 (15)
Operating netback (1)
Oil and liquids - ($/bbl) 32.39 25.96 25 35.23 25.04 41
Natural gas - ($/mcf) 2.27 2.19 4 3.03 2.09 45
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Oil equivalent-(boe/d @ 6:1) 18.73 17.72 6 23.18 17.11 35
Realized loss on risk
management contracts
- ($/boe) 1.00 - 100 1.28 - 100
Unrealized loss (gain) on
risk management contracts
- ($/boe) 0.79 - 100 (1.42) - 100
General and administrative
expenses ($/boe) 3.39 5.98 (43) 3.82 6.35 (40)
Interest expense - ($/boe) 2.68 1.42 89 3.39 1.06 220
Depletion, depreciation, and
accretion - ($/boe) 27.89 32.10 (13) 26.18 31.43 (17)
Stock-based compensation
- ($/boe) 1.12 1.34 (16) 1.19 1.29 (8)
Future income tax recovery
- ($/boe) (4.96) (5.63) (12) (2.95) (5.50) (46)
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Net loss - ($/boe) (13.18) (17.49) (25) (8.31) (17.52) (53)
(1) Operating netback does not have any standardized meaning prescribed by
Canadian GAAP 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.
/T/
Operations Update
In the second quarter, Crocotta continued to develop and evaluate its key resource plays at Pembina, Edson and Dawson / Glacier.
At Pembina, Crocotta completed its first horizontal Cardium well and is preparing to drill an offset well in late August or early September (43%WI). At Dawson / Glacier, the Company completed one Montney vertical test well (50% WI) and drilled one additional vertical test well (100% WI). At Edson, Crocotta completed and started to produce its first horizontal Bluesky well (29% WI).
Crocotta is currently gathering additional information and anticipates it will press release a more detailed operational update by late August or early September.
Management's Discussion and Analysis ("MD&A")
July 28, 2010
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. On November 15, 2006, Crocotta commenced active oil and natural gas operations with the acquisition of certain oil and natural gas properties. Crocotta commenced trading on the Toronto Stock Exchange ("TSX") on October 17, 2007 under the symbol "CTA".
The MD&A should be read in conjunction with the unaudited interim financial statements and notes thereto for the three and six months ended June 30, 2010 and the audited annual consolidated financial statements and notes thereto for the year ended December 31, 2009. The unaudited interim financial statements and financial data contained in the MD&A have been prepared in accordance with Canadian generally accepted accounting principles ("GAAP") in Canadian currency (except where noted as being in another currency).
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.
BOE Conversions
Barrel of oil equivalent ("boe") amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil (6:1) unless otherwise stated. The term "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 equivalence 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 document 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 Canadian 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, depreciation and accretion, stock-based compensation, unrealized gains and losses on risk management contracts, future income taxes, goodwill impairment, and extraordinary gains and losses) and excludes the change in non-cash working capital related to operating activities and expenditures on asset retirement obligations and reclamation. 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 to 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 secured bridge facility and excluding the 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".
Crocotta Energy Inc.
Management's Discussion & Analysis
Three and Six Months Ended June 30, 2010
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 document 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.
/T/
Three Months Ended June 30 Six Months Ended June 30
Summary of
Financial Results 2010 2009 2008 2010 2009 2008
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($000s, except
per share amounts)
Oil and natural
gas sales 7,720 6,358 19,255 18,682 13,420 32,192
Funds from
operations 2,597 1,884 11,953 6,717 3,601 19,420
per share - basic
and diluted 0.04 0.04 0.36 0.10 0.08 0.59
Net earnings
(loss) (2,935) (3,193) 3,446 (3,797) (6,498) 4,254
per share - basic
and diluted (0.05) (0.07) 0.10 (0.06) (0.15) 0.13
Total assets 233,498 186,681 150,571
Net debt 54,977 29,878 9,170
/T/
General
On August 13, 2009, the Company closed a business combination whereby it acquired all of the issued and outstanding shares of Salvo Energy Corporation ("Salvo"). Salvo had oil and natural gas assets located in West Central Alberta that produced approximately 1,550 boe/d at the time of closing of the acquisition. Subsequent to the acquisition, Crocotta initiated a sales process on several of the Company's non-core oil and natural gas assets. During the latter half of 2009 and the first half of 2010, the Company sold certain non-core oil and natural gas properties for cash proceeds of approximately $31.3 million. Production from these assets totaled approximately 880 boe/d.
/T/
Production Three Months Ended June 30 Six Months Ended June 30
2010 2009 % Change 2010 2009 % Change
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Average Daily
Production
Oil and NGLs
(bbls/d) 665 722 (8) 737 751 (2)
Natural gas
(mcf/d) 10,698 7,706 39 10,731 7,792 38
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Total (boe/d) 2,448 2,006 22 2,526 2,050 23
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/T/
Daily production for the three months ended June 30, 2010 increased 22% to 2,448 boe/d compared to 2,006 boe/d for the comparative period in 2009. Year-to-date, daily production increased 23% to 2,526 boe/d from 2,050 boe/d for the six months ended June 30, 2009. The increase in production was due to the acquisition of Salvo in August 2009. Daily production for the three months ended June 30, 2010 decreased 6% compared to 2,604 boe/d for the three months ended March 31, 2010, mainly due to the disposition of certain oil and natural gas assets in the first quarter of 2010.
Crocotta's production profile in the first half of 2010 was comprised of 71% natural gas and 29% oil and NGLs. During the year ended December 31, 2009, Crocotta's production profile was comprised of 63% natural gas and 37% oil and NGLs. The change in the production profile was the result of the sale of certain oil weighted assets in the first quarter of 2010.
/T/
Revenue Three Months Ended June 30 Six Months Ended June 30
($000s) 2010 2009 % Change 2010 2009 % Change
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Oil and NGLs 3,685 3,654 1 8,896 6,945 28
Natural gas 4,035 2,704 49 9,786 6,475 51
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Total revenue 7,720 6,358 21 18,682 13,420 39
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Average Sales Price
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Oil and NGLs
($/bbl) 60.91 55.62 10 66.68 51.08 31
Natural gas ($/mcf) 4.14 3.86 7 5.04 4.59 10
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Average sales price
($/boe) 34.66 34.82 - 40.87 36.17 13
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/T/
Revenue totaled $7.7 million for the second quarter of 2010, up 21% from $6.4 million for the second quarter of 2009. The increase was the result of a significant increase in production stemming from the acquisition of Salvo in August 2009. Year-to-date, revenue increased 39% to $18.7 million in 2009 compared to $13.4 million in 2008. The increase was due to a significant increase in production combined with an increase in oil, natural gas, and NGLs commodity prices.
The following table outlines the Company's realized wellhead prices and industry benchmarks:
/T/
Commodity Pricing Three Months Ended June 30 Six Months Ended June 30
2010 2009 % Change 2010 2009 % Change
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Oil and NGLs
Corporate Price
($Cdn/bbl) 60.91 55.62 10 66.68 51.08 31
West Texas
Intermediate
($US/bbl) 77.89 59.51 31 78.28 51.19 53
Edmonton Par
($Cdn/bbl) 75.46 66.16 14 77.89 58.16 34
Natural gas
Corporate Price
($Cdn/mcf) 4.14 3.86 7 5.04 4.59 10
AECO Price
($Cdn/mcf) 3.90 3.45 13 4.59 4.20 9
Exchange Rates
U.S./Cdn. Dollar
Average Exchange
Rate 0.9736 0.8581 13 0.9672 0.8311 16
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/T/
Corporate average oil and NGLs price were 80.7% and 85.6% of Edmonton Par price for the three and six months ended June 30, 2010, respectively. Corporate average natural gas prices were 106.2% and 109.8% of AECO prices for the three and six months ended June 30, 2010, respectively. Differences between corporate and benchmark prices can be a result of quality (higher or lower API, higher or lower heat content), 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. Note that these differences change on a monthly basis depending on demand for each particular product.
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 2010. Beginning January 1, 2010, the Company entered into hedges in the form of monthly settled puts ("Floors") as detailed below.
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Product Period Production Floor Price
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Oil January 2010 - December 2010 1,000 bbls/d WTI CDN $50.00/bbl
Gas January 2010 - December 2010 10.0 mmcf/d AECO CDN $4.00/mcf
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/T/
For the three months ended June 30, 2010, the realized loss on the risk management contracts was $0.2 million and the unrealized loss on the risk management contracts was $0.2 million. Year-to-date, the realized loss on the risk management contracts was $0.6 million and the unrealized gain on the risk management contracts was $0.6 million. The fair value of the risk management contracts at June 30, 2010 was a liability of $0.4 million.
/T/
Royalties Three Months Ended June 30 Six Months Ended June 30
($000s) 2010 2009 % Change 2010 2009 % Change
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Oil and NGLs 989 1,242 (20) 2,635 2,113 25
Natural gas 155 (568) 127 776 210 270
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Total royalties 1,144 674 70 3,411 2,323 47
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Average Royalty
Rate (% of sales)
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Oil and NGLs 26.8 34.0 (21) 29.6 30.4 (3)
Natural gas 3.8 (21.0) 118 7.9 3.2 147
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Average royalty
rate 14.8 10.6 40 18.3 17.3 6
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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.
For the three months ended June 30, 2010, oil, NGLs, and natural gas royalties increased 70% to $1.1 million compared to $0.7 million for the comparative period. For the six months ended June 30, 2010, oil, NGLs, and natural gas royalties increased 47% to $3.4 million compared to $2.3 million for the six months ended June 30, 2009. The increase was the result of a significant increase in production and an increase in oil, natural gas, and NGLs commodity prices. Natural gas royalties in Q2 2009 were negative as a result of favorable prior period adjustments to the annual capital cost and processing fee deductions and an increase in the monthly capital cost and processing fee deductions.
The overall effective royalty rate was 14.8% for the three months ended June 30, 2010, compared to 10.6% for the quarter ended June 30, 2009. Year-to-date, the overall effective royalty rate was 18.3% in 2010 compared to 17.3% in 2009. The effective oil and NGLs royalty rate for the three and six months ended June 30, 2010 decreased as a result of the disposition of certain oil weighted assets in the first quarter of 2010 that had higher associated royalty rates. The effective natural gas royalty rate for the three and six months ended June 30, 2010 increased from the comparative periods due to an increase in production and natural gas commodity prices.
/T/
Production Expenses Three Months Ended Six Months Ended
June 30 June 30
2010 2009 % Change 2010 2009 % Change
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Oil and NGLs
($/bbl) 10.87 8.32 31 10.21 8.55 19
Natural gas ($/mcf) 1.53 2.28 (33) 1.43 2.17 (34)
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Total ($/boe) 9.64 11.76 (18) 9.04 11.40 (21)
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/T/
Per unit production expenses for the three months ended June 30, 2010 were $9.64/boe, down significantly from $11.76/boe for the comparative period ended June 30, 2009. Year-to-date, per unit production expenses declined 21% to $9.04/boe in 2010 compared to $11.40/boe in 2009. Per unit production expenses increased 14% to $9.64/boe in Q2 2010 compared to $8.47/boe in Q1 2010 due mainly to property taxes paid during the second quarter.
Oil and NGLs per unit production expenses increased for the three and six months ended June 30, 2010 from the comparative periods in 2009 due to the disposition of certain oil weighted assets in the first quarter of 2010 that had lower associated production expenses. Natural gas per unit production expenses declined for the three and six months ended June 30, 2010 from the comparative periods in 2009 as a result of the acquisition of Salvo and other oil and natural gas assets in 2009 which had lower associated operating costs. The natural gas assets acquired included ownership interests in two separate gas plants that generate processing and gathering income related to joint venture and third party production resulting in a reduction in production expenses. The Company continues to focus on opportunities that will improve operational efficiencies and reduce per boe production expenses to enhance netbacks.
/T/
Transportation Expenses Three Months Ended Six Months Ended
June 30 June 30
2010 2009 % Change 2010 2009 % Change
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Oil and NGLs ($/bbl) 1.30 2.43 (47) 1.49 1.95 (24)
Natural gas ($/mcf) 0.18 0.20 (10) 0.18 0.18 -
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Total ($/boe) 1.15 1.65 (30) 1.19 1.40 (15)
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/T/
Transportation expenses are mainly third-party pipeline tariffs incurred to deliver the products to the purchasers at main hubs. For the quarter ended June 30, 2010 compared to the quarter ended June 30, 2009, transportation expenses decreased 30% to $1.15/boe from $1.65/boe. Year-to-date, transportation expenses decreased to $1.19/boe in 2010 from $1.40/boe in 2009. Natural gas transportation expenses were consistent year-over-year, while oil and NGLs transportation expenses decreased significantly. The decrease in oil and NGLs transportation costs in 2010 from 2009 was due to an adjustment incurred in the second quarter of 2009 relating to prior period expenses, which resulted in higher transportation expenses in Q2 2009.
/T/
Operating Netback Three Months Ended June 30 Six Months Ended June 30
2010 2009 % Change 2010 2009 % Change
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Oil and NGLs
($/bbl)
Revenue 60.91 55.62 10 66.68 51.08 31
Royalties 16.35 18.91 (14) 19.75 15.54 27
Production expenses 10.87 8.32 31 10.21 8.55 19
Transportation
expenses 1.30 2.43 (47) 1.49 1.95 (24)
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Operating netback 32.39 25.96 25 35.23 25.04 41
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Natural gas ($/mcf)
Revenue 4.14 3.86 7 5.04 4.59 10
Royalties 0.16 (0.81) 120 0.40 0.15 167
Production expenses 1.53 2.28 (33) 1.43 2.17 (34)
Transportation
expenses 0.18 0.20 (10) 0.18 0.18 -
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Operating netback 2.27 2.19 4 3.03 2.09 45
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Combined ($/boe)
(6:1)
Revenue 34.66 34.82 - 40.87 36.17 13
Royalties 5.14 3.69 39 7.46 6.26 19
Production expenses 9.64 11.76 (18) 9.04 11.40 (21)
Transportation
expenses 1.15 1.65 (30) 1.19 1.40 (15)
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Operating netback 18.73 17.72 6 23.18 17.11 35
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/T/
During the second quarter of 2010, Crocotta generated an operating netback of $18.73/boe, up 6% from $17.72/boe for the second quarter of 2009. Year-to-date, the Company generated an operating netback of $23.18/boe in 2010, up 35% from $17.11/boe in 2009. The increase in the operating netback was mainly due to an increase in oil, NGLs, and natural gas commodity prices and a decrease in production expenses.
The following is a reconciliation of operating netback per boe to net loss per boe for the periods noted:
/T/
Three Months Ended June 30 Six Months Ended June 30
($/boe) 2010 2009 % Change 2010 2009 % Change
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Operating netback 18.73 17.72 6 23.18 17.11 35
Realized loss on
risk management
contracts 1.00 - 100 1.28 - 100
Unrealized loss
(gain) on risk
management
contracts 0.79 - 100 (1.42) - 100
General and
administrative
expenses 3.39 5.98 (43) 3.82 6.35 (40)
Interest expense 2.68 1.42 89 3.39 1.06 220
Depletion,
depreciation,
and accretion 27.89 32.10 (13) 26.18 31.43 (17)
Stock-based
compensation 1.12 1.34 (16) 1.19 1.29 (8)
Future income tax
recovery (4.96) (5.63) (12) (2.95) (5.50) (46)
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Net loss (13.18) (17.49) (25) (8.31) (17.52) (53)
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General and Administrative
Expenses Three Months Ended June 30 Six Months Ended June 30
($000s) 2010 2009 % Change 2010 2009 % Change
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G&A expenses
(gross) 1,142 1,281 (11) 2,512 2,862 (12)
G&A capitalized (148) (171) (13) (320) (398) (20)
G&A recoveries (240) (18) 1,233 (446) (108) 313
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G&A expenses (net) 754 1,092 (31) 1,746 2,356 (26)
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G&A expenses ($/boe) 3.39 5.98 (43) 3.82 6.35 (40)
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/T/
General and administrative expenses ("G&A") decreased to $3.39/boe for the second quarter of 2010 compared to $5.98/boe for the quarter ended June 30, 2009. Year-to-date, G&A expenses decreased 40% to $3.82/boe in 2010 from $6.35/boe in 2009. The decrease per boe was due to a significant increase in production combined with an increase in G&A recoveries and a decrease in employment costs.
/T/
Interest Three Months Ended June 30 Six Months Ended June 30
($000s) 2010 2009 % Change 2010 2009 % Change
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Interest expense 622 260 139 1,640 426 285
Interest income (24) - 100 (93) (33) 182
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Net interest expense 598 260 130 1,547 393 294
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Interest expense
($/boe) 2.68 1.42 89 3.39 1.06 220
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/T/
Interest expense amounts in the first half of 2010 relate mainly to interest incurred on amounts drawn from the Company's credit facility. Interest expense also includes interest incurred on a secured bridge facility acquired in conjunction with the acquisition of Salvo in August 2009, which was repaid in full during the first quarter of 2010. The increase in interest expense correlates to the increase in amounts drawn on the revolving credit facility in 2010 compared to 2009.
/T/
Depletion, Depreciation and Accretion
Three Months Ended June 30 Six Months Ended June 30
2010 2009 % Change 2010 2009 % Change
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DD&A ($000s) 6,213 5,861 6 11,969 11,660 3
DD&A ($/boe) 27.89 32.10 (13) 26.18 31.43 (17)
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/T/
Depletion, depreciation and accretion ("DD&A") decreased 13% to $27.89/boe for the quarter ended June 30, 2010 compared to $32.10/boe for the quarter ended June 30, 2009. Year-to-date, DD&A decreased 17% to $26.18/boe in 2010 from $31.43/boe in 2009. The decrease in DD&A was due to a significant increase in proved reserves as a result of the acquisition of Salvo in August 2009. The provision for DD&A for the three and six months ended June 30, 2010 includes $0.2 million (2009 - $0.1 million) and $0.3 million (2009 - $0.1 million), respectively, for accretion of asset retirement obligations.
/T/
Stock-based Compensation
Three Months Ended June 30 Six Months Ended June 30
2010 2009 % Change 2010 2009 % Change
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Stock-based
compensation ($000s) 248 245 1 543 478 14
Stock-based
compensation
($/boe) 1.12 1.34 (16) 1.19 1.29 (8)
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/T/
The Company grants stock options to officers, directors, employees and consultants and calculates the related stock-based compensation using the Black-Scholes option-pricing model. The Company recognizes the expense over the vesting period of the stock options. Stock-based compensation expense decreased to $1.12/boe for the three months ended June 30, 2010 from $1.34/boe in the comparative period. Year-to-date, stock-based compensation decreased to $1.19/boe in 2010 from $1.29/boe in 2009. During the first half of 2010, the Company granted 0.2 million options (2009 - 1.0 million), 0.4 million options were forfeited (2009 - nil), and 0.1 million options were exercised (2009 - nil).
Taxes
At June 30, 2010, the Company had approximately $220.6 million in effective tax pools, losses, and share issue costs.
/T/
June 30, June 30,
2010 2009 % Change
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($000s)
Canadian oil and gas property expense (COGPE) 27,691 18,302 51
Canadian development expense (CDE) 46,157 39,349 17
Canadian exploration expense (CEE) 82,660 71,970 15
Undepreciated capital costs (UCC) 34,090 28,385 20
Non-capital losses carried forward 33,199 15,270 117
Capital losses carried forward 1,796 1,796 -
Share issue costs 1,043 1,871 (44)
Valuation allowance (5,996) (7,121) (16)
----------------------------------------------------------------------------
Total pools, losses, and share issue costs 220,640 169,822 30
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Funds from Operations
Funds from operations for the three months ended June 30, 2010 was $2.6 million ($0.04 per diluted share) compared to $1.9 million ($0.04 per diluted share) for the three months ended June 30, 2009. Year-to-date, funds from operations was $6.7 million ($0.10 per diluted share) in 2010 compared to $3.6 million ($0.08 per diluted share) in 2009. The increase was a result of higher production and higher oil, NGLs, and natural gas commodity prices in the first half of 2010 compared to the first half of 2009.
The following is a reconciliation of funds from operations to cash flow from operating activities for the periods noted:
/T/
Three Months Ended June 30 Six Months Ended June 30
2010 2009 % Change 2010 2009 % Change
----------------------------------------------------------------------------
Funds from
operations
(non-GAAP) 2,597 1,884 38 6,717 3,601 87
Asset retirement
expenditures (298) - 100 (356) - 100
Change in non-cash
working capital (151) 114 232 (762) (65) 1,072
----------------------------------------------------------------------------
Cash flow from
operating
activities (GAAP) 2,148 1,998 8 5,599 3,536 58
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Net Loss
The Company had a net loss of $2.9 million ($0.05 per diluted share) for the three months ended June 30, 2010 compared to a net loss of $3.2 million ($0.07 per diluted share) for the three months ended June 30, 2009. Year-to-date, the Company had a net loss of $3.8 million ($0.06 per diluted share) in 2010 compared to a net loss of $6.5 million ($0.15 per diluted share) in 2009. The decrease in the net loss was mainly a result of higher production and higher oil, NGLs, and natural gas commodity prices in the first half of 2010 compared to the first half of 2009.
Capital Expenditures
For the three months ended June 30, 2010, the Company had net capital expenditures of $4.5 million compared to $2.1 million for the three months ended June 30, 2009. For the six months ended June 30, 2010, the Company had net capital dispositions of $9.3 million compared to net capital expenditures of $12.5 million for the six months ended June 30, 2009.
/T/
Three Months Ended June 30 Six Months Ended June 30
($000s) 2010 2009 % Change 2010 2009 % Change
----------------------------------------------------------------------------
Land 360 178 102 1,097 858 28
Drilling,
completions, and
workovers 2,962 1,219 143 6,039 6,501 (7)
Equipment 2,110 620 240 3,668 2,350 56
Geological and
geophysical 408 224 82 641 535 20
Other - 5 (100) - 19 (100)
----------------------------------------------------------------------------
Total exploration
and development 5,840 2,246 160 11,445 10,263 12
Property
acquisitions - - - - 2,442 (100)
Property
dispositions (1,360) (170) 700 (20,698) (170) 12,075
----------------------------------------------------------------------------
Net property
acquisitions
(dispositions) (1,360) (170) 700 (20,698) 2,272 1,011
----------------------------------------------------------------------------
Total capital
expenditures 4,480 2,076 116 (9,253) 12,535 174
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
During the first half of 2010, Crocotta drilled 4 (2.5 net) wells, which resulted in 1 (0.2 net) oil well, 2 (1.3 net) natural gas wells, and 1 (1.0 net) well anticipated to be completed in Q3 2010.
During the first six months of 2010, the Company sold certain non-core oil and natural gas properties to three unrelated parties for cash proceeds of approximately $20.7 million. Production from these assets totaled approximately 420 boe/d.
Liquidity and Capital Resources
The Company had net debt of $55.0 million at June 30, 2010 compared to net debt of $70.7 million at December 31, 2009. The decrease of $15.7 million was mainly due to $20.7 million in net property dispositions and funds from operations of $6.7 million, which were offset by $11.4 million used for the purchase and development of oil and natural gas properties and equipment and $0.4 million for asset retirement expenditures.
At June 30, 2010, the Company had total credit facilities of $65.0 million, consisting of a $65.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The demand loan credit facility bears interest at prime plus a range of 0.75% to 2.50% and is secured by a $235 million fixed and floating charge debenture on the assets of the Company. The next review of the demand loan credit facility by the bank is scheduled on or before September 30, 2010. At June 30, 2010, $53.4 million (December 31, 2009 - $52.4 million) had been drawn on the demand loan credit facility.
During the first six months of 2010, the Company sold certain non-core oil and natural gas properties for approximately $20.7 million. The majority of the proceeds were used to retire the remaining balance on the secured bridge facility during the first quarter of 2010. The secured bridge facility was acquired in conjunction with the acquisition of Salvo in 2009.
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. Downward trends in commodity prices have resulted in the Company experiencing reduced operating netbacks and funds from operations. Although commodity prices improved during the first half of 2010 compared to the same period in 2009, continued pressure on commodity prices would result in the Company experiencing reduced operating netbacks and funds from operations in future periods. The Company has partially mitigated this risk through commodity price hedges on its 2010 production in the form of monthly settled puts ("Floors"). The sale of non-core properties during the latter half of 2009 and the first half of 2010, the repayment of the secured bridge facility during the first quarter of 2010, and the increase in the Company's revolving operating demand loan credit facility to $65.0 million has allowed the Company to strengthen its financial position on a go forward basis and focus capital spending on its three core areas. Crocotta's capital program is flexible and can be adjusted as needed based upon the economic environment. Crocotta has implemented adequate strategies to protect its business as much as possible in the current economic environment, including strategies to balance funds from operations, available credit limits, and capital spending. However, Crocotta is still exposed to the risks associated with the current economic situation. The Company will continue to monitor the possible impact on its business and strategy and will make adjustments as necessary.
Contractual Obligations
The following is a summary of the Company's contractual obligations and commitments at June 30, 2010:
/T/
Less than 1 - 3 After 3
($000s) Total 1 year years years
----------------------------------------------------------------------------
Revolving credit facility 53,370 53,370 - -
Office leases 1,223 712 511 -
Field equipment leases 311 307 4 -
Firm transportation agreements 1,034 486 548 -
Capital processing agreements 500 - - 500
----------------------------------------------------------------------------
Total contractual obligations 56,438 54,875 1,063 500
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Outstanding Share Data
The Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, and Class A 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:
/T/
(000s) June 30, 2010 July 28, 2010
----------------------------------------------------------------------------
Voting common shares 65,133 65,141
Options 5,823 5,638
Warrants 3,604 3,537
----------------------------------------------------------------------------
Total 74,560 74,316
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Summary of Quarterly Results
Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3
2010 2010 2009 2009 2009 2009 2008 2008
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of
producing days 91 90 92 92 91 90 92 92
($000s,
except per
share
amounts)
----------------------------------------------------------------------------
Oil and
natural gas
sales 7,720 10,962 12,130 8,649 6,358 7,062 8,729 13,547
Funds from
operations 2,597 4,120 3,972 1,752 1,884 1,717 3,463 7,724
per share -
basic and
diluted 0.04 0.06 0.06 0.03 0.04 0.04 0.09 0.23
Net earnings
(loss)
before
extraordinary
items (2,935) (862) (4,155) (3,919) (3,193) (3,305) (2,511) 1,232
per share -
basic and
diluted (0.05) (0.01) (0.06) (0.06) (0.07) (0.08) (0.07) 0.04
Net earnings
(loss) (2,935) (862) 3,276 (3,919) (3,193) (3,305) (2,511) 1,232
per share -
basic and
diluted (0.05) (0.01) 0.05 (0.06) (0.07) (0.08) (0.07) 0.04
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
Oil and natural gas sales and funds from operations decreased in Q2 2010 from Q1 2010 and Q4 2009 and were consistent with results for the first three quarters of 2009. The decrease in oil and natural gas sales and funds from operations in Q2 2010 from Q1 2010 and Q4 2009 was the result of a decrease in oil, NGLs, and natural gas commodity prices. The decrease in commodity prices also resulted in an increase in the net loss in Q2 2010 from the prior quarter.
Critical Accounting Policies
Management is required to make judgments, assumptions, and estimates in the application of generally accepted accounting principles that have a significant impact on the financial results of the Company. By their nature, these estimates are subject to change and the effect on the financial statements of changes in such estimates in future periods could be significant. The following summarizes the accounting policies that are critical to determining the Company's financial results.
Full Cost Accounting - The Company follows the full cost method of accounting whereby all costs related to the acquisition of, exploration for, and development of oil and natural gas reserves are capitalized and charged against earnings. These costs, together with the estimated future costs to be incurred in developing proved reserves, are depleted or depreciated using the unit-of-production method based on the proved reserves before royalties as estimated by independent petroleum engineers. The costs of undeveloped properties are excluded from the costs subject to depletion and depreciation until it is determined whether proved reserves are attributable to the properties or impairment occurs. Reserve estimates can have a significant impact on earnings, as they are a key component in the calculation of depletion. A downward revision to the reserve estimate could result in higher depletion and thus lower net earnings. In addition, estimated reserves are also used in the calculation of the impairment (ceiling) test. Oil and natural gas properties are evaluated each reporting period through an impairment test to determine the recoverability of capitalized costs. The carrying amount is assessed as recoverable when the sum of the undiscounted cash flows expected from proved reserves plus the cost of unproved interests, net of impairments, exceeds the carrying amount. When the carrying amount is assessed not to be recoverable, an impairment loss is recognized to the extent that the carrying amount exceeds the sum of the discounted cash flows from proved and probable reserves plus the cost of unproved interests, net of impairments. The cash flows are estimated using expected future prices and costs and are discounted using a risk-free interest rate.
Proceeds from the sale of oil and natural gas properties are applied against capitalized costs, with no gain or loss recognized, unless such a sale would result in a change in the depletion rate of 20% or more.
Oil and Natural Gas Reserves - The Company's oil and natural gas reserves are evaluated and reported on by independent petroleum engineers. The estimates of reserves is a very subjective process as forecasts are based on engineering data, projected future rates of production, estimated future commodity prices and the timing of future expenditures, which are all subject to uncertainty and interpretation.
Asset Retirement Obligations - The Company is required to provide for future abandonment and site restoration costs. These costs are estimated based on existing laws, contracts or other policies. The obligations are initially measured at fair value and subsequently adjusted each reporting period for the passage of time, with the accretion charged to earnings, and for revisions to the estimated future cash flows. The asset retirement cost is capitalized to oil and natural gas properties and equipment and amortized into earnings on a basis consistent with depletion and depreciation. The estimate of future abandonment and site restoration costs involves estimates relating to the timing of abandonment, the economic life of the asset and the costs associated with abandonment and site restoration which are all subject to uncertainty and interpretation.
Recent Accounting Pronouncements
Business Combinations
The CICA issued Handbook Section 1582, Business Combinations, which replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently re-measured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. The Company is currently assessing the impact of the standard on potential future business combinations.
International Financial Reporting Standards (IFRS)
The Canadian Accounting Standards Board has confirmed that the use of IFRS will be required in 2011 for publicly accountable, profit-oriented enterprises. IFRS will replace current Canadian GAAP. The Company will be required to begin reporting under IFRS effective January 1, 2011 and will be required to provide information following IFRS for the comparative period. While IFRS uses a conceptual framework similar to Canadian GAAP, there are significant differences in accounting policies which must be addressed.
The Company has completed the diagnostic assessment phase of IFRS by comparing the differences between Canadian GAAP and IFRS. This assessment has provided insight into what are anticipated to be the most significant differences applicable to the Company. The Company is currently performing an in-depth review of the significant differences, identified during the preliminary assessment, in order to identify all specific Canadian GAAP and IFRS differences and select ongoing IFRS policies. The Company's external auditors have been and will continue to be involved throughout the process to ensure the Company's policies are in accordance with IFRS. The Company has determined that accounting for property, plant and equipment, impairment testing, asset retirement obligations, business combinations, stock-based compensation, and income taxes will be impacted by the conversion to IFRS. The impact of IFRS on the Company's consolidated financial statements is not reasonably determinable at this time. The Company plans to maintain both Candian GAAP and IFRS compliant financial statements in 2010.
In July 2009 an amendment to IFRS 1 First Time Adoption of International Reporting Standards was issued that applies to oil and gas assets. The amendment allows an entity that used full cost accounting under its previous GAAP to elect to measure oil and gas assets, including exploration and evaluation assets and development and production assets, at values determined under their previous GAAP with development and production assets being allocated pro rata values using reserve volumes or reserve values as of the date of adoption, providing that all assets are tested for impairment on adoption. The Company expects that it will use this exemption.
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 the management of Crocotta 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 Crocotta successfully acquiring or discovering new reserves. Without the continual addition of new reserves, any existing reserves Crocotta 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 which Crocotta has identified as being the most prospective for increasing Crocotta's reserves on an economic basis. To further mitigate reserve replacement risk, Crocotta has targeted a majority of its prospects in areas which have multi-zone potential, year-round access and lower drilling costs and employs advanced geological and geophysical techniques to increase the likelihood of finding additional reserves.
Operational Risks
Crocotta's operations are subject to the risks normally incidental to the operation and development of oil and natural gas properties and the drilling of oil and natural gas wells. Continuing production from a property, and to some extent the marketing of production therefrom, are largely dependent upon the ability of the operator of the property.
Market risk
Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk is comprised of foreign currency risk, interest rate risk, and other price risk, such as commodity price risk. The objective of market risk management is to manage and control market price exposures within acceptable limits, while maximizing returns.
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 U.S. 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
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. From time to time the Company may attempt to mitigate commodity price risk through the use of financial derivatives. Commencing January 2010, the Company entered into commodity price hedges in the form of monthly settled puts ("Floors"), as previously outlined.
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, 2009. 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 Canadian GAAP. The Company's internal controls over financial reporting includes 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 of assets 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 financial statements.
The Company evaluated the effectiveness of our internal controls over financial reporting as of December 31, 2009. 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. The Company's CEO and CFO have concluded that, based on their evaluation, the Company's internal controls over financial reporting were effective as of December 31, 2009. 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.
/T/
Crocotta Energy Inc.
Balance Sheets
(unaudited)
As at As at
June 30, December 31,
2010 2009
----------------------------------------------------------------------------
($000s)
----------------------------------------------------------------------------
Assets
Current assets:
Cash and cash equivalents 364 1,854
Accounts receivable 5,994 5,042
Prepaid expenses and deposits 834 1,443
----------------------------------------------------------------------------
7,192 8,339
Oil and natural gas properties and equipment
(note 3) 224,739 245,562
Future income tax asset 1,567 255
----------------------------------------------------------------------------
233,498 254,156
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued liabilities 8,799 6,397
Revolving credit facility (note 4) 53,370 52,355
Secured bridge facility (note 4) - 20,243
Risk management contracts (note 8(b)) 394 1,042
----------------------------------------------------------------------------
62,563 80,037
Asset retirement obligations (note 5) 9,971 10,084
Shareholders' equity:
Capital stock (note 6) 166,740 166,632
Contributed surplus (note 6(c)) 4,332 3,714
Deficit (10,108) (6,311)
----------------------------------------------------------------------------
160,964 164,035
----------------------------------------------------------------------------
233,498 254,156
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements
Approved by the Board of Directors:
Director, "signed" Rob Zakresky Director, "signed" Larry Moeller
The interim financial statements of the Company have not been reviewed by
the Company's auditors.
Crocotta Energy Inc.
Statements of Operations, Comprehensive Loss, and Retained Earnings
(Deficit)
Three months ended Six months ended
June 30, June 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
($000s, except per share amounts)
----------------------------------------------------------------------------
Revenue:
Oil and natural gas sales 7,720 6,358 18,682 13,420
Royalties (1,144) (674) (3,411) (2,323)
----------------------------------------------------------------------------
6,576 5,684 15,271 11,097
Realized gain (loss) on risk
management contracts (note 8(b)) (223) - (583) -
Unrealized gain (loss) on risk
management contracts (note 8(b)) (176) - 648 -
----------------------------------------------------------------------------
6,177 5,684 15,336 11,097
Expenses:
Production 2,147 2,147 4,133 4,228
Transportation 257 301 545 519
General and administrative 754 1,092 1,746 2,356
Interest 598 260 1,547 393
Depletion, depreciation and
accretion 6,213 5,861 11,969 11,660
Stock-based compensation 248 245 543 478
----------------------------------------------------------------------------
10,217 9,906 20,483 19,634
----------------------------------------------------------------------------
Loss before income taxes (4,040) (4,222) (5,147) (8,537)
Income Taxes:
Future income tax recovery (1,105) (1,029) (1,350) (2,039)
----------------------------------------------------------------------------
Net loss and comprehensive loss (2,935) (3,193) (3,797) (6,498)
Retained earnings (deficit),
beginning of period (7,173) (2,475) (6,311) 830
----------------------------------------------------------------------------
Deficit, end of period (10,108) (5,668) (10,108) (5,668)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net loss per share:
Basic and diluted (0.05) (0.07) (0.06) (0.15)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements
Crocotta Energy Inc.
Statements of Cash Flows
Three months ended Six months ended
June 30, June 30,
2010 2009 2010 2009
----------------------------------------------------------------------------
($000s)
----------------------------------------------------------------------------
Cash provided by (used in):
Operating:
Net loss (2,935) (3,193) (3,797) (6,498)
Items not affecting cash:
Depletion, depreciation and
accretion 6,213 5,861 11,969 11,660
Stock-based compensation 248 245 543 478
Unrealized loss (gain) on risk
management contracts (note 8(b)) 176 - (648) -
Future income tax recovery (1,105) (1,029) (1,350) (2,039)
----------------------------------------------------------------------------
2,597 1,884 6,717 3,601
Asset retirement expenditures (298) - (356) -
Net change in non-cash working
capital (151) 114 (762) (65)
----------------------------------------------------------------------------
2,148 1,998 5,599 3,536
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Financing:
Issuance of capital stock 22 - 65 -
Revolving credit facility 1,441 38 1,015 15,443
Secured bridge facility - - (20,243) -
Capital lease payments - (58) - (115)
----------------------------------------------------------------------------
1,463 (20) (19,163) 15,328
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Investing:
Purchase and development of oil and
natural gas properties and
equipment (5,840) (2,246) (11,445) (12,705)
Disposition of oil and natural gas
properties and equipment (note 2) 1,360 170 20,698 170
Net change in non-cash investing
working capital 906 98 2,821 (6,329)
----------------------------------------------------------------------------
(3,574) (1,978) 12,074 (18,864)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Change in cash and cash equivalents 37 - (1,490) -
Cash and cash equivalents, beginning
of period 327 - 1,854 -
----------------------------------------------------------------------------
Cash and cash equivalents, end of
period 364 - 364 -
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying notes to the financial statements
/T/
Crocotta Energy Inc.
Notes to the Financial Statements
Three and Six Months Ended June 30, 2010
(Tabular amounts in 000s, unless otherwise stated)
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. On November 15, 2006, Crocotta commenced active oil and natural gas operations with the acquisition of certain oil and natural gas properties. Crocotta commenced trading on the Toronto Stock Exchange ("TSX") on October 17, 2007 under the symbol "CTA".
1. SIGNIFICANT ACCOUNTING POLICIES
a) Basis of presentation
The interim financial statements of Crocotta have been prepared by management in accordance with Canadian generally accepted accounting principles ("GAAP"). The interim financial statements have been prepared following the same accounting policies and methods of computation as the audited consolidated financial statements for the year ended December 31, 2009. The disclosures provided below are incremental to those included with the audited annual consolidated financial statements. The interim financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto for the year ended December 31, 2009.
b) Recent accounting pronouncements
Business Combinations
The CICA issued Handbook Section 1582, Business Combinations, which replaces the previous business combinations standard. Under this guidance, the purchase price used in a business combination is based on the fair value of shares exchanged at the market price at acquisition date. Under the current standard, the purchase price used is based on the market price of shares for a reasonable period before and after the date the acquisition is agreed upon and announced. In addition, the guidance generally requires all acquisition costs to be expensed. Current standards allow for the capitalization of these costs as part of the purchase price. This new Section also addresses contingent liabilities, which will be required to be recognized at fair value on acquisition, and subsequently re-measured at each reporting period until settled. Currently, standards require only contingent liabilities that are payable to be recognized. The new guidance requires negative goodwill to be recognized in earnings rather than the current standard of deducting from non-current assets in the purchase price allocation. This standard applies prospectively to business combinations on or after January 1, 2011 with earlier application permitted. The Company is currently assessing the impact of the standard on potential future business combinations.
International Financial Reporting Standards (IFRS)
The Canadian Accounting Standards Board has confirmed that the use of IFRS will be required in 2011 for publicly accountable, profit-oriented enterprises. IFRS will replace current Canadian GAAP. The Company will be required to begin reporting under IFRS effective January 1, 2011 and will be required to provide information following IFRS for the comparative period.
2. PROPERTY DISPOSITIONS
During the six months ended June 30, 2010, the Company sold certain oil and natural gas properties to three unrelated parties for cash proceeds of approximately $20.7 million. The following table details the allocation of the proceeds on disposition:
/T/
Net assets disposed Amount
----------------------------------------------------------------------------
Oil and natural gas properties 21,172
Asset retirement obligation (474)
----------------------------------------------------------------------------
20,698
----------------------------------------------------------------------------
----------------------------------------------------------------------------
3. OIL AND NATURAL GAS PROPERTIES AND EQUIPMENT
June 30, December 31,
2010 2009
----------------------------------------------------------------------------
Oil and natural gas properties 292,876 302,070
Office and other equipment 347 347
----------------------------------------------------------------------------
293,223 302,417
Accumulated depletion and depreciation (68,484) (56,855)
----------------------------------------------------------------------------
Net book value 224,739 245,562
----------------------------------------------------------------------------
----------------------------------------------------------------------------
/T/
As at June 30, 2010, the cost of oil and natural gas properties includes approximately $34.2 million (December 31, 2009 - $36.4 million) relating to properties from which there is no production and no reserves assigned and which have been excluded from costs subject to depletion and depreciation. During the three and six months ended June 30, 2010, the provision for depletion, depreciation and accretion includes $0.2 million (2009 - $0.1 million) and $0.3 million (2009 - $0.1 million), respectively, for accretion of asset retirement obligations. During the three and six months ended June 30, 2010, the Company capitalized $0.1 million (2009 - $0.2 million) and $0.3 million (2009 - $0.4 million), respectively, of general and administrative costs and $0.1 million (2009 - $0.1 million) and $0.1 million (2009 - $0.1 million), respectively, of stock-based compensation.
The Company performed an impairment test calculation at June 30, 2010 to assess the recoverable value of the oil and natural gas properties. The oil and natural gas future prices are based on July 1, 2010 commodity price forecasts of the Company's independent reserve evaluators. These prices have been adjusted for commodity price differentials specific to the Company. The following table summarizes the benchmark prices used in the impairment test calculation. Based on these assumptions, there was no impairment at June 30, 2010.
/T/
Foreign Edmonton Light
WTI Oil Exchange Crude Oil AECO Gas
Year ($US/bbl) Rate ($Cdn/bbl) ($Cdn/mmbtu)
----------------------------------------------------------------------------
2010 80.00 0.950 83.26 4.62
2011 83.00 0.950 86.42 5.21
2012 86.00 0.950 89.58 5.95
2013 89.00 0.950 92.74 6.42
2014 92.00 0.950 95.90 6.79
2015 93.84 0.950 97.84 7.05
2016 95.72 0.950 99.81 7.40
2017 97.64 0.950 101.83 7.72
2018 99.59 0.950 103.88 7.89
2019 101.58 0.950 105.98 8.06
Escalate
Thereafter 2.0% per year 2.0% per year 2.0% per year
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4. CREDIT FACILITIES
At June 30, 2010, the Company had total credit facilities of $65.0 million, consisting of a $65.0 million revolving operating demand loan credit facility with a Canadian chartered bank. The demand loan credit facility bears interest at prime plus a range of 0.75% to 2.50% and is secured by a $235 million fixed and floating charge debenture on the assets of the Company. The next review of the demand loan credit facility by the bank is scheduled on or before September 30, 2010. At June 30, 2010, $53.4 million (December 31, 2009 - $52.4 million) had been drawn on the demand loan credit facility.
During the first six months of 2010, the Company sold certain non-core oil and natural gas properties for approximately $20.7 million (note 2). The majority of the proceeds were used to retire the remaining balance on the secured bridge facility during the first quarter of 2010. The secured bridge facility was acquired in conjunction with the acquisition of Salvo in 2009.
5. ASSET RETIREMENT OBLIGATIONS
The Company's asset retirement obligations result from net ownership interests in oil and natural gas properties including well sites, gathering systems, and processing facilities. The Company estimates the total undiscounted amount of cash flows (adjusted for inflation at 2% per year) required to settle its asset retirement obligations is approximately $26.8 million which is estimated to be incurred between 2010 and 2039. A credit-adjusted risk-free rate of 7% was used to calculate the fair value of the asset retirement obligations.
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A reconciliation of the asset retirement obligations is provided below:
Six Months Ended Year Ended
June 30, 2010 December 31, 2009
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Balance, beginning of period 10,084 4,158
Liabilities acquired upon business
combination - 6,531
Liabilities incurred in period 68 135
Liabilities disposed through property
dispositions (note 2) (474) (1,146)
Liabilities settled in period (47) (62)
Accretion expense 340 468
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Balance, end of period 9,971 10,084
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6. SHARE CAPITAL
a) Authorized
Unlimited number of voting common shares.
Unlimited number of non-voting common shares.
Class A preferred shares, issuable in series.
Class B preferred shares, issuable in series.
b) Issued and outstanding
Number Amount
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Voting common shares
Balance at December 31, 2009 65,084 166,632
Exercise of stock options 49 108
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Balance at June 30, 2010 65,133 166,740
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c) Contributed surplus
Six Months Ended Year Ended
June 30, 2010 December 31, 2009
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Balance, beginning of period 3,714 1,002
Stock-based compensation - expensed 543 2,403
Stock-based compensation - capitalized 118 309
Exercise of stock options (43) -
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Balance, end of period 4,332 3,714
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d) 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 2009, approval was obtained to extend the expiry date of the warrants to December 23, 2012.
On October 29, 2009, the Company issued an additional 1.2 million warrants at an exercise price of $1.40 per share in conjunction with a private placement share issuance.
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The Company had the following warrants outstanding at June 30, 2010:
Weighted
Number of Average Exercisable at
Warrants Price ($) June 30, 2010 Expiry Date
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Warrants
- issued at $1.40
per share 1,200 1.40 1,200 October 29, 2012
- issued at $3.75
per share 747 3.75 747 December 23, 2012
- issued at $4.05
per share 21 4.05 21 December 23, 2012
- issued at $4.50
per share 781 4.50 781 December 23, 2012
- issued at $5.25
per share 54 5.25 54 December 23, 2012
- issued at $6.00
per share 747 6.00 747 December 23, 2012
- issued at $6.75
per share 54 6.75 54 December 23, 2012
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3,604 3.67 3,604
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e) Stock options
The Company has authorized and reserved for issuance 6.5 million common shares under a stock option plan enabling certain officers, directors, employees, and consultants to purchase common shares. The Company will not issue options exceeding 10% of the shares outstanding at the time of the option grants. Under the plan, the exercise price of each option equals the market price of the Company's shares on the date of the grant. The options vest over a period of 3 years and an option's maximum term is 5 years. As at June 30, 2010, 5.8 million options have been granted and are outstanding at prices ranging from $1.10 to $3.75 per share with expiry dates ranging from January 23, 2012 to April 23, 2015.
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The Company had the following stock options outstanding at June 30, 2010:
Weighted
Number of Average
Options Price ($)
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Balance at December 31, 2009 6,072 2.08
Granted 225 1.58
Exercised (49) 1.32
Forfeited (425) 2.40
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Balance at June 30, 2010 5,823 2.05
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Exercisable at June 30, 2010 2,415 2.79
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f) Stock-based compensation
The compensation cost charged to earnings during the three and six months ended June 30, 2010 for the stock option plan was $0.2 million (2009 - $0.2 million) and $0.5 million (2009 - $0.5 million), respectively.
The Company granted 0.1 million options during the three months ended June 30, 2010 (2009 - nil) and 0.2 million options during the six months ended June 30, 2010 (2009 - 1.0 million). The fair value of each option granted during the three and six months ended June 30, 2010 was determined using the Black-Scholes option-pricing model with the following weighted average assumptions:
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Three Months Ended Six Months Ended
June 30, 2010 June 30, 2010
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Fair value per option $1.10 $1.06
Risk-free rate 2.8% 2.5%
Expected life 4.0 years 4.0 years
Expected volatility 93.1% 94.3%
Dividend yield - -
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g) Per share information
The weighted average number of shares outstanding for the determination of
basic and diluted per share amounts are as follows:
Three Months Ended Six Months Ended
June 30, 2010 June 30, 2010
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Basic 65,126 65,116
Diluted 65,281 65,221
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7. CAPITAL DISCLOSURES
The Company's objectives when managing capital are to maintain a flexible capital structure, which optimizes the cost of capital at an acceptable risk, and to maintain investor, creditor, and market confidence to sustain future development of the business.
The Company manages its capital structure and makes adjustments to it in light of changes in economic conditions and the risk characteristics of the underlying assets. The Company considers its capital structure to include shareholders' equity and net debt (current liabilities, including the revolving credit facility and secured bridge facility and excluding the risk management contracts, less current assets). To maintain or adjust the capital structure, the Company may, from time to time, issue shares, raise debt, and/or adjust its capital spending to manage its current and projected debt levels.
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June 30, December 31,
2010 2009
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Shareholders' equity 160,964 164,035
Net debt 54,977 70,656
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In addition, management prepares annual, quarterly, and monthly budgets, which are updated depending on varying factors such as general market conditions and successful capital deployment.
The Company's share capital is not subject to external restrictions; however, the Company's revolving operating demand loan credit facility includes a covenant requiring the Company to maintain a working capital ratio of not less than one-to-one. The working capital ratio, as defined by its creditor, is calculated as current assets plus any undrawn amounts available on its credit facilities less current liabilities excluding any current portion drawn on the credit facility. The Company was fully compliant with this covenant at June 30, 2010.
There were no changes in the Company's approach to capital management from the previous year.
8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company is exposed to market risks related to the volatility of commodity prices, foreign exchange rates, and interest rates. The Company employs risk management strategies and policies to ensure that any exposure to risk is in compliance with the Company's business objectives and risk tolerance levels. Risk management is ultimately established by the Board of Directors and is implemented by management.
a) Fair value of financial instruments
The Company's financial assets and financial liabilities are comprised of cash and cash equivalents, accounts receivable, prepaid expenses and deposits, accounts payable and accrued liabilities, risk management contracts, and amounts drawn on the revolving credit facility (note 4). The fair values of the Company's financial assets and financial liabilities approximate their carrying amount due to the short-term maturity of these instruments.
b) 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.
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 U.S. 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. A $0.01 increase or decrease in the Canadian/U.S. dollar exchange rate would have impacted net earnings and other comprehensive income by approximately $0.1 million for the three months ended June 30, 2010 and $0.1 million for the six months ended June 30, 2010.
Interest rate risk
The Company is exposed to interest rate risk as it borrows funds at floating interest rates (note 4). 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. A 100 basis point increase or decrease in interest rates would have impacted net earnings and other comprehensive income by approximately $0.1 million for the three months ended June 30, 2010 and $0.3 million for the six months ended June 30, 2010.
Commodity price risk
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. From time to time the Company may attempt to mitigate commodity price risk through the use of financial derivatives.
At June 30, 2010, the Company had the following risk management contracts outstanding:
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Product Period Production Floor Price
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Oil January 2010 - December 2010 1,000 bbls/d WTI CDN $50.00/bbl
Gas January 2010 - December 2010 10.0 mmcf/d AECO CDN $4.00/mcf
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For the three months ended June 30, 2010, the realized loss on the risk management contracts was $0.2 million and the unrealized loss on the risk management contracts was $0.2 million. Year-to-date, the realized loss on the risk management contracts was $0.6 million and the unrealized gain on the risk management contracts was $0.6 million. The fair value of the risk management contracts at June 30, 2010 was a liability of $0.4 million. The fair value of the risk management contracts has been determined using information classified as level two. Level two valuations are based on inputs, including quoted forward prices for commodities, time value, and volatility factors, which can be substantially observed or corroborated in the marketplace.
A $1.00/boe increase or decrease in commodity prices would have impacted net earnings and other comprehensive income by approximately $0.1 million for the three months ended June 30, 2010 and $0.3 million for the six months ended June 30, 2010.
c) 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 petroleum 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 balance sheet. At June 30, 2010, there are no material financial assets that the Company considers impaired.
d) Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they become due. The Company's processes for managing liquidity risk include ensuring, to the extent possible, that it will have sufficient liquidity to meet its liabilities when they become due. The Company prepares annual, quarterly, and monthly capital expenditure budgets, which are monitored and updated as required, and requires authorizations for expenditures on projects to assist with the management of capital. In managing liquidity risk, the Company ensures that it has access to additional financing, including potential equity issuances and additional debt financing. The Company also mitigates liquidity risk by maintaining an insurance program to minimize exposure to insurable losses.
The following are the contractual maturities of financial liabilities at June 30, 2010:
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1 to
Less than less than
Financial Liability 1 Year 2 Years Thereafter Total
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Accounts payable and
accrued liabilities 8,799 - - 8,799
Revolving credit
facility 53,370 - - 53,370
Risk management
contracts 394 - - 394
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62,563 - - 62,563
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CORPORATE INFORMATION
OFFICERS AND DIRECTORS
Robert J. Zakresky, CA BANK
President, CEO & Director National Bank of Canada
2700, 530 - 8th Avenue SW
Nolan Chicoine, MPAcc, CA Calgary, Alberta T2P 3S8
VP Finance & CFO
Terry L. Trudeau, P.Eng.
VP Operations & COO TRANSFER AGENT
Valiant Trust Company
Weldon Dueck, BSc., P.Eng. 310, 606 - 4th Street SW
VP Business Development Calgary, Alberta T2P 1T1
R.D. (Rick) Sereda, M.Sc., P.Geol.
VP Exploration
LEGAL COUNSEL
Helmut R. Eckert, P.Land Gowling Lafleur Henderson LLP
VP Land 1400, 700 - 2nd Street SW
Calgary, Alberta T2P 4V5
Kevin Keith
VP Production
Larry G. Moeller, CA, CBV AUDITORS
Chairman of the Board KPMG LLP
2700, 205 - 5th Avenue SW
Daryl H. Gilbert, P.Eng. Calgary, Alberta T2P 4B9
Director
Don Cowie
Director INDEPENDENT ENGINEERS
GLJ Petroleum Consultants Ltd.
Brian Krausert 4100, 400 - 3rd Avenue SW
Director Calgary, Alberta T2P 4H2
Gary W. Burns
Director
Don D. Copeland, P.Eng.
Director
Brian Boulanger
Director
Patricia Phillips
Director
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