CALGARY, ALBERTA–(Marketwired – May 13, 2014) – CROCOTTA ENERGY INC. (TSX:CTA) is pleased to announce its financial and operating results for the three months ended March 31, 2014, 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
| FINANCIAL RESULTS | |||||
| Three Months Ended March 31 | |||||
| ($000s, except per share amounts) | 2014 | 2013 | % Change | ||
| Oil and natural gas sales | 39,836 | 28,267 | 41 | ||
| Funds from operations (1) | 28,758 | 17,124 | 68 | ||
| Per share – basic | 0.30 | 0.19 | 58 | ||
| Per share – diluted | 0.29 | 0.19 | 53 | ||
| Net earnings | 9,518 | 2,604 | 266 | ||
| Per share – basic and diluted | 0.10 | 0.03 | 233 | ||
| Capital expenditures | 53,102 | 31,518 | 68 | ||
| Property dispositions | (400 | ) | – | 100 | |
| Net debt (2) | 140,696 | 94,590 | 49 | ||
| Common shares outstanding (000s) | |||||
| Weighted average – basic | 96,728 | 89,261 | 8 | ||
| Weighted average – diluted | 98,248 | 91,670 | 7 | ||
| End of period – basic | 97,699 | 89,261 | 9 | ||
| End of period – diluted | 105,661 | 100,188 | 5 | ||
| (1) | Funds from operations and funds from operations per share do not have any standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details and the Funds from Operations section in the MD&A for a reconciliation from cash flow from operating activities. | |
| (2) | Net debt includes current liabilities (excluding risk management contracts) and the credit facility less current assets. Net debt does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non- GAAP Measures section in the MD&A for more details. |
| OPERATING RESULTS | Three Months Ended March 31 | ||||||
| 2014 | 2013 | % Change | |||||
| Daily production | |||||||
| Oil and NGLs (bbls/d) | 2,545 | 2,691 | (5 | ) | |||
| Natural gas (mcf/d) | 38,385 | 36,869 | 4 | ||||
| Oil equivalent (boe/d) | 8,943 | 8,836 | 1 | ||||
| Revenue | |||||||
| Oil and NGLs ($/bbl) | 89.57 | 67.88 | 32 | ||||
| Natural gas ($/mcf) | 5.59 | 3.56 | 57 | ||||
| Oil equivalent ($/boe) | 49.49 | 35.55 | 39 | ||||
| Royalties | |||||||
| Oil and NGLs ($/bbl) | 8.73 | 9.16 | (5 | ) | |||
| Natural gas ($/mcf) | 0.19 | 0.21 | (10 | ) | |||
| Oil equivalent ($/boe) | 3.31 | 3.69 | (10 | ) | |||
| Production expenses | |||||||
| Oil and NGLs ($/bbl) | 5.18 | 5.24 | (1 | ) | |||
| Natural gas ($/mcf) | 0.92 | 1.09 | (16 | ) | |||
| Oil equivalent ($/boe) | 5.42 | 6.13 | (12 | ) | |||
| Transportation expenses | |||||||
| Oil and NGLs ($/bbl) | 1.41 | 0.90 | 57 | ||||
| Natural gas ($/mcf) | 0.14 | 0.11 | 27 | ||||
| Oil equivalent ($/boe) | 1.02 | 0.72 | 42 | ||||
| Operating netback (1) | |||||||
| Oil and NGLs ($/bbl) | 74.25 | 52.58 | 41 | ||||
| Natural gas ($/mcf) | 4.34 | 2.15 | 102 | ||||
| Oil equivalent ($/boe) | 39.74 | 25.01 | 59 | ||||
| Depletion and depreciation ($/boe) | (14.61 | ) | (13.46 | ) | 9 | ||
| Asset impairment ($/boe) | – | (0.25 | ) | (100 | ) | ||
| General and administrative expenses ($/boe) | (1.94 | ) | (1.93 | ) | 1 | ||
| Share based compensation ($/boe) | (0.51 | ) | (0.65 | ) | (22 | ) | |
| Finance expenses ($/boe) | (1.68 | ) | (1.12 | ) | 50 | ||
| Gain on sale of assets ($/boe) | 0.50 | – | 100 | ||||
| Deferred tax expense ($/boe) | (4.12 | ) | (1.32 | ) | 212 | ||
| Realized loss on risk management contracts ($/boe) | (0.59 | ) | (0.58 | ) | 2 | ||
| Unrealized loss on risk management contracts ($/boe) | (4.95 | ) | (2.44 | ) | 103 | ||
| Net earnings ($/boe) | 11.84 | 3.26 | 263 | ||||
| (1) | Operating netback does not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures used by other companies. Please refer to the Non-GAAP Measures section in the MD&A for more details. |
OPERATIONS UPDATE
In Q1 2014, Crocotta focused on expanding and exploiting both core areas and new initiatives. Most of the drilling continues to be at Edson, while significant capital was spent in expanding the opportunity bases at Edson, at Dawson (Montney) and Stoddart (new oil exploration prospect).
At Edson, Crocotta drilled 9 (8.0 net) wells targeting Cardium light oil and Bluesky liquids-rich gas and added to its infrastructure to accommodate future growth and to maintain its current low cost structure. Approximately 87% of Q1 2014 capital excluding land was spent at Edson.
In the Montney, Crocotta drilled one upper Montney well at Sunrise and continues to work on its plans to expand its gas plant to handle sour gas and to expand the capacity of its current plant. In Q3 2014, Crocotta will drill an acid gas injection well and work on regulatory applications for the expansion. It is estimated that the plant would not be expanded and operational until late 2015.
At Stoddart in Northeast British Columbia, Crocotta purchased a well that it intends to use for water disposal to assist in testing its new light oil play. In 2013, Crocotta had drilled and completed a test well which produced both light oil and water. In Q3 2014, Crocotta intends to set up water disposal and properly evaluate the well. Crocotta has accumulated over 40 sections of land in the general Stoddart area.
As part of an effort to expand its land base in all areas, Crocotta invested approximately 30% of its Q1 2014 capital on land purchases. Land was purchased in all areas noted above and will assist in Crocotta long term growth plans for 2015 and beyond.
For the remainder of 2014, Crocotta’s capital will be spent on the continual evaluation of all three areas and we look forward to reporting on new developments as they arise.
MANAGEMENT’S DISCUSSION AND ANALYSIS (“MD&A”)
May 8, 2014
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, 2014 and the audited consolidated financial statements and related notes for the year ended December 31, 2013. 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”.
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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 plus non-cash items (depletion and depreciation, asset impairments, share based compensation, non-cash finance expenses, unrealized gains and losses on risk management contracts, and deferred income taxes) and excludes the change in non-cash working capital related to operating activities and expenditures on decommissioning obligations. The Company also presents funds from operations per share whereby amounts per share are calculated using weighted average shares outstanding, consistent with the calculation of earnings per share. Funds from operations is reconciled from cash flow from operating activities under the heading “Funds from Operations”.
Management uses net debt as a measure to assess the Company’s financial position. Net debt includes current liabilities (excluding risk management contracts) and the credit facility less current assets.
Management considers operating netback an important measure as it demonstrates its profitability relative to current commodity prices. Operating netback, which is calculated as average unit sales price less royalties, production expenses, and transportation expenses, represents the cash margin for every barrel of oil equivalent sold. Operating netback per boe is reconciled to net earnings per boe under the heading “Operating Netback”.
Q1 2014 HIGHLIGHTS
| SUMMARY OF FINANCIAL RESULTS | ||||
| Three Months Ended March 31 | ||||
| ($000s, except per share amounts) | 2014 | 2013 | % Change | |
| Oil and natural gas sales | 39,836 | 28,267 | 41 | |
| Funds from operations | 28,758 | 17,124 | 68 | |
| Per share – basic | 0.30 | 0.19 | 58 | |
| Per share – diluted | 0.29 | 0.19 | 53 | |
| Net earnings | 9,518 | 2,604 | 266 | |
| Per share – basic and diluted | 0.10 | 0.03 | 233 | |
| Total assets | 417,123 | 322,053 | 30 | |
| Total long-term liabilities | 157,206 | 22,086 | 612 | |
| Net debt | 140,696 | 94,590 | 49 | |
The Company has experienced significant growth in oil and natural gas sales, funds from operations, and net earnings in Q1 2014 compared to Q1 2013. Continued successful capital activity during the past year at Edson, AB and Northeast BC combined with a significant increase in oil, NGLs, and natural gas commodity prices and a decrease in production expenses led to increased revenue, funds from operations, and net earnings. Total assets and net debt have also increased period-over-period as a result of significant capital activity during the past year.
| PRODUCTION | Three Months Ended March 31 | |||
| 2014 | 2013 | % Change | ||
| Average Daily Production | ||||
| Oil and NGLs (bbls/d) | 2,545 | 2,691 | (5 | ) |
| Natural gas (mcf/d) | 38,385 | 36,869 | 4 | |
| Combined (boe/d) | 8,943 | 8,836 | 1 | |
Daily production of 8,943 boe/d for the three months ended March 31, 2014 was consistent with daily production of 8,836 boe/d for the comparative period in 2013. Compared to the previous quarter, daily production in Q1 2014 decreased slightly from 9,233 boe/d in Q4 2013 due to delays in bringing on new wells in Northeast BC, operational difficulties with the new Northeast BC facility, and pipeline construction delays.
Crocotta’s production profile for the first quarter of 2014 was comprised of 72% natural gas and 28% oil and NGLs, consistent with the production profile for the year ended December 31, 2013 which was comprised of 71% natural gas and 29% oil and NGLs.
| REVENUE | Three Months Ended March 31 | ||
| ($000s) | 2014 | 2013 | % Change |
| Oil and NGLs | 20,519 | 16,438 | 25 |
| Natural gas | 19,317 | 11,829 | 63 |
| Total | 39,836 | 28,267 | 41 |
| Average Sales Price | |||
| Oil and NGLs ($/bbl) | 89.57 | 67.88 | 32 |
| Natural gas ($/mcf) | 5.59 | 3.56 | 57 |
| Combined ($/boe) | 49.49 | 35.55 | 39 |
Revenue totaled $39.8 million for the first quarter of 2014, up 41% from $28.3 million in the comparative period. The increase in revenue was due to significant increases in oil, NGLs, and natural gas commodity prices.
The following table outlines the Company’s realized wellhead prices and industry benchmarks:
| Commodity Pricing | Three Months Ended March 31 | |||
| 2014 | 2013 | % Change | ||
| Oil and NGLs | ||||
| Corporate price ($CDN/bbl) | 89.57 | 67.88 | 32 | |
| Edmonton par ($CDN/bbl) | 100.18 | 88.65 | 13 | |
| West Texas Intermediate ($US/bbl) | 98.68 | 94.35 | 5 | |
| Natural gas | ||||
| Corporate price ($CDN/mcf) | 5.59 | 3.56 | 57 | |
| AECO price ($CDN/mcf) | 5.42 | 3.20 | 69 | |
| Exchange rate | ||||
| CDN/US dollar average exchange rate | 0.9066 | 0.9917 | (9 | ) |
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 price was 89.4% of Edmonton Par price for the three months ended March 31, 2014, up from 76.6% for the comparative period in 2013. The Company experienced an increase in realized NGLs prices for a significant portion of its NGLs volumes at Edson, AB and Northeast BC as they were transitioned to new marketing arrangements in June 2013 and September 2013, respectively, which allowed the Company to access higher propane and butane prices in the United States. Corporate average natural gas price was 103.1% of AECO price for the three months ended March 31, 2014, down from 111.3% in the comparative period. The decrease in realized natural gas prices was also due to gas volumes at Edson, AB and Northeast BC being transitioned to the new marketing arrangements in 2013, which decreased the premium received on the Company’s natural gas production.
Future prices received from the sale of the products may fluctuate as a result of market factors. In addition, the Company may enter into commodity price contracts to manage future cash flows. For the period ended March 31, 2014, the realized loss on the Company’s oil contracts was $0.5 million, the unrealized loss on the oil contracts was $1.1 million, and the unrealized loss on the natural gas contracts was $2.9 million. At March 31, 2014, the Company had the following commodity price contracts outstanding:
| Commodity | Period | Type of Contract | Quantity Contracted | Contract Price |
| Oil | January 1, 2014 – December 31, 2014 | Financial – Swap | 500 bbls/d | WTI CDN $100.80/bbl |
| Oil | April 1, 2014 – June 30, 2014 | Financial – Swap | 500 bbls/d | WTI CDN $108.00/bbl |
| Oil | July 1, 2014 – September 30, 2014 | Financial – Swap | 500 bbls/d | WTI CDN $110.00/bbl |
| Natural Gas | April 1, 2014 – October 31, 2014 | Financial – Swap | 5,000 GJ/d | AECO CDN $3.505/GJ |
| Natural Gas | April 1, 2014 – October 31, 2014 | Financial – Swap | 5,000 GJ/d | AECO CDN $3.650/GJ |
| Natural Gas | April 1, 2014 – October 31, 2014 | Financial – Swap | 10,000 GJ/d | AECO CDN $3.745/GJ |
| ROYALTIES | Three Months Ended March 31 | |||
| ($000s) | 2014 | 2013 | % Change | |
| Oil and NGLs | 2,000 | 2,218 | (10 | ) |
| Natural gas | 666 | 712 | (6 | ) |
| Total | 2,666 | 2,930 | (9 | ) |
| Average Royalty Rate (% of sales) | ||||
| Oil and NGLs | 9.7 | 13.5 | (28 | ) |
| Natural gas | 3.5 | 6.0 | (42 | ) |
| Combined | 6.7 | 10.4 | (36 | ) |
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, 2014, oil, NGLs, and natural gas royalties decreased 9% to $2.7 million from $2.9 million in the comparative period. The overall effective royalty rate for the three months ended March 31, 2014 decreased 36% to 6.7% from 10.4% in the comparative period. These decreases were the result of royalty incentives received on new wells brought on production during the year combined with an increase in the monthly capital cost and processing fee deductions in 2014 compared to 2013.
| PRODUCTION EXPENSES | Three Months Ended March 31 | |||
| 2014 | 2013 | % Change | ||
| Oil and NGLs ($/bbl) | 5.18 | 5.24 | (1 | ) |
| Natural gas ($/mcf) | 0.92 | 1.09 | (16 | ) |
| Combined ($/boe) | 5.42 | 6.13 | (12 | ) |
Per unit production expenses for the three months ended March 31, 2014 were $5.42/boe, down 12% from $6.13/boe for the comparative period ended March 31, 2013. The Company reduced production expenses in Northeast BC by expanding the Company’s infrastructure during the third quarter of 2013. In addition, the Company reduced production expenses at Edson, AB and Northeast BC by transitioning to new marketing arrangements in June 2013 and September 2013, respectively. The Company continues to focus on opportunities to maintain operational efficiencies to enhance operating netbacks.
| TRANSPORTATION EXPENSES | Three Months Ended March 31 | ||
| 2014 | 2013 | % Change | |
| Oil and NGLs ($/bbl) | 1.41 | 0.90 | 57 |
| Natural gas ($/mcf) | 0.14 | 0.11 | 27 |
| Combined ($/boe) | 1.02 | 0.72 | 42 |
Transportation expenses are mainly third-party pipeline tariffs incurred to deliver production to the purchasers at main hubs. For the quarter ended March 31, 2014 compared to the quarter ended March 31, 2013, transportation expenses increased 42% to $1.02/boe from $0.72/boe. The increase in oil and NGLs transportation expenses was a result of entering into a new marketing arrangement in June 2013 for a significant portion of the Company’s NGLs production. This resulted in a change in marketer and sales point which had higher associated transportation expenses. The increase in natural gas transportation expenses is due to an increase in the contracted transportation rates in Q1 2014 compared to Q1 2013.
| OPERATING NETBACK | Three Months Ended March 31 | |||||
| 2014 | 2013 | % Change | ||||
| Oil and NGLs ($/bbl) | ||||||
| Revenue | 89.57 | 67.88 | 32 | |||
| Royalties | (8.73 | ) | (9.16 | ) | (5 | ) |
| Production expenses | (5.18 | ) | (5.24 | ) | (1 | ) |
| Transportation expenses | (1.41 | ) | (0.90 | ) | 57 | |
| Operating netback | 74.25 | 52.58 | 41 | |||
| Natural gas ($/mcf) | ||||||
| Revenue | 5.59 | 3.56 | 57 | |||
| Royalties | (0.19 | ) | (0.21 | ) | (10 | ) |
| Production expenses | (0.92 | ) | (1.09 | ) | (16 | ) |
| Transportation expenses | (0.14 | ) | (0.11 | ) | 27 | |
| Operating netback | 4.34 | 2.15 | 102 | |||
| Combined ($/boe) | ||||||
| Revenue | 49.49 | 35.55 | 39 | |||
| Royalties | (3.31 | ) | (3.69 | ) | (10 | ) |
| Production expenses | (5.42 | ) | (6.13 | ) | (12 | ) |
| Transportation expenses | (1.02 | ) | (0.72 | ) | 42 | |
| Operating netback | 39.74 | 25.01 | 59 | |||
During the first quarter of 2014, Crocotta generated an operating netback of $39.74/boe, up 59% from $25.01/boe for the first quarter of 2013. Compared to the previous quarter, operating netbacks increased 45% from $27.49/boe in Q4 2013. These increases were due to significant increases in oil, NGLs, and natural gas commodity prices and reduced production expenses.
The following is a reconciliation of operating netback per boe to net earnings per boe for the periods noted:
| Three Months Ended March 31 | ||||||
| ($/boe) | 2014 | 2013 | % Change | |||
| Operating netback | 39.74 | 25.01 | 59 | |||
| Depletion and depreciation | (14.61 | ) | (13.46 | ) | 9 | |
| Asset impairment | – | (0.25 | ) | (100 | ) | |
| General and administrative expenses | (1.94 | ) | (1.93 | ) | 1 | |
| Share based compensation | (0.51 | ) | (0.65 | ) | (22 | ) |
| Finance expenses | (1.68 | ) | (1.12 | ) | 50 | |
| Gain on sale of assets | 0.50 | – | 100 | |||
| Deferred tax expense | (4.12 | ) | (1.32 | ) | 212 | |
| Realized loss on risk management contracts | (0.59 | ) | (0.58 | ) | 2 | |
| Unrealized loss on risk management contracts | (4.95 | ) | (2.44 | ) | 103 | |
| Net earnings | 11.84 | 3.26 | 263 | |||
| DEPLETION AND DEPRECIATION | Three Months Ended March 31 | ||
| 2014 | 2013 | % Change | |
| Depletion and depreciation ($000s) | 11,762 | 10,700 | 10 |
| Depletion and depreciation ($/boe) | 14.61 | 13.46 | 9 |
Depletion and depreciation for the three months ended March 31, 2014 was $14.61/boe, up 9% from $13.46/boe for the comparative period ended March 31, 2013. The increase was due to a significant increase in estimated future capital costs associated with proved plus probable reserves at Edson, AB in Q1 2014 compared to Q1 2013. Depletion and depreciation in Q1 2014 was consistent with depletion and depreciation of $14.64/boe for the previous quarter ended December 31, 2013.
| ASSET IMPAIRMENT | Three Months Ended March 31 | |||
| 2014 | 2013 | % Change | ||
| Asset impairment ($000s) | – | 199 | (100 | ) |
| Asset impairment ($/boe) | – | 0.25 | (100 | ) |
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. At March 31, 2014, there were no indicators of impairment of property, plant, and equipment. 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).
| GENERAL AND ADMINISTRATIVE | Three Months Ended March 31 | ||||
| ($000s) | 2014 | 2013 | % Change | ||
| G&A expenses (gross) | 2,071 | 2,009 | 3 | ||
| G&A capitalized | (216 | ) | (187 | ) | 16 |
| G&A recoveries | (297 | ) | (290 | ) | 2 |
| G&A expenses (net) | 1,558 | 1,532 | 2 | ||
| G&A expenses ($/boe) | 1.94 | 1.93 | 1 | ||
General and administrative expenses (“G&A”) of $1.94/boe for the first quarter of 2014 were consistent with general and administrative expenses of $1.93/boe for the first quarter of 2013.
| SHARE BASED COMPENSATION | Three Months Ended March 31 | |||
| 2014 | 2013 | % Change | ||
| Share based compensation ($000s) | 413 | 515 | (20 | ) |
| Share based compensation ($/boe) | 0.51 | 0.65 | (22 | ) |
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 $0.51/boe for the three months ended March 31, 2014 from $0.65/boe in the comparative period due to the graded vesting of awards and timing of option issuances over the past two years.
| FINANCE EXPENSES | Three Months Ended March 31 | ||
| ($000s) | 2014 | 2013 | % Change |
| Interest expense | 1,195 | 771 | 55 |
| Accretion of decommissioning obligations | 161 | 123 | 31 |
| Finance expenses | 1,356 | 894 | 52 |
| Finance expenses ($/boe) | 1.68 | 1.12 | 50 |
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 2014 compared to the first quarter of 2013. At March 31, 2014, $132.4 million (2013 – $88.5 million) had been drawn on the Company’s credit facility.
DEFERRED INCOME TAXES
Deferred income tax expense on the earnings before taxes was $3.3 million in the first quarter of 2014 (2013 – $1.0 million). This was consistent with expectations by applying the statutory tax rate to the earnings before taxes.
Estimated tax pools at March 31, 2014 total approximately $363.3 million (December 31, 2013 – $341.1 million).
FUNDS FROM OPERATIONS
Funds from operations for the three months ended March 31, 2014 was $28.8 million ($0.29 per diluted share) compared to $17.1 million ($0.19 per diluted share) for the three months ended March 31, 2013. The increase was mainly due to a significant increase in oil, NGLs, 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:
| Three Months Ended March 31 | ||||||
| ($000s) | 2014 | 2013 | % Change | |||
| Cash flow from operating activities (GAAP) | 24,528 | 17,395 | 41 | |||
| Add back (deduct): | ||||||
| Decommissioning expenditures | 38 | 84 | (55 | ) | ||
| Change in non-cash working capital | 4,192 | (355 | ) | 1,281 | ||
| Funds from operations (non-GAAP) | 28,758 | 17,124 | 68 | |||
NET EARNINGS
The Company had net earnings of $9.5 million ($0.10 per diluted share) for the three months ended March 31, 2014 compared to net earnings of $2.6 million ($0.03 per diluted share) for the three months ended March 31, 2013. The increase was mainly due to a significant increase in oil, NGLs, and natural gas commodity prices which resulted in a significant increase in revenue.
| CAPITAL EXPENDITURES | Three Months Ended March 31 | ||||
| ($000s) | 2014 | 2013 | % Change | ||
| Land | 14,879 | 1,220 | 1,120 | ||
| Drilling, completions, and workovers | 31,823 | 20,085 | 58 | ||
| Equipment | 6,019 | 9,746 | (38 | ) | |
| Geological and geophysical | 381 | 467 | (18 | ) | |
| Exploration and development expenditures | 53,102 | 31,518 | 68 | ||
| Property dispositions | (400 | ) | – | 100 | |
| Net capital expenditures | 52,702 | 31,518 | 67 | ||
For the three months ended March 31, 2014, the Company had net capital expenditures of $52.7 million compared to capital expenditures of $31.5 million for the three months ended March 31, 2013. The increase in exploration and development expenditures in Q1 2014 was due to an increase in capital activity in the Company’s core areas of Edson, AB and Northeast BC. During the first quarter of 2014, Crocotta drilled a total of 10 (9.0 net) wells, which resulted in 7 (6.0 net) oil wells and 3 (3.0 net) liquids-rich natural gas wells. In addition, the Company sold land for cash proceeds of $0.4 million from a non-core property.
LIQUIDITY AND CAPITAL RESOURCES
Management uses net debt as a measure to assess the Company’s financial position and is reconciled as follows:
| ($000s) | March 31, 2014 | December 31, 2013 | % Change | |||
| Current liabilities (excluding risk management contracts) | 29,744 | 19,480 | 53 | |||
| Credit facility | 132,429 | 116,324 | 14 | |||
| Less: | ||||||
| Current assets | (21,477 | ) | (17,964 | ) | 20 | |
| Net debt | 140,696 | 117,840 | 19 | |||
The Company had net debt of $140.7 million at March 31, 2014 compared to net debt of $117.8 million at December 31, 2013. The increase of $22.9 million was due to $53.1 million used for the purchase and development of oil and natural gas properties and equipment, offset by funds from operations of $28.8 million, shares issuances of $1.1 million relating to the exercise of stock options, and proceeds from the sale of assets of $0.4 million.
During 2013, the Company entered into a $150 million syndicated credit facility with three Canadian chartered banks. The credit facility consists of a $140 million revolving line of credit and a $10 million operating line of credit and replaced the Company’s previous $140 million revolving operating demand loan credit facility. Subsequent to March 31, 2014, the Company signed an agreement to increase the credit facility to $165 million. The syndicated facility revolves for a 364 day period and will be subject to its next 364 day extension by April 30, 2015. If not extended, the syndicated facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date.
Advances under the syndicated facility are available by way of prime rate loans, with interest rates between 1.00% and 2.50% over the Canadian prime lending rate, and bankers’ acceptances and LIBOR loans, which are subject to stamping fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash flow ratio of the Company. Standby fees are charged on the undrawn syndicated facility at rates ranging from 0.50% to 0.875%. The credit facility is secured by a $300 million fixed and floating charge debenture on the assets of the Company. The credit facility includes a covenant requiring the Company to maintain a working capital ratio of not less than one-to-one. The working capital ratio, as defined by its creditor, is calculated as current assets plus any undrawn amounts available on its credit facility less current liabilities (excluding risk management contracts and any current portion drawn on the credit facility). The Company was fully compliant with this covenant at March 31, 2014.
At March 31, 2014, $132.4 million (December 31, 2013 – $116.3 million) had been drawn on the credit facility. In addition, at March 31, 2014, the Company had outstanding letters of guarantee of approximately $2.6 million (December 31, 2013 – $2.5 million) which reduce the amount that can be borrowed under the credit facility. The next scheduled borrowing base review of the syndicated facility is scheduled on or before October 31, 2014.
The ongoing global economic conditions have continued to impact the liquidity in financial and capital markets, restrict access to financing, and cause significant volatility in commodity prices. Despite the economic downturn and financial market volatility, the Company continued to have access to both debt and equity markets recently. The Company raised gross proceeds of approximately $22.0 million from the issuance of common shares during the second quarter of 2013 and subsequent to March 31, 2014, the Company obtained an increase to its credit facility to $165 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. 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, 2014:
| Less than | One to | After | ||
| ($000s) | Total | One Year | Three Years | Three Years |
| Accounts payable and accrued liabilities | 29,744 | 29,744 | – | – |
| Credit facility | 132,429 | – | 132,429 | – |
| Risk management contracts | 4,354 | 4,354 | – | – |
| Decommissioning obligations | 24,025 | 85 | 75 | 23,865 |
| Office leases | 277 | 277 | – | – |
| Field equipment leases | 367 | 367 | – | – |
| Firm transportation agreements | 20 | 8 | 12 | – |
| Total contractual obligations | 191,216 | 34,835 | 132,516 | 23,865 |
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:
| (000s) | March 31, 2014 | May 8, 2014 |
| Voting common shares | 97,699 | 97,738 |
| Stock options | 7,962 | 7,923 |
| Total | 105,661 | 105,661 |
SUMMARY OF QUARTERLY RESULTS
| Q1 2014 |
Q4 2013 |
Q3 2013 |
Q2 2013 |
Q1 2013 |
Q4 2012 |
Q3 2012 |
Q2 2012 |
||||
| Average Daily Production | |||||||||||
| Oil and NGLs (bbls/d) | 2,545 | 2,605 | 2,497 | 2,158 | 2,691 | 2,476 | 2,103 | 2,053 | |||
| Natural gas (mcf/d) | 38,385 | 39,767 | 36,593 | 36,412 | 36,869 | 29,160 | 29,053 | 27,309 | |||
| Combined (boe/d) | 8,943 | 9,233 | 8,596 | 8,227 | 8,836 | 7,336 | 6,945 | 6,604 | |||
| ($000s, except per share amounts) | |||||||||||
| Oil and natural gas sales | 39,836 | 31,090 | 26,950 | 25,152 | 28,267 | 24,938 | 17,922 | 17,518 | |||
| Funds from operations | 28,758 | 19,691 | 16,102 | 14,280 | 17,124 | 14,478 | 10,888 | 12,275 | |||
| Per share – basic | 0.30 | 0.20 | 0.17 | 0.16 | 0.19 | 0.16 | 0.12 | 0.14 | |||
| Per share – diluted | 0.29 | 0.20 | 0.16 | 0.15 | 0.19 | 0.16 | 0.12 | 0.14 | |||
| Net earnings (loss) | 9,518 | 4,387 | 975 | 3,604 | 2,604 | (2,082 | ) | (3,944 | ) | 1,065 | |
| Per share – basic | 0.10 | 0.05 | 0.01 | 0.04 | 0.03 | (0.02 | ) | (0.04 | ) | 0.01 | |
| Per share – diluted | 0.10 | 0.04 | 0.01 | 0.04 | 0.03 | (0.02 | ) | (0.04 | ) | 0.01 | |
The Company has experienced significant increases in production over the previous two years stemming from successful drilling activities at Edson, AB and Northeast BC. In addition, oil, NGLs, and natural gas commodity prices have gradually increased over the previous two years, with a significant increase in Q1 2014. These production and commodity price increases have led to substantial increases in revenue, funds from operations, and net earnings over the previous two years. The Company had a net loss in two of the previous eight quarters mainly as a result of asset impairments recognized in each quarter on non-core properties.
CRITICAL ACCOUNTING ESTIMATES
Management is required to make estimates, judgments, and assumptions in the application of IFRS that affect the reported amounts of assets and liabilities at the date of the financial statements and revenues and expenses for the period then ended. Certain of these estimates may change from period to period resulting in a material impact on the Company’s results from operations, financial position, and change in financial position. The Company’s significant critical accounting estimates have not changed from the year ended December 31, 2013.
CHANGES IN ACCOUNTING POLICIES
On January 1, 2014, the Company retrospectively adopted amendments to IAS 36, Impairment of Assets, IFRIC 21, Levies, and amendments to IAS 32, Financial Instruments: Presentation, which had no impact on the amounts recorded in the condensed interim 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
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:
The fair value of derivative contracts used for risk management as shown in the statement of financial position as at March 31, 2014 is measured using level 2 inputs. During the three months ended March 31, 2014, there were no transfers between level 1, level 2, and level 3 classified assets and liabilities.
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. In addition, the Company may enter into commodity price contracts to manage future cash flows. For the period ended March 31, 2014, the realized loss on the Company’s oil contracts was $0.5 million, the unrealized loss on the oil contracts was $1.1 million, and the unrealized loss on the gas contracts was $2.9 million.
At March 31, 2014, the Company had the following commodity price contracts outstanding:
| Commodity | Period | Type of Contract | Quantity Contracted | Contract Price |
| Oil | January 1, 2014 – December 31, 2014 | Financial – Swap | 500 bbls/d | WTI CDN $100.80/bbl |
| Oil | April 1, 2014 – June 30, 2014 | Financial – Swap | 500 bbls/d | WTI CDN $108.00/bbl |
| Oil | July 1, 2014 – September 30, 2014 | Financial – Swap | 500 bbls/d | WTI CDN $110.00/bbl |
| Natural Gas | April 1, 2014 – October 31, 2014 | Financial – Swap | 5,000 GJ/d | AECO CDN $3.505/GJ |
| Natural Gas | April 1, 2014 – October 31, 2014 | Financial – Swap | 5,000 GJ/d | AECO CDN $3.650/GJ |
| Natural Gas | April 1, 2014 – October 31, 2014 | Financial – Swap | 10,000 GJ/d | AECO CDN $3.745/GJ |
Credit risk
Credit risk represents the financial loss that the Company would suffer if the Company’s counterparties to a financial asset 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 of accounts receivable on the statement of financial position. At March 31, 2014, $18.8 million or 96.1% of the Company’s outstanding accounts receivable were current while $0.8 million or 3.9% were outstanding over 90 days but not impaired. During the period ended March 31, 2014, 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, 2013. The Company’s CEO and CFO have concluded that, based on their evaluation, the Company’s disclosure controls and procedures are not effective due to the existence of the weakness in internal controls over financial reporting noted below.
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, 2013. 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 issued in 1992. Based on their evaluation, the Company’s CEO and CFO have identified weaknesses over segregation of duties. Specifically, due to the limited number of finance and accounting personnel at the Company, it is not feasible to achieve complete segregation of duties with regards to certain complex and non-routine accounting transactions that may arise. This weakness is considered to be a common deficiency for many smaller listed companies in Canada. Notwithstanding the weaknesses identified with regards to segregation of duties, the Company concluded that all other of its internal controls over financial reporting were effective as of December 31, 2013. No material changes in the Company’s internal controls over financial reporting were identified during the most recent reporting period that have materially affected, or are likely to material affect, the Company’s internal controls over financial reporting.
Because of their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, errors, or fraud. Control systems, no matter how well conceived or operated, can provide only reasonable, not absolute, assurance that the objectives of the control systems are met. As a result of the weaknesses identified in the Company’s internal controls over financial reporting, there is a greater likelihood that a material misstatement would not be prevented or detected. To mitigate the risk of such material misstatement in financial reporting, the CEO and CFO oversee all material and complex transactions of the Company and the financial statements are reviewed and approved by the Board of Directors each quarter. In addition, the Company will seek the advice of external parties, such as the Company’s external auditors, in regards to the appropriate accounting treatment for any complex and non-routine transactions that may arise.
FORWARD-LOOKING INFORMATION
This document contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words “expect”, “anticipate”, “continue”, “estimate”, “may”, “will”, “should”, “believe”, “intends”, “forecast”, “plans”, “guidance” and similar expressions are intended to identify forward-looking statements or information.
More particularly and without limitation, this MD&A contains forward looking statements and information relating to the Company’s risk management program, oil, NGLs, and natural gas production, capital programs, oil, NGLs, and natural gas commodity prices, and debt levels. The forward-looking statements and information are based on certain key expectations and assumptions made by the Company, including expectations and assumptions relating to prevailing commodity prices and exchange rates, applicable royalty rates and tax laws, future well production rates, the performance of existing wells, the success of drilling new wells, the availability of capital to undertake planned activities, and the availability and cost of labour and services.
Although the Company believes that the expectations reflected in such forward-looking statements and information are reasonable, it can give no assurance that such expectations will prove to be correct. Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results may differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to, the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production, delays or changes in plans with respect to exploration or development projects or capital expenditures, the uncertainty of estimates and projections relating to production rates, costs, and expenses, commodity price and exchange rate fluctuations, marketing and transportation, environmental risks, competition, the ability to access sufficient capital from internal and external sources and changes in tax, royalty, and environmental legislation. The forward-looking statements and information contained in this document are made as of the date hereof for the purpose of providing the readers with the Company’s expectations for the coming year. The forward-looking statements and information may not be appropriate for other purposes. The Company undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.
ADDITIONAL INFORMATION
Additional information related to the Company, including the Company’s Annual Information Form (AIF), may be found on the SEDAR website at www.sedar.com.
| Crocotta Energy Inc. | |||||||
| Condensed Consolidated Statements of Financial Position | |||||||
| (unaudited) | |||||||
| March 31 | December 31 | ||||||
| ($000s) | Note | 2014 | 2013 | ||||
| Assets | |||||||
| Current assets | |||||||
| Accounts receivable | 19,559 | 16,166 | |||||
| Prepaid expenses and deposits | 1,918 | 1,798 | |||||
| 21,477 | 17,964 | ||||||
| Property, plant, and equipment | (5 | ) | 342,536 | 313,142 | |||
| Exploration and evaluation assets | (4 | ) | 53,110 | 39,629 | |||
| Deferred income taxes | – | 2,566 | |||||
| 395,646 | 355,337 | ||||||
| 417,123 | 373,301 | ||||||
| Liabilities | |||||||
| Current liabilities | |||||||
| Accounts payable and accrued liabilities | 29,744 | 19,480 | |||||
| Risk management contracts | 4,354 | 368 | |||||
| 34,098 | 19,848 | ||||||
| Credit facility | (6 | ) | 132,429 | 116,324 | |||
| Decommissioning obligations | (7 | ) | 24,025 | 22,438 | |||
| Deferred income taxes | 752 | – | |||||
| 191,304 | 158,610 | ||||||
| Shareholders’ Equity | |||||||
| Shareholders’ capital | (8 | ) | 252,471 | 250,563 | |||
| Contributed surplus | 12,672 | 12,970 | |||||
| Deficit | (39,324 | ) | (48,842 | ) | |||
| 225,819 | 214,691 | ||||||
| Subsequent event | (6 | ) | |||||
| 417,123 | 373,301 | ||||||
| The accompanying notes are an integral part of these condensed interim consolidated financial statements. |
| Crocotta Energy Inc. | |||||||
| Condensed Consolidated Statements of Operations and Comprehensive Earnings | |||||||
| (unaudited) | |||||||
| Three Months Ended March 31 | |||||||
| ($000s, except per share amounts) | Note | 2014 | 2013 | ||||
| Revenue | |||||||
| Oil and natual gas sales | 39,836 | 28,267 | |||||
| Royalties | (2,666 | ) | (2,930 | ) | |||
| 37,170 | 25,337 | ||||||
| Realized loss on risk management contracts | (476 | ) | (458 | ) | |||
| Unrealized loss on risk management contracts | (3,986 | ) | (1,937 | ) | |||
| 32,708 | 22,942 | ||||||
| Expenses | |||||||
| Production | 4,364 | 4,879 | |||||
| Transportation | 819 | 573 | |||||
| Depletion and depreciation | (5 | ) | 11,762 | 10,700 | |||
| Asset impairment | – | 199 | |||||
| General and administrative | 1,558 | 1,532 | |||||
| Share based compensation | (9 | ) | 413 | 515 | |||
| 18,916 | 18,398 | ||||||
| Operating earnings | 13,792 | 4,544 | |||||
| Other Income (Expenses) | |||||||
| Finance expense | (11 | ) | (1,356 | ) | (894 | ) | |
| Gain on sale of assets | (4 | ) | 400 | – | |||
| (956 | ) | (894 | ) | ||||
| Earnings before taxes | 12,836 | 3,650 | |||||
| Taxes | |||||||
| Deferred income tax expense | 3,318 | 1,046 | |||||
| Net earnings and comprehensive earnings | 9,518 | 2,604 | |||||
| Net earnings per share | |||||||
| Basic and diluted | 0.10 | 0.03 | |||||
| The accompanying notes are an integral part of these condensed interim consolidated financial statements. |
| Crocotta Energy Inc. | ||||||
| Condensed Consolidated Statements of Shareholders’ Equity | ||||||
| (unaudited) | ||||||
| Three Months Ended March 31 | ||||||
| ($000s) | Note | 2014 | 2013 | |||
| Shareholders’ Capital | ||||||
| Balance, beginning of period | 250,563 | 228,277 | ||||
| Issued on exercise of stock options | (8 | ) | 1,126 | – | ||
| Share based compensation – exercised | (8 | ) | 782 | – | ||
| Balance, end of period | 252,471 | 228,277 | ||||
| Contributed Surplus | ||||||
| Balance, beginning of period | 12,970 | 12,026 | ||||
| Share based compensation – expensed | (9 | ) | 413 | 515 | ||
| Share based compensation – capitalized | (9 | ) | 71 | 76 | ||
| Share based compensation – exercised | (8 | ) | (782 | ) | – | |
| Balance, end of period | 12,672 | 12,617 | ||||
| Deficit | ||||||
| Balance, beginning of period | (48,842 | ) | (60,412 | ) | ||
| Net earnings | 9,518 | 2,604 | ||||
| Balance, end of period | (39,324 | ) | (57,808 | ) | ||
| Total Shareholders’ Equity | 225,819 | 183,086 | ||||
| The accompanying notes are an integral part of these condensed interim consolidated financial statements. |
| Crocotta Energy Inc. | |||||||
| Condensed Consolidated Statements of Cash Flows | |||||||
| (unaudited) | |||||||
| Three Months Ended March 31 | |||||||
| ($000s) | Note | 2014 | 2013 | ||||
| Operating Activities | |||||||
| Net earnings | 9,518 | 2,604 | |||||
| Depletion and depreciation | (5 | ) | 11,762 | 10,700 | |||
| Asset impairment | – | 199 | |||||
| Share based compensation | (9 | ) | 413 | 515 | |||
| Finance expense | (11 | ) | 1,356 | 894 | |||
| Interest paid | (11 | ) | (1,195 | ) | (771 | ) | |
| Gain on sale of assets | (4 | ) | (400 | ) | – | ||
| Deferred income tax expense | 3,318 | 1,046 | |||||
| Unrealized loss on risk management contracts | 3,986 | 1,937 | |||||
| Decommissioning expenditures | (7 | ) | (38 | ) | (84 | ) | |
| Change in non-cash working capital | (13 | ) | (4,192 | ) | 355 | ||
| 24,528 | 17,395 | ||||||
| Financing Activities | |||||||
| Credit facility | (6 | ) | 16,105 | – | |||
| Revolving credit facility | (6 | ) | – | 19,981 | |||
| Issuance of shares | (8 | ) | 1,126 | – | |||
| 17,231 | 19,981 | ||||||
| Investing Activities | |||||||
| Capital expenditures – property, plant, and equipment | (5 | ) | (38,255 | ) | (28,177 | ) | |
| Capital expenditures – exploration and evaluation assets | (4 | ) | (14,847 | ) | (3,341 | ) | |
| Proceeds on sale of exploration and evaluation assets | (4 | ) | 400 | – | |||
| Change in non-cash working capital | (13 | ) | 10,943 | (5,858 | ) | ||
| (41,759 | ) | (37,376 | ) | ||||
| Change in cash and cash equivalents | – | – | |||||
| Cash and cash equivalents, beginning of period | – | – | |||||
| Cash and cash equivalents, end of period | – | – | |||||
| The accompanying notes are an integral part of these condensed interim consolidated financial statements. |
Crocotta Energy Inc.
Notes to the Condensed Interim Consolidated Financial Statements
Three Months Ended March 31, 2014
(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 – 5th Avenue SW, Calgary, Alberta, Canada, T2P 0M9.
2. BASIS OF PRESENTATION
(a) Statement of compliance
These condensed interim consolidated financial statements have been prepared in accordance with International Accounting Standard (“IAS”) 34, Interim Financial Reporting and accordingly do not include all of the information required in the preparation of annual consolidated financial statements. The condensed interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and related notes for the year ended December 31, 2013.
The condensed interim consolidated financial statements were authorized for issuance by the Board of Directors on May 8, 2014.
(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 functional currency of the Company and its subsidiary.
(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, 2013.
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, 2013 with the exception of the new policies adopted below. The accounting policies have been applied consistently by the Company to all periods presented in these condensed interim consolidated financial statements.
On January 1, 2014, the Company retrospectively adopted amendments to IAS 36, Impairment of Assets, IFRIC 21, Levies, and amendments to IAS 32, Financial Instruments: Presentation, which had no impact on the amounts recorded in the condensed interim consolidated financial statements.
4. EXPLORATION AND EVALUATION ASSETS
| Total | |||
| Balance, December 31, 2012 | 28,302 | ||
| Additions | 60,576 | ||
| Transfer to property, plant, and equipment | (48,610 | ) | |
| Impairment | (639 | ) | |
| Balance, December 31, 2013 | 39,629 | ||
| Additions | 14,847 | ||
| Transfer to property, plant, and equipment | (1,366 | ) | |
| Balance, March 31, 2014 | 53,110 | ||
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 $14.8 million of additions during the three months ended March 31, 2014 were additions of $0.2 million related to the Edson AB CGU, $13.7 million related to the Northeast BC CGU, and $0.9 million related to the Miscellaneous AB CGU.
During the first quarter of 2014, the Company sold land for proceeds of $0.4 million (CGU – Miscellaneous AB) and recorded a gain on sale of $0.4 million as the net book value was $nil.
5. PROPERTY, PLANT, AND EQUIPMENT
| Cost | Total | |
| Balance, December 31, 2012 | 331,642 | |
| Additions | 66,694 | |
| Transfer from exploration and evaluation assets | 48,610 | |
| Change in decommissioning obligation estimates | 687 | |
| Capitalized share based compensation | 207 | |
| Balance, December 31, 2013 | 447,840 | |
| Additions | 38,255 | |
| Transfer from exploration and evaluation assets | 1,366 | |
| Change in decommissioning obligation estimates | 1,464 | |
| Capitalized share based compensation | 71 | |
| Balance, March 31, 2014 | 488,996 | |
| Accumulated Depletion, Depreciation, and Impairment | Total | |
| Balance, December 31, 2012 | 89,939 | |
| Depletion and depreciation | 44,596 | |
| Impairment | 163 | |
| Balance, December 31, 2013 | 134,698 | |
| Depletion and depreciation | 11,762 | |
| Balance, March 31, 2014 | 146,460 | |
| Net Book Value | Total | |
| December 31, 2012 | 241,703 | |
| December 31, 2013 | 313,142 | |
| March 31, 2014 | 342,536 | |
During the three months ended March 31, 2014, approximately $0.2 million (2013 – $0.2 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, 2014 included an estimated $305.1 million (2013 – $215.3 million) for future development costs associated with proved plus probable undeveloped reserves and excluded approximately $12.8 million (2013 – $13.4 million) for the estimated salvage value of production equipment and facilities.
6. CREDIT FACILITY
During 2013, the Company entered into a $150 million syndicated credit facility with three Canadian chartered banks. The credit facility consists of a $140 million revolving line of credit and a $10 million operating line of credit and replaced the Company’s previous $140 million revolving operating demand loan credit facility. Subsequent to March 31, 2014, the Company signed an agreement to increase the credit facility to $165 million. The syndicated facility revolves for a 364 day period and will be subject to its next 364 day extension by April 30, 2015. If not extended, the syndicated facility will cease to revolve, the margins thereunder will increase by 0.50%, and all outstanding advances will become repayable in one year from the extension date.
Advances under the syndicated facility are available by way of prime rate loans, with interest rates between 1.00% and 2.50% over the Canadian prime lending rate, and bankers’ acceptances and LIBOR loans, which are subject to stamping fees and margins ranging from 2.00% to 3.50% depending upon the debt to cash flow ratio of the Company. Standby fees are charged on the undrawn syndicated facility at rates ranging from 0.50% to 0.875%. The credit facility is secured by a $300 million fixed and floating charge debenture on the assets of the Company. The credit facility includes a covenant requiring the Company to maintain a working capital ratio of not less than one-to-one. The working capital ratio, as defined by its creditor, is calculated as current assets plus any undrawn amounts available on its credit facility less current liabilities (excluding risk management contracts and any current portion drawn on the credit facility). The Company was fully compliant with this covenant at March 31, 2014.
At March 31, 2014, $132.4 million (December 31, 2013 – $116.3 million) had been drawn on the credit facility. In addition, at March 31, 2014, the Company had outstanding letters of guarantee of approximately $2.6 million (December 31, 2013 – $2.5 million) which reduce the amount that can be borrowed under the credit facility. The next scheduled borrowing base review of the syndicated facility is scheduled on or before October 31, 2014.
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 $34.3 million which is estimated to be incurred over the next 27 years. At March 31, 2014, a risk-free rate of 2.8% (December 31, 2013 – 3.1%) was used to calculate the net present value of the decommissioning obligations.
| Three Months Ended | Year Ended | ||||
| March 31, 2014 | December 31, 2013 | ||||
| Balance, beginning of period | 22,438 | 21,852 | |||
| Provisions incurred | 705 | 2,253 | |||
| Provisions disposed | – | (80 | ) | ||
| Provisions settled | (38 | ) | (691 | ) | |
| Revisions | 759 | (1,486 | ) | ||
| Accretion | 161 | 590 | |||
| Balance, end of period | 24,025 | 22,438 | |||
8. SHAREHOLDERS’ CAPITAL
The Company is authorized to issue an unlimited number of voting common shares, an unlimited number of non-voting common shares, Class A preferred shares, issuable in series, and Class B preferred shares, issuable in series. No non-voting common shares or preferred shares have been issued.
| Voting Common Shares | Number | Amount | ||
| Balance, December 31, 2012 | 89,261 | 228,277 | ||
| Exercise of stock options | 1,409 | 3,399 | ||
| Share issuances | 6,042 | 21,983 | ||
| Share issue costs, net of future tax effect of $0.2 million | (749 | ) | ||
| Flow-through share premium | (2,347 | ) | ||
| Balance, December 31, 2013 | 96,712 | 250,563 | ||
| Exercise of stock options | 987 | 1,908 | ||
| Balance, March 31, 2014 | 97,699 | 252,471 | ||
9. SHARE BASED COMPENSATION PLANS Stock options
The Company has authorized and reserved for issuance 9.8 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, 2014, 8.0 million options are outstanding at exercise prices ranging from $1.10 to $3.46 per share.
The number and weighted average exercise price of stock options are as follows:
| Number of | Weighted Average | |||
| Options | Exercise Price ($) | |||
| Balance, December 31, 2012 | 8,601 | 2.09 | ||
| Granted | 1,717 | 2.77 | ||
| Exercised | (1,409 | ) | 1.46 | |
| Forfeited | (60 | ) | 2.83 | |
| Balance, December 31, 2013 | 8,849 | 2.32 | ||
| Granted | 100 | 2.85 | ||
| Exercised | (987 | ) | 1.14 | |
| Balance, March 31, 2014 | 7,962 | 2.47 | ||
For the stock options exercised during the first quarter of 2014, the weighted average share price of the Company’s common shares at the date of exercise was $3.39 per share (2013 – $2.95 per share).
The following table summarizes the stock options outstanding and exercisable at March 31, 2014:
| Options Outstanding | Options Exercisable | ||||
| Weighted Average | Weighted Average | Weighted Average | |||
| Exercise Price | Number | Remaining Life | Exercise Price | Number | Exercise Price |
| $1.10 to $2.00 | 1,554 | 1.1 | 1.32 | 1,554 | 1.32 |
| $2.01 to $3.00 | 5,667 | 2.7 | 2.66 | 3,516 | 2.57 |
| $3.01 to $3.46 | 741 | 2.8 | 3.44 | 479 | 3.46 |
| 7,962 | 2.4 | 2.47 | 5,549 | 2.29 | |
Share based compensation
The Company accounts for its share based compensation plans using the fair value method. Under this method, compensation cost is charged to earnings over the vesting period for stock options granted to officers, directors, employees, and consultants with a corresponding increase to contributed surplus.
The fair value of the stock options granted were estimated on the date of grant using the Black-Scholes-Merton option pricing model with the following weighted average assumptions:
| Three Months Ended March 31 | ||
| 2014 | 2013 | |
| Risk-free interest rate (%) | 1.5 | 1.2 |
| Expected life (years) | 4.0 | 4.0 |
| Expected volatility (%) | 48.4 | 62.7 |
| Expected dividend yield (%) | – | – |
| Forfeiture rate (%) | 5.7 | 6.2 |
| Weighted average fair value of options granted ($ per option) | 1.11 | 1.34 |
10. PER SHARE AMOUNTS
The following table summarizes the weighted average number of shares used in the basic and diluted net earnings per share calculations:
| Three Months Ended March 31 | ||
| 2014 | 2013 | |
| Weighted average number of shares – basic | 96,728 | 89,261 |
| Dilutive effect of share based compensation plans | 1,520 | 2,409 |
| Weighted average number of shares – diluted | 98,248 | 91,670 |
For the three months ended March 31, 2014, 2.5 million stock options (2013 – 2.3 million) were anti-dilutive and were not included in the diluted earnings per share calculation.
11. FINANCE EXPENSES
Finance expenses include the following:
| Three Months Ended March 31 | ||
| 2014 | 2013 | |
| Interest expense (note 6) | 1,195 | 771 |
| Accretion of decommissioning obligations (note 7) | 161 | 123 |
| Finance expenses | 1,356 | 894 |
12. FAIR VALUE OF FINANCIAL INSTRUMENTS Derivatives
The fair value of risk management contracts is determined by discounting the difference between the contracted price and published forward curves as at the statement of financial position date using the remaining contracted volumes and a risk-free interest rate (based on published government rates).
The Company classified the fair value of its financial instruments at fair value according to the following hierarchy based on the amount of observable inputs used to value the instrument:
The fair value of derivative contracts used for risk management as shown in the statement of financial position as at March 31, 2014 is measured using level 2 inputs. During the three months ended March 31, 2014, there were no transfers between level 1, level 2, and level 3 classified assets and liabilities.
Financial assets and liabilities are only offset if the Company has the legal right to offset and intends to settle on a net basis or settle the asset and liability simultaneously. The following table summarizes the gross asset and liability positions of the Company’s risk management contracts that are offset on the statement of financial position:
| March 31, 2014 | December 31, 2013 | |||
| Gross liability | (4,428 | ) | (447 | ) |
| Gross asset | 74 | 79 | ||
| Net liability | (4,354 | ) | (368 | ) |
13. SUPPLEMENTAL CASH FLOW INFORMATION
| Three Months Ended March 31 | |||||
| 2014 | 2013 | ||||
| Accounts receivable | (3,393 | ) | (1,402 | ) | |
| Prepaid expenses and deposits | (120 | ) | 173 | ||
| Accounts payable and accrued liabilities | 10,264 | (4,274 | ) | ||
| Change in non-cash working capital | 6,751 | (5,503 | ) | ||
| Relating to: | |||||
| Investing | (4,192 | ) | (5,858 | ) | |
| Operating | 10,943 | 355 | |||
| Change in non-cash working capital | 6,751 | (5,503 | ) | ||
| CORPORATE INFORMATION | ||
| OFFICERS AND DIRECTORS | ||
| Robert J. Zakresky, CA | BANK | |
| President, CEO & Director | National Bank of Canada | |
| 1800, 311 – 6th Avenue SW | ||
| Nolan Chicoine, MPAcc, CA | Calgary, Alberta T2P 3H2 | |
| VP Finance & CFO | ||
| Terry L. Trudeau, P.Eng. | ||
| VP Operations & COO | TRANSFER AGENT | |
| Valiant Trust Company | ||
| Weldon Dueck, BSc., P.Eng. | 310, 606 – 4th Street SW | |
| VP Business Development | Calgary, Alberta T2P 1T1 | |
| R.D. (Rick) Sereda, M.Sc., P.Geol. | ||
| VP Exploration | ||
| LEGAL COUNSEL | ||
| Helmut R. Eckert, P.Land | Gowling Lafleur Henderson LLP | |
| VP Land | 1600, 421 – 7th Avenue SW | |
| Calgary, Alberta T2P 4K9 | ||
| Larry G. Moeller, CA, CBV | ||
| Chairman of the Board | ||
| Daryl H. Gilbert, P.Eng. | AUDITORS | |
| Director | KPMG LLP | |
| 2700, 205 – 5th Avenue SW | ||
| Don Cowie | Calgary, Alberta T2P 4B9 | |
| Director | ||
| Brian Krausert | ||
| Director | INDEPENDENT ENGINEERS | |
| GLJ Petroleum Consultants Ltd. | ||
| Gary W. Burns | 4100, 400 – 3rd Avenue SW | |
| Director | Calgary, Alberta T2P 4H2 | |
| Don D. Copeland, P.Eng. | ||
| Director | ||
| Brian Boulanger | ||
| Director | ||
| Patricia Phillips | ||
| Director | ||
Crocotta Energy Inc.
Robert J. Zakresky
President & CEO
(403) 538-3736
Crocotta Energy Inc.
Nolan Chicoine
VP Finance & CFO
(403) 538-3738
Crocotta Energy Inc.
Suite 700, 639 – 5th Avenue SW
Calgary, Alberta T2P 0M9
(403) 538-3737
(403) 538-3735 (FAX)
www.crocotta.ca
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