News PERIOD ENDED JULY 31, 2012
MANAGEMENT DISCUSSION AND ANALYSIS
1
This Management’s Discussion and Analysis (“MD&A”) of the consolidated financial position and results of operations of the Company, which includes its subsidiaries and partnership arrangements, was prepared as of September 28, 2012, and is for the three and six months ended July 31, 2012 and 2011. For a full understanding of the consolidated financial position and results of operations of the Company, the MD&A should be read in conjunction with the documents filed on SEDAR, including historical financial statements and press releases. These documents are available at www.sedar.com. The selected financial information contained herein has been prepared in accordance with International Financial Reporting Standards, and are expressed in Canadian dollars, unless otherwise noted.
The Company’s Board of Directors and Audit Committee have reviewed and approved the interim consolidated financial statements and MD&A.
Readers are cautioned of the advisories of forward-looking statements, estimates, non-IFRS measures and numerical references which can be found at the end of this MD&A. This MD&A is dated and was prepared using currently available information as of September 28, 2012.
Description of the Company
Thunderbird Energy Corp. (the “Company”) is focused on the exploration, exploitation, acquisition and production of natural
gas and crude oil, primarily in the United States. The Company owns and operates a producing natural gas field in Carbon
County, Utah, known as the Gordon Creek field, and holds a 50% interest in a producing light oil project located in Rush County, Kansas. The Company also holds a 100% interest in a non-producing oil project in Weston County, Wyoming.
HIGHLIGHTS AND OUTLOOK
The Company is party to a US$25 million commodity stream production payment agreement with Sandstorm Metals & Energy Ltd. ("Sandstorm") whereby Sandstorm has the right to purchase 35% of the Company's Gordon Creek natural gas production at a price of US$1.00 per Mcf plus 20% of the amount by which the Gordon Creek field gate price exceeds US$4.00. During the first quarter of the current fiscal year, the Company and Sandstorm amended the commodity stream production payment agreement whereby all minimum cash flow guarantees and drilling commitments at Gordon Creek were deferred by one year to the dates set out below. As consideration for this deferral, in March 2013, Thunderbird will issue to Sandstorm $2.55 million of Thunderbird shares determined at a deemed price equivalent to the 50 day volume weighted average trading price prior to issuance.
Under the terms of the agreement, Sandstorm advanced the Company $15 million in 2011 and was scheduled to advance the remaining balance of $10 million in 2013. On July 11, 2012 the Company negotiated an amendment to its agreement with Sandstorm whereby Sandstorm advanced $3 million of the $10 million originally due in 2013, in order to facilitate the current eight well completion program. In exchange, the Company has agreed to expand the boundaries of the area of mutual interest set out in the original Sandstorm agreement by roughly 2 miles on all sides. This will provide Sandstorm with the right to continue to participate with Thunderbird over a substantially expanded area as the development operations at Gordon Creek grow in the future.
The Company is obligated to drill 15 wells and workover 5 standing wells on the Gordon Creek Property by December 31, 2012 and to drill a further 35 wells by December 31, 2013. Sandstorm advanced US$15 million to the Company in August
2011, US$3 million to the Company in July 2012 and will advance a further US$7 million in calendar 2013. In order to secure the further advance of US$7 million the Company must have drilled 20 wells and completed 5 workovers. Under the amended agreement, the Company has provided Sandstorm with minimum annual before tax cash flows guarantees earned through the sale of their 35% share of natural gas produced in Gordon Creek. The guarantee is the lesser of US$2.3 million or 790mmcf by December 31, 2013, US$5.1 million or 1740mmcf in calendar 2014, US$4.6 million or 1560mmcf in calendar 2015, US$4.2 million or 1410mmcf in calendar 2016, US$3.8 million or 1260mmcf in calendar 2017, US$3.3 million or 1140mmcf in calendar 2018 and US$1.7 million or 590mmcf in calendar 2019.
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MANAGEMENT DISCUSSION AND ANALYSIS
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As the ability of the Company to obtain the financing necessary to meet its full future exploration commitments under the agreement is uncertain, the Company has accounted for the US$18 million advance from Sandstorm as a financing deposit liability. In the event the Company should default on its future commitments, the default fee due to Sandstorm is amounts advanced or recovered from Sandstorm less production provided to Sandstorm and is due within 60 days of being in default.
Until December 31, 2013, the Company has the option to repurchase 50% of the commodity stream by making a US$16.25 million payment to Sandstorm, upon receipt of which, the percentage of natural gas Sandstorm will be entitled to purchase will decrease to 17.5%. If the Company drills additional wells on the Gordon Creek Property over and above the minimum 50 net wells, the Sandstorm has the option to have production from the additional net wells form a part of the commodity stream by providing additional production payment advances to the Company at an agreed amount per well.
During the quarter, the Company continued conducting a detailed review of its completion program for its eight previously drilled wells at Gordon Creek. The Company is studying recent innovations in completion technology with the view to enhancing completion results and potentially reducing costs.??? The timing of the completion and tie in program has been pushed back to early fall???. Completion programs will vary somewhat for each well depending on pay zone thicknesses and porosities, but will typically involve fracture stimulating the wells, equipping them and tying them into the existing Gordon Creek pipeline and infrastructure.
During the quarter, the Company received the outstanding balance of $1.0 million related to the terminated Gordon Creek Carbon Sequestration Phase III: Deep Saline Sequestration Deployment Project.
The Company’s natural gas production for the current quarter increased 8% over the immediately preceding quarter and 20% over the comparable quarter of the prior year, due to increased production from existing wells. However, average prices declined sharply during the current quarter as compared to the prior quarter and the prior fiscal year. Natural gas prices realized by the Company during the second quarter of fiscal 2013 year averaged US$1.69 (could it get any worse) compared to an average price of US$3.94 received during the second quarter of the prior year.
US domestic production of natural gas remained strong throughout calendar 2012 and residual storage levels were high following a relatively mild winter, leading to depressed prices. Prices began to recover during the latter part of the current quarter and the recovery continued into Q3, due in part to utility companies’ increased use of gas instead of coal for power generation. Natural gas drilling has also been reduced by up to 30% over the past twelve months which is expected to lead to declines in gas production during calendar 2013 if these trends continue. Natural gas pricing for thebalance of the Company’s fiscal year will depend in large part on whether or not these trends continue and on the levelsof weather dependent heating and cooling demand.
QUARTER ENDED JULY 31, 2012
MANAGEMENT DISCUSSION AND ANALYSIS
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RESULTS OF OPERATIONS
July 31, 2012 April 30, 2012 July 31, 2011 July 31, 2012 July 31, 2011
Operating Income/(Loss)(1) (102,677) (35,190) 54,225 (137,866) 111,519
General and administrative (314,594) (288,421) (276,050) (603,014) (429,746)
Finance Costs (186,941) (182,525) (224,237) (369,468) (392,249)
Funds Flow From Operations (1) (604,212) (506,136) (446,062) (1,110,348) (710,476)
Non-cash operating items:
Finance Costs (475,795) (353,596) (196,797) (829,391) (373,484)
Depletion and depreciation (44,944) (40,317) (51,715) (85,261) (95,383)
Share based compensation (49,792) (91,873) (45,013) (141,665) (59,702)
Foreign exchange gain (5,077) (2,203) 20,250 (7,280) 35,564
Net loss for the period (1,179,820) (994,125) (719,337) (2,173,945) (1,203,481)
Three Months Ended Six Months Ended
(1) “Operating income” and “funds flow from operations” are non-IFRS terms and may not be comparable with the calculation of similar measures for other entities. Operating income is equal to petroleum and natural gas sales minus royalties, operating costs, while funds flow from operations represents cash flow from operations before net changes in operating working capital accounts. Refer to the advisory on non-IFRS measures at the end of this MD&A.
Operating Income Items
Sales Volumes
During the three months ended July 31, 2012 the Company’s sales volume averaged 675 mcf/d of natural gas and 4 bbls/d of oil, compared to average daily sales volumes of 639 mcf/d and 5 bbls/d, respectively realized during the three month ended April 30, 2012. Sales volumes for the comparable quarter of the prior year averaged 563 mcf/d of natural gas and 3 bbls/day of oil. The Company’s natural gas production is attributable to its Gordon Creek, Utah natural gas project and its oil production is attributable to its 50% working interest in its Rush County, Kansas oil project.
Production Summary
The following table summarizes the production for the second quarter of fiscal 2013 and fiscal 2012:
Three months ended July 31, Six months ended July 31,
2012 2011 2012 2011
Production:
Natural gas (mcf) 62,092 51,828 119,571 94,424
Oil (bbls) 376 245 808 539
Total (BOE) (6:1) 10,725 8,883 20,737 16,276
Production split:
Natural gas (%) 96% 97% 96% 97%
Oil (%) 4% 3% 4% 3%
Average Realized Price
The following table summarizes the average realized price for the second quarter of fiscal 2013 and fiscal 2012:
Three months ended July 31, Six months ended July 31,
2012 2011 2012 2011
Exchange Rate US$/Cdn$ 0.9833 1.0341 0.9942 1.0302
Natural gas (mcf) US$/Mcf $ 1.69 $ 3.94 $ 1.74 $ 3.74
Oil (bbls) US$/bbls $ 80.25 $ 90.49 $ 89.18 $ 90.35
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MANAGEMENT DISCUSSION AND ANALYSIS
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Revenues, Royalties & Operating Costs
July 31, 2012 April 30, 2012 July 31, 2011 July 31, 2012 July 31, 2011
Revenues $ 166,353 $ 182,688 $ 260,423 $ 349,041 $ 467,980
Royalties 36,362 23,413 55,484 59,774 89,541
Direct operating and transportation 232,668 194,465 150,714 427,133 266,920
Operating Income(1) $ (102,677) $ (35,190) $ 54,225 $ (137,866) $ 111,519
Three Months Ended Six Months Ended
(1) Refer to the advisories on non-IFRS measures at the end of this MD&A.
Revenues
While production levels in the second quarter of fiscal 2013 were 5% higher than the first quarter and 19% higher than the second quarter of fiscal 2012, the current quarter revenues decreased 9% over the first quarter and 36% over the second quarter of fiscal 2012, due to lower prices of natural gas. The decrease in revenues was partially offset by increased oil production.
Royalties
Royalties as a percentage of petroleum and natural gas sales were 27% during the second quarter, consistent with the second quarter of fiscal 2012. Royalties as a percentage of petroleum and natural gas sales were 10% higher than the first quarter of fiscal 2013 as the Utah State annual required minimum royalty charge period ended during the quarter and therefore the remaining minimum royalties are expensed. This is consistent with prior years. Royalties vary for each producing well and therefore as a percentage of petroleum and natural gas sales will fluctuate from time to time depending on the production from each well during the respective period
Operating costs
Operating expenses include all normal operating costs as well as workover costs for both the Gordon Creek and the Rush County projects. Second quarter costs increased 20% over the first quarter and 54% over the second quarter of the prior year. In addition, the operating costs increased 60% over the six months ended July 31, 2011. The increase is primarily due to increased compressor lease costs incurred during the quarter as the Company prepared for anticipated higher production volumes as recently drilled wells are completed and tied in for production.
OTHER INCOME STATEMENT ITEMS
General and administrative
General and administrative costs include such items as office rent, accounting fees, legal fees, professional and consulting fees, filing fees, salaries and wages, transfer agent fees, travel costs, and investor relations, as well as general office expenses.
July 31, 2012 April 30, 2012 July 31, 2011 July 31, 2012 July 31, 2011
Reported amount $ 314,594 $ 288,421 $ 276,050 $ 603,014 $ 429,746
G&A ($/boe) $ 29.33 $ 28.81 $ 37.34 $ 29.08 $ 26.40
Three Months Ended Six Months Ended
G&A expenses increased 9% over the first quarter of fiscal 2013. The increase was attributable to additional audit fees incurred on the fiscal 2012 audit that were billed in the second quarter of the current fiscal year. G&A expense was 14% higher than the second quarter of fiscal 2012 due to additional consulting fees paid in connection with the ongoing Gordon Creek development program.
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MANAGEMENT DISCUSSION AND ANALYSIS
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G&A expenses were 40% higher in the six months ending July 31, 2012 than the corresponding period of the prior fiscal year. The increase is due significantly to additional consulting fees paid in connection with the Gordon Creek drilling program as well as the hiring of the Company’s current CFO.
Finance costs
July 31, 2012 April 30, 2012 July 31, 2011 July 31, 2012 July 31, 2011
Reported amount $ 662,736 $ 536,121 $ 421,034 $ 1,198,859 $ 765,733
Expense per sales volume ($/boe) $ 61.80 $ 53.55 $ 47.40 $ 57.81 $ 47.05
Three Months Ended Six Months Ended
Finance costs for the quarter include interest paid on gas linked debentures (see “Debentures” below) of $441,091 (2011 -$339,215). Included in the amount of interest paid on gas linked debentures is the fair value of common shares issued as quarterly interest totaling $252,049 (2011 -$193,834).
Also included in the finance costs are non-cash items including the fair value of accretion of debentures of $219,004 (2012– nil) and accretion of the decommissioning liabilities of $4,740 (2012 - $2,963). In addition, finance costs include nominal interest income of $2,099 (2012 - $171). The significant increase in interest, accretion and debt service costs for the three and six months ending July 31, 2012 over the immediate preceding quarter and corresponding period of fiscal 2012 is due a higher expense on the non-cash accretion of the debentures.
Depletion and depreciation
July 31, 2012 April 30, 2012 July 31, 2011 July 31, 2012 July 31, 2011
Reported amount $ 44,944 $ 40,317 $ 51,715 $ 85,261 $ 95,383
Expense per sales volume ($/boe) $ 4.19 $ 4.03 $ 6.99 $ 4.11 $ 5.86
Three Months Ended Six Months Ended
Depletion and depreciation is associated with the Gordon Creek project. The net carrying value of the development or production assets is depleted using the unit-of-production method by reference to the ratio of production in the period over the related proven and probable reserves while also taking into account estimated future development costs necessary to bring those reserves into production. Changes in depletion and depreciation expense are consistent with the changes in production over previous quarters.
Foreign exchange gain
For the six months ended July 31, 2012, the Company had a foreign exchange loss of $7,280 (July 31, 2011 – foreign exchange gain of $35,564). Unrealized foreign exchange gains and losses in fiscal 2012 pertain to the translation of shortterm debt and promissory notes denominated in U.S. currency.
Share-based compensation
There were no options issued during the quarter.
RISKS AND TRENDS
Demand for natural gas has traditionally been highly cyclical and somewhat predictable. Demand for, and pricing of, natural gas has traditionally been highest during the coldest months of winter. The primary driver for this cyclicality is the
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MANAGEMENT DISCUSSION AND ANALYSIS
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need for residential and commercial heating. Because natural gas is increasingly being used to generate electricity, increased electrical demand often means increased natural gas demand and pricing. This results in a smaller spike in natural gas demand during the warmest months of the year, as electrical demand for space cooling increases. Accordingly, the spring and fall “shoulder seasons” are typically becoming the periods of lowest natural gas prices.
Unconventional natural gas reserves and production have steadily increased in the United States over the past few years as a result of new horizontal drilling and “multi-frac” stimulation technologies that have allowed the commercialization of several large shale gas formations. This has caused downward pressure on gas prices. This downward pressure has been mitigated somewhat by the decrease in conventional gas drilling as well as increasing overall demand coincident with the ongoing economic recovery. Long term, there is an ongoing push to switch to natural gas for energy generation and transportation as a cleaner burning and potentially less expensive alternative to coal and oil, however, the timing and extent of this shift is uncertain.
Although the Company has no set policy concerning hedges, management may utilize various techniques to mitigate financial risks including hedging contracts, other financial instruments, and/or fixed price forward sales contracts to reduce corporate risk in certain situations. The Company currently has no fixed price contracts.
Oil and natural gas operations involve many risks that even a combination of experience and knowledge and careful evaluation may not be able to overcome. The long-term commercial success of the Company depends on its ability to find, acquire, develop and commercially produce oil and natural gas reserves. Without the continual addition of new reserves, the Company’s total reserves and the production there from will decline as such existing reserves are exploited.
A future increase in the Company’s reserves will depend not only on the Company’s ability to explore and develop any properties it may have from time to time, but also on its ability to select and acquire suitable producing properties or prospects. No assurance can be given that further commercial quantities of oil and natural gas will be discovered or acquired by the Company.
The Company’s principal risks include finding and developing economic hydrocarbon reserves efficiently and the ability to fund the required capital programs. The recently completed hydrocarbon purchase agreement with Sandstorm Metals & Energy Ltd. will fund the next phase of the Company’s development activities at Gordon Creek, however, further capital will be required as the Company enters into subsequent phases of development and fulfills its drilling commitments to Sandstorm. The Company anticipates that future capital requirements will be funded through a combination of internal cash flow, debt, joint venture and equity financing. There is no assurance that financing will be available on terms acceptable to the Company to meet its capital requirements. If any components of the Company’s business plan are missing, the Company may not be able to exercise the entire business plan.
These risk factors should not be construed as exhaustive. There are numerous factors, both known and unknown, that could cause results or events to differ materially from forecast results.
Safety and Environment
Oil and gas exploration and production can involve environmental risks such as pollution of the environment and destruction of natural habitat, as well as safety risks such as personal injury. The Company conducts its operations with high standards in order to protect the environment and the general public. The Company maintains current insurance coverage for comprehensive and general liability as well as limited pollution liability. The amount and terms of this insurance are reviewed on an ongoing basis and adjusted as necessary to reflect current corporate requirements, as well as industry standards and government regulations.
LIQUIDITY AND CAPITAL RESOURCES
The Company’s traditional sources of funding included the issuance of equity securities for cash, primarily through private placements and debt financing. The Company has issued debentures and common shares pursuant to private placement financings and exercise of warrants and options. The Company’s access to exploration financing when the financing is not transaction specific is always uncertain. There can be no assurance of the continued access to significant equity financing.
During the prior year, the Company entered into a US$25 million commodity stream production payment agreement with
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MANAGEMENT DISCUSSION AND ANALYSIS
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Sandstorm Metals & Energy Ltd. whereby Sandstorm will advance US$25 million to the Company in calendar 2011 and 2013 in exchange for the right to purchase 35% of the Company's Gordon Creek natural gas production at a price of US$1.00 per Mcf plus 20% of the amount by which the Gordon Creek field gate price exceeds US$4.00. The Company has agreed to drill 50 wells and workover 5 standing wells during fiscal 2013 and 2014, and has also provided Sandstorm with minimum annual production/cash flow guarantees. Under the terms of the agreement, Sandstorm advanced the Company US$15 million in 2011 and was scheduled to advance the remaining balance of US$10 million in 2013. On July 11, 2012 the Company negotiated an amendment to its agreement with Sandstorm whereby Sandstorm advanced US$3 million of the US$10 million originally due in 2013, in order to facilitate the current eight well completion program. In exchange, the Company has agreed to expand the boundaries of the area of mutual interest set out in the original Sandstorm agreement by roughly 2 miles on all sides. This will provide Sandstorm with the right to continue to participate with Thunderbird over a substantially expanded area as the development operations at Gordon Creek grow in the future.
The Company is required to drill 20 wells and workover 5 standing wells in order to receive the remaining US$7 million payment. Once the additional US$7 million is advanced, the Company will be required to drill an additional 30 wells. The Company anticipates raising additional capital to complete its commitments to Sandstorm, by way of debt and/or equity. These funding arrangements are not yet in place.
During the prior quarter, the Company and Sandstorm amended the commodity stream production payment agreement whereby all minimum cash flow guarantees and drilling commitments at Gordon Creek were deferred by one year to the dates referenced herein. As consideration for this deferral, in March 2013, Thunderbird will issue to Sandstorm $2.55 million of Thunderbird shares determined at a deemed price equivalent to 50 day volume weighted average trading price prior to issuance. Under the amended agreement, the Company has provided Sandstorm with minimum annual before tax cash flows guarantees earned through the sale of their 35% share of natural gas produced in Gordon Creek. The guarantee is the lesser of US$2.3 million or 790mmcf by December 31, 2013, US$5.1 million or 1740mmcf in calendar 2014, US$4.6 million or 1560mmcf in calendar 2015, US$4.2 million or 1410mmcf in calendar 2016, US$3.8 million or 1260mmcf in calendar 2017, US$3.3 million or 1140mmcf in calendar 2018 and US$1.7 million or 590mmcf in calendar 2019.
At July 31, 2012, the Company had cash of $4,499,905 (January 31, 2012 - $7,628,701).
The Company has no “purchase obligations” defined as any agreement to purchase goods or services that is enforceable and legally binding on the Company that specifies all significant terms, including fixed or minimum quantities to be purchased; fixed, minimum or variable price provisions; and the proximate timing of the transaction.
With the exception of the obligations to drill 50 wells and complete 5 workover operations pursuant to the Sandstorm Agreement outlined above, the Company had no commitments for capital expenditures as of July 31, 2012. The Company has no lines of credit or other sources of financing which have been arranged at this time, other than those listed below.
Debentures
The Company issued $10,000,000 principal amount of three year, secured, natural gas linked debentures. The debentures bear interest at a base rate of 15% per annum with an adjustment provision whereby a 1% interest premium is added each quarter for every US$0.50 by which the price of natural gas as published by the Henry Hub exceeds US$5.00, capped at 25% per annum. One-half of each quarterly interest payment will be paid in fully paid common shares of the Company at a deemed price per interest share equal to the greater of (i) a 10% discount to the volume weighted average trading price of the Company’s common shares on the TSX Venture Exchange over the quarter and (ii) the discounted market price of the Company’s common shares. The purchasers of the gas linked debentures were also issued two detachable transferable warrants for every $1.00 of principal amount to purchase up to 20,000,000 common shares of the Company at escalating prices between $0.30 and $0.50 per share until October 31, 2013. The Company paid a 7.5% finder’s fee in respect of a portion of the debenture issuance and issued non-transferable finder’s warrants to purchase up to 2,161,250 common shares of the Company at a price of $0.20 per share until October 31, 2013.
TRANSACTIONS WITH RELATED PARTIES
Koele Capital Corp. (“Koele”) of which the CEO is a shareholder, was paid $22,500 in consulting fees for the quarter. The Company has an ongoing contractual arrangement with Koele to pay consulting fees of $7,500 per month.
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MANAGEMENT DISCUSSION AND ANALYSIS
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Westrich Resources Inc. (“Westrich”) of which the President and COO is a shareholder, was paid $36,000 in consulting fees for the quarter. The Company has an ongoing contractual arrangement with Westrich to pay consulting fees of $12,000 per month.
D. John Bell Professional Corporation, of which the CFO is a shareholder, was paid $8,875 in consulting fees for the quarter. Bently Oil & Gas Ltd., a company that shares common directors with the Company, was paid $8,875 by way of partial reimbursement of accounting fees.
Thunderbird Films Inc, a company that shares common directors with the Company, was paid $38,295 (2012 - $32,043) during the quarter by way of a partial reimbursement of accounting fees, office reception, rent and supplies pursuant to a cost sharing arrangement between the two companies.
Amounts due to related parties includes $66,124 (January 31, 2012 - $69,161) due to officers and directors and companies with common directors. Amounts due from related parties includes $37,765 (January 31, 2012 - nil) due from companies with common directors. Included in the debentures is $2,629,000 held by related parties.
QUARTERLY FINANCIAL INFORMATION (unaudited)
Income Statement: Q2 2013 Q1 2013 Q4 2012 Q3 2012 Q2 2012 Q1 2012 Q4 2011 Q3 2011
Net Revenues after
Royalties 129,991 159,275 193,043 210,478 204,939 173,500 193,876 231,878
Expenses 1,309,811 1,153,400 1,696,574 2,867,148 924,276 657,644 1,129,104 1,113,340
Net loss for the period (1,179,820) (994,125) (1,503,531) (2,656,670) (719,337) (484,144) (935,228) (881,462)
Basic and diluted loss per share (0.01) (0.01) (0.02) (0.03) (0.01) (0.01) (0.01) (0.01)
Weighted average number of shares outstanding (thousands) 82,269 80,813 79,985 78,468 75,297 73,174 71,926 69,864
CRITICAL ACCOUNTING ESTIMATES
The preparation of the interim consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities at the date of the financial statements and for the periods presented. Such estimates primarily related to unsettled transactions and events as at the date of the interim consolidated financial statements. Actual results may differ from those estimates. Significant estimates and judgments made by Management in the preparation of these interim consolidated financial statements are outlined below.
Fair value of oil and gas properties, depletion and depreciation and amounts used in impairment calculations are based on estimates of oil and natural gas reserves, future prices and future costs required to develop those reserves. By nature, estimates of reserves and the related future cash flows are subject to measurement uncertainty, and the impact of the differences between actual and estimated amounts on the consolidated financial statements of future periods could be material.
Petroleum and natural gas properties, exploration and evaluation assets and other corporate assets are aggregated into cash-generating-units ("CGUs") based on their ability to generate largely independent cash flows and are used for impairment testing. The determination of the Company's CGUs is subject to management's judgment.
The decision to transfer exploration and evaluation assets to property and equipment is based on management's
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MANAGEMENT DISCUSSION AND ANALYSIS
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determination of an area's technical feasibility and commercial viability based on proved and probable reserves. Amounts recorded in decommissioning liabilities and the related accretion expense require the use of estimates including timing of asset retirements, site remediation, discount rate, inflation rate and related cash flows. Provisions are ecognized in the period when it becomes probable that there will be a future cash outflow.
Compensation costs accrued for share-based compensation plans are subject to the estimated fair values, forfeiture rates.
Tax interpretations, regulations and legislation in the various jurisdictions in which the Company and its subsidiaries operate are subject to change and interpretation. Deferred tax assets are assessed by management at the end of the reporting period to determine the likelihood that they will be realized from future taxable earnings.
FORWARD LOOKING STATEMENTS
This discussion includes certain statements that may be deemed “forward-looking statement”. Forward-looking statements or information do not relate strictly to historical or current facts, and can be identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “may”, “will”, “plan”, “project”, “should”, “believe”, “intend”, or similar expressions. These statements represent managements’ reasonable projections, expectations and estimates as of the date of this document, but undue reliance should not be placed upon them as they are derived from numerous assumptions. These assumptions are subject to known and unknown risks and uncertainties, including the business risk discussed in the MD&A, which may cause actual performance and financial results to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements.
Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. In addition to the other assumptions identified in this document, assumptions have been made regarding, among other things:
• Future oil and gas supply and prices;
• Drilling and operational results consistent with expectations;
• The ability for the Company to obtain financing on acceptable terms;
• Currency, exchange and interest rates;
• Cash flow consistent with expectations;
• The ability of the Company to obtain equipment, services and supplies in a timely manner to carry out its activities;
The forward looking information in this document is subject to significant risks and uncertainties and is based on a number of material factors and assumptions which may prove to be incorrect; including but not limited to the following assumptions:
• Normal risks common to the petroleum and natural gas industry including various operational risk in exploring for, developing and producing petroleum and natural gas and market demand
• Risks and uncertainties involving geology of oil and gas deposits
• Revisions, amendments or changes to capital expenditure plans including exploration, development and exploitation projects
• Uncertainties as to the availability and cost of appropriate financing alternatives on acceptable terms, including the Company’s ability to extend its credit facility on an ongoing basis
• Potential changes in income tax regulations, governmental policies, rules, practices or approval process changes, or delays, or enhancements
• Ability to attract and retain qualified professional employees
• Fluctuations in oil and gas prices, foreign currency exchange rates and interest rates
• The uncertainty of reserve estimate and reserve life
• The uncertainty of estimates and projections relating to future production, costs and expenses
• Health, safety and environmental risks
Statements relating to “reserves” or “resources” are by their nature deemed to be forward-looking statements, as they involve the implied assessment based on certain estimates and assumptions that the resources and reserves described
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MANAGEMENT DISCUSSION AND ANALYSIS
can be profitably produced in the future.
Although the company believes the expectations expressed in such forward-looking statements or information are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. Accordingly, readers should not place undue reliance on forward-looking information.
The forward-looking statements or information contained in this document represent our views as of the date hereof and as such information should not be relied upon as representing our views as of any date subsequent to the date of this document. 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.
Non-IFRS Measures
In this document, the Company uses the terms “funds flow from operations” and “operating income” which do not have any standardized meaning under IFRS and may not be comparable to similar measures presented by other companies.
“Funds flow from operations” refers to the cash flow from operating activities before net changes in operating working capital. The most direct comparable measure to “funds flow from operations” calculated in accordance with IFRS is the cash flow from operating activities. “Funds flow from operations” can be reconciled to cash flow from operating activities by adding (deducting) the net change in working capital as shown in the consolidated statements of cash flow.
“Operating income” is equal to petroleum and natural gas sales minus royalties and operating costs. Management believes that the Non-IFRS measures provide useful information to investors as indicative measures of performance.
Investors are cautioned that the Non-IFRS measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with IFRS, as set forth above, or other measures of financial performance calculated in accordance with reporting standards.
BOE Presentation
Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of gas (“Mcf”) to one barrel of oil (“bbl”) (6 Mcf: 1 bbl) is used as an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. All boe conversions in this report are derived by converting natural gas to oil in the ratio of six Mcf of gas to one barrel of oil. Readers should be aware that historical results are not necessarily indicative of future performance.
DISCLOSURE OF OUTSTANDING SHARE DATA
As at September 28, 2012 the Company had the following common shares and stock options outstanding:
Common Shares 84,062,830
Share Purchase Warrants 33,841,459
Stock Options 6,590,000
There are no shares held in escrow.
“CAMERON WHITE”
Cameron White, Chief Executive Officer
“STEPHEN CHEIKES”
Steven Cheikes, Director