Exhibit 99.2
Management’s Discussion and Analysis
for the Six Month Period Ended May 31, 2011
ALBERTA STAR DEVELOPMENT CORP.
506 – 675 West Hastings Street
Vancouver, British Columbia
V6B 1N2
Telephone: (604) 488-0860
Facsimile: (604) 408-3884
Contact Name: Tim Coupland, President
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ALBERTA STAR DEVELOPMENT CORP.
Management’s Discussion and Analysis
for the Six Month Period Ended May 31, 2011
This management’s discussion and analysis (“MD&A”) of Alberta Star Development Corp. (the “Company”), dated July 22, 2011 should be read in conjunction with the accompanying financial statements and notes for the six month period ended May 31, 2011. The Company’s financial statements are prepared in accordance with Canadian generally accepted accounting principles (“GAAP”). Except as noted, all financial amounts are expressed in Canadian dollars. Additional information relating to the Company is available on SEDAR and may be accessed at www.sedar.com.
NON-GAAP MEASURES
The Company’s management uses and reports certain measures not prescribed by generally accepted accounting principles (referred to as “non-GAAP measures”) in the evaluation of operating and financial performance. Operating netback, which is calculated as average unit sales prices less royalties and operating expenses, and corporate netback, which further deducts administrative and interest expense, represent net cash margin calculations for every barrel of oil equivalent sold. Net debt, which is current assets less current and other financial liabilities (e.g. note payable), is used to assess efficiency and financial strength. Operating netback, corporate netback and net debt do not have any standardized meanings prescribed by GAAP and therefore may not be comparable with the calculation of a similar measure for other companies. The Company uses these terms as an indicator of financial performance because such terms are often utilized by investors to evaluate junior producers in the oil and natural gas sector.
FORWARD-LOOKING INFORMATION
This document contains certain statements that may be deemed “forward-looking statements”. All statements in this document, other than statements of historical fact, that address future production, reserve potential, exploration drilling, exploitation activities and events or developments that the Company expects to occur, are forward looking statements. Forward looking statements are statements that are not historical facts and are generally, but not always, identified by the words “expects”, “plans” “anticipates”, “believes”, “intends”, “estimates”, “projects”, “potential” and similar expressions, or that events or conditions “will”, “would”, “may”, “could” or “should” occur. In particular, the forward-looking statements in this MD&A include: (i) under the heading “Overview and Overall Performance”and “Outlook” statements relating to increasing and maximizing future production and expansion by the Company into the oil and natural gas sector through the development of the Company’s existing assets and the acquisition of additional oil and natural gas properties; (ii) under the heading “Outlook” statements relating to the Company’s capital expenditure plans for 2011; (iii) under the heading “Outlook” statements relating to licensing approval and the ability to obtain drilling rigs in order to complete the Company’s exploration program; and (iv) under the heading “Liquidity and Capital Resources” the statement that the Company believes it has sufficient funds to fund its currently planned exploration and administrative budget through the balance of fiscal 2011. Further, information inferred from the interpretation of drilling results and information concerning mineral resource estimates may also be deemed to be forward looking statements, as it constitutes a prediction of what might be found to be present when and if a project is actually developed. Forward-looking statements involve numerous risks and uncertainties. Estimates and forward-looking statements are based on assumptions of future events and actual results may vary from these estimates The foregoing forward-looking statements are based on assumptions including that the Company will be able to identify potential assets for acquisition on terms that are satisfactory to the Company; that the execution of the Company’s capital expenditure plans will remain in the best interests of the Company; that the Company will obtain all required regulatory approvals; and that the
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company will be able to source the required services (including drilling rigs) to execute its capital expenditure plans.
Although the Company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results may differ materially from those in the forward-looking statements. Factors that could cause the actual results to differ materially from those in forward-looking statements include market prices, exploitation and exploration successes, and continued availability of capital and financing, and general economic, market or business conditions and other factors discussed under the heading “Risks and Uncertainties”. Investors are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements.
The forward-looking statements contained in this MD&A are made as of the date hereof and the Company undertakes no obligation to update publicly or revise any forward-looking statements or in any other documents filed with Canadian securities regulatory authorities whether as a result of new information, future events or otherwise, except in accordance with applicable securities laws. The forward-looking statements are expressly qualified by this cautionary statement.
Except for the statements of historical fact contained herein, certain information presented constitutes "forward-looking statements" within the meaning of the United States Private Securities Litigation Reform Act of 1995. Such forward-looking statements, including but not limited to, those with respect to potential expansion of mineralization, potential size of mineralized zone, timing of resource calculation and size of exploration program involve known and unknown risks, uncertainties and other factors which may cause the actual results, performance or achievement of Alberta Star Development Corp. (the “Company”) to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements. Such factors include, among others, risks related to international operations and joint ventures, the actual results of current exploration activities, conclusions of economic evaluations, uncertainty in the estimation of ore reserves and mineral resources, changes in project parameters as plans continue to be refined, future prices of gold, silver, uranium and base metals, environmental risks and hazards, increased infrastructure and/or operating costs, labor and employment matters, aboriginal and government regulation and permitting requirements as well as those factors discussed in the section entitled "Risk Factors" in the Company’s latest Form 20-F on file with the United States Securities and Exchange Commission in Washington, D.C. Although the Company has attempted to identify important factors that could cause actual results to differ materially, there may be other factors that cause results not to be as anticipated, estimated or intended. There can be no assurance that such statements will prove to be accurate as actual results and future events could differ materially from those anticipated in such statements. The Company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. Accordingly, readers should not place undue reliance on forward-looking statements.
OVERVIEW AND OVERALL PERFORMANCE
The Company is a Canadian resource exploration and development company that identifies, acquires and finances oil and natural gas assets in Western Canada and advanced stage mineral exploration projects in North America. In August 2010, the Company made two strategic heavy oil & gas acquisitions in Lloydminster, Alberta and Saskatchewan which has expanded its diversification into the oil and natural gas resource sector with the acquisition of revenue producing resource assets which compliments its existing mineral exploration interests. The Company is evolving into an Alberta based, junior heavy oil producer that has a growing production base, and intends to maximize future production through its exploration drilling activities, production acquisitions and strategic asset acquisition both domestically and in the international arena. The strategic heavy oil & gas property acquisitions combined with a growing production portfolio has further strengthened the Company’s relationship, with an experienced working
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interest partner and heavy oil industry leader. This strategic partnership will allow for future expansion into the oil and natural gas resource sector through exploration drilling, existing asset development and production asset acquisition.
The Company maintains a strong balance sheet and has a qualified management team in field exploration, exploration drilling, well operations and has the necessary manpower ready for the development of the Company’s oil and gas and natural resource properties. The Company is committed to increasing its daily aggregate oil production, by selecting and acquiring additional strategic oil and gas properties and then developing these petroleum and natural gas resource assets.
HIGHLIGHTS OF SIX MONTH PERIOD ENDED MAY 31, 2011
In August 2010, the Company diversified into the oil and natural gas resource sector with the acquisition of revenue producing resource assets to complement its existing advanced stage mining interests and provides the Company with a reputable working interest partner and field operator for future expansion in the oil and natural gas resource sector. The Company is now a heavy oil producer.
The Company continues to strengthen its financial position with stable production volumes, strong oil prices and control over costs as more wells are drilled, completed and brought into production.
On December 14, 2010, the Company announced that it was successful at the December 6, 2010, Saskatchewan Crown Land Sale, acquiring petroleum and natural gas rights on a 160 acre parcel of undeveloped lands in the Lloydminster heavy oil region. The acquisition increases the Company’s growing land base in west central Alberta and Saskatchewan and increases the additional potential for multiple drilling opportunities being identified, finalized and planned by Alberta Star and its industry partner Western Plains Petroleum Ltd., for drilling exploration in 2011. Alberta Star holds an undivided 50% working interest in the acquired lands, as the acquisition was made jointly on a 50/50 basis with Western Plains.
On January 14, 2011, the Company announced its capital expenditure plans for 2011. Current plans anticipate capital exploration and development expenditures of $2.5 million dollars for additional in-fill drilling and completions located on our Landrose, Saskatchewan, Kitscoty, Alberta, Northminster, Saskatchewan and on other working interest heavy oil properties situated in both the Lloydminster area of west central Alberta and Saskatchewan. The majority of our 2011 capital spending will be used to drill, complete and equip a scheduled twelve wells (6 net) for approximately $2.1 million. The plan also includes facilities investments, primarily in Saskatchewan which will optimize new production as well as improving existing production efficiencies.
In addition, first quarter spending included carryover activity as the Company completed and added production from wells that were drilled in the fourth quarter of 2010. The Company has submitted applications for a twelve well (6 net wells) program for approval in 2011. The Company will place a priority on it’s Landrose heavy oil property and our previously announced Phase 3 drilling program consisting of three (1.5 net) in-fill drilling locations. The Company has drill applications submitted and pending on the Kitscoty, Alberta property (3 well locations) and Northminster, Saskatchewan property (6 well locations). The Company expects to commence drilling, once permit applications have been approved and drilling rigs have been secured. Drilling is expected to be ongoing through 2011 as the Company pursues its strategy of increasing daily production growth. The Company’s success in adding production in the last six months of 2010 has enabled us to establish a credit facility of $1.1 million with the Canadian Western Bank consisting of an $800,000 revolving operating loan and a non-revolving acquisition and development loan. The Credit facility combined with the Company’s strong cash position will allow financial flexibility as we look to implement and execute our 2011 capital expenditure plan.
On February 16, 2011, and subsequently on April 21, 2011, the Company announced that it had agreed to participate in drilling one well (0.5 net to the Company) on the Blackfoot lands located in the Lloydminster area of Alberta.
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On April 21, 2011, the agreements were amended on the following terms. The Company entered into a Participation Farmout Agreement to drill and complete one heavy oil well (0.5 net to the Company) on the Blackfoot lands located west of Lloydminster, Alberta. Upon completion of its earning obligations, the Company will earn a 50% working interest in the test well lands, subject to a convertible gross over riding royalty. The proposed well is located at 04-02-050-02-W4M, is subject to rig availability, and is expected to be spudded in 2011.
Sahara Energy Ltd.(“Sahara”) will be the operator and holds a 50% working interest in the well. The Company must pay 50% of the cost to drill, complete and equip or abandon the well to earn a 50% working interest, reserving to the farmor a gross convertible overriding royalty of 15%.
On April 14, 2011, the Company announced that it had drilled, cased and completed the first well of the Company’s Blackfoot Phase 1- three (3) well (1.0 net well to the Company) drilling program on the Blackfoot heavy oil property in Lloydminster, Alberta. The well is located at 3D-11-050-02-W4 and is currently producing and the Company expects that once the well has stabilized, production rates will be comparable to that of surrounding heavy oil wells. The Blackfoot Phase 1 – three (3) well program is scheduled to include drilling and completing three in-fill heavy oil wells at the following locations:3D-11-050-02-W4 (drilled, completed and on initial production). C6-24-050-02-W4 (not participating) and C7-14-050-02-W4 (not participating).
On May 10, 2011, the Company announced that it had completed a property swap with a major Canadian oil producer resulting in the Company acquiring a 50% working interest in petroleum and natural gas rights, including one standing cased well, on 240 acres located in the Landrose area of Saskatchewan, located approximately 16 kilometres east of Lloydminster, Alberta in exchange for its 50% working interest on 320 acres (160 net acres) of undeveloped land located in the Golden Lake area of west central Saskatchewan.
On June 3, 2011, the Company announced that it had started phase III drilling and re-completed a standing cased well situated on its Landrose property, located in west central Saskatchewan. The re-completed well was recently acquired in a property swap with a major Canadian oil producer announced in the press release dated May 10, 2011.
On June 27, 2011, the Company announced the re-completion of the new well at Landrose on section B13-6-50-25W3 which was brought into production at an average rate of 40 bbls/d (20 bbls/d net to the Company). In addition, the Company has identified six drill locations on the recently acquired Landrose properties. The Company expects to include at least three additional drilling locations from the Landrose properties in its 2011 drilling program. The Company’s Phase 3 drilling program is scheduled to consist of three wells which are anticipated to be drilled, completed and, if successful, on production by the end of August 2011.
The Company has implemented a responsible growth strategy, which includes the acquisition of low risk drilling locations, the continual acquisition of additional oil and gas assets located in the provinces of Alberta and Saskatchewan. A $2.5 million dollar capital budget has been approved for 2011, of which $2.1 million is budgeted for drilling, completing and equipping an estimated 10-12 wells (5- 6 net to the Company).
Alberta Star continues to pursue, review and evaluate a number of strategic exploration and production opportunities in several oil & gas regions in Colombia, South America. The Company over the past few months has been actively reviewing oil and natural gas exploration and production opportunities in several regions of Colombia with a number of interested parties. The Company believes that Colombian oil exploration and development activity is now targeting the heavy oil resources situated in Colombia, particularly in the upper, middle and southern Magdalena river valley where the Company and its working interest partner, hope to implement their successful Canadian heavy oil exploration, production strategy model, which has been developed successfully in the prolific heavy oil fields straddling Lloydminster, Alberta and Saskatchewan.
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The Company’s shares are listed on the TSX Venture Exchange under the symbol “ASX”, on the OTCBB under the symbol “ASXSF” and on the Frankfurt Exchange under the symbol “QLD”.
As at May 31, 2011, the Company had working capital of $7,208,527, inclusive of $8,422,503 of cash and cash equivalents on hand. Cash and cash equivalents on hand at the date of this MD&A are approximately $8,400,000 which will provide sufficient working capital to cover additional property acquisitions, planned exploration expenditures, and administration expenses through the same period.
Management has taken steps to reduce its general and administrative costs primarily through reduction in advertising and promotional expenses.
Effective August 1, 2010, the Company started receiving oil and gas revenue from its recently acquired interests in its oil and gas resource properties. Only the 1stand 2ndquarters of 2011 and the 3rdand 4thquarters of 2010 show oil and gas revenue and prior quarters are not shown as there was no production. The following table is from August 1, 2010 to May 31, 2011.
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FINANCIAL AND OPERATING SUMMARY
TABLE A - OPERATIONS BY QUARTER (August 1, 2010 to May 31, 2011)
| | | | |
| All production is conventional heavy oil | | | | |
| | Q2 | Q1 | Q4 | Q3 |
| Production and per share | 2011 | 2011 | 2010 | 2010 |
| Production - total barrels | 7,989 | 8,230 | 5,045 | 722 |
| Production - bbls/ day | 86 | 91 | 55 | 23 |
| Heavy oil revenue | 568,888 | 485,285 | 281,651 | 46,489 |
| Royalty income | 7,451 | 31,074 | 36,493 | 6,632 |
| Royalties | (105,260) | (84,221) | (39,255) | (4,874) |
| Production & transportation | (169,902) | (209,849) | (147,432) | (31,505) |
| Operating net back | 301,177 | 222,289 | 131,457 | 16,742 |
| General and administrative | (368,335) | (598,470) | (516,823) | (325,127) |
| Corporate net back | (67,158) | (376,181) | (385,366) | (308,385) |
| Depletion, accretion & amortization | (248,188) | (232,319) | (147,601) | (22,671) |
| Other (expenses) revenue | 2,486 | (71,809) | (267,115) | 253,521 |
| Income (loss) for the period | (312,860) | (680,309) | (800,082) | (77,535) |
| Basic and diluted income (loss) per share | (0.015) | (0.032) | (0.037) | (0.004) |
| Royalties as % of petroleum revenue | 19 | 17 | 14 | 10 |
| | | | | |
| | | | | |
| Per bbl analysis | Per bbl | Per bbl | Per bbl | Per bbl |
| Heavy oil revenue | 71.21 | 58.97 | 55.83 | 64.39 |
| Royalty income | 0.93 | 3.78 | 7.23 | 9.19 |
| Royalties | (13.18) | (10.23) | (7.78) | (6.75) |
| Production and transportation | (21.27) | (25.50) | (29.22) | (43.64) |
| Operating net back | 37.69 | 27.02 | 26.06 | 23.19 |
| General and administrative | (46.11) | (72.72) | (102.44) | (450.31) |
| Corporate net back | (8.42) | (45.70) | (76.38) | (427.12) |
| Depletion, accretion & amortization | (31.07) | (28.23) | (29.26) | (31.40) |
| Other (expenses) revenue | 0.31 | (8.73) | (52.95) | 351.13 |
| Income (loss) for the period | (39.18) | (82.66) | (158.59) | (107.39) |
| | | | | |
| Funds (invested in) petroleum properties | (6,125) | (525,000) | (482,979) | (3,123,779) |
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FINANCIAL AND OPERATING SUMMARY
TABLE C – BALANCE SHEET
| | | | |
| | Q2 | Q1 | Q4 | Q3 |
| | 2011 | 2011 | 2010 | 2010 |
| Net cash | 8,422,503 | 8,717,027 | 9,456,219 | 10,292,528 |
| Total assets | 12,650,886 | 13,102,221 | 13,605,905 | 14,077,712 |
| Total liabilities | 1,886,819 | 2,033,175 | 2,066,420 | 1,747,766 |
| Shareholders’ equity | 10,874,067 | 11,069,046 | 11,539,485 | 12,329,946 |
| SHARES | | | | |
| Basic outstanding | 21,403,979 | 21,403,979 | 21,403,979 | 21,403,979 |
| Weighted average | 21,403,979 | 21,403,979 | 21,403,979 | 21,403,979 |
OPERATING RESULTS FOR SIX MONTHS ENDED MAY 31, 2011
The oil and gas properties were acquired on August 9, 2010 and August 26, 2010. The pre-acquisition earnings are an adjustment to the purchase price with the revenue and operating costs not being recorded. Only the August production of 722 barrels from the August 9, 2010 acquisition are recorded in Q3 2010, 5,045 barrels of production were recorded in the 4thquarter of 2010, 8,230 barrels of production were recorded in the 1stquarter of 2011 and 7,989 barrels of production were recorded in the 2ndquarter of 2011. A total of 24 wells were producing in Q2 2011.
Q2 2011 average production was 86 bbls per day compared to Q1 2011 average production of 91 bbls per day. The Company has no debt. As our production profile continues to increase, we anticipate higher netbacks per bbl as costs per bbl for general and administrative (G & A) and production costs decrease.
The Company will continue to increase production on a more diverse property base. The strong balance sheet, the unused credit facilities and the motivated partner will allow the Company to finance this continued production growth and the resulting increase in cash flow.
All of the Company’s crude oil consists of heavy oil produced in Saskatchewan and Alberta that is marketed base on refiner’s posted prices for Western Canadian Select heavy oil, adjusted for the quality (primarily density) of the crude oil on a well by well basis. The majority of the Company’s heavy oil ranges in density from approximately 13.6 API to 15.9 API. The refiner’s posted prices are influenced by the US$WTI reference price, transportation costs, US$/C$ exchange rates and the supply/demand situation of particular crude oil quality streams during the year. The prices realized by the Company on heavy oil sales are net of treating fees, blending costs, required for its heavy grades of oil to meet pipeline stream specification, and pipeline tariffs.
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The price differential between heavy and light crude oil increased in Q 2 2011 (approximately $25/bbl) over prior quarters primarily due to a transportation disruption resulting from the nine week maintenance shut-down of a pipeline that carries Canadian crude oil to refineries in the U.S. Midwest. Further short term maintenance shut-downs of this pipeline followed in January and February 2011, with product delivery rates having been largely restored by late April. As a result, the Company realized an average oil price of $71.21 per bbl in Q2 2011 as compared to $58.97 per bbl in Q1 2011. Current revenue per bbl is approximately $75 per bbl.
Q2 2011 overall royalty burden averaged 19% compared to 17% in Q1 2011. Q2 2011 includes the higher production volumes from the newly drilled wells. The higher production volumes and strong oil prices triggers a higher royalty burden under the crown regimes. This explains the higher overall burden in Q2 2011 of 19% compared to 17% in Q 1 2011. The Company incurs a mix of crown, freehold and overriding royalties. The Volumes and mix of oil wells producing in a quarter impact the overall average burden.
Winter operating costs are higher than other seasons as certain costs (e.g. snowplowing) are incurred only in cold weather. A significant portion of production costs are fixed and therefore production expense per bbl varies significantly with volume. Major repairs in a quarter also significantly increase costs per bbl given the small production volumes of the Company. Heavy oil production costs tend to be higher than light oil production costs. Transportation costs are low and comprise only the trucking of clean oil short distances to the sales terminal. The plans to drill additional wells to increase production should reduce production costs per bbl for 2011.
As production just started as a result of the oil and gas acquisitions, costs per bbl will reduce significantly as general and administrative costs tend to be fixed. Legal, accounting, advisory, regulatory and travel expenses were incurred in Q3 2010 related to the property transactions.
Depletion expense is a function of volume produced as it is computed on a “units of production” basis.
Petroleum property costs of $4,483,115 are included in property, plant and equipment which includes $345,230 in asset retirement obligations and these costs were subjected to depletion. These properties include 190,437 bbls of proven reserves which is the volume base on which depletion is computed.
Probable reserves for the acquired property were significant and may include future locations. Under IFRS energy companies may choose this larger production basis for the computation of depletion. As probable reserves are determined based on a probability of recovery of 50% or more, this broader depletion base under IFRS will generate a more realistic estimate of real depletion.
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OUTLOOK
The Company continues to strengthen its financial position with stable production volumes, strong oil prices and control over costs as more wells are drilled, completed and brought into production and oil and gas drilling exploration is expanded in 2011.
The Company focuses on the production of conventional heavy oil, building on the core competency of its people, further acquisitions, exploration and development in the Lloydminster area (Lloydminster is a border city 250 km east of Edmonton, Alberta and 275 km west of Saskatoon, Saskatchewan). The Company is implementing careful control of development and field production costs.
On April 14, 2011, the Company announced that it had drilled, cased and completed the first well of the Company’s Blackfoot Phase 1- three (3) well (1.0 net well to the Company) drilling program on the Blackfoot heavy oil property in Lloydminster, Alberta. The well is located at 3D-11-050-02-W4 and is currently producing and the Company expects that once the well has stabilized, production rates will be comparable to that of surrounding heavy oil wells. The remaining two (2) Blackfoot Phase 1 wells on adjacent sections, are expected to be spudded after spring break-up. The Blackfoot Phase 1 – three (3) well program is scheduled to include drilling and completing three in-fill heavy oil wells at the following locations:3D-11-050-02-W4 (drilled, completed and on initial production), C6-24-050-02-W4 (not, participating) and C7-14-050-02-W4 (not participating).
On May 10, 2011, the Company announced that it had completed a property swap with a major Canadian oil producer resulting in the Company acquiring a 50% working interest in petroleum and natural gas rights, including one standing cased well, on 240 acres located in the Landrose area of Saskatchewan, located approximately 16 kilometres east of Lloydminster, Alberta in exchange for its 50% working interest on 320 acres (160 net acres) of undeveloped land located in the Golden Lake area of west central Saskatchewan.
On June 3, 2011, the Company announced that it had re-completed a standing cased well situated on its Landrose property, located in west central Saskatchewan. The re-completed well was recently acquired in a property swap with a major Canadian oil producer announced in the press release dated May 10, 2011.
On June 27, 2011, this well was brought into production at an average rate of 40 bbls/d (20 bbls/d net to the Company). In addition, the Company has identified six drill locations on the recently acquired Landrose properties. The Company expects to include at least three additional drilling locations from the Landrose properties in its 2011 drilling program. The Company’s Phase 3 drilling program is scheduled to consist of three wells which are anticipated to be drilled, completed and, if successful, on production by the end of August 2011.
During the six month period ended May 31, 2011, production was slowed due to extremely cold weather conditions. Several wells were off production for a portion of the harsh winter and were repaired or otherwise reactivated following break up. The Company was averaging approximately 86 bbls per day with an average price of $71 per bbl for the 2ndquarter ended May 31, 2011. The prices for heavy oil have increased with the estimated June price being $75 per bbl using the heavy oil price differentials. Unusually wet weather and seasonal maintenance at sales delivery points during the month of June may impact on sales volumes of the Company in the short term.
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MINERAL EXPLORATION PROPERTIES
The Company’s mineral exploration property assets consist of:
The Eldorado & Contact Lake IOCG & Uranium Properties:
The Company’s property interests consist of 32,598.70 ha (80,553.43 acres), situated in the Eldorado/Port Radium/Contact Lake area, McKenzie Mining District, NT. The Company is the first mineral exploration company in 75 years to successfully stake and control this large contiguous land package in the Northwest Territories.
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1. | Contact Lake Mineral Claims – Contact Lake, and North Contact Lake Mineral Claims – Great Bear Lake, NT |
During the year ended November 30, 2005, the Company acquired a 100% undivided right, title and interest, subject to a 1% net smelter return royalty (“NSR”), in five (5) mineral claims, totalling 1,801.82 ha (4,450.50 acres) located five miles southeast of Port Radium on Great Bear Lake, NT for cash payments of $60,000 (paid) and 60,000 common shares (issued and valued at $72,000) of the Company. The Company may purchase the NSR for a one-time payment of $1,000,000. The Company completed additional staking in the area in order to increase the project size to sixteen (16) contiguous claims, totalling 10,563.76 ha (26,103.52 acres). Collectively the properties are known as the Contact Lake Mineral Claims.
Expenditures related to the Contact Lake Mineral Claims for the six month period ended May 31, 2011 consist of amortization of $Nil (2010 - $25,164), camp costs and field supplies of $1,350 (2010 - $3,495), and claim maintenance and permitting of $4,749 (2010 - $4,739).
During the year ended November 30, 2006, the Company acquired a 100% right, interest and title, subject to a 2% NSR, in eleven (11) mineral claims (the “North Contact Lake Mineral Claims”), for cash payments of $75,000 and the issue of 50,000 common shares of the Company valued at $182,500. The Company may purchase one-half of the NSR for a one-time payment of $1,000,000. The North Contact Lake Mineral Claims are situated north of Contact Lake on Great Bear Lake approximately 680 km (423 miles) north of Yellowknife, NT, totalling 6,305.22 ha (15,580.48 acres).
There were no expenditures related to the North Contact Lake Mineral Claims for the six month period ended May 31, 2011 and May 31, 2010.
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| 2. | Port Radium – Glacier Lake Mineral Claims, NT |
During the year ended November 30, 2005, the Company acquired a 100% undivided right, title and interest, subject to a 2% NSR in four (4) mineral claims, totalling 2,520.78 ha (6,229.00 acres) (the “Glacier Lake Mineral Claims”) located one mile east of Port Radium on Great Bear Lake, NT, for cash payments of $30,000 (paid) and 72,000 common shares (issued and valued at $72,000) of the Company. The Company may purchase one-half of the NSR for a one-time payment of $1,000,000.
The property contains a fully operational all-season airstrip situated at Glacier Lake. The Echo Bay claim (produced 23,779,178 ounces of silver) and the Port Radium – Eldorado claim (produced 15 million pounds of uranium and 8 million ounces of silver). The Port Radium uranium belt was formerly one of Canada’s principal producers of uranium during the 1930s and 1940s.
Expenditures related to the Glacier Lake Mineral Claims for the six month period ended May 31, 2011 consist of amortization of $Nil (2010 - $3,275) and claim maintenance and permitting of $8,383 (2010 - $6,227).
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| 3. | Eldorado South Project, NT |
During the year ended November 30, 2007, the Company staked sixteen (16) claims (the “Eldorado South Uranium Mineral Claims”), and four (4) additional claims (the “Eldorado West Uranium Mineral Claims”)
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located ten miles south of Eldorado uranium mine on the east side of Great Bear Lake, NT and 680 km (423 miles) north of the city of Yellowknife, NT, collectively known as the Eldorado South Uranium Project. During the year ended November 30, 2009, the project area was reduced. The Eldorado South Uranium Project now consists of sixteen (16) mineral claims totaling 11,281.85 ha (27,878.62 acres).
The Eldorado South claims cover a radiometric anomaly that is over 3.5 kilometers in length and the expression suggests a potential near surface IOCG & uranium target. The radiometric maps show a well defined uranium anomaly with a marked correlation of strong thorium (Th) and potassium (k) ratio patterns. The Eldorado South Anomaly has never been drill tested. The Eldorado South Anomaly was discovered as a result of the completion of a High Resolution, Multi-Parameter Regional radiometric and magnetic geophysical survey which was conducted in July 2006. The survey consisted of 16,708 line-kilometers at 100 meter line-spacing’s. The purpose of the radiometric survey was to measure the gamma radiation field and locate prospective areas of high-grade uranium and poly-metallic deposition.
There were no expenditures related to the Eldorado South IOCG & Uranium Mineral Claims for the six month period ended May 31, 2011 and May 31, 2010.
INVESTOR RELATIONS
On December 20, 2010, the Company announced that it had retained MI3 Communications Financieres Inc. (“MI3”) as its investor relations and corporate communications service provider in Eastern Canada. MI3 has been retained for a period of one year, and will be responsible for the dissemination of corporate data packages, broker presentations and communications, analyst communications and handling of shareholder enquiries regarding the Company in Eastern Canada. MI3 will receive $5,000 (plus taxes) per month in remuneration and be reimbursed for all approved expenses. The Company has granted MI3 stock options to acquire 100,000 shares in the capital of the Company at an exercise price of $0.48.
MI3 is a full service investor relations firm based in Montreal, Quebec and headed by Mario Drolet. MI3 is a proactive results-driven firm that offers premium investor relations services to an international portfolio of client companies operating in a broad range of industries including oil & gas, mining and special situations. MI3 provides comprehensive investor relations representation to a wide and diverse Canadian audience through their offices in Montreal.
RESULTS OF OPERATIONS – SIX MONTH PERIOD ENDED MAY 31, 2011
The Company’s net loss for the six month period ended May 31, 2011 was $993,169 or $0.05 per share compared to a net loss of $1,129,042 or $0.05 per share for the six month period ended May 31, 2010. The significant changes during the current fiscal period compared to the same period a year prior are as follows:
Advertising and promotion expenses increased to $111,471 during the six month period ended May 31, 2011 from the $18,858 during the same period a year prior. The increase in advertising and promotion is primarily attributable to an increase in advertising costs and news release dissemination.
Filing and financing fees decreased to $32,475 for the six month period ended May 31, 2011 from $72,623 for the six month period ended May 31, 2010. The decrease in costs is attributed to a general decrease in fees associated with regulatory filings.
Legal and accounting fees decreased to $75,436 for the six month period ended May 31, 2011, from $115,079 for the six month period ended May 31, 2010. The legal and accounting fees were reduced from the previous year and were mainly for legal fees paid to the Company’s various legal counsels in Alberta, British Columbia and the Northwest Territories for general corporate matters.
Office and miscellaneous expenses for the six month period ended May 31, 2011 were reduced to $23,468 as compared to $51,346 in the prior year. The current year office expenses were less due to reduced office overhead associated with the exploration programs.
Salaries and benefits for the six month period ended May 31, 2011 were $270,565 as compared to $270,302 for the six month period ended May 31, 2010.
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Stock-based compensation expense totalling $217,751, a non-cash item, was incurred during the six month period ended May 31, 2011 on the granting of 910,000 stock options that vested during the period as compared to $22,890 for the six month period ended May 31, 2010.
Transfer fees and shareholder information costs decreased to $70,700 for the six month period ended May 31, 2011 from $153,803 for the six month period ended May 31, 2010. The decrease in transfer fees and shareholder information costs period over period is due mainly to a decrease in fees and number of consultants and analysts used for the Company’s investor relations and corporate development activities.
Travel expenses increased to $22,938 during the six month period ended May 31, 2011 from $11,838 during the same period a year prior. This was due to increased travel costs relating to the newly acquired oil and gas properties and production and drilling meetings with its working partners at the corporate offices in Lloydminister, Alberta.
Interest income increased to $31,815 for the six month period ended May 31, 2011, compared to $23,124 during the same period a year prior primarily due to higher realized interest rates.
There was a foreign exchange loss of $86,656 for the six month period ended May 31, 2011 based on the valuation of US$1,503,750 held in U.S. funds. This loss resulted as the Canadian dollar increased in value compared to the US dollar.
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MINERAL PROPERTY EXPENSES
Mineral property expenses comprise (1) exploration expenses, (2) acquisition costs, and (3) recoveries. Total expenditures for the periods ended May 31, 2011 and 2010 are summarized below:
| | | | |
| For the six month period ended May 31, 2011: | Exploration | Acquisition | Recoveries | Total |
| | Expenses | Costs | | |
| | $ | $ | $ | $ |
| Contact Lake Mineral Claims – Contact Lake, NT | 6,099 | - | - | 6,099 |
| Port Radium – Glacier Lake Mineral Claims, NT | 8,383 | - | - | 8,383 |
| | 14,482 | - | - | 14,482 |
| | | | |
| For the six month period ended May 31, 2010: | Exploration | Acquisition | Recoveries | Total |
| | Expenses | Costs | | |
| | $ | $ | $ | $ |
| Contact Lake Mineral Claims – Contact Lake, NT | 60,804 | - | - | 60,804 |
| Port Radium – Glacier Lake Mineral Claims, NT | 9,502 | - | - | 9,502 |
| Sterling Mining Property, Idaho, USA | 11,736 | - | - | 11,736 |
| | 82,042 | - | - | 82,042 |
Additional particulars of expenditures on mineral properties are provided in Note 7 to the financial statements for the six month period ended May 31, 2011.
SUMMARY OF QUARTERLY RESULTS
The following information is derived from the Company’s quarterly financial statements for the past eight quarters:
| | | |
| | | | Fully Diluted Loss per |
| Quarter Ended | Net Comprehensive Loss | Basic Loss per Share | Share |
| | | | |
| May 31, 2011 | $(312,860) | $(0.02) | $(0.02) |
| February 28, 2011 | $(680,309) | $(0.03) | $(0.03) |
| November 30, 2010 | $(800,082) | $(0.04) | $(0.04) |
| August 31, 2010 | $(77,535) | $(0.00) | $(0.00) |
| May 31, 2010 | $(490,301) | $(0.02) | $(0.02) |
| February 28, 2010 | $(638,741) | $(0.03) | $(0.03) |
| November 30, 2009 | $(679,571) | $(0.03) | $(0.03) |
| August 31, 2009 | $(1,300,073) | $(0.05) | $(0.05) |
The Company’s net loss of $1,300,073 for the third quarter ended August 31, 2009, is comprised of $478,590 of expenses relating to mineral properties expenditures and $855,513 of general and administrative costs, offset by $34,030 of interest income. Included in general and administrative costs are legal and accounting fees of $44,752 (August 31, 2008 - $35,430). Also included in general and administrative costs are transfer fees and shareholder information expenses of $48,541 (August 31, 2008 - $105,642) relating to ongoing investor relations and services.
The Company’s net loss of $679,571 for the fourth quarter ended November 30, 2009, is comprised of $189,698 of expenses relating to mineral properties expenditures and $522,986 of general and administrative costs, offset by $32,823 of interest income. Included in general and administrative costs are legal and accounting fees of $158,322 that were incurred for the February 8, 2010 annual general meeting. Also included in general and administrative costs are transfer fees and shareholder information expenses of $88,812 relating to ongoing investor relations and services relating to the annual general meeting.
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The Company’s net loss of $638,741 for the first quarter ended February 28, 2010, is comprised of $37,192 of expenses relating to mineral properties expenditures and $622,234 of general and administrative costs, offset by $20,685 of interest income. Included in general and administrative costs are consulting fees of $100,525 of which $65,625 was paid to various consultants engaged in the evaluation of potential mineral projects and $34,900 was paid for services relating to the annual general meeting. Also included in general and administrative costs are transfer fees and shareholder information expenses of $104,092 relating to ongoing investor relations.
The Company’s net loss of $490,301 for the second quarter ended May 31, 2010, is comprised of $44,850 of expenses relating to mineral properties expenditures and $447,890 of general and administrative costs, offset by $2,439 of interest income. Included in general and administrative costs are consulting fees of $29,413 which were paid to various consultants engaged in the evaluation of potential mineral projects. Also included in general and administrative costs are transfer fees and shareholder information expenses of $49,706 relating to ongoing investor relations. Legal and accounting costs were $85,132 primarily due to the Company’s unsuccessful bid to acquire the shares of the Sterling Mining Company.
The Company’s net loss of $77,535 for the third quarter ended August 31, 2010, is comprised of $5,688 of expenses relating to mineral properties expenditures, $4,874 in petroleum royalties, $31,505 in petroleum production and transportation, $22,671 in petroleum depletion and accretion and $325,127 of general and administrative costs, offset by $2,234 interest income and $256,975 compensation fee. Included in general and administrative costs are consulting fees of $38,205 which were paid to various consultants engaged in the evaluation of potential mineral projects. Also included in general and administrative costs are transfer fees and shareholder information expenses of $53,000 relating to ongoing investor relations. Legal and accounting costs of $18,868 were related to the acquisition of the oil and gas interests in Alberta and Saskatchewan.
The Company generated oil and gas revenues of $53,121 for one month from the August 9, 2010 acquisition as pre-acquisition earnings are an adjustment to the purchase price. The Company recovered Cdn$256,975 (US$250,000) as a compensation break fee on its unsuccessful bid to acquire the shares of the Sterling Mining Company in the current quarter
The Company’s net loss of $800,082 for the fourth quarter ended November 30, 2010, is mainly comprised of $220,870 of expenses relating to the one time write down of field, camp and exploration equipment in mineral properties expenditures, and general and administrative expenses of $516,823. The Company generated oil and gas revenues of $371,265 for the four month period from the August 1, 2010 to November 30, 2010 and contributed an operating net back of $148,199.
The Company’s net loss of $680,309 for the first quarter ended February 28, 2011, is mainly comprised of $209,870 of expenses relating to the non cash stock-based compensation on the granting of stock options and general and administrative expenses of $388,600. The Company generated oil and gas revenues of $516,359 for the three month period ended February 28, 2011 and contributed an operating net back of $222,289.
The Company’s net loss of $312,860 for the second quarter ended May 31, 2011, is mainly comprised of $52,989 of net petroleum income and general and administrative expenses of $368,335. The Company generated oil and gas revenues of $576,339 for the three month period ended May 31, 2011 and contributed an operating net back of $301,177. After deducting the depletion and accretion expense of $248,188, the Company realized net petroleum income of $52,989.
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LIQUIDITY AND CAPITAL RESOURCES
The Company began recognizing and receiving revenue from its oil and gas resource properties as of August 1, 2010. The Company also relies on equity financing as well as the exercise of options and warrants to fund its exploration and administrative costs.
The Company’s cash resources are invested in R1-High bankers acceptance notes and redeemable Canadian Guaranteed Investment Certificates on deposit with an AAA rated Canadian Banking Institution. None of the Company’s funds are exposed to repayment risks associated with short term commercial paper or asset-backed commercial paper. These securities comply with the Company’s strict investment criteria and policy of utilizing only R1-High Investment Guaranteed Instruments that are paid promptly on maturity or are convertible on demand.
As at May 31, 2011, the Company had cash and cash equivalents on its balance sheet of $8,422,503 and working capital of $7,208,527 as compared to $9,456,219 of cash and cash equivalents and working capital of $8,025,748 at November 30, 2010. The reduction in cash and cash equivalents of $1,033,716 was due to cash used in operations and $531,125 that was used to acquire interests in oil and gas resource properties.
The Company established a credit facility agreement with a Canadian chartered bank, consisting of a revolving operating facility of $800,000 with an interest rate of bank prime plus 1.5%, and a development facility of $300,000 with an interest rate of bank prime plus 2.0%. The Company has not yet drawn on either credit facility.
Total assets at May 31, 2011 decreased to $12,650,886 from $13,605,905 at November 30, 2010, primarily as a result of general and administrative expenses.
As of the date of this report the Company has cash and cash equivalents of approximately $8,400,000. The Company believes that this is sufficient to fund its currently planned exploration and administrative budget through the balance of fiscal 2011.
A $2,500,000 capital budget has been approved for 2011, of which approximately $2,100,000 is budgeted for drilling, completing and equipping an estimated 10 - 12 wells (5 - 6 net to the Company) in Alberta and Saskatchewan. The budget also includes facilities investments, primarily in Saskatchewan which will optimize new production while improving existing production efficiencies.
CONTINGENCIES
The Company is aware of no contingencies or pending legal proceedings as of July 22, 2011.
OFF-BALANCE SHEET ARRANGEMENTS
The Company has no off-balance sheet arrangements.
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TRANSACTIONS WITH RELATED PARTIES
The Company’s Board of Directors consists of Tim Coupland, Brian Morrison, Edward Burylo, Robert Hall and Stuart Rogers. Tim Coupland is the Company’s President and Chief Executive Officer and Gord Steblin is the Company’s Chief Financial Officer.
The Company paid or accrued amounts to related parties as follows:
| | |
| | For the Six Month |
| | Period Ended |
| | May 31, | May 31, |
| | 2011 | 2010 |
| Management fees paid to a company controlled by Tim Coupland | - | 50,000 |
| Management fees paid to a company controlled by Robert Hall | - | 15,000 |
| Accounting fees paid to a company controlled by Gord Steblin | 37,500 | 43,000 |
| Secretarial fees paid to a company controlled by Tamiko Coupland | - | 15,000 |
| Director fees paid to a company controlled by a Stuart Rogers | 1,000 | 21,000 |
| Director fees paid to Brian Morrison | 1,000 | 21,000 |
| Director fees paid to Edward Burylo | 1,000 | 21,000 |
| Salaries and benefits paid to directors and/or officers of the Company | 270,565 | 270,302 |
| | $311,065 | $456,302 |
These transactions were in the normal course of operations and were measured at the exchange value which represented the amount of consideration established and agreed to by the related parties.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Company’s financial statements requires management to make estimates and assumptions regarding future events. These estimates and assumptions affect the reported amounts of certain assets and liabilities, and disclosure of contingent liabilities.
Significant areas requiring the use of management estimates include the determination of impairment of equipment, environmental and reclamation obligations, rates for amortization and variables used in determining stock-based compensation. These estimates are based on management’s best judgment. Factors that could affect these estimates include risks inherent in mineral exploration and development, changes in reclamation requirements, changes in government policy and changes in foreign exchange rates.
Management has assessed the carrying value of its assets and does not believe the remaining assets have suffered any impairment.
The Company does not believe it has incurred any material environmental liabilities to date. The Company has the responsibility to perform reclamation in certain jurisdictions upon completion of drilling. The costs to complete this reclamation are immaterial and are expensed when incurred.
Management has made significant assumptions and estimates in determining the fair market value of stock-based compensation granted to employees and non-employees and the value attributed to various warrants and broker warrants issued on financings. These estimates have an effect on the stock-based compensation expense recognized and the contributed surplus and share capital balances on the Company’s balance sheet. Management has made estimates of the life of stock options and warrants, the expected volatility and expected dividend yields that could materially affect the fair market value of these types of securities. The estimates were chosen after reviewing the historical life of the Company’s options and analyzing share price history to determine volatility.
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CHANGES IN ACCOUNTING POLICIES
Revenue recognition of petroleum and natural gas properties
Effective July 1, 2010, the Company adopted the following accounting policy to account for its petroleum resource properties.
Revenue from the production of crude oil and natural gas is recognized when title passes to the customer, delivery has taken place and collection is reasonably assured. The Company assesses customer creditworthiness, both before entering into contracts and throughout the revenue recognition process.
Revenue as reported represents the Company’s share and is presented before royalty payments to governments and other mineral interest owners.
Related costs of goods sold are comprised of production; transportation and blending; and depletion, depreciation and amortization expenses. These amounts have been separately presented in the statements of loss, comprehensive loss and deficit.
Petroleum and natural gas properties
Effective July 1, 2010, the Company adopted the following accounting policy to account for its petroleum resource properties.
The Company follows the full cost method of accounting for petroleum and natural gas operations whereby all costs related to the exploration and development of petroleum and natural gas reserves are capitalized. These costs include land acquisition costs, geological and geophysical expenses, the costs of drilling both productive and non-productive wells, directly related overhead and estimated abandonment costs. Proceeds from the disposal of properties are deducted from the full cost pool without recognition of a gain or loss unless such a sale would significantly alter the rate of depletion and depreciation.
Depletion and depreciation of petroleum and natural gas properties
Effective July 1, 2010, the Company adopted the following accounting policy to account for its petroleum resource properties.
Depletion of petroleum and natural gas properties is provided using the unit-of-production method based on production volumes before royalties in relation to total estimated proved reserves as determined annually by independent engineers and determined in accordance with National Instrument 51-101. Natural gas reserves and production are converted at the energy equivalent of six thousand cubic feet to one barrel of oil.
Calculations for depletion and depreciation of production equipment are based on total capitalized costs plus estimated future development costs of proved undeveloped reserved. The costs of acquiring and evaluating unproved properties are excluded from depletion calculations. These properties are assessed periodically to ascertain whether impairment has occurred. When the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion.
Ceiling Test
Effective July 1, 2010, the Company adopted the following accounting policy to account for its petroleum resource properties.
The Company reviews the carrying amount of its petroleum and natural gas properties relative to their recoverable amount at each annual balance sheet date or more frequently if circumstances or events indicate impairment may have occurred. The recoverable amount is calculated as the undiscounted cash flow from the properties using proved reserves and expected future prices and costs. If the carrying amount of the properties exceeds their recoverable amount, an impairment loss is recognized in depletion and depreciation expense equal to the amount by which the carrying amount of the properties exceeds their fair
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value. Fair value is calculated as the cash flow from those properties using proved and probable reserve and expected future prices and costs, discounted at a risk-free interest rate.
International Financial Reporting Standards (“IFRS”)
In January 2006, the Canadian Accounting Standards Board adopted a strategic plan, which includes the decision to move financial reporting for Canadian publicly accountable enterprises to a single set of globally accepted standards, IFRS, as issued by the International Accounting Standards Board. The effective implementation date of the conversion from Canadian generally accepted accounting principles (“Canadian GAAP”) to IFRS is December 1, 2011, with an effective transition date of December 1, 2010 for financial statements prepared on a comparative basis. The Company is engaged in an assessment and conversion process which includes consultation with external consulting firms. The Company’s approach to the conversion to IFRS includes three phases.
Phase one, an initial general diagnostic of its accounting policies and Canadian GAAP relevant to its financial reporting requirements to determine the key differences and options with respect to acceptable accounting standards under IFRS. This phase was completed in late 2009.
Phase two, an in-depth analysis of the IFRS impact in those areas identified under phase one. During 2010, the Company substantially completed assessing and quantifying IFRS transition adjustments. The Company’s auditors are in the process of completing their review of these adjustments. A summary of this analysis is provided in Table 2 below.
Phase three, the implementation of the conversion process, including the completion of the opening balance sheet as at December 1, 2010 together with related discussion and notes, has commenced. Preliminary drafts of financial statement disclosures have been prepared in order to ensure systems are in place to collect the necessary data; to date no significant changes to current procedures have been identified.
The Company’s IT accounting and financial reporting systems are not expected to be significantly impacted.
The above comments, including the summary in Table 2, should not be considered as a complete and final list of the changes that will result from the transition to IFRS as the Company intends to maintain a current and proactive approach based on changes in circumstances and no final determinations have been made. IFRS standards, and the interpretation thereof, are constantly evolving. As a result, the Company expects there may be new or revised IFRS accounting standards prior to the issuance of its first IFRS financial statements. The Company is continuing to monitor IFRS accounting developments and updates and will assess their impact in the course of its transition process to IFRS.
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Table 2. Summary of financial statements impact on transition from Canadian GAAP to IFRS.
| | | |
| Key Area | Canadian GAAP
(as currently applied) | IFRS | Analysis and preliminary
conclusions |
|
| Property, plant | PP&E is recorded at | PP&E can be recorded using the | PP&E will continue to be recorded |
| and equipment | historical cost. | cost (on transition to IFRS, the | at their historical costs due to the |
| (“PP&E”) | | then fair value can be deemed to | complexity and resources required |
| | | be the cost) or revaluation | to determine fair values on an |
| | | models. | annual basis. |
| | | | |
| | Depreciation is based on | Depreciation must be based on | Based on an analysis of PP&E and |
| | their useful lives after due | the useful lives of each | its significant components, the |
| | estimation of their residual | significant component within | Company has determined that no |
| | values. | PP&E. | change to their useful lives is |
| | | | warranted and, therefore, |
| | | | depreciation expense will continue |
| | | | to be calculated using the same |
| | | | rates under IFRS. |
| | | | |
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| | | |
| Key Area | Canadian GAAP
(as currently applied) | IFRS | Analysis and preliminary
conclusions |
|
| Mineral | Exploration costs and | IFRS 6 provides the Company | The existing accounting policy will |
| properties | option maintenance | with the option of expensing the | be maintained. |
| | payments are expensed as | exploration and evaluation costs | |
| | incurred. If proven and | as incurred, or deferring these | |
| | probable reserves are | costs until technical feasibility | |
| | established, costs incurred | and commercial viability has | |
| | prospectively to develop | been determined, at which point | |
| | the property are | they are transferred to the | |
| | capitalized as incurred and | development and production | |
| | depreciated using the unit- | phase and allocated to specific | |
| | of-production depreciation | projects. | |
| | method over the estimated | | |
| | life of the ore body. | | |
| | | | |
| Asset | Canadian GAAP limits the | IFRS defines ARO as legal or | The broadening of this definition |
| retirement | definition of ARO to legal | constructive obligations. | will not cause a significant change |
| obligations | obligations. | | in the Company’s current |
| (“ARO”) | | | estimates. |
| | | | |
| | ARO is calculated using a | ARO is calculated using a | The Company expects to record a |
| | current credit-adjusted, | current pre-tax discount rate | transition adjustment. In |
| | risk-free rate for upward | (which reflects current market | accordance with IFRIC 1, the |
| | adjustments, and the | assessment of the time value of | effect of any changes to an existing |
| | original credit-adjusted, | money and the risk specific to | ARO as a result of changes in |
| | risk-free rate for | the liability) and is revised every | market interest rates is added to or |
| | downward revisions. The | reporting period to reflect | deducted from the cost of the |
| | original liability is not | changes in assumptions or | related asset. |
| | adjusted for changes in | discount rates. | |
| | current discount rates. | | |
| | | | |
| | | IFRS requires that, on transition, | The Company will rely on the |
| | | the net book value of the asset | IFRS 1 exemption which allows a |
| | | related to ARO be adjusted on | company to use current estimates |
| | | the basis of the ARO balance | of future reclamation costs and |
| | | existing at inception. | current amortization rates to |
| | | | determine the net book value on |
| | | | transition to IFRS. |
| | | | |
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| | | |
| Key Area | Canadian GAAP
(as currently applied) | IFRS | Analysis and preliminary
conclusions |
|
| Stock-based | The Company recognizes | Under IFRS, stock-based | The Company is in the process of |
| compensation | stock-based compensation | compensation is amortized | quantifying the difference. |
| | on straight line method and | under the graded method only. | |
| | updates the value of the | In addition, the Company is | |
| | options for forfeitures as | required to update its value of | |
| | they occur. | options for each reporting | |
| | | period for expected forfeitures. | |
| | | | |
| | The Company included | IFRS does not preclude the | The Company does not intend to |
| | stock-based compensation | Company from recognizing a | transfer stock-based compensation |
| | in contributed surplus and | transfer of compensation costs | expense included in contributed |
| | previously recognized | within equity (i.e. from | surplus to another component of |
| | compensation cost is not | contributed surplus to deficit) | equity. |
| | reversed if a vested | after vesting. | |
| | employee stock option | | |
| | expires unexercised. | | |
| | | | |
| Income taxes | There is no exemption | A deferred income tax is not | The Company does not expect the |
| | from recognizing a | recognized if it arises from the | difference in recognition of |
| | deferred income tax for the | initial recognition of an asset or | deferred income tax to have any |
| | initial recognition of an | liability in a transaction that is | significant change in the future. |
| | asset or liability in a | not a business combination, and | |
| | transaction that is not a | at the time of the transaction | |
| | business combination. The | affects neither accounting profit | |
| | carrying amount of the | nor taxable profit. | |
| | asset or liability acquired is | | |
| | adjusted for the amount of | | |
| | the deferred income tax | | |
| | recognized. | | |
| | | | |
| | All deferred income tax | A deferred tax asset is | “Probable” in this context is not |
| | assets are recognized to the | recognized if it is “probable” | defined and does not necessarily |
| | extent that it is “more | that it will be realized. | mean “more likely than not”. |
| | likely than not” that the | | However, the Company does not |
| | deferred income tax assets | | expect this difference to have any |
| | will be realized. | | impact in the future. |
| | | | |
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The above assessment and conclusions are based on the analysis completed by the Company as of the date of this report and may be subject to change.
The quantification of the amounts that resulted from the differences between Canadian GAAP and IFRS relating to the key standards are based on management’s estimates and decisions, and are subject to further internal review and audit by the Company’s external auditors.
FINANCIAL INSTRUMENTS AND OTHER INSTRUMENTS
Fair value - The fair value of cash and cash equivalents, amounts receivable and accounts payable and accrued liabilities approximates their carrying value due to the short-term nature of these financial instruments.
Exchange risk - The Company operates solely in Canada and therefore is subject to minimal foreign currency risk arising from changes in exchange rates with other currencies.
Interest rate risk - The Company is exposed to interest rate risk on its short-term investments, but this risk relates only to investments held to fund future activities and does not affect the Company’s current operating activities.
Credit risk - The Company places its temporary investment funds with government and bank debt securities and is subject to minimal credit risk with regard to temporary investments.
The Company does not have any risk associated with “other instruments”; that is, instruments that may be settled by the delivery of non-financial assets.
RISKS AND UNCERTAINTIES
The Company believes that the following items represent significant areas for consideration.
Cash Flows and Additional Funding Requirements
The Company has limited financial resources, some operating cash flows from its oil and gas properties and no assurances that sufficient funding, including adequate financing, will be available. If the Company’s exploration programs are successful, additional funds will be required in order to complete the development of its properties. The sources of funds currently available to the Company include; raising equity or debt capital, or offering an interest in its projects to another party. There is no assurance that the Company will be successful in raising sufficient funds to conduct further exploration and development of its projects or to fulfill its obligations under the terms of any option or joint venture agreements, in which case the Company may have to delay or indefinitely postpone further exploration and development, or forfeit its interest in its properties or prospects.
Industry
The Company is engaged in the exploration of mineral and oil and gas properties, an inherently risky business. There is no assurance that funds spent on the exploration and development of a mineral deposit or oil and gas well will result in the discovery of an economic ore body or producing oil well. Most exploration projects do not result in the discovery of commercially mineable ore deposits.
The business of exploration, development and acquisition of oil and gas reserves involves a number of business risks inherent in the oil and gas industry which may impact the Company’s results and several of which are beyond control of the Company. These business risks are operational, financial or regulatory in nature. The Company does not use derivative instruments as a means to manage risk.
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Commodity Prices
The profitability of the Company’s operations will be dependent upon the market price of oil, gas and mineral commodities. Oil, gas and mineral prices fluctuate widely and are affected by numerous factors beyond the control of the Company. The prices of oil, gas and mineral commodities have fluctuated widely in recent years. Current and future price declines could cause commercial production to be impracticable. The Company’s revenues and earnings also could be affected by the prices of other commodities such as fuel and other consumable items, although to a lesser extent than by the price of oil, gas and mineral commodities.
Competition
The oil, gas and mining industries are intensely competitive in all of its phases, and the Company competes with many companies possessing greater financial resources and technical facilities than itself with respect to the discovery and acquisition of interests in oil, gas and mineral properties, the recruitment and retention of qualified employees and other persons to carry out its exploration activities. Competition in the oil, gas and mining industry could adversely affect the Company’s prospects for exploration in the future.
Government Laws, Regulation & Permitting
Oil, gas and mining and exploration activities of the Company are subject to domestic laws and regulations governing prospecting, development, production, taxes, labour standards, occupational health, mine safety, waste disposal, toxic substances, the environment and other matters. Although the Company believes that all exploration activities are currently carried out in accordance with all applicable rules and regulations, no assurance can be given that new rules and regulations will not be enacted or that existing rules and regulations will not be applied in a manner which could limit or curtail production or development. Amendments to current laws and regulations governing the operations and activities of the Company or more stringent implementation thereof could have a substantial adverse impact on the Company.
The operations of the Company will require licenses and permits from various governmental authorities to carry out exploration and development at its projects. There can be no assurance that the Company will be able to obtain the necessary licences and permits on acceptable terms, in a timely manner or at all. Any failure to comply with permits and applicable laws and regulations, even if inadvertent, could result in the interruption or closure of operations or material fines, penalties or other liabilities.
Title to Properties
Acquisition of rights to the oil, gas and mineral properties is a very detailed and time-consuming process. Title to, and the area of, oil, gas and mineral properties may be disputed. To the best of the Company’s knowledge, the Company has title to all of the properties for which it holds mineral leases or licenses or in respect of which it has a right to earn an interest, however, the Company cannot give an assurance that title to such properties will not be challenged or impugned.
The Company has the right to earn an increased interest in some of its properties. To earn this increased interest in each property, the Company is required to make certain cash payments. If the Company fails to make these payments, the Company may lose its right to such properties and forfeit any funds expended to such time.
Estimates of Oil, Gas and Mineral Resources
The oil, gas and mineral resource estimates used by the Company are estimates only and no assurance can be given that any particular level of recovery of oil, gas or minerals will in fact be realized or that an identified resource will ever qualify as a commercially mineable (or viable) deposit which can be legally or commercially exploited. In addition, the grade of mineralization ultimately mined may differ from that indicated by drilling results and such differences could be material.
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Key Management
The success of the Company will be largely dependent upon the performance of its key officers, consultants and employees. Locating oil and gas resources and mineral deposits depends on a number of factors, not the least of which is the technical skill of the exploration personnel involved. The success of the Company is largely dependent on the performance of its key individuals. Failure to retain key individuals or to attract or retain additional key individuals with necessary skills could have a materially adverse impact upon the Company’s success.
Volatility of Share Price
Market prices for shares of early stage companies are often volatile. Factors such as announcements of mineral discoveries, financial results, and other factors could have a significant effect on the price of the Company’s shares.
Conflict of Interest
Some of the Company’s directors and officers are directors and officers of other natural resource or mining-related companies. These associations may give rise from time to time to conflicts of interest. As a result of such conflicts, the Company could potentially miss the opportunity to participate in certain transactions or opportunities.
SHARE DATA
As of July 22, 2011, the Company has 21,403,979 common shares without par value issued and outstanding. In addition, the Company has 2,090,000 incentive stock options (“Options”) outstanding. Each Option entitles the holder to receive one common share upon its exercise. Of the Options, 410,000 are exercisable at $1.75 each, 770,000 are exercisable at $1.00 each and 910,000 are exercisable at $0.48.
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