Exhibit 99.1
2003 ANNUAL REPORT
Corporate Profile
Luke Energy Ltd. is an emerging oil and gas company based in Calgary and operating in Western Canada.
The Company’s business plan is to grow through a combination of internally generated low to medium risk drilling opportunities and strategic acquisitions with exploitation potential.
Luke Energy had a reserve base at December 31, 2003 of 300,000 barrels of oil and 2.1 billion cubic feet of gas for a total of 658,000 barrels of oil equivalent. Production volumes during 2003 averaged 152 boe per day and were weighted 58% to oil. In addition, the Company held an average 81% interest in 20,500 gross acres.
During its first year the Company arranged financing, assembled people and commenced operations. At year-end Luke Energy had $35 million in working capital, no debt and 34.8 million common shares outstanding. The Company’s shares are listed on the Toronto Stock Exchange under the symbol “LKE”.
Annual Meeting
Luke Energy invites its shareholders and other interested parties to attend the Company’s Annual Meeting on Wednesday, May 19th at 3:00 p.m. in the Viking Room of the Calgary Petroleum Club, 319 - 5th Avenue S.W., Calgary, Alberta.
TSE Listed : LKE
| Contents | ||||
| Highlights | 1 | |||
| Report to Shareholders | 2 | |||
| Operations Overview | 4 | |||
| Management’s Discussion and Analysis | 9 | |||
| Financial Statements | 17 | |||
| Notes to Financial Statements | 22 | |||
Abbreviations
| bbls | barrels |
| mbbls | thousand barrels |
| mmbbls | million barrels |
| bbls/d | barrels per day |
| bopd | barrels of oil per day |
| mcf | thousand cubic feet |
| mmcf | million cubic feet |
| bcf | billion cubic feet |
| mcf/d | thousand cubic feet per day |
| mmcf/d | million cubic feet per day |
| ngls | natural gas liquids |
| boe | barrels of oil equivalent (6 mcf=1 bbl) |
| boepd | barrels of oil equivalent per day |
Highlights
| Period ended | ||||
| December 31, 2003 | ||||
Operating1 | ||||
| Number of producing days | 309 | |||
| Production | ||||
| Oil – bopd | 88 | |||
| Gas – mcf/d | 380 | |||
Total – boepd (6 mcf = 1 bbl) | 152 | |||
| Product Prices ($Cdn) | ||||
| Oil – $/bbl | $ | 35.08 | ||
| Gas – $/mcf | $ | 6.47 | ||
| Reserves | ||||
| Oil – mbbls | 300 | |||
| Gas – mmcf | 2,138 | |||
| Total – mboe | 658 | |||
| Present value, discounted @ 10% ($000’s) | $ | 6,588 | ||
| Undeveloped lands | ||||
| Net acres | 16,600 | |||
Financial ($Cdn except per share numbers)1 | ||||
| Gross production revenue | $ | 1,715,620 | ||
Cash flow from operations2 | $ | 1,374,948 | ||
| per share – basic and diluted | $ | 0.05 | ||
| Earnings | $ | 583,296 | ||
| per share – basic and diluted | $ | 0.02 | ||
| Weighted average shares outstanding | 29,759,428 | |||
| Shares outstanding | 34,828,949 | |||
| Capital expenditures | $ | 4,834,865 | ||
| Working capital | $ | 35,026,238 | ||
| Shareholders’ equity | $ | 42,814,715 | ||
| 1 | There are no comparative numbers as the Company began operations February 26, 2003. |
| 2 | Cash flow from operations reflects earnings plus future taxes, stock option expense, and depletion, depreciation and accretion. |
| 1 | ||
Report to Shareholders
[Picture ofHarold V. Pedersen - Chief Executive Officer]
This is Luke Energy Ltd.’s first annual report which covers its start-up year.
In our first year we focused mainly on creating the Company, arranging financing, assembling people, and commencing operations. With those key elements now firmly in place we have created a cash rich start-up company with a strong management and technical team which is now fully operational.
A summary of the key highlights follows.
Creation of the Company
Luke Energy was created in February of 2003 in conjunction with the sale of KeyWest Energy Corporation (our former company) to Viking Energy Trust. KeyWest shareholders received one share of Luke Energy for every 10 shares they held in KeyWest. As part of the transaction, Viking agreed to roll average daily production of 150 boe and 100% in 11,720 acres of undeveloped land into Luke Energy. As a result, Luke Energy qualified for a Toronto Stock Exchange listing.
Financing
Three successful financings were completed during 2003 which collectively netted the Company $38.5 million.
The initial financing raised $1.3 million in startup capital through the sale to Company insiders of 1.6 million shares at 81 cents per share.
A subsequent major financing in March raised net proceeds of $33.8 million. A total of 24.8 million shares were sold at $1.45 per share and insiders subscribed for 10% of the issue.
Finally, a September financing netted $3.4 million for the Company’s account. Insiders bought 50% of the1.8 million shares which were issued at $2.00 per share on a “tax-flow through” basis.
People
A strong technical team has now been assembled to complement Luke Energy’s experienced senior executives: our Chairman Hugh Mogensen, Chief Executive Officer Harold Pedersen, and President Mary Blue have worked together for more than 20 years and are reunited in this, their fourth start-up.
Heading up the geological team is Rob Wollmann, Vice-President of Exploration. He is joined by two geologists, Terry Fullerton (Chief Geologist) and Kevin Mottershead.
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The engineering group is led by Kevin Lee, Vice-President, Engineering. Assisting him are Edward Ostrowski, Senior Exploitation Engineer and Ruth DeGama, Manager of Production Services.
The land department is headed up by Peter Abercrombie, Vice-President, Land. Our Vice-President of Finance and CFO is Carrie McLauchlin who has rejoined us from KeyWest Energy.
Operations
The Company’s near-term growth strategy is to focus on generating new drilling prospects while continuing to review potential corporate and property acquisitions.
Luke’s “grass roots” prospect generation has already resulted in the establishment of the Company’s first core area at Marten Creek in Northern Alberta where the target is shallow multi-zone gas in the Cretaceous. A multi-well drilling program was initiated prior to year-end. Subsequently a total of ten wells were drilled resulting in eight successful gas wells for an 80% success rate. Initial production from this winter work area began on a restricted basis in mid March and will gradually increase in the coming weeks.
Our exploration group has also identified a new multi-zone oil and gas prospect area in Northeastern British Columbia. We are currently acquiring land and seismic with a view to potential drilling in late summer.
Outlook
We are enthusiastic about Luke Energy’s prospect-generating possibilities in the upcoming year. Our strong geological staff is demonstrating its ability to generate real value on a reasonable cost basis. Our engineering group will continue to evaluate prospective purchases, however recent high prices being paid by Canadian energy trusts are limiting the economic value of most production purchases. Commodity prices are strong and are expected to remain so. Continued uncertainty in the Middle East and increasing demand world wide is expected to keep oil prices high. Natural gas prices are also expected to remain strong as the American economy continues to improve.
We are grateful to our Board of Directors for their enthusiastic support and counsel over the past year. All were directors of our previous company and some have been with us through each of our three previous ventures as well. We also thank our shareholders without whose support none of this would be possible.
Respectfully Submitted
On Behalf of the Board of Directors,
-s-Harold V. Pedersen
Harold V. Pedersen
Chief Executive Officer
March 17, 2004
| 3 | ||
Operations Overview
[Picture ofMary C. Blue - President & COO]
Management plans to maintain the same growth and operating strategy which has proven successful in its past three companies.
Luke Energy’s business plan is to grow through a combination of internally generated low to medium risk drilling opportunities and strategic acquisitions with exploitation potential.
The Company’s operating strategy may be summarized as follows:
| u | Develop core-operating areas in Western Canada |
| u | Focus on quality oil and gas properties |
| u | Maintain operatorship and high interests |
| u | Maintain a low finding and operating cost structure |
[Production MAP -Marten Creek, Northern Alberta]
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[Picture ofRob Wollmann - Vice-President Exploration]
Prospect Review
Marten Creek, Northern Alberta
Marten Creek is a relatively shallow (1,925 feet) multi-zone Cretaceous natural gas prospect located about 150 miles north of the City of Edmonton and it is 100% owned and operated by Luke Energy. This is a “grass roots” full cycle exploration project initiated by Luke’s geological team in mid 2003. During the year the Company purchased and shot about 325 miles of 2D seismic data in the Marten Creek area. Subsequently, Luke acquired some 11,000 acres of land for its 100% account to capitalize on a number of prospective leads identified on the seismic data. A drilling program was initiated just prior to year-end and a total of ten wells were drilled during the course of the winter work season. The program resulted in eight successful gas wells for an 80% success rate.
Well testing was carried out in February and early March of 2004 with encouraging results. Individual wells tested at restricted rates of 500 mcf/d to over 2.5 mmcf/d from multiple Cretaceous zones. The reserve potential for the project is attractive, averaging 1 to 2 bcf of gas per well. Costs to drill, complete and tie-in a well are in the order of $550,000 reflecting the higher costs associated with winter access. Pipelines together with a field compressor were constructed to tie the wells into a nearby main line which is owned by a mid-stream processor. Construction in this winter work area was substantially completed by March 15th which was the start of spring breakup. Initial gas production from the area has commenced on a restricted basis and will be gradually increased over the course of several weeks.
This rapidly developing project is Luke Energy’s first core property. The Company will continue to expand its position in the area and a second multi-well drilling program is planned for next winter.
[Picture of Peter W. Abercombie - Vice-President Land]
Land
As part of Luke Energy’s formation, Viking Energy Trust rolled 100% interest in11,720 acres into the new entity. The majority of this acreage block was subsequently farmed out.
Luke Energy was an active participant at Crown land sales in the latter half of 2003. The Company focused on establishing an acreage position in Marten Creek – its new gas exploration area in Northern Alberta. As a result, Luke Energy’s undeveloped land inventory at year-end increased to an average 81% interest in 20,500 gross undeveloped acres (16,600 net).
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[Picture of Kevin Lee - Vice-President Engineering]
At December 31, 2003, the Company’s lands were valued at $2.9 million by Seaton-Jordan Associates Ltd., an independent land consulting firm. This is up from the $1.0 million attributed to Luke Energy’s lands in the Seaton-Jordan report of a year ago.
Luke will continue to aggressively build its undeveloped land inventory in 2004, both in Marten Creek and in new project areas being developed by the Company’s exploration team.
Drilling
Just prior to year-end Luke Energy drilled the first well in the Company’s 10 well drilling program on its 100%-owned Marten Creek project. The well was completed in early January and subsequently tested gas at 1.5 million cubic feet per day on a restricted basis.
In addition, during 2003 the Company granted a third party the right to drill two wells to earn an interest in lands owned by Luke in Western Alberta. One well was successfully completed as a Baldonnel gas well. Luke retains a royalty on production until the well achieves payout and will be entitled to a 26% share of production thereafter.
Reserves
Luke Energy’s reserves were evaluated effective January 1, 2004 by the independent engineering firm of Gilbert Laustsen Jung Associates Ltd., one of the leading reserve evaluation firms in Canada. The Company reserves were evaluated in accordance with National Instrument 51-101.
The Company’s proven oil and gas reserves were up 5% at year-end. Decreases in the Company’s gas reserves bookings at Bassano were offset by new gas reserves attributed to a farmout well at Spirit River and higher oil bookings at Bashaw.
Total proven and probable oil and gas reserves increased 37% as a result of new probable gas reserves added on a farmout well at Spirit River and the Company’s first drilled well at Marten Creek.
On a proven basis the Company replaced 145% of its production. Based on proven and probable reserves the Company replaced 477% of 2003 production.
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Oil and Gas Reserves
Light Oil & NGLs | Gas | BOE1 | |||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||
| January 1, 2004 | mbbls | mbbls | mmcf | mmcf | mboe | mboe | |||||||||||||
| Proven Reserves | |||||||||||||||||||
Producing | 267 | 203 | 563 | 481 | 361 | 283 | |||||||||||||
Non-Producing | – | – | 448 | 357 | 75 | 60 | |||||||||||||
| Total Proven | 267 | 203 | 1,011 | 838 | 436 | 343 | |||||||||||||
| Probable Reserves | 33 | 26 | 1,127 | 922 | 222 | 180 | |||||||||||||
| Total Proven + Probable | 300 | 229 | 2,138 | 1,760 | 658 | 522 | |||||||||||||
| 1 | Gas is converted to oil at 6 mcf to 1 bbl. |
| Gross reserves are the Company’s reserves before the deduction of any royalties. | |
| Net reserves are the Company’s reserves with royalty deductions. |
Net Present Worth of Reserves
Present Worth ($000’s)1 | ||||||||||
| Discounted at Rate of | ||||||||||
| January 1, 2004 | 0% | 10% | 15% | |||||||
| Proven Reserves | ||||||||||
| Producing | 5,372 | 3,513 | 3,025 | |||||||
| Non-Producing | 1,426 | 858 | 721 | |||||||
| Total Proven | 6,798 | 4,371 | 3,746 | |||||||
| Probable Reserves | 3,778 | 2,217 | 1,848 | |||||||
| Total Proven + Probable | 10,576 | 6,588 | 5,594 | |||||||
| 1 | Values shown are calculated on a before tax basis. |
The pricing forecasts used in Gilbert Laustsen’s engineering evaluation are as follows:
| Crude Oil | Natural Gas | ||||||
| Year | US $/bbl | Cdn $/mmbtu | |||||
| 2004 | $ | 29.00 | $ | 5.85 | |||
| 2005 | $ | 26.00 | $ | 5.15 | |||
| 2006 to 2014 | $ | 25.00 | $ | 5.00 | |||
| 2015+ | +1.5%/yr. | +1.5%/yr. | |||||
Crude oil price is WTI at Cushing, Oklahoma. Natural gas is the AECO spot price.
| 7 | ||
Reconciliation of Reserves
| Oil & NGLs (mbbls) | Natural Gas (mmcf) | ||||||||||||||||||
| Reserves | Proven | Probable | Total | Proven | Probable | Total | |||||||||||||
| On January 1, 2003 | 242 | 24 | 266 | 1,036 | 254 | 1,290 | |||||||||||||
| Drilling | – | – | – | 496 | 982 | 1,478 | |||||||||||||
| Revisions | 52 | 9 | 61 | (404 | ) | (109 | ) | (513 | ) | ||||||||||
| Total Additions | 52 | 9 | 61 | 92 | 873 | 965 | |||||||||||||
| Production | (27 | ) | – | (27 | ) | (117 | ) | – | (117 | ) | |||||||||
| As at January 1, 2004 | 267 | 33 | 300 | 1,011 | 1,127 | 2,138 | |||||||||||||
Reserve Life Index
| January 1, 2004 | January 1, 2003 | ||||||||||||
| Total | Total | ||||||||||||
| Years | Proven | Reserves | Proven | Reserves1 | |||||||||
| Oil | 9.4 | 10.6 | 8.6 | 9.5 | |||||||||
| Gas | 8.2 | 17.4 | 5.7 | 7.1 | |||||||||
| Combined | 8.9 | 13.5 | 7.1 | 8.2 | |||||||||
| 1 | Probable reserves at January 1, 2003 were evaluated using National Policy 2B definitions adjusted for risk (50% factor). |
[Picture ofRuth A. DeGama - Manager Production Services]
Marketing
Luke Energy received an average of $35.08 Cdn per barrel for its oil in 2003. Luke’s production averaged 88 barrels per day of light gravity oil from Bassano (30º API) and Bashaw (37º API).
The Company’s natural gas price averaged $6.47 Cdn per mcf in 2003. The Company’s average natural gas production was 380 mcf per day in 2003. Luke sold its natural gas to Pan-Alberta Gas, Progas Limited and Nexen Marketing during the year.
Luke Energy plans to sell its Marten Creek gas on the daily spot market.
Environmental and Safety Programs
Luke Energy is committed to protecting the health and safety of our employees and the public, as well as preserving the quality of the environment. The Company has a formal Emergency Response Plan in place to ensure the safe operations of our oil and gas properties.
In future, the Company will commission independent consultants to conduct detailed safety and environmental audits on all new operated properties.
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Management’s Discussion and Analysis
[Picture ofCarrie McLauchlin - Vice-President Finance & Chief Financial Officer]
The following discussion and analysis of financial results should be read in conjunction with the audited financial statements of the Company for the period ended December 31, 2003, together with the notes related thereto. The discussion contains forward-looking statements that involve risks and uncertainties. Such information, although considered reasonable by Luke Energy management at the time of preparation, may prove to be inaccurate and actual results may differ materially from those anticipated in the statements made.
Management’s discussion and analysis contains the term “cash flow from operations” which is calculated by adding non-cash items (future taxes, stock option compensation expense, and depletion, depreciation and accretion) to earnings for the period. Cash flow from operations is not a generally accepted accounting principle standard and therefore may not be comparable to similar benchmarks presented by issuers outside the oil and gas industry.
Incorporation
The Company was incorporated pursuant to the Canada Business Corporations Act on January 9, 2003 as a wholly-owned subsidiary of KeyWest Energy Corporation (“KeyWest”). Pursuant to a plan of arrangement between Viking Energy Royalty Trust (“Viking”), Viking Holdings Inc., Viking KeyWest Inc., KeyWest and Luke Energy, KeyWest transferred interests in certain petroleum and natural gas properties and related facilities to Luke Energy in exchange for common shares in Luke Energy. On February 26, 2003, the closing of the plan of arrangement, the common shares of Luke Energy held by KeyWest were distributed to the shareholders of KeyWest on a one for ten basis. Luke Energy began trading on the Toronto Stock Exchange on February 28, 2003.
The transfer of the assets was recorded at KeyWest’s net book value as Luke Energy and KeyWest were related parties.
Revenue
Oil and gas revenues for the period ended December 31, 2003 were $1,715,620. As Luke Energy’s Marten Creek drilling program did not commence until late December, sales volumes for the reporting period relate only to those properties acquired from KeyWest on February 26, 2003. Volumes for the period were 152 boepd which was in line with management’s expectations for these properties. The Company’s average oil price was $35.08 per barrel while gas averaged $6.47 per mcf, reflecting the strong commodity prices during the period.
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The Company’s strategy is to grow through a combination of low to medium risk exploration projects and acquisitions. Oil and gas revenues for 2004 are expected to be significantly higher with the gas volumes from the Marten Creek drilling program coming on-stream in late March. Additional sales volumes are expected from other internally generated exploration projects already underway. The engineering group continues to evaluate acquisition opportunities, however due to the highly competitive market at present, growth in this area is difficult to forecast.
Royalties
Royalty expense for the period was $434,687 or $9.28 per boe. Royalty expense as a percentage of production revenue was consistent throughout the period at 25%.
Operating Expenses
Operating expenses for the period were $262,754 or $5.61 per boe. Operating expenses were consistent over the period on a dollar basis as they generally reflected fixed costs related to the production acquired from KeyWest and thus did not vary significantly with changes in production levels.
Operating costs for 2004 are expected to increase concurrently with production growth and are not expected to exceed $7.00 per boe with the Marten Creek wells coming on-stream. Operating expenses will vary on a per boe basis with production increases from other internally generated projects or from acquisitions.
General and Administrative Expenses
The Company has strategically enhanced staffing levels and space requirements to grow its operations, resulting in relatively high general and administrative expenses for current production levels. General and administrative expenses were $1,134,408 for the period as summarized below:
| Gross expense | $ | 1,369,026 | ||
| Operator recoveries | (46,143 | ) | ||
| Capitalized expenses | (188,475 | ) | ||
| Net expense | $ | 1,134,408 | ||
Interest Income and Gain on Sale of Marketable Securities
The Company’s return on invested cash balances was 5.6%. This relatively high rate was achieved through interest income of $953,464 (or approximately 3.4%) earned on term deposits, investment grade commercial paper and Government of Canada Bonds, and also through a $629,575 gain realized on the Company’s sale of its Government of Canada Bonds during the period.
| 10 | ||
Depletion, Depreciation and Asset Retirement Obligation
The provision for depletion, depreciation, and accretion for the period was $493,404 or $10.54 per boe. The provision increased from $8.78 per boe in the first quarter to a year-end rate of $10.54 per boe due to facility upgrades and geological and geophysical costs that do not immediately result in reserve increases. The following table summarizes the provision:
| Depletion and depreciation of petroleum and natural gas properties | $ | 463,000 | ||
| Depreciation of office furniture and equipment | 25,934 | |||
| Accretion of asset retirement obligation | 4,470 | |||
| Total depletion, depreciation and accretion | $ | 493,404 | ||
Included in the depletion and depreciation of petroleum and natural gas properties is $8,416 representing the depletion on the capitalized asset retirement obligation of $106,460.
Taxes
Current taxes of $96,800 for the period relate exclusively to the federal Large Corporations Tax. The provision for future taxes of $290,000 is 30% of pre-tax earnings to December 31, 2003 and reflects that the sale of the Government of Canada bonds resulted in a capital gain which is only 50% taxable.
At the end of 2003 the Company had approximately $10.3 million of accumulated tax pools that are available for deduction against future earnings.
| Annual | |||||||
| Deduction | |||||||
| $000’s | Rate | ||||||
| Canadian exploration expense | $ | 517 | 100% | ||||
| Canadian development expense | 279 | 30% | |||||
| Canadian oil & gas property expense | 5,466 | 10% | |||||
| Undepreciated capital cost | 1,838 | 20%-30% | |||||
| Share issue costs | 1,887 | 20% | |||||
| Non-capital losses | 353 | 100% | |||||
| $ | 10,340 | ||||||
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Cash Flow and Earnings
Cash flow for the period of $1,374,948 ($0.05 per share) and earnings of $583,296 ($0.02 per share) were improved by the $629,575 gain on the sale of marketable securities. Excluding the gain, cash flow and earnings would be $745,373 ($0.03 per share) and $82,217 ($0.00 per share) respectively.
Liquidity and Capital Resources
The Company is well capitalized for growth with working capital of $35 million and a $2 million credit facility. The 2004 capital expenditure program of $30 million will be funded by working capital, cash flow and credit facility borrowings.
Initially the Company raised $1.3 million by issuing 1.6 million shares to directors, officers, and employees at the time KeyWest was sold to Viking. In March the Company completed a private placement of 24,827,585 special warrants for gross proceeds of $36,000,000. Management and directors subscribed for approximately 10% of the issue. In September, the Company issued 1,775,000 common shares on a tax flow-through basis at $2.00 per share for gross proceeds of $3,550,000. Management and directors subscribed for 50% of the issue.
At December 31, 2003 the Company had 34,828,949 common shares outstanding and 2,665,000 stock options outstanding.
Capital Expenditures
Capital expenditures for 2003 totaled $4.8 million as summarized in the table below. The land costs were incurred for the Marten Creek project. Seismic costs were incurred for the Marten Creek project and the Northeastern British Columbia gas prospects. Three quarters of the drilling, equipping, facilities and flowline expenditures were also for the Marten Creek project. The remainder of the costs were related to the Company’s Bashaw and Bassano properties.
| Land | $ | 2,077,054 | ||
| Seismic | 1,064,144 | |||
| Drilling and equipping | 953,070 | |||
| Facilities and flowlines | 564,614 | |||
| Corporate | 175,983 | |||
| $ | 4,834,865 | |||
Critical Accounting Estimates
Significant accounting policies are contained in note 2 to the financial statements. The following discusses the accounting estimates that are critical in determining the reported financial results:
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Full Cost Accounting The Company follows the full cost method of accounting as prescribed by Accounting Guideline #16 issued by the CICA. All costs for exploration and development of reserves are capitalized in a single cost centre. The costs are depleted on the unit-of-production method based on estimated proved reserves. The capitalized costs may not exceed a ceiling amount. If the net capitalized costs are determined to be in excess of the calculated ceiling, which is normally a reserve-based estimate, the excess must be expensed. Proceeds on disposal of properties are deducted from such costs without recognition of a gain or loss except where such disposal is a significant portion of the reserves. An alternative method of accounting for oil and natural gas operations is the successful efforts method. A major difference in applying the successful efforts method is that exploratory dry holes and geological and geophysical exploration costs are charged against earnings as incurred rather than being capitalized. Also, under this method the cost centre is defined to be a property rather than a country cost centre. Reserves The Company engages independent petroleum engineering consultants to evaluate its reserves. Reserve determinations involve forecasts based on property performance, future prices, projected future production and the timing of future capital expenditures; all of which are subject to uncertainties and interpretations. Reserve estimates have a significant impact on reported financial results as they are the basis for the calculation of depreciation and depletion and many non-GAAP key performance indicators. Revisions can change reported depletion and depreciation and earnings; downward revisions could result in a ceiling test write-down. Asset Retirement Obligation The Company provides for the estimated abandonment costs of properties using a fair value method. This future estimate is based on estimated costs and technology following current legislation and industry practice. The reported liability is a discounted amount. The amount of the liability is affected by factors such as the number of wells, the timing of the expected expenditures and the discount factor. These estimates will change and the revisions could impact the depletion and depreciation rates. Stock-based Compensation The stock option plan provides for granting of stock options to directors, officers, employees and consultants. Stock options granted have a maximum term of five years to expiry and vest equally over a three-year period. The exercise price of each stock option granted is determined as the closing market price of the common shares on the day prior to the day of the grant. Each stock option granted permits |
| 13 | ||
| the holder to purchase one common share at the stated exercise price. The Company does not record a compensation expense for stock options granted to directors, officers and employees. If the Company had used the fair-value method to account for its stock based compensation to directors, officers and employees, an expense of $214,092 would have been charged to net earnings in 2003. | |
Financial Reporting and Regulatory Changes New and amended standards described below were implemented by the Company in 2003 with the following impact: | |
Asset Retirement Obligations The Canadian Institute of Chartered Accountants “CICA” issued Section 3110 which harmonizes Canadian GAAP with SFAS No. 143 “Accounting for Asset Retirement Obligations”. The new standard requires that companies recognize the present value of the liability associated with future site reclamation costs in the financial statements at the time when the liability is incurred. The new Canadian standard is effective for fiscal years beginning on or after January 1, 2004, however the Company adopted the standard upon formation. As a result the Company has recorded a liability for asset retirement obligation of $110,930, an increase to capital assets of $106,460 and an accretion expense of $4,470 (included in the depletion, depreciation and accretion expense on the statement of earnings). Full Cost Accounting Guideline In September 2003, the CICA issued Accounting Guideline 16 “Oil and Gas Accounting – Full Cost” to replace CICA Accounting Guideline 5. The new guideline proposes amendments to the ceiling test calculation applied by the Company. The new guideline is effective for fiscal years beginning on or after January 1, 2004. The Company implemented this new guideline in 2003 in accordance with transitional provisions that encouraged early adoption. Implementation of this new guideline did not impact the Company’s financial results for 2003. | |
| Certain new and amended standards are expected to impact the Company in 2004 as follows: | |
Continuous Disclosure Obligations Effective March 31, 2004, the Company and all reporting issuers in Canada will be subject to new disclosure requirements as per National Instrument 51-102 “Continuous Disclosure Obligations”. This new instrument is effective for fiscal years beginning on or after January 1, 2004. The instrument proposes shorter reporting periods for filing of annual and interim financial statements, MD&A and Annual Information Form. The instrument also proposes enhanced disclosure in the annual and interim financial statements, MD&A and Annual Information Forms which the Company is incorporating into this annual report and filings for 2003. | |
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Stock Based Compensation In September 2003, the CICA issued an amendment to section 3870 “Stock based compensation and other stock based payments”. The amended section is effective for fiscal years beginning on or after January 1, 2004. The amendment requires that companies measure all stock based payments using the fair value method of accounting and recognize the compensation expense in their financial statements. Currently the Company provides this information as note disclosure in the financial statements which illustrates the impact on the earnings if the compensation expense had been booked. The Company will adopt this new standard in the first quarter of 2004. |
Business Risks
Luke Energy operates in a business environment that is subject to numerous risks, some of which are within the Company’s ability to manage and some of which are beyond its control. By adhering to its effective business strategies, Luke can manage those risks within its control and partially mitigate the risks that are associated with the industry.
The prospect of finding oil and gas reserves in commercial quantities is inherently uncertain, and significant financial resources must be employed before production can be brought on-stream. To minimize this risk, Luke has employed a highly qualified exploration team to generate low to medium risk prospects in areas commensurate with the financial resources of the Company. The Company focuses on exploring new areas to find oil and gas and to this end, extensive geological and geophysical analysis is performed prior to drilling. Once an area is targeted, the Company strives to build an extensive land base and maintain high working interests in its prospects.
Luke also mitigates its risk by employing a technically strong team of engineers to evaluate and acquire core properties which have exploitation potential. The Company also strives to reduce outside risk by operating most of its production.
The Company strives to maintain a balance between the use of cash flow, equity markets and debt. While Luke currently has significant working capital and an unused credit line, it does not intend to allow its debt to exceed two times cash flow.
Once reserves are brought on-stream, there are risks associated with transportation and markets for oil and gas, especially for a junior oil and gas company. To reduce these risks, Luke endeavors to arrange firm transportation service where possible and markets its oil and gas through more than one purchaser. In addition, Luke maintains a portfolio of both oil and gas assets to minimize the risks associated with changing market conditions.
| 15 | ||
Commodity price volatility is also a significant risk to oil and gas producers. Prices for oil and gas are related to conditions beyond the Company’s control such as worldwide supply and demand, competition, the US dollar exchange rate and weather related seasonal changes in demand. When production grows, Luke may, from time to time, utilize the combination of fixed price contracts and financial instruments to mitigate the risk of price volatility.
The Company does invest from time to time in bonds to improve the return on invested cash balances. As a result Luke Energy is subject to bond market volatility. This risk is reduced by only investing in Government of Canada bonds which are investment grade and are highly liquid. In addition, the bond market is monitored closely and investments will be liquidated if the return, including the gain or loss, would result in a return lower than that which could be achieved on term deposits or commercial paper.
The industry is subject to extensive regulations imposed by governments related to the protection of the environment. Environmental legislation has undergone major revisions resulting in more stringent environmental and compliance standards in recent years. Luke is committed to operating in a manner that meets or exceeds the required standards and compliance guidelines. In addition, the Company strives to minimize the impact of its activities on the environment by using the best available technologies.
Quarterly Information
($000’s except per share amounts)
| Gross | Cash Flow | |||||||||||||||
| Production | From | Per | Per | |||||||||||||
| 2003 | Revenue | Operations | Share1 | Earnings | Share1 | |||||||||||
| Q1 | $ | 266 | $ | 68 | $ | 0.01 | $ | 5 | $ | 0.00 | ||||||
| Q2 | 537 | 287 | $ | 0.01 | 85 | $ | 0.00 | |||||||||
Q32 | 487 | 772 | $ | 0.02 | 464 | $ | 0.01 | |||||||||
| Q4 | 426 | 248 | $ | 0.01 | 29 | $ | 0.00 | |||||||||
| Total | $ | 1,716 | $ | 1,375 | $ | 0.05 | $ | 583 | $ | 0.02 | ||||||
| 1 | The sum of the quarterly per share amounts may not necessarily equal the annual per share amounts due to the different weightings of shares issued during the year. |
| 2 | Cash flow and earnings for the third quarter were positively impacted by the gain on sale of Government of Canada bonds. |
| 16 | ||
Management’s Report
The accompanying financial statements of Luke Energy Ltd. and all other financial and operating information contained in this Annual Report are the responsibility of management. The financial statements have been prepared in accordance with accounting policies detailed in the notes to the financial statements and in accordance with Canadian generally accepted accounting principles. Financial statements are not precise as they include certain amounts based on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that the financial statements are presented fairly, in all material respects. Financial information presented elsewhere in this annual report has been prepared on a basis consistent with that in the financial statements.
The Company’s systems of internal control have been designed and maintained to provide reasonable assurance that assets are properly safeguarded and that the financial records are sufficiently well maintained to provide relevant, timely and reliable information to management.
External auditors, appointed by the shareholders, have independently examined the financial statements. They have performed such tests as they deemed necessary to enable them to express an opinion on these financial statements.
An Audit & Reserves Committee of the Board of Directors, composed of non-management Directors, has reviewed these financial statements with management and the external auditors.
The Board of Directors has approved the financial statements on the recommendation of the Audit & Reserves Committee.
| -s-Harold V. Pedersen | -s-Carrie L. McLauchlin | |
| Harold V. Pedersen | Carrie L. McLauchlin | |
| Chief Executive Officer | Vice-President, Finance & CFO |
| 17 | ||
Auditors’ Report to the Shareholders
We have audited the balance sheets of Luke Energy Ltd. as at December 31, 2003 and January 9, 2003 and the statement of earnings and retained earnings and cash flows for the period from January 9, 2003 to December 31, 2003. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with Canadian and United States generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.
In our opinion, these financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2003 and January 9, 2003 and the results of its operations and its cash flows for the period from January 9, 2003 to December 31, 2003 in accordance with Canadian generally accepted accounting principles.
-s-KPMG LLP
KPMG LLP
Chartered Accountants
Calgary, Canada
March 8, 2004
| 18 | ||
Balance Sheets
| December 31, 2003 | January 9, 2003 | ||||||
Assets | |||||||
| Current assets: | |||||||
| Cash and term deposits | $ | 36,699,571 | $ | 100 | |||
| Receivables | 529,815 | – | |||||
37,229,386 | 100 | ||||||
| Capital assets (note 4) | 7,998,257 | – | |||||
$ | 45,227,643 | $ | 100 | ||||
Liabilities and Shareholders’ Equity | |||||||
| Current liabilities: | |||||||
| Accounts payable and accrued liabilities | $ | 2,203,148 | $ | – | |||
| Future taxes (note 9) | 98,850 | – | |||||
| Asset retirement obligations (note 6) | 110,930 | – | |||||
| Shareholders’ equity: | |||||||
| Share capital (note 7) | 42,223,171 | 100 | |||||
| Contributed surplus | 7,618 | – | |||||
| Retained earnings | 583,926 | – | |||||
42,814,715 | 100 | ||||||
$ | 45,227,643 | $ | 100 | ||||
See accompanying notes to financial statements.
On behalf of the Board:
| -s-Harold V. Pedersen | -s-Mary C. Blue | |
| Director | Director | |
| Harold V. Pedersen | Mary C. Blue |
| 19 | ||
Statement of Earnings and Retained Earnings
| Period ended December 31 | 2003 | |||
| Revenue: | ||||
| Oil and gas production | $ | 1,715,620 | ||
| Royalties | (434,687 | ) | ||
| Gain on sale of marketable securities | 629,575 | |||
| Interest | 953,464 | |||
2,863,972 | ||||
| Expenses: | ||||
| Operating | 262,754 | |||
| General and administrative | 1,134,408 | |||
| Interest | 2,680 | |||
| Depletion, depreciation and accretion | 493,404 | |||
1,893,246 | ||||
| Earnings before taxes | 970,726 | |||
| Taxes (note 9): | ||||
| Current | 96,800 | |||
| Future | 290,000 | |||
386,800 | ||||
| Earnings and retained earnings, end of period | $ | 583,926 | ||
| Weighted average number of common shares outstanding (note 8) | 29,759,428 | |||
| Earnings per share – basic and diluted | $ | 0.02 | ||
See accompanying notes to financial statements.
| 20 | ||
Statement of Cash Flows
| Period ended December 31 | 2003 | |||
| Cash provided by (used in): | ||||
| Operating: | ||||
| Earnings for the period | $ | 583,926 | ||
| Items not affecting cash: | ||||
Depletion and depreciation and accretion | 493,404 | |||
Future taxes | 290,000 | |||
Stock based compensation expense | 7,618 | |||
| Cash flow from operations | 1,374,948 | |||
| Change in non-cash working capital (note 10) | 45,959 | |||
1,420,907 | ||||
| Financing: | ||||
| Common shares issued (note 7) | 38,486,155 | |||
| Initial common shares redeemed for cash | (100 | ) | ||
38,486,055 | ||||
| Investing: | ||||
| Additions to capital assets | (4,834,865 | ) | ||
| Change in non-cash working capital (note 10) | 1,627,374 | |||
(3,207,491 | ) | |||
| Increase in cash | 36,699,471 | |||
| Cash position, beginning of period | 100 | |||
| Cash position, end of period | $ | 36,699,571 | ||
Cash position includes cash and term deposits.
See accompanying notes to financial statements.
| 21 | ||
Notes to Financial Statements
Period ended December 31, 2003
| 1. | INCORPORATION AND PLAN OF ARRANGEMENT: Luke Energy Ltd. (“Luke Energy” or the “Company”) is engaged in the acquisition, exploration, development and production of oil and gas reserves in western Canada. The Company was incorporated pursuant to the Canada Business Corporations Act on January 9, 2003 as a wholly-owned subsidiary of KeyWest Energy Corporation (“KeyWest”). Pursuant to a plan of arrangement between Viking Energy Royalty Trust, Viking Holdings Inc., Viking KeyWest Inc., KeyWest and Luke Energy, KeyWest transferred interests in certain petroleum and natural gas properties and related facilities (“Retained Assets”) to Luke Energy in exchange for common shares in Luke Energy. On February 26, 2003, the closing of the plan of arrangement, the common shares of Luke Energy held by KeyWest were distributed to the shareholders of KeyWest on a one for ten basis. Luke Energy began trading on the Toronto Stock Exchange on February 28, 2003. The following summarizes the transfer of the Retained Assets which were initially recorded at KeyWest’s net book value as Luke Energy and KeyWest were related parties. The amounts were then adjusted for the booking of the site restoration provision and the future tax asset. The results of the operations of the Retained Assets were included from February 26, 2003. Net assets acquired and liabilities assumed: |
| Petroleum and natural gas rights | $ | 2,482,106 | ||
| Equipment and facilities | 1,126,009 | |||
| Future tax asset | 628,550 | |||
| Site restoration | (62,250 | ) | ||
| $ | 4,174,415 | |||
Consideration: | ||||
| Issuance of 6,581,364 common shares | $ | 4,174,415 | ||
| 2. | SIGNIFICANT ACCOUNTING POLICIES: The financial statements of the Company have been prepared in accordance with Generally Accepted Accounting Principles in Canada. In all material respects, these accounting principles are generally accepted in the United States except as described in Note 13. The preparation of the financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingencies at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results may differ from these estimates. |
| 22 | ||
Capital assets The Company follows the full cost method of accounting for petroleum and natural gas operations, whereby all costs of exploring, developing and acquiring petroleum and natural gas properties, including asset retirement costs, are capitalized and accumulated in one cost centre. Costs include land acquisition costs, geological and geophysical charges, carrying charges on non-productive properties, costs of drilling both productive and non-productive wells, tangible production equipment and that portion of general and administrative expenses directly attributable to exploration and development activities. Gains and losses are not recognized upon disposition of petroleum and natural gas properties unless such a disposition would alter the rate of depletion by 20 per cent or more. Depletion and Depreciation All costs of acquisition, exploration and development of oil and gas reserves, associated well equipment and facilities (net of salvage value), and estimated costs of future development of proven undeveloped reserves are depleted and depreciated by the unit-of-production method based on estimated proven reserves before royalties as determined by independent engineers. Natural gas reserves and production are converted to equivalent barrels of crude oil based on relative energy content of six mcf of gas to one barrel of oil. Costs of unproved properties are initially excluded from depletion calculations. These unproved properties are assessed periodically to ascertain whether impairment has occurred. When proven reserves are assigned or the property is considered impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion. Depreciation of office furniture and equipment is provided using the straight-line method based on estimated useful lives. Ceiling Test In applying the full cost method, the Company calculates a ceiling test whereby the carrying value of petroleum and natural gas properties is compared annually to the sum of the undiscounted cash flows expected to result from the Company’s proved reserves and the lower of cost or market of unproved properties. Cash flows are based on third party quoted forward prices, adjusted for the Company’s contracted prices and quality differentials. Should the ceiling test result in an excess of carrying value, the Company would then measure the amount of impairment by comparing the carrying amounts of petroleum and natural gas properties to an amount equal to the estimated net present value of future cash flows from proved plus probable reserves and the lower of cost and market of unproved properties. The Company’s risk-free interest rate is used to arrive at the net present va lue of the future cash flows. Any excess carrying value of the Company’s future cash flows would be recorded as a permanent impairment. |
| 23 | ||
Asset Retirement Obligations The Company recognizes the fair value of an asset retirement obligation in the period in which it is incurred when a reasonable estimate of fair value can be made. The fair value is based on estimated reserve life, inflation and discount rates. The provision is recorded as a long-term liability, with a corresponding increase in the carrying value of the associated asset. The capitalized amount is depleted on a unit-of-production basis based on estimated proven reserves before royalties as determined by independent engineers. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is charged to earnings in the period. Revisions to the estimated timing of cash flows or to the original estimated undiscounted cost would also result in an increase or decrease to the asset retirement obligation. Actual asset retirement expenditures ar e charged against the liability to the extent of the liability recorded. Any difference between the actual costs incurred and the amount of the liability recorded is recognized as a gain or loss in the Company’s earnings in the period the costs are incurred. Joint Interest Operations A portion of the Company’s exploration, development and production activities are conducted jointly with others. These financial statements reflect only the Company’s proportionate interest in such activities. Flow-through Shares The resource expenditure deductions related to exploratory activities funded by flow through share arrangements are renounced to investors in accordance with tax legislation. A future tax liability is recognized and share capital is reduced by the estimated tax cost of the renounced expenditures. Stock-based Compensation Plans The Company has a stock-based compensation plan as described in Note 7. The Company uses the intrinsic value method of accounting for its stock based compensation plan. Consideration paid by employees or directors on the exercise of stock options under the employee stock option plan are recorded as share capital. The Company does not recognize compensation expense on the issuance of stock options to employees and directors because the exercise price equals the market price on the day of the grant. The Company does apply the fair value method to stock options granted to non-employees resulting in recognition of compensation expense recorded to general and administrative costs with a corresponding amount to contributed surplus. The Black-Scholes option pricing model is used to estimate fair value. The Company discloses the pro forma effect of accounting for those stock option awards u nder the fair value method. |
| 24 | ||
Income Taxes The Company uses the liability method of tax allocation accounting for income taxes. Under this method, future tax assets and liabilities are determined based on differences between the financial reporting and tax bases of assets and liabilities, and measured using the substantially enacted tax rates and laws that will be in effect when the differences are expected to reverse. Foreign Currency Translation Amounts denominated in foreign currencies are translated into Canadian dollars at the year-end exchange rates. Gains or losses on translation are included in earnings. Per share amounts Basic earnings per common share are computed by dividing earnings by the weighted average number of common shares outstanding for the period. Diluted per share amounts reflect the potential dilution that could occur if securities or other contracts to issue common shares, including stock options, were exercised or converted to common shares. The treasury stock method is used to determine the dilutive effect of stock options and other dilutive instruments. Hedging The Company may use certain financial instruments to manage its exposure to commodity price and foreign exchange. The Company does not use these instruments for speculative purposes. Gains and losses on these transactions are reported as adjustments to revenue when related production is sold. | |
| 3. | CHANGES IN ACCOUNTING POLICIES In December 2003, the Company adopted AcG -16 “Oil and Gas Accounting – Full Cost”, the new guideline issued by the Canadian Institute of Chartered Accountants replaces AcG-5 “Full cost Accounting in the Oil and Gas Industry”. Under AcG-5, future net revenues for ceiling test purposes were based on proved reserves and were not discounted. Estimated future general and administrative costs and financing charges associated with the future net revenues were deducted in arriving at the “ceiling”. There were no changes to earnings, capital assets or any other reported amounts in the financial statements as a result of early adoption. |
| 25 | ||
| 4. | CAPITAL ASSETS |
| Accumulated | |||||||
| depletion and | |||||||
| Cost | depreciation | ||||||
| Petroleum and natural gas properties, including well equipment | $ | 8,311,208 | $ | 463,000 | |||
| Office furniture and equipment | 175,983 | 25,934 | |||||
| $ | 8,487,191 | $ | 488,934 | ||||
| Net book value | $ | 7,998,257 | |||||
At December 31, 2003, costs of $2,817,099 related to unproven properties have been excluded from the depletion calculation. In 2003, the Company capitalized $188,475 of general and administrative expenses directly related to exploration and development activities. Included in the Company’s petroleum and natural gas properties is $98,044, net of accumulated depletion, relating to the asset retirement obligation. The Company performed a ceiling test calculation at December 31, 2003 to assess the recoverable value of petroleum and natural gas properties. The present value of future net revenues from the Company’s proved plus probable reserves exceeded the carrying value of the Company’s petroleum and natural gas properties at December 31, 2003. The calculation was based on the independent engineering evaluation (escalated price case). The future pricing assumptions used in the engineering evaluation are as follows: |
| WTI Oil | Foreign | AECO Gas | ||||||||
| Year | ($US/bbl) | Exchange Rate | ($Cdn/mmbtu) | |||||||
| 2004 | 29.00 | 0.75 | 5.85 | |||||||
| 2005 | 26.00 | 0.75 | 5.15 | |||||||
| 2006-2014 | 25.00 | 0.75 | 5.00 | |||||||
| 2015+ | +1.5%/yr. | +1.5%/yr | ||||||||
| 5. | CREDIT FACILITY The Company has a $2 million production loan facility available with a major Canadian bank. Pursuant to the terms of the agreement, any amounts owing will revolve until June 30, 2004 and for a further period of 364 days thereafter at the request of the Company and with the consent of the bank. During the revolving phase, the loan has no specific terms of repayment. Loans under the facility may be made by way of prime based loans. A standby fee of 0.375 percent per annum is levied on the unused portion of the facility. |
| 26 | ||
Upon the expiration or termination of the revolving phase of the loan, any balance outstanding on the loan converts to a two-year term loan. The first repayment of one half of the outstanding balance is due on the 366th day after conversion followed by four quarterly repayments. During the term loan phase, interest rates will increase 1.0 percent from those during the revolving phase. The facility is secured by a first floating charge demand debenture over all of the Company’s assets. | |
| 6. | ASSET RETIREMENT OBLIGATIONS The total future asset retirement obligation was estimated by management based on the Company’s net ownership in wells and facilities, estimated costs to reclaim and abandon wells and facilities and the estimated timing of the costs to be incurred in future periods. At December 31, 2003 the net present value of the total asset retirement obligation is estimated to be $106,460 based on a total future liability of $230,600. These payments are expected to be made over the next 30 years with the majority of costs incurred between 2011 and 2024. The Company’s adjusted risk free rate of five percent and an inflation rate of 1.5 per cent were used to calculate the present value of the asset retirement obligation. The following table reconciles the Company’s asset retirement obligations: |
| 2003 | ||||
| Carrying amount, beginning of the period | $ | – | ||
| Recorded on acquisition of properties (note1) | 62,250 | |||
| Increase in liabilities, during the period | 44,210 | |||
| Settlement of liabilities during the period | – | |||
| Accretion expense | 4,470 | |||
| Carrying amount, end of period | $ | 110,930 | ||
| 7. | SHARE CAPITAL The Company is authorized to issue an unlimited number of common shares together with an unlimited number of preferred shares issuable in series. |
| 27 | ||
Common Shares Common shares issued and outstanding: |
| Number of Shares | Amount | ||||||
| Balance at January 9, 2003, date of incorporation | 100 | $ | 100 | ||||
| Initial shares redeemed for cash | (100 | ) | (100 | ) | |||
| Issued on completion of the plan of arrangement (note 1) | 6,581,364 | 4,174,415 | |||||
| Issued through private placement to directors, officers and employees | 1,645,000 | 1,332,450 | |||||
| Conversion of special warrants | 24,827,585 | 36,000,000 | |||||
| Issued through private placement of flow-through shares | 1,775,000 | 3,550,000 | |||||
| Tax effect on flow-through shares | – | (1,329,000 | ) | ||||
| Share issue costs | – | (2,396,294 | ) | ||||
| Future tax effect of the share issue costs | – | 891,600 | |||||
| Balance at December 31, 2003 | 34,828,949 | $ | 42,223,171 | ||||
In September, the Company issued 1,775,000 common shares on a tax flow-through basis at $2.00 per share for proceeds of $3,550,000. Management and directors subscribed for 50% of the issue. Under the terms of the private placement the proceeds are to be expended on qualifying exploration drilling and seismic prior to December 31, 2004. At December 31, 2003, $2.7 million remains to be spent. In March the Company completed a private placement of 24,827,585 special warrants for gross proceeds of $36,000,000. The proceeds of this financing were placed in escrow until shareholder approval was received on April 14, 2003. At that time the special warrants were deemed to be exercised for common shares on a one for-one basis without additional consideration. Management and directors subscribed for approximately 10% of the issue. Stock-based Compensation Plan Pursuant to the Officers, Directors and Employees Stock Plan, (“the Plan”), the Company was entitled to reserve for issuance and grant stock options to a maximum of 3.3 million shares on a cumulative basis (not to exceed 10% of the issued and outstanding shares of Luke Energy on an undiluted basis). Options granted under the Plan have a term of five years to expiry and vest equally over a three-year period starting on the first anniversary date of the grant. The exercise price of each option equals the market price of the Company’s common shares on the date of the grant. At December 31, 2003, 2,665,000 options with exercise prices between $0.81 and $1.85 were outstanding and exercisable on various dates to 2008. |
| 28 | ||
| A summary of the status of the Plan at December 31, 2003, and changes during the period ended is presented below: |
| Number | Weighted Average | ||||||
| Of Options | Exercise Price | ||||||
| Stock options, beginning of period | – | – | |||||
| Granted | 3,055,000 | $ | 1.51 | ||||
| Exercised | – | – | |||||
| Cancelled | (390,000 | ) | $ | 1.39 | |||
| Stock options, end of period | 2,665,000 | $ | 1.52 | ||||
| Exercisable, end of period | – | – | |||||
| The following table summarizes information about the stock options outstanding at December 31, 2003: |
| Options Outstanding at | ||||||||||
| December 31, 2003 | ||||||||||
| Weighted | ||||||||||
| Average | Weighted | |||||||||
| Remaining | Average | |||||||||
| Number | Contractual | Exercise | ||||||||
| of Options | Life | Price | ||||||||
| Range of Exercise Prices | ||||||||||
| Less than $1.00 | 675,000 | 4.14 | $ | 0.81 | ||||||
| Greater than $1.00 | 1,990,000 | 4.69 | $ | 1.77 | ||||||
| $0.81 to $1.85 | 2,665,000 | 4.55 | $ | 1.52 | ||||||
| The Company accounts for its stock-based compensation plans using the intrinsic-value method whereby no costs have been recognized in the financial statements for stock options granted to employees and directors. If the fair value method had been used, the Company’s earnings and earnings per share would approximate the following pro-forma amounts: |
| Period ended | ||||
| December 31, 2003 | ||||
| Fair value of options granted | $ | 1,879,895 | ||
| Compensation expense | $ | 214,092 | ||
| Earnings – as reported | $ | 583,926 | ||
| Earnings – pro forma | $ | 369,834 | ||
| Basic and diluted earnings per share – as reported | $ | 0.02 | ||
| Basic and diluted loss per share – pro forma | $ | 0.01 | ||
| 29 | ||
The fair value of each stock option was estimated on the date of grant using the Black-Scholes option pricing model with the following weighted average assumptions: risk-free interest rate of 5%, dividend yield of 0%, expected life of 5 years, and volatility of 45%. During the period ended December 31, 2003 the Company recognized $7,618 of compensation expense (included in general and administrative expense) for stock options issued to non-employees. | |
| 8. | PER SHARE AMOUNTS |
| In computing diluted earnings per share, 581,480 shares were added to the weighted average number of common shares outstanding during the period ended December 31, 2003 for the dilutive effect of employee stock options and warrants. No adjustments were required to reported earnings from operations in computing diluted per share amounts. | |
| 9. | TAXES |
| The future income tax liability includes the following temporary differences: |
| Oil and gas properties | $ | 990,450 | ||
| Share issue costs | (891,600 | ) | ||
| $ | 98,850 | |||
| The provision for income taxes differs from the amount computed by applying the combined federal and provincial tax rates to earnings before income taxes. The difference results from the following: |
| Earnings before taxes | $ | 970,726 | ||
| Combined federal and provincial tax rate | 40.62 | % | ||
| Computed “expected” tax | $ | 394,309 | ||
| Increase (decrease) in taxes resulting from: | ||||
| Non-deductible crown charges | 29,066 | |||
| Non-taxable portion of capital gain | (127,866 | ) | ||
| Non-deductible expenses | 12,972 | |||
| Effect of change in corporate tax rate | (50,558 | ) | ||
| Resource allowance | 32,077 | |||
| Large corporations tax | 96,800 | |||
| Reported income taxes | $ | 386,800 | ||
| 30 | ||
| 10. | CHANGE IN NON-CASH WORKING CAPITAL |
| 2003 | ||||
| Receivables | $ | (529,815 | ) | |
| Accounts payable and accrued liabilities | 2,203,148 | |||
| $ | 1,673,333 | |||
| Non-cash working capital – operating | $ | 45,959 | ||
| Non-cash working capital – investing | 1,627,374 | |||
| $ | 1,673,333 | |||
| 11. | FINANCIAL INSTRUMENTS |
The financial instruments included in the balance sheets are comprised of accounts receivable and accounts payable and accrued liabilities. The fair values of these financial instruments approximate their carrying amounts due to the short-term maturity of the instruments. All of the Company’s accounts receivable are with customers in the oil and natural gas industry and are subject to normal industry credit risk. Purchasers of the Company’s natural gas, crude oil and natural gas liquids are subject to an internal credit review to minimize risk of non-payment. | |
| 12. | SUPPLEMENTAL CASH FLOW INFORMATION |
| Amounts actually paid during the period relating to interest expense and capital taxes are as follows: |
| Period ended | ||||
| December 31, 2003 | ||||
| Interest paid | $ | 2,680 | ||
| Capital taxes paid | $ | – | ||
| 31 | ||
| 13. | Reconciliation to United States generally accepted accounting principles (“U.S. GAAP”): | |
| The Company follows accounting principles generally accepted in Canada which differ in certain respects from those applicable in the United States and from practices prescribed by the Securities and Exchange Commission (SEC). The significant differences in accounting principles and practices that could affect the reported earnings are as follows: | ||
| u | The Company would be required to perform an SEC prescribed ceiling test. In determining the limitation on capitalized costs, SEC rules require a 10 percent discounting of after-tax future net revenues from production of proved oil and gas reserves. To date, application of the SEC prescribed test has not resulted in a write-down of capitalized costs. | |
| u | The Company finances a portion of its activities with flow-through share issues whereby the tax deductions on expenditures are renounced to the share subscribers. The estimated cost of the tax deductions renounced to shareholders has been reflected as a reduction of the stated value of the shares. The SEC requires that when the qualifying expenditures are incurred and renounced to the shareholders the estimated tax cost of the renunciation, less any proceeds received in excess of the quoted value of the shares is reflected as a tax expense. | |
| Reconciliation of the reported earnings as a result of the differences between Canada and the United States accounting principles for the period ended December 31, 2003 are as follows: | ||
| Earnings for the period, as reported | $ | 583,926 | ||
| Estimated tax cost of the renunciation of tax benefits on expenditures | (1,329,000 | ) | ||
| Loss for the period in accordance with United States Accounting Principles | $ | (745,074 | ) | |
| Loss per share – basic and diluted | $ | 0.03 | ||
| 32 | ||
Corporate Information
Directors Ronald L. Belsher1,2 Calgary, Alberta Mary C. Blue President & COO Calgary, Alberta David Crevier1,3 Montreal, Quebec Alain Lambert2 Montreal, Quebec Hugh Mogensen1 Chairman Victoria, B.C. Harold V. Pedersen2 Chief Executive Officer Calgary, Alberta Lyle D. Schultz3 Calgary, Alberta J. Ronald Woods1,3 Toronto, Ontario 1 Audit & Reserves Committee 2 Compensation Committee 3 Corporate Governance Committee | Management Harold V. Pedersen Chief Executive Officer Mary C. Blue President & COO Robert E. Wollmann Vice-President, Exploration Kevin Lee Vice-President, Engineering Carrie McLauchlin Vice-President, Finance & CFO Peter W. Abercrombie Vice-President, Land Ruth A. DeGama Manager, Production Services Chris von Vegesack Corporate Secretary Head Office 1200, 520 - 5 Avenue S.W. Calgary, Alberta T2P 3R7 Telephone: (403) 261-4811 Facsimile: (403) 261-4818 Website: www.lukeenergy.com | Stock Exchange Listing Toronto Stock Exchange Trading Symbol: LKE Registrar and Transfer Agent Valiant Trust Company Calgary, Alberta Telephone: (403) 233-2801 Bankers Canadian Imperial Bank of Commerce Oil & Gas Group, Calgary, Alberta Auditors KPMG LLP, Calgary, Alberta Evaluation Engineers Gilbert Laustsen Jung Associates Ltd. Calgary, Alberta Solicitors Burnet, Duckworth & Palmer LLP Calgary, Alberta Colby, Monet, Demers, Delage & Crevier, Montreal, Quebec |
| Luke Energy 1200, 520 - 5 Avenue S.W. Calgary, Alberta T2P 3R7 Telephone: (403) 261-4811 Facsimile: (403) 261-4818 www.lukeenergy.com |