Management's Discussion and Analysis



Managements Discussion and Analysis should be read in conjunction with our audited consolidated financial statements and related notes for the years ended December 31, 2004 and 2003.  The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) applicable in Canada.  A reconciliation of Canadian GAAP to U.S. GAAP is included in note 14 to our consolidated financial statements.  Unless otherwise noted, all amounts are stated in Canadian dollars, and sales volumes, production volumes and reserves are before royalties. The calculation of barrels of oil equivalent (boe) is based on a conversion ratio of six thousand cubic feet of natural gas to one barrel of oil (6:1) to estimate relative energy content.  This conversion should be used with caution, particularly when used in isolation, since the 6 mcf:1 bbl ratio is based on an energy equivalency at the burner tip and does not represent the value equivalency at the well head.



This Discussion and Analysis includes references to financial measures commonly used in the oil and gas industry, such as cash flow from operations (expressed before changes in non-cash working capital) and cash flow from operations per share (using the weighted average shares outstanding consistent with the calculation of net income (loss) per share).  These financial measures are not defined by GAAP and therefore are referred to as non-GAAP measures.  The non-GAAP measures used by us may not be comparable to similar measures presented by other companies.  We use these non-GAAP measures to evaluate the performance of the Company.  The non-GAAP measures should not be considered an alternative to or more meaningful than net earnings, as determined in accordance with GAAP, as an indication of our performance.



This document contains certain forward-looking statements relating, but not limited, to operations, financial performance, business prospects and strategies of the Company.  Forward-looking information typically contains statements with words such as "anticipate", "believe", "expect", "plan", "intend" or similar words suggesting future outcomes or statements regarding an outlook on, without limitation, commodity prices, estimates of future production, the estimated amounts and timing of capital expenditures, anticipated future debt levels and royalty rates, or other expectations, beliefs, plans, objectives, assumptions or statements about future events or performance.



Shareholders are cautioned not to place undue reliance on forward-looking information.  By its nature, forward-looking information of the Company involves numerous assumptions, inherent risks and uncertainties both general and specific that contribute to the possibility that the predictions, forecasts, projections and other forward-looking statements will not occur.  These factors include, but are not limited to: the pricing of natural gas and oil; the effects of competition and pricing pressures; risks and uncertainties involving the geology of natural gas and oil; operational risks in exploring for, developing and producing natural gas and oil; the uncertainty of estimates and projections relating to production, costs and expenses; the significant costs associated with the exploration and development of the properties on which the Company has interests, particularly the Kotaneelee field; shifts in market demands; risks inherent in the Company's marketing operations; industry overcapacity; the strength of the Canadian economy in general; currency and interest rate fluctuations; general global and economic and business conditions; changes in business strategies; potential delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of reserves estimates; various events which could disrupt operations, including severe weather conditions, technological changes, our anticipation of and success in managing the above risks; potential increases in maintenance expenditures; changes in laws and regulations, including trade, fiscal, environmental and regulatory laws; and health, safety and environmental risks that may affect projected reserves and resources and anticipated earnings or assets.  See also the information set forth under the heading "Information Concerning the Oil and Natural Gas Industry" in our 2004 Annual Information Form.  Statements relating to "reserves" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions that the reserves described can be profitably produced in the future.



We caution that the foregoing list of important factors is not exhaustive.  We undertake no obligation to update publicly or revise the forward-looking information provided in this document, whether as a result of new information, future events or otherwise, or the foregoing list of factors affecting this information.



This Managements Discussion and Analysis is dated as at March 28, 2005.

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Overview



|                                                            | Year ended December 31, |  
|----------------------------------------------------------- | ----------------------- | -
|($000s, except per share amounts)                          | 2004                    |  
|                                                            |                         |  
|Petroleum and natural gas sales                             | 10,812                  |  
|Royalties                                                   | (1,600                  | )
|Carried interest                                            | 3,381                   |  
|Lease operating costs                                       | (1,548                  | )
|Operating netback                                           | 11,045                  |  
|Interest and other income                                   | 1,235                   |  
|General and administrative                                  | (3,341                  | )
|Foreign exchange losses                                     | (96                     | )
|Asset retirement expenditures                               | (1                      | )
|Income tax expense                                          | (782                    | )
|Settlement of litigation                                    | -                       |  
|Fair value of abandonment liabilities assumed on settlement | -                       |  
|Cash flow from operations(1)                                | 8,060                   |  
|Depletion and depreciation                                  | (3,357                  | )
|Fair value of abandonment liabilities assumed on settlement | -                       |  
|Asset retirement obligations accretion                      | (240                    | )
|Future income tax                                           | (348                    | )
|Asset retirement expenditures                               | 1                       |  
|Stock-based compensation                                    | (837                    | )
|Net income                                                  | 3,279                   |  
|                                                            |                         |  
|Cash flow from operations per share(1):                     |                         |  
|Basic                                                       | $    0.56               |  
|Diluted                                                     | $    0.56               |  
|Net income per share:                                       |                         |  
|Basic                                                       | $    0.23               |  
|Diluted                                                     | $    0.23               |  
|Average number of shares outstanding:                       |                         |  
|Basic                                                       | 14,417,770              |  
|Diluted                                                     | 14,435,234              |  

(1)

Cash flow from operations is a non-GAAP measure that does not have a standardized meaning as prescribed by GAAP and is therefore unlikely to be comparable to similar measures presented by other oil and gas companies.  We consider it an important measure as it demonstrates our ability to generate the cash flow necessary to fund future growth through capital investment.

|($000s)                                   | 2004  |   | 2003    |   | % Change |  
|------------------------------------------ | ----- | - | ------- | - | -------- | -
|Cash flow from operating activities (GAAP) | (617  | ) | 32,720  |   | (102     | )
|Change in non-cash working capital (GAAP)  | 8,677 |   | (10,492 | ) | 183      |  
|Cash flow from operations (non-GAAP)       | 8,060 |   | 22,228  |   | (64      | )



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Quarterly Information



|Summary of Quarterly Information  |                    |  
|--------------------------------- | ------------------ | -
|($000s, except per share amounts) |                    |  
|                                  | 2004 Quarter ended |  
|                                  | December 31        |  
|Total revenues                    | 3,405              |  
|Net income                        | 1,108              |  
|Per basic share                   | 0.08               |  
|Per diluted share                 | 0.08               |  
|                                  |                    |  
|                                  | 2003 Quarter ended |  
|                                  | December 31        |  
|                                  | restated           |  
|Total revenues                    | 2,571              |  
|Settlement of litigation          | (1,000             | )
|Net income (loss)                 | (490               | )
|Per basic share                   | (0.04              | )
|Per diluted share                 | (0.04              | )



Net income for the year ended December 31, 2004 was $3.3 million, or $0.23 per share compared to a restated $17.1 million, or $1.18 per share, for 2003.



Net income for the fourth quarter ended December 31, 2004 was $1.1 million, or $0.08 per share compared to a restated loss of $490,000, or $0.04 per share in the 2003 comparative.  In the fourth quarter of 2004, we recorded a one-time benefit of an $841,000 reduction in income tax expense as a result of utilizing certain tax pools previously thought to be unusable.  During the fourth quarter of 2003, the loss was mainly as a result of the recognition of $1million of expense for settlement with the contingent interest grantees on the Kotaneelee litigation.



Cash flow from operations was $8.1 million, or $0.56 per share, in 2004, a 64% drop from 2003, where we had cash flow of $22.2 million, or $1.54 per share.



The decrease in net income and cash flow from operations is primarily attributable to the impact of the one-time settlement of the Kotaneelee litigation in the third quarter of 2003.  In addition, declining production volumes, higher depletion costs, higher lease operating costs and increased general and administrative expenses contributed to the decrease.



Impact of Conversion of Kotaneelee to a Working Interest



Effective May 1, 2004, we converted our 30.67% carried interest in the Kotaneelee field to a corresponding 30.67% working interest.  Although the conversion has no impact on the aggregate amounts of our share of field production and related field operating cash flow, the conversion has financial statement disclosure implications as discussed below.



Proceeds from carried interests decreased significantly from 2003 to 2004 and revenue from working interest natural gas sales increased significantly during the same period.  These changes are due to conversion of Kotaneelee to a working interest effective May 1, 2004.  Carried interest revenues in future periods are expected to be minimal.



Proceeds from carried interests represent passive net investment income in a net cash flow stream, and appropriately were recorded after the reduction of all royalties, lease operating costs and capital expenditures.  The conversion to a working interest at Kotaneelee and certain of our other properties in previous years represents a decision by us toward direct management of our oil and gas assets.



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As the majority of our carried interest revenue (prior to conversion) related to Kotaneelee, our carried interest revenues have decreased significantly.  Subsequent to May 1, 2004, sales from the Kotaneelee field are being reported as working interest natural gas sales while royalties and lease operating costs for Kotaneelee are being included under their respective captions.  As a result, working interest natural gas sales, royalties and lease operating expenses have increased significantly over comparable periods.



Capital expenditures for Kotaneelee are no longer a deduction from carried interest revenue but are instead recorded as capital asset additions on our balance sheet.



Petroleum and natural gas sales and carried interest



|Sales volumes               |        |  | 2004  |  | 2003  |  | % Change |  
|--------------------------- | ------ |  | ----- |  | ----- |  | -------- | -
|Natural gas                 |        |  |       |  |       |  |          |  
|Working interest            | mcf/d  |  | 4,492 |  | 1,887 |  | 138      |  
|Carried interest            | mcf/d  |  | 2,077 |  | 6,106 |  | (66      | )
|Royalty interest            | mcf/d  |  | 478   |  | 147   |  | 224      |  
|Total natural gas           | mcf/d  |  | 7,046 |  | 8,141 |  | (13      | )
|Oil and natural gas liquids | bbls/d |  | 31    |  | 31    |  | -        |  
|Combined (6:1)              | boe/d  |  | 1,206 |  | 1,388 |  | (13      | )



Sales volumes, on a boe basis, were 1,206 boe per day, down 13% from the 1,388 boe per day in 2003.  Expected production declines continue to affect our sales volumes for most of our areas with an average natural gas production rate of 7.0 mmcf/d in 2004 compared to 8.1 mmcf/d in 2003.  Although our natural gas working interest volumes increased 138% over last year, this is solely the result of the conversion of our Kotaneelee carried interest to a working interest, as noted above, which is also reflected in the decrease in natural gas carried interest volumes from last year.



Production from our Kotaneelee field continues to decline due to a combination of reservoir pressure declines and increased water production.  Our average net natural gas sales from Kotaneelee during 2004 were 4.7 mmcf/d, or approximately 65% of our total natural gas sales, with associated gross water production of 2,483 bbls/d, compared to averages of 6.1 mmcf/d (approximately 73% of total natural gas sales) and 1,452 bbls/d, respectively, for 2003.



Included in the natural gas working interest volumes for 2004 is an additional one-time amount of 274 mcf/d (46 boe/d) of sales which represents an extra month of Kotaneelee production.  Previous to the conversion to a working interest, Kotaneelee carried interest results had been reported with a one month lag.  With the conversion to a working interest, we obtain more timely access to revenue and operating cost information for the field.  Consequently, the 2004 results from operations reflect thirteen months of operating activity for the Kotaneelee field.



The natural gas production declines were offset by increased royalty interest volumes from our Town area in northeast British Columbia.  The operator drilled several successful wells in 2004 and our royalty volumes from this area increased 224% over last year.



Oil and natural gas liquids (NGLs) production remained constant from last year at 31 bbls/d.



|Revenues ($000s)            |  |  | 2004   |  | 2003   |  | % Change |  
|--------------------------- |  |  | ------ |  | ------ |  | -------- | -
|Natural gas                 |  |  |        |  |        |  |          |  
|Working interest            |  |  | 9,310  |  | 4,060  |  | 129      |  
|Carried interest (1)        |  |  | 3,381  |  | 8,749  |  | (61      | )
|Royalty interest            |  |  | 1,051  |  | 326    |  | 223      |  
|Total natural gas           |  |  | 13,742 |  | 13,135 |  | 5        |  
|Oil and natural gas liquids |  |  | 451    |  | 384    |  | 17       |  
|Total                       |  |  | 14,193 |  | 13,519 |  | 5        |  

(1)

Carried interest is net of related carried interest royalties, lease operating costs and capital.



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Our gross revenue from the sale of petroleum and natural gas in 2004 was 5% higher at $14.2 million, compared to $13.5 million in 2003.  Working interest revenue was significantly higher at $9.3 million in 2004 compared to $4.1 million in 2003.  This gain was mostly the result of the conversion of the Kotaneelee carried interest to a working interest.  A corresponding decrease in the carried interest revenues also results from this conversion.  Overall natural gas sales were $13.7 million in 2004, slightly higher than the $13.1 million received in 2003.  The natural declines in our natural gas working and carried interest producing properties were more than offset by the three-fold increase in royalty income received from our Town property.



Included in natural gas working interest revenue is $622,000 from Kotaneelee which represents an extra month of revenue, also relating to the conversion to a working interest during the year.



Oil and natural gas liquids revenue rose 17% to $451,000 in 2004 from $384,000 in 2003.  This increase is mainly due to the increase in product prices as production volumes were flat year-over-year.



|Average Sales Prices        |       |  | 2004  |  | 2003  |  | % Change |  
|--------------------------- | ----- |  | ----- |  | ----- |  | -------- | -
|Natural gas                 |       |  |       |  |       |  |          |  
|Working interest            | $/mcf |  | 5.66  |  | 5.89  |  | (4       | )
|Carried interest            | $/mcf |  | 5.76  |  | 5.76  |  | -        |  
|Royalty interest            | $/mcf |  | 6.01  |  | 6.05  |  | (1       | )
|Total natural gas           | $/mcf |  | 5.72  |  | 5.80  |  | (1       | )
|Oil and natural gas liquids | $/bbl |  | 39.24 |  | 34.23 |  | 15       |  
|Combined (6:1)              | $/boe |  | 34.43 |  | 34.77 |  | (1       | )

(1)

The average sales price for Carried interest is calculated before deducting the related carried interest royalties, lease operating costs and capital.



The overall average price we received upon sale of our oil and gas products in 2004 was relatively unchanged from that which we received in 2003.  A slight decrease in the natural gas price received for our working interest properties, $5.66 per mcf in 2004 versus $5.89 per mcf in 2003, was partially offset by higher oil prices.



Royalties



|($000s)                           |  |  | 2004  |  | 2003  |  | % Change |  
|--------------------------------- |  |  | ----- |  | ----- |  | -------- | -
|Crown royalties                   |  |  | 1,223 |  | 1,005 |  | 22       |  
|Freehold and GORR                 |  |  | 377   |  | 149   |  | 153      |  
|Total                             |  |  | 1,600 |  | 1,155 |  | 39       |  
|As % of working interest revenues |  |  | 15%   |  | 24%   |  | (38      | )



Total royalties increased 39% in 2004, totaling $1.6 million versus $1.2 million in 2003.  Royalties as a percentage of working interest revenues, however, dropped from 24% in 2003 to 15% in 2004.  The increase in royalty dollars, for crown and freehold and gross overriding royalty (GORR), and the decrease in the royalty rate are mainly a result of our conversion of the Kotaneelee carried interest to a working interest.  The crown royalty rate for the Kotaneelee property is approximately 10%, which is lower than the rate for the balance of our working interest properties.  Due to the significance of the Kotaneelee revenues and, therefore the royalties, this resulted in a lower overall corporate royalty rate.  Also impacting the 2004 royalties was an additional $81,000 representing the extra month of Kotaneelee operations relating to the elimination of the one-month lag discussed above.  A prior period crown royalty adjustment, recorded in 2004, contributed approximately 2% to the drop in the 2004 royalty rate.



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Lease Operating Costs



|($000s, except per boe)      | 2004  |  | 2003  |  | % Change |  
|---------------------------- | ----- |  | ----- |  | -------- | -
|Lease operating costs        | 1,548 |  | 1,258 |  | 23       |  
|Per working interest boe ($) | 5.42  |  | 9.98  |  | (46      | )



Lease operating costs increased 23% from $1.3 million in 2003 to $1.5 million in 2004.  Operating costs were higher in 2004 mainly due to the conversion of our interest at Kotaneelee to a working interest in May 2004.  After the conversion, operating costs from this area were recorded in lease operating costs whereas before, they were recorded net of carried interest revenues.  Lease operating costs attributable to Kotaneelee since the conversion amounted to $476,000.  Also impacting the 2004 lease operating costs is an additional $69,000 representing the extra month of Kotaneelee operations relating to the elimination of the one-month lag discussed above.



On a boe basis, lease operating costs dropped 46% in 2004 to $5.42 per boe from $9.98 per boe in 2003.  This drop is also largely due to the conversion of Kotaneelee to a working interest, where the operating costs averaged $2.48 per boe in 2004.



Interest and other income



|($000s)         | 2004  |  | 2003 |  | % Change | 
|--------------- | ----- |  | ---- |  | -------- | 
|Interest income | 914   |  | 799  |  | 14       | 
|Other           | 321   |  | 20   |  | 1,504    | 
|Total           | 1,235 |  | 819  |  | 51       | 



Interest and other income increased 51% in 2004.  Interest income increased 14% from $799,000 to $914,000 in 2004 as our average monthly balance of funds available for investment was higher in 2004 than in 2003 due to receiving the funds from settlement of the litigation in the last quarter of 2003.  This was somewhat offset by slightly lower yields in 2004.



Other income was significantly higher in 2004 as we received $300,000 in settlement of an outstanding issue relating to the carried interest revenues for the Buick Creek, Wargen and Clarke Lake properties from the year 2000.  Seismic sales, which make up the balance of other income, were relatively unchanged year-over-year.



General and Administrative



|($000s, except per boe)    | 2004  |  | 2003  |  | % Change |  
|-------------------------- | ----- |  | ----- |  | -------- | -
|General and administrative | 2,802 |  | 2,327 |  | 20       |  
|Legal                      | 539   |  | 727   |  | (26      | )
|Total                      | 3,341 |  | 3,054 |  | 9        |  
|Per boe ($)                | 7.57  |  | 6.03  |  | 26       |  



General and administrative costs, inclusive of legal expenses, increased 9% in 2004 to $3.3 millionfrom $3.1 million in 2003 primarily due to increased salaries and benefits and shareholder communication expenses.  The addition of three new employees in 2004 increased our salary and benefits expense by 142%, finishing the year with a full-time staff of 6, compared to 3 full-time staff members at the end of 2003.  As a result of the special shareholders meeting held late in the year, the related printing, mailing and proxy solicitation costs added $111,000, or 44%, to shareholders communication expense over 2003.



Legal expenses decreased 26% during 2004 to $539,000 compared to $727,000 in 2003.  The drop is primarily due to decreased legal work relating to the settlement of the Kotaneelee litigation in late 2003.  While legal costs related to the litigation have decreased due to the settlement, general corporate legal expenses increased over 2003 due to the update of corporate governance materials related to our continuance from Nova Scotia to Alberta, and new disclosure and corporate governance regulations that have been adopted in both Canada and the United States.

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We have been incurring significant administrative, auditing and legal expenses with respect to new SEC and accounting rules adopted pursuant to the Sarbanes-Oxley Act of 2002 (the Act).  Canadian regulators are also commencing to adopt new rules.  Such expenses will continue and may increase, particularly due to the requirements to document, test and audit our internal controls to comply with Section 404 of the Act, and rules adopted thereunder, that are anticipated to apply to us for the first time with respect to our annual report for the fiscal year ending December 31, 2006.



No general and administrative expenses were capitalized during the 2004 and 2003 periods.



Depletion and Depreciation



|($000s, except per boe)    | 2004  |  | 2003  |  | % Change | 
|-------------------------- | ----- |  | ----- |  | -------- | 
|Depletion and depreciation | 3,357 |  | 2,363 |  | 42       | 
|Per boe ($)                | 7.61  |  | 4.67  |  | 63       | 



Depletion and depreciation expense increased 42% in 2004 to $3.4 millionfrom $2.4 million in 2003.  Depletion and depreciation are a high percentage (19%, or taking into account those items excluded from the depletion calculation, 32%), in comparison with our peers, of the net book value of oil and gas properties and equipment mainly due to the limited expected life of the proven reserves at the Kotaneelee field.



In 2004, all costs incurred in drilling the Kotaneelee L-38 well were capitalized.  We have not recorded any depletion expense for the drilling costs of the L-38 well that commenced on August 22, 2004.  The well represents a major development project, and as the cumulative well costs to December 31, 2004 were $6.0 million (or approximately 34% of the net book value of capital assets as at December 31, 2004), inclusion of the amounts for depletion purposes would not represent a fair matching of revenues with expenses.  Had we included these costs in the depletable base, depletion for the fiscal year ended December 31, 2004 would have been $483,000 higher.  Once drilling of the well is completed and the results are known, we will include all drilling costs in the depletable base.



There is no assurance that the completion and testing of the L-38 well will result in a commercially viable well.  Whether or not it is successful, because of the large capital investment, in combination with the rest of our drilling during the winter 2004/2005 drilling season, we expect to record higher depletion rates in the future.  We could also experience a ceiling test impairment that would result in a material write-down of our oil and gas properties and equipment, if the L-38 well does not encounter additional proven reserves.



Asset Retirement Obligations Accretion



Asset retirement obligations accretion expense increased by 135% to $240,000 in 2004 compared with the restated amount of $102,000 in 2003.  The increase is mainly due to a full years inclusion of related liabilities resulting from the settlement of the Kotaneelee litigation in September 2003.  In connection with the settlement, the Company agreed to be responsible for its share of abandonment and reclamation liabilities at the Kotaneelee field when they occur.  At the time of settlement, it was estimated that our 30.67% share of the abandonment liabilities amounted to approximately $2,400,000 (undiscounted).



We have not included any asset retirement obligations for the Kotaneelee L-38 well that has recently been completed.  The commercial success or failure of the well is not yet known but if the well is ultimately determined to be capable of production, sufficient information is expected to be available at that time to estimate the components of the asset retirement obligation.  However, if the well is unsuccessful it would immediately be abandoned, with the related abandonment costs included in oil and gas property and equipment, subject to the ceiling test impairment mentioned above.



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Stock-based Compensation



Stock-based compensation expenseincreased to $837,000 in 2004 compared to $253,000 in 2003 after retroactive adoption of the Canadian Institute of Chartered Accountants (CICA) section 3870 (Stock-based Compensation and Other Stock-based Payments).  The increase is due to the number of options granted and the timing of vesting this year compared to last year.  In 2004, options granted to employees and directors totalled 325,000.  During 2003, only 80,000 stock options were granted.



Foreign Exchange



A foreign exchange loss of $96,000 was recorded in 2004, compared to a loss of $536,000 in 2003 on our U.S. dollar investments.  During the first half of 2004, the U.S. dollar was strong relative to the Canadian dollar, resulting in early foreign exchange gains.  However, growth in the value of the Canadian dollar relative to the U.S. dollar during the last half of the year resulted in exchanges losses that more than offset the gains recorded during the first half.



With the relative volatility between the U.S and Canadian dollar, we expect to record further foreign exchange gains or losses in the future, but cannot predict either with certainty.  The value of the Canadian dollar was U.S. $.8303 at December 31, 2004 compared to U.S. $.7724 at December 31, 2003.



Income Taxes



The income tax provision decreased to $1.1 million in 2004ascompared to the income tax provision of $11.3 million in 2003.  The large income tax provision in 2003 was attributable mainly to the taxable proceeds from settlement of the Kotaneelee litigation.  During the year ended December 31, 2004, our effective tax rate was 25.6% as compared to 39.8% for the year ended December 31, 2003.  During the first three quarters of the year ended December 31, 2004, the expected effective tax rate was 40%, down from 42% in 2003.  During the fourth quarter of 2004, we determined that we could utilize certain successor tax pools that were previously thought to be unusable.  As a result, we were able to access and utilize $1.9 million of successor tax pools that created a one time reduction of income tax expense of approximately $841,000, thereby reducing the effective tax rate for the year.



In 2003, we re-filed our tax returns for the taxation years of 1994 to 2002 inclusive.  On March 15, 2005, we received a preliminary audit adjustment letter from Canada Revenue Agency outlining the results of their review process.  We will not record any of the expected benefit until we formally receive the Notices of Reassessment.  Should the Notices of Reassessment be consistent with the preliminary audit adjustment letter, the benefit to us will be approximately $850,000.  This would result in a one time reduction of income tax expense.



Liquidity and Capital Resources



We recognize the need for a strong balance sheet in order to withstand volatile natural gas prices and to be able to capitalize on opportunities when or if they become available.  At December 31, 2004, we continued to enjoy a strong balance sheet and had no bank debt with approximately $39.4 million of cash and cash equivalents.  These funds are expected to be used for oil and gas exploration and development activities and for general corporate purposes.



Net cash flow used in operating activities during 2004 was $617,000 compared to cash flow provided from operating activities of $32.7 million during 2003.  The $33.3 million decrease in net cash flow from operating activities during 2004 is comprised of:



|($000s)                                            |         |  
|--------------------------------------------------- | ------- | -
|Decrease in cash flow from operations               | (14,168 | )
|Net changes in accounts receivable and other        | 1,121   |  
|Net changes in current liabilities                  | (1,802  | )
|Net changes in current income taxes payable         | (18,488 | )
|Decrease in net cash flow from operating activities | (33,337 | )



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The oil and gas business is inherently risky and capital intensive and can require significant capital and cash resources to expand and develop the business.



Our current cash flow from oil and gas operations is mainly derived from the Kotaneelee field.  Net field level receipts from Kotaneelee represented approximately 66% of our total net field receipts for the year ended December 31, 2004, compared to 79% in the same period of 2003.



Kotaneelee continues to experience a decrease in formation reservoir pressure, an increase in water production, and as a result, a decrease in gas production.  There is a possibility that our cash flow from Kotaneelee could either be significantly reduced or terminated at any time in the future.



In an effort to extend the remaining life of the B-38 well, during the spring of 2005, the operator is installing a siphon string in order to improve the lifting of the increasing amount of water.  We are participating to the extent of our working interest in the operation.  As the project is not yet complete, we do not know if, or to the degree of which, it will be successful in extending the economic life of the well.



Further development of the Kotaneelee field may assist with the recovery of the existing remaining reserves, and as well, identify additional reserves.  However, future development of Kotaneelee is highly risky due to the geographic location, geological complexity, depth and temperature of the producing formation, inherent risks of seismic interpretations and the costs of drilling.



Effective May 1, 2004, we converted from a 30.67% carried interest in the Kotaneelee natural gas field to a 30.67% working interest.  On May 3, 2004, we were served by the field operator with a notice to commence drilling the Kotaneelee L-38 development well in the third quarter of 2004.  Subsequent to our technical evaluation, we elected to participate to our full 30.67% working interest.  The notice from the operator to drill and case the proposed well included an estimated gross cost of $16.7 million, of which our share was to be approximately $5.1 million.



The well reached total depth on March 10, 2005 and due to the technical and drilling challenges experienced by the operator, gross drilling costs are estimated to be $29.5 million($9.0 million our share).  The L-38 well was completed in late March 2005 with estimated gross completion costs of $4.9 million ($1.5 million our share).  As part of the completion operation the well was flowed for a short period of time.  However, due to the warm weather in the area and the rapidly deteriorating ice bridges, the decision was made to suspend the flow and remove the drilling rig and test equipment to avoid paying standby charges.  Otherwise, the equipment would need to remain on location until approximately June when the river is open for barging operations.



While there is natural gas present, there is currently insufficient information to estimate expected flow rates or to estimate recoverable proven reserves.



Testing will be performed after the well is tied in during the second quarter of 2005.  Additional gross costs of $4.6 million ($1.4 million our share) are expected to be incurred for surface equipment and tie-in of the well for production.  Total costs for the project are estimated to be $39 million ($11.9 million our share), of which approximately 50% was incurred prior to year end and reflected in the financial statements for the year ended December 31, 2004.



We agreed with the operators decision to remove the drilling and testing equipment, and to incur the cost and risk of tying in prior to testing.  However, readers are cautioned that presently we do not have sufficient information to determine whether or not the well will be commercially successful.



At this time we are not aware of, and do not expect, further drilling to occur in the Kotaneelee area in the near future.  We believe that any such decision would only be considered subsequent to the receipt of positive production information from the L-38 well and a complete re-evaluation of our existing 2-D seismic data, or acquisition of new seismic data, in the area.



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In an effort to address the risks associated with our dependence on Kotaneelee, we have directed considerable resources toward other areas with the objective of diversifying our cash flow, production, and proven reserve base.  This includes evaluating and acquiring new mineral leases in areas of interest, acquisition of either trade or proprietary 2-D and 3-D seismic and evaluating certain asset and corporate acquisitions.  Given the high cost of acquisitions and their related reserves in the current market, we have concentrated our attention on growth through the drill bit.



Our northeast British Columbia properties are not as risky as Kotaneelee, but cannot be considered low risk due to depth of drilling, limited period of access to surface locations, and related costs.



We drilled two Company operated wells (one deep test and one shallow test) in the Mike/Hazel area of northeast British Columbia during the winter 2004/2005 drilling/construction season.  As a result of three separate land transactions, we acquired additional mineral rights lands in the area.  We are to pay 100% of the drilling and completion costs to earn 85% of the deep mineral rights on our deep test well.  The drilling costs for the A-19-L/94-H-2 well are estimated to be approximately $3.9 million net to us, of which approximately 26% was incurred prior to year end and is included in capital costs for the year.  We also drilled the shallower A-81-H/94-H-3 well in February 2005 on our 100% working interest lands at an estimated cost of $1.0 million.  Both of these wells were drilled and cased, however as a result of an unusually short winter drilling season due to early warm weather, we were unable to gain the necessary access for well completion and production testing programs.  We are currently examining the alternatives to test the two wells as soon as possible.



During the year ended December 31, 2004, we expended $11.5 million on capital additions as summarized below:



|Capital Expenditures($000s) | 2004   |  | 2003  |  | % Change |  
|--------------------------- | ------ |  | ----- |  | -------- | -
|Land and acquisitions       | 896    |  | 850   |  | 5        |  
|Geological and geophysical  | 1,151  |  | 1,789 |  | (36      | )
|Drilling and completion     | 8,749  |  | 1,850 |  | 373      |  
|Facilities and equipment    | 679    |  | 417   |  | 63       |  
|Other                       | 31     |  | 74    |  | (58      | )
|Total capital expenditures  | 11,506 |  | 4,980 |  | 131      |  
|Dispositions                | -      |  | -     |  | -        |  
|Net capital expenditures    | 11,506 |  | 4,980 |  | 131      |  



During the first quarter of 2005, further capital expenditures for land, seismic, drilling, workovers, equipment, and other activities are expected to be up to $11.1 million.



We have budgeted $16 million of capital expenditures on oil and gas activities during 2005.  Any management requests for additional capital in excess of this amount would acquire Board of Directors approval on an individual project basis.



In the near term, we expect to rely on internally generated cash flows and current cash on hand to fund our annual capital expenditure program.



Contractual Obligations



We do not use off-balance sheet arrangements.  We are committed to an operating lease for our office space and the future minimum rental payments and estimated operating costs to the end of lease are as follows:



|Year                          | ($000s) | 
|----------------------------- | -------- | 
|2005                          | 88       | 
|2006                          | 91       | 
|2007                          | 61       | 
|Total contractual obligations | 240      | 



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New Accounting Standards



Asset retirement obligations



Effective January 1, 2004, we have retroactively adopted the Canadian Institute of Chartered Accountants (CICA) Handbook section 3110 for accounting for asset retirement obligations.  This standard requires that the fair value of the legal obligation associated with the retirement and reclamation of tangible long-lived assets be recorded when the obligation is incurred, with a corresponding increase to the carrying amount of the related assets.  This corresponding increase to capitalized costs is amortized to earnings on a basis consistent with depletion of the underlying assets.  Subsequent changes in the estimated fair value of the asset retirement obligations will be capitalized and amortized over the remaining useful life of the underlying asset.



The asset retirement obligation liabilities are carried on the consolidated balance sheet at their discounted present value and are accreted over time for the change in their present value.  This standard was adopted retroactively and prior period amounts were restated.



Stock-based compensation



We have adopted the CICA Handbook section 3870, Stock-based Compensation and Other Stock-based Payments, which requires the use of the fair value method for valuing stock option grants.  Under this method, compensation cost attributable to stock options granted to employees and directors is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus.  Upon the exercise of the stock options, consideration paid is recorded as an increase to total capital.  This standard was adopted retroactively on January 1, 2004 and prior period amounts were restated.  Pursuant to the transition rules, the expense recognized applies to stock options granted on or after January 1, 2002.



Full cost accounting



Effective January 1, 2004, we adopted the CICA Accounting Guideline AcG-16 Oil and Gas Accounting  Full Cost.  Under the new guideline, future net revenues from total proven reserves used in the ceiling test calculation are estimated using expected future product prices and costs.  Prior to adopting this new standard, constant dollar pricing was used to test impairment.  There is no impact on our reported financial results for the year ended December 31, 2004 as a result of adopting this guideline.



Risks and Uncertainties



Set forth below are risk factors that could materially adversely affect our cash flow from operations, operating results and financial condition.



Competition



The natural gas and oil industry is highly competitive.  We experience competition in all aspects of our business, including acquiring reserves, leases, licenses and concessions, obtaining the equipment and labor needed to conduct operations and market natural gas and oil.  Our competitors include multinational energy companies, other independent natural gas and oil companies and individual producers and operators.  Because both natural gas and oil are fungible commodities, the principal form of competition with respect to product sales is price competition.  Many competitors have financial and other resources substantially greater than those available to us and, accordingly, may be better positioned to acquire and exploit prospects, hire personnel and market production.  In addition, many of our competitors may be better able to respond to factors such as changes in worldwide natural gas or oil prices, levels of production, the cost and availability of alternative fuels or the application of government regulations.  Such factors, which are beyond our control, may affect demand for our natural gas and oil production. We expect a high level of competition to continue.



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Dependence on one major property



During 2004, our core property at Kotaneelee contributed 65% of our total production.  Kotaneelee continues to experience a decrease in formation reservoir pressure, an increase in water production, and as a result, a decrease in natural gas production.  There is a possibility that our cash flow from Kotaneelee could either be significantly reduced or terminated at any time in the future.



Further development of the Kotaneelee field may assist with the recovery of the existing remaining reserves and identify additional reserves.  However, future development of Kotaneelee is highly risky due to the geographic location, geological complexity, depth and temperature of the producing formation, inherent risks of seismic interpretations and the costs of drilling.  Challenges encountered during the recent drilling of Kotaneelee L-38 well highlight the major risks associated with the property.  Due to the presence of numerous geological faults in the area, our seismic interpretation was challenging (geophysical risk) and resulted in the sidetrack drilling operation when the target formation (Nahanni) was not encountered.  Upon encountering the Nahanni Formation with the sidetrack operation, the next challenge to overcome was to attempt to encounter the fracture system (geological risk) that assists in natural gas production from this otherwise tight reservoir.  If a fracture system was not encountered, the well would most likely not be commercial.  Having successfully encountered a fracture system, the next risk is whether that fracture system is connected to commercial quantities of hydrocarbons.  As part of the completion operation the well was flowed for a short period of time.  However, due to the warm weather in the area and the rapidly deteriorating ice bridges, the decision was made to suspend the flow and remove the drilling rig and test equipment to avoid paying standby charges.  Otherwise, the equipment would need to remain on location until approximately June when the river is open for barging operations.  While there is natural gas present, there is currently insufficient information to estimate expected flow rates or to estimate recoverable proven reserves.  Testing will be performed after the well is tied in during the second quarter of 2005.  We agreed with the operators decision to remove the drilling and testing equipment, and to incur the cost and risk of tying in prior to testing.  However, readers are cautioned that presently we do not have sufficient information to determine whether or not the well will be commercially successful.  Therefore, the next group of major risks includes the sustainable production rates, the impact of this well on the other producing wells, if any, and the amount of water production (production risk).  As the water disposal facilities have a limited amount of capacity, when water production exceeds that capacity either additional capital would have to be spent to increase capacity or wells production would have to be reduced to decrease water production, which could ultimately lead to having the wells shut-in.  The decision as whether to expand water disposal facilities would be based on project economics at the time.  As such, the presence and predicted amounts of water are factors used by independent reserve evaluators in determining the amount of additional proved reserves, if any are discovered.



As a result of the geophysical and geological risks associated with the Kotaneelee L-38 well, the original gross estimated costs of the drilling project have almost doubled from $16 million to $30 million (exclusive of completion, equipping and tie-in costs) (cost risk).



Unless we can successfully drill for or acquire economically viable reserves of natural gas and crude oil in other areas, as our reserves at Kotaneelee deplete, our operating results may be materially adversely affected.



Exploration and development risks



Exploration and development of natural gas and oil involves a high degree of risk that no commercial production will be obtained or that the production will be insufficient to recover drilling and completion costs.  The costs of drilling, completing, and operating wells are sometimes uncertain, and cost overruns in exploration and development operations can adversely affect the economics of a project.  Our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including mineral lease title deficiencies, equipment failures, weather conditions, shortages or delays in sourcing qualified personnel, shortages or delays in the delivery of equipment, ability to access surface topography, compliance with governmental requirements, and fires and explosions. Furthermore, completion of a well does not ensure a profit on the investment or a recovery of the drilling, completion and tie-in costs.



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We cannot be certain that the exploratory or development wells we drill will be productive or that we will recover all or any portion of our investments.  In order to increase the chances for success, we often invest in seismic or other geoscience data to assist us in identifying potential drilling candidates.  Additionally, the cost of drilling, completing and testing wells is often uncertain at the time of our initial investment.  Depending on complications encountered while drilling, the final cost of the well may significantly exceed that which we originally estimated.



Commodity price fluctuations



Our products, including natural gas, NGLs and oil, and other hydrocarbon products, are commodities.  Because our contracts do not fix a long-term price for the products we purchase or sell, market changes in the price of such products can have a direct and immediate effect (whether favorable or adverse) upon our revenues and profitability.   Prices for products may be subject to material change in response to relatively minor changes in supply and demand, general economic conditions and other market conditions over which we have no control.  As the majority of our production is from natural gas sales, the price of crude oil does not have a large impact in our profitability.  Other conditions affecting our business include the level of domestic oil and gas production, the availability and prices of competing commodities and of alternative energy sources, the availability of local, intraprovincial and interprovincial transportation systems with adequate capacity, the proximity of gas production to gas pipelines and facilities, the availability of pipeline capacity, government regulation, the seasons, the weather and the impact of energy conservation efforts.



Access to additional mineral rights for expansion in the Yukon Territory



The Yukon Government has been attempting to resolve native land claim issues on presently un-leased acreage surrounding our Kotaneelee leases.  Until such time as these land claim issues have been resolved, we believe that no additional lands in the area will be leased for future oil and gas exploration and development.  With Kotaneelees remaining recoverable reserves rapidly depleting, it is possible that we may be required to abandon our field and facilities before they could be utilized as strategic assets to provide us with a competitive advantage in acquiring new mineral leases in the surrounding area.



Estimating reserves and future net cash flows risk



Estimating natural gas, natural gas liquids and crude oil reserves, and future net cash flows include numerous uncertainties, many of which may be beyond our control.  Such estimates are essential in our decision-making, as to whether further investment is warranted.  These estimates are derived from several factors and assumptions, some of which are:

·

reservoir characteristics based on variable geological, geophysical and engineering assessments;

·

future rates of production based on historical production draw-down rates;

·

future net cash flows based on commodity price/quality assumptions, production costs, taxes and investment decisions;

·

recoverable reserves based on estimated future net cash flows; and

·

compliance expectations based on assumed federal, provincial and environmental laws and regulations.



Ultimately, actual production rates, reserves recovered, commodity prices, production costs, government regulations or taxation may differ materially from those assumed in earlier reserve estimates.  Higher or lower differences could materially impact our production, revenues, production costs, depletion expense, taxes and capital expenditures.



Reserve estimates and net present values reported by us elsewhere in this document are based on independent third party estimated escalated commodity prices and associated production costs that are assumed for the life of the reserves.  Actual future prices and costs may be materially higher or lower.



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Replacement of reserves



In general, the rate of production from natural gas and oil properties declines as reserves are depleted.  The rate of decline depends on reservoir characteristics and other factors.  Except to the extent we acquire properties containing proved reserves or conduct successful exploration and development activities, or both, our estimated proved reserves will decline as reserves are produced.  Our future natural gas and oil production, and therefore cash flow from operations and net earnings, are highly dependent upon our level of success in finding or acquiring additional economically recoverable reserves.  The business of exploring for, developing and acquiring reserves is capital intensive.  To the extent cash flow from operations is reduced and external sources of capital become limited or unavailable, our ability to make the necessary capital investment to maintain or expand our asset base of natural gas and oil reserves could be materially impaired.



Risks pertaining to acquisitions and joint ventures



As part of implementing our business strategy, we may consider expanding our business through the acquisition of oil and gas properties or companies.  Our ability to expand in this manner would depend upon our ability to identify suitable acquisitions, complete the acquisitions, and effectively integrate any acquired assets or companies into our current business operations.  Suitable acquisitions, on terms acceptable to us, may not be available in the future or may require us to assume certain liabilities, including, without limitation, environmental liabilities, known or unknown.  Should suitable acquisition candidates be evaluated, we may require debt financing and/or additional equity to be raised to fund the acquisition.  As we currently have no debt and have not raised equity during the past few years, it is not certain that we could obtain suitable financing to close an acquisition.



Potential variability in quarterly operating results



The exploration for and development of oil and natural gas reserves depends on access to areas where operations are to be conducted.  Seasonal weather variations, including freeze-up and break-up affect access in certain circumstances.  Natural gas is used principally as a heating fuel and for power generation.  Accordingly, seasonal variations in weather patterns affect the demand for natural gas.  Depending on prevailing conditions, the prices received for sales of natural gas are generally higher in winter than summer months, while prices are generally higher in summer than spring and fall months.  Accordingly, any increase or decrease in our net operating revenues and their effects on profitability cannot be predicted.  Because of the seasonality of our business and continuous fluctuations in the prices of our products, our operating results for any past quarterly period may not necessarily be indicative of results for future periods and there can be no assurance that we will be able to maintain steady levels of profitability on a quarterly or annual basis in the future.



Operating hazards and uninsured risks



The oil and gas business involves a variety of operating risks, including fire, explosion, pipe failure, casing collapse, abnormally high pressured formations, adverse weather conditions, governmental and political actions, native rights, surface topography, limited or no access during summer months, premature reservoir declines, and environmental hazards such as oil spills, gas leaks and discharges of toxic gases.  The occurrence of any of these events with respect to any property operated or owned (in whole or in part) by us could have a material adverse impact on us. We, and the operators of our properties, maintain insurance in accordance with customary industry practices and in amounts that we believe to be reasonable.  However, insurance coverage is not always economically feasible and is not obtained to cover all types of operational risks.  The occurrence of a significant event that is not fully insured could have a material adverse effect on our financial condition.



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Drilling plans subject to change



A prospect is a property on which our geoscientists have identified what they believe, based on available seismic and geological information, to have indications of hydrocarbons.  Our prospects are in various stages of review. Whether or not we ultimately drill a prospect may depend on the following factors: receipt of additional seismic data or reprocessing of existing data and interpretation; material changes in oil or gas prices; the costs and availability of drilling equipment; success or failure of wells drilled in similar formations, availability of capacity in existing facilities and pipelines; availability and cost of capital; changes in the estimates of costs to drill or complete wells; our ability to attract other industry partners to acquire a portion of the working interest to reduce exposure to costs and drilling risks; decisions of our joint working interest owners; and restrictions imposed by governmental agencies.  We will continue to gather data about our prospects, and it is possible that additional information may cause us to alter our drilling schedule or determine that a prospect should not be pursued at all.



Shortage of supplies and equipment



Our ability to conduct operations in a timely and cost effective manner is subject to the availability of natural gas and crude oil field supplies, rigs, equipment and service crews.  Although none are expected currently, any shortage of certain types of supplies and equipment could result in delays in our operations as well as in higher operating and capital costs.



Restoration, safety and environmental risk



Certain laws and regulations exist that require companies engaged in petroleum activities to obtain necessary safety and environmental permits to operate.  Such legislation may restrict or delay us from conducting operations in certain geographical areas.  Further, such laws and regulations may impose liability on us for remedial and clean-up costs, personal injuries related to safety and environmental damages.



While our safety and environmental activities have been prudent and have enabled us to operate successfully in managing such risks, there can be no assurance that we will always be successful in protecting ourselves from the impact of all such risks.  Consistent with our growth in other areas, we seek opportunities for performance improvement in our operating practices.



Government regulation and environmental matters



We are subject to various federal and provincial laws and regulations including environmental laws and regulations. We believe that we are in substantial compliance with such laws and regulations, however, such laws and regulations may change in the future in a manner that will increase the burden and cost of compliance.  In addition, we could incur significant liability for damages, cleanup costs and penalties in the event of certain discharges into the environment.



Certain laws and governmental regulations may impose liability on us for personal injuries, clean-up costs, environmental damages and property damages, as well as administrative, civil and criminal penalties.  We maintain limited insurance coverage for sudden and accidental environmental damages, but do not maintain insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damage. Accordingly, we may be subject to liability or may be required to cease production from properties in the event of such damages.



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Kyoto Protocol risk



The Kyoto Protocol treaty (Protocol) was established in 1997 to reduce emissions of greenhouse gases (GHG) that are believed to be responsible for increasing the Earths surface temperatures and affecting the global climate change.  Canada ratified the Protocol in December 2002. Since the implementation of the Protocol, approximately 160 countries have committed to reduce GHG internationally.  Canada has committed to meet a 6% reduction of emission over base-year 1990 during the period 2008 to 2012.  Canadian government assurances of cost and volume limits suggest that incremental risks and liabilities attributable to addressing Protocol related policies are manageable.  It is not possible to predict the impact of how Protocol-related policies will ultimately be resolved and to what extent their impact will affect our future unit operating costs and capital expenditures.



Critical Accounting Estimates



Use of estimates



Inherent in the preparation of financial statements is the use of estimates and assumptions regarding certain assets, liabilities, revenues and expenses.  Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.  Accordingly actual results may differ from the estimated amounts.  Areas that involve the use of significant estimates critical to an understanding of our accounts are outlined below.



Full cost ceiling test calculations



We follow the full cost method of accounting for our oil and gas properties.  The full cost method requires us to calculate whenever there is an indication of impairment, a ceiling test or limitation of the amount of properties that can be capitalized on the balance sheet.



The ceiling test is a cost recovery test that compares the expected future net revenues from our oil and gas assets (adjusted for certain items) with the capitalized or net book value on the consolidated balance sheet.  If the capitalized costs on the consolidated balance sheet are in excess of the calculated ceiling, the excess must be immediately written off as an impairment loss.



Effective January 1, 2004, we adopted the CICA Accounting Guideline AcG-16 Oil and Gas Accounting  Full Cost.  Under the new guideline, future net revenues from total proved reserves used in the ceiling test calculation are estimated using expected future product prices and costs.  Prior to adopting this new standard, constant dollar pricing was used to test impairment.  There is no impact on our reported financial results for the year ended December 31, 2004 as a result of adopting this guideline.



The discounted present value of our proved natural gas, natural gas liquids, and oil reserves is a major component of the ceiling test calculation.  This component inherently contains many subjective judgments, such as projected future production rates, the timing of future expenditures, and the economic productive limit of our assets.  We utilize the resources of an independent reserves evaluator to evaluate all of our reserves on an annual basis.



The passage of time provides additional qualitative information regarding our reserves that could result in reserve revisions.  Significant decreases in proven reserves or product pricing could result in a full cost ceiling test writedown.



Significant changes in proven reserves will also impact the calculation of depletion.



Asset retirement obligations



The determination of the amount of asset retirement obligations, asset retirement costs, reclamation, and other similar activities is subject to the use of significant estimates and assumptions.  Such estimates include major items such as the remaining economic reserve life of a property as discussed above, the timing of abandonment, the costs related to the abandonment, and others.  Significant changes in any of the assumptions could alter the amount of asset retirement obligations and related accretion and depletion.

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Effective January 1, 2004, we retroactively adopted the CICA new standard for accounting for asset retirement obligations.  This standard requires that the fair value of the legal obligation associated with the retirement and reclamation of tangible long-lived assets be recorded when the obligation is incurred, with a corresponding increase to the carrying amount of the related assets.  This corresponding increase to capitalized costs is amortized to earnings on a basis consistent with depletion of the underlying assets. Subsequent changes in the estimated fair value of the asset retirement obligations are capitalized and amortized over the remaining useful life of the underlying asset.



The asset retirement obligation liabilities are carried on the consolidated balance sheet at their discounted present value and are accreted over time for the change in their present value.  This standard was adopted retroactively on and prior period amounts were restated.



Stock-based compensation



We have adopted the Canadian accounting standard as outlined in the CICA Handbook Section 3870, Stock-based Compensation and Other Stock-based Payments, which requires the use of the fair value method for valuing stock option grants.  Under this method, compensation cost attributable to stock options is measured at fair value at the grant date and expensed over the vesting period with a corresponding increase to contributed surplus.  Upon the exercise of the stock options, consideration paid is recorded as an increase to total capital.  This standard was adopted retroactively on January 1, 2004 and prior period amounts were restated.  Pursuant to the transition rules, the expense recognized applies to stock options granted on or after January 1, 2002.



For U.S. GAAP reporting purposes, we have elected to adopt the fair value expense recognition provisions of Financial Accounting Standard (FAS) 123 Accounting for Stock-based Compensation and have reported using the modified prospective method.  This method provides prospective expense recognition for all new awards and the unvested portion of awards granted subsequent to January 1, 1995.



Revenue recognition



Revenue is recorded in the period when the proceeds become receivable and measurable and collection is reasonably assured.  Under certain agreements we receive oil and natural gas revenues net of operating and capital costs incurred by the working interest participants.  The time the net revenues become receivable and collection is reasonably assured depends on the terms and conditions of the relevant agreements and the practices followed by the operator.  As a result, reported net revenues may lag the production month by one or more months.



Related party transactions



Mr. Timothy L. Largay was a director of Canada Southern until June 15, 2004.  Mr. Largay is also a partner in the law firm Murtha Cullina, which acts as the Companys U.S. securities counsel.  During 2004, Murtha Cullina was paid fees of $268,793 for legal services ($134,135 for 2003).



Additional information



Additional information relating to Canada Southern may be found on our website at http://www.cansopet.com, on the Canadian Securities Administrators website at www.sedar.com and on the EDGAR section of the U.S. Securities and Exchange Commissions website at www.sec.gov.



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