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, 2005 and 2004.  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 12 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 Managements Discussion and Analysis includes references to financial measures commonly used in the oil and gas industry, such as funds from operations (expressed before changes in non-cash working capital) and funds 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 2005 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 22, 2006



Overview

|                                             |                                 |   |                          |   |          |   |        |   |        |   |          |  
|-------------------------------------------- | ------------------------------- | - | ------------------------ | - | -------- | - | ------ | - | ------ | - | -------- | -
|                                             | Three months ended
December 31, |   | Year  ended
December 31, |  
|($000s, except share amounts)                | 2005                            |   | 2004                     |   | %
Change |   | 2005   |   | 2004   |   | %
Change |  
|                                             |                                 |   |                          |   |          |   |        |   |        |   |          |  
|Petroleum and natural gas sales              | 6,337                           |   | 4,080                    |   | 55       |   | 20,371 |   | 11,513 |   | 77       |  
|Royalties                                    | (1,010                          | ) | (472                     | ) | 114      |   | (2,806 | ) | (1,600 | ) | 75       |  
|Carried interest                             | 61                              |   | (100                     | ) | -        |   | 67     |   | 3,381  |   | (98      | )
|Lease operating costs                        | (348                            | ) | (503                     | ) | (31      | ) | (1,868 | ) | (1,548 | ) | 21       |  
|Transportation                               | (556                            | ) | (351                     | ) | 58       |   | (2,192 | ) | (701   | ) | 213      |  
|Operating netback                            | 4,484                           |   | 2,654                    |   | 69       |   | 13,572 |   | 11,045 |   | 23       |  
|Interest and other income                    | 186                             |   | 248                      |   | (25      | ) | 779    |   | 1,235  |   | (37      | )
|General and administrative                   | (838                            | ) | (903                     | ) | (7       | ) | (2,931 | ) | (3,341 | ) | (12      | )
|Foreign exchange losses                      | (49                             | ) | (86                      | ) | (43      | ) | (107   | ) | (96    | ) | 11       |  
|Asset retirement expenditures                | (5                              | ) | -                        |   | -        |   | (8     | ) | (1     | ) | 700      |  
|Current income tax recovery (expense)        | 99                              |   | 478                      |   | (79      | ) | 1,178  |   | (782   | ) | -        |  
|Funds from operations(1)                     | 3,877                           |   | 2,391                    |   | 62       |   | 12,483 |   | 8,060  |   | 55       |  
|Depletion and depreciation                   | (1,864                          | ) | (939                     | ) | 99       |   | (6,995 | ) | (3,357 | ) | 108      |  
|Asset retirement obligations accretion       | (51                             | ) | (60                      | ) | 15       |   | (256   | ) | (240   | ) | 7        |  
|Future income tax recovery (expense)         | (565                            | ) | 56                       |   | -        |   | (1,170 | ) | (348   | ) | 236      |  
|Asset retirement expenditures                | 5                               |   | -                        |   | -        |   | 8      |   | 1      |   | 700      |  
|Stock-based compensation                     | (101                            | ) | (340                     | ) | (70      | ) | (512   | ) | (837   | ) | (39      | )
|Net income                                   | 1,301                           |   | 1,108                    |   | 17       |   | 3,558  |   | 3,279  |   | 9        |  
|                                             |                                 |   |                          |   |          |   |        |   |        |   |          |  
|Funds from operations per share(1):          |                                 |   |                          |   |          |   |        |   |        |   |          |  
|Basic ($)                                    | 0.26                            |   | 0.17                     |   | 53       |   | 0.86   |   | 0.56   |   | 54       |  
|Diluted ($)                                  | 0.26                            |   | 0.17                     |   | 53       |   | 0.86   |   | 0.56   |   | 54       |  
|Net income per share:                        |                                 |   |                          |   |          |   |        |   |        |   |          |  
|Basic ($)                                    | 0.09                            |   | 0.08                     |   | 13       |   | 0.25   |   | 0.23   |   | 9        |  
|Diluted ($)                                  | 0.09                            |   | 0.08                     |   | 13       |   | 0.25   |   | 0.23   |   | 9        |  
|Average number of shares outstanding (000s): |                                 |   |                          |   |          |   |        |   |        |   |          |  
|Basic                                        | 14,493                          |   | 14,418                   |   | 1        |   | 14,453 |   | 14,418 |   | -        |  
|Diluted                                      | 14,505                          |   | 14,465                   |   | -        |   | 14,488 |   | 14,435 |   | -        |  

(1)

Funds 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.

|                                                     |                                 |   |                         |   |          |  |        |  |       |   |          | 
|---------------------------------------------------- | ------------------------------- | - | ----------------------- | - | -------- |  | ------ |  | ----- | - | -------- | 
|                                                     | Three months ended December 31, |   | Year ended December 31, |  
|($000s)                                              | 2005                            |   | 2004                    |   | % Change |  | 2005   |  | 2004  |   | % Change | 
|Cash flow from (used in) operating activities (GAAP) | 3,918                           |   | 2,900                   |   | -        |  | 10,734 |  | (617  | ) | -        | 
|Change in non-cash working capital (GAAP)            | (41                             | ) | (509                    | ) | -        |  | 1,749  |  | 8,677 |   | -        | 
|Funds from operations (non-GAAP)                     | 3,877                           |   | 2,391                   |   | 62       |  | 12,483 |  | 8,060 |   | 55       | 



Quarterly Information



|                                  |                    |  |              |  |         |  |          | 
|--------------------------------- | ------------------ |  | ------------ |  | ------- |  | -------- | 
|Summary of Quarterly Information  |                    | 
|($000s, except per share amounts) |                    | 
|                                  | 2005 Quarter ended | 
|                                  | December 31        |  | September 30 |  | June 30 |  | March 31 | 
|Total revenues, net of royalties  | 5,574              |  | 6,068        |  | 3,732   |  | 3,037    | 
|Net income                        | 1,301              |  | 1,003        |  | 1,146   |  | 108      | 
|Per basic share                   | 0.09               |  | 0.07         |  | 0.08    |  | 0.01     | 
|Per diluted share                 | 0.09               |  | 0.07         |  | 0.08    |  | 0.01     | 
|                                  |                    |  |              |  |         |  |          | 
|                                  | 2004 Quarter ended | 
|                                  | December 31        |  | September 30 |  | June 30 |  | March 31 | 
|Total revenues, net of royalties  | 3,756              |  | 3,521        |  | 3,782   |  | 3,470    | 
|Net income                        | 1,108              |  | 445          |  | 570     |  | 1,156    | 
|Per basic share                   | 0.08               |  | 0.03         |  | 0.04    |  | 0.08     | 
|Per diluted share                 | 0.08               |  | 0.03         |  | 0.04    |  | 0.08     | 



Funds from Operations



|                          |                                 |  |                          |  |          |  |        |  |       |  |          | 
|------------------------- | ------------------------------- |  | ------------------------ |  | -------- |  | ------ |  | ----- |  | -------- | 
|($000s, except per share) | Three months ended
December 31, |  | Year  ended
December 31, | 
|                          | 2005                            |  | 2004                     |  | % Change |  | 2005   |  | 2004  |  | % Change | 
|Funds from operations     | 3,877                           |  | 2,391                    |  | 62       |  | 12,483 |  | 8,060 |  | 55       | 
|Per share:                |                                 |  |                          |  |          |  |        |  |       |  |          | 
|Basic($)                  | 0.26                            |  | 0.17                     |  | 53       |  | 0.86   |  | 0.56  |  | 54       | 
|Diluted ($)               | 0.26                            |  | 0.17                     |  | 53       |  | 0.86   |  | 0.56  |  | 54       | 



Funds from operations for the three months ended December 31, 2005 were $3.9 million, or $0.26 per share, up 53% over the same quarter in 2004.  For the year ended December 31, 2005, funds from operations were $12.5 million or $0.86 per share, 54% higher than in 2004.  The increases were mainly due to higher commodity prices realized in 2005, particularly during the third and fourth quarters.  The higher commodity prices more than offset the 8% decline in production experienced over the year.  We also realized a recovery of current income taxes as a result of a prior period re-filing of our income tax returns from 1994 to 2002.



Net Income



|                          |                                 |  |                          |  |          |  |       |  |       |  |          | 
|------------------------- | ------------------------------- |  | ------------------------ |  | -------- |  | ----- |  | ----- |  | -------- | 
|($000s, except per share) | Three months ended
December 31, |  | Year  ended
December 31, | 
|                          | 2005                            |  | 2004                     |  | % Change |  | 2005  |  | 2004  |  | % Change | 
|Net income                | 1,301                           |  | 1,108                    |  | 17       |  | 3,558 |  | 3,279 |  | 9        | 
|Per share:                |                                 |  |                          |  |          |  |       |  |       |  |          | 
|Basic($)                  | 0.09                            |  | 0.08                     |  | 13       |  | 0.25  |  | 0.23  |  | 9        | 
|Diluted ($)               | 0.09                            |  | 0.08                     |  | 13       |  | 0.25  |  | 0.23  |  | 9        | 



Net income for the three month period ended December 31, 2005 was 17% higher than the previous year, with higher commodity prices realized during the quarter more than offsetting production declines.  Higher revenues for the fourth quarter of 2005, together with lower lease operating costs, were also tempered somewhat by higher depletion costs and higher transportation costs.



For the twelve months ended December 31, 2005, net income was $3.6 million, or $0.25 per share, 9% higher than the net income for the twelve months of 2004.  Higher commodity prices, lower general and administrative expenses and the recovery of current income taxes were offset by higher depletion charges and higher transportation costs.



Petroleum and natural gas sales and carried interest



|                            |       |  |                                 |  |                          |   |          |   |       |  |       |  |          |  
|--------------------------- | ----- |  | ------------------------------- |  | ------------------------ | - | -------- | - | ----- |  | ----- |  | -------- | -
|Sales volumes               |       |  | Three months ended
December 31, |  | Year  ended
December 31, |  
|                            |       |  | 2005                            |  | 2004                     |   | % Change |   | 2005  |  | 2004  |  | % Change |  
|Natural gas                 |       |  |                                 |  |                          |   |          |   |       |  |       |  |          |  
|Working interest            | mcf/d |  | 5,634                           |  | 6,519                    |   | (14      | ) | 6,033 |  | 4,492 |  | 34       |  
|Royalty interest            | mcf/d |  | 383                             |  | 483                      |   | (21      | ) | 425   |  | 478   |  | (11      | )
|Carried interest            | mcf/d |  | 2                               |  | (57                      | ) | -        |   | 2     |  | 2,077 |  | (100     | )
|Total natural gas           | mcf/d |  | 6,019                           |  | 6,945                    |   | (13      | ) | 6,460 |  | 7,046 |  | (8       | )
|Oil and natural gas liquids | bbl/d |  | 19                              |  | 39                       |   | (52      | ) | 27    |  | 31    |  | (14      | )
|Combined (6:1)              | boe/d |  | 1,022                           |  | 1,196                    |   | (15      | ) | 1,104 |  | 1,206 |  | (8       | )



Sales volumes for the fourth quarter averaged 1,022 boe/d, 15% lower than the average for the comparable quarter in 2004.  Steady production from the Kotaneelee L-38 well, which came on production in May 2005 and at December 31, 2005 was still adding 3.9 mmcf/d to our sales volumes, was offset by significant declines at the Kotaneelee B-38 and I-48 wells.



For the year, our sales volumes averaged 1,104 boe/d, slightly below the 1,206 boe/d averaged during 2004.  The production addition of Kotaneelee L-38 was mostly offset by the production declines, most significantly by the Kotaneelee B-38 and I-48 wells; however, L-38 has only been on production for eight of the twelve months in 2005.  As a result, the 2005 versus 2004 year to date comparison is not representative of the full year impact.



Production from our Kotaneelee field continues to contribute the majority of our sales volumes.  Our average net natural gas sales from Kotaneelee during the fourth quarter of 2005 were 4.2 mmcf/d, or approximately 70% of our total natural gas sales.  This compares to 67% of total gas sales during the fourth quarter last year.  The increase is attributable to the addition of Kotaneelee L-38 volumes beginning in May 2005.  As the new wells at Mike/Hazel and Buick Creek are brought on stream they will represent an increasing amount of the total production for the company.



Sales volumes were reduced during the second and third quarters of 2005 by a scheduled turnaround at the third-party Duke McMahon Gas Plant.  Production from the Buick Creek and Siphon fields were shut-in from June 21to July 9, 2005.



Although our natural gas working interest volumes increased 34% over the prior years comparative, this is mainly the result of the conversion of our Kotaneelee carried interest to a working interest, as noted below, which is also reflected in the decrease in natural gas carried interest volumes from last year.



Consistent with our strategy to diversify the concentration risk of our production away from Kotaneelee, during the first quarter of 2006, we tied in our two operated wells at Mike/Hazel and one operated and two non-operated wells at Buick Creek.  As such, we anticipate future volumes to increase as we continue to acquire new lands and develop prospects to execute this growth and diversification strategy.



Due to a scheduled turnaround at the third-party Duke Fort Nelson Gas Plant, we expect that both our Kotaneelee and Clarke Lake fields will be impacted during the majority of the month of July 2006.  As a result, we expect our third quarter 2006 volumes to be negatively impacted.



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.



Prior to the conversion, the majority of our carried interest revenue related to Kotaneelee.  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 expenses, transportation costs, and capital expenditures.



Since May 1, 2004, sales from the Kotaneelee field are being reported as working interest natural gas sales while related royalties, lease operating expenses and transportation costs are being included under their respective captions.  As a result, working interest natural gas sales, royalties, lease operating expenses, and transportation costs have increased significantly over comparable periods and proceeds of carried interests has decreased accordingly.



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.



Carried interest revenues in 2005 are, and in future periods are expected to be, minimal.  During the fourth quarter of 2005, we received $58,000 relating to a previous years joint venture audit recovery at Kotaneelee.





|                            |  |  |                                 |  |                          |   |          |   |        |  |        |  |          |  
|--------------------------- |  |  | ------------------------------- |  | ------------------------ | - | -------- | - | ------ |  | ------ |  | -------- | -
|Revenues ($000s)            |  |  | Three months ended
December 31, |  | Year  ended
December 31, |  
|                            |  |  | 2005                            |  | 2004                     |   | % Change |   | 2005   |  | 2004   |  | % Change |  
|Natural gas                 |  |  |                                 |  |                          |   |          |   |        |  |        |  |          |  
|Working interest            |  |  | 5,766                           |  | 3,647                    |   | 58       |   | 18,496 |  | 10,012 |  | 85       |  
|Royalty interest            |  |  | 443                             |  | 267                      |   | 66       |   | 1,329  |  | 1,051  |  | 26       |  
|Carried interest(1)         |  |  | 62                              |  | (100                     | ) | -        |   | 67     |  | 3,381  |  | (98      | )
|Total natural gas           |  |  | 6,271                           |  | 3,815                    |   | 64       |   | 19,893 |  | 14,444 |  | 38       |  
|Oil and natural gas liquids |  |  | 128                             |  | 165                      |   | (23      | ) | 546    |  | 450    |  | 21       |  
|Total                       |  |  | 6,398                           |  | 3,980                    |   | 61       |   | 20,439 |  | 14,894 |  | 37       |  

(1)

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



Commodity prices remained very strong in the fourth quarter this year and were the major factor in the 61% increase in petroleum and natural gas revenues versus the fourth quarter last year.   The higher commodity prices more than offset the 15% decline in quarterly sales volumes noted above.



For the twelve months ended December 31, 2005, the 2004 conversion of the Kotaneelee carried interest to a working interest in May also contributed to the 37% increase in revenues in two ways.  First, revenue was recorded under working interest revenues in all of the twelve months of 2005 as opposed to treatment as carried interest revenues during the first four months of 2004.  Also, transportation costs after conversion are recorded separately from revenue, as an expense, whereas before conversion, they were treated as a reduction from carried interest revenue.  A corresponding decrease in the carried interest revenues also resulted from this conversion.



|                            |       |  |                                 |  |                          |  |          |  |       |  |       |  |          | 
|--------------------------- | ----- |  | ------------------------------- |  | ------------------------ |  | -------- |  | ----- |  | ----- |  | -------- | 
|Average Sales Prices        |       |  | Three months ended
December 31, |  | Year  ended
December 31, | 
|                            |       |  | 2005                            |  | 2004                     |  | % Change |  | 2005  |  | 2004  |  | % Change | 
|Natural gas                 |       |  |                                 |  |                          |  |          |  |       |  |       |  |          | 
|Working interest            | $/mcf |  | 11.13                           |  | 6.08                     |  | 83       |  | 8.40  |  | 6.09  |  | 38       | 
|Royalty interest            | $/mcf |  | 12.58                           |  | 6.02                     |  | 109      |  | 8.57  |  | 6.01  |  | 43       | 
|Carried interest(1)         | $/mcf |  | -                               |  | -                        |  | -        |  | -     |  | 5.76  |  | -        | 
|Total natural gas           | $/mcf |  | 11.33                           |  | 6.23                     |  | 82       |  | 8.44  |  | 5.99  |  | 41       | 
|Oil and natural gas liquids | $/bbl |  | 74.45                           |  | 45.90                    |  | 62       |  | 55.17 |  | 39.15 |  | 41       | 
|Combined (6:1)              | $/boe |  | 68.09                           |  | 36.29                    |  | 88       |  | 50.74 |  | 36.01 |  | 41       | 

(1)

The average sales price for Carried interest is calculated before deducting the related carried interest royalties, lease operating expenses, transportation costs, and capital.  Carried interest revenue for the three and twelve months ending December 31, 2005 was not material.



Natural gas prices continued to rise during the fourth quarter of 2005, averaging 21% higher than the third quarter this year and 83% higher than the fourth quarter last year.  Market factors contributing to the rise in North American natural gas prices include continuing worldwide high oil prices and the extensive damage to oil and gas production facilities by the hurricanes in the Gulf of Mexico.  These lofty fourth quarter prices helped to bring our annual average natural gas price to $8.44/mcf, 41% higher than the 2004 average.



During the first quarter of 2006 natural gas prices have declined by almost 50% from their highs in December 2005, due mainly to decreases in demand as a result of an unseasonably mild winter in North America.



We continue to take more of our gas in kind from our properties as their long-term sales contracts expire.   Gas from our Siphon and Buick Creek properties was taken in kind commencing August 1, and November 1, 2005, respectively.  We now control the marketing of the majority of our gas, which is currently being sold on a daily basis on the spot market.



Royalties



|                                  |  |  |                                 |  |                          |  |          |  |       |  |       |  |          | 
|--------------------------------- |  |  | ------------------------------- |  | ------------------------ |  | -------- |  | ----- |  | ----- |  | -------- | 
|($000s)                           |  |  | Three months ended
December 31, |  | Year  ended
December 31, | 
|                                  |  |  | 2005                            |  | 2004                     |  | % Change |  | 2005  |  | 2004  |  | % Change | 
|Crown royalties                   |  |  | 735                             |  | 364                      |  | 102      |  | 2,279 |  | 1,223 |  | 86       | 
|Freehold and GORR                 |  |  | 276                             |  | 109                      |  | 154      |  | 527   |  | 377   |  | 40       | 
|Total                             |  |  | 1,010                           |  | 472                      |  | 114      |  | 2,806 |  | 1,600 |  | 75       | 
|As % of working interest revenues |  |  | 17%                             |  | 12%                      |  | 38       |  | 15%   |  | 15%   |  | -        | 



Total royalties increased by 114% in the fourth quarter of 2005, and by 75% for the twelve month period ended December 31, 2005.  Royalties as a percentage of working interest revenues amounted to 17% during the fourth quarter of 2005, compared to 12% during the same quarter last year.  This increase results mainly from higher gas prices and an adjustment during the fourth quarter this year to certain properties over-riding royalties.



For the twelve months ended December 31, 2005 and 2004, the 75% increase in absolute amounts for royalties this year as compared with last year was a function of higher revenues, the result of higher product prices, and treatment of Kotaneelee as a carried interest in the first four months of 2004.  Royalties as a percentage of working interest revenues, however, remained consistent at 15%.



During the third quarter this year, we were able to take advantage of British Columbias Summer Oil and Gas Royalty Program by drilling the two 100% working interest wells at Siphon and Buick Creek.  As a result of this program, which provides a royalty credit of up to $100,000 per new well drilled, we expect our royalties to decrease in 2006 by approximately $150,000 to $175,000.



Lease Operating Costs



|                             |                                 |  |                          |  |          |   |       |  |       |  |          |  
|---------------------------- | ------------------------------- |  | ------------------------ |  | -------- | - | ----- |  | ----- |  | -------- | -
|($000s, except per boe)      | Three months ended
December 31, |  | Year  ended
December 31, | 
|                             | 2005                            |  | 2004                     |  | % Change |   | 2005  |  | 2004  |  | % Change |  
|Lease operating costs        | 348                             |  | 503                      |  | (31      | ) | 1,868 |  | 1,548 |  | 21       |  
|Per working interest boe ($) | 3.95                            |  | 4.86                     |  | (19      | ) | 4.96  |  | 5.42  |  | (9       | )



Lease operating costs decreased 31% from the fourth quarter last year to the fourth quarter of 2005 due mainly to a prior period facility equalization of $61,000 received in the fourth quarter of 2005 for the Buick Creek facility.  Also contributing to the lower fourth quarter expenses was reduced processing and gathering fees as certain of these costs were being recorded under transportation expenses in 2005 versus 2004 when, prior to taking our gas in kind, we were unable to identify transportation costs separately.  On a boe basis, lease operating costs were 19% lower during the fourth quarter compared to the fourth quarter in 2004.  The reduced dollars expended on operating costs were offset somewhat by the lower sales volumes recorded in 2005.



For the years ended December 31, 2005 and 2004, lease operating costs increased by 21% year-over-year, due mainly to the conversion of Kotaneelee from a carried to a working interest in the 2004 comparative period.  Prior to the conversion, operating costs from Kotaneelee were recorded as a reduction of carried interest revenues as opposed to operating costs.  On a boe basis, lease operating costs dropped 9% from last year, also largely due to the conversion of Kotaneelee to a working interest, where the operating costs averaged $3.02/boe for 2005.  We believe that our lease operating costs on a per boe basis compare favorably with our competition.



Transportation



|                             |                                 |  |                          |  |          |  |       |  |      |  |          | 
|---------------------------- | ------------------------------- |  | ------------------------ |  | -------- |  | ----- |  | ---- |  | -------- | 
|($000s, except per boe)      | Three months ended
December 31, |  | Year  ended
December 31, | 
|                             | 2005                            |  | 2004                     |  | % Change |  | 2005  |  | 2004 |  | % Change | 
|Transportation               | 556                             |  | 351                      |  | 58       |  | 2,192 |  | 701  |  | 213      | 
|Per working interest boe ($) | 6.31                            |  | 3.39                     |  | 86       |  | 5.82  |  | 2.45 |  | 137      | 



The increase in transportation costs for the three months ended December 31, 2005, compared to the same period in 2004, was due mainly to the impact of us taking our gas in kind.  In the 2004 comparative period when we were not marketing our own gas, we were unable to identify the transportation cost component for the Kotaneelee, Buick Creek, Siphon, and Clarke Lake areas.  As a result, in the 2004 comparative period certain of the transportation costs were included in lease operating costs as discussed above.



For the twelve months ended December 31, 2005 and 2004, transportation costs were $2.2 million and $701,000 respectively. These costs result almost entirely (95%) from the transportation of our gas at Kotaneelee and have increased due to commencement of production at the L-38 well during the second quarter of 2005.  In addition to that shown in the 2004 comparative above, transportation costs of $286,000 were also expended in 2004; however they were included as a reduction of carried interest revenues for financial statement purposes.



For gas, we consider transportation to include all downstream costs commencing from the point that the gas is transferred to a transmission system for delivery to the ultimate sales point.  As a result, transportation costs may also include certain processing costs at third party extraction and acid gas processing plants.



Operating Netbacks



|                                |                                 |   |                          |   |          |   |       |   |       |   |          |  
|------------------------------- | ------------------------------- | - | ------------------------ | - | -------- | - | ----- | - | ----- | - | -------- | -
|($/boe)                         | Three months ended
December 31, |   | Year  ended
December 31, |  
|                                | 2005                            |   | 2004                     |   | % Change |   | 2005  |   | 2004  |   | % Change |  
|Petroleum and natural gas sales | 67.42                           |   | 37.06                    |   | 82       |   | 50.57 |   | 26.09 |   | 94       |  
|Royalties                       | (10.75                          | ) | (4.29                    | ) | 151      |   | (6.97 | ) | (3.63 | ) | 92       |  
|Carried interest                | 0.66                            |   | (0.92                    | ) | -        |   | 0.17  |   | 7.66  |   | (98      | )
|Net revenues                    | 57.32                           |   | 31.85                    |   | 80       |   | 43.77 |   | 30.12 |   | 45       |  
|Lease operating costs           | (3.70                           | ) | (4.57                    | ) | (19      | ) | (4.64 | ) | (3.51 | ) | 32       |  
|Transportation                  | (5.91                           | ) | (3.19                    | ) | 86       |   | (5.44 | ) | (1.59 | ) | 243      |  
|Operating netback               | 47.71                           |   | 24.09                    |   | 98       |   | 33.69 |   | 25.03 |   | 35       |  



Operating netbacks were higher for the three and twelve months ended December 31, 2005, when compared to the prior year periods, due mainly to the increase in commodity prices.  Higher prices were somewhat offset by higher royalties and higher transportation costs.



The figures in this table represent the netbacks calculated on a total boe basis, including carried interest and royalty income volumes.  The tables in the preceding paragraphs contain values that are calculated on a working interest boe basis, which exclude carried interest and royalty income volumes.  In those tables, it provides a better comparison to prior year values where there was a significant component of carried interest revenues.  Given that the carried interest component is no longer material, we expect that commencing in the first quarter of 2006 we will provide data in the relevant tables on a total boe basis.



Interest and Other Income



|                |                                 |  |                          |  |          |   |      |  |       |  |          |  
|--------------- | ------------------------------- |  | ------------------------ |  | -------- | - | ---- |  | ----- |  | -------- | -
|($000s)         | Three months ended
December 31, |  | Year  ended
December 31, | 
|                | 2005                            |  | 2004                     |  | % Change |   | 2005 |  | 2004  |  | % Change |  
|Interest income | 183                             |  | 242                      |  | (25      | ) | 761  |  | 914   |  | (17      | )
|Other           | 3                               |  | 6                        |  | (50      | ) | 18   |  | 321   |  | (94      | )
|Total           | 186                             |  | 248                      |  | (25      | ) | 779  |  | 1,235 |  | (37      | )



Interest and other income decreased 25% in the fourth quarter of 2005 compared to the same period in 2004, resulting from a lower cash balance available for investment.



For the years ended December 31, 2005 and 2004, the 37% decrease in interest and other income, year-over-year, resulted from a one-time $300,000 settlement that occurred in the second quarter of 2004 as well as the declining average monthly balance of funds available for investment.  This was somewhat offset by slightly higher yields in 2005 versus 2004.



General and Administrative



|                           |                                 |  |                          |  |          |   |       |  |       |  |          |  
|-------------------------- | ------------------------------- |  | ------------------------ |  | -------- | - | ----- |  | ----- |  | -------- | -
|($000s, except per boe)    | Three months ended
December 31, |  | Year  ended
December 31, | 
|                           | 2005                            |  | 2004                     |  | % Change |   | 2005  |  | 2004  |  | % Change |  
|General and administrative | 796                             |  | 794                      |  | -        |   | 2,726 |  | 2,802 |  | (3       | )
|Legal                      | 41                              |  | 108                      |  | (62      | ) | 205   |  | 539   |  | (62      | )
|Total                      | 837                             |  | 902                      |  | (7       | ) | 2,931 |  | 3,341 |  | (12      | )
|Per boe ($)                | 8.91                            |  | 8.20                     |  | 9        |   | 7.27  |  | 7.57  |  | (4       | )



General and administrative costs were unchanged in the fourth quarter of this year when compared to the same period last year. Higher salary and consulting expenses were offset by lower director fees and shareholder expenses.  Legal fees were down substantially quarter-over-quarter as considerable legal expense was incurred in 2004 to prepare the update of corporate governance voted on by our shareholders at the meetings held in November and December 2004.  On a boe basis, total general and administrative costs were 9% higher in the fourth quarter this year as compared with the respective period in 2004, reflecting the lower sales volumes recorded this year.



For the twelve months ended December 31, 2005, general and administrative costs were on par with those of last year and legal expenses were 62% lower this year due to the corporate governance update mentioned in the preceding paragraph.  Higher salaries and benefits were offset by lower director fees, consulting costs, insurance costs and shareholder expenses.  Overall, on a boe basis, total general and administrative expenses were 4% lower this year in comparison to last year.



In the coming quarters, we expect to incur significant administrative, auditing and legal expenses with respect to the Sarbanes-Oxley Act of 2002 (the Act), the requirements of which are 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 2005 and 2004 periods.



Depletion and Depreciation



|                           |                                 |  |                          |  |          |  |       |  |       |  |          | 
|-------------------------- | ------------------------------- |  | ------------------------ |  | -------- |  | ----- |  | ----- |  | -------- | 
|($000s, except per boe)    | Three months ended
December 31, |  | Year  ended
December 31, | 
|                           | 2005                            |  | 2004                     |  | % Change |  | 2005  |  | 2004  |  | % Change | 
|Depletion and depreciation | 1,864                           |  | 939                      |  | 99       |  | 6,995 |  | 3,357 |  | 108      | 
|Per boe ($)                | 19.83                           |  | 8.53                     |  | 132      |  | 17.36 |  | 7.61  |  | 128      | 



Depletion and depreciation expense increased 99% in the third quarter of 2005 from the same period of 2004.  For the year ended December 31, 2005, depletion and depreciation more than doubled to $7.0 million compared to 2004.  This increase is mainly a result of the increased capital expenditures during the year and the inclusion of Kotaneelee L-38 capital costs in the depletable base.



Asset Retirement Obligations Accretion



Asset retirement obligations accretion expense for the fourth quarter of 2005 decreased to $51,000 from $60,000 in the comparative 2004 period.  For the years ended December 31, accretion expense was $256,000 in 2005 versus $240,000 in 2004.  The increase in the year-to-date expense relates to the inclusion of estimated retirement costs for the Kotaneelee L-38 well and the new wells at Mike/Hazel and Buick Creek.



Stock-based Compensation



Stock-based compensation expensefor the fourth quarter ended December 31, 2005 was $101,000, compared to $340,000 for the same period in 2004.  For the years ended December 31, stock-based compensation expense decreased from $837,000 in 2004 to $511,000 in 2005.  The decrease is due to the number, timing and vesting of stock options granted in the relative periods.



Foreign Exchange



A foreign exchange loss of $49,000 was recorded in the fourth quarter of 2005, compared to a loss of $86,000 in the 2004 comparative.  Losses for the years ended December 31 were $107,000 and $96,000 for 2005 and 2004, respectively.  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 any certainty.  The value of the Canadian dollar was U.S. $.8580 at December 31, 2005 compared to U.S. $.8303 at December 31, 2004.



Income Taxes



The income tax provision for the fourth quarter ended December 31 amounted to an expense of $466,000 in 2005, compared to a recovery of $56,000 in the comparative period of 2004.  An income tax recovery of $8,000 was recorded for the twelve months ended December 31, 2005 as opposed to an expense of $1.1 million in the 2004 period.  During 2005, our effective tax rate was Nil as compared with 25.6% in 2004.



Income taxes are comprised of two components: current and future income taxes.  The expected 2005 income tax rate as a percentage of pre-tax income is 39%.  Our 2005 effective tax rate is due mainly to the recovery of current income taxes from the one-time recognition of a Notice of Reassessment from Canada Revenue Agency.  In 2003, we re-filed tax returns for the taxation years of 1994 to 2002 inclusive, which resulted in a Canada Revenue Agency audit and ultimately the recovery of $1.2 million of current income taxes in the second quarter of 2005.



In 2004, our effective tax rate was also lower than the expected 40% rate as a result of our ability to access certain successor tax pools previously thought to be unusable.



In 2006, although we believe we will have sufficient tax pools to avoid paying cash taxes, we expect our corporate income tax rate to increase to the expected rate of 39%.



Liquidity and Capital Resources



The oil and gas business is inherently risky and capital intensive and can require significant capital and cash resources to expand by growing reserves, production and cashflow.  Our strong financial position relative to most of our peers provides us with the ability to withstand volatile natural gas prices and to be able to capitalize on opportunities when they become available.  At December 31, 2005, we had no bank debt and approximately $24 million ($1.63 per share) 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 provided from operating activities during 2005 was $10.7 million compared to cash flow used in operating activities of $617,000 in 2004.



|                                             |        |  
|-------------------------------------------- | ------ | -
|($000s)                                      | 2005   |  
|Funds from operations                        | 12,483 |  
|Net changes in accounts receivable and other | (1,123 | )
|Net changes in current liabilities           | 390    |  
|Net changes in current income taxes payable  | (1,016 | )
|Cash flow from operating activities          | 10,734 |  



Our current cash flow from oil and gas operations is mainly derived from the Kotaneelee field.  Net field level receipts from Kotaneelee represented approximately 68% of our total net field receipts for the year ended December 31, 2005, compared to 66% in the same period of 2004.



Notwithstanding that the recently drilled Kotaneelee L-38 well has continued to produce at a steady gross production rate of approximately 17 mmcf/d with little water during its first eleven months, previously experienced annual production declines in the range of  25% to 30% and increased water production in the fields older wells remain a significant concern to us.  The field continues to experience an overall decrease in reservoir pressure, which decreases the ability of the older wells to lift water, and results in a decrease in gas production.



In late January 2006, the operator at Kotaneelee implemented certain production optimization techniques in an attempt to reduce the production declines at B-38 and I-48.  They were successful in temporarily arresting the decline at B-38 where gross production actually increased from 600 mcf/d at the end of January 2006 to approximately 1,500 mcf/d on March 19, 2006.  We expect that this short-term trend will not continue to increase B-38 production rates materially, and that the well will stabilize and then re-commence its normal decline.  At I-48 however, the well is still declining rapidly and the well may become unproductive at any time.



In an effort to address the risks associated with our dependence on Kotaneelee production, 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 current market conditions, we have concentrated our attention on reserves growth through exploration and development.



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 in the Mike/Hazel area of northeast British Columbia during the winter 2004/2005 drilling/construction season.  The cost to drill, complete and test the A-19-L and A-81-H wells were approximately $5.9 million and $2.6 million respectively.  Subsequent to year-end, we have tied them in, at an estimated cost of $1.7 million, and recently placed them on production.



Late in the third quarter of 2005, we commenced drilling two wells in northeast British Columbia.  The first well, Siphon 15-5-86-16W6, was dry and abandoned.  The second well, Buick Creek d-60-C/94-A-14, costing approximately $1.7 million to drill, complete and test, is expected to be tied in at an estimated cost of $500,000 and commence production near the end of March 2006.



During the three and twelve months ended December 31, 2005, we expended $2.6 million and $23.3 million respectively on capital additions, as summarized below:



|                            |                                 |  |                          |  |          |   |        |  |        |  |          |  
|--------------------------- | ------------------------------- |  | ------------------------ |  | -------- | - | ------ |  | ------ |  | -------- | -
|Capital Expenditures($000s) | Three months ended
December 31, |  | Year  ended
December 31, | 
|                            | 2005                            |  | 2004                     |  | % Change |   | 2005   |  | 2004   |  | % Change |  
|Land and acquisitions       | 29                              |  | 417                      |  | (93      | ) | 2,816  |  | 896    |  | 214      |  
|Geological and geophysical  | 32                              |  | 239                      |  | (86      | ) | 954    |  | 1,151  |  | (17      | )
|Drilling and completion     | 2,059                           |  | 5,148                    |  | (60      | ) | 16,259 |  | 8,750  |  | 86       |  
|Facilities and equipment    | 409                             |  | 596                      |  | (31      | ) | 3,163  |  | 679    |  | 366      |  
|Other                       | 27                              |  | 13                       |  | 105      |   | 75     |  | 30     |  | 151      |  
|Total capital expenditures  | 2,555                           |  | 6,413                    |  | (60      | ) | 23,267 |  | 11,506 |  | 102      |  
|Dispositions                | -                               |  | -                        |  | -        |   | -      |  | -      |  | -        |  
|Net capital expenditures    | 2,555                           |  | 6,413                    |  | (60      | ) | 23,267 |  | 11,506 |  | 102      |  



The potential for significant cost overruns exists in the oil and gas industry, especially in the current environment where high demand for services has been experienced during the last two years.  A recent summary of the risk of cost overruns is as follows:



In 2004, we agreed to participate in the drilling of the Kotaneelee L-38 well at an initial estimated cost of $16.7 million (net $5.1 million our share).  Due in part to the technical and drilling challenges experienced by the operator, actual gross costs were approximately $42 million($13 million our share), all of which are reflected in the financial statements for the year ended December 31, 2005.



Our 2006 capital expenditure budget is $25 million with $4.6 million of that amount estimated to have occurred during the first quarter of 2006.  We expect to rely on internally generated cash flows and current cash on hand to fund our annual capital expenditure program.



A significant portion of our capital resources is cash and until such time that these funds are required for our capital expenditures, acquisitions or operations, they are invested in short term investments.



We utilize the guidance provided from the Dominion Bond Rating Service Limited (DBRS) Commercial Paper and Short Term Rating Scale in evaluating our investments.  DBRS is one of the benchmark rating services for money market securities in Canada (as are S&P and Moodys in the U.S.).  This rating scale is meant to give an indication of the risk that the borrower will not fulfill its repayment obligations in a timely manner.  DBRS utilizes three main classifications of investment quality; R-1 (prime credit quality), R-2 (adequate credit quality), and R-3 (speculative).  Within each main classification, DBRS uses subset grades to designate the relative standing of credit within the particular category (high, mid or low).  As an example, Government of Canada guaranteed investments earn an R-1 high rating.



To ensure capital preservation, our current policy mandates that we invest in products with a minimum investment grade of R-1 low.  Given that credit ratings can change rapidly in todays economy, our current practice is to invest in a particular investment for periods of no longer than 90 days.  As a result of the strategy to select high quality investments in combination with short terms to maturity, we expect to hold the investments to maturity, and realize full maturity value.



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) | 
|2006                          | 91       | 
|2007                          | 61       | 
|Total contractual obligations | 152      | 



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.



Dependence on one major property



During 2005, our core property at Kotaneelee contributed 68% of our total production.  Irrespective that our new Kotaneelee L-38 well continues to produce at a steady rate of approximately 17 Mmcf/d over its eleven month history with little water, the field continues to experience an overall decrease in formation reservoir pressure.  Given the complex nature of the reservoir, we could experience water breakthrough at Kotaneelee L-38 at any time in the future.  When this occurs we will experience an increase in water production, and as a result, a decrease in natural gas production.



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 drilling of Kotaneelee L-38 well highlighted the major risks associated with the property.  Testing was performed after the well was tied in and commenced production on May 4, 2005.  To date the well has been producing at a steady rate of approximately 17 mmcf/d, however  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 water disposal 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 a result of the geophysical and geological risks associated with the Kotaneelee L-38 well, the original gross estimated costs of the drilling project more than doubled from $16 million to $34 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 government 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.



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, natural gas liquids and crude 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 on 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 aboriginal 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, 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.



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.



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 services, such as rigs, equipment and service crews.  Shortage of certain types of equipment and supplies 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.



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 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.



The expected future net revenues 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, product prices, 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 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.

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.



Stock-based compensation



In accordance with CICA Handbook Section 3870, Stock-based Compensation and Other Stock-based Payments, we follow 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 and the associated cost recorded in contributed surplus is recorded as an increase to total capital.



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 that 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 carried interest net revenues may lag the production month by one or more months.



Disclosure controls and procedures



The company has established disclosure controls and procedures to ensure timely and accurate preparation of financial and other reports.  Disclosure controls and procedures are designed to provide reasonable assurance that material information is recorded, processed, summarized and reported within the time periods specified by securities regulations and that information required to be disclosed is communicated to the appropriate members of management and properly reflected in our filings.  The Chief Executive Officer (CEO) and the Chief Financial Officer (CFO) oversee this process and have concluded that the design and operation of these disclosure controls and procedures are adequate and effective in ensuring that the information required to be disclosed in reports filed with the Canadian Securities Administrators is accurate and complete and filed on a timely basis.  The CEO and CFO have individually signed certifications to this effect.



It should be noted that, while we believe that our disclosure controls and procedures provide a reasonable level of assurance that they are effective, they will not necessarily prevent all errors and fraud.  A control system, no matter how well conceived or operated, can only provide reasonable, not absolute, assurance that the control system's objectives are met.



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 LLP, which acts as the Companys U.S. securities counsel.  During 2004, Murtha Cullina LLP was paid fees of $268,793 for legal services.



Additional information



Additional information relating to Canada Southern may be found on our website at 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.