Canada Southern Petroleum Ltd.
NASDAQ : CSPLF
TSX : CSW

Canada Southern Petroleum Ltd.

March 27, 2006 17:21 ET

Canada Southern Announces 2005 Results

CALGARY, ALBERTA--(CCNMatthews - March 27, 2006) - Canada Southern Petroleum Ltd. (NASDAQ:CSPLF) (TSX:CSW) (the Company) is pleased to announce financial and operating results for the fourth quarter and year ended December 31, 2005. Net income for the three months ended December 31, 2005 was $1.3 million ($0.09 per share) on revenues of $5.6 million, compared to $1.1 million ($0.08 per share) on revenues of $3.8 million for the fourth quarter last year. Net income for the year ended December 31, 2005 was $3.6 million ($0.25 per share) on revenues of $18.4 million, as compared with $3.2 million ($0.23 per share) on revenues of $14.5 million in the same period last year.

2005 Accomplishments

Canada Southern made significant operational progress in 2005. Major accomplishments include:

- Improved funds from operations by 55% to $12.5 million ($0.86 per share) from $8 million ($0.56 per share)

- Drilling activity during the year slowed the production decline and actually reversed the reserve decline of the prior years

- Increased drilling activity by 250% to 7 gross wells in 2005, as compared to 2 in 2004

- Drilled 6 (3.6 net) successful gas wells and 1 (1 net) dry hole for an overall success rate of 78%

- Increased proved plus probable reserves by 39% from 1,642 mboe to 2,275 mboe during the year

- Doubled reserve value of proved plus probable reserves (discounted at 10%) from $23.5 million to $49.9 million

- Increased reserves by replacing 2005 production volume by 2.5 times mainly through successful drilling

- Increased undeveloped land inventory by 62% from 21,023 to 34,029 net acres in our focus areas of British Columbia and Alberta

- Commenced presentations to the financial community



Financial and Operating Highlights

2005 2004
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Financial Review
($000s, except share amounts)

Total revenues, net of royalties 18,411 14,528
Funds flow from operations (1) 12,483 8,060
Per share - basic 0.86 0.56
Per share - diluted 0.86 0.56
Net income 3,558 3,279
Per share - basic 0.25 0.23
Per share - diluted 0.25 0.23
Capital expenditures, net 23,267 11,506
Working capital 24,457 34,765
Total assets 61,799 59,789
Shareholders' equity 51,636 47,090
Shares outstanding 14,496,165 14,417,770
Weighted average shares outstanding
Basic 14,453,145 14,417,770
Diluted 14,487,455 14,435,234

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(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.


2005 2004
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Operating Review

Sales volumes
Natural gas mcf/d 6,458 4,970
Oil and natural gas liquids bbls/d 27 31
Carried interest natural gas mcf/d 2 2,077
Combined (6:1) (1) boe/d 1,104 1,206
Average sales prices
Natural gas $/mcf 8.44 5.72
Oil and natural gas liquids $/bbl 55.17 39.24
Combined $/boe 50.74 34.43
Total proved plus probable reserves mboe 2,275 1,642
Undeveloped land
Gross acres 252,517 238,507
Net acres 82,490 69,484

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(1)means barrels of oil equivalent, with natural gas converted at 6
mcf per barrel of oil equivalent.


For the three months ended December 31, 2005, total sales volumes declined 15% to 1,022 barrels of oil equivalent per day (boe/d) from the 1,196 boe/d recorded in the same period last year. For the year ended December 31, 2005, volumes declined 8% year-over-year from 1,206 boe/d to 1,104 boe/d.

Kotaneelee sales volumes represent 68% of the Company's total sales volumes for the year ended December 31, 2005 versus 65% in the comparable period of 2004. As a result of the successful drilling of Kotaneelee L-38, Kotaneelee annual sales volumes declined by only 4% year-over-year, as compared with the 24% decline we experienced in 2004. The L-38 well came on stream in May 2005. If the well had been on stream for the full year there would have been no decline in production year over year. The L-38 well continues to produce at approximately 17 mmcf/d.

The gross production from the Kotaneelee field for the month of December 2005 was approximately 17.9 mmcf /d (16.9 mmcf/d from L-38, 0.6 mmcf/d from B-38 and 0.4 mmcf/d from I-48). Gross natural gas sales (net of shrinkage) from all wells at Kotaneelee were approximately 13.4 mmcf/d (3.9 mmcf/d our net share) for the month of December 2005.

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 may become unproductive at any time.

2006: First Quarter Developments and Full Year Plans

Pipeline tie-in

A key objective for this winter was tying in and bringing on production the successful wells drilled in 2005. We are pleased to report that 5 wells were tied-in for production during this winter season, with our 100% interest Buick Creek d-60-C well just being finalized. The wells tied in include 2 operated wells at Mike/Hazel, 2 non-operated wells and 1 operated well at Buick Creek. Although the wells' production has yet to stabilize, we expect our net share of production from these wells to be in the range of 250 to 300 boe/d. As a result, we expect that our 2006 Q1 exit rate will be higher than that experienced in Q4 2005.

Drilling

During the first quarter we drilled a 100% interest well at Mike/Hazel a-A21-I/94-H-3. The well did not have economic quantities of hydrocarbons, therefore it was considered dry and abandoned.

Our 2006 capital expenditure and operational program focuses on adding to shareholder value in a competitive and high cost environment. We are employing the following tactics:

- Continuing to grow our production and reserves with our 2006 capital expenditure budget of up to $25 million for:

-- drilling exploration and development wells;

-- acquiring additional undeveloped land inventory; and

-- acquiring additional proprietary and trade seismic;

- Seeking additional opportunities in new or core areas via acquisition or merger; and

- Deepening our knowledge of our long term Arctic Island assets

Annual Information Form and NI 51-101 Reserves Disclosure

Our Annual Information Form ("AIF") for the year ended December 31, 2005 has been filed on the System for Electronic Document Analysis and Retrieval ("SEDAR") and also filed as part of our Form 40-F filing with the SEC.

The AIF contains the supplemental disclosure, including detailed reserves information, as mandated and required by Canadian Securities Administrators National Instrument 51-101 including the Statements and Reports required by Forms 51-101F1, 51-101F2 and 51-101F3.

The purpose of Canadian NI 51-101 is to enhance the quality, consistency, timeliness and comparability of crude oil and natural gas activities by reporting issuers and elevate reserves reporting to a higher level of confidence and accountability.

This document may be obtained at SEDAR's website address of www.sedar.com or at the SEC's website address of www.sec.gov. A link to the Company's SEDAR and SEC filings can also be found on the Company website address of www.cansopet.com.

Management's Discussion and Analysis for the Fourth Quarter and Year Ended December 31, 2005



Overview

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

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Three months ended Year ended
December 31, December 31,
% %
($000s) 2005 2004 Change 2005 2004 Change
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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 -
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Funds from operations
(non-GAAP) 3,877 2,391 62 12,483 8,060 55
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Quarterly Information
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Summary of Quarterly Information
($000s, except per share amounts)
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2005 Quarter ended
December 31 September 30 June 30 March 31
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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
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2004 Quarter ended
December 31 September 30 June 30 March 31
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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
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Funds from Operations

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

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

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Three months ended Year ended
December 31, December 31,
% %
Sales volumes 2005 2004 Change 2005 2004 Change
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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)
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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)
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Combined (6:1) boe/d 1,022 1,196 (15) 1,104 1,206 (8)
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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 21 to 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.



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Three months ended Year ended
December 31, December 31,
% %
Revenues ($000s) 2005 2004 Change 2005 2004 Change
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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)
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Total natural gas 6,271 3,815 64 19,893 14,444 38
Oil and natural
gas liquids 128 165 (23) 546 450 21
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Total 6,398 3,980 61 20,439 14,894 37
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(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.



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Three months ended Year ended
December 31, December 31,
% %
Average Sales Prices 2005 2004 Change 2005 2004 Change
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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 -
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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
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Combined (6:1) $/boe 68.09 36.29 88 50.74 36.01 41
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(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

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Three months ended Year ended
December 31, December 31,
% %
($000s) 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
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Total 1,010 472 114 2,806 1,600 75
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As % of working
interest revenues 17% 12% 38 15% 15% -
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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

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

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

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Three months ended Year ended
December 31, December 31,
% %
($/boe) 2005 2004 Change 2005 2004 Change
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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)
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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
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Operating netback 47.71 24.09 98 33.69 25.03 35
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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

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

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

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



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($000s) 2005
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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)
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Cash flow from operating activities 10,734
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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 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:



Three months ended Year ended
December 31, December 31,
Capital Expenditures % %
($000s) 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 - - - - - -
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Net capital
expenditures 2,555 6,413 (60) 23,267 11,506 102
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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:



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Year ($000's)
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2006 91
2007 61
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Total contractual obligations 152
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The Company's audited financial statements, management discussion and analysis, and AIF for the period ended December 31, 2005 has been filed today with the Canadian Securities Administrators' System for Electronic Document Analysis and Retrieval (SEDAR). The Company's annual report on Form 40-F for the year ended December 31, 2005 was also filed with the U.S. Securities and Exchange Commission (SEC). These documents may be obtained at SEDAR's website address of www.sedar.com or at the SEC's website address of www.sec.gov. A link to the Company's SEDAR and SEC filings can also be found on the Company website address of www.cansopet.com.

Canada Southern Petroleum Ltd. is an independent energy company based in Calgary, Alberta, Canada. The Company is engaged in oil and gas exploration and development, with its primary interests in producing properties in the Yukon Territory and British Columbia, Canada. The Company's common shares are traded on the NASDAQ Capital Market under the symbol "CSPLF," and on the Toronto Stock Exchange under the symbol "CSW". The Company has 14,496,165 shares outstanding.

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.



CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED BALANCE SHEETS
(in Canadian dollars)

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---------------------------------------------------------------------
As at December 31,
2005 2004
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Assets

Current assets
Cash and cash equivalents $ 23,704,819 $ 39,353,717
Accounts receivable 3,058,252 2,495,678
Other assets 976,632 370,011
---------------------------------------------------------------------
27,739,703 42,219,406

Oil and gas properties and equipment 34,059,467 17,570,085
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Total assets $ 61,799,170 $ 59,789,491
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---------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities
Accounts payable $ 1,915,808 $ 3,627,644
Accrued liabilities 1,366,467 2,810,263
Income taxes payable - 1,016,419
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3,282,275 7,454,326

Future income tax liability 3,739,864 2,569,864
Asset retirement obligations 3,141,115 2,675,743
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10,163,254 12,699,933
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Commitments

Shareholders' equity
Share capital 15,152,207 14,417,770
Contributed surplus 29,267,655 29,014,151
Retained earnings 7,216,054 3,657,637
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51,635,916 47,089,558
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Total liabilities and shareholders' equity $ 61,799,170 $ 59,789,491
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CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS
AND RETAINED EARNINGS
(in Canadian dollars)

---------------------------------------------------------------------
---------------------------------------------------------------------
Years ended December 31,
2005 2004
---------------------------------------------------------------------

Revenues
Petroleum and natural gas sales $ 20,371,244 $ 11,513,062
Royalties (2,806,489) (1,600,117)
Carried interest 67,419 3,380,781
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17,632,174 13,293,726
Interest and other income 778,537 1,234,898
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18,410,711 14,528,624
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Expenses

Lease operating costs 1,868,172 1,547,908
Transportation 2,192,087 700,605
General and administrative 2,930,675 3,340,864
Depletion and depreciation 6,995,000 3,357,000
Asset retirement obligations accretion 256,000 240,000
Stock-based compensation 511,449 836,700
Foreign exchange losses 106,625 96,281
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14,860,008 10,119,358
---------------------------------------------------------------------
Income before income taxes 3,550,703 4,409,266

Income tax recovery (expense) 7,714 (1,130,000)
---------------------------------------------------------------------
Net income 3,558,417 3,279,266

Retained earnings - beginning of year 3,657,637 378,371
---------------------------------------------------------------------
Retained earnings - end of year $ 7,216,054 $ 3,657,637
---------------------------------------------------------------------
---------------------------------------------------------------------

Net income per share:
Basic $ 0.25 $ 0.23
Diluted $ 0.25 $ 0.23

Average number of shares outstanding:
Basic 14,453,145 14,417,770
Diluted 14,488,465 14,435,234


CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in Canadian dollars)

---------------------------------------------------------------------
---------------------------------------------------------------------
Years ended December 31,
2005 2004
---------------------------------------------------------------------

Cash flow from operating activities:
Net income $ 3,558,417 $ 3,279,266
Adjustments to reconcile net income to net
cash provided by (used in) operating
activities:
Depletion and depreciation 6,995,000 3,357,000
Asset retirement obligations accretion 256,000 240,000
Asset retirement expenditures (7,670) (1,243)
Stock-based compensation 511,449 836,700
Future income tax expense 1,170,000 348,000
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Funds from operations 12,483,196 8,059,723

Change in non-cash working capital (1,749,255) (8,676,831)
---------------------------------------------------------------------
10,733,941 (617,108)
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Cash flow used in investing activities:
Additions to oil and gas properties and
equipment (23,267,340) (11,506,182)
Change in non-cash working capital (3,591,991) 2,394,621
---------------------------------------------------------------------
(26,859,331) (9,111,561)
---------------------------------------------------------------------

Cash flow from financing activities:
Exercise of stock options 476,492 -
---------------------------------------------------------------------
476,492 -
---------------------------------------------------------------------

Decrease in cash and cash equivalents (15,648,898) (9,728,669)

Cash and cash equivalents
- beginning of year 39,353,717 49,082,386
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Cash and cash equivalents - end of year $ 23,704,819 $ 39,353,717
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Contact Information

  • Canada Southern Petroleum Ltd.
    John W. A. McDonald
    President and Chief Executive Officer
    (403) 269-7741
    or
    Canada Southern Petroleum Ltd.
    Randy Denecky
    Chief Financial Officer
    (403) 269-7741