Canada Southern Petroleum Ltd.
NASDAQ : CSPLF
TSX : CSW

Canada Southern Petroleum Ltd.

August 11, 2005 17:39 ET

Canada Southern Petroleum Ltd Reports Second Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Aug. 11, 2005) - Canada Southern Petroleum Ltd. (TSX:CSW) (NASDAQ:CSPLF) is pleased to announce operational and financial results for the three and six months ended June 30, 2005.



Financial and Operating Highlights
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Three months ended June 30, Six months ended June 30,
% %
2005 2004 Change 2005 2004 Change
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Financial
($000s, except
per share)
Gross revenues 3,732 3,782 (1) 6,769 7,251 (7)
Funds from
operations(1) 3,004 1,639 83 4,559 4,100 11
Per share
- basic and
diluted ($) 0.21 0.11 91 0.32 0.28 14
Net income 1,146 570 101 1,254 1,726 (27)
Per share
- basic and
diluted ($) 0.08 0.04 100 0.09 0.12 (25)
Capital
expenditures, net 5,056 770 557 14,939 2,055 627
Working capital 24,658 34,765 (29) 24,658 34,765 (29)
Total assets 59,748 59,789 - 59,748 59,789 -
Shareholders' equity 48,839 47,090 4 48,839 47,090 4
Weighted average
shares
outstanding (000s)
Basic 14,426 14,418 - 14,422 14,418 -
Diluted 14,528 14,420 1 14,497 14,419 1
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Operational

Sales volumes
Natural gas mcf/d 6,890 4,143 66 6,126 3,193 92
Oil and
natural gas
liquids bbl/d 28 33 (15) 32 29 10
Carried
interest
natural gas mcf/d 1 3,161 (100) 1 4,204 (100)
Combined
(6:1)(2) boe/d 1,176 1,251 (6) 1,053 1,262 (17)
Average sales
prices
Natural gas $/mcf 6.36 5.86 9 6.42 5.84 10
Oil and
natural gas
liquids $/bbl 48.48 33.83 43 45.79 34.93 31
Combined $/boe 38.43 35.15 9 38.77 35.02 11
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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.
(2) Barrels of oil equivalent, with natural gas converted at 6 mcf
per barrel of oil equivalent.


Summary

- Success at Kotaneelee added 3.7 BCF to reserves and is contributing 4.1 mmcf/d to sales volumes.

- Completion activities are underway at Mike/Hazel with reserve additions expected before year end.

- Capital budget increased by $6.5 million to support new opportunities; seven new drilling locations identified utilizing 3D seismic; four licensed to date.

- Acquired 3,458 net undeveloped acres in core areas during and subsequent to the second quarter.

- Income tax recovery of $1.1 million recorded in the second quarter.

- G&A down 23% over second quarter 2004 and down 15% year to date.

Report to Shareholders

The second quarter of 2005 was monumental for us with the commencement of production from Kotaneelee L-38 and the recognition of related reserve additions. Outside of the activity at Kotaneelee, the focus of our activities during the second quarter was on planning for the balance of this year's field activities, as we continued to acquire land and seismic to identify drilling locations. Given the expected continuing high level of demand for drilling rigs, service rigs and other oilfield equipment and personnel, at least six months of advance planning for anticipated field activities has become the norm, particularly in certain of our areas of interest where access is limited to winter only.

Net income for the quarter ended June 30, 2005 was $1.1 million, or $0.08 per share, compared to $570,000, or $0.04 per share, for the same period in 2004. The increase is mainly a result of the recognition of an income tax recovery related to a re-filing of prior year tax returns and because the revenue and net income impact of Kotaneelee L-38 sales was largely offset by the associated higher non-cash depletion charges. Net income for the six months ended June 30, 2005 was $1.3 million, or $0.09 per share compared with $1.7 million, or $0.12 per share for the same period in 2004.

Funds from operations for the three months ended June 30, 2005 were $3.0 million, or $0.21 per share, compared to $1.6 million, or $0.11 per share, for the same period in 2004. This increase is due mainly to the income tax recovery as well as the increased revenues for a portion of the quarter resulting primarily from the commencement of production from Kotaneelee L-38. For the six months ended June 30, funds from operations were $4.6 million, or $0.32 per share in 2005, as compared with $4.1 million or $0.28 per share in 2004. This increase is mainly due to the recovery of income taxes.

The commencement of production from the Kotaneelee L-38 well on May 4, 2005, which has stabilized at a rate of approximately 17 mmcf/d (4.1 mmcf/d net sales to us), more than offset expected normal production declines. Average sales volumes during the second quarter of 2005 were up 27% to 1,176 boe/d from the 929 boe/d average in the first quarter of this year. Our net proven plus probable reserve additions (after royalties), attributable to Kotaneelee L-38, were 3.7 Bcf in the second quarter.

During most of the second quarter we were in "spring break-up", where road bans implemented by provincial governments prohibit the movement of heavy equipment to field operations. During this period, we identified, surveyed, and made application to drill four locations in northeast British Columbia of which three are in Siphon and one in Buick Creek. Currently, all four of these well locations have been approved by the regulatory authorities. Depending upon the level of success at Mike/Hazel, we may license either one or two additional wells in the Mike/Hazel area for the upcoming winter's drilling season.

Late in the second quarter, we were able to access the Mike/Hazel area through roads that we constructed prior to break-up. We have completed the Mike A-19-L/94-H-2 well and are currently waiting for surface conditions to improve to remove downhole recorders. We also performed certain components of the completion program for Mike A-81-H/94-H-3, and are currently also waiting for weather conditions to improve to finish those activities. Upon finalization of these activities, we expect to be able to properly size equipment to enable us to bring one or both of these wells on production either late in the fourth quarter or during the first quarter of 2006.

We are continuing to execute our plan and believe that our activity during the second quarter of this year contributes to building value for the benefit of all shareholders.



"John W.A. McDonald"
John W.A. McDonald
President and Chief Executive Officer
August 9, 2005


Management's Discussion and Analysis

Management's Discussion and Analysis should be read in conjunction with our unaudited interim consolidated financial statements and selected notes for the three and six months ended June 30, 2005 and 2004 and our audited consolidated financial statements and related notes for the year ended December 31, 2004. The interim 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 9 to our interim 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 Management's Discussion and Analysis is dated as at August 9, 2005.
Overview



Overview

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Three months ended June 30, Six months ended June 30,
($000s, except % %
share amounts) 2005 2004 Change 2005 2004 Change
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Petroleum and
natural gas sales 4,113 2,335 76 7,388 3,583 106
Royalties (574) (522) 10 (1,053) (59) 78
Carried interest 1 1,469 (100) 4 3,475 (100)
Lease operating costs (538) (437) 23 (1,013) (661) 53
Transportation (514) (139) 270 (905) (139) 551
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Operating netback 2,488 2,706 (8) 4,421 5,667 (22)
Interest and other
income 193 499 (61) 431 783 (45)
General and
administrative (772) (998) (23) (1,409) (1,650) (15)
Foreign exchange gains 16 68 (76) 37 96 (61)
Current income tax
recovery (expense) 1,079 (636) - 1,079 (796) -
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Funds from
operations (1) 3,004 1,639 83 4,559 4,100 11
Depletion and
depreciation (1,753) (861) 104 (2,819) (1,622) 74
Asset retirement
obligations
accretion (67) (60) 12 (133) (120) 11
Future income tax 40 86 (53) (130) (365) (64)
Stock-based
compensation (78) (234) (67) (223) (267) (16)
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Net income 1,146 570 101 1,254 1,726 (27)
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Funds from operations
per share (1):
Basic ($) 0.21 0.11 91 0.32 0.28 14
Diluted ($) 0.21 0.11 91 0.31 0.28 11
Net income per share:
Basic ($) 0.08 0.04 100 0.09 0.12 (25)
Diluted ($) 0.08 0.04 100 0.09 0.12 (25)
Average number of
shares outstanding
(000s):
Basic 14,426 14,418 - 14,422 14,418 -
Diluted 14,528 14,420 1 14,497 14,419 1
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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 June 30, Six months ended June 30,
% %
(000s) 2005 2004 Change 2005 2004 Change
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Cash flow from
(used in)
operating
activities (GAAP) 2,219 3,941 (44) 4,361 (5,119) -
Change in non-cash
working capital
(GAAP) 785 (2,302) - 198 9,219 (98)
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Funds from operations
(non-GAAP) 3,004 1,639 83 4,559 4,100 11
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Funds from Operations
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Three months ended June 30, Six months ended June 30,
($000s, except % %
per share) 2005 2004 Change 2005 2004 Change
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Funds from operations 3,004 1,639 83 4,559 4,100 11
Per share:
Basic ($) 0.21 0.11 91 0.32 0.28 14
Diluted ($) 0.21 0.11 91 0.31 0.28 11
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Funds from operations for the three months ended June 30, 2005 were $3.0 million or $0.21 per share, compared to $1.6 million, or $0.11 per share, for the same period in 2004. Funds from operations for the six months ended June 30, 2005 and 2004 were $4.6 million or $0.32 per share, and $4.1 million or $0.28 per share, respectively. The increases were mainly due to the recovery of current income taxes realized as a result of a prior period re-filing our income tax returns from 1994 to 2002.



Net Income

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Three months ended June 30, Six months ended June 30,
($000s, except % %
per share ) 2005 2004 Change 2005 2004 Change
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Net income 1,146 570 101 1,254 1,726 (27)
Per share:
Basic ($) 0.08 0.04 100 0.09 0.12 (25)
Diluted ($) 0.08 0.04 100 0.09 0.12 (25)
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Net income for the three month period ended June 30, 2005 was $1.1 million, or $0.08 per share, compared to $570,000, or $0.04 per share, for the same period in 2004. Net income for the six months ended June 30, 2005 was $1.3 million, or $0.09 per share compared to $1.7 million or $0.12 per share in the 2004 comparative. The increase in second quarter income is mainly as a result of the recovery of current income taxes and higher product prices, partially offset by higher depletion charges.

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.

Subsequent to 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 future periods are expected to be minimal.



Petroleum and natural gas sales and carried interest

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Three months ended June 30, Six months ended June 30,
Sales % %
Volumes 2005 2004 Change 2005 2004 Change
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Natural gas
Working
interest mcf/d 6,488 3,563 82 5,689 2,717 109
Royalty
interest mcf/d 402 581 (31) 437 476 (8)
Carried
interest mcf/d 1 3,161 (100) 1 4,204 (100)
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Total
natural gas mcf/d 6,891 7,305 (6) 6,128 7,397 (17)
Oil and
natural gas
liquids bbl/d 28 33 (16) 32 29 10
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Combined (6:1) boe/d 1,176 1,251 (6) 1,053 1,262 (17)
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Sales volumes, on a boe basis, averaged 1,176 boe/d during the second quarter of 2005, down 6% from the 1,251 boe/d average in the second quarter of 2004. Expected production declines continue to affect our sales volumes for most of our areas with an average natural gas production rate in the second quarter of 2005 of 6.9 mmcf/d compared to 7.3 mmcf/d during the same quarter last year. For the six month periods ended June 30, 2005 and 2004, sales volumes, on a boe basis, averaged 1,053 boe/d and 1,262 boe/d, respectively.

Second quarter 2005 average sales volumes were up by 27% from the first quarter 2005 average of 929 boe/d to 1,176 boe/d. The majority of the increase in sales quarter over quarter is due to the commencement of production from Kotaneelee L-38 in May 2005.

Sales volumes from the Kotaneelee field are currently approximately double the amount of what they were prior to the commencement of production from the L-38 well in early May 2005. Although L-38 has been contributing approximately 4.1 mmcf/d (683 boe/d) of sales volumes since it was brought on stream, production from I-48 has declined at a rate greater than predicted. Volumes from the well have declined by approximately 25% from its first quarter 2005 average sales of 2.3 mmcf/d (380 boe/d) to approximately 1.7 mmcf/d (283 boe/d).

Production from our Kotaneelee field continues to decline due to a combination of reservoir pressure declines and increased water production. Our average net natural gas sales from Kotaneelee during the second quarter of 2005 were 5.1 mmcf/d, or approximately 74% of our total natural gas sales, with associated gross water production of 1,831 bbl/d, compared to averages of 4.8 mmcf/d (approximately 65% of total natural gas sales) and 1,868 bbl/d, respectively, for the second quarter of 2004.

Sales volumes in the second quarter of 2005 were adversely affected by a scheduled turnaround at the third party owned Duke McMahon Gas Plant. Production from the Buick Creek, Siphon, and Ekwan fields were shut-in from June 21 to July 9, 2005. These fields re-commenced production on completion of the turnaround.

Although our natural gas working interest volumes increased 82% and 109% over the three and six month comparatives from last year, this is solely the result of the conversion of our Kotaneelee carried interest to a working interest, as noted above, which is also reflected in the decrease in natural gas carried interest volumes from last year.



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Three months ended June 30, Six months ended June 30,
Revenues % %
($000s) 2005 2004 Change 2005 2004 Change
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Natural gas
Working interest 3,736 1,917 95 6,608 2,893 128
Royalty interest 253 315 (20) 513 504 2
Carried interest(1) 2 1,469 (100) 4 3,475 (100)
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Total natural gas 3,991 3,701 8 7,125 6,872 4
Oil and natural
gas liquids 123 103 20 267 186 43
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Total 4,114 3,804 8 7,392 7,058 5
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(1) "Carried interest" is net of related carried interest
royalties, lease operating expenses, transportation costs,
and capital.


Our gross revenue from the sale of petroleum and natural gas in the second quarter of 2005 was $4.1 million, up by 8% from the same quarter last year. Working interest revenue was significantly higher at $3.7 million during this period of 2005 compared to $1.9 million in 2004. The conversion of the Kotaneelee carried interest to a working interest contributed to this increase in two ways. First, revenue was recorded under working interest revenues in all of the second quarter of 2005 as opposed to treatment as carried interest revenues during a portion of the comparative period in 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. Overall natural gas sales were $4.0 million in the three months ended June 30, 2005, slightly higher than the $3.7 million received in the second quarter of 2004.

Our gross revenue from the sale of petroleum and natural gas in the six month period ended June 30, 2005 was up 5%, to $7.4 million from $7.1 million over the comparable period in 2004.

In both the three and six month periods of 2005, increases in product pricing more than offset the decrease in sales volumes when compared with prior periods.

Oil and natural gas liquids revenue rose 20% to $123,000 in the second quarter of 2005 from $103,000 in the same period of 2004. This increase resulted from higher product prices year-over-year that more than offset the slightly lower production volumes.



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Three months ended June 30, Six months ended June 30,
Average Sales % %
Price 2005 2004 Change 2005 2004 Change
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Natural gas
Working
interest $/mcf 6.33 5.91 7 6.42 5.85 10
Royalty
interest $/mcf 6.91 5.96 16 6.48 5.82 11
Carried
interest(1) $/mcf - 5.79 - - 5.83 -
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Total natural
gas $/mcf 6.36 5.86 9 6.42 5.84 10
Oil and natural
gas liquids $/bbl 48.48 33.83 43 45.79 34.93 31
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Combined (6:1) $/boe 38.43 35.15 9 38.77 35.02 11
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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 six months ending June 30,
2005 was not material.


The overall average price we received from the sale of our oil and gas products in the second quarter of 2005 was up 9%, to $38.43/boe, from the $35.15/boe we received in the second quarter of last year. A 7% increase in the average natural gas price received for our working interest properties ($6.33 per mcf (before transportation) in 2005 versus $5.91 per mcf in 2004) contributed the majority of the gain. After transportation costs, the average price received in the second quarter of 2005 for our working interest natural gas was $5.48/mcf.

During the six month period ended June 30, 2005, the overall average price for our products increased by 11% from $35.02/boe to $38.77/boe.



Royalties

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Three months ended June 30, Six months ended June 30,
% %
($000s) 2005 2004 Change 2005 2004 Change
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Crown royalties 460 419 10 832 452 84
Freehold and GORR 115 103 12 221 139 59
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Total 574 522 10 1,053 591 78
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As % of working
interest revenues 15% 26% (42) 15% 19% (20)
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Total royalties increased by 10% in the second quarter of 2005, totaling $574,000 versus $522,000 in the same period of 2004. Total royalties increased by 78% when comparing the six month periods of 2005 to 2004. The total increase in absolute amounts for royalties this year as compared with last year was a function of higher product prices and treatment of Kotaneelee as a carried interest in the comparative periods.

Royalties as a percentage of working interest revenues amounted to 15% during the second quarter of 2005, compared to 26% during the same quarter last year. For the six months ended June 30, 2005 and 2004, royalties as a percentage of working interest revenues decreased to 15% from 19%. The increase in total royalties, offset by a decrease in the royalty rate, was mainly a result of our conversion of the Kotaneelee carried interest to a working interest. The crown royalty rate for the Kotaneelee property is approximately 10%, which is lower than the rate for the balance of our working interest properties. Due to the significance of the Kotaneelee revenues and, therefore the royalties, this resulted in a lower overall corporate royalty rate.



Lease Operating Costs

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Three months ended June 30, Six months ended June 30,
($000s, except % %
per boe) 2005 2004 Change 2005 2004 Change
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Lease operating costs 538 437 23 1,013 661 53
Per working interest
boe ($) 5.33 7.67 (30) 5.71 7.54 (24)
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Lease operating costs increased 23% from $437,000 in the second quarter last year to $538,000 in the second quarter of 2005. For the six month periods ended June 30, 2005 and 2004, lease operating costs increased by 53% from $661,000 to $1,013,000 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 30% in the second quarter ended June 30, 2005 to $5.33/boe from $7.67/boe in the same period of 2004. The six month period of 2005 versus 2004 experienced an operating cost per boe drop of 24% from $7.54 to $5.17 respectively. This drop is also largely due to the conversion of Kotaneelee to a working interest, where the operating costs averaged $3.54/boe in the second quarter of 2005, and $3.96/boe for the six months of 2005.



Transportation

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Three months ended June 30, Six months ended June 30,
($000s, except % %
per boe) 2005 2004 Change 2005 2004 Change
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Transportation 513 139 269 905 139 548
Per working interest
boe ($) 5.09 2.44 108 5.10 1.59 221
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Transportation costs for the three months ended June 30, 2005 amounted to $513,000 as compared with $139,000 for the comparable period in 2004. For the six months ended June 30, 2005 and 2004, transportation costs were $905,000 and $139,000 respectively. These costs result entirely from the transportation of our gas at Kotaneelee and have increased due to commencement of production of the L-38 well during the second quarter. In addition to that shown in the 2004 comparative above, transportation costs of $22,000 and $286,000 were also expended in the three and six month periods respectively, however they were included as a reduction of carried interest revenues for financial statement purposes. We do not receive sufficient information from the operators of our other working interest properties to determine the amount of related transportation costs.



Interest and other income

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Three months ended June 30, Six months ended June 30,
% %
($000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Interest income 188 197 (5) 418 465 (10)
Other 5 302 (98) 13 318 (96)
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Total 193 499 (61) 431 783 (45)
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Interest and other income decreased 61% in the second quarter of 2005 from $197,000 to $188,000 when compared to the same period in 2004. For the six month period, interest and other income decreased 45% from $783,000 to $431,000 in 2004 to 2005 respectively. The majority of the decrease related to a $300,000 settlement that occurred in the second quarter of 2004. During 2005, our average monthly balance of funds available for investment was lower as compared to the previous year. This was somewhat offset by slightly higher yields this year versus last year.



General and Administrative

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Three months ended June 30, Six months ended June 30,
($000s, except % %
per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
General and
administrative 700 871 (20) 1,276 1,473 (13)
Legal 72 126 (43) 133 177 (25)
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Total 772 997 (23) 1,409 1,650 (15)
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Per boe ($) 7.21 8.77 (18) 7.39 7.18 3
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General and administrative costs, inclusive of legal expenses, decreased 23% in the second quarter of this year, to $772,000 from $997,000 in the same period last year. For the six month period ended June 30, general and administrative costs decreased by 15% from $1.7 million to $1.4 million. On a boe basis, costs were 18% lower and 3% higher this year as compared with the respective periods in 2004.

Legal expenses were lower to June 30 this year as compared with the last year. We expect legal costs for the remainder of the year to be lower than that in 2004, as considerable legal expense was involved to prepare for the update of corporate governance voted on by our shareholders at the meetings held in November and December 2004.

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

No general and administrative expenses were capitalized during the six months of 2005 and 2004.



Depletion and Depreciation

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Three months ended June 30, Six months ended June 30,
($000s, except % %
per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Depletion and
depreciation 1,753 861 104 2,819 1,622 74
Per boe ($) 16.37 7.56 116 14.78 7.06 109
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Depletion and depreciation expense increased 104% in the second quarter of 2005 to $1.8 million from $861,000 in the same period of 2004. Depletion and depreciation increased by 74% from $1.6 million in the first six months of 2004 to $2.8 million during the comparative period in 2005. This increase is a result of the increased capital expenditures during the year, the commencement of inclusion of Kotaneelee L-38 capital costs in the depletable base, and the weather delays in completing and testing two wells in the Mike/Hazel area that were drilled during last winter drilling season. Upon completion and testing of these wells, we intend to provide the testing results to an independent qualified reserves evaluator for assessment of additional proved reserves, if any.

All costs incurred in drilling, completing and equipping the Kotaneelee L-38 well that commenced drilling on August 22, 2004 were capitalized. As the well represented a major development project and represented a large portion the net book value of capital assets, prior inclusion of these amounts for depletion purposes would not have represented a fair matching of revenues with expenses. The L-38 well was tied in and commenced production on May 4, 2005. An independent qualified reserve evaluator estimated the amount of related reserve additions during the second quarter of 2005 and the well's cumulative costs of $12.7 million and reserve additions were included for the first time in the computation of depletion.

Asset Retirement Obligations Accretion

Asset retirement obligations accretion expense for the second quarter of 2005 increased by 12% to $67,000 from $60,000 in the comparative period. Asset retirement obligations accretion expense for the six month periods ended June 30 was $133,000 in 2005 versus $120,000 in 2004. The increase in expense relates directly to the inclusion of estimated retirement costs for the Kotaneelee L-38 well.

We have not included any asset retirement obligations for any of the four other wells drilled this past winter drilling season. All of the wells were cased but have yet to be either completed or tested. Weather permitting, we expect to have sufficient testing information on the two Company operated wells at Mike/Hazel during the third quarter of 2005, and the remaining non-operated wells during the fourth quarter of 2005. Only upon testing of the wells will we have sufficient information to estimate the components of each well's asset retirement obligation.

Stock-based Compensation

Stock-based compensation expense for the second quarter ended June 30, 2005 was $78,000, compared to $234,000 for the same period in 2004. For the six month periods ended June 30, stock based compensation expense decreased from $267,000 in 2004 to $223,000 in 2005. The decrease is due to the number, timing and vesting of stock options granted in the relative periods. In July 2005, 50,000 options were granted that will increase stock based compensation expense in future periods.

Foreign Exchange

A foreign exchange gain of $16,000 was recorded in the second quarter of 2005, compared to a gain of $67,000 in the 2004 comparative. Gains for the six month periods were $37,000 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 certainty. The value of the Canadian dollar was U.S. $.8303 at December 31, 2004 compared to U.S. $.8139 at June 30, 2005.

Income Taxes

Due mainly to the one-time recognition of benefits realized from re-filing our tax returns, the income tax provision for the second quarter ended June 30 decreased from an expense of $550,000 in 2004 to a recovery of $1.1 million in 2005. An income tax recovery of $949,000 was experienced for the six months ended June 30, 2005 as opposed to $1.2 million of expense in the 2004 comparative period. The recovery of current income taxes stems mainly from the one-time recognition of a Notice of Reassessment from Canada Revenue Agency received during the second quarter of 2005. The $1.1 million of current taxes recovered as a result of the Notice of Assessment is higher than the $850,000 that we estimated in the subsequent event note disclosure in our financial statements for the year ended December 31, 2004. 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 current income taxes.

In addition, we also recorded a one-time recovery of income tax of approximately $90,000 from successor tax pools previously thought to be unusable. A valuation allowance on these pools was previously recorded. However, these pools were fully utilized in the second quarter of 2005 and as a result, the Company no longer has any valuation allowance on any of its tax pools.

Liquidity and Capital Resources

We recognize the need for a strong balance sheet in order to withstand volatile natural gas prices and to be able to capitalize on opportunities when or if they become available. At June 30, 2005, we continued to enjoy a strong balance sheet and had no bank debt with approximately $27 million of cash and cash equivalents. These funds are expected to be used for oil and gas exploration and development activities and for general corporate purposes.

Net cash flow provided from operating activities during the first six months of 2005 was $4.4 million compared to cash flow used in operating activities of $5.1 million during the first half of 2004.



---------------------------------------------------------------------
---------------------------------------------------------------------
($000s)
---------------------------------------------------------------------
Funds from operations 4,559
Net changes in accounts receivable and other 311
Net changes in current liabilities 508
Net changes in current income taxes payable (1,016)
---------------------------------------------------------------------
Cash flow from operating activities 4,362
---------------------------------------------------------------------
---------------------------------------------------------------------


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

Our current cash flow from oil and gas operations is mainly derived from the Kotaneelee field. Net field level receipts from Kotaneelee represented approximately 64% of our total net field receipts for the six months ended June 30, 2005, compared to 68% in the same period of 2004.

Kotaneelee continues to experience a decrease in formation reservoir pressure, an increase in water production, and as a result, a decrease in gas production. The Kotaneelee I-48 well has experienced a drop in production from the first quarter of 2005 of approximately 25%. There is a possibility that our cash flow from Kotaneelee could either be significantly reduced or terminated at any time in the future.

In an effort to extend the remaining life of the Kotaneelee B-38 well, during the spring of 2005 the operator installed a siphon string in order to improve the lifting of the increasing amount of water. We participated to the extent of our working interest in the operation. To date, the operator has been unable to successfully establish production flow from within the siphon string; however, the well is currently producing up the annulus. It is unclear if the economics justify the operator to attempt to remediate the situation. As the project is not yet complete, we do not know if, or to what degree, it will be successful in extending the economic life of the well.

The potential for significant cost overruns exists in the oil and gas industry, especially in areas where access to the property is remote. A recent example of the risk of cost overruns is as follows:

In 2004, we converted from a 30.67% carried interest in the Kotaneelee natural gas field to a 30.67% working interest and subsequently agreed to participate in the drilling of the L-38 well at an initial estimated cost of $16.7 million (net $5.1 million our share). The well spud on August 22, 2004 and reached total depth on March 10, 2005 and due to the technical and drilling challenges experienced by the operator, gross drilling costs were approximately $33.1 million ($10.1 million our share). The L-38 well was completed in late March 2005 with estimated gross completion costs of $3.6 million ($1.1 million our share). Additional gross costs of $4.6 million ($1.4 million our share) were incurred for surface equipment and tie-in of the well for production. Total costs for the project are now estimated to be $41 million ($12.6 million our share), all of which are reflected in the financial statements for the six months ended June 30, 2005.

The Kotaneelee L-38 well was tied in and commenced production on May 4, 2005. The well has stabilized at a rate of approximately 17 mmcf/d, resulting in expected sales volumes, after shrinkage, of 12.8 mmcf/d (4.1 mmcf/d net). The production rate has remained steady over the 3 months that it has been on-stream.

We caution that initial production rates may not be indicative of future rates.

We have agreed to participate in an upgrade to the Kotaneelee water disposal system for approximately $426,000 (our share). The upgrade will increase the water disposal capacity from 2,200 bbl/d to 4,000 bbl/d. Although little water is currently being produced from the new L-38 well, given the history of the reservoir we expect water to encroach at some time in the future. As we also expect water volumes to continue to increase at B-38 and I-48, we agreed with the operator that this upgrade was essential.

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 the current market, we have concentrated our attention on growth through the drill bit.

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

We drilled two Company operated wells (one deep test and one shallow test) in the Mike/Hazel area of northeast British Columbia during the winter 2004/2005 drilling/construction season. As a result of three separate land transactions, we acquired additional mineral rights in the area. We paid 100% of the drilling and completion costs to earn 85% of the deep mineral rights on our A-19-L/94-H-2 deep test well. The cost to drill the A-19-L well was approximately $4.0 million. We also drilled the shallower A-81-H/94-H-3 well in February 2005 on our 100% working interest lands at an estimated cost of $1.0 million. Both of these wells were drilled and cased, however as a result of an unusually short winter drilling season due to early warm weather, we were unable to gain the necessary access for well completion and production testing programs.

Late in the second quarter, we were able to access the Mike/Hazel area through roads that we constructed prior to break-up. We have completed the Mike A-19-L/94-H-2 well and are currently waiting for surface conditions to improve to remove downhole recorders. We also performed certain components of the completion program for Mike A-81-H/94-H-3, and are currently also waiting for weather conditions to improve to finish those activities. Upon finalization of these activities we expect to be able to properly size equipment to enable us to bring one or both of these wells on production either late in the fourth quarter or during the first quarter of 2006.

We currently have applied for and received respective regulatory approval to drill four wells in northeast British Columbia. We expect to apply for at least an additional two wells in British Columbia in the third quarter of 2005, and possibly up to two locations in southern Alberta.

During the three and six months ended June 30, 2005, we expended $5.1 million and $14.9 million respectively on capital additions, as summarized below:



---------------------------------------------------------------------
---------------------------------------------------------------------
Capital Three months ended June 30, Six months ended June 30,
Expenditures % %
($000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Land and
acquisitions 225 9 2,400 1,567 287 446
Geological
and geophysical 329 222 48 703 898 (22)
Drilling and
completion 2,702 405 567 10,640 702 1,416
Facilities
and equipment 1,799 134 1,242 2,012 154 1,207
Other 1 - - 17 14 19
---------------------------------------------------------------------
Total capital
expenditures 5,056 770 557 14,939 2,055 627
Dispositions - - - - - -
---------------------------------------------------------------------
Net capital
expenditures 5,056 770 557 14,939 2,055 627
---------------------------------------------------------------------
---------------------------------------------------------------------


In early 2005 we budgeted $16.5 million of capital expenditures for oil and gas activities during 2005. Capital expenditures through June 30, 2005 were $14.9 million, including previously disclosed cost overruns of certain projects. The Board of Directors has authorized additional capital expenditures for 2005 of up to $6.5 million over the original budgeted amount for projects in core areas. Major projects within this budget will be considered by the Board of Directors on a case by case basis.

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

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.

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

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

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

The term "BOE" may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf/1 bbl is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.




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

---------------------------------------------------------------------
---------------------------------------------------------------------
June 30, December 31,
Note 2005 2004
---------------------------------------------------------------------

Assets

Current assets
Cash and cash equivalents 2 $ 27,260,068 $ 39,353,717
Accounts receivable 1,759,096 2,495,678
Other assets 795,584 370,011
---------------------------------------------------------------------
29,814,748 42,219,406

Oil and gas properties
and equipment 3 29,933,294 17,570,085
---------------------------------------------------------------------

Total assets $ 59,748,042 $ 59,789,491
---------------------------------------------------------------------
---------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities
Accounts payable $ 2,342,549 $ 3,627,644
Accrued liabilities 2,814,105 2,810,263
Accrued income taxes payable - 1,016,419
---------------------------------------------------------------------
5,156,654 7,454,326

Future income tax liability 2,699,864 2,569,864
Asset retirement obligations 4 3,052,292 2,675,743
---------------------------------------------------------------------
Total liabilities 10,908,810 12,699,933
---------------------------------------------------------------------

Shareholders' equity
Share capital 5 14,838,357 14,417,770
Contributed surplus 5 29,089,406 29,014,151
Retained earnings 4,911,469 3,657,637
---------------------------------------------------------------------
Total shareholders' equity 48,839,232 47,089,558
---------------------------------------------------------------------

Total liabilities and
shareholders' equity $ 59,748,042 $ 59,789,491
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes.


CANADA SOUTHERN PETROLEUM LTD.
CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(in Canadian dollars)
(unaudited)

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
Note 2005 2004 2005 2004
---------------------------------------------------------------------

Revenues
Petroleum
and natural
gas sales $ 4,112,675 $ 2,334,707 $ 7,387,968 $ 3,582,819
Royalties (574,452) (521,517) (1,053,155) (590,243)
Carried interest 1,306 1,469,792 3,678 3,475,794
---------------------------------------------------------------------
3,539,529 3,282,982 6,338,491 6,468,370
Interest
and other
income 192,710 498,782 430,586 782,915
---------------------------------------------------------------------
3,732,239 3,781,764 6,769,077 7,251,285
---------------------------------------------------------------------

Expenses
Lease operating
costs 538,104 437,921 1,012,533 661,421
Transportation 1 513,457 139,498 904,538 139,498
General and
administrative 771,952 996,739 1,408,991 1,649,649
Depletion and
depreciation 1,753,000 861,000 2,819,000 1,622,000
Asset retirement
obligations
accretion 67,300 60,000 133,300 120,000
Stock-based
compensation 78,200 233,700 223,050 267,100
Foreign exchange
gains (16,415) (67,556) (37,138) (95,635)
---------------------------------------------------------------------
3,705,598 2,661,302 6,464,274 4,364,033
---------------------------------------------------------------------
Income before
income taxes 26,641 1,120,462 304,803 2,887,252

Income tax
recovery
(expense) 6 1,119,029 (550,000) 949,029 (1,161,000)
---------------------------------------------------------------------
Net income 1,145,670 570,462 1,253,832 1,726,252

Retained
earnings
- beginning
of period 3,765,799 1,534,161 3,657,637 378,371
---------------------------------------------------------------------
Retained
earnings
- end of
period $ 4,911,469 $ 2,104,623 $ 4,911,469 $ 2,104,623
---------------------------------------------------------------------
---------------------------------------------------------------------

Net income
per share: 7
Basic $ 0.08 $ 0.04 $ 0.09 $ 0.12
Diluted $ 0.08 $ 0.04 $ 0.09 $ 0.12

Average number
of shares
outstanding:
Basic 14,425,542 14,417,770 14,421,677 14,417,770
Diluted 14,527,920 14,420,429 14,496,540 14,419,394

See accompanying notes.


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

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
Note 2005 2004 2005 2004
---------------------------------------------------------------------

Cash flow
relating to
operating
activities:
Net income $ 1,145,670 $ 570,462 $ 1,253,832 $ 1,726,252
Adjustments to
reconcile net
income to net
cash provided
by (used in)
operating
activities:
Depletion and
depreciation 1,753,000 861,000 2,819,000 1,622,000
Asset retirement
obligations
accretion 67,300 60,000 133,300 120,000
Asset retirement
expenditures (148) (663) (404) (880)
Stock-based
compensation 78,200 233,700 223,050 267,100
Future income
tax expense
(recovery) (40,000) (86,000) 130,000 365,000
--------------------------------------------------------------------
Funds from
operations 3,004,022 1,638,499 4,558,778 4,099,472

Change in
non-cash
working
capital 8 (784,667) 2,302,881 (197,138) (9,218,924)
---------------------------------------------------------------------
Cash flow from
(used in)
operating
activities 2,219,355 3,941,380 4,361,640 (5,119,452)
---------------------------------------------------------------------

Cash flow
relating to
investing
activities:
Additions to
oil and gas
properties and
equipment (5,055,750) (770,489)(14,938,556) (2,055,442)
Change in non-cash
working capital 8 (4,126,209) (262,622) (1,789,525) (2,023,695)
---------------------------------------------------------------------
Cash flow used
in investing
activities (9,181,959) (1,033,111)(16,728,081) (4,079,137)
---------------------------------------------------------------------

Cash flow
relating to
financing
activities:
Exercise of
stock options 5 272,792 - 272,792 -
---------------------------------------------------------------------
Cash flow from
financing
activities 272,792 - 272,792 -
---------------------------------------------------------------------

Increase
(decrease) in
cash and cash
equivalents (6,689,812) 2,908,269 (12,093,649) (9,198,589)

Cash and cash
equivalents at
the beginning
of period 33,949,880 36,975,528 39,353,717 49,082,386
---------------------------------------------------------------------
Cash and cash
equivalents
at the end
of period 2 $27,260,068 $39,883,797 $27,260,068 $39,883,797
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes.

Notes to the Consolidated Financial Statements
Three and six months ended June 30, 2005 and 2004
(in Canadian dollars)
(unaudited)


1. Summary of significant accounting policies

Significant accounting policies and basis of presentation

The accompanying unaudited interim consolidated financial statements, including the accounts of Canada Southern Petroleum Ltd. ("Canada Southern" or "the Company") and its wholly-owned subsidiaries, Canpet Inc. and C.S. Petroleum Limited, have been prepared in accordance with Canadian generally accepted accounting principles ("Canadian GAAP"). These financial statements have been prepared following the same accounting policies and methods of computation as the annual audited consolidated financial statements for the year ended December 31, 2004. The effect of differences between these principles and accounting principles generally accepted in the United States ("U.S. GAAP") is discussed in Note 9. Certain information and disclosures normally required to be included in the notes to the annual consolidated financial statements have been omitted or condensed. These interim financial statements should be read in conjunction with the consolidated financial statements and footnotes thereto included in the Company's annual report for the year ended December 31, 2004.

Comparative figures

Certain figures presented for comparative purposes have been reclassified to conform to the current period's financial statement presentation.

Transportation costs

Effective January 1, 2005, and consistent with the adoption of Canadian Institute of Chartered Accountants Handbook Section 1100, "Generally Accepted Accounting Principles", transportation costs are presented as an expense in the Statement of Operations and Retained Earnings. For the period January 1, 2004 to April 30, 2004, when the Company was in a carried interest position at Kotaneelee, transportation costs of $263,841 are shown net of carried interest revenues and have not been reclassified. The Company does not receive sufficient information from the operators of its other minor working interest properties to determine the amount of related transportation costs.

2. Cash and cash equivalents

Canada Southern considers all highly liquid short-term investments with maturities of three months or less at date of acquisition to be cash equivalents. Cash equivalents are carried at cost, which approximates market value due to their short term nature.



---------------------------------------------------------------------
---------------------------------------------------------------------
June 30, December 31,
2005 2004
---------------------------------------------------------------------
CASH $ 740,108 $ 219,353
Canadian marketable securities
(yield: 2005 - 2.5%; 2004 - 2.5%) 25,295,376 38,173,069
U.S. marketable securities
(yield: 2005 - 3.3%; 2004 - 2.4%) 1,224,584 961,295
---------------------------------------------------------------------
Total $ 27,260,068 $ 39,353,717
---------------------------------------------------------------------
---------------------------------------------------------------------


3. Oil and gas properties and equipment

The following tables provide the detail of oil and gas properties and equipment at June 30, 2005 and December 31, 2004:



---------------------------------------------------------------------
---------------------------------------------------------------------
Depreciation,
Depletion and Net Book
Cost Write downs Value
---------------------------------------------------------------------
BALANCE, JUNE 30, 2005
Oil and gas properties $ 52,046,536 $ 22,192,766 $ 29,853,770
Oil and gas properties
(U.S.) 1,319,218 1,319,218 -
---------------------------------------------------------------------
53,365,754 23,511,984 29,853,770
Office equipment 207,876 128,352 79,524
---------------------------------------------------------------------
$ 53,573,630 $ 23,640,336 $ 29,933,294
---------------------------------------------------------------------
---------------------------------------------------------------------

Balance, December 31, 2004
Oil and gas properties $ 36,881,033 $ 19,385,766 $ 17,495,267
Oil and gas properties
(U.S.) 1,319,218 1,319,218 -
---------------------------------------------------------------------
38,200,251 20,704,984 17,495,267
Office equipment 191,170 116,352 74,818
---------------------------------------------------------------------
$ 38,391,421 $ 20,821,336 $ 17,570,085
---------------------------------------------------------------------
---------------------------------------------------------------------


As at June 30, 2005, there were $2,449,044 (2004 - $634,601) of capital assets relating to unproved properties which have been excluded from the depletion calculation.

During the six months ended June 30, 2005 and 2004, no indirect general and administrative expenses were capitalized.



4. Asset retirement obligations

June 30, December 31,
2005 2004
---------------------------------------------------------------------
Balance - beginning of period $ 2,675,743 $ 2,436,986
Liabilities incurred 243,653 -
Asset retirement obligations accretion 133,300 240,000
Asset retirement expenditures (404) (1,243)
---------------------------------------------------------------------
Balance - end of period $ 3,052,292 $ 2,675,743
---------------------------------------------------------------------
---------------------------------------------------------------------


The total undiscounted amount of the cash flows required to settle the Company's asset retirement obligation is estimated to be $4,146,000. The estimated cash flows have been discounted using credit-adjusted risk-free interest rates ranging from 7% to 11%. These payments are expected to be incurred between the years 2005 and 2022.



5. Share capital

Authorized

Unlimited common shares
Unlimited first preferred shares
Unlimited second preferred shares

Issued

---------------------------------------------------------------------
---------------------------------------------------------------------
Number of Share Contributed Total
Common shares Shares Capital Surplus Capital
---------------------------------------------------------------------
Outstanding at
December 31,
2003 14,417,770 $ 14,417,770 $ 28,177,451 $ 42,595,221
Stock-based
compensation - - 836,700 836,700
---------------------------------------------------------------------
Outstanding at
December 31,
2004 14,417,770 14,417,770 29,014,151 43,431,921
Stock-based
compensation - - 223,050 223,050
Exercise of
stock options 43,395 420,587 (147,795) 272,792
---------------------------------------------------------------------
Outstanding at
June 30, 2005 14,461,165 $ 14,838,357 $ 29,089,406 $ 43,927,763
---------------------------------------------------------------------
---------------------------------------------------------------------


The shares outstanding throughout 2004 and up until March 2, 2005 were limited voting shares with $1.00 par value per share. Pursuant to special shareholders meetings held in late 2004, Canada Southern received final approval of the continuance of the Company from Nova Scotia to Alberta on March 2, 2005. As a result, the outstanding limited voting shares became common shares on a 1 for 1 basis. Also pursuant to the continuance, Canada Southern is authorized to issue two series of preferred shares.

Stock options

Under the terms of Canada Southern's 1985, 1992 and 1998 stock option plans, Canada Southern is authorized to grant options to purchase common shares at prices based on the market price of the shares as determined on the date of the grant. The options are normally issued for a period of five years from the date of grant.

A summary of stock option transactions for the six months ended June 30, 2005 is as follows:



---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted Average
Options Exercise Price
---------------------------------------------------------------------
Outstanding at beginning of period 550,000 $ 6.87
Granted 10,000 6.59
Expired (50,000) 7.53
Exercised (43,395) 6.29
---------------------------------------------------------------------
Outstanding at June 30, 2005 466,605 $ 6.85
---------------------------------------------------------------------
---------------------------------------------------------------------
Exercisable at June 30, 2005 313,270 $ 6.73
---------------------------------------------------------------------
---------------------------------------------------------------------


Options granted during the six months ended June 30, 2005, vest 1/3 on January 26, 2006, 1/3 on January 26, 2007, and the remainder on January 26, 2008. On July 12, 2005, 50,000 options to purchase common shares were granted to a director. These options vest 1/3 immediately, 1/3 on July 12, 2006, and the remainder on July 12, 2007.

As at June 30, 2005, there were 387,834 common shares reserved for future issuance under the stock option plans.

The following table summarizes information about stock options outstanding at June 30, 2005:



---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted Weighted Weighted
Ranges of Average Average Average
Exercise Number Remaining Exercise Number Exercisable
Prices Outstanding Term (years) Price Exercisable Price
---------------------------------------------------------------------
$ 5.50 to
5.99 80,000 4.1 $ 5.89 80,000 $ 5.89
$ 6.00 to
6.49 120,000 3.8 6.26 50,000 6.21
$ 6.50 to
6.99 151,605 2.5 6.84 111,605 6.84
$ 7.53 50,000 1.5 7.53 50,000 7.53
$ 8.64 65,000 4.5 8.64 21,665 8.64
---------------------------------------------------------------------
$ 5.50 to
8.64 466,605 3.3 $ 6.85 313,270 $ 6.73
---------------------------------------------------------------------
---------------------------------------------------------------------


The fair value for stock options granted is estimated at the date of grant using a Black-Scholes option pricing model. Option valuation models require the input of highly subjective assumptions including the expected stock price volatility. A summary of the weighted average assumptions used and the resulting values for options granted in the first six months of 2005 is as follows:



Six months ended June 30,
2005
---------------------------------------------------------------------
Assumptions:
Dividend yield 0%
Risk-free interest rate 3.52%
Expected life 5 years
Expected volatility 60.5%
---------------------------------------------------------------------
Results:
Weighted average fair value of options granted $ 3.59
---------------------------------------------------------------------
---------------------------------------------------------------------


As at August 9, 2005, there were 14,466,165 common shares and 456,605 stock options outstanding.



6. Income tax recovery (expense)

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Income tax
Current $ 1,079,029 $ (636,000) $ 1,079,029 $ (796,000)
Future 40,000 86,000 (130,000) (365,000)
---------------------------------------------------------------------
$ 1,119,029 $ (550,000) $ 949,029 $ (1,161,000)
---------------------------------------------------------------------
---------------------------------------------------------------------


In 2003, the tax returns for the taxation years of 1994 to 2002 inclusive were re-filed. In June 2005, the Notice of Reassessment was received and a one-time recovery of current income tax was recorded.

7. Net income per share

The following table outlines the calculation of basic and diluted net income per share using the treasury stock method:



---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
2005 2004 2005 2004
---------------------------------------------------------------------

Net income $ 1,145,670 $ 570,462 $ 1,253,832 $ 1,726,252
---------------------------------------------------------------------
---------------------------------------------------------------------

Weighted
average
common
shares
outstanding 14,425,542 14,417,770 14,421,677 14,417,770
Effect of
dilutive
stock options 102,378 2,659 74,863 1,624
---------------------------------------------------------------------
14,527,920 14,420,429 14,496,540 14,419,394
---------------------------------------------------------------------
---------------------------------------------------------------------

Basic
earnings
per share $ 0.08 $ 0.04 $ 0.09 $ 0.12
Diluted
earnings
per share $ 0.08 $ 0.04 $ 0.09 $ 0.12
---------------------------------------------------------------------
---------------------------------------------------------------------

8. Supplemental disclosure of cash flow information

Changes in non-cash working capital were as follows:

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Decrease
(increase)
in non-cash
working
capital:
Accounts
receivable $ (123,475) $ 1,437,719 $ 736,582 $ 906,423
Other assets (362,529) 147,860 (425,573) 116,534
Accounts
payable (3,295,948) (223,573) (1,285,095) (2,068,338)
Accrued
liabilities (437,505) 73,250 3,842 (1,049,938)
Accrued income
taxes payable (691,419) 605,003 (1,016,419) (9,147,300)
---------------------------------------------------------------------
Net change
in non-cash
working
capital $ (4,910,876) $ 2,040,259 $ (1,986,663) $(11,242,619)
---------------------------------------------------------------------
---------------------------------------------------------------------
Relating to:
Operating
activities $ (784,667) $ 2,302,881 $ (197,138) $ (9,218,924)
Investing
activities (4,126,209) (262,622) (1,789,525) (2,023,695)
---------------------------------------------------------------------

$ (4,910,876) $ 2,040,259 $ (1,986,663) $(11,242,619)
---------------------------------------------------------------------
---------------------------------------------------------------------


Other cash flow information:

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Cash taxes
paid $ - $ 300 $ 325,000 $ 9,943,300
---------------------------------------------------------------------
---------------------------------------------------------------------


9. U. S. GAAP differences

The reconciliation of net income between Canadian and U.S. GAAP is
summarized in the table below:

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended June 30, Six months ended June 30,
2005 2004 2005 2004
---------------------------------------------------------------------

Net income
- Canadian
GAAP $ 1,145,670 $ 570,462 $ 1,253,832 $ 1,726,252
Change in
income taxes
(c) - 26,400 - -
Net income
- U.S. GAAP 1,145,670 596,862 1,253,832 1,726,252
Change in
value of
available for
sale
securities (b) (29,883) 34,755 (9,454) 44,074
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Other
comprehensive
income $ 1,115,787 $ 631,617 $ 1,244,378 $ 1,770,326
---------------------------------------------------------------------
---------------------------------------------------------------------
U.S. GAAP
- net income
per share
Basic $ 0.08 $ 0.04 $ 0.09 $ 0.12
Diluted $ 0.08 $ 0.04 $ 0.09 $ 0.12
---------------------------------------------------------------------
---------------------------------------------------------------------
Average number
of shares
outstanding:
Basic 14,425,542 14,417,770 14,421,677 14,417,770
Diluted 14,527,920 14,420,429 14,496,540 14,419,394
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---------------------------------------------------------------------

The balance sheet information for the Canadian and U.S. GAAP
differences is summarized in the table below:

---------------------------------------------------------------------
---------------------------------------------------------------------
June 30, 2005 December 31, 2004
---------------------------------------------------------------------
Canadian U.S. Canadian U.S.
GAAP GAAP GAAP GAAP
---------------------------------------------------------------------

Current
assets (b) $ 29,814,748 $ 29,890,563 $ 42,219,406 $ 42,307,342
Oil and gas
properties
and equipment 29,933,294 29,933,294 17,570,085 17,570,085
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$ 59,748,042 $ 59,823,857 $ 59,789,491 $ 59,877,427
---------------------------------------------------------------------
---------------------------------------------------------------------

Current
liabilities $ 5,156,654 $ 5,156,654 $ 7,454,326 $ 7,454,326
Future income
tax liability
(b) 2,699,864 2,697,197 2,569,864 2,570,957
Asset
retirement
obligations 3,052,292 3,052,292 2,675,743 2,675,743
Share capital
and contributed
surplus (a) 43,927,763 43,927,763 43,431,921 45,217,294
Retained
earnings (a) 4,911,469 4,911,469 3,657,637 1,872,264
Accumulated other
comprehensive
income (b) - 78,482 - 86,843
---------------------------------------------------------------------
$ 59,748,042 $ 59,823,857 $ 59,789,491 $ 59,877,427
---------------------------------------------------------------------
---------------------------------------------------------------------


(a) Stock-based compensation

For U.S. GAAP reporting purposes, Canada Southern elected to adopt the fair value expense recognition provisions of Financial Accounting Standards (FAS) 123 "Accounting for Stock-based Compensation" and has reported using the modified prospective method. This method provides prospective expense recognition for all new awards and the unvested portion of awards granted subsequent to January 1, 1995. As a result, the cumulative effects of stock option grants from 1995 to January 1, 2004 were recorded as an opening adjustment to retained earnings and shareholders equity as at January 1, 2004. This is in contrast to Canadian GAAP where prior periods were restated.

(b) Other comprehensive income

Classifications within other comprehensive income relate to unrealized gains on certain investments in equity securities. During 1998, the Company wrote down the value of its interest in the Tapia Canyon, California heavy oil project to a nominal value. During August 1999, the project was sold and the Company received shares of stock in the purchaser. The purchaser has become a public company (Sefton Resources, Inc), which is listed on the London Stock Exchange (trading symbol "SER"). At June 30, 2005, the Company owned approximately 0.6% (December 31, 2004 - 0.6%) of Sefton Resources, Inc. ("Sefton") with a fair market value of $75,815 (December 31, 2004 - $87,936) and a carrying value of $1.00.

Under U.S. GAAP, the Sefton shares would be classified as available-for-sale securities and recorded at fair value at June 30, 2005. This would result in other comprehensive income for the three and six month periods ended June 30, 2005 and 2004. In addition, the balance sheet would reflect Marketable Securities in the amount of $75,815 (December 31, 2004 - $87,936) with a corresponding credit to Shareholders' Equity - Accumulated other comprehensive income in the same amount.

(c) Future income taxes

Under Canadian GAAP, the benefits of substantively enacted income tax rate reductions can be recorded, however under FASB 109 the benefits attributable to income tax rate changes can only be recorded when enacted. During the three-month period ended June 30, 2004, a substantially enacted income tax rate reduction was enacted and U.S. GAAP required the recognition of an future income tax benefit of $26,400 related to an Alberta tax rate reduction recognized in the first quarter of 2004 for Canadian GAAP purposes.



Corporate Information
Head Office
Directors
250, 706 - 7th Avenue SW
Richard C. McGinity (1)(2)(4) Calgary, AB T2P 0Z1
School Street Capital Group Tel: (403) 269-7741
Crowheart, Wyoming Fax: (403) 261-5667
Email: info@cansopet.com
Donald E. Foulkes (1)(2)(3)(4)
AltaCanada Energy Corp. Website
Calgary, Alberta
www.cansopet.com
Myron F. Kanik (1)(2)(3)(4)
Kanik & Associates Ltd. Auditors
Calgary, Alberta
Ernst & Young LLP
Raymond P. Cej (1)(2)(3)(4) Suite 1000, Ernst & Young Tower
BA Energy Inc. 440 - 2nd Avenue SW
Calgary, Alberta Calgary, AB T2P 5E9
www.ey.ca
John W.A. McDonald
Canada Southern Petroleum Ltd. Legal Counsel
Calgary, Alberta
Canada
(1) Member of the Audit Blake, Cassels & Graydon LLP
Committee Suite 3500, East Tower, Bankers
(2) Member of the Corporate Hall
Governance and Nominating 855 - 2nd Street SW
Committee Calgary, AB T2P 4J8
(3) Member of the Operations
Committee United States
(4) Member of the Compensation Murtha Cullina LLP
Committee 29th Floor, City Place I
185 Asylum Street
Officers Hartford, CT 06103-3469

John W.A. McDonald Evaluation Engineers
President & Chief Executive
Officer Gilbert Laustsen Jung Associates
Ltd.
Randy L. Denecky 4100, 400 - 3rd Avenue SW
Vice President Finance & Calgary, AB T2P 4H2
Chief Financial Officer
Stock Transfer Agent
Patrick C. Finnerty
Corporate Secretary American Stock Transfer & Trust
59 Maiden Lane
New York, NY 10038
Tel: (800) 937-5449

Stock Exchange Listing

NASDAQ: CSPLF
The Toronto Stock Exchange: CSW

Abbreviations

bbl barrels
bbl/d barrels per day
mbbl 1,000 barrels
boe barrels of oil equivalent (6:1)
boe/d barrels of oil equivalent per day
(6:1)
mboe 1,000 Barrels of oil equivalent
(6:1)
mcf 1,000 cubic feet
mcf/d 1,000 cubic feet per day
mmcf 1,000,000 cubic feet
mmcf/d 1,000,000 cubic feet per day
bcf billion cubic feet
NGL natural gas liquids


Contact Information

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