Canada Southern Petroleum Ltd.
NASDAQ : CSPLF
TSX : CSW

Canada Southern Petroleum Ltd.

November 14, 2005 08:00 ET

Canada Southern Reports Third Quarter Results

CALGARY, ALBERTA--(CCNMatthews - Nov. 14, 2005) - Canada Southern Petroleum Ltd. (TSX:CSW) (NASDAQ:CSPLF) is pleased to announce operational and financial results for the three and nine months ended September 30, 2005.



Financial and Operating Highlights

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Three months ended Nine months ended
September 30, September 30,
% %
2005 2004 Change 2005 2004 Change
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Financial ($000s, except
per share)

Gross revenues 6,068 3,521 72 12,837 10,773 20
Funds from
operations(1) 4,047 1,569 158 8,606 5,669 52
Per share
- basic ($) 0.28 0.11 155 0.60 0.39 54
- diluted ($) 0.28 0.11 155 0.59 0.39 51

Net income 1,003 445 125 2,257 2,171 4
Per share
- basic and
diluted ($) 0.07 0.03 133 0.16 0.15 7
Capital
expenditures, net 5,774 3,038 90 20,712 5,093 307
Working capital 23,106 38,787 (40) 23,106 38,787 (40)
Total assets 61,376 56,162 9 61,376 56,162 9
Shareholders'
equity 50,204 45,641 10 50,204 45,641 10
Weighted
average
shares
outstanding (000s)
Basic 14,475 14,418 - 14,440 14,418 -
Diluted 14,507 14,426 - 14,482 14,421 -
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Operational

Sales volumes
Natural gas mcf/d 7,552 6,451 17 6,607 4,287 54
Oil and
natural
gas liquids bbl/d 26 28 (7) 30 29 4
Carried
interest
natural gas mcf/d 2 1 100 1 2,793 (100)
Combined
(6:1)(2) boe/d 1,285 1,103 16 1,131 1,209 (6)
Average sales
prices
Natural gas $/mcf 9.35 6.32 48 7.55 5.99 26
Oil and
natural
gas liquids $/bbl 64.35 38.46 67 51.14 36.08 42
Combined $/boe 56.27 37.96 48 45.46 35.92 27
Operating
netback $/boe 39.48 26.85 47 29.42 25.34 16
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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

- Strong financial statement results include the benefits of higher product pricing, higher volumes, and lower general and administrative costs, partially offset by higher depletion rates.

- Reserve additions of 0.3 bcf (after Kotaneelee revision) during the third quarter and a total of 4.2 bcf for the nine months ended September 30, 2005, or a 56% increase year to date increase of proven reserves.

- Upcoming winter drilling season expected to be active.

- Presentations to financial community commencing in the 4th quarter.

Report to Shareholders

During and subsequent to the third quarter of 2005, we focused primarily on activity in northeast British Columbia as part of our strategy to reduce our dependence on the Kotaneelee field. Notwithstanding the high demand for equipment, services, personnel, and the unpredictable weather conditions, we accomplished the following:

- Completed, tested and added reserves on wells drilled last winter at:

-- both operated Mike/Hazel wells, and

-- one non-operated well in Buick Creek

- Drilled two 100% interest wells (one successful)

- Prepared for the upcoming winter drilling season.

Mike/Hazel

In the Mike/Hazel area, we are pleased to report that both of the wells we drilled last winter were new pool discoveries.

The 85% interest a-19-L/94-H-2 well discovered a Jean Marie gas pool at a depth of approximately 8,200 feet. To the best of our knowledge, there is no Jean Marie production within approximately 25 miles of this discovery. Given its lack of proximity to comparable pools in the area, we will tie in the well and evaluate its long term productive capability. The well's performance will assist us in determining when, or if, follow up drilling to this depth would be economic to pursue on additional identified anomalies by our proprietary 3-D seismic across 100% interest Company lands.

The 100% interest a-81-H/94-H-2 discovered a new pool of liquids-rich Gething gas. We plan to spend the necessary capital to tie-in this well and pursue further drilling opportunities in the area. Surveys for our new well locations and pipeline right of ways are expected to be submitted for regulatory approval within the coming weeks. Available equipment and services permitting, we expect to tie-in existing wells and drill new wells in the area this upcoming winter season.

Buick Creek

Our recently drilled 100% interest Buick Creek d-60-C/94-A-14 well is currently undergoing flow testing in the primary zone of interest. We are optimistic that we will include reserves additions for this well and will proceed with its tie-in for production in 2006.

The non-operated Buick Creek b-88-C/94-A-14 well (22.5% Company interest) that was drilled last winter has now been completed and tested; accordingly, we have recorded additional proven reserves in the third quarter. This well is currently being tied-in for production.

We are expecting the operator of the Buick Creek d-24-E/94-A-14 well (22.5% Company interest), also drilled last winter, to complete and test this well in the near future. Based on log analysis, we are optimistic that this well will also contribute to reserve additions prior to year end and production cash flows in 2006.

Financial

We are pleased that net income is higher in this quarter than for the same period in 2004. The principal contributing factors were the significant increase in commodity prices and higher production volumes.

Net income for the quarter ended September 30, 2005 was $1.0 million, or $0.07 per share, compared to $445,000, or $0.03 per share, for the same period in 2004. Net income for the nine months ended September 30, 2005 was $2.3 million, or $0.16 per share, compared to $2.2 million, or $0.15 per share, for the same period in 2004.

Funds from operations for the quarter ended September 30, 2005 was $4.0 million, or $0.28 per share, compared to $1.6 million, or $0.11 per share, for the same period in 2004. For the nine months ended September 30, 2005 funds from operations were $8.6 million, or $0.60 per basic share, compared to $5.7 million, or $0.39 per share, for the same period in 2004.

Other

The Kotaneelee L-38 well, which commenced production on May 4, 2005, continues to produce approximately 4.0 mmcf/d net sales to us. In the third quarter of 2005, the Kotaneelee I-48 well, and to a lesser degree, the B-38 well experienced further declines in production. The I-48 well averaged approximately 1.7 mmcf/d net sales to us for the month of June 2005, however by late October this well was contributing only 0.1 mmcf/d of net sales to us. The operator is currently evaluating what, if any, remedial action can be taken.

We continue to increase the proportion of our production that we market ourselves. Effective November 1, 2005, we commenced marketing our production from Buick Creek. We now control the marketing of the majority of our gas, which is currently being sold on a daily basis on the spot market.

This upcoming winter drilling season will be our busiest in many years, as we expect to:

- Install surface well equipment on two operated wells at Mike/Hazel and construct approximately 5 miles of pipeline infrastructure to enable us to commence production in the first quarter of 2006

- Install surface well equipment and pipelines on up to three (1.45 net) wells in the Buick Creek area

- Drill up to three operated wells in the Mike/Hazel area

- Commence presentations to the investment community.

Our goal remains to increase shareholder value and we believe that by selectively adding to our undeveloped land base and carefully and thoroughly evaluating and exploiting our development opportunities, we will build this value for our shareholders.

"John W.A. McDonald"

John W.A. McDonald

President and Chief Executive Officer

November 7, 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 nine months ended September 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 November 7, 2005.



Overview

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Three months ended Nine months ended
September 30, September 30,
($000s, except % %
share amounts) 2005 2004 Change 2005 2004 Change
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Petroleum and
natural gas
sales 6,647 3,850 73 14,034 7,433 89
Royalties (743) (537) 38 (1,796) (1,128) 59
Carried interest 2 6 (67) 6 3,481 (100)
Lease operating
costs (508) (384) 32 (1,520) (1,045) 45
Transportation (732) (211) 246 (1,636) (350) 367
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Operating netback 4,666 2,724 71 9,088 8,391 8
Interest and
other income 163 204 (21) 593 987 (40)
General and
administrative (684) (788) (13) (2,093) (2,438) (14)
Foreign exchange
gains (95) (106) (10) (58) (10) 480
Asset retirement
expenditures (3) (1) 200 (3) (1) 200
Current income
tax recovery
(expense) - (464) (100) 1,079 (1,260) -
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Funds from
operations (1) 4,047 1,569 158 8,606 5,669 52
Depletion and
depreciation (2,312) (796) 190 (5,131) (2,418) 112
Asset retirement
obligations
accretion (72) (60) 20 (205) (180) 14
Future income tax (475) (39) 1118 (605) (404) 50
Asset retirement
expenditures 2 1 100 2 1 100
Stock-based
compensation (187) (230) (19) (410) (497) (18)
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Net income 1,003 445 125 2,257 2,171 4
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Funds from operations
per share(1):
Basic ($) 0.28 0.11 155 0.60 0.39 54
Diluted ($) 0.28 0.11 155 0.59 0.39 51
Net income
per share:
Basic ($) 0.07 0.03 133 0.16 0.15 7
Diluted ($) 0.07 0.03 133 0.16 0.15 7
Average number
of shares
outstanding (000s):
Basic 14,475 14,418 - 14,440 14,418 -
Diluted 14,507 14,426 - 14,482 14,421 -
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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 Nine months ended
September 30, September 30,
% %
($000s) 2005 2004 Change 2005 2004 Change
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Cash flow from (used in)
operating activities
(GAAP) 2,455 1,603 53 6,816 (3,517) -
Change in non-cash
working capital (GAAP) 1,592 (34) - 1,790 9,186 (81)
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Funds from operations
(non-GAAP) 4,047 1,569 158 8,606 5,669 52
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Funds from Operations

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Three months ended Nine months ended
September 30, September 30,
($000s, except % %
share amounts) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Funds from operations 4,047 1,569 158 8,606 5,669 52
Per share:
Basic ($) 0.28 0.11 155 0.60 0.39 54
Diluted ($) 0.28 0.11 155 0.59 0.39 51
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Funds from operations for the three months ended September 30, 2005 were $4.0 million, or $0.28 per share, up 158% over the same quarter in 2004. For the nine months ended September 30, 2005, funds from operations were $8.6 million or $0.60 per share, 52% higher than the same period last year. The increases were mainly due to higher commodity prices realized so far in 2005, including significantly higher gas prices during the third quarter and the recovery of current income taxes realized as a result of a prior period re-filing of our income tax returns from 1994 to 2002. Increased sales volumes resulting from the successful drilling of the Kotaneelee L-38 well contributed to the gains but were slightly offset by production declines in the I-48 well and, to a lesser degree, the B-38 well at Kotaneelee.



Net Income

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Three months ended Nine months ended
September 30, September 30,
($000s, except % %
share amounts) 2005 2004 Change 2005 2004 Change
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Net income 1,003 445 125 2,257 2,171 4
Per share:
Basic ($) 0.07 0.03 133 0.16 0.15 7
Diluted ($) 0.07 0.03 133 0.16 0.15 7
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Net income for the three month period ended September 30, 2005 was 125% higher than the previous year, due mainly to the higher commodity prices realized during the quarter. Higher revenues for the third quarter of 2005 were tempered somewhat by higher depletion costs.

For the nine months ended September 30, 2005, net income was $2.3 million, or $0.16 per share, slightly higher than the net income for the first nine months of 2004. Higher commodity prices, lower general and administrative expenses and the recovery of current income taxes were 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 Nine months ended
September 30, September 30,
% %
Sales volumes 2005 2004 Change 2005 2004 Change
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Natural gas
Working
interest mcf/d 7,110 5,975 19 6,168 3,811 62
Royalty
interest mcf/d 442 476 (7) 439 476 (8)
Carried
interest mcf/d 2 1 22 1 2,793 (100)
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Total natural
gas mcf/d 7,554 6,452 17 6,608 7,080 (7)
Oil and natural
gas liquids bbl/d 26 28 (9) 30 29 4
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Combined (6:1) boe/d 1,285 1,103 16 1,131 1,209 (6)
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Sales volumes for the third quarter averaged 1,285 boe/d, 16% higher than the comparable quarter in 2004. This increase is due to the added volumes from the Kotaneelee L-38 well, which came on production in May 2005. Production from the L-38 well, which continues to add approximately 4 mmcf/d to our sales volumes, has been partially offset by declining production at the Kotaneelee I-48 and B-38 wells.

Year to date, our sales volumes averaged 1,131 boe/d, relatively unchanged from the 1,209 boe/d averaged year to date in 2004. The production addition of Kotaneelee L-38 has more than offset the production declines; however, this well has only been on production for 5 of the 9 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 third quarter of 2005 were 5.5 mmcf/d, or approximately 73% of our total natural gas sales. This compares to 63% of total gas sales during the third quarter last year. The increase is attributable to the addition of Kotaneelee L-38 volumes beginning in May 2005; however, with the expected increase in production from new wells in combination with the decline in production from the Kotaneelee B-38 and I-48 wells, this percentage is expected to decrease in the coming quarters.

Sales volumes in the third quarter of 2005 continued to be adversely affected by a scheduled turnaround at the third-party 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 100% over the nine month comparative from last year, this is mainly 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 Nine months ended
September 30, September 30,
% %
Revenues ($000s) 2005 2004 Change 2005 2004 Change
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Natural gas
Working interest 6,122 3,472 76 12,730 6,364 100
Royalty interest 373 280 33 886 784 13
Carried interest(1) 2 6 (67) 6 3,481 (100)
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Total natural gas 6,497 3,757 73 13,622 10,629 28
Oil and natural gas
liquids 152 99 53 418 285 47
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Total 6,649 3,856 72 14,040 10,914 29
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(1) "Carried interest" is net of related carried interest royalties,
lease operating expenses, transportation costs, and capital.


Commodity prices remained strong in the third quarter this year and were the major factor in the 72% increase in petroleum and natural gas revenues versus the third quarter last year. The 16% increase in sales volumes, as shown above, was also a contributing factor.

For the nine months ended September 30, 2005, the 2004 conversion of the Kotaneelee carried interest to a working interest in May also contributed to the 29% increase in revenues in two ways. First, revenue was recorded under working interest revenues in all of the first nine months 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.



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Three months ended Nine months ended
September 30, September 30,
% %
Average Sales Prices 2005 2004 Change 2005 2004 Change
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Natural gas
Working interest $/mcf 9.36 6.32 48 7.56 6.09 24
Royalty interest $/mcf 9.16 6.39 43 7.39 6.01 23
Carried
interest(1) $/mcf - - - - 5.83 -
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Total natural
gas $/mcf 9.35 6.32 48 7.55 5.99 26
Oil and natural
gas liquids $/bbl 64.35 38.46 67 51.14 36.08 42
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Combined (6:1) $/boe 56.27 37.96 48 45.46 35.92 27
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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 nine months ending September
30, 2005 was not material.


Average natural gas prices continued to rise during the third quarter of 2005, averaging 47% higher than the second quarter this year and 48% higher than the third 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 recent hurricanes in the Gulf of Mexico.

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 Nine months ended
September 30, September 30,
% %
($000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Crown royalties 713 407 75 1,545 859 80
Freehold and GORR 30 130 (77) 251 269 (6)
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Total 743 538 38 1,796 1,128 59
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As % of working
interest revenues 12% 15% (21) 14% 17% (19)
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Total royalties increased by 38% in the third quarter of 2005, and by 59% for nine month period ended September 30, 2005. The total increase in absolute amounts for royalties this year as compared with last year was a function of higher revenues, the result of higher sales volumes in the third quarter and higher product prices, and treatment of Kotaneelee as a carried interest in the first four months of the 2004 comparative period.

Royalties as a percentage of working interest revenues amounted to 12% during the third quarter of 2005, compared to 15% during the same quarter last year. This drop results mainly from an adjustment to the over-riding royalties paid at Kotaneelee.

For the nine months ended September 30, 2005 and 2004, royalties as a percentage of working interest revenues decreased to 14% from 17%. 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 in May 2004. 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.

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 Nine months ended
September 30, September 30,
% %
($000s, except per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Lease operating
costs 508 383 32 1,520 1,045 46
Per working
interest boe ($) 4.56 4.07 12 5.26 5.74 (8)
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Lease operating costs increased 32% from the third quarter last year to the third quarter of 2005 as increased volumes in the third quarter of 2005 resulted in corresponding higher operating costs. On a boe basis, however, lease operating costs were only 12% higher. Also contributing to the higher costs in the third quarter of 2005 was a plant turnaround conducted at the third-party operated Siphon facility during the summer. Our lease operating costs on a per boe basis compare favorably with our competition.

For the nine month periods ended September 30, 2005 and 2004, lease operating costs increased by 46% 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 8% from last year, also largely due to the conversion of Kotaneelee to a working interest, where the operating costs averaged $3.17/boe for the first nine months of 2005.



Transportation

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Three months ended Nine months ended
September 30, September 30,
% %
($000s, except per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Transportation 732 210 248 1,636 350 368
Per working interest
boe ($) 6.57 2.23 194 5.67 1.92 195
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Transportation costs for the three months ended September 30, 2005 rose to $732,000, compared to $210,000 for the comparable period in 2004 due mainly to the increased volumes subject to transportation with the addition of the Kotaneelee L-38 well in May 2005.

For the nine months ended September 30, 2005 and 2004, transportation costs were $1.6 million and $350,000 respectively. These costs result almost 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 of 2005. In addition to that shown in the 2004 comparative above, transportation costs of $286,000 were also expended in the nine month period; however they were included as a reduction of carried interest revenues for financial statement purposes. As we continue to take more of our gas production in kind, we expect to record the appropriate amounts of related transportation expenses.

For gas, we consider transportation to include all downstream costs commencing from the point that it 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.



Interest and other income

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Three months ended Nine months ended
September 30, September 30,
% %
($000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Interest income 161 207 (22) 579 671 (14)
Other 2 (3) (167) 14 315 (96)
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Total 163 204 (20) 593 987 (40)
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Interest and other income decreased 20% in the third quarter of 2005 compared to the same period in 2004, resulting from a lower cash balance available for investment.

For the nine month period, interest and other income decreased 40% from 2004, the majority of the decrease relating 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 Nine months ended
September 30, September 30,
% %
($000s, except per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
General and
administrative 654 535 22 1,930 2,008 (4)
Legal 30 254 (88) 164 431 (62)
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Total 684 789 (13) 2,093 2,438 (14)
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Per boe ($) 5.79 7.77 (25) 6.78 7.36 (8)
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General and administrative costs were 22% higher in the third quarter of this year when compared to the same period last year due mainly to retaining a stronger technical team and the related higher salary expenses and geological support costs. These were somewhat offset by lower directors fees and insurance costs. 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 25% lower in the third quarter this year as compared with the respective period in 2004.

For the nine months ended September 30, 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. Overall, on a boe basis, total general and administrative expenses were 8% lower this year to date 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 nine months of 2005 and 2004.



Depletion and Depreciation

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Three months ended Nine months ended
September 30, September 30,
% %
($000s, except per boe) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Depletion and
depreciation 2,312 796 190 5,131 2,418 112
Per boe ($) 19.56 7.84 149 16.61 7.30 128
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Depletion and depreciation expense increased 190% in the third quarter of 2005 from the same period of 2004. For the nine month period ended September 30, 2005, depletion and depreciation more than doubled to $5.1 million compared to the first nine months of 2004. This increase is mainly a result of the increased capital expenditures during the year and the commencement of inclusion of Kotaneelee L-38 capital costs in the depletable base.

All costs incurred in drilling, completing and equipping the Kotaneelee L-38 well that commenced drilling on August 22, 2004 have been 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 reserve additions attributable to this well during the second quarter of 2005. The well's cumulative costs of $12.7 million and reserve additions were included for the first time in the computation of depletion during that quarter.

In the third quarter of 2005, reserve additions totaling 0.7 bcf for the two Mike/Hazel wells and one of two third-party wells drilled at Buick Creek, all drilled in the winter of 2004/2005, have been included in the depletion calculation. These additions were partially offset by a downward revision to the Kotaneelee reserves of 0.4 bcf due to the significant decline in production from the Kotaneelee I-48 well and, to a lesser degree, the B-38 well. This brings the total net reserve additions for the nine months ended September 30, 2005 to 4.2 bcf (702 mboe), or a 56% increase over the proven reserves of 1,238 mboe (before current year production) as at December 31, 2004.

Asset Retirement Obligations Accretion

Asset retirement obligations accretion expense for the third quarter of 2005 increased to $72,000 from $60,000 in the comparative 2004 period. Asset retirement obligations accretion expense for the nine month periods ended September 30 was $205,000 in 2005 versus $180,000 in 2004. The increase in 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 third quarter ended September 30, 2005 was $187,000, compared to $230,000 for the same period in 2004. For the nine month periods ended September 30, stock based compensation expense decreased from $497,000 in 2004 to $410,000 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 $95,000 was recorded in the third quarter of 2005, compared to a loss of $105,000 in the 2004 comparative, nullifying the gains recorded during the previous six months of 2005 and 2004. Losses for the nine month periods were $58,000 and $10,000 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 reasonable certainty. The value of the Canadian dollar was U.S. $.8303 at December 31, 2004 compared to U.S. $.8538 at September 30, 2005.

Income Taxes

The income tax provision for the third quarter ended September 30 decreased from $503,000 in 2004 to $475,000 in 2005. An income tax recovery of $474,000 was recorded for the nine months ended September 30, 2005 as opposed to $1.7 million of expense in the 2004 comparative period, due mainly to the one-time recognition of benefits realized from re-filing our tax returns. 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 they become available. At September 30, 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 the first nine months of 2005 was $6.8 million compared to cash flow used in operating activities of $3.5 million during the comparable period in 2004.



---------------------------------------------------------------------
---------------------------------------------------------------------
($000s)
---------------------------------------------------------------------
Funds from operations 8,606
Net changes in accounts receivable and other (1,196)
Net changes in current liabilities 422
Net changes in current income taxes payable (1,016)
---------------------------------------------------------------------
Cash flow from operating activities 6,816
---------------------------------------------------------------------
---------------------------------------------------------------------


Our current cash flow from oil and gas operations is mainly derived from the Kotaneelee field. Net field level receipts from Kotaneelee represented approximately 69% of our total net field receipts for the nine months ended September 30, 2005, compared to 66% in the same period of 2004.

The continuing production declines experienced at the older two wells in Kotaneelee remain a significant concern to us. Notwithstanding that the recently drilled L-38 well has continued to produce with little water at a steady gross production rate of 17 mmcf/d during its first six months, the field continues to experience a decrease in reservoir pressure, which decreases the ability of the older wells to lift water, and results in a decrease in gas production.

In early October 2005, Kotaneelee I-48 was producing at a rate of approximately 10% of those rates averaged during the second quarter of 2005. It appears that both the I-48 and B-38 wells may be capable of continued production for a very limited period of time unless they can be successfully remediated. Although there are no current plans for remediation at B-38, we are in discussions with the operator to determine possible economic remediation alternatives for the I-48 well. There are no assurances that the operator will be able to remediate the decline in I-48 production. There is a possibility that our cash flow from Kotaneelee could be significantly reduced at any time in the future.

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 production.

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 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. We are currently in the process of surveying and permitting the revised pipeline right of ways to tie in these gas wells during the winter of 2005/2006. We expect these wells to come on production and add cash flow to the Company during the first quarter of 2006.

Late in the third quarter of 2005, we commenced drilling two wells in northeast British Columbia. We hope to drill up to three more locations this upcoming winter season, pending availability of equipment.

During the three and nine months ended September 30, 2005, we expended $5.8 million and $20.7 million respectively on capital additions, as summarized below:



---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
Capital Expenditures % %
($000s) 2005 2004 Change 2005 2004 Change
---------------------------------------------------------------------
Land and acquisitions 1,220 192 535 2,787 479 482
Geological and
geophysical 219 14 1466 922 912 1
Drilling and
completion 3,560 2,900 23 14,200 3,602 294
Facilities and
equipment 742 (71) - 2,755 83 3219
Other 32 3 962 49 17 186
---------------------------------------------------------------------
Total capital
expenditures 5,774 3,038 90 20,712 5,093 307
Dispositions - - - - - -
---------------------------------------------------------------------
Net capital
expenditures 5,774 3,038 90 20,712 5,093 307
---------------------------------------------------------------------
---------------------------------------------------------------------


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 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 $41 million ($12.6 million our share), all of which are reflected in the financial statements for the nine months ended September 30, 2005.

Our initial 2005 capital expenditure budget of $16.5 million was increased to $23 million in the third quarter of 2005 to evaluate certain additional opportunities. Capital expenditures incurred through September 30, 2005 were $20.7 million, leaving $2.3 million of the budget remaining. Additional expenditures expected to be incurred during the winter 2005/2006 season, are estimated to be between $2.5 million to $5.6 million. These expenditures will be considered by the Board of Directors on a case by case basis.

We expect to rely on internally generated cash flows and current cash on hand to fund the remainder of 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, particularly the recent decline of production at Kotaneelee I-48, and to a lesser degree B-38; 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)

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

Assets

Current assets
Cash and cash equivalents 2 $ 23,638,262 $ 39,353,717
Accounts receivable 3,055,557 2,495,678
Other assets 1,052,691 370,011
---------------------------------------------------------------------
27,746,510 42,219,406

Oil and gas properties
and equipment 3 33,629,049 17,570,085
---------------------------------------------------------------------
Total assets $ 61,375,559 $ 59,789,491
---------------------------------------------------------------------
---------------------------------------------------------------------

Liabilities and Shareholders' Equity

Current liabilities
Accounts payable $ 1,478,294 $ 3,627,644
Accrued liabilities 3,162,669 2,810,263
Accrued income taxes payable - 1,016,419
---------------------------------------------------------------------
4,640,963 7,454,326

Future income tax liability 3,174,864 2,569,864
Asset retirement obligations 4 3,356,083 2,675,743
---------------------------------------------------------------------
Total liabilities 11,171,910 12,699,933
---------------------------------------------------------------------

Shareholders' equity
Share capital 5 15,106,557 14,417,770
Contributed surplus 5 29,182,406 29,014,151
Retained earnings 5,914,686 3,657,637
---------------------------------------------------------------------
Total shareholders' equity 50,203,649 47,089,558
---------------------------------------------------------------------
Total liabilities and
shareholders' equity $ 61,375,559 $ 59,789,491
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes.


CANADA SOUTHERN PETROLEUM LTD.

CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
(in Canadian dollars)
(unaudited)
---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
Note 2005 2004 2005 2004
---------------------------------------------------------------------

Revenues
Petroleum and
natural gas
sales $6,646,509 $3,849,387 $14,034,477 $7,432,206
Royalties (743,096) (537,514) (1,796,251) (1,127,757)
Carried
interest 2,152 5,786 5,830 3,481,580
---------------------------------------------------------------------
5,905,565 3,317,659 12,244,056 9,786,029
Interest and
other income 162,680 203,729 593,266 986,644
---------------------------------------------------------------------
6,068,245 3,521,388 12,837,322 10,772,673
---------------------------------------------------------------------

Expenses
Lease operating
costs 507,817 383,297 1,520,350 1,044,718
Transportation 1 731,647 210,366 1,636,185 349,864
General and
administrative 684,332 788,846 2,093,323 2,438,495
Depletion and
depreciation 2,312,000 796,000 5,131,000 2,418,000
Asset retirement
obligations
accretion 71,800 60,000 205,100 180,000
Stock-based
compensation 187,200 229,500 410,250 496,600
Foreign exchange
losses 95,232 105,439 58,094 9,804
---------------------------------------------------------------------
4,590,028 2,573,448 11,054,302 6,937,481
---------------------------------------------------------------------
Income before
income taxes 1,478,217 947,940 1,783,020 3,835,192

Income tax
recovery
(expense) 6 (475,000) (503,000) 474,029 (1,664,000)
---------------------------------------------------------------------
Net income 1,003,217 444,940 2,257,049 2,171,192

Retained
earnings -
beginning of
period 4,911,469 2,104,623 3,657,637 378,371
---------------------------------------------------------------------

Retained
earnings - end
of period $5,914,686 $2,549,563 $5,914,686 $2,549,563
---------------------------------------------------------------------
---------------------------------------------------------------------

Net income per
share: 7
Basic $ 0.07 $ 0.03 $ 0.16 $ 0.15
Diluted $ 0.07 $ 0.03 $ 0.16 $ 0.15

Average number
of shares
outstanding:
Basic 14,475,188 14,417,770 14,439,710 14,417,770
Diluted 14,506,543 14,425,599 14,481,708 14,421,472

See accompanying notes.


CANADA SOUTHERN PETROLEUM LTD.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in Canadian dollars)
(unaudited)
---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
Note 2005 2004 2005 2004
---------------------------------------------------------------------

Cash flow
relating to
operating
activities:
Net income $ 1,003,217 $ 444,940 $ 2,257,049 $ 2,171,192
Adjustments to
reconcile net
income to
net cash
provided by
(used in)
operating
activities:
Depletion and
depreciation 2,312,000 796,000 5,131,000 2,418,000
Asset retirement
obligations
accretion 71,800 60,000 205,100 180,000
Asset retirement
expenditures (2,184) (339) (2,588) (1,218)
Stock-based
compensation 187,200 229,500 410,250 496,600
Future income
tax expense 475,000 39,000 605,000 404,000
---------------------------------------------------------------------
Funds from
operations 4,047,033 1,569,101 8,605,811 5,668,574

Change in
non-cash
working
capital 8 (1,592,257) 33,567 (1,789,395) (9,185,357)
---------------------------------------------------------------------
Cash flow from
(used in)
operating
activities 2,454,776 1,602,668 6,816,416 (3,516,783)
---------------------------------------------------------------------

Cash flow
relating to
investing
activities:
Additions to oil
and gas
properties
and equipment (5,773,579) (3,037,892) (20,712,135) (5,093,334)
Change in
non-cash
working
capital 8 (477,003) 1,973,507 (2,266,528) (50,188)
---------------------------------------------------------------------
Cash flow used
in investing
activities (6,250,582) (1,064,385) (22,978,663) (5,143,522)
---------------------------------------------------------------------

Cash flow
relating to
financing
activities:
Exercise of
stock options 5 174,000 - 446,792 -
---------------------------------------------------------------------
Cash flow from
financing
activities 174,000 - 446,792 -
---------------------------------------------------------------------

Increase
(decrease) in
cash and cash
equivalents (3,621,806) 538,283 (15,715,455) (8,660,305)

Cash and cash
equivalents at
the beginning
of period 27,260,068 39,883,798 39,353,717 49,082,386
---------------------------------------------------------------------
Cash and cash
equivalents at
the end of
period 2 $23,638,262 $40,422,081 $ 23,638,262 $40,422,081
---------------------------------------------------------------------
---------------------------------------------------------------------

See accompanying notes.


Notes to the Consolidated Financial Statements
Three and nine months ended September 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.

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.



---------------------------------------------------------------------
---------------------------------------------------------------------
September 30, December 31,
2005 2004
---------------------------------------------------------------------
Cash $ 722,235 $ 219,353
Canadian marketable securities
(yield: 2005 -2.8%; 2004 -2.5%) 21,055,774 38,173,069
U.S. marketable securities
(yield: 2005 - 3.8%; 2004 - 2.4%) 1,860,253 961,295
---------------------------------------------------------------------
Total $ 23,638,262 $ 39,353,717
---------------------------------------------------------------------
---------------------------------------------------------------------


3. Oil and gas properties and equipment

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



---------------------------------------------------------------------
---------------------------------------------------------------------
Depreciation, Net
Depletion and Book
Cost Write downs Value
---------------------------------------------------------------------

Balance, September 30, 2005
Oil and gas properties $ 58,022,437 $ 24,498,766 $ 33,523,671
Oil and gas properties
(U.S.) 1,319,218 1,319,218 -
---------------------------------------------------------------------
59,341,655 25,809,984 33,523,671
Office equipment 239,730 134,352 105,378
---------------------------------------------------------------------
$ 59,581,385 $ 25,944,336 $ 33,629,049
---------------------------------------------------------------------
---------------------------------------------------------------------

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 September 30, 2005, there were $2,908,201 (2004 - $635,667) of capital assets relating to unproved properties which have been excluded from the depletion calculation.

During the nine month periods ended September 30, 2005 and 2004, no indirect general and administrative expenses were capitalized.

4. Asset retirement obligations



September 30, December 31,
2005 2004
---------------------------------------------------------------------
Balance - beginning of period $ 2,675,743 $ 2,436,986
Liabilities incurred 477,828 -
Asset retirement obligations
accretion 205,100 240,000
Asset retirement expenditures (2,588) (1,243)
---------------------------------------------------------------------
Balance - end of period $ 3,356,083 $ 2,675,743
---------------------------------------------------------------------
---------------------------------------------------------------------


The total undiscounted amount of the cash flows required to settle the Company's asset retirement obligation is estimated to be $4,353,000. 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 2024.



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 - - 410,250 410,250
Exercise of stock
options 73,395 688,787 (241,995) 446,792
---------------------------------------------------------------------
Outstanding at
September 30,
2005 14,491,165 $15,106,557 $29,182,406 $44,288,963
---------------------------------------------------------------------
---------------------------------------------------------------------


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 nine months ended
September 30, 2005 is as follows:

---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted
Average
Exercise
Options Price
---------------------------------------------------------------------
Outstanding at beginning of period 550,000 $6.87
Granted 110,000 7.28
Expired (50,000) 7.53
Cancelled (25,000) 6.92
Exercised (73,395) 6.09
---------------------------------------------------------------------
Outstanding at September 30, 2005 511,605 $7.01
---------------------------------------------------------------------
---------------------------------------------------------------------
Exercisable at September 30, 2005 298,271 $6.89
---------------------------------------------------------------------
---------------------------------------------------------------------


Options granted during the nine months ended September 30, 2005, vest as follows: 16,667 immediately, 36,667 in 2006, 36,666 in 2007 and 20,000 options in 2008.

As at September 30, 2005, there were 312,834 common shares reserved for future issuance under the stock option plans.



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

---------------------------------------------------------------------
---------------------------------------------------------------------
Weighted
Average Weighted Weighted
Ranges of Remaining Average Average
Exercise Number Term Exercise Number Exercisable
Prices Outstanding (years) Price Exercisable Price
---------------------------------------------------------------------
$5.50
to 5.99 50,000 4.0 $5.94 50,000 $5.94
$6.00
to 6.49 100,000 3.5 6.21 50,000 6.21
$6.50
to 6.99 201,605 2.9 6.76 111,605 6.84
$7.53 50,000 1.3 7.53 50,000 7.53
$8.17 50,000 4.8 8.17 16,667 8.17
$8.64 60,000 4.2 8.64 19,999 8.64
---------------------------------------------------------------------
$5.50
to 8.64 511,605 3.3 $7.01 298,271 $6.89
---------------------------------------------------------------------
---------------------------------------------------------------------


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 nine months of 2005 is as follows:



Nine months ended September 30,
2005
---------------------------------------------------------------------
Assumptions:
Dividend yield 0%
Risk-free interest rate 3.37%
Expected life 5 years
Expected volatility 61.0%
---------------------------------------------------------------------
Results:
Weighted average fair value of options granted $ 3.95
---------------------------------------------------------------------
---------------------------------------------------------------------


As at November 7, 2005, there were 14,491,165 common shares and
511,605 stock options outstanding.

6. Income tax recovery (expense)

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Income tax
Current $ - $ (464,000) $ 1,079,029 $ (1,260,000)
Future (475,000) (39,000) (605,000) (404,000)
---------------------------------------------------------------------
$ (475,000) $ (503,000) $ 474,029 $ (1,664,000)
---------------------------------------------------------------------
---------------------------------------------------------------------


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 Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------

Net income $ 1,003,217 $ 444,940 $ 2,257,049 $ 2,171,192
---------------------------------------------------------------------
---------------------------------------------------------------------

Weighted average
common shares
outstanding 14,475,188 14,417,770 14,439,710 14,417,770
Effect of
dilutive
stock options 31,355 7,829 41,998 3,702
---------------------------------------------------------------------
14,506,543 14,425,599 14,481,708 14,421,472
---------------------------------------------------------------------
---------------------------------------------------------------------

Basic earnings
per share $ 0.07 $ 0.03 $ 0.16 $ 0.15
Diluted earnings
per share $ 0.07 $ 0.03 $ 0.16 $ 0.15
---------------------------------------------------------------------
---------------------------------------------------------------------


8. Supplemental disclosure of cash flow information

Changes in non-cash working capital were as follows:

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Decrease (increase) in non-cash working capital:
Accounts
receivable $(1,296,461) $ (929,146) $ (559,879) $ (22,724)
Other assets (257,108) (198,137) (682,681) (81,603)
Accounts payable (864,255) 96,608 (2,149,350) (1,971,730)
Accrued liabilities 348,564 2,148,333 352,406 1,098,396
Accrued income
taxes payable - 889,416 (1,016,419) (8,257,884)
---------------------------------------------------------------------
Net change in
non-cash working
capital $(2,069,260) $ 2,007,074 $(4,055,923) $(9,235,545)
---------------------------------------------------------------------
---------------------------------------------------------------------
Relating to:
Operating
activities $(1,592,257) $ 33,567 $(1,789,395) $(9,185,357)
Investing
activities (477,003) 1,973,507 (2,266,528) (50,188)
---------------------------------------------------------------------
$(2,069,260) $ 2,007,074 $(4,055,923) $(9,235,545)
---------------------------------------------------------------------
---------------------------------------------------------------------


Other cash flow information:

---------------------------------------------------------------------
---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------
Cash taxes paid $ - $ - $ 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 Nine months ended
September 30, September 30,
2005 2004 2005 2004
---------------------------------------------------------------------

Net income -
Canadian & U.S.
GAAP $ 1,003,217 $ 444,940 $ 2,257,049 $ 2,171,192
Change in value
of available for
sale securities
(b) 1,878 (18,209) (7,576) 25,865
---------------------------------------------------------------------
Other
comprehensive
income $ 1,005,095 $ 426,731 $ 2,249,473 $ 2,197,057
---------------------------------------------------------------------
---------------------------------------------------------------------
U.S. GAAP - net
income per share
Basic $ 0.07 $ 0.03 $ 0.16 $ 0.15
Diluted $ 0.07 $ 0.03 $ 0.16 $ 0.15
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Average number of
shares
outstanding:
Basic 14,475,188 14,417,770 14,439,710 14,417,770
Diluted 14,506,543 14,425,599 14,481,708 14,421,472
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The balance sheet information for the Canadian and U.S. GAAP
differences is summarized in the table below:

---------------------------------------------------------------------
---------------------------------------------------------------------
September 30, 2005 December 31, 2004
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Canadian U.S. Canadian U.S.
GAAP GAAP GAAP GAAP
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Current assets
(b) $27,746,510 $27,824,733 $42,219,406 $42,307,342
Oil and gas
properties and
equipment 33,629,049 33,629,049 17,570,085 17,570,085
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$61,375,559 $61,453,782 $59,789,491 $59,877,427
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Current
liabilities $ 4,640,963 $ 4,640,963 $ 7,454,326 $ 7,454,326
Future income tax
liability (b) 3,174,864 3,172,727 2,569,864 2,570,957
Asset retirement
obligations 3,356,083 3,356,083 2,675,743 2,675,743
Share capital and
contributed
surplus (a) 44,288,963 44,288,963 43,431,921 45,217,294
Retained earnings
(a) 5,914,686 5,914,686 3,657,637 1,872,264
Accumulated other
comprehensive
income (b) - 80,360 - 86,843
---------------------------------------------------------------------
$61,375,559 $61,453,782 $59,789,491 $59,877,427
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---------------------------------------------------------------------


(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 September 30, 2005, the Company owned approximately 0.6% (December 31, 2004 - 0.6%) of Sefton Resources, Inc. ("Sefton") with a fair market value of $78,223 (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 September 30, 2005. This would result in other comprehensive income for the three and nine month periods ended September 30, 2005 and 2004. In addition, the balance sheet would reflect Marketable Securities in the amount of $78,223 (December 31, 2004 -$87,936) with a corresponding credit of $80,360 (December 31, 2004 -$86,843) to Shareholders' Equity - Accumulated other comprehensive income. The difference is an adjustment to Future income tax liability of $2,137 (December 31, 2004 - ($1,093)).



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,
(2) Member of the Corporate Bankers 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