Prairie Schooner Petroleum Ltd.
TSX : PSL

Prairie Schooner Petroleum Ltd.

March 21, 2006 19:42 ET

Prairie Schooner Petroleum Ltd. Announces 2005 Results

CALGARY, ALBERTA--(CCNMatthews - March 21, 2006) - Prairie Schooner Petroleum Ltd. (TSX:PSL) is pleased to announce its operating and financial results for the fourth quarter and year ended December 31, 2005.

Prairie Schooner's first full year of operations demonstrated strong performance with growth per share in production, cash flow, reserves and net asset value. We have exceeded our internal expectations with the methodical execution of our business plan. Since our Initial Public Offering ("IPO") in March 2005, PSL has grown its production base from 2,050 boe/d (95% natural gas) to in excess of 7,200 boe/d (88% natural gas) at year end 2005, while transforming and expanding our asset base such that 60% of the Company's production will be located west of the fifth meridian by the end of March 2006.



Financial Highlights

Three months
ended Year ended
December 31, December 31,
-------------- Percent -------------- Percent
2005 2004 Change 2005 2004 Change
------ ------ ------- ------ ------ -------

Financial (thousands
of dollars except
share data)

Petroleum and natural
gas revenue 35,582 5,384 561 70,584 18,756 276
Cash flow from
operations 21,146 1,859 1,037 41,631 8,344 399
Per share - basic 1.33 0.15 787 2.95 1.10 168
- diluted 1.29 0.09 1,333 2.82 0.96 194
Net earnings (loss) 7,524 (57) n/a 13,513 2,684 403
Per share - basic 0.49 - n/a 0.96 0.35 174
- diluted 0.46 - n/a 0.91 0.31 194
Capital expenditures 21,860 3,413 540 45,463 10,723 324
Acquisitions, gross 108,405 - n/a 162,071 20,524 689
Debt, net 60,871 29,351 107
Weighted average
shares (thousands)
Basic 18,407 9,598 92 14,112 7,538 87
Diluted 19,566 10,717 83 14,780 8,657 71
Shares outstanding
(thousands)
Basic 20,053 10,412 93
Diluted 22,033 11,531 91

Operating (6:1 boe conversion)

Average daily production
Natural gas (mmcf/d) 31.2 8.0 290 19.2 7.2 167
Liquids (bbls/d) 639 86 643 276 88 214
Barrels of oil
equivalent (boe/d) 5,844 1,417 312 3,479 1,285 171

Average sales price
Natural gas ($/mcf) 11.17 6.84 63 9.23 6.54 41
Liquids ($/bbl) 59.27 53.29 11 57.76 48.66 19
Barrel of oil
equivalent ($/boe) 66.18 41.79 58 55.59 39.88 39


2005 Highlights

- Three significant property and corporate acquisitions for a total consideration of $162.1 million

- The Company drilled 100 gross (55.8 net) wells during 2005 with an 89 percent success rate

- Fourth quarter production averaged 5,844 boe/d, an increase of 76 percent over the third quarter of 2005 and a 312 percent increase over the comparable quarter of 2004

- Current production is approximately 7,400 boe/d with 400-600 boe/d of production awaiting tie-in

- Record cash flow in the fourth quarter of 2005 of $21.1 million or $1.33 per share, an increase of 125 percent or $11.7 million or $0.62 per share over the third quarter and an increase of 786 percent over 2004 on a per share basis

- Drilling for the three months ended December 31, 2005 resulted in 44 gross (21.3 net) wells drilled with a success rate of 93 percent

- Significant expansion to the Company's undeveloped land position to 273,115 net acres with an average working interest of 64 percent

Reserves

- Independent reserves evaluation by GLJ Petroleum Consultants Ltd. ("GLJ") as at December 31, 2005 in accordance with NI 51-101

- Total proven and proven plus probable reserves of 14.1 mmstb and 20.6 mmstb respectively

- Total proven and proven plus probable reserve growth per share of 149% and 165% respectively

- Production was replaced 7.5 times on a total proved basis and 11.1 times on a total proved plus probable basis

- Corporate proven plus probable reserves allocation of 88% natural gas, 7% natural gas liquids 3% light oil and 2 % heavy oil.

Capital Efficiency

- Total proven finding and development costs including changes to forward capital were $22.40 per boe ($21.85 excluding changes to forward capital).

- Total proven and probable finding and development costs including changes to forward capital were $15.91 per boe ($14.66 excluding changes to future development capital).

- Based on 2005 field netbacks a recycle ratio of 2.4 was achieved for 2005.

- Reserve life index based on the year end production rate is 7.9 years.

Net Asset Value

- Since January 1, 2005, the net asset value per fully diluted share has increased by 154% to $15.95 per share (10% before tax on GLJ January 1, 2006 Price Deck)

- Net asset value per fully diluted share of $19.22 based on GLJ's year end constant price deck and a 10% before tax discount rate.

Corporate

2005 was a year of transformation for Prairie Schooner. At year end 2004, we were a tightly held private company whose operations were primarily focused on long reserve life shallow gas, in south eastern Alberta. Our promise was to aggressively yet methodically, refocus the company through grassroots exploration combined with strategic acquisitions. The results achieved in 2005 have gone a long way to attaining those goals.

Through a combination of strategic acquisitions in addition to exploration and development drilling, we have increased our west central Alberta production to 60% of our total current production base. As well as growing our overall production base we have assembled an enviable inventory of undeveloped land and drillable prospects. At the current capital levels of $85 million per year we have assembled an inventory that provides in excess of 3 years of conventional and coal bed methane prospects.

This inventory has been developed at the same time as we have grown our reserves, cash flow, earnings and net asset value on a total and per share basis. Fundamentally our business plan to date has been successfully executed. The market has rewarded us for our accomplishments with Prairie Schooner shareholders seeing a 50% increase in share value since the initial public offering in March, 2005.

2005 proved to be a very opportunistic year for acquisitions. Through a combination of new equity issues and debt financing we spent $162 million acquiring two private companies and the majority of the Alberta assets of Purcell Energy. All three of these acquisitions occurred in areas where our team has historically been able to apply their skill sets to enhance the underlying value of the assets. As we continue to monetize these assets our inventory is anticipated to yield production addition costs of approximately $20,000 per boe/d and F&D of $12.40 per proven plus probable boe.

In April, we closed the $26.5 million purchase of Westrock Energy, a private company whose only asset was ownership and operatorship of a contiguous 73 section block of land at Ferrier. Although the lands are covered entirely by three dimensional seismic the lands had historically remained under exploited. Since April we have more than doubled production from the area through a highly successful exploration program targeting gas charged horizons from the belly river through to the Pekisko. Key wells in Q4, 2005 and Q1, 2006 have delineated and established a resource style tight gas play that covers at least ten sections of land. Expectations are that this play alone could add 800 boepd to the company and in excess of 25 bcf of reserves this year.

In September we closed the $27.2 million acquisition of a private company focused at Killian in East central Alberta. The strategic merits of this acquisition included a significant inventory of short lead time prospects that have drilling access throughout the year. Since closing, we have experienced 90 percent drilling success on our first 9 wells and added production in excess of 800 boe/d. This area will continue to receive an allocation of approximately 15% of the total corporate budget which will allow for the drilling of five to seven net wells per quarter.

By far our largest and most strategic acquisition was the $108.4 million transaction we closed in October. Key to the opportunity was that it significantly expanded our west central Alberta focus. Since closing this acquisition we have developed and extensive inventory over the asset base which includes everything from Edmonton development at Penhold through to CBM development at Corbett Creek. The key achievements to date on the asset base:

- 100% success on 3 wells at Pembina that should add in excess of 400 boepd by early April 2006.

- Successful conventional development and exploration program in the greater Corbett Creek and Doris areas which has seen net production grow from 400 boepd to 1,050 boepd.

- A successful two well horse-shoe Canyon CBM pilot at Penhold

- Additional undeveloped inventory for these assets of in excess of 40 net conventional wells and 500 CBM locations.

In conjunction with the aforementioned acquisitions we had a very busy year exploring and developing assets. Throughout 2005 100 gross, (55.8 net) wells were drilled at an 89 percent success rate. Total capital expenditures on E&P activities were $45.5 million. The results achieved with those expenditures were impressive with total production addition costs of $18,800 per boepd and drill bit F&D costs of $8.42 per boe. Long term value creation will ultimately continue to come with the drill bit. During 2006, we will drill 135 net wells to start to define the upside on our 273,000 net undeveloped acres of land. With a conventional inventory of over 250 net wells and in excess of 500 CBM wells planned for the next few years our drilling program will remain the key to fully extracting value from our acquired lands and assets.

Outlook

Natural gas assets have been and will remain the driver of our business plan. In our 2004 annual report we indicated our business plan and investment criteria were fundamentally sound at long term commodity prices of $6.00/mcf and WTI $40/bbl. This statement remains true today. With our capital efficiency forecast to be at $20,000 per boe/d and finding and development forecast cost of $12.40 per boe it is apparent that we are poised to achieve a recycle ratio in excess of 2 for the foreseeable future.

Over the near term we anticipate that natural gas prices will remain relatively flat at approximately $7 per mcf with strengthening to $8-9 per mcf in the fourth quarter of 2006. Utilizing this forecast, we anticipate that our planned capital budget of $85 million will be approximately equal to our cash flow. As with 2005 this allows us to continually maintain a strong balance sheet with an anticipated debt to cash flow ratio of 0.7. This prudent balance sheet management gives us the ability to step up should additional strategic acquisitions become available.

Our initial focus in 2006 has been the monetization of the extensive inventory that has been developed. To date in the first quarter of 2006, we have drilled 22 gross (12.6 net) wells with a 90% success rate. We continue to be actively drilling with 5 drilling rigs currently active in the company. On going tie-in operations should see Prairie Schooner achieve 7,700-8,000 boe/d by mid April.

We continue to have the financial resources, undeveloped land, opportunity inventory and skilled and motivated staff to continue the relentless pursuit of our business plan.



On behalf of the Board of Directors and the team at Prairie Schooner;


Jim Saunders Neil Roszell, P. Eng
Chairman and President and
Chief Executive Officer Chief Operating Officer
March 21, 2006 March 21, 2006


ANNUAL MEETING

The Annual and Special Meeting of Shareholders will be held on May 11, 2006, at 10:00 am in the Strand / Tivoli Room at the Metropolitan Conference Centre located at 333 - 4th Avenue S.W., Calgary, AB. All shareholders and invited guests are encouraged to attend.

ANNUAL REPORT

The Company does not intend on preparing a 2005 annual report. This press release in conjunction with the related MD&A and the audited financial statements will be located at www.sedar.com and www.psei.ca. We also encourage investors to review our updated corporate presentation located at www.psei.ca.

To the extent investors do not have access to the internet, copies of the audited financial statements and related MD&A can be obtained on request without charge by contacting Prairie Schooner Petroleum Ltd. at (403) 266-6400 or at Suite 1000, 520 - 5th Avenue S.W., Calgary, AB T2P 3R7.

MANAGEMENT'S DISCUSSION AND ANALYSIS

The following discussion and analysis as provided by the management of Prairie Schooner Petroleum Ltd. ("Prairie Schooner" or the "Company") should be read in conjunction with the audited consolidated financial statements for the year ended December 31, 2005 and 2004 and the unaudited consolidated interim financial statements for the three months ended December 31, 2005 and 2004. This discussion is based on information available to and is dated, March 21, 2006. The financial data presented is in accordance with Canadian generally accepted accounting principles in Canadian dollars, except where indicated otherwise.

Forward Looking Statements

Statements in this document, including the MD&A, may contain forward-looking information including expectations of future production, components of cash flow and earnings, expected future events and/or financial results that are forward-looking in nature and subject to substantial risks and uncertainties. The reader is cautioned that assumptions used in the preparation of such information may prove to be incorrect. The Company cautions the readers that actual performance will be affected by a number of factors, as many may respond to changes in the economic and political circumstances throughout the world. Events or circumstances may cause actual results to differ materially from those predicted, as a result of numerous known and unknown risks, uncertainties and other factors, many of which are beyond the control of the Company. These risks include, but are not limited to; operational risks in exploration, development and production, delays or changes in plans, risks associated with the uncertainty of reserve estimates, health and safety risks and the uncertainty of estimates and projections of production costs and expenses. These external factors are beyond the Company's control and may affect the marketability of oil and natural gas produced, industry conditions including changes in laws and regulations, changes in income tax regulations, increased competition, fluctuations in commodity prices, interest rates, and variations in the Canadian/United States dollar exchange rate. The reader is cautioned not to place undue reliance on the forward-looking information.

The Company's disclosure controls and procedures as defined in Multilateral Instrument 52-109 were reviewed by management, including the Chief Executive Officer (CEO) and the Chief Financial Officer (CFO). Based on this review, the Company's management, including the CEO and CFO, concluded that the Company's disclosure controls and procedures are effective as of December 31, 2005.

The Management's Discussion and Analysis ("MD&A") contains the term cash flow from operations which should not be considered an alternative to, or more meaningful than, cash flow from operating activities as determined in accordance with Canadian generally accepted accounting principles ("GAAP") as an indicator of the Company's performance. The reconciliation between net earnings and cash flow from operations can be found in the consolidated statement of cash flow in the audited consolidated financial statements and the unaudited interim consolidated financial statements. The Company presents cash flow from operations per share whereby per share amounts are calculated consistent with the calculation of earnings per share.

The MD&A also contains other terms such as net debt and operating netbacks, which are not recognized measures under GAAP. Management believes these measures are useful supplemental measures of firstly, the total amount of current and long-term debt the Company has, and secondly, the amount of revenues received after the royalties and operating costs. Readers are cautioned however, that these measures should not be construed as an alternative to other terms such as current and long-term debt or net earnings in accordance with GAAP as measures of performance. The Company's method of calculating these measures may differ from other companies, and accordingly, may not be comparable to measures used by other companies.

The term barrels of oil equivalent ("boe") may be misleading, particularly if used in isolation. Per boe amounts have been calculated using a conversion rate of six thousand cubic feet of natural gas to one barrel of oil. This equivalence is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.



Petroleum and Natural Gas Revenue

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
(thousands of dollars)

Natural gas revenue 32,561 4,655 65,386 16,477 297
Liquids revenue 3,459 387 5,712 1,455 293
Hedging gains (loss) (677) 231 (1,051) 392 268
Royalty and other 239 111 537 432 24
----------- ------- -------- -------
35,582 5,384 70,584 18,756 276
----------- ------- -------- -------
----------- ------- -------- -------


The Company's production for the fourth quarter averaged 5,844 boe/d, an increase of 76 percent from the 3,314 boe/d in the third quarter of 2005, and an increase of 312 percent compared to the fourth quarter of 2004. Natural gas production increased to 31.2 mmcf/d in the fourth quarter from 18.9 mmcf/d in the third quarter. Liquids production increased to 638 bbls/d from 171 bbls/d in the third quarter. This increase was primarily attributable to a combination of the closing of a $108 million property acquisition in October and a successful drilling program that resulted in 44 gross (21.3 net) wells drilled in the quarter. Production for the twelve months ended December 31, 2005 was 3,479 boe/d comprised of 19.2 mmcf/d of natural gas and 276 bbls/d of liquids. Average production volumes on a year-over-year basis in 2005 have increased by 171 percent when compared to 2004.

Petroleum and natural gas revenue for the fourth quarter increased by 120 percent to $35.6 million from the $16.2 million recorded in the third quarter of 2005. Strong natural gas prices, combined with increased production, resulted in the increase for the quarter. Year-over-year, revenue increased by 276 percent as a result of a 39 percent increase in commodity prices and a 171 percent increase in production volumes.

During 2005, Prairie Schooner closed three property and corporate acquisitions for a total of $162.1 million. Additionally, a total of 100 gross (55.8 net) wells were drilled with a success rate of 89 percent. Both of these factors contributed to the substantial production increase of 171 percent on a year over year basis

Producing Areas:

The following table summarizes the Company's average production in its core areas for the three months ended and year ended December 2005 and the year ended December 31, 2004.



Three months ended Year ended
December 31, December 31,
2005 2005 2004
------------------- ------- ------
Areas (boe/d)
Ferrier / Pembina 1,114 544 -
Sylvan Lake 278 70 -
Two Hills 1,055 665 187
Killam 651 176 -
Doris 397 100 -
Southern Alberta 1,497 1,575 904
Minors 852 349 194
------------------- ------- ------
5,844 3,479 1,285
------------------- ------- ------
------------------- ------- ------


Financial instruments are entered into by the Company to protect the downside prices received on the sale of a portion of its crude oil and natural gas production.

The following contracts were outstanding as at December 31, 2005:





Commodity Type Term Volume Price Index
----------- ----- -------------- ------------- -------- ------
Natural gas Fixed January 2006
- March 2006 8,000 GJ's/d $9.87/GJ AECO

Natural gas Collar January 2006 $12.00 -
- March 2006 2,000 GJ's/d $14.70/GJ AECO

Natural gas Fixed April 2006
- October 2006 7,000 GJ's/d $8.36/GJ AECO

Natural gas Collar April 2006 $9.50 -
- October 2006 2,000 GJ's/d $10.86/GJ AECO



Royalties
Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
(thousands of dollars)

Crown 3,976 496 7,422 1,464 407
Freehold and GORR 4,694 568 9,539 2,035 369
Alberta Royalty Tax Credit (164) (72) (389) (273) 42
----------- ------- -------- -------
8,506 992 16,572 3,226 414
----------- ------- -------- -------
----------- ------- -------- -------

Percent of total revenue 23.9% 18.4% 23.5% 17.2% 37
Per boe ($) 15.82 7.61 13.05 6.86 90


For the three months ended December 31, 2005, royalty expense net of ARTC, and royalty rates increased compared to the third quarter of 2005 as a result of increased production and higher commodity prices. On a per unit basis, royalties have increased reflecting the impact of higher commodity prices.

For 2005, crown royalty rates increased due to a higher number of wells drilled on crown land when compared to 2004.



Operating Expenses
Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
Total operating
costs ($000's) 3,840 865 7,855 3,124 151
Percent of total revenue 10.8% 16.1% 11.1% 16.7% (34)
Per boe ($) 7.15 6.64 6.18 6.64 (7)


Operating costs for the fourth quarter of 2005 increased substantially to $3.8 million from the $1.7 million incurred in the third quarter of 2005 primarily as a result of the 176 percent increase in production volumes. Unit operating expenses are up from the third quarter of 2005 by 28 percent. The rise in overall operating expenses is due to the two acquisitions completed in the fourth quarter. Both of which came with a more expensive barrel from an operating cost perspective. Ultimately we expect operating costs to be somewhat higher in the first quarter of 2006 at approximately $8.00 per boe prior to seeing the benefits from our operating costs reduction initiatives which should ultimately result in the operating costs being reduced to a range of approximately $7 - 7.50/boe level.

On a per unit basis, operating expenses were 7 percent lower at $6.18 per boe for 2005 compared to $6.64 per boe during 2004. This decrease reflects the efficiencies initiated by Prairie Schooner in field operations as well as the economics of scale from higher production volumes. This decrease is indicative of the longer term benefits seen from operating cost reduction initiatives and as stated above the combined asset base will benefit from this over the course of 2006.



Transportation Expenses

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
Total transportation
costs ($000's) 649 170 1,362 785 74
Percent of total revenue 1.8% 3.2% 1.9% 4.2% (55)
Per boe ($) 1.21 1.31 1.07 1.67 (36)



General and Administrative Expenses

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
(thousands of dollars)

General and administrative 1,027 396 2,776 1,586 75
Overhead recoveries (258) (50) (680) (198) 243
Capitalized G & A (183) (38) (582) (38) 1,432
----------- ------- -------- -------
Net 586 308 1,514 1,350 12
----------- ------- -------- -------
----------- ------- -------- -------

Percent of total revenue 1.6% 5.7% 2.1% 7.2% (71)
Per boe ($) 1.09 2.36 1.19 2.88 (59)


General and administrative expenses for the fourth quarter were $586 thousand after recoveries and capitalized costs, an increase from $341 thousand in the third quarter of 2005.

In the fourth quarter, costs have increased reflecting the additional personnel required to administer the substantial increase in the production base while continuing to generate exploration and exploitation opportunities. During the quarter the technical, operational, land and financial personnel of the Company was expanded with the addition of eight employees. Additionally, office rent, computer services and general office costs have also increased proportionately with the increase in personnel.

On a per unit basis, in the fourth quarter, general and administrative expenses have been reduced on both a gross and net basis due to the 76 percent increase in production volumes.

Overhead recoveries were higher in the fourth quarter due to increased capital and operating activities when compared to the third quarter of 2005.



Stock-Based Compensation

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
(thousands of dollars)

Stock-based compensation 331 115 1,115 145 669
Percent total of revenue 0.9% 2.1% 1.6% 0.8% 100
Per boe ($) 0.62 0.88 0.88 0.31 184


The Company applies the fair value method for valuing stock option expenses. For the year ended December 31, 2005, Prairie Schooner recorded a stock-based compensation charge of $1.1 million in connection with the issuance of stock options. This charge is related to options granted in 2004 as well as the options granted in 2005. As Prairie Schooner was a private company in 2004, there was nominal stock-based compensation expense in 2004.



Financial Charges

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
Total financial
charges ($000's) 490 113 1,139 765 49
Percent of total revenue 1.4% 2.1% 1.6% 4.1% (61)
Per boe ($) 0.91 0.87 0.90 1.63 (45)


Compared to the third quarter of 2005, interest expense increased by $269 thousand. Debt levels increased as a result of the previously mentioned $108 million property acquisition on October 27, which was financed by a combination of bank debt and share equity.



Depletion, Depreciation and Accretion

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
(thousands of dollars) 2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
Depletion and depreciation 9,110 1,650 19,035 4,200 353
Accretion 198 99 451 223 102
----------- ------- -------- -------
9,308 1,749 19,486 4,423 341
----------- ------- -------- -------
----------- ------- -------- -------

Percent of total revenue 26.2% 32.5% 27.6% 23.6% 17
Per boe ($) 17.31 13.42 15.35 9.40 63


Depletion and depreciation expense for the fourth quarter was $9.1 million, substantially higher than the $4.4 million recorded in the third quarter. This increase in depletion expense was attributable to a combination of a 76 percent increase in production in the quarter and a 18 percent increase in the per unit depletion factor. On a unit of production basis, the provision was $15.35 per boe for 2005, an increase of 63 percent when compared to 2004.

Accretion increased to $450 thousand, a 102 percent increase over the year 2004. This increase was attributable to the increase in the Company's property and equipment base to $255 million as at December 31, 2005 as compared to $69 million at December 31, 2004. Accretion represents the time value of the asset retirement obligation and is calculated at the Company's credit adjusted risk-free rate of 8 percent. It will continue to increase with the passage of time and the increases in asset retirement obligations.

Income and Capital Taxes

For the year ended 2005, capital taxes were $390 thousand which is comprised of the Federal Large Corporations Tax (LCT), The LCT increased in the quarter corresponding with the increase in the Company's taxable capital base.

Future income tax expense for the year ended December 31, 2005 was $7.6 million and reflects an effective tax rate of 35.5 percent. The total liability for future income tax was $30.1 million as at December 31, 2005.

Summary of Tax Pools



($ thousands) Estimated balance at
January 1, 2006
------------------------------------------------------------------------
Canadian oil and gas property expense 77,389
Canadian development expense 33,039
Canadian exploration expense 16,801
Undepreciated capital cost 45,234
Non-capital losses 15,150
Share issue costs 3,993
------------------------------------------------------------------------
Total 191,606
------------------------------------------------------------------------
------------------------------------------------------------------------


Cash Flow from Operations and Net Income

Cash flow from operations for the three months ended December 31, 2005 was $21.1 million ($1.33 per share) compared to $9.4 million ($0.71 per share) in the third quarter. In the fourth quarter the Company had net earnings of $8.1 million ($0.53 per share) compared to net earnings of $2.8 million ($0.21 per share) in the third quarter of 2005.

For the year ended December 31, 2005, cash flow from operations was $41.6 million or $2.95 per share as compared to $8.3 million and $1.10 per share in 2004.



Capital Investment

Three months ended Year ended
December 31, December 31,
------------------- ---------------- Percent
2005 2004 2005 2004 Change
----------- ------- -------- ------- ---------
(thousands of dollars)

Land 309 76 1,611 694 132
Geological and geophysical 916 300 1,428 395 262
Drilling and completions 16,295 1,695 28,524 5,411 427
Production facilities 4,254 1,281 13,764 4,076 238
Other 86 61 136 147 (7)
----------- ------- -------- -------
Property and equipment
additions 21,860 3,413 45,463 10,723 324
----------- ------- -------- -------

Property acquisitions(1) 108,435 20,524 108,435 20,524 428
Corporate acquisitions(1) - - 53,636 - 100
----------- ------- -------- -------
Total acquisitions 108,435 20,524 162,071 20,524 679
----------- ------- -------- -------

Total capital investment 130,295 23,937 207,534 31,247 557
----------- ------- -------- -------
----------- ------- -------- -------

(1)acquisition costs include both cash and share equity issued and
net debt assumed


Of the total capital spent in 2005, $28.5 million was incurred on the Company's drilling program. The Company drilled 100 gross (55.8 net) wells during 2005 with an 89 percent success rate. During the third and fourth quarters of 2005, Prairie Schooner participated with an industry major in the commercial development program for CBM in the Huxley area with a total of 33 wells drilled with a success rate of 100 percent. Drilling for the three months ended December 31, 2005 resulted in 44 gross (21.3 net) wells drilled with a success rate of 93 percent. The fourth quarter drilling program was concentrated at Huxley where the Company drilled 18 gross (2.5 net) wells, at Ferrier with 5 gross (3.8 net) wells, at Killam with 4 gross (3.83 net) and at Pembina with 3 gross (1.5 net) wells drilled. This program resulted in 41 natural gas wells and 3 abandoned wells.

During 2005, the Company increased its undeveloped land base by incurring $1.6 million of crown and freehold land acquisitions. Facility and infrastructure expenditures were incurred in the Company's core areas of Ferrier, Two Hills, Killam and Irvine, primarily for compressor facilities and pipelines to tie-in and bring production on-stream.

During 2005, Prairie Schooner closed three significant acquisitions for a total consideration of $162.1 million. These acquisitions contributed approximately 8.8 mmboe of proven plus probable reserves with initial production of 3,650 boe/d and undeveloped land of approximately 133,000 net acres. All three acquisitions were characterized by high working interests, significant undeveloped land and operated facilities and infrastructure. These acquisitions enhanced and expanded the Company's west central Alberta core areas.

Land Holdings

We have evaluated our undeveloped land holdings internally. This internal evaluation estimated the fair market value of our undeveloped land holdings, being 273,115 net acres, as at December 31, 2005, at $32.0 million. For purposes of the internal evaluation "fair market value" is defined as the price which we feel could be expected to be received for the undeveloped lands in an arm's length transaction. In order to determine fair market value, we considered a number of factors including a) the acquisition costs, the surrounding properties and general oil and gas climate since the acquisition, b) current prices being paid for crown lands in the same area c) terms and conditions, expressed in monetary terms of recent farm-in and/or work commitments and the degree of exploration activity in each area, and d) recent industry sales of similar properties in the same general area. In areas where current prices or other pertinent information were not available, we used our best judgment.

We expect that rights to explore, develop and exploit approximately 35,000 net acres of our undeveloped land holdings will expire by December 31, 2006.

The following table summarizes our developed and undeveloped land holdings (in acres) as at December 31, 2005.



Undeveloped Developed Total
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
--------------------------------------------------------
Alberta 411,340 261,144 252,510 158,001 663,850 419,145
Saskatchewan 10,914 10,914 13,152 13,152 24,066 24,066
British Columbia 7,334 1,057 5,390 832 12,724 1,889
-----------------------------------------------------------------------
Total 429,588 273,115 271,052 171,985 700,640 445,100
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1)"Gross" means the total number of acres in which we hold an
interest.
(2)"Net" means the aggregate of the percentage working interests of
Prairie Schooner in the gross acres


The following table summarizes our developed and undeveloped land holdings (in acres) as at December 31, 2004.



Undeveloped Developed Total
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
--------------------------------------------------------
Alberta 172,814 147,885 139,680 94,407 312,494 242,292
Saskatchewan 5,120 5,120 17,280 17,280 22,400 22,400
-----------------------------------------------------------------------
Total 177,934 153,005 156,960 111,687 334,894 264,692
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1)"Gross" means the total number of acres in which we hold an
interest.
(2)"Net" means the aggregate of the percentage working interests of
Prairie Schooner in the gross acres


Drilling Activity

The following table summarizes our drilling results for the years indicated.



2005 2004

Gross(1) Net(2) Gross(1) Net(2)
-------------------------------------
Natural gas 88 47.1 33 29.6
Crude oil 1 0.6 - -
Dry and abandoned 11 8.1 1 1.0
-----------------------------------------------------------------------
Total 100 55.8 34 30.6
-----------------------------------------------------------------------
Success 89% 85% 97% 97%
-----------------------------------------------------------------------
-----------------------------------------------------------------------
(1)"Gross" wells, refers to all wells in which we have either a
working interest or a royalty interest.
(2)"Net" wells refers to the aggregate of the percentage our working
interests in the gross wells


Liquidity and Capital Resources

At December 31, 2005, total net debt (including the working capital deficit) was $60.9 million compared to net debt of $29.4 million at December 31, 2004. For the year ended December 31, 2005, cash flow of $41.6 million, common share equity issuance proceeds of $131.9 million and an increase in net debt of $31.5 million, were utilized to fund $205 million of gross capital expenditures.

During 2005 the Company issued common shares as follows:

- 1,924,000 common shares issued on the Company's Initial Public Offering for net proceeds of $23.1 million

- 2,740,000 common shares issued on a private placements for gross proceeds of $41.6 million

- 70,000 common share options exercised for gross proceeds of $352 thousand

- 1,181,089 common shares issued as part consideration in the private company acquisition in April 2005

- 700,000 common shares issued as part consideration in the private company acquisition in September 2005

- 2,800,340 common shares issued as part consideration in the acquisition of properties in October 2005

On March 16, 2005, the Company completed a public offering by way of a long form prospectus for the issuance of 1,924,000 common shares for gross proceeds of $25 million. Common shares of Prairie Schooner commenced trading on March 16, 2005 on the Toronto Stock Exchange under the symbol "PSL".

On September 15, 2005, the Company increased its credit facility to $53 million. On October 28, 2005 the credit facility was increased to $80 million, concurrent with the closing of the $108 million property acquisition

At December 31, 2005, the Company had a $80 million demand revolving credit facility with its lender.

As at March 21, 2006, the Company had the following changes to its share capital from that disclosed in notes 7 and 8 to the audited consolidated financial statements for the year ended December 31, 2005:

- 79,167 common share options granted

- 43,333 common share options exercised

- 135,000 common share options cancelled

Contractual Obligations

Prairie Schooner has assumed various contractual obligations and commitments in the normal course of operations and financing activities. We consider these obligations when assessing cash requirements in the discussion of future liquidity that follows:



Contractual Obligations

Payments due by Period Less than 1 to 3 4 to 5 After 5
($ thousands) 1 Year Years Years Years Total
------------------------------------------------------------------------
Long term debt(1) 53,158 - - - 53,158
Operating lease
obligations(2) 376 157 - - 533
Firm transportation
commitments 951 778 - - 1,729
Asset retirement
obligations 268 1,437 1,038 18,906 21,649
------------------------------------------------------------------------
Total contractual
obligations 54,753 2,372 1,038 18,906 77,069
------------------------------------------------------------------------
------------------------------------------------------------------------
(1)Revolving credit facility with a major Canadian chartered bank. The
credit facility bears interest at the bank's prime rate. See note 6
to the audited consolidated financial statements for the year ended
December 31, 2005.
(2)Operating lease obligations consist of the office lease.


Contractual obligations include both financial and non-financial obligations. Financial obligations represent known future cash payments that Prairie Schooner is required to make under existing contractual arrangements, such as debt and lease arrangements. Non-financial obligations represent contractual obligations to perform specified activities such as work commitments.

Firm transportation commitments relate to agreements that Prairie Schooner has with pipeline companies to send a certain volume of our product through their pipelines.

At December 31, 2005, total future asset retirement obligation costs to be accrued over the life of the remaining proved reserves were estimated at $21.6 million. This estimate is subject to change based on amendments to environmental laws and as new information concerning operations becomes available. The timing of any payments is difficult to determine with certainty and the table has been prepared using best estimates.

Off-Balance Sheet Arrangements

There are currently no off-balance sheet arrangements.



Summary of Quarterly Results 2005

($ thousands except
where noted) Q1 Q2 Q3 Q4 2005
------------------------------ ------- ------- ------- ------- -------
Production
Liquids (bbls/d) 92 197 171 639 276
Natural gas (mcf/d) 11,762 14,804 18,859 31,231 19,217
Barrels of oil
equivalent (boe/d) 2,052 2,664 3,314 5,844 3,479
Average sales price
Liquids ($/bbl) 55.15 54.06 57.70 59.27 57.76
Natural gas ($/mcf) 7.22 7.24 8.80 11.17 9.23
Barrel of oil
equivalent ($/boe) 43.87 44.25 53.03 66.18 55.59
Revenues 8,103 10,727 16,172 35,582 70,584
Cash flow from operations 4,906 6,176 9,403 21,146 41,631
Per share - basic 0.45 0.46 0.71 1.33 2.95
Per share - diluted 0.43 0.43 0.67 1.29 2.82
Net earnings 1,576 1,601 2,812 8,062 14,051
Per share - basic 0.15 0.11 0.21 0.53 1.00
Per share - diluted 0.14 0.11 0.20 0.50 0.95
Capital expenditures 6,592 11,475 5,536 21,860 45,463
------------------------------ ------- ------- ------- ------- -------
------------------------------ ------- ------- ------- ------- -------


2004

($ thousands except
where noted) Q1 Q2 Q3 Q4 2004
------------------------------ ------- ------- ------- ------- -------
Production
Liquids (bbls/d) 113 90 62 86 88
Natural gas (mcf/d) 6,729 7,018 6,997 7,985 7,184
Barrels of oil
equivalent ($/boe) 1,234 1,260 1,228 1,417 1,285
Average sales price
Liquids ($/bbl) 40.64 44.76 62.23 53.29 48.66
Natural gas ($/mcf) 6.54 6.60 6.14 6.84 6.54
Barrel of oil
equivalent ($/boe) 39.39 39.95 38.11 41.79 39.88
Revenues 4,486 4,579 4,307 5,384 18,756
Cash flow from operations 2,168 2,350 1,967 1,859 8,344
Per share - basic 0.32 0.34 0.29 0.15 1.10
Per share - diluted 0.30 0.31 0.26 0.09 0.96
Net earnings (loss) 935 972 834 (57) 2,684
Per share - basic 0.09 0.14 0.12 - 0.35
Per share - diluted 0.07 0.13 0.11 - 0.31
Capital expenditures 1,734 1,237 4,339 3,413 10,723
------------------------------ ------- ------- ------- ------- -------
------------------------------ ------- ------- ------- ------- -------


Factors that have caused variations over the quarters:

- During 2005, Prairie Schooner made three substantial property and corporate acquisitions for a total of $162.1 million

- During 2005, the Company participated in drilling 100 gross (55.8 net) wells with a success rate of 89 percent

- Production growth is the result of the Company's successful development and exploitation activities combined with an aggressive acquisition program

- Revenue, cash flow and net earnings growth is primarily the result of production growth and commodity price increases. Other factors include depletion and depreciation rates and income tax rates which are influenced by both internal and external elements

Critical Accounting Estimates

The significant accounting policies used by Prairie Schooner are disclosed in note 2 to the Company's audited financial statements. Certain accounting policies require that management make appropriate decisions with respect to the formulation of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses. The following discusses such accounting policies and is included in Management's Discussion and Analysis to aid the reader in assessing the critical accounting policies and practices of the Company, and the likelihood of materially different results being reported. Prairie Schooner's Management reviews its estimates regularly. The emergence of new information and changed circumstances may result in actual results or changes to estimated amounts that differ materially from current estimates.

The following assessment of significant accounting policies is not meant to be exhaustive. The Company might realize different results from the application of new accounting standards promulgated, from time to time, by various rule-making bodies.

Proven Oil and Gas Reserves

The independent petroleum engineering firm of GLJ Petroleum Consultants Ltd. ("GLJ") evaluated 98.7% of and reported on 100% of Prairie Schooner's oil and natural gas reserves. The remaining 1.3% of reserves were evaluated by the independent petroleum engineering firm of Sproule Associates Limited. This 1.3% of the total represents the Huxley CBM portion of the report. GLJ took the numbers as presented to them by Sproule and incorporated into the corporate total report.

The estimation of reserves is a subjective process. Forecasts are based on engineering data, projected future rates of production and the timing of future expenditures, all of which are subject to numerous uncertainties and various interpretations. The Company expects that its estimates of reserves will change with updated information from the results of future drilling, testing or production levels. Such revisions could be upward or downward. Reserve estimates have a material impact on depletion and depreciation, asset retirement expenses and impairment costs which could possibly have a material impact on consolidated net earnings.

Depletion Expense

The Company uses the full cost method of accounting for exploration and development activities. In accordance with this method of accounting, all costs associated with exploration and development, are capitalized whether or not the activities funded were successful. The aggregate of net capitalized costs and estimated future development costs, less estimated salvage values, is amortized using the unit-of-production method based on estimated proven oil and gas reserves.

An increase in estimated proven oil and gas reserves would result in a corresponding reduction in depletion expense. A decrease in estimated future development costs would result in a corresponding reduction in depletion expense.

Impairment of Property & Equipment

The Company is required to review the carrying value of all property and equipment, including the carrying value of oil and gas assets, for potential impairment. Impairment is indicated if the carrying value of the long-lived asset or oil and gas asset is not recoverable by the future undiscounted cash flows. If impairment is indicated, the amount by which the carrying value exceeds the estimated fair value of the property and equipment is charged to earnings.

Asset Retirement Obligation

The asset retirement obligation is estimated based on existing laws, contracts or other policies. The fair value of the asset retirement requires an estimate of the future costs to abandon and reclaim wells, pipelines and facilities discounted to its present value using the Company's credit adjusted risk-free interest rate. The liability is adjusted each reporting period to reflect the passage of time, with the accretion charged to earnings. Revisions to the estimated timing of cash flows or to the original undiscounted cost could also result in an increase or decrease to the obligation. By their nature, these estimates are subject to measurement uncertainty and the impact on the financial statements could be material.

Income Tax Accounting

The determination of the Company's income and other tax liabilities requires interpretation of complex laws and regulations often involving multiple jurisdictions. All tax filings are subject to audit and potential reassessment after the lapse of considerable time. Accordingly, the actual income tax liability may differ significantly from that estimated and recorded by management.

Risk Management

The Company is involved in the exploration, development and production of petroleum and natural gas in the western Canadian Sedimentary Basin. These activities involve a number of risks and uncertainties inherent in the industry. Prairie Schooner's external business risks arise from the uncertainty of petroleum and natural gas pricing, the uncertainty of interest and exchange rates, environmental, safety and regulatory issues.

Inherent in exploration and development are the risks of drilling dry holes, encountering drilling or production difficulties or experiencing high decline rates in producing wells. These risks are mitigated in a number of ways. The Company employs a team of highly qualified and experienced professionals to pursue exploration and development activities. Geological, geophysical, engineering, environmental and economic analyses are performed on prospects to ensure acceptable rates of return and risk for the Company. In addition, the Company uses prudent safety programs.

Being a commodity-based industry, the Company's financial results can be significantly affected by the prices received for petroleum and natural gas as these commodity prices fluctuate in response to external market conditions. The Company maintains a risk management program that fixes the prices of petroleum and natural gas on a percentage of the total expected production volume. This program is under the direction of the Company's Board of Directors. Prairie Schooner is exposed to changes in interest rates as the Company's banking facilities are based on the banker's prime lending rate and short-term banker's acceptance rates.

The Company takes a proactive approach with all provincial and federal environmental and safety regulations as well as carrying appropriate insurance to cover the risks associated with its operations in the field. Changes in regulatory standards can add to the cost of doing business.

2006 Outlook

Prairie Schooner is a Calgary, Alberta based oil and natural gas exploration and production company currently producing approximately 7,400 boe/d, of which approximately 88% is weighted towards natural gas. Our focus is to increase our underlying value through a combination of grassroots exploration, strategic acquisitions and subsequent exploitation. Over the next few years it is our intent to establish a portfolio of assets of varying maturity in order to increase the overall predictability of our cash flow stream. Our current area of exploration focus is west central Alberta where our team has considerable experience.

Our exploration strategy is to generate and drill low risk shallow to medium depth prospects. We prefer to operate in areas with year round access thereby minimizing time delays between prospect generation and first production.

Prairie Schooner anticipates an $85 million capital exploration program for 2006, of which in excess of 70 percent is budgeted to continue to enhance and exploit our west central Alberta core assets. The program will be entirely funded from cash flow. The capital program provides for the drilling of 250 gross (140 net) wells as well as investing approximately $7.5 million in land and seismic, and $18 million for facilities construction. Approximately 30 percent of the capital program will be invested in the first quarter of 2006.

Prairie Schooner's production is expected to average 8,000 barrels of oil equivalent per day (boe/d) in 2006, (88 percent natural gas), and exit 2006 at approximately 9,000 boe/d. Current production is 7,400 boe/d with approximately 400-600 boe/d awaiting tie in. This incremental production is anticipated to be onstream by mid April 2006.

The Company remains in a very strong financial position with net debt of $60.9 million (0.72 years trailing forecasted fourth quarter cash flow) on a credit facility of $80 million. With a current capital inventory of $230 million (380 net wells), Prairie Schooner is in an enviable position to further expand its capital program should conditions dictate. Beginning in the first quarter of 2006, Prairie Schooner will embark on its most aggressive drilling program to date. The winter drilling program encompasses a multiple well, multi zone program in each of the Pembina/Ferrier, Doris and Killam properties in west and east central Alberta. With its strong asset base and technical team, Prairie Schooner is well positioned to deliver on its growth objective.

Reserves

Information regarding the Company's December 31, 2005 reserves has been previously distributed in a press release dated February 22, 2006. The Company's reserves were evaluated for the year ended December 31, 2005 by GLJ in accordance with the rules provided by National Instrument 51-101. The following table provides summary information presented in the GLJ report effective December 31, 2005 and based on the GLJ (2006-01) price forecast. Additional reserves information will be presented in the Statement of Reserves Data and Other Oil and Gas Information section of the Company's 2005 Annual Information Form scheduled to be filed on SEDAR prior to March 31, 2006.

The December 31, 2005 reserve report was prepared by GLJ utilizing the methodology and definitions as set out under National Instrument 51-101 ("NI 51-101"). The year end working interest reserves for 2005 include company working interests excluding royalty interests received before royalties payable. Where amounts and volumes are expressed on a barrel of oil equivalent basis, gas volumes have been converted to barrels of oil at 6,000 cubic feet per barrel (6 mcf/bbl).



Summary of Company Working Interest Oil and Gas Reserves - Forecasted
Prices and Costs

Light and Natural
Medium Heavy Gas Natural
Crude Oil Oil Liquids Gas BOE
December 31, 2005 (mbbls) (mbbls) (mbbls) (bcf) (mboe)
------------------------------------------------
Proved
- Developed Producing 332 393 820 61.9 11,859
- Developed Non-Producing 93 - 121 7.4 1,439
- Undeveloped - - 23 4.8 828
------------------------------------------------
Total Proved 425 393 964 74.1 14,126
Probable 160 107 415 34.8 6,482
------------------------------------------------
Total Proved Plus Probable 585 500 1,379 108.9 20,608
------------------------------------------------
------------------------------------------------

Net Present Value of Reserves - Forecasted Prices and Costs

Discounted at
------------------------------------
December 31, Undiscounted 5% 10% 15% 20%
2005(1) (2) (M$) (M$) (M$) (M$) (M$)
------------------------------------------------
Proved
- Developed Producing 320,370 265,456 231,062 207,148 189,270
- Developed
Non-Producing 40,001 33,481 29,445 26,544 24,295
- Undeveloped 12,506 9,118 6,801 5,108 3,826
------------------------------------------------
Total Proved 372,877 308,055 267,308 238,800 217,391
Probable 163,396 114,975 89,946 74,533 63,964
------------------------------------------------

Total Proved Plus
Probable 536,273 423,030 357,254 313,333 281,355
------------------------------------------------
------------------------------------------------

(1) Utilizing GLJ January 1, 2006 price forecast per below
(2) As required by NI 51-101, undiscounted well abandonment costs of
$14.4 million for total proved reserves and $16.8 million for total
proved plus probable reserves are included in the Net Present Value
determination


Summary of Pricing Assumptions as of December 31, 2005 - Forecast Prices

WTI Foreign Edmonton Company's AECO Company's
Oil Exchange Oil Price Gas Price
(US$/bbl) Rate (Cdn$/bbl) Oil ($/bbl) (Cdn$/mcf) (Cdn$/mcf)
------------------------------------------------------------------
2006 57.00 0.85 66.25 62.15 10.60 10.58
2007 55.00 0.85 64.00 60.02 9.25 9.18
2008 51.00 0.85 59.25 55.38 8.00 7.89
2009 48.00 0.85 55.75 52.17 7.50 7.37
2010 46.50 0.85 54.00 50.46 7.20 7.05
2011 45.00 0.85 52.25 48.47 6.90 6.75
2012 45.00 0.85 52.25 48.39 6.90 6.75
2013 46.00 0.85 53.25 49.37 7.05 6.90
2014 46.75 0.85 54.25 50.35 7.20 7.04
2015 47.75 0.85 55.50 51.50 7.40 7.23
2016 48.75 0.85 56.50 52.31 7.55 7.38

Annual escalation rate of 2.0% thereafter

Summary of Company Working Interest Oil and Gas Reserves -
Constant Prices and Costs

Light and Natural
Medium Heavy Gas Natural
Crude Oil Oil Liquids Gas BOE
December 31, 2005 (mbbls) (mbbls) (mbbls) (bcf) (mboe)
------------------------------------------------
Proved
- Developed Producing 358 404 832 63.1 12,111
- Developed Non-Producing 93 - 121 7.5 1,457
- Undeveloped - - 23 4.9 842
------------------------------------------------
Total Proved 451 404 976 75.5 14,410
Probable 179 100 415 35.2 6,559
------------------------------------------------
Total Proved Plus
Probable 630 504 1,391 110.7 20,969
------------------------------------------------
------------------------------------------------


Net Present Value of Reserves - Constant Prices and Costs

Discounted at
------------------------------------
December 31, Undiscounted 5% 10% 15% 20%
2005(1) (2) (M$) (M$) (M$) (M$) (M$)
------------------------------------------------
Proved
- Developed Producing 406,491 321,204 270,368 236,177 211,320
- Developed
Non-Producing 49,440 39,906 34,181 30,163 27,120
- Undeveloped 20,340 14,697 10,954 8,310 6,366
------------------------------------------------
Total Proved 476,271 375,807 315,503 274,650 244,806
Probable 217,189 148,996 113,922 92,417 77,804
------------------------------------------------
Total Proved Plus
Probable 693,460 524,803 429,425 367,067 322,610
------------------------------------------------
------------------------------------------------

Note:
(1) Price assumptions: $64.36/bbl Cdn. Crude Oil Edmonton Light and
$9.57/mmbtu Cdn. AECO "C"
(2) As required by NI 51-101, undiscounted well abandonment costs of
$10.2 million for total proved reserves and $11.0 million for total
proved plus probable reserves are included in the Net Present Value
determination
(3) May not add due to rounding


The following reconciliation of Company Interest (note 1) reserves compares changes in the Company's reserves as at December 31, 2004 to the reserves as at December 31, 2005, each evaluated following National Instrument 51-101(N151-101) definitions.



Total
Total Proved Total Proved plus
Proved Probable Probable
----------------------------------------
(mboe) (mboe) (mboe)

Balance December 31, 2004 6,005 1,850 7,855
Technical (50) (181) (231)
Exploration discoveries 102 39 141
Acquisitions 6,191 2,571 8,762
Drilling extensions 1,831 1,246 3,077
Economic factors 131 19 150
Improved recoveries 1,294 966 2,260
Production (1,270) - (1,270)
----------------------------------------
Balance December 31, 2005 14,234 6,510 20,744
----------------------------------------
----------------------------------------

Note:
(1) Company Interest reserves means, our working interest (operating
and non-operating) share before deduction of royalties and including
any royalty interest of the Company.
(2) May not add due to rounding


($ thousands) 5% discount 10% discount
------------------------------------------------------------------------
Net present value of proved plus probable
reserves (1) 423,029 357,255
Undeveloped land (2) 31,965 31,965
Working capital deficit (60,871) (60,871)
Proceeds from exercise of stock options 23,011 23,011
------------------------------------------------------------------------
Total 417,134 351,360

Diluted shares at December 31, 2005 (thousands) 22,033 22,033
Net asset value per diluted share $18.93 $15.95
------------------------------------------------------------------------
------------------------------------------------------------------------

Amounts are in millions of dollars except per share data.

(1) Net present value of reserves evaluated by GLJ as of December 31,
2005, in accordance with the standards of NI 51-101 using forecasted
prices and costs, discounted at five percent and ten percent before
taxes.
(2) Undeveloped lands in Canada were internally evaluated by management
in accordance with the standards of NI 51-101.


Capital Program Efficiency

The efficiency of the Company's capital program for the year ended
December 31, 2005 is summarized below:

Proved plus
Proved Probable
--------- ------------
Capital expenditures
Capital expenditures ($ thousands) 207,534 207,534
Change in future development capital
($ thousands) 5,242 17,786
--------- ------------
Total costs ($ thousands) 212,776 225,320
--------- ------------
--------- ------------

Finding and development costs
Reserves additions including revisions (mboe) 9,499 14,159
--------- ------------
Finding and development costs without change
in future capital ($/boe) 21.85 14.66
Finding and development costs with change in
future capital ($/boe) 22.40 15.91
--------- ------------
--------- ------------

Recycle Ratio
Operating netback ($/boe) 35.28 35.28
Finding and development costs ($/boe) 21.85 14.66
--------- ------------
Recycle ratio 1.6x 2.4x
--------- ------------
--------- ------------

Reserves
Reserves additions including revisions (mboe) 9,499 14,159
Total production 2005 1,270 1,270
--------- ------------
Reserves replacement 748% 1,115%
--------- ------------
--------- ------------

Reserve Life Index
Total Company Interest reserves (mboe) 14,234 20,744
Fourth quarter 2005 production (boe/d) 5,844 5,844
Annual 2005 production (boe/d) 3,479 3,479
--------- ------------
RLI based on fourth quarter annualized production
(years) 6.7 9.7
RLI based on 2005 annual production (years) 11.2 16.3
--------- ------------
--------- ------------


Corporate Information

Board of Directors Officers

MURRAY COBBE (1)(3) JAMES SAUNDERS
President, Trican Well Service Ltd. Chairman & CEO
Calgary, Alberta

JAMES SAUNDERS NEIL ROSZELL, P. Eng.
Chairman & CEO, Prairie Schooner President & COO
Petroleum Ltd.
Calgary, Alberta
BRUCE ROBERTSON
HARVEY TRIMBLE (2)(3) Executive Vice President
Independent Businessman
Okotoks, Alberta
JERRY SAPIEHA, CA
WARREN STECKLEY (1)(2)(3) Vice President, Finance & CFO
President, Barnwell of Canada, Limited
Calgary, Alberta
SHANE PEET, P. Eng.
BOB CHAISSON (2) Vice President, Engineering
V.P. Operations, Atlas Energy Ltd.
Calgary, Alberta
STEVE DELAHAY, P. Geol.
KEVIN OLSON (1) Vice President, Exploration
Fund Manager, Energy One Equity Inc.
Calgary, Alberta
Head Office
GARY BUGEAUD (Corporate Secretary) Suite 1000, 520 - 5th Avenue SW
Burnet Duckworth & Palmer LLP Calgary, Alberta T2P 3R7
Tel: (403) 266-6400
Fax: (403) 266-8681

Members of the following committee: Bankers
Bank of Montreal
(1) Audit Committee Calgary, Alberta

(2) Reserve Committee Auditors
KPMG LLP
(3) Compensation and Corporate Calgary, Alberta
Governance
Independent Reservoir
Consultants
GLJ Petroleum Consultants Ltd.
Calgary, Alberta


PRAIRIE SCHOONER PETROLEUM LTD.

CONSOLIDATED BALANCE SHEET

As at December 31, 2005 2004
------------------------------------------------------------------------
(thousands) $ $

ASSETS

Current assets
Accounts receivable 12,989 3,099
Prepaid expenses 1,101 689
------------------------------------------------------------------------
14,090 3,788
Property and equipment (notes 4 & 5) 254,786 68,789
Goodwill (notes 2(c) & 4) 27,107 -
------------------------------------------------------------------------
295,983 72,577
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Accounts payable 21,803 4,631
Bank debt (note 6) 53,158 28,508
------------------------------------------------------------------------
74,961 33,139
Future income taxes 30,139 6,083
Asset retirement obligations (note 9) 10,960 3,001
------------------------------------------------------------------------
116,060 42,223
------------------------------------------------------------------------

Shareholders' equity
Share capital (note 7) 157,564 22,452
Contributed surplus 1,089 145
Retained earnings 21,270 7,757
------------------------------------------------------------------------
179,923 30,354
------------------------------------------------------------------------

295,983 72,577
------------------------------------------------------------------------
------------------------------------------------------------------------

(See accompanying notes to the consolidated financial statements)


PRAIRIE SCHOONER PETROLEUM LTD.

CONSOLIDATED STATEMENT OF OPERATIONS AND RETAINED EARNINGS

Three months ended Year ended
December 31, December 31,
---------------------------------------------
2005 2004 2005 2004

------------------------------------------------------------------------
(thousands except
per share data) $ $ $ $

Revenue
Petroleum and natural
gas sales 35,582 5,384 70,584 18,756
Royalties, net (8,506) (992) (16,572) (3,226)
------------------------------------------------------------------------
27,076 4,392 54,012 15,530
------------------------------------------------------------------------

Expenses
Operating 3,840 865 7,855 3,124
Transportation 649 170 1,362 785
General and administrative 586 308 1,514 1,350
Restructuring charges
(note 4(d)) - 1,115 - 1,115
Stock-based compensation 331 115 1,115 145
Financial charges 490 113 1,139 765
Depletion, depreciation and
accretion (note 5 & 9) 9,308 1,749 19,486 4,423
------------------------------------------------------------------------
15,204 4,435 32,471 11,707
------------------------------------------------------------------------

Earnings (loss) before taxes 11,872 (43) 21,541 3,823

Capital taxes 260 14 390 36
Future income taxes (note 10) 4,088 - 7,638 1,103
------------------------------------------------------------------------
4,348 14 8,028 1,139
------------------------------------------------------------------------

Net earnings (loss) 7,524 (57) 13,513 2,684

Retained earnings,
beginning of period 13,746 7,814 7,757 5,073

Retained earnings,
end of year 21,270 7,757 21,270 7,757
------------------------------------------------------------------------
------------------------------------------------------------------------

Net earnings per share
Basic 0.49 - 0.96 0.35
Diluted 0.46 - 0.91 0.31


PRAIRIE SCHOONER PETROLEUM LTD.

CONSOLIDATED STATEMENT OF CASH FLOW

Three months ended Year ended
December 31, December 31,
--------------------------------------------
2005 2004 2005 2004

------------------------------------------------------------------------
(thousands) $ $ $ $

Cash flow related to the
following activities

Operating
Net earnings (loss) for
the period 7,524 (57) 13,513 2,684
Items not affecting cash:
Depletion, depreciation
and accretion 9,308 1,749 19,486 4,423
Future income taxes 4,088 - 7,638 1,103
Stock-based compensation 331 115 1,115 145
Risk management gain - 62 - -
Asset retirement
expenditures (105) (10) (121) (11)

------------------------------------------------------------------------

Funds from operations 21,146 1,859 41,631 8,344

Changes in non-cash
operating working capital (1,812) (240) (3,824) (838)
------------------------------------------------------------------------
19,334 1,619 37,807 7,506
------------------------------------------------------------------------

Financing
Change in bank debt 18,305 9,141 24,649 10,758
Share issuance, net 40,265 12,872 63,864 12,938
------------------------------------------------------------------------
58,570 22,013 88,513 23,696
------------------------------------------------------------------------

Cash available for
investment activities 77,904 23,632 126,320 31,202
------------------------------------------------------------------------

Investing
Property and equipment
additions (21,860) (3,413) (45,463) (10,723)
Acquisitions (note 4) (65,729) (20,524) (89,322) (20,524)
Changes in non-cash investing
working capital 9,685 305 8,465 (406)
------------------------------------------------------------------------
(77,904) (23,632) (126,320) (31,653)
------------------------------------------------------------------------

Change in cash - - - (451)

Cash, beginning of period - - - 451
------------------------------------------------------------------------

Cash, end of year - - - -
------------------------------------------------------------------------
------------------------------------------------------------------------

(See accompanying notes to the consolidated financial statements)


PRAIRIE SCHOONER PETROLEUM LTD.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2005

(tabular amounts in thousands of dollars, unless otherwise stated)

1. NATURE OF OPERATIONS

Prairie Schooner Petroleum Ltd. ("the Company") is engaged primarily in the exploration for and development and production of petroleum and natural gas in western Canada. The Company was incorporated under the laws of the Province of Alberta.

2. SIGNIFICANT ACCOUNTING POLICIES

a) Basis of Presentation

The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries.

The Company's Financial Statements which have been prepared in accordance with Canadian generally accepted accounting principles, have in managements opinion been properly prepared and have reasonable limits of materiality and reflect the following policies:

b) Petroleum and Natural Gas Operations

i) Capitalized Costs

The Company follows the full cost method of accounting for petroleum and natural gas operations whereby all costs of exploring for and developing oil and gas properties and related reserves are capitalized into a single Canadian cost center. Costs include land acquisition costs, geological and geophysical expenditures, costs of drilling both productive and non-productive wells, well equipment and certain other overhead expenditures related to exploration.

Gains or losses on the sale or disposition of oil and gas properties are not ordinarily recognized except under circumstances which result in a significant revision of depletion rates.

ii) Depletion and Depreciation

Petroleum and natural gas properties and related equipment, excluding undeveloped properties, are depleted and depreciated using the unit-of-production method based on estimated gross proved reserves. For purposes of the calculation, petroleum and natural gas reserves are converted at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of crude oil. In determining its depletion base, the Company includes estimated future costs to be incurred in developing proved reserves and excludes salvage values and the cost of unproved properties. Costs of acquiring and evaluating unproved properties are excluded from the depletion base until it is determined whether proved reserves are attributable to the properties or impairment occurs.

iii) Ceiling Test

Property and equipment is evaluated in each reporting period to determine that the carrying amount in a cost center is recoverable and does not exceed the fair value of the properties in the cost centre.

The carrying amounts are assessed to be recoverable when the sum of the undiscounted cash flows expected from the production of proved reserves, the lower of cost and market of unproved properties and the cost of the major development projects exceeds the carrying amount of the cost centre. When the carrying amount is not assessed to be recoverable, an impairment loss is recognized to the extent that the carrying amount of the cost centre exceeds the sum of the discounted cash flows expected from the production of proved and probable reserves, the lower of cost and market of unproved properties and the cost of major development projects of the cost centre. The cash flows are estimated using expected future product prices and costs and, are discounted using a risk-free interest rate.

c) Goodwill

Goodwill, which represents the excess of purchase price over fair value of net assets received, is tested for impairment on an annual basis in the fourth quarter. If indications of impairment are present, a loss would be charged to earnings for the amount that the carrying value of goodwill exceeds its fair value

d) Joint Ventures

Substantially all of the Company's exploration and development activities are conducted jointly with others and, accordingly, the financial statements reflect only the Company's proportionate interest in such activities.

e) Asset Retirement Obligations ("ARO")

The Company uses the ARO method of recording the future cost associated with the legal obligation to abandon and reclaim property and equipment. The fair value of the liability has the Company's ARO is recorded in the period in which it is incurred, with a corresponding increase in the carrying amount of the related asset. The capitalized amount is depleted on the unit-of-production method based on proved reserves. The liability amount is increased each reporting period due to the passage of time and the amount of accretion is expensed in the period. Actual costs incurred upon the settlement of the ARO are charged against the ARO.

f) Flow-through Shares

The Company from time to time issues flow-through shares. Under these financing agreements, shares are issued at a fixed price with the resultant proceeds used to fund exploration and development work within a defined time period. The exploration and development expenditures funded by flow-through arrangements are renounced to investors in accordance with the appropriate tax legislation. A future tax liability is recorded and share capital is reduced by the estimated tax benefits transferred to shareholders when the expenditures are renounced.

g) Future Income Taxes

Income taxes are calculated using the liability method of tax allocation. Temporary differences arising from the difference between the tax basis of an asset or liability and its carrying amount on the balance sheet are used to calculate future income tax liabilities or assets. The effect on future income tax liabilities or assets of a change in tax rates is recognized in net income in the period in which the change occurs.

h) Stock-Based Compensation Plan

The Company has a stock-based compensation plan which is described in note 8. As of January 1, 2004, the Company adopted a new accounting standard on stock-based compensation. Stock option expense is recorded as general and administrative expense for all options granted on or after January 1, 2004, with a corresponding increase recorded to contributed surplus.

The fair value of options granted, are estimated at the date of the grant using the Black-Scholes evaluation model. Upon the exercise of the stock option, consideration paid by employees or directors together with the amount previously recognized in contributed surplus, is credited to share capital.

i) Per Share Amounts

Per share amounts are calculated on the basis of the weighted average number of common shares outstanding during the period.

j) Revenue Recognition

Petroleum and natural gas sales are recognized as revenue at the time the respective commodities are delivered to purchasers.

k) Financial Instruments

Financial instruments may be utilized by the Company to manage its exposure to commodity price fluctuations and foreign currency. The Company's practice is not to utilize financial instruments for trading or speculative purposes.

The Company formally documents relationships between hedging instruments and hedged items, as well as its risk management objective and corporate strategy for undertaking various hedge transactions. This process includes linking derivatives to specific assets and liabilities on the balance sheet or to specific firm commitments or forecasted transactions. The Company formally assesses both at the inception of the hedge and at each reporting period, whether the derivatives that are used in hedging transactions are highly effective in offsetting changes in fair value or cash flows of hedged items.

Settlement of crude oil and natural gas swap agreements, which have been arranged as a hedge against commodity price, are reflected in revenues at the time of sale of the related hedged production.

l) Measurement Uncertainty

The amount recorded for depletion and depreciation of property and equipment, the provision for asset retirement obligations and the ceiling test calculation are based upon estimates of gross proved reserves, production rates, crude oil and natural gas prices, future costs and other relevant assumptions. By their nature, these estimates are subject to measurement uncertainty, and the impact on the financial statements of future periods could be material.

m) Comparative Numbers

Certain of the comparative numbers have been reclassified to conform to the current year presentation.

3. INITIAL PUBLIC OFFERING

On March 16, 2005, pursuant to its Initial Public Offering, the Company issued a total of 1,924,000 common shares at a price of $13.00 per common share for gross proceeds of $25 million. The net proceeds of approximately $23.1 million were initially applied to reduce bank debt. The Company commenced trading on the Toronto Stock Exchange on March 16, 2005.

4. ACQUISITIONS

During 2005, the Company completed the following acquisitions, each of which was accounted for using the purchase method:

a) On October 27, 2005 the Company acquired selected properties and a limited partnership from Purcell Energy Ltd. for consideration, after closing adjustments, consisting of approximately $65.3 million of cash and the issuance of 2,800,340 common shares at an ascribed value of $15.25 per share,

b) On September 15, 2005 the Company acquired 100% of the issued and outstanding shares of 1161646 Alberta Ltd., a private company involved in oil and gas exploration, development and production in east central Alberta for consideration consisting of approximately $16.5 million of cash and the issuance of 700,000 common shares at an ascribed value of $15.25 per share; and

c) On April 12, 2005 the Company acquired 100% of the issued and outstanding shares of Westrock Energy Ltd, a private company involved in oil and gas exploration for consideration consisting of approximately $17.2 million of cash and the issuance of 1,181,089 common shares at an ascribed value of $14.50 per share.

The results of operations of the acquired properties were included in these consolidated financial statements from the respective dates noted above. The under-noted amounts are estimates made by management based on information currently available. Amendments may be made to the purchase equation as the cost estimates and tax balances are finalized.



Westrock 1161646 Purcell Total
---------- --------- --------- ---------
Cost of Acquisition $ $ $ $

Common shares issued 17,126 10,675 42,705 70,506
Transaction costs 98 55 396 549
Cash 17,179 16,409 65,334 98,922
----------------------------------------

34,403 27,139 108,435 169,977
----------------------------------------
----------------------------------------


Allocated at estimated fair values $ $ $ $

Property and equipment 22,347 27,194 108,435 157,976
Goodwill 8,566 8,281 10,260 27,107
Future income taxes (4,157) (7,572) (5,261) (16,990)
Asset retirement obligations (259) (764) (4,999) (6,022)
Cash 10,149 - - 10,149
Non-cash working capital (2,243) - - (2,243)
----------------------------------------

34,403 27,139 108,435 169,977
----------------------------------------
----------------------------------------


d) Merger Agreement

On October 13, 2004, through an amalgamation of the Company's wholly owned subsidiary 1130975 Alberta and Prairie Schooner Energy Inc. ("PSEI"), the Company indirectly acquired all of the outstanding common shares of PSEI in exchange for 3,000,000 common shares. The assets of PSEI were comprised of approximately $9 million of cash.

Concurrent with this amalgamation, restructuring charges of $1.1 million were incurred of which $1.0 million was related to severance costs.



5. PROPERTY AND EQUIPMENT

December 31, 2005
--------------------------------
Accumulated Net
Depletion & Book
Cost Depreciation Value
--------------------------------
$ $ $

Petroleum and Natural Gas properties 288,910 34,342 254,568
Office Equipment 679 461 218
------------------------------------------------------------------------
289,589 34,803 254,786
------------------------------------------------------------------------
------------------------------------------------------------------------


December 31, 2004
--------------------------------
Accumulated Net
Depletion & Book
Cost Depreciation Value
--------------------------------
$ $ $

Petroleum and Natural Gas properties 84,014 15,437 68,577
Office Equipment 543 331 212
------------------------------------------------------------------------
84,557 15,768 68,789
------------------------------------------------------------------------
------------------------------------------------------------------------


The Company has capitalized, as part of petroleum and natural gas properties, indirect exploration overhead relating to property acquisition, exploration and development activities of $582 thousand for the year ended December 31, 2005 (2004 - $38 thousand).

At December 31, 2005, undeveloped land costs of $23.4 million (December 31, 2004 - $4.6 million) have been excluded from the amount subject to depletion and depreciation.

The Company performed a ceiling test calculation as at December 31, 2005 to assess the recoverable value of the property and equipment. The oil and gas future price is based on the January 1, 2006 commodity price forecast of the Company's independent reserve evaluators as outlined in the following table. Based on these assumptions, the undiscounted value of future net revenues from the Company's estimated proved reserves exceeded the carrying value of property and equipment as at December 31, 2005.

The following table summarizes the future benchmark prices and the Company's prices used in the ceiling test.





Foreign Edmonton Company's Company's
WTI Oil Exchange Oil Price Oil AECO Gas Price Gas
(US$/bbl) Rate (Cdn$/bbl) ($/bbl) (Cdn$/mcf) ($/mcf)
-------------------------------------------------------------------

2006 57.00 0.85 66.25 62.15 10.60 10.58
2007 55.00 0.85 64.00 60.02 9.25 9.18
2008 51.00 0.85 59.25 55.38 8.00 7.89
2009 48.00 0.85 55.75 52.17 7.50 7.37
2010 46.50 0.85 54.00 50.46 7.20 7.05
2011 45.00 0.85 52.25 48.47 6.90 6.75
2012 45.00 0.85 52.25 48.39 6.90 6.75
2013 46.00 0.85 53.25 49.37 7.05 6.90
2014 46.75 0.85 54.25 50.35 7.20 7.04
2015 47.75 0.85 55.50 51.50 7.40 7.23
2016 48.75 0.85 56.50 52.31 7.55 7.38

Annual escalation rate of 2.0% thereafter


6. BANK DEBT

2005 2004
----------------
$ $

Prime rate advances 13,158 5,008
Bankers' acceptances 40,000 23,500
------------------------------------------------------------------------
53,158 28,508
------------------------------------------------------------------------
------------------------------------------------------------------------


The Company has a demand revolving credit facility to a maximum of $80 million. The credit facility bears interest at the lenders' prime rate or at the Bankers' Acceptance rate plus a stamping fee of 1.25%. The $80 million borrowing base is subject to an annual review by the lender. The credit facility is secured by a first fixed and floating charge debenture in the amount of $150 million covering all the Company's assets.



7. SHARE CAPITAL

a) Authorized

Unlimited number of common shares
Unlimited number of preferred shares, issuable in series

b) Issued

Number of Amount
Shares $
------------------------------------------------------------------------
Common Shares
Balance, December 31, 2003 6,829,067 9,490
Exercise of stock options 582,500 2,901
Repayment of shareholder loans and accrued interest - 1,061
Issued on acquisition of PSEI (note 4(d) & (e) 3,000,000 9,000
------------------------------------------------------------------------

Balance, December 31, 2004 10,411,567 22,452
Exercise of stock options 296,001 1,722
Issued on Private Placements 2,740,000 41,550
Issued on Initial Public Offering 1,924,000 25,012
Issued on acquisition of Westrock (note 4(c)) 1,181,089 17,126
Issued on acquisition of 1161646 (note 4(b)) 700,000 10,675
Issued on acquisition of Purcell properties
(note 4(a)) 2,800,340 42,705
Tax effect of 2004 flow-through shares - (909)
Share issue costs, net of tax affect - (2,769)
------------------------------------------------------------------------
Balance, December 31, 2005 20,052,997 157,564
------------------------------------------------------------------------
------------------------------------------------------------------------


c) Flow Through Shares

PSEI issued a total of 4,375,000 flow through common shares for gross proceeds of $2.6 million. With the amalgamation of PSEI and the Company, these flow through shares were exchanged for 1,087,053 common shares of the Company. Under the terms of the flow through agreement, the Company is required to expend $2.6 million on qualifying crude oil and natural gas expenditures prior to December 31, 2005 all of which was incurred.



d) Contributed Surplus

2005 2004
----------------
$ $

Balance, beginning of year 145 24
Options granted 1,132 145
Options exercised (188) (24)
------------------------------------------------------------------------
Balance, end of year 1,089 145
------------------------------------------------------------------------
------------------------------------------------------------------------


e) Per share amounts

Basic per share amounts are calculated using the weighted average number of shares outstanding during the year.

The reconciling items between the basic and diluted average common shares outstanding are outstanding stock options. Diluted per share amounts are calculated assuming all options are exercised and included as the shares outstanding at December 31.



2005 2004
----------------

Weighted average shares outstanding (thousands)
Basic 14,112 7,538
Diluted 14,780 8,657


8. STOCK-BASED COMPENSATION

The Company has implemented a Stock Option Plan for directors and employees. Options granted under the Plan vest either over a three year period with 33% vesting upon each anniversary date of the grant (time criteria) or vest based on certain performance measurements (performance criteria) established by the Board of Directors. At December 31, 2005, 1,979,667 (2004 - 1,119,000) options with exercise prices between $5.50 and $19.25 were outstanding.



The following tables summarize the information about the share options:

2005 2004
----------------------------------------------
Weighted Weighted
average average
exercise exercise
Shares price Shares price
------------------------------------------------------------------------

Outstanding at beginning
of period 1,119,000 $ 5.46 637,500 $ 4.84
Granted 1,181,667 $15.92 1,079,000 $ 5.53
Exercised (296,000) $ 5.34 (582,500) $ 4.94
Cancelled (25,000) $13.00 (15,000) $ 5.10
------------------------------------------------------------------------

Outstanding at end of year 1,979,667 $11.62 1,119,000 $ 5.46
------------------------------------------------------------------------
Options exercisable at year end 123,666 $ 5.50 70,000 $ 4.81
------------------------------------------------------------------------

Options Outstanding Options exercisable
----------------------------------------------- ----------------------
Weighted
Number average Weighted Number Weighted
Range of outstanding remaining average exercisable average
exercise at December contractual exercise at December exercise
prices 31, 2005 life (years) price 31, 2005 price
------------------------------------------------------------------------

$ 5.50-$ 7.00 923,000 2.8 $ 5.61 123,666 $5.50
$ 7.01-$10.00 40,000 3.1 $ 7.50 - -
$10.01-$14.50 250,000 3.3 $14.20 - -
$14.51-$17.05 205,000 3.7 $16.08 - -
$17.06-$19.25 561,667 3.8 $19.03 - -
------------------------------------------------------------------------
1,979,667 $11.62 123,666 $5.50
------------------------------------------------------------------------
------------------------------------------------------------------------


The weighted average fair market value of options granted in the year
ended December 31, 2005 is $3.57 per option. The fair market of each
option granted was estimated on the date of grant using the Modified
Black-Scholes option-pricing model with the following assumptions:

2005 2004
----------------

Risk-free interest rate (%) 3.25 4.50
Expected life (years) 4 4
Expected volatility (%) 33% 30%
Dividend per share nil nil


9. ASSET RETIREMENT OBLIGATIONS

The Company's asset retirement obligations are based on the Company's net ownership in wells and facilities and management's estimate of costs to abandon and reclaim those wells and facilities as well as an estimate of the future timing of the costs to be incurred.

The Company has estimated the present value of its total asset retirement obligations to be $11.0 million at December 31, 2005 based on a total future liability of $21.6 million. Payments to settle asset retirement obligations occur over the operating lives of the underlying assets, estimated to be from zero to 30 years, with the majority of costs incurred between 2011 and 2017. Estimated cash flows have been discounted at the Company's credit-adjusted risk free rate of 8 percent and an inflation rate of 2 percent.



2005 2004
-------------------
Asset retirement obligations, beginning of period 3,001 2,226
Liabilities incurred during period 7,629 563
Liabilities settled during period (121) (11)
Accretion 451 223
-------------------
Asset retirement obligations, end of period 10,960 3,001
------------------------------------------------------------------------
------------------------------------------------------------------------


10. INCOME TAXES


The provision for income tax differs from the result which would be obtained by applying the combined Federal and Provincial statutory income tax rates to income before taxes. This difference results from the following:



2005 2004
-------------------
$ $

Earnings before taxes 21,541 3,823
------------------------------------------------------------------------

Statutory income tax rate 37.6% 38.3%

Expected income tax 8,100 1,464
Increase (decrease) resulting from:
Non-deductible crown charges 1,770 179
Resource allowance (1,603) (481)
Statutory rate adjustment (761) (141)
Stock-based compensation 420 56
Other (288) 26
------------------------------------------------------------------------
Provision for taxes 7,638 1,103
------------------------------------------------------------------------
------------------------------------------------------------------------


The future income tax liability is comprised of temporary differences
related to the following:

2005 2004
-------------------
$ $

Property and equipment 28,500 4,417
Deferral of partnership income 12,264 2,572
Asset retirement obligation (3,794) (1,003)
Non-capital losses (5,396) -
Share issue costs (1,383) -
Other (52) 97
------------------------------------------------------------------------
Future income taxes 30,139 6,083
------------------------------------------------------------------------
------------------------------------------------------------------------


11. SUPPLEMENTAL CASH FLOW INFORMATION

Changes in non-cash working capital:

2005 2004
$ $
------------------------------------------------------------------------
Accounts receivable (9,890) 334
Prepaid expenses (412) (266)
Accounts payable 14,943 (1,312)
------------------------------------------------------------------------
Changes in non-cash working capital 4,641 (1,244)
------------------------------------------------------------------------
------------------------------------------------------------------------


These changes relate to the following activities:

Operating activities (3,824) (838)
Investing activities 8,465 (406)
------------------------------------------------------------------------
4,641 (1,244)
------------------------------------------------------------------------
------------------------------------------------------------------------


Amounts paid during the year relating to interest expense and capital
taxes are as follows:

2005 2004
------------------------------------------------------------------------
$ $

Interest expense paid 819 765
Capital taxes paid in the year 50 21
------------------------------------------------------------------------
869 786
------------------------------------------------------------------------
------------------------------------------------------------------------


12. FINANCIAL INSTRUMENTS

The Company is exposed to fluctuations in commodity prices, interest rates and Canada/U.S. exchange rates. The Company, when appropriate, utilizes financial instruments to manage its exposure to these risks.

a) Commodity Price Risk Management

Financial instruments are entered into by the Company to protect the downside prices received on the sale of a portion of its crude oil and natural gas production. The agreements entered into are forward transactions providing the Company with a range of fixed prices on the commodities sold. Petroleum and natural gas revenue for the year ended December 31, 2005 include losses of $1.1 million (2004 - $392 thousand gain) on those transactions.



The following contracts were outstanding as at December 31, 2005:

Commodity Type Term Volume Price Index
------------ -------- ---------------- -------------- ---------- -------
January 2006 - $12.00 -
Natural gas Collar March 2006 2,000 GJ's/d $14.70/GJ AECO
January 2006 -
Natural gas Fixed March 2006 8,000 GJ's/d $9.87/GJ AECO
April 2006 - $9.50 -
Natural gas Collar October 2006 2,000 GJ's/d $10.86/GJ AECO
April 2006 -
Natural gas Fixed October 2006 7,000 GJ's/d $8.36/GJ AECO


The estimated fair value at December 31, 2005 of these transactions, had the contracts been settled at that time, would be a loss of $2.3 million.


Contact Information

  • Prairie Schooner Petroleum Ltd.
    Mr. Jim Saunders
    Chairman and Chief Executive Officer
    (403) 303-3750
    (403) 266-8681 (FAX)
    or
    Prairie Schooner Petroleum Ltd.
    Mr. Jerry Sapieha, CA
    Vice President, Finance and Chief Financial Officer
    (403) 303-3762
    (403) 266-8681 (FAX)