Prairie Schooner Petroleum Ltd.

Prairie Schooner Petroleum Ltd.

March 23, 2005 18:12 ET

Prairie Schooner Petroleum Ltd. Announces 2004 Results


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: PRAIRIE SCHOONER PETROLEUM LTD.

TSX SYMBOL: PSL

MARCH 23, 2005 - 18:12 ET

Prairie Schooner Petroleum Ltd. Announces 2004 Results

CALGARY, ALBERTA--(CCNMatthews - March 23, 2005) - Prairie Schooner
Petroleum Ltd. (TSX:PSL) is pleased to announce its operating and
financial results for the fourth quarter and year ended December 31,
2004.

During the fourth quarter of 2004, Prairie Schooner was restructured
including a new management team and a recapitalization of the Company.
The Company incurred restructuring expenses in the fourth quarter of
$1.1 million which was primarily severance costs. Additionally, Gilbert
Laustsen Jung Associates Ltd. ("GLJ") were engaged as new independent
engineers to review the Company's reserves. This review resulted in
negative revisions to the beginning of the year reserve balance and
accordingly, the Company's fourth quarter depletion rate was
substantially higher than the previous nine months of 2004. Combined,
these factors resulted in a net loss of $57 thousand for the fourth
quarter of 2004.



Financial Highlights

Three months ended Year ended
December 31, December 31,
-------------------- Percent --------------- Percent
2004 2003 Change 2004 2003 Change
------------------- -------- --------------- --------

Financial
(thousands of
dollars except
share data)

Petroleum and natural
gas revenue 5,384 3,516 53 18,756 13,618 38
Cash flow from
operations 1,859 1,547 20 8,344 6,200 35
Per share - basic 0.15 0.22 (32) 1.10 0.91 21
- diluted 0.09 0.20 (55) 0.96 0.83 16
Net earnings (loss) (57) 1,121 - 2,684 2,978 (10)
Per share - basic - 0.15 - 0.35 0.44 (20)
- diluted - 0.14 - 0.31 0.40 (23)
Capital expenditures 23,937 5,162 364 31,247 21,318 47
Debt, net 29,351 19,384 51
Weighted average
shares (thousands)
Basic 9,598 6,782 42 7,538 6,791 11
Diluted 10,717 7,420 44 8,657 7,429 17
Shares outstanding
(thousands)
Basic 10,412 6,829 52
Diluted 11,531 7,467 54

Operating
(6:1 boe conversion)

Average daily production
Natural gas (mmcf/d) 8.0 5.9 36 7.2 5.2 38
Liquids (bbls/d) 86 121 (29) 88 114 (23)
Barrels of oil
equivalent (boe/d) 1,417 1,099 29 1,285 977 32

Average sales price
Natural gas ($/mcf) 6.84 5.51 24 6.54 6.11 7
Liquids ($/bbl) 53.29 36.77 45 48.66 39.57 23
Barrel of oil
equivalent ($/boe) 41.79 33.48 25 39.88 37.01 8


Highlights of our successful year follow:

- Acquired properties (650 boe/d) on December 17, 2004 which
significantly increased corporate production and our inventory of
drillable prospects

- Year end reserves on a proven and probable basis were 7,855 mboe's
reflecting a 10.7 year reserve life index based on 2004 exit rate
production

- Fourth quarter production averaged 1,417 boe/d, an increase of 15
percent over the third quarter of 2004 and a 29 percent increase over
the comparable quarter of 2003. Current production is up 50 percent from
the fourth quarter

- Record cash flow in 2004 of $8.3 million or $1.10 per share, an
increase of 35 percent over 2003 and a 21 percent increase on a per
share basis

- Drilling for the year ended December 31, 2004 resulted in 34 gross
(30.6 net) wells drilled with a success rate of 97%

- Exited 2004 with 2,000 boe/d of production (95% natural gas)

Corporate

On March 16, 2005, Prairie Schooner announced the closing of its Initial
Public Offering. At closing, a total of 1,924,000 common shares were
issued at a price of $13.00 per common share for gross proceeds of $25
million. The common shares of the Company commenced trading on March 16
on the Toronto Stock Exchange. As at March 16, 2005, there were
12,445,567 common shares outstanding (13,669,567 fully diluted).

Operations

To date in the first quarter we have been very pleased with our results,
having achieved a 100 percent success rate on the eight gross (5.9 net)
wells drilled to date. At Two Hills in northeast Alberta, four gross
(2.25 net) wells were cased and completed as successful gas wells. These
wells will be on-stream by the end of the first quarter. Since October
we have generated a 90 plus percent success rate in the area with upward
of 10 drillable prospects remaining for 2005. At Faith in southern
Alberta where the Company has recently completed a 36 section farm-in
arrangement, 2 shallow wells have been cased as successful natural gas
wells. In west central Alberta the first of a multi-well gas program at
Chigwell has been cased. At Innisfail, Prairie Schooner is planning to
commence the first of a three well farm-in commitment in the second
quarter.

We anticipate participating in a minimum 60 net wells in 2005 including
an 11 well shallow program at Irvine in southern Alberta which we
anticipate commencing in April. Overall, a $30 million capital program
is forecast for 2005 with approximately $5 million to be incurred in the
first quarter. Production is currently 2,100 boe/d and with new
production being brought on-stream, the Company anticipates production
to exceed 2,300 boe/d by the end of March.

Outlook

Prairie Schooner has seen an exciting six months since it was
restructured in October 2004. A successful corporate restructuring; a
significant property transaction combined with a successful drilling
program has propelled corporate growth. We anticipate this growth to
continue over 2005 as we drill and exploit our extensive capital
inventory.

The Company's fundamental focus remains unchanged; increasing
shareholder value through a combination of grass roots exploration,
strategic acquisitions and subsequent exploitation.



On behalf of the Board of Directors:


Jim Saunders
Chairman and Chief Executive Officer
March 23, 2005


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, 2004 and 2003 and the
unaudited consolidated interim financial statements for the three months
ended December 31, 2004 and 2003. This discussion is based on
information available to and is dated, March 23, 2005. The financial
data presented is in accordance with Canadian generally accepted
accounting principles in Canadian dollars, except where indicated
otherwise.

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
2004 2003 2004 2003 Change
-------------------- ---------------- ---------
(thousands of dollars)

Natural gas revenue 4,655 2,987 16,477 11,545 43
Liquids revenue 387 384 1,455 1,528 (5)
Hedging gains (loss) 231 47 392 71 452
Royalty and other 111 98 432 474 (9)
----------------------------------------

5,384 3,516 18,756 13,618 38
----------------------------------------
----------------------------------------



The Company's production for the fourth quarter averaged 1,417 boe/d, an
increase of 15 percent from the 1,228 boe/d in the third quarter of
2004, and an increase of 29 percent compared to the fourth quarter of
2003. Natural gas production increased to 8.0 mmcf/d in the fourth
quarter from 7.0 mmcf/d in the third quarter. Liquids production
increased to 86 bbls/d from 62 bbls/d in the third quarter. This
increase was attributable to a successful drilling program that resulted
in a 97 percent drilling success rate for the year ended December 31,
2004. Production for the twelve months ended December 31, 2004 was 1,285
boe/d comprised of 7.2 mmcf/d of natural gas and 88 bbls/d of liquids.
Average production volumes on a year-over-year basis in 2004 have
increased by 32 percent when compared to 2003.

Petroleum and natural gas revenue increased by 23 percent to $5.4
million from the $4.4 million recorded in the third quarter of 2004.
Strong natural gas prices, combined with increased production, resulted
in the increase for the quarter. Year-over-year, revenue increased by 38
percent as a result of an 8 percent increase in commodity prices and a
successful drilling program which resulted in a 32 percent increase in
production volumes.

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, 2004:

Commodity Type Term Volume Price Index
------------------------------------------------------------------------

Natural gas Collar January 2005 1,250 GJ's/d $7.50 -
- March 2005 $11.50/GJ AECO

Natural gas Fixed January 2005 2,250 GJ's/d $ 8.06/GJ AECO
- March 2005

Natural gas Fixed April 2005 -
October 2005 2,500 GJ's/d $ 6.83/GJ AECO


Royalties

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------
(thousands of dollars)

Crown 496 274 1,464 1,176 24
Freehold and GORR 568 354 2,035 1,681 21
Alberta Royalty Tax Credit (72) (26) (273) (255) 7
----------------------------------------

992 602 3,226 2,602 24
----------------------------------------
----------------------------------------

Percent of total revenue 18.4% 17.1% 17.2% 19.1% (10)
Per boe ($) 7.61 5.95 6.86 7.30 (6)


For the three months ended December 31, 2004, royalty expense net of
ARTC, and royalty rates increased compared to the same quarter of 2003
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 2004, crown royalty rates increased due to a higher number of wells
drilled on crown land when compared to 2003. Royalties on a percent of
total revenue basis were positively impacted by the hedging gains
incurred in the year ended December 31, 2004. These gains decreased the
royalty rate for the year by approximately 0.5%.



Operating Expenses

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------

Total operating
costs ($000's) 865 583 3,124 2,205 42
Percent of total revenue 16.1% 16.6% 16.7% 16.2% 3
Per boe ($) 6.64 5.76 6.64 6.18 7


Operating costs for the fourth quarter of 2004 increased to $0.9 million
from the $0.6 million incurred in the third quarter of 2004 primarily as
a result of the 15 percent increase in production volumes. Unit
operating expenses are up from the third quarter of 2004 by 16 percent.
The increase is due to an increase in power costs, chemicals and
equipment maintenance and rentals that are normally associated with the
higher costs of winter operations.

On a per unit basis, operating expenses were 7 percent higher at $6.64
per boe for 2004 compared to $6.18 per boe during 2003. This increase
reflects the rising operating costs that reflect the higher cost of
operations and field services as a result of increased drilling activity
in the industry. Operating costs for 2004 included $0.6 million or $1.22
per boe for third party gathering and processing charges and water
disposal expenses.



Transportation Expenses

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------

Total transportation
costs ($000's) 170 130 785 419 87
Percent of total revenue 3.2% 3.7% 4.2% 3.1% 35
Per boe ($) 1.31 1.28 1.67 1.17 43


Effective January 1, 2004, the Company adopted a new accounting standard
and began disclosing transportation costs separately rather than netting
out the costs from revenue.



General and Administrative Expenses

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------
(thousands of dollars)

General and
administrative 396 539 1,586 1,968 (19)
Stock-based compensation 115 6 145 24 504
Overhead recoveries (50) (126) (198) (397) (50)
Capitalized G & A (38) - (38) - 100
----------------------------------------

Net 423 419 1,495 1,595 (6)
----------------------------------------
----------------------------------------

Percent of total revenue 7.9% 11.9% 8.0% 11.7% (32)
Per boe ($) 3.25 4.15 3.18 4.48 (29)


General and administrative expenses for the fourth quarter were $423
thousand after recoveries and capitalized costs, an increase from $344
thousand in the third quarter of 2004. This increase is attributable to
the $115 thousand expense related to Stock-Based Compensation. The
Company adopted the new accounting standard in the first quarter of 2004
which resulted in an expense for 2004 of $145 thousand as compared to
$24 thousand in 2003.

Overhead recoveries were lower in the fourth quarter due to decreased
capital activity when compared to the fourth quarter of 2003.



Restructuring Expenses

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------

Total restructuring
costs ($000's) 1,115 - 1,115 - n/a
Percent of total revenue 20.7% - 5.9% - n/a
Per boe ($) 8.56 - 2.36 - n/a


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.



Financial Charges

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------
Total financial
charges ($000's) 113 159 765 507 51
Percent of total
revenue 2.1% 4.5% 4.1% 3.7% 11
Per boe ($) 0.87 1.57 1.63 1.42 15


Compared to the third quarter of 2004, interest expense decreased by
$146 thousand due to the previously mentioned recapitalization which
early in the quarter reduced bank debt by approximately $9 million. Debt
levels increased as a result of the previously mentioned property
acquisition in late December which was financed by bank debt.



Depletion, Depreciation and Accretion

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------
(thousands of dollars)

Depletion and
depreciation 1,650 635 4,200 1,976 113
Accretion 99 43 223 153 46
----------------------------------------

1,749 678 4,423 2,129 108
----------------------------------------
----------------------------------------

Percent of total
revenue 32.5% 19.3% 23.6% 15.6% 51
Per boe ($) 13.42 6.71 9.40 5.98 57


Depletion and depreciation expense for the fourth quarter was $1.7
million, substantially higher than the $1.0 million recorded in the
third quarter. This increase in depletion expense was attributable to a
combination of increased production in the quarter and a 33 percent
increase in the per unit depletion factor. On a unit of production
basis, the provision was $13.42 per boe for the fourth quarter, an
increase of 100 percent when compared to $6.71 per boe in the fourth
quarter of 2003.

As part of the restructuring previously described, management retained
GLJ as independent engineers to review the Company's reserve base. This
review resulted in negative revisions to the beginning of the year
reserve balance and accordingly, the Company's fourth quarter depletion
rate was substantially higher than the previous nine months of 2004.
Additionally, depletion has been adjusted to factor an increase in the
depletion base in accordance with new rules regarding Asset Retirement
Obligations.

Accretion increased to $223 thousand, a 46% increase over the year 2003.
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 2004, capital taxes were $36 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, 2004 was $1.1
million and reflects an effective tax rate of 29%. During 2004, both the
Federal and Alberta income tax authorities substantially enacted
reductions on income tax rates for the current and future years. The
total liability for future income tax was $6.1 million as at December
31, 2004.

Cash Flow from Operations and Net Income

Cash flow from operations for the three months ended December 31, 2004
was $1.9 million ($0.15 per share) compared to $2.0 million ($0.29 per
share) in the third quarter. In the fourth quarter the Company incurred
a net loss of $57 thousand ($nil per share) compared to net earnings of
$835 thousand ($0.12 per share) in the third quarter.

As previously indicated, restructuring expenses of $1.1 million combined
with higher depletion expenses negatively impacted the fourth quarter of
2004 reducing both cash flow from operations and net earnings.

For the year ended December 31, 2004, cash flow from operations was $8.3
million or $1.10 per share as compared to $6.2 million and $0.91 per
share in 2003.



Capital Expenditures

Three months ended Year ended
December 31, December 31,
-------------------- ---------------- Percent
2004 2003 2004 2003 Change
-------------------- ---------------- ---------
(thousands of dollars)

Land 76 314 694 1,611 (57)
Property acquisitions
(dispositions) 20,524 (32) 20,524 405 4,968
Geological and
geophysical 300 (5) 395 46 759
Drilling and
completions 1,695 3,192 5,411 12,661 (57)
Production facilities 1,281 1,692 4,076 6,514 (37)
Other 61 1 147 81 81
----------------------------------------

Total 23,937 5,162 31,247 21,318 47
----------------------------------------
----------------------------------------


The Company drilled 34 gross (30.6 net) wells during the year with a 97
percent success rate. Prairie Schooner drilled 8 gross (6.1 net) wells
during the fourth quarter with an 88 percent success rate. During the
fourth quarter the Company drilled 3 gross (3.0 net) wells at Irvine, 2
gross (0.34 net) wells at Huxley, 2 gross (1.8 net) wells at Two Hills
and 1 gross (1.0 net) wells at Rattlesnake. This program resulted in 7
successful natural gas wells and one abandoned well.

Facility and infrastructure expenditures were incurred in the Company's
core area of Rattlesnake to bring on-stream wells that were drilled and
completed in the second and third quarter of 2004.

Liquidity and Capital Resources

At December 31, 2004, total net debt (including the working capital
deficit) was $29.4 million compared to net debt of $19.4 million at
December 31, 2003. For the year ended December 31, 2004, cash flow of
$8.3 million, common share equity issuance proceeds of $12.9 million and
an increase in net debt of $10 million, were utilized to fund $31.2
million of capital expenditures.

During 2004 the Company issued common shares as follows:

- 3,000,000 common shares issued for gross proceeds of $9.0 million

- 582,500 common share options exercised for gross proceeds of $2.9
million

At December 31, 2004, the Company had a $35 million demand revolving
credit facility with its lender.

As at March 23, 2005, 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, 2004:

- 1,924,000 common shares issued on the Company's Initial Public Offering

- 175,000 common share options granted

- 70,000 common share options exercised

- 40,000 common shares issued on a Private Placement

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".

Changes in Accounting Policy in 2004

Effective January 1, 2004, Prairie Schooner adopted Accounting Guideline
16, "Oil and Gas Accounting - Full Cost". In September 2002, the
Canadian Institute of Chartered Accountants ("CICA") approved Section
3063, "Impairment of Long-Lived Assets", establishing standards for the
recognition, measurement and disclosure of the impairment of long-lived
assets and applies to long-lived assets held for use. An impairment loss
is recognized when the carrying value exceeds its fair value and is not
recoverable. This standard is effective for fiscal years beginning on or
after April 1, 2003. AcG-16, issued in September 2003, includes this
section in the application of the impairment test for oil and gas
companies using the full cost method of accounting. The carrying value
for oil and gas properties is limited to their fair value, which is
equal to estimated future cash flows from proved and probable reserves,
calculated using future price forecasts and costs discounted at a
risk-free rate. The former ceiling test used undiscounted cash flows
determined using constant prices, reduced for general and administrative
and financing costs. The adoption of this standard had no material
adverse impact on the Company's financial results.

For the fiscal year beginning January 1, 2004, Prairie Schooner adopted
the CICA's new section "Asset Retirement Obligations" (Section 3110).
This new accounting pronouncement requires accrued reclamation and
abandonment obligations be recognized on the balance sheet by increasing
oil and gas properties offset by a corresponding liability. The asset
and liability are initially measured at fair value, being the discounted
future value of the liability, and then capitalized as part of the cost
of the asset and subsequently amortized over the life of the asset. The
liability accretes until the retirement obligation is settled.
Comparative numbers for 2003 and prior periods have been restated and
the impact is disclosed in Note 2 of the financial statements. The
adoption of this standard does not have a material adverse impact on the
Company's financial position or results of operations.

For the fiscal year beginning January 1, 2004, Prairie Schooner revised
its presentation of transportation costs in accordance with CICA
Handbook Section 1100 "Generally Accepted Accounting Principles". As a
result, revenue has been presented prior to transportation costs and a
separate expense for transportation costs has been presented in the
statements of operations and retained earnings. The Company has
reclassified previously reported amounts to be consistent with the
presentation under this new policy. There was no impact on net earnings
or cash flow in any quarter of 2004, nor did it impact restated net
income or cash flow for any quarter of 2003.

Reserves

The December 31, 2004 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 2004 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 Gas Natural
Crude Oil Liquids Gas BOE
December 31, 2004 (mbbls) (mbbls) (bcf) (mboe)
-------------------------------------
Proved
- Developed Producing 69 50 29.0 4,948
- Developed Non-Producing - - 0.8 133
- Undeveloped - - 5.2 869
-------------------------------------
Total Proved 69 50 35.0 5,950
Probable 16 11 10.9 1,841
-------------------------------------

Total Proved Plus Probable 85 61 45.9 7,791
-------------------------------------
-------------------------------------

Net Present Value of Reserves - Forecasted Prices and Costs

Discounted at
--------------------------------
Undiscounted 5% 10% 15% 20%
December 31, 2004(1) (2) (M$) (M$) (M$) (M$) (M$)
----------------------------------------------

Proved
- Developed Producing 90,294 73,207 61,680 53,554 47,566
- Developed Non-Producing 4,135 2,990 2,249 1,744 1,382
- Undeveloped 10,284 7,458 5,465 4,025 2,959
----------------------------------------------
Total Proved 104,713 83,655 69,394 59,323 51,907
Probable 39,559 24,525 16,942 12,693 10,087
----------------------------------------------
Total Proved Plus Probable 144,272 108,180 86,336 72,016 61,994
----------------------------------------------
----------------------------------------------

(1) Utilizing GLJ January 1, 2005 price forecast per below
(2) As required by NI 51-101, undiscounted well abandonment costs of
$10.2 million for total proved reserves and $11.4 million for total
proved plus probable reserves are included in the Net Present Value
determination

Summary of Pricing Assumptions as of December 31, 2004 - Forecast Prices

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

2005 42.00 0.82 50.25 49.99 6.60 6.40
2006 40.00 0.82 47.75 47.36 6.35 6.11
2007 38.00 0.82 45.50 45.00 6.15 5.90
2008 36.00 0.82 43.25 42.66 6.00 5.74
2009 34.00 0.82 40.75 40.07 6.00 5.72
2010 33.00 0.82 39.50 38.74 6.00 5.72
2011 33.00 0.82 39.50 38.51 6.00 5.71
2012 33.00 0.82 39.50 34.90 6.00 5.70
2013 33.50 0.82 40.00 35.40 6.10 5.79
2014 34.00 0.82 40.75 36.15 6.20 5.89
2015 34.50 0.82 41.25 36.65 6.30 5.98

Annual escalation rate of 2.0% thereafter

Net Present Value of Reserves - Constant Prices and Costs

Discounted at
--------------------------------
Undiscounted 5% 10% 15% 20%
December 31, 2004(1) (2) (M$) (M$) (M$) (M$) (M$)
----------------------------------------------

Proved
- Developed Producing 111,384 86,837 71,435 61,036 53,583
- Developed Non-Producing 4,259 3,156 2,428 1,922 1,553
- Undeveloped 13,946 10,146 7,543 5,695 4,342
----------------------------------------------
Total Proved 129,589 100,140 81,407 68,653 59,478
Probable 45,393 27,747 19,122 14,333 11,388
----------------------------------------------
Total Proved Plus Probable 174,982 127,887 100,529 82,985 70,866
----------------------------------------------
----------------------------------------------

Note: May not add due to rounding
(1) Price assumptions: $46.54/bbl Cdn. Crude Oil Edmonton Light and
$6.79/mmbtu Cdn. AECO "C"
(2) As required by NI 51-101, undiscounted well abandonment costs of
$7.2 million for total proved reserves and $7.4 million for total
proved plus probable reserves are included in the Net Present
Value determination


Reserve Life Index

The reserve life calculated using exit 2004 production may be more
reflective of reserve life due to the level of new production added
during the year. The Company's reserve life index using exit 2004
production is 8.2 years for proved boe reserves and 10.7 years for
proven plus provable boe reserves. The Company's reserve life index
using annualized fourth quarter production is 11.4 years for proven boe
reserves and 15 years for proven plus probable boe reserves.



2004
------------------------
Using
Using Annualized
Exit Q4
Production Production
------------------------
Production (mboe) 730 521
Proved reserves (mboe) 5,950 5,950
Proved reserve life index (years) 8.2 11.4
Proved plus probable reserves (mboe) 7,791 7,791
Proved plus probable reserve life index (years) 10.7 15.0


This disclosure contains certain forward looking statements that involve
substantial known and unknown risks and uncertainties, certain of which
are beyond Prairie Schooner's control, including: the impact of general
economic conditions in Canada and the United States, industry
conditions, changes in laws and regulations including the adoption of
new environmental laws and regulations and changes in how they are
interpreted and enforced, increased competition, the lack of
availability of qualified personnel or management, fluctuations in
foreign exchange or interest rates, stock market volatility and market
valuations of companies with respect to announced transactions and the
final valuations thereof, and obtaining required approvals of regulatory
authorities. Prairie Schooner's actual results, performance or
achievement could differ materially from those expressed in, or implied
by, these forward looking statements and, accordingly, no assurances can
be given that any of the events anticipated by the forward looking
statements will transpire or occur, or it any of them do so, what
benefits, including the amount of proceeds, that Prairie Schooner will
derive therefrom.




PRAIRIE SCHOONER PETROLEUM LTD.
CONSOLIDATED BALANCE SHEET


2003
As at December 31, 2004 (Restated - note 3)
---------------------------------------------------------------------
(thousands)
$ $
ASSETS

Current assets
Cash - 451
Accounts receivable 3,099 3,433
Prepaid expenses 689 424
---------------------------------------------------------------------
3,788 4,308
Property and equipment (note 4(b) & 5) 68,789 41,177
---------------------------------------------------------------------
72,577 45,485
---------------------------------------------------------------------
---------------------------------------------------------------------


LIABILITIES AND SHAREHOLDERS' EQUITY

Current liabilities
Accounts payable 4,631 5,942
Bank debt (note 6) 28,508 17,750
---------------------------------------------------------------------
33,139 23,692
Future income taxes 6,083 4,980
Asset retirement obligations (note 9) 3,001 2,226
---------------------------------------------------------------------
42,223 30,898
---------------------------------------------------------------------

Shareholders' equity
Share capital (note 7) 22,452 9,490
Contributed surplus 145 24
Retained earnings 7,757 5,073
---------------------------------------------------------------------
30,354 14,587
---------------------------------------------------------------------

Subsequent event (note 13)
72,577 45,485
---------------------------------------------------------------------
---------------------------------------------------------------------

(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,
----------------------------------------
2004 2003 2004 2003
(Restated (Restated
-note 3) -note 3)
------------------------------------------------------------------------
(thousands except $ $ $ $
per share data) (unaudited)

Revenue
Petroleum and natural gas sales 5,384 3,516 18,756 13,618
Royalties, net (992) (602) (3,226) (2,602)
------------------------------------------------------------------------
4,392 2,914 15,530 11,016
------------------------------------------------------------------------

Expenses
Operating 865 583 3,124 2,205
Transportation (note 3 (d)) 170 130 785 419
General and administrative 423 419 1,495 1,595
Restructuring charges
(note 4(a)) 1,115 - 1,115 -
Financial charges 113 159 765 507
Depletion, depreciation
and accretion (note 5 & 9) 1,749 678 4,423 2,129
------------------------------------------------------------------------
4,435 1,969 11,707 6,855
------------------------------------------------------------------------

Earnings (loss) before taxes (43) 945 3,823 4,161

Capital taxes 14 35 36 57
Future income taxes (note 10) - (211) 1,103 1,126
------------------------------------------------------------------------
14 (176) 1,139 1,183
------------------------------------------------------------------------

Net earnings (loss) (57) 1,121 2,684 2,978

Retained earnings,
beginning of period 7,820 3,809 5,220 2,099
Retroactive application of
change in accounting policy
(note 3 (b) & (c)) (6) 143 (147) (4)
------------------------------------------------------------------------

Retained earnings, end of year 7,757 5,073 7,757 5,073
------------------------------------------------------------------------
------------------------------------------------------------------------

Net earnings per share
Basic - 0.15 0.35 0.44
Diluted - 0.14 0.31 0.40


(See accompanying notes to the consolidated financial statements)



PRAIRIE SCHOONER PETROLEUM LTD.
CONSOLIDATED STATEMENT OF CASH FLOW

Three months ended Year ended
December 31, December 31,
----------------------------------------
2004 2003 2004 2003
(Restated (Restated
-note 3) -note 3)
------------------------------------------------------------------------
(thousands)
$ $ $ $
(unaudited)
Cash flow related to the
following activities

Operating
Net earnings (loss) for
the period (57) 1,121 2,684 2,978
Items not affecting cash:
Depletion, depreciation
and accretion 1,749 678 4,423 2,129
Future income taxes - (211) 1,103 1,126
Stock-based compensation 115 6 145 24
Risk management gain 62 - - -
Interest income (note 7d) - (45) - (45)
Asset retirement expenditures (10) (2) (11) (12)
------------------------------------------------------------------------

Funds from operations 1,859 1,547 8,344 6,200

Changes in non-cash
operating working capital (240) 72 (838) 286
------------------------------------------------------------------------
1,619 1,619 7,506 6,486
------------------------------------------------------------------------

Financing
Change in bank debt 9,141 2,050 10,758 15,750
Share issuance, net 12,872 28 12,938 74
------------------------------------------------------------------------
22,013 2,078 23,696 15,824
------------------------------------------------------------------------

Cash available for
investment activities 23,632 3,697 31,202 22,310
------------------------------------------------------------------------

Investing
Property and equipment
additions (23,937) (5,162) (31,247) (21,318)
Changes in non-cash
investing working capital 305 2,067 (406) (397)
------------------------------------------------------------------------
(23,632) (3,095) (31,653) (21,715)
------------------------------------------------------------------------

Change in cash - 602 (451) 595

Cash, beginning of period - (151) 451 (144)
------------------------------------------------------------------------

Cash, end of year - 451 - 451
------------------------------------------------------------------------
------------------------------------------------------------------------


(See accompanying notes to the consolidated financial statements)


PRAIRIE SCHOONER PETROLEUM LTD.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

YEAR ENDED DECEMBER 31, 2004

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

1. NATURE OF OPERATIONS

Prairie Schooner Petroleum Ltd. (formerly Piper Energy Inc.) ("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.

The shareholders of the Company approved a name change at the Special
Meeting held on December 20, 2004.

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) 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.

d) 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.

e) 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.

f) 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.

g) 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.

h) Per Share Amounts

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

i) Revenue Recognition

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

j) 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.

k) 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.

l) Comparative Numbers

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

3. CHANGE IN ACCOUNTING POLICY

a) Full Cost Accounting

Effective January 1, 2004, the Company adopted Accounting Guideline 16
"Oil and Gas Accounting - Full Cost", the new guideline issued by the
Canadian Institute of Chartered Accountants ("CICA") which replaces
Accounting Guideline 5, "Full Cost Accounting in the Oil & Gas Industry".

The Accounting Guideline 16 modifies how the ceiling test is performed
and is consistent with CICA Section 3063, "Impairment of Long- Lived
Assets". The new standards prescribe the recognition of impairment only
if the carrying amount of a long-lived asset is not recoverable from its
estimated undiscounted future cash flow. The impairment amount is the
difference between the carrying amount and the estimated fair value of
the asset. This approach incorporates risks and uncertainties in the
expected future cash flows, which are discounted using a risk free rate.
The adoption of Accounting Guideline 16 had no effect on the Company's
financial results.

b) Asset Retirement Obligation

Effective January 1, 2004, the Company adopted the recommendations of
CICA Handbook Section 3110, "Asset Retirement Obligations". This change
in accounting policy has been applied retroactively with restatement of
prior periods presented for comparative purposes.

The Company recognizes the fair value of its asset retirement obligation
("ARO") in the period in which it is incurred and when a reasonable
estimate of fair value can be made. The fair value of the estimated ARO
is recorded as a long-term liability, with a corresponding increase in
the carrying amount of the related asset. The capitalized amount is
depleted on a unit-of-production basis over the life of the reserves.
The liability amount is increased each reporting period due to the
passage of time and the amount of accretion is charged to earnings in
the period. Revisions to the estimated timing of cash flows or to the
original estimated undiscounted cost would also result in an increase or
decrease to the ARO. Actual costs incurred upon settlement of the ARO
are charged against the ARO to the extent of the liability recorded. Any
difference between the actual costs incurred upon settlement of the ARO
and the recorded liability is recognized as a gain or loss in the
Company's earnings in the period in which the settlement occurs.

Previously, the Company recognized a provision for site restoration and
abandonment costs calculated on the unit-of-production method over the
life of the petroleum and natural gas properties based on total
estimated proved reserves and the estimated future liability.

This change in accounting policy has been applied retroactively with
restatement of prior periods presented for comparative purposes as
follows:



Consolidated Balance Sheet as at December 31, 2003

As Reported Change As Restated
-------------------------------------
$ $ $

Assets
Property and equipment 39,384 1,793 41,177
Liabilities and shareholders' equity
Future site restoration 348 (348) -
Asset retirement obligations - 2,226 2,226
Future income taxes 4,942 38 4,980
Retained earnings 5,220 (123) 5,097(1)


Consolidated Statement of Operations and Retained Earnings for the year
ended December 31, 2003

As Reported Change As Restated
-------------------------------------
$ $ $


Depletion and depreciation 1,999 (23) 1,976
Accretion - 153 153
Future income taxes 1,137 (11) 1,126
Net earnings 3,120 (119) 3,001(1)

(1) See Note 3(c) for additional adjustment to Retained earnings
and Net earnings


There was no impact on the Company's cash flow as a result of adopting
this new policy. See note 9 for additional information on the asset
retirement obligation and the impact on the consolidated financial
statements.

c) Stock-based Compensation Plan

Effective January 1, 2004, the Company adopted the CICA Section 3870,
"Stock-Based Compensation and Other Stock-Based Payments", retroactively
with restatement of prior periods. The Company accounts for its
Stock-Based Compensation programs using the fair value method. Under
this method, compensation expense related to these programs is recorded
in the consolidated statement of operations over the vesting period with
a corresponding increase to contributed surplus. Upon exercise of the
stock options, consideration received together with the amount
previously recognized in the contributed surplus is recorded as an
increase to share capital.

The effect of adoption of the revised standard is a charge to
Stock-Based Compensation expense of $145 thousand for the year ended
December 31, 2004, with a corresponding increase to Contributed Surplus.
For the year ended December 31, 2003, the effect of the revised standard
is an increase of $24 thousand to Contributed Surplus with a
corresponding decrease to Retained Earnings.

d) Transportation Costs

Effective January 1, 2004, the Company adopted CICA Handbook Section
1100, "Generally Accepted Accounting Principles". In prior years, it had
been industry practice for companies to net transportation charges
against revenue rather than showing transportation as a separate expense
in the income statement. Beginning January 1, 2004, the Company has
recorded revenue gross of transportation charges with the offset
included in production expense on the income statement. Prior periods
have been reclassified for comparative purposes. This adjustment has no
impact on net income or cash flow.

4. ACQUISITIONS

a) 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.

b) Property Acquisition

On December 17, 2004, the Company completed an acquisition of producing
properties in Southern Alberta for a purchase price of $20.5 million
after adjustments. The acquisition provided the Company with 650 boe/d
(100% natural gas) of production, operatorship and a 100% working
interest in the infrastructure in the area. This acquisition was funded
through enhanced credit facilities.



5. PROPERTY AND EQUIPMENT

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


December 31, 2003
----------------------------------
Accumulated Net
Depletion & Book
Cost Depreciation Value
----------------------------------
$ $ $

Petroleum and Natural Gas properties 52,465 11,474 40,991
Office Equipment 396 210 186
------------------------------------------------------------------------
52,861 11,684 41,177
------------------------------------------------------------------------
------------------------------------------------------------------------


The Company has capitalized, as part of petroleum and natural gas
properties, indirect exploration overhead relating to property
acquisition, exploration and development activities of $38 thousand for
the year ended December 31, 2004 (2003 - nil).

At December 31, 2004, undeveloped land costs of $4.6 million (December
31, 2003 - nil) have been excluded from the amount subject to depletion
and depreciation.

The Company performed a ceiling test calculation as at December 31, 2004
to assess the recoverable value of the property and equipment. The oil
and gas future price is based on the January 1, 2005 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,
2004.



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


WTI Foreign Edmonton Company's AECO Company's
Oil Exchange Oil Price Gas Price
(US$/bbl) Rate (Cdn$/bbl) Oil ($/bbl) (Cdn$/mcf) Gas ($/mcf)
------------------------------------------------------------------------
2005 42.00 0.82 50.25 49.99 6.60 6.40
2006 40.00 0.82 47.75 47.36 6.35 6.11
2007 38.00 0.82 45.50 45.00 6.15 5.90
2008 36.00 0.82 43.25 42.66 6.00 5.74
2009 34.00 0.82 40.75 40.07 6.00 5.72
2010 33.00 0.82 39.50 38.74 6.00 5.72
2011 33.00 0.82 39.50 38.51 6.00 5.71
2012 33.00 0.82 39.50 34.90 6.00 5.70
2013 33.50 0.82 40.00 35.40 6.10 5.79
2014 34.00 0.82 40.75 36.15 6.20 5.89
2015 34.50 0.82 41.25 36.65 6.30 5.98

Annual escalation rate of 2.0% thereafter


6. BANK DEBT

2004 2003
-----------------------
$ $

Prime rate advances 5,008 7,750
Bankers' acceptances 23,500 10,000
------------------------------------------------------------------------
28,508 17,750
------------------------------------------------------------------------
------------------------------------------------------------------------


The Company has a demand revolving credit facility to a maximum of $35
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 $35
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 Amount
of Shares $
------------------------------------------------------------------------
Common Shares
Balance, December 31, 2002 6,770,942 9,461
Exercise of stock options 58,125 74
Interest accrued on shareholder loans - (45)
------------------------------------------------------------------------
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(a)) (e) 3,000,000 9,000
------------------------------------------------------------------------
Balance, December 31, 2004 10,411,567 22,452
------------------------------------------------------------------------
------------------------------------------------------------------------


c) Conversion

At the Company's Special Meeting on December 20, 2004 the shareholders
approved a resolution to convert all of the issued and un-issued class A
voting shares of the Company to common shares of the Company on a
one-for-one basis and to delete the class A voting shares. The table
above reflects the change on a retroactive basis.

d) Shareholder Loans

During 2002, the Company, with the approval of the Board of Directors,
granted loans in the amount of $1 million to members of the Management
to re-finance the cost of common voting shares of the Company which were
acquired by Management in prior years. Pursuant to the terms of the
agreements, the loans bear interest at the Company's cost of borrowing.
As part of the Merger Agreement described in note 4(a), these
shareholder loans were paid in full as of October 29, 2004.

e) 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. As at December 31, 2004,
the Company had incurred qualifying expenditures in the amount of nil.



f) Contributed Surplus
2004 2003
--------------------
$ $

Balance, beginning of year 24 -
Options granted 145 24
Options exercised (24) -
------------------------------------------------------------------------

Balance, end of year 145 24
------------------------------------------------------------------------
------------------------------------------------------------------------


g) 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.



2004 2003
--------------------

Weighted average shares outstanding (thousands)
Basic 7,538 6,791
Diluted 8,657 7,429


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, 2004,
1,119,000 (2003 - 637,500) options with exercise prices between $2.50
and $7.00 were outstanding.



The following tables summarize the information about the share options:

2004 2003
---------------------------------------
Weighted Weighted
average average
exercise exercise
Shares price Shares price
------------------------------------------------------------------------

Outstanding at beginning
of period 637,500 $4.84 627,500 $4.27
Granted 1,079,000 $5.53 85,625 $6.60
Exercised (582,500) $4.94 (58,125) $1.27
Cancelled (15,000) $5.10 (17,500) $4.86
------------------------------------------------------------------------

Outstanding at end of period 1,119,000 $5.46 637,500 $4.84
------------------------------------------------------------------------

Options exercisable at
period end 70,000 $4.81 41,565 $2.91
------------------------------------------------------------------------


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, 2004 life (years) price 31, 2004 price
------------------------------------------------ ----------------------

$2.50 - $5.50 25,000 0.2 $2.50 25,000 $2.50
$5.51 - $7.00 1,094,000 3.9 $5.61 45,000 $6.09
------------------------------------------------ ----------------------
1,119,000 $5.46 70,000 $4.81
------------------------------------------------ ----------------------
------------------------------------------------ ----------------------


The weighted average fair market value of options granted in the year
ended December 31, 2004 is $1.71 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:


2004 2003
----------------------
Risk-free interest rate (%) 4.50 4.50
Expected life (years) 4 5
Expected volatility (%) 30% nil
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 $3.0 million at December 31, 2004 based on
a total future liability of $10.2 million. Payments to settle asset
retirement obligations occur over the operating lives of the underlying
assets, estimated to be from zero to 25 years, with the majority of
costs incurred between 2011 and 2030. 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.



2004 2003
----------------------
Asset retirement obligations, beginning of period 2,226 1,672
Liabilities incurred during period 563 413
Liabilities settled during period (11) (12)
Accretion 223 153
----------------------
Asset retirement obligations, end of period 3,001 2,226
------------------------------------------------------------------------
------------------------------------------------------------------------


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:



2004 2003
----------------------
$ $

Earnings before taxes 3,823 4,161
------------------------------------------------------------------------

Statutory income tax rate 38.3% 40.8%

Expected income tax 1,464 1,698
Increase (decrease) resulting from:
Non-deductible crown charges 179 312
Resource allowance (481) (601)
Statutory rate adjustment (141) (313)
Stock-based compensation 56 -
Other 26 30
------------------------------------------------------------------------

Provision for taxes 1,103 1,126
------------------------------------------------------------------------
------------------------------------------------------------------------


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

2004 2003
----------------------
$ $

Property and equipment 4,417 2,854
Deferral of partnership income 2,572 2,220
Asset retirement obligation (1,003) (82)
Other 97 (12)
------------------------------------------------------------------------

Future income taxes 6,083 4,980
------------------------------------------------------------------------
------------------------------------------------------------------------


11. SUPPLEMENTAL CASH FLOW INFORMATION


Changes in non-cash working capital:
2004 2003
------------------------------------------------------------------------
$ $

Accounts receivable 334 (590)
Prepaid expenses (266) (254)
Accounts payable (1,312) 733
------------------------------------------------------------------------

Changes in non-cash working capital (1,244) (111)
------------------------------------------------------------------------
------------------------------------------------------------------------

These changes relate to the following activities:

Operating activities (838) 286
Investing activities (406) (397)
------------------------------------------------------------------------

(1,244) (111)
------------------------------------------------------------------------
------------------------------------------------------------------------


Amounts paid during the year relating to interest expense and capital
taxes are as follows:
2004 2003
------------------------------------------------------------------------
$ $

Interest paid in the year 765 507
Capital taxes paid in the year 21 40
------------------------------------------------------------------------

786 547
------------------------------------------------------------------------
------------------------------------------------------------------------


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, 2004 include gains of $392 thousand (2003 - $71 thousand)
on those transactions.



The following contracts were outstanding as at December 31, 2004:

Commodity Type Term Volume Price Index
------------------------------------------------------------------------
January 2005 $7.50 -
Natural gas Collar - March 2005 1,250 GJ's/d $11.50/GJ AECO
January 2005
Natural gas Fixed - March 2005 2,250 GJ's/d $8.06/GJ AECO
April 2005
Natural gas Fixed - October 2005 2,500 GJ's/d $6.83/GJ AECO


The estimated fair value at December 31, 2004 of these transactions, had
the contracts been settled at that time, would be a gain of $1.1 million.

13. SUBSEQUENT EVENT

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.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    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)