Paramount Resources Ltd.

Paramount Resources Ltd.

March 09, 2005 16:59 ET

Paramount Resources Ltd.: Financial and Operating Results for the Period Ended December 31, 2004


NEWS RELEASE TRANSMITTED BY CCNMatthews

FOR: PARAMOUNT RESOURCES LTD.

TSX SYMBOL: POU

MARCH 9, 2005 - 16:59 ET

Paramount Resources Ltd.: Financial and Operating
Results for the Period Ended December 31, 2004

CALGARY, ALBERTA--(CCNMatthews - March 9, 2005) - Paramount Resources
Ltd. (TSX:POU) ("Paramount" or the "Company") is pleased to announce its
financial and operating results for the year ended December 31, 2004.



2004 Financial Highlights
-------------------------
($ thousands Three Months Ended Year Ended
except per share December 31, December 31,
amounts and where % %
stated otherwise) 2004 2003 Change 2004 2003 Change
------------------------------------------------------------------------
FINANCIAL
Petroleum and
natural gas
sales, net of
transportation 165,844 86,068 93% 550,616 434,059 27%
Cash Flow(1)
From
operations 92,117 43,157 113% 295,566 167,276 77%
Per share
- basic 1.48 0.72 106% 4.95 2.78 78%
- diluted 1.43 0.72 99% 4.84 2.77 75%
Earnings
Net earnings
(loss) (17,753) 11,108 (260%) 41,174 1,151 3,477%
Per share
- basic (0.28) 0.18 (256%) 0.69 0.02 3,350%
- diluted (0.28) 0.18 (256%) 0.67 0.02 3,250%
------------------------------------------------------------------------
Capital
expenditures(2)
Exploration and
development 108,551 84,500 28% 316,284 223,753 41%
Acquisitions,
dispositions
and other(3) 37,480 (97,678) 138% 262,730 (368,731) 171%
Net capital
expenditures 146,031 (13,178) 1,208% 579,014 (144,978) 498%
------------------------------------------------------------------------
Total assets 1,542,786 1,177,130 31%
Net debt(4) 451,187 297,055 52%
Shareholders'
equity 625,039 496,033 26%
------------------------------------------------------------------------
Weighted average
common shares
outstanding
(thousands) 59,755 60,098 (1%)
Common shares
outstanding at
year end
(thousands) 63,186 60,095 5%
Common shares
outstanding at
March 8, 2005
(thousands) 63,899
------------------------------------------------------------------------
OPERATING
Production
Natural gas
(MMcf/d) 198 141 40% 173 153 13%
Crude oil and
liquids
(Bbl/d) 8,903 5,877 51% 7,297 7,169 2%
Total
Production
(Boe/d) @ 6:1 41,878 29,353 43% 36,150 32,630 11%
------------------------------------------------------------------------
Average Prices(5)
Natural gas
(pre-financial
instruments)
($/Mcf) 6.97 5.14 36% 6.72 5.99 12%
Natural gas
($/Mcf)(6) 7.54 5.39 40% 6.86 5.16 33%
Crude oil and
liquids (pre-
financial
instruments)
($/Bbl) 47.59 36.02 32% 46.80 38.27 22%
Crude oil and
liquids
($/Bbl)(6) 44.06 32.89 34% 44.13 35.50 24%
------------------------------------------------------------------------
Reserves (proved
and probable)
Natural gas
(Bcf) 568.6 329.4 73%
Crude oil and
liquids
(MBbl) 20,460 12,513 64%
Estimated present
value before
tax (discounted
@10% using
forecast prices
and costs)
Proved
($ millions) 1,156.0 597.4 94%
Proved and
probable
($ millions) 1,659.3 733.6 126%
------------------------------------------------------------------------
Land (thousands
of acres)
Total net land
holdings 4,081 3,386 21%
Net undeveloped
land holdings 3,441 2,800 23%
------------------------------------------------------------------------
Drilling
Activity (gross)
Gas 89 58 53% 229 180 27%
Oil 4 4 - 12 16 (25%)
Oilsands
evaluation (7) - - - 17 - 100%
D&A 1 5 (80%) 13 15 (13%)
Total wells 94 67 40% 271 211 28%
Success rate(7) 99% 93% 7% 95% 93% 2%
------------------------------------------------------------------------

(1) Cash flow from operations is a non-GAAP term that represents net
earnings adjusted for non-cash items, dry hole costs and geological
and geophysical costs. The Company considers cash flow from
operations a key measure as it demonstrates the Company's ability to
generate the cash necessary to fund future growth through capital
investment and to repay debt.
(2) Excludes capital expenditures of discontinued operations and other
minor accounting adjustments.
(3) 2003 disposition proceeds include the $51 million related to
Paramount Energy Trust units.
(4) Net debt is equal to long-term debt including working capital,
excluding discontinued operations.
(5) Average prices are net of transportation costs.
(6) Excludes non-cash gains and losses on financial instruments.
(7) Success rate excludes oilsands evaluation wells.


Significant Events

- REORGANIZATION

The Board of Directors unanimously approved a proposed reorganization
which would result in Paramount shareholders receiving units of a new
energy trust. A special meeting of securityholders to consider this
matter has been scheduled for Monday, March 28, 2005. The Information
Circular in respect of this meeting has been mailed to securityholders
and filed on SEDAR (www.sedar.com), and is available on the Paramount
website (www.paramountres.com). This proposed transaction (the "Trust
Spinout") is discussed in more detail in the Trilogy Energy Trust
section of this news release.

- DEBT EXCHANGE AND REDEMPTION

In the fourth quarter of 2004, Paramount commenced an exchange offer and
consent solicitation for its 7 7/8 percent Senior Notes due 2010 and 8
7/8 percent Senior Notes due 2014. This transaction was completed on
February 17, 2005 with the issuance of approximately $US 213.6 million
in principal amount of 8 1/2 percent Senior Notes due 2013 plus cash
consideration of approximately $US 36.2 million.

On December 30, 2004 Paramount redeemed US$41,744,000 aggregate
principal amount of its 7 7/8 percent senior notes due 2010 and
US$43,750,000 aggregate prinicipal amount of its 8 7/8 percent senior
notes due 2014. The amount that was redeemed represented approximately
29 percent of the US$300 million aggregate principal amount that was
outstanding.

- EQUITY ISSUANCE

In October 2004, Paramount completed a public offering of 2.5 million
common shares at $23.00 per share and a private placement of 2.0 million
"flow through" common shares at $29.50 per share. Aggregate gross
proceeds from these two offerings was $116.5 million.

- $87 MILLION ASSET ACQUISITION

On August 16, 2004, Paramount completed the acquisition of assets in the
Marten Creek area. The assets acquired were producing approximately 14
MMcf/d of natural gas with no liquids. Reserves attributable to the
properties as at July 1, 2004 were estimated to be 17.4 Bcf on a proved
basis and 22.2 Bcf on a proved plus probable basis.

- $185 MILLION ASSET ACQUISITION

On June 30, 2004, Paramount completed the acquisition of assets in the
Kaybob area of central Alberta and the Fort Liard area of the Northwest
Territories. The assets acquired were producing approximately 10,000
Boe/d (67 percent natural gas). Reserves attributable to the properties
as at June 1, 2004 were estimated to be 12.3 million Boe (64 percent
natural gas) on a proved basis and 22.2 million Boe (70 percent natural
gas) on a proved plus probable basis

On August 12, 2004, Paramount disposed of the Notikewan assets acquired
as part of this acquisition for approximately $20 million.

- ISSUANCE OF US $125 MILLION OF LONG-TERM SENIOR NOTES

On June 29, 2004, the Company issued US $125 million 8 7/8 percent
Senior Notes due 2014. Proceeds from the Senior Notes issuance were used
to partially finance the $185 million asset acquisition.

- DISPOSITION OF ASSETS

On July 27, 2004, Wilson Drilling Ltd., a private drilling company in
which Paramount owned a 50 percent equity interest, closed the sale of
its drilling assets for $32 million to a publicly traded Income Trust.
The gross proceeds were $19.2 million in cash with the balance in
exchangeable shares. The exchangeable shares can be exchanged for trust
units in the Income Trust.

Financial

Natural gas production averaged 173 MMcf/d in 2004, a 21 percent
increase over 2003 production of 143 MMcf/d after excluding the 2003
production related to the properties sold to Paramount Energy Trust. The
increase in production is primarily the result of the Company's capital
program and acquisitions made during the year. Paramount's average
natural gas sales price before financial instruments was $6.72/Mcf, a 12
percent increase compared to $5.99/Mcf in 2003, due to stronger natural
gas demand. Paramount's average natural gas price after financial
instruments was $6.86/Mcf as compared to $5.16/Mcf in 2003.

Oil and natural gas liquids ("NGLs") production averaged 7,297 Bbl/d in
2004, a two percent increase from 2003's average production of 7,169
Bbl/d. Paramount's average oil and NGLs sales price before financial
instruments was $46.80/Bbl in 2004 compared to $38.27/Bbl in 2003,
primarily due to stronger market prices. In addition, the Company's
average oil and NGLs price increased due to a change in product mix as a
result of NGLs and light oil properties acquired in 2004 replacing
medium grade oil producing properties disposed of in October 2003.

Paramount's 2004 production profile continues to be significantly
weighted to natural gas. In 2004 natural gas production contributed 80
percent of Paramount's total production compared to 78 percent in 2003.

Natural gas production volumes averaged 198 MMcf/d during the fourth
quarter of 2004, an increase of 40 percent from 141 MMcf/d for the
comparable quarter in 2003. The higher natural gas production is
primarily a result of the acquisitions. Oil and NGLs sales averaged
8,903 Bbl/d in the fourth quarter of 2004, an increase of 51 percent as
compared to 5,877 Bbl/d for the comparable quarter in 2003, primarily
due to increased NGLs production associated with assets acquired in the
Kaybob area.

Paramount's cash flow from operations for the year increased 77 percent
to $295.6 million from $167.3 million in 2003, as a result of higher
commodity prices and production levels.

Fourth-quarter cash flow totalled $92.1 million, an increase of 113
percent from $43.2 million during the same period in 2003. The increase
in cash flow is primarily a result of higher production levels and
higher commodity prices as compared to the fourth quarter of 2003.

The Company recorded net earnings of $41.2 million for the year ended
2004, as compared to net earnings of $1.2 million in 2003. The higher
earnings in 2004 are primarily due to an increase in petroleum and
natural gas sales resulting from higher production and commodity prices,
financial instrument gains as opposed to 2003 losses, and unrealized
foreign exchange gains on US debt. This was partially offset by higher
non-cash stock based compensation expense, depletion and depreciation
expense, and future income tax expense.

Core Producing Areas

Kaybob

The levels of drilling and completion activity continued to increase in
the Kaybob area throughout the year. At its peak during the fourth
quarter, five drilling rigs and eight service rigs were active.
Paramount participated in 26 (16.9 net) wells in the fourth quarter
bringing the 2004 total to 75 (52.2 net) wells for the year, resulting
in 66 (45.7 net) gas wells, 7 (6.2 net) oil wells and 2 (0.3 net) dry
holes. Capital expenditures in the Kaybob Operating Unit, including
facility additions and optimization projects, were $111 million, up from
$68 million in 2003. An additional $18.1 million was spent acquiring
Crown lands in 2004, adding additional opportunities to Paramount's
prospect inventory.

On June 30, 2004, Paramount completed the acquisition of additional
interests in the Kaybob area. This acquisition initially added 6,600
Boe/d of production and a large undeveloped land base principally in the
Deep Basin area west of the Kaybob core production area. These
undeveloped lands are complementary to Paramount's own land assets
resulting in a large prospect inventory for future drilling. As well, a
significant amount of seismic data was included in the transaction
providing Paramount with a competitive advantage for evaluating drilling
prospects, Crown land sales and farm-in opportunities.

Gas production in the Kaybob Operating Unit averaged 96 MMcf/d in 2004
up 20 percent from the 2003 average of 80 MMcf/d. Oil and natural gas
liquids production was 4,091 Bbl/d for 2004 up 67 percent from the 2003
average of 2,451 Bbl/d. Kaybob production averaged 15,701 Boe/d in 2003
and grew to 20,157 Boe/d in 2004. In spite of average production
declines of approximately 24 percent, we were able to increase
production through our capital spending program, as well as through the
acquisition. The properties acquired in the transaction averaged 6,130
Boe/d for the second half of 2004. Kaybob production for December 2004
averaged 108 MMcf/d and 5,600 Bbl/d of oil and natural gas liquids
(23,600 Boe/d).

Operating costs in the Kaybob area increased from a 2003 average of
$6.05/Bbl to $6.96/Bbl. This increase in operating costs is due in part
to higher per unit costs of the acquired properties. In addition, we
performed a number of workovers on the acquired properties in the fourth
quarter of 2004 and further workovers are planned in 2005. It is
anticipated that the operating costs will be reduced to approximately
$6.50/Bbl in 2005.

Proved plus probable reserve additions in the Kaybob Operating Unit were
51.5 Bcf and 1,254.6 MMBbl (9.8 MMBoe) which replaces 2004 production of
35.3 Bcf and 1.5 MMBbl (7.38 MMBoe). Costs of finding and development,
including future capital, for the proved plus probable reserve additions
for the Kaybob area were $6.37/Boe in 2004 which is down from $9.66/Boe
in 2003.

The proposed reorganization involves spinning off a portion of the
Kaybob Operating Unit assets into Trilogy Energy Trust. These assets
will be combined with the Marten Creek assets from the Grande Prairie
Operating Unit to form the basis of Trilogy Energy Trust. The
Paramount-operated producing assets and lands that will be moved from
the Kaybob Operating Unit to Trilogy are characterized by concentrated,
high working interest, liquids-rich gas. The lands are in an area that
can be characterized by multi-zone potential and a combination of
conventional oil and gas and tight gas reservoirs. Paramount feels that
a large portion of these lands can be further developed by drilling
additional wells into these known tight gas reservoirs. Paramount
believes that it can continue to develop these reserves using the
expertise that it has gained over the past ten years in this area, and
maintain both reserves and production rates for a number of years with
the existing prospect inventory.

Grande Prairie

The Grande Prairie Operating Unit grew significantly in 2004. The
Company drilled 57 (47.0 net) wells compared to 45 (29.9 net) wells
drilled in 2003. Of the total wells drilled in 2004, 21.4 net wells have
been tied in and are presently producing and 9.4 net gas wells have been
tested and are currently waiting to be tied in. Capital expenditures
totaled $58 million in 2004 as compared to $41 million in 2003.

Gas production in 2004 increased 108 percent to average 25 MMcf/d as
compared to 12 MMcf/d in 2003. The increase was the result of the Marten
Creek acquisition in August 2004 which added approximately 12 MMcf/d of
natural gas production and the significant gas production growth in the
Mirage area. Oil and NGLs production decreased 67 percent to average 585
Bbl/d in 2004 as compared to 1,767 Bbl/d in 2003 as a result of the
Sturgeon Lake property disposition in October of 2003. The 2004 year end
production exit rate was 40 MMcf/d of natural gas and 400 Bbl/d of oil
and NGLs. The 2004 production rates were lower than expected primarily
due to third-party infrastructure limitations and wet weather delaying
operations. The delays postponed the addition of approximately 5 to 6
MMcf/d of natural gas production to the first quarter of 2005.

In 2004, Marten Creek was the most significant growth area in the Grande
Prairie Operating Unit. The first seven wells of this new area were
brought on production in March 2004 with initial rates of 5 MMcf/d. A
facility expansion was completed in November 2004 to mitigate
third-party facility limitations resulting in an increase in production
to over 10 MMcf/d by year end. The acquisition in August added
production resulting in a field exit rate that was over 20 MMcf/d.
Paramount is planning to drill up to 12 wells in 2005, add a field
compressor, expand the gathering system and add two water disposal wells
to increase production. The Marten Creek project area will also be one
of the initial properties to comprise the assets of Trilogy Energy Trust.

The Mirage area was Grande Prairie's most active area with 28 (25.1 net)
wells drilled in 2004, two compressors installed and 44 sections of
gross land added. Proved plus probable reserve additions at Mirage for
2004 were 4 Bcf. Mirage's 2004 exit production rate was 14 MMcf/d of
natural gas and 250 Bbl/d of oil and NGLs. The drilling operations in
2004 were delayed two to four months by wet weather, which also delayed
a third-party gathering system expansion. The current standing wells are
expected to be tied in by the end of the first quarter of 2005 and will
initially produce approximately 6 MMcf/d. The growth in this field has
been the result of the ongoing development of the shallow Dunvegan
formation, as well as the success in new, slightly deeper formations.

Northwest Alberta / Cameron Hills, Northwest Territories

During the year, Paramount participated in the drilling of 22 (14.5 net)
wells of which only 1 (0.5 net) well was dry and abandoned. Due to
restricted seasonal access, the vast majority of field activities
related to seismic acquisition, drilling, and construction were
performed in the first quarter. Capital expenditures for the year
totaled $32.6 million which was evenly split between drilling and
facility expenditures.

For 2004, natural gas production averaged 20 MMcf/d of gas and 797 Bbl/d
of oil and NGLs, compared to 22 MMcf/d of natural gas and 448 Bbl/d of
oil and NGLs in 2003. Significant production increases were realized in
the Haro area with the drilling of 12 gas wells (7.5 net), and the
completion of the expansion in June of the existing natural gas
production capacity from 1.4 MMcf/d to 5.9 MMcf/d. This increase was
offset by declines at Cameron Hills and Bistcho.

The planned focus of activity in Northwest Alberta in 2005 will be in
the Bistcho-Zama-Larne area with potential participation in the drilling
of 19 gross (9.5 net), operated and non-operated gas wells. In the Haro
area, 6 (4 net) gas wells are expected to be drilled. The Company also
plans to conduct two seismic programs on new lands acquired in 2004.
Activity in Cameron Hills, NWT, will be limited as regulatory approvals
for new drilling has not been received.

Northwest Territories / Northeast British Columbia

Production from this operating area increased from 12 MMcf/d in 2003 to
16 MMcf/d in 2004. The increase was a result of both drilling activity
and the acquisition of additional working interests in three of the four
producing properties. A total of 18 (9.4 net) wells were drilled during
2004, and two separate property transactions were closed during the year.

Development activity was focused on the West Liard field with the
drilling of 3K-29 and 2M-25 along with a workover on the shut-in well at
M-25. Both 2M-25 and M-25 were brought on production during the fourth
quarter. Paramount's working interest in this field increased from 3
percent to 67 percent as a result of the 2004 acquisitions. Also
included in the asset acquisitions was the remaining 50 percent interest
in the Tattoo and Maxhamish production facilities.

Exploratory drilling continued at Colville Lake, NWT, where three wells
were drilled with encouraging results. Two of these wells at K-14 and
C-34 tested potential new pools while the third well at B-23 was drilled
to delineate the Nogha discovery. Paramount will continue its
exploration efforts in the Colville Lake area with the drilling of five
wells this winter and further completion and testing of existing wells.

Delineation and tie in of new discoveries in Northeast British Columbia
should add between 2-5 MMcf/d in the first quarter of 2005. Six wells
were also drilled on various exploratory prospects in Northeast British
Columbia with two of these encountering potential new pools that require
further delineation, while a third discovery is slated to be on
production in 2005. The upcoming winter program will include drilling
and workover activity to maximize value from the higher working
interests in the existing production facilities.
Southern

The Southern Operating Unit encompasses three different regulatory
jurisdictions, southern Alberta, northern Montana and the southwest of
North Dakota.

The Company drilled 82 (40.8 net) wells in 2004 as compared to 20 (14.6
net) in 2003. The average production for the year was 11 MMcf/d of gas,
with 1,798 Bbl/d of oil and NGLs as compared to 10 MMcf/d of gas and
2,459 Bbl/d of oil and NGLs in 2003. In the fourth quarter of 2004, the
Southern Operating Unit produced 11 MMcf/d of gas, and 1,600 Bbl/d of
oil and NGLs. This was the most active quarter with 52 (21.8 net) wells
drilled. Most of the activity was in the Chain region where 18 (14.6
net) coal bed methane ("CBM") wells and 5 (4.0 net) Belly River wells
were drilled.

In the third quarter of 2004, Paramount divested all its operated
properties in southeast Saskatchewan (for a gain of $14 million) to
further focus the operations in the Southern Operating Unit core areas.
The primary core areas of production are the gas-producing
Chain/Craigmyle field and the oil producing area of the Williston Basin
in the United States.

The Chain region has seen a revival over the last two years and has
doubled production from 3 MMcf/d to 6.2 MMcf/d. The 18 CBM wells were
all successful and will form the base for a multiyear development
program of the Horseshoe Canyon CBM play. These wells are drilled to a
depth of 350 meters and produce natural gas at average rates of over 100
Mcf/d with no associated water production. The continuing Belly River
drilling program has been very successful and has enabled existing
infrastructure to operate at capacity. A re-evaluation of our facilities
has shown the need for a new parallel low pressure production system on
which we will start construction in the second quarter of 2005. The
Chain region will be the focus of most of our activity in 2005 with 98
wells planned which consist of 88 CBM wells, eight wells for Belly River
targets and two for Mannville targets.

The North Dakota area is presently producing 564 Boe/d and will be the
second area of focus for the Southern Operating Unit. Paramount will be
drilling six wells for deep oil in the Knutson and Beavercreek Fields.

Heavy Oil

During 2004 Paramount Resources increased its oil sands acreage by 70
percent with the acquisition of 51,000 acres of oil sands rights for a
total cost of $2.7 million. The Company's total oil sands acreage is
approximately 120,000 acres and is located mainly in the Leismer and
Surmont areas of northeast Alberta. During 2004 Paramount drilled 17 Oil
Sands Evaluation (OSE) wells. The encouraging results of these wells are
being followed-up with a 15 to 20 well OSE program in early 2005. The
Company is optimistic that the results of the oil sands evaluation
program will allow it to bring forward a 3,000 Bbl/d SAGD pilot
application in 2005.

Gas Re-injection and Production Experiment

Paramount made a significant step towards a technical solution to the
Gas over Bitumen issue with the approval of the Gas Re-Injection and
Production Experiment to be conducted in the Surmont area of northeast
Alberta. This pilot project involves the collection and re-injection of
up to 3 MMcf/d of compressor exhaust gases, maintaining pressure,
allowing a similar volume of natural gas production from previously
shut-in gas pools. The experiment also enables the sequestration of up
to 400 Mcf/d of carbon dioxide. This experimental pilot project is
expected to start up in the second quarter of 2005. If successful,
Paramount is hopeful that this experiment will offer some resolution at
Surmont to the Gas over Bitumen issue as well as provide for
sequestration opportunities for carbon dioxide.

Reserves

Paramount's reserves for the year ended December 31, 2004, were
evaluated by McDaniel and Associates Consultants Ltd. ("McDaniel") who
have evaluated Paramount's reserves for the entire 25-year existence of
the Company, and by Paddock Lindstrom and Associates Ltd. ("Paddock
Lindstrom"). As defined by National Instrument ("NI") 51-101 proved
reserves are defined as having a 90 percent probability that these
reserves will be recovered and probable reserves are defined as having
at a 50 percent probability that these reserves will be recovered.

The following table summarizes the reserves evaluated as at December 31,
2004, using McDaniel's and Paddock Lindstrom's forecast prices and costs.



Gross Proved and Before Tax Net
Probable Reserves Present Value
------------------------------- ------------------------
Light ($ millions)
and
Medium Natural
Natural Crude Gas
Reserve Category Gas Oil Liquids Boe Discount Rate
(Bcf) (MBbl) (MBbl) (MBoe) 0% 5% 10%
Canada
Proved
Developed
Producing 254.5 5,615 5,552 53,592 1,266.6 1,063.9 929.5
Developed
Non-Producing 52.4 667 501 9,898 205.7 166.1 140.8
Undeveloped 39.9 308 289 7,251 142.8 91.2 64.0
------------------------------------------------------------------------
Total Proved 346.9 6,590 6,342 70,741 1,615.2 1,321.3 1,134.3
Probable 221.3 2,901 2,087 41,882 950.6 663.5 500.7
------------------------------------------------------------------------
Total Proved Plus
Probable Canada 568.2 9,492 8,430 112,622 2,565.8 1,984.7 1,635.0
------------------------------------------------------------------------
United States
Proved
Developed
Producing 0.4 2,108 - 2,169 29.8 25.3 21.9
Developed
Non-Producing - - - - (0.4) (0.3) (0.3)
Undeveloped - - - - - - -
------------------------------------------------------------------------
Total Proved 0.4 2,108 - 2,169 29.5 25.0 21.6
Probable - 431 - 437 6.0 3.9 2.7
------------------------------------------------------------------------
Total Proved Plus
Probable US 0.4 2,539 - 2,606 35.5 28.8 24.3
------------------------------------------------------------------------
Total Company
Total Proved 347.2 8,698 6,342 72,910 1,644.7 1,346.2 1,156.0
Total Probable 221.4 3,332 2,087 42,319 956.6 667.4 503.4
------------------------------------------------------------------------
Total Reserves 568.6 12,031 8,430 115,230 2,601.3 2,013.6 1,659.3
------------------------------------------------------------------------
------------------------------------------------------------------------
(Columns may not add due to rounding)

Reserve Reconciliation for Year-end 2004

The following table sets forth the reconciliation of Paramount's gross
reserves for the year ended December 31, 2004, as evaluated by McDaniel
and Paddock Lindstrom using forecast prices and costs. Gross reserves
include working interest reserves before royalties.

Reserves (Company share before royalty)

Proved Reserves Probable Reserves
Oil Oil
Gas & NGL Boe Gas & NGL Boe
Bcf MBbl MBoe Bcf MBbl Mboe
------------------------------------------------------------------------
Total Reserves
Jan 1, 2004 241.7 10,617 50,900 87.7 1,896 16,513
------------------------------------------------------------------------
Total 2004 Divestments (0.2) (1,021) (1,042) - (176) (176)
Total 2004 Acquisitions 63.1 5,426 15,951 51.6 1,505 10,108
2004 Capital Program
Additions 83.3 1,624 15,510 64.9 1,532 12,346
Total 2004 Production (63.4) (2,671) (13,231) - - -
Technical Revisions(1) 22.6 1,066 4,830 17.2 662 3,525
------------------------------------------------------------------------
Total Reserves
Jan 1, 2005 347.2 15,041 72,910 221.4 5,420 42,319
------------------------------------------------------------------------

Proved + Probable Reserves
Oil
Gas & NGL Boe
Bcf MBbl Mboe
------------------------------------------------------------------------
Total Reserves Jan 1, 2004 329.4 12,513 67,413
------------------------------------------------------------------------
Total 2004 Divestments (1) (0.2) (1,196) (1,224)
Total 2004 Acquisitions (1) 114.8 6,931 26,059
2004 Capital Program Additions (1) 148.2 3,156 27,856
Total 2004 Production (63.4) (2,671) (13,231)
Technical Revisions(1) 39.8 1,727 8,355
------------------------------------------------------------------------
Total Reserves Jan. 1, 2005 568.6 20,460 115,230
------------------------------------------------------------------------
(Columns may not add due to rounding)

(1) Paramount estimates


Finding and Development Costs

Paramount has calculated the capital associated with the 2004 reserve
additions and as such has excluded certain capital expenditures. The
calculation excluded the $37.6 million of expenditures from the finding
and development cost calculation associated with the exploration at
Colville Lake and the Bitumen evaluation. This capital will be included
in the finding and development calculation during the year in which
reserves are first booked for Colville Lake and Bitumen by the Company.
In addition, capital was reduced by $45.1 million to reflect the net
increase in the value of our undeveloped acreage inventory. Future
capital of $36.2 million to fully develop the booked proved reserves,
and $103.2 million to fully develop the proved and probable reserves
were included in the finding and development calculation. Paramount's
finding and development costs were $13.57/Boe on a proved reserves and
$9.48/Boe for proved plus probable reserves. Finding and development
costs for 2003 were $18.93 on a proved basis and $15.73 on a proved plus
probable basis.

Trilogy Energy Trust

The Company has announced that a special meeting of securityholders to
consider its previously announced trust spinout transaction is scheduled
to be held on Monday, March 28, 2005. The Trust Spinout is to be
effected through an arrangement under the Business Corporations Act
(Alberta). The transaction is subject to approval by the shareholders
and optionholders of Paramount, the Court of Queen's Bench of Alberta
and regulatory authorities.

At the meeting, holders of Paramount common shares and options will be
asked to approve the Trust Spinout which would result in Paramount
shareholders receiving units of a new energy trust, to be known as
Trilogy Energy Trust ("Trilogy"). Upon completion of the Trust Spinout,
Paramount shareholders will own 100 percent of post-reorganization
Paramount and 81 percent of the outstanding units of Trilogy. Paramount
will own the remaining 19 percent of the outstanding units of Trilogy.
Shareholders will receive one trust unit for each existing common share.
Based on the number of Paramount shares outstanding on February 25,
2005, there are expected to be approximately 63.9 million common shares
of Paramount and 78.9 million units of Trilogy outstanding upon
completion of the Trust Spinout.

Trilogy will indirectly own certain of Paramount's existing assets with
current production of approximately 25,000 Boe/d (80 percent natural
gas). These assets, in the Kaybob and Marten Creek areas of Alberta, are
primarily low-risk, high working interest, lower decline properties that
are geographically concentrated with numerous infill drilling
opportunities and good access to infrastructure and processing
facilities to be operated and controlled by Trilogy. The balance of
Paramount's assets, consisting of its predominantly growth-oriented
assets, will remain with Paramount. Current production from these assets
is approximately 20,000 Boe/d (75 percent natural gas). Through
Paramount, shareholders will participate in the potential upside of its
remaining predominantly growth-oriented assets. Through Trilogy,
unitholders will receive regular distributions of cash derived from the
cash flow produced by Trilogy's low-risk development assets. Due to
Trilogy's extensive development drilling portfolio, it is anticipated
that Trilogy will retain approximately 35 percent of its cash flow for
capital expenditures with the remaining 65 percent of its cash flow
being distributed to unitholders in monthly distributions. This
extensive development drilling portfolio is expected to make Trilogy
less reliant on the competitive acquisition market for developed assets
to maintain and grow distributions. Paramount believes that the Trust
Spinout will enhance value for shareholders by dividing Paramount's
assets into two specific groups, consisting of (i) the higher free cash
flow Kaybob and Marten Creek assets which will be owned through Trilogy,
and (ii) the predominantly growth oriented assets that will continue to
be owned by Paramount. The Trust Spinout will allow shareholders to
participate either separately or on a combined basis in the growth
potential and low-risk development qualities of Paramount's assets.
Paramount believes that the post-transaction structure better aligns
risks and returns from each asset class in a way that is both
sustainable and tax effective. If the necessary securityholder and court
approvals are obtained and other conditions are satisfied, the Trust
Spinout is expected to be completed on or about April 1, 2005.

Outlook

Paramount has budgeted a total of $340 million for capital expenditures
for 2005; of this, $100 million is to be directed to the Trilogy assets
and the remaining $240 million will be directed to the properties
retained by Paramount Resources Ltd. This capital program is intended to
entirely replace both production and reserves in Trilogy which is
forecasted to produce 120 MMcf/d and 5,000 Bbl/d or 25,000 Boe/d.
Paramount's capital program is designed to grow production to 25,000
Boe/d by the end of the year. Total cash flow in 2005 is estimated to be
approximately $425 million or approximately $6.66/share. We look forward
to delivering further value to Paramount shareholders with the creation
of the income generating Trilogy Energy Trust, as well as a continued
growth oriented investment in Paramount Resources which will continue to
add value through its short and medium term drilling opportunities as
well as the longer term projects the company continues to work on such
as Colville Lake in the Northwest Territories and Bitumen development
projects in northeast Alberta.

Advisory Regarding Reserves Data and Other Oil and Gas Information

Unless otherwise indicated, all reserves information in this news
release represents gross reserves based on forecast prices and costs.

In this news release, certain natural gas volumes have been converted to
Boe on the basis of six thousand cubic feet (Mcf) to one barrel (Bbl).
Boe may be misleading, particularly if used in isolation. A Boe
conversion ration of 6 Mcf:1 Bbl is based on an energy equivalency
conversion method primarily applicable at the burner tip and does not
represent equivalency at the well head.

Finding and development costs were calculated for each year shown by
dividing exploration and development costs plus changes in estimated
future development costs less the increase in value of undeveloped land
and capital associated with long term development projects by reserve
additions for the year. The increase in value of undeveloped land and
capital associated with long term development projects was excluded from
the numerator as these items are not associated with reserve additions
for the year. The 2003 figures do not include technical revisions, a
significant portion of which were associated with the adoption of
National Instrument 51-101 in September 2003. The aggregate of the
exploration and development costs incurred in 2004 and the change during
that year in estimated future development costs generally will not
reflect total finding and development costs related to reserve additions
for that year.

Advisory Regarding Forward-Looking Statements

This news release contains forward-looking statements within the meaning
of applicable securities laws. Forward-looking statements include
estimates, plans, expectations, opinions, forecasts, projections,
guidance or other statements that are not statements of fact. The
forward-looking statements in this news release include statements with
respect to future production, capital expenditures, drilling, operating
costs, cash flow, and the magnitude of oil and natural gas reserves.
Although the Company believes that the expectations reflected in such
forward-looking statements are reasonable, undue reliance should not be
placed on them because we can give no assurance that such expectations
will prove to have been correct. Factors that could cause actual results
to differ materially from those set forward in the forward looking
statements include general economic business and market conditions,
fluctuations in interest rates, production estimates, our future costs,
future crude oil and natural gas prices, and our reserve estimates. The
Company's forward-looking statements are expressly qualified in their
entirety by this cautionary statement. We undertake no obligation to
update our forward-looking statements except as required by law.

A conference call will be held with the senior management of Paramount
Resources Ltd. to answer questions with respect to the year-end results
at 8:30 a.m. MST on Thursday, March 10, 2005. To participate please call
1-866-902-2211 or 1-416-695-5261 approximately 15 minutes before the
call is to begin.

The conference call will be live webcast from www.paramountres.com.

A replay of the conference call will be available within an hour of the
call for seven days: until March 17, 2005. The number for the replay is
1-888-509-0082 or 1-416-695-5275.

The conference call will be available for replay on the Company website,
www.paramountres.com within two hours of the webcast.

Paramount is a Canadian oil and natural gas exploration, development and
production company with operations focused in Western Canada.
Paramount's common shares are listed on the Toronto Stock Exchange under
the symbol "POU".

MANAGEMENT'S DISCUSSION AND ANALYSIS ("MD & A")

Paramount Resources Ltd. ("Paramount" or the "Company") is pleased to
report its financial and operating results for the year ended December
31, 2004.

The following discussion of financial position and results of operations
should be read in conjunction with the consolidated financial statements
and related notes for the year ended December 31, 2004. The consolidated
financial statements have been prepared in Canadian dollars and in
accordance with Canadian generally accepted accounting principles
("GAAP"). A reconciliation to United States GAAP is included in Note 17
to the consolidated financial statements.

This MD&A contains forward-looking statements within the meaning of
applicable securities laws. Forward-looking statements include
estimates, plans, expectations, opinions, forecasts, projections,
guidance or other statements that are not statements of fact. The
forward-looking statements in this MD&A include statements with respect
to, among other things: Paramount's business strategy, Paramount's
intent to control marketing and transportation activities, the weighting
of Paramount's production toward natural gas, reserve estimates,
production estimates, financial instrument policies, asset retirement
obligations, the size of available income tax pools, the renewal of the
Company's credit facility, the funding sources for the Company's capital
expenditure program, cash flow estimates, environmental risks faced by
the Company and compliance with environmental regulations, commodity
prices, and the impact of the adoption of various Canadian Institute of
Chartered Accountants Handbook Sections and Accounting Guidelines.

Although Paramount believes that the expectations reflected in such
forward-looking statements are reasonable, undue reliance should not be
placed on them because the Company can give no assurance that such
expectations will prove to have been correct. There are many factors
that could cause forward-looking statements not to be correct, including
known and unknown risks and uncertainties inherent in the Company's
business. These risks include, but are not limited to: crude oil and
natural gas price volatility, exchange rate and interest rate
fluctuations, availability of services and supplies, market competition,
uncertainties in the estimates of reserves, the timing of development
expenditures, production levels and the timing of achieving such levels,
the Company's ability to replace and expand oil and gas reserves, the
sources and adequacy of funding for capital investments, future growth
prospects and current and expected financial requirements of the
Company, the cost of future asset retirement obligations, the Company's
ability to enter into or renew leases, the Company's ability to secure
adequate product transportation, changes in environmental and other
regulations, the Company's ability to extend its debt on an ongoing
basis, and general economic conditions. The Company's forward-looking
statements are expressly qualified in their entirety by this cautionary
statement. We undertake no obligation to update our forward-looking
statements except as required by law.

Included in this MD&A are references to financial measures such as cash
flow from operations ("cash flow") and cash flow per share. While widely
used in the oil and gas industry, these financial measures have no
standardized meaning and are not defined by Canadian generally accepted
accounting principles ("GAAP"). Consequently, these are referred to as
non-GAAP financial measures. Cash flow appears as a separate caption on
the Company's consolidated statement of cash flows and is reconciled to
net earnings. Paramount considers cash flow a key measure as it
demonstrates the Company's ability to generate the cash necessary to
fund future growth through capital investment and to repay debt. Cash
flow should not be considered an alternative to, or more meaningful
than, net earnings as determined in accordance with GAAP, as an
indicator of the Company's performance.

In this MD&A, certain natural gas volumes have been converted to barrels
of oil equivalent (Boe) on the basis of six thousand cubic feet (Mcf) to
one barrel (Bbl). Boe may be misleading, particularly if used in
isolation. A Boe conversion ratio of 6 Mcf equals 1 Bbl is based on an
energy equivalency conversion method, primarily applicable at the burner
tip and does not represent equivalency at the well head.

Early in 2003, the Company disposed of a significant number of assets to
Paramount Energy Trust. The net book value of the assets amounted to
$244.4 million (17 percent) of total assets as of December 31, 2002,
94.8 Mcf/d (39 percent) of total natural gas production, and 15,807
Boe/d (34 percent) of total production. As such, the 2002 comparative
figures shown in this MD&A report contains the results of these assets
and should be read and interpreted with this understanding.

The date of this MD&A is March 9, 2005.

Additional information on the Company, including the Annual Information
Form, can be found on the SEDAR website at www.sedar.com.

Paramount Resources Ltd. (Paramount" or the "Company") is an independent
Canadian energy company involved in the exploration, development,
production, processing, transportation and marketing of natural gas and
oil. The Company's principal properties are located in Alberta, the
Northwest Territories and British Columbia in Canada. The Company also
has properties in Saskatchewan and offshore the East Coast in Canada,
and in Montana and North Dakota in the United States. Management's
strategy is to maintain a balanced portfolio of opportunities, to grow
reserves and production in the Company's core areas while maintaining a
large inventory of undeveloped acreage, to focus on natural gas as a
commodity, and to selectively enter into joint venture agreements for
high risk/high return prospects.

Significant Events

REORGANIZATION

On December 13, 2004 Paramount announced that its Board of Directors had
unanimously approved a proposed reorganization which would result in
Paramount's shareholders receiving units of a new energy trust (the
"Trust", now named Trilogy Energy Trust) which will indirectly own
existing properties of Paramount with current production of
approximately 25,000 Boe/d (the "Trust Spinout"). Under the Trust
Spinout, Paramount's shareholders will continue to be shareholders of
Paramount, which will continue to operate as it has in the past.

The Company has also announced that a special meeting of security
holders to consider its previously announced trust spinout transaction
is scheduled to be held on Monday, March 28, 2005. The Trust Spinout is
expected to be effected through an arrangement under the Business
Corporations Act (Alberta). The transaction is subject to approval by
the shareholders and option holders of Paramount, the Court of Queen's
Bench of Alberta and regulatory authorities.

At the meeting, holders of Paramount common shares and options will be
asked to approve the Trust Spinout which would result in Paramount
shareholders receiving units of a new energy trust, to be known as
Trilogy Energy Trust ("Trilogy"). Upon completion of the Trust Spinout,
Paramount shareholders will own 100 percent of post-reorganization
Paramount and 81 percent of the outstanding units of Trilogy. Paramount
will own the remaining 19 percent of the outstanding units of Trilogy.
Shareholders will receive one trust unit for each existing common share.
Based on the number of Paramount shares outstanding on February 25,
2005, there are expected to be approximately 63.9 million common shares
of Paramount and 78.9 million units of Trilogy outstanding upon
completion of the Trust Spinout.

Trilogy will, subject to approval, indirectly own certain of Paramount's
existing assets with current production of approximately 25,000 Boe/d
(80 percent natural gas). These assets, in the Kaybob and Marten Creek
areas of Alberta, are primarily low-risk, high working interest
properties that are geographically concentrated with numerous infill
drilling opportunities and good access to infrastructure and processing
facilities to be operated and controlled by Trilogy. The balance of
Paramount's assets, consisting of its predominantly growth-oriented
assets, will remain with Paramount. Current production from these assets
is approximately 20,000 Boe/d (75 percent natural gas). Through
Paramount, shareholders will participate in the potential upside of its
remaining predominantly growth-oriented assets. Through Trilogy,
unitholders will receive regular distributions of cash derived from the
cash flow produced by Trilogy's low-risk development assets.

Due to Trilogy's extensive development drilling portfolio, it is
anticipated that Trilogy will retain approximately 35 percent of its
cash flow for capital expenditures with the remaining 65 percent of its
cash flow being distributed to unitholders in monthly distributions.
This extensive development drilling portfolio is expected to make
Trilogy less reliant on the competitive acquisition market for developed
assets to maintain and grow distributions. Paramount believes that the
Trust Spinout will enhance value for shareholders by dividing
Paramount's assets into two specific groups, consisting of (i) the
higher free cash flow Kaybob and Marten Creek assets which will be owned
through Trilogy, and (ii) the predominantly growth oriented assets that
will continue to be owned by Paramount. The Trust Spinout will allow
shareholders to participate either separately or on a combined basis in
the growth potential and low-risk development qualities of Paramount's
assets.

Paramount believes that the post-transaction structure better aligns
risks and returns from each asset class in a way that is both
sustainable and tax effective. If the necessary securityholder and court
approvals are obtained and other conditions are satisfied, the Trust
Spinout is expected to be completed on or about April 1, 2005.

NOTE REDEMPTION

On December 30, 2004 the Company redeemed approximately US$41.7 million
of the 7 7/8 percent senior notes due 2010 and US$43.7 million of the 8
7/8 percent notes due 2014. The indentures governing the notes permit
the Company to redeem up to 35 percent of the aggregate principal amount
of each series of notes outstanding. The redemptions were made pursuant
to the rights offering arising from the Company's October equity
offerings.

NOTE EXCHANGE

On December 17, 2004, Paramount commenced the exchange offer and consent
solicitation for its 7 7/8 percent Senior Notes due 2010 (the "2010
Notes") and 8 7/8 percent Senior Notes due 2014 (the "2014 Notes"). On
February 7, 2005, the Company completed the notes offer by issuing US
$213.6 million principal amount of 2013 notes and paying aggregate cash
consideration of approximately US $36.2 million in exchange for
approximately 99.31 percent of the 2010 notes and 100 percent of the
2014 notes. The 2013 notes bear interest at a rate of 8 1/2 percent per
annum and mature January 31, 2013. The notes are secured by
approximately 80 percent of the Trust units that will be owned by
Paramount following completion of the Trust Spinout (see Reorganization
Announcement above).

EQUITY ISSUANCE

On October 26, 2004, Paramount completed its public offering of
2,500,000 common shares (including 500,000 common shares issued
following the exercise in full of the underwriters' option) at a price
of $23.00 per share for gross proceeds of $57.5 million.

On October 15, 2004, Paramount completed the private placement of
2,000,000 common shares issued on a "flow-through" basis at $29.50 per
share. The gross proceeds of the issue were $59 million.

DISPOSITION OF ASSETS

On July 27, 2004, Wilson Drilling Ltd. ("Wilson"), a private drilling
company in which Paramount owns a 50 percent equity interest, closed the
sale of its drilling assets for $32 million to a publicly traded Income
Trust. The gross proceeds were $19.2 million in cash with the balance in
exchangeable shares. The exchangeable shares can be redeemed for trust
units in the Income Trust, subject to customary securities laws and
regulations. In connection with the closing of the sale, certain
indebtedness related to these operations has been extinguished.

$87 MILLION ASSET ACQUISITION

On August 16, 2004, Paramount completed the acquisition of assets in the
Marten Creek area in Grande Prairie for $86.9 million, after
adjustments. The assets acquired were producing approximately 14 MMcf/d
of natural gas, or 2,300 Boe/d. The reserves attributable to the
properties as of July 1, 2004, as estimated by McDaniel and Associates,
consist of proved reserves of approximately 17.4 Bcf of natural gas, or
2.9 million Boe; proved plus probable reserves of approximately 22.2 Bcf
or 3.7 million Boe. The asset retirement associated with these assets is
$2.1 million. In accounting for this acquisition, the Company recorded a
future tax asset in the amount of $89.0 million.

$185 MILLION ASSET ACQUISITION

On June 30, 2004, Paramount completed the acquisition of assets in the
Kaybob area of central Alberta and the Fort Liard area of the Northwest
Territories for $185.1 million, after adjustments. The properties
acquired were producing approximately 10,000 Boe/d, comprised of 40
MMcf/d of natural gas and 3,300 Bbl/d of oil and natural gas liquids
("NGLs"). The reserves attributable to the properties as of June 1, 2004
were estimated by Paramount to consist of proved reserves of
approximately 47.2 Bcf of natural gas and 4.4 million Bbl of oil and
NGLs, or a total of 12.3 million Boe; proved plus probable reserves of
approximately 93.6 Bcf of natural gas and 6.7 million Bbl of oil and
NGLs, or a total of 22.2 million Boe.

On August 12, 2004, Paramount disposed of the Notikewan assets acquired
in the $185 million asset acquisition for approximately $20 million. No
gain or loss was recorded on the transaction.

ISSUANCE OF US $125 MILLION OF LONG-TERM SENIOR NOTES

On June 29, 2004, the Company issued US $125 million 8 7/8 percent
Senior Notes due 2014. Proceeds from the Senior Notes issuance were used
to partially finance the $185 million asset acquisition. Interest on the
notes is payable semi-annually, beginning in 2005. The Company may
redeem some or all of the notes at any time after July 15, 2009, at
redemption prices ranging from 100 percent to 104.438 percent of the
principal amount, plus accrued and unpaid interest to the redemption
date, depending on the year in which the notes are redeemed. In
addition, the Company may redeem up to 35 percent of the notes prior to
July 15, 2007 at 108.875 percent of the principal amount, plus accrued
interest to the redemption date, using the proceeds of certain equity
offerings. The notes are unsecured and rank equally with all the
Company's existing and future senior unsecured indebtedness. The
financing charges related to the issuance of the senior notes are
capitalized to other assets and amortized evenly over the term of the
notes.

Revenue & Production



Revenue (thousands of dollars) 2004 2003 2002
--------------------------------------------------------------------
Natural gas, net of
transportation $ 425,626 $ 333,924 $ 311,438
Oil and natural gas liquids,
net of transportation 124,990 100,135 72,750
--------------------------------------------------------------------
Petroleum and natural gas
revenue 550,616 434,059 384,188
Realized financial
instrument gain (loss) (683) (53,204) 46,813
Unrealized financial
instrument gain 19,376 - -
Gain (loss) on investments (34) (1,020) 40,830
--------------------------------------------------------------------
Gross revenue $ 569,275 $ 379,835 $ 471,831
--------------------------------------------------------------------
--------------------------------------------------------------------


Petroleum and natural gas revenue totaled $550.6 million in 2004, as
compared to $434.1 million in 2003 (2002 - $384.2 million). The increase
in revenue is due to increased production and higher commodity prices.
Stronger natural gas demand resulted in an increase of 12 percent in
Paramount's average natural gas sales price before financial instruments
to $6.72/Mcf as compared to $5.99/Mcf in 2003 (2002 - $3.53/Mcf). The
Company's average natural gas price after financial instruments was
$6.86/Mcf as compared to $5.16/Mcf in 2003 (2002 - $4.08/Mcf). Natural
gas production volumes averaged 173 MMcf/d in 2004, a 13 percent
increase from the 153 MMcf/d produced in 2003 (2002 - 241 MMcf/d),
primarily as a result of acquisitions made during the year.

Oil and natural gas liquids ("NGLs") production averaged 7,297 Bbl/d in
2004, a two percent increase from 2003's average production of 7,169
Bbl/d. Paramount's average oil and NGLs sales price before financial
instrument was $46.80/Bbl in 2004 compared to $38.27/Bbl in 2003,
primarily due to stronger market prices. In addition, the Company's
average oil and NGL price increased due to a change in product mix as a
result of NGLs and light oil properties acquired in 2004 replacing
medium grade properties disposed of in October 2003.

Paramount's 2004 production profile continued to be significantly
weighted to natural gas. In 2004 natural gas production contributed 80
percent of Paramount's total production compared to 78 percent in 2003
(2002 - 88 percent).

Fourth quarter petroleum and natural gas revenue before financial
instruments totaled $165.8 million as compared to $86.1 million for the
comparable quarter in 2003 (2002 - $135.0 million). The increase in
revenue is due to increased production volumes and to higher commodity
prices. Natural gas production volumes averaged 198 MMcf/d during the
fourth quarter, an increase of 40 percent as compared to 141 MMcf/d for
the comparable quarter in 2003 (2002 - 263 MMcf/d). The increase in
natural gas production is primarily a result of production from acquired
properties during the year. Oil and NGL sales averaged 8,903 Bbl/d in
the fourth quarter of 2004 as compared to 5,877 Bbl/d for the comparable
quarter in 2003 (2002 - 8,552 Bbl/d). Increased oil and NGL production
during the fourth quarter of 2004 is mainly the result of increased NGL
production associated with the properties acquired combined with a
decrease in oil and NGL production resulting from the sale of Sturgeon
lake in October, 2003.

The Alberta Securities Commission released National Instrument 51-101
(the "Instrument") in 2003, with an effective date of September 30,
2003. The Instrument requires all reported petroleum and natural gas
production to be measured in marketable quantities, with adjustments for
heat content included in the commodity price reported. Commencing the
fourth quarter of 2003 the Company adopted the Instrument prospectively.
As such, fourth quarter 2003 and subsequent period natural gas
production volumes are measured in marketable quantities, with
adjustments for heat content and transportation reflected in the
reported natural gas price.

Financial Instruments

Paramount's financial success is contingent upon the growth of reserves
and production volumes and the economic environment that creates a
demand for natural gas and crude oil. Such growth is a function of the
amount of cash flow that can be generated and reinvested into a
successful capital expenditure program. To protect cash flow against
commodity price volatility, the Company will, from time to time, manage
cash flow by utilizing commodity price hedges. The financial instrument
program is generally for periods of less than one year and would not
exceed 50 percent of Paramount's current production volumes.

At December 31, 2004, Paramount had the following commodity price
financial instrument contracts in place:



Amount Price Term
--------------------------------------------------------------------
Sales Contracts
NYMEX Fixed Price 10,000 MMbtu/d US $6.41 November 2004 -
March 2005
NYMEX Fixed Price 10,000 MMbtu/d US $7.46 November 2004 -
March 2005
NYMEX Fixed Price 10,000 MMbtu/d US $7.95 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $7.90 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $8.03 November 2004 -
March 2005
AECO Fixed Price 20,000 GJ/d $7.60 November 2004 -
March 2005
NYMEX Call Option 20,000 MMbtu/d US $10.00 December 2004 -
Strike March 2005
AECO Fixed Price 20,000 GJ/d $6.28 April 2005 -
June 2005
AECO Fixed Price 20,000 GJ/d $6.30 April 2005 -
June 2005
AECO Fixed Price 20,000 GJ/d $6.80 April 2005 -
June 2005
Purchase Contracts
AECO Fixed Price 20,000 GJ/d $6.76 November 2004 -
March 2005
--------------------------------------------------------------------
--------------------------------------------------------------------

Had these financial contracts been settled on December 31, 2004,
using prices in effect at that time, the mark to market before tax
gain would have totaled $14.2 million.

As at December 31, 2004, the Company had entered into the following
physical delivery contracts:

Physical delivery contracts
Station 2 Fixed Price 8,000 GJ/d $7.99 November 2004 -
March 2005
Station 2 Fixed Price 12,000 GJ/d $8.00 November 2004 -
March 2005
--------------------------------------------------------------------
--------------------------------------------------------------------

Subsequent to December 31, 2004, the Company has entered into the
following financial instrument contracts:

Amount Price Term
--------------------------------------------------------------------
Sales Contracts

NYMEX Fixed Price 1,000 Bbl/d US $46.77 March 2005 -
December 2005
NYMEX Fixed Price 1,000 Bbl/d US $47.30 March 2005 -
September 2005
NYMEX Fixed Price 1,000 Bbl/d US $53.26 April 2005 -
September 2005
AECO Fixed Price 10,000 GJ/d $7.06 April 2005 -
October 2005
AECO Fixed Price 10,000 GJ/d $7.10 April 2005 -
October 2005
--------------------------------------------------------------------
--------------------------------------------------------------------


On January 1, 2004, the Company adopted the recommendations set out by
the Canadian Institute of Chartered Accountants ("CICA") in Accounting
Guideline ("AcG") 13 - Hedging Relationships and Emerging Issues
Committee Abstract 128 - Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments. According to the
recommendations, financial instruments that do not qualify as a hedge
under AcG 13 or are not designated as a hedge are recorded in the
consolidated balance sheets as either an asset or a liability, with
changes in fair value recorded in net earnings. The Company has chosen
not to designate any of its financial instruments as hedges and
accordingly, has used mark-to-market accounting for these instruments.

As a result of applying these recommendations, the Company recorded
deferred financial instrument gains and losses at January 1, 2004 of
$3.3 million and $1.8 million, respectively, representing the fair
values of financial contracts outstanding at the beginning of the fiscal
year. These deferred gains and losses are being recognized in the
earnings over the term of the related contracts. Amortization for the
year ended December 31, 2004 totaled $1.8 million for the deferred
financial instrument loss and $1.6 million for the deferred financial
instrument gain, for a net decrease in earnings before tax of $0.2
million.

In addition, the Company recorded a net financial instrument asset at
December 31, 2004, with a fair value of $19.4 million. This amount
reflects the unrealized changes in fair value of Paramount's financial
instruments.

The total gain on financial instruments for the period of $18.7 million
is comprised of unrealized gains of $19.4 million (change in fair value
of contracts recorded on transition - $1.3 million gain, amortization of
the fair value of contracts - $0.2 million loss, fair value of contracts
entered into during the period - $18.3 million gain) less realized
losses of - $0.7 million. The $0.7 million realized cash losses on
financial instruments for the year ended December 31, 2004 is a 99
percent decrease from the $53.2 million of realized cash losses on
financial instruments for the 2003 comparative period.

The Company is exposed to credit risk from financial instruments to the
extent of non-performance by third parties, and non-performance by
counterparties to swap agreements. The Company minimizes credit risk
associated with possible non-performance by financial instrument
counterparties by entering into contracts with only highly rated
counterparties and controls third party credit risk with credit
approvals, limits on exposures to any one counterparty, and monitoring
procedures.

During 2004, approximately 65 percent of Paramount's natural gas sales
were under long-term contracts to gas aggregators and direct-sales
purchasers as compared to 75 percent and 43 percent for 2003 and 2002,
respectively. The decrease in the percentage is due to decreased
aggregator gas sales as well as termination of the Company's Ventura
northern border agreement.

Paramount closed a transaction in March 2005 whereby it acquired an
indirect 25 percent ownership interest in a gas marketing limited
partnership. In conjunction with the acquisition of the ownership
interest, Paramount will make available for delivery an average of 150
million GJ/d of natural gas over a five year term, to be marketed on
Paramount's behalf by the gas marketing limited partnership.

Paramount and Summit Operating Partnership (which will become Trilogy
Energy LP, subject to the completion of the Trust Spinout) have entered
into a Call on Production Agreement. Under this agreement, Paramount
will have the right to purchase all or any portion of Trilogy Energy
LP's available gas production at a price no less favourable than the
price Paramount will receive on the resale of the natural gas to the gas
marketing limited partnership. The term of the Call on Production
Agreement will be no longer than five years.

Paramount is not entitled to demand collateral securities from the gas
marketing limited partnership to ensure payment for the gas volumes
delivered, but is entitled to other means of protection in this regard
including stringent credit and risk management restrictions.

Netbacks



Netbacks ($/Boe) 2004 2003 2002
--------------------------------------------------------------------
P&NG revenue, net of
transportation $ 41.61 $ 36.36 $ 25.50
Royalties 7.94 6.93 4.44
Operating costs 7.24 6.82 5.14
--------------------------------------------------------------------
Operating netback 26.43 22.61 15.92
Realized financial
instrument loss (gain) 0.05 4.47 (2.79)
General and administrative 1.91 1.60 0.95
Bad debt expense (recovery) (0.42) 0.50 -
Lease rentals 0.27 0.30 0.27
Interest on long-term debt(1) 1.82 1.60 1.43
Current and Large
Corporations Tax 0.51 0.23 0.55
--------------------------------------------------------------------
Cash flow netback $ 22.29 $ 13.91 $ 15.51
--------------------------------------------------------------------
--------------------------------------------------------------------
(1) Net of non-cash interest expense.


Royalties

Royalties
(thousands of dollars) 2004 2003 2002
--------------------------------------------------------------------
Crown royalties (net of ARTC) $ 99,298 $ 78,996 $ 70,786
Other royalties 5,748 3,516 3,658
--------------------------------------------------------------------
Net royalties $ 105,046 $ 82,512 $ 74,444
--------------------------------------------------------------------
Average corporate royalty
rate as a percentage of
petroleum and natural gas
revenue before financial
instruments 19.1% 19.0% 19.4%
--------------------------------------------------------------------
--------------------------------------------------------------------


For 2004, net royalties increased to $105.0 million from $82.5 million
in 2003 (2002 - $74.4 million) due to higher production and commodity
prices. As a percentage of revenue, Paramount's corporate royalty rate
is substantially unchanged from the prior year, at 19.1 percent compared
to 19.0 percent in 2003.

Fourth quarter royalties totaled $30.4 million as compared to $10.7
million for the fourth quarter in 2003 (2002 - $28.2 million). The
increase in royalty costs reflects the increase in production volumes
and higher commodity prices.

Operating Costs



Operating Expenses
(thousands of dollars) 2004 2003 2002
--------------------------------------------------------------------
Operating expenses $ 95,767 $ 81,193 $ 86,067
--------------------------------------------------------------------
Net operating expenses
per Boe $ 7.24 $ 6.82 $ 5.14
--------------------------------------------------------------------
--------------------------------------------------------------------


Paramount's 2004 operating expenses increased 18 percent to $95.8
million from $81.2 million in 2003 (2002 - $86.1 million). On a
units-of-production basis, operating costs increased 6 percent to
$7.24/Boe from $6.82/Boe in 2003 (2002 - $5.14/Boe). The industry in
general experienced increases in the costs of goods and services
particularly higher labour and energy costs. In addition, properties
acquired by the Company during the year have higher per unit operating
costs than existing Paramount properties. Paramount constructs and
operates plant facilities and gathering systems as a corporate strategy
in order to control the flow of its natural gas to market. These
facilities incur fixed costs, which are in addition to the costs
incurred at the well level, thereby increasing total operating expenses
and the relative magnitude of the per unit costs.

Fourth quarter operating costs increased to $30.9 million as compared to
$22.3 million a year earlier. Fourth quarter operating costs decreased
on a units-of-production basis to $8.02/Boe from $8.25/Boe for the
comparable quarter in 2003. The 2004 fourth quarter operating costs
included workovers related to acquired properties, while the fourth
quarter of 2003 included the settlement of a dispute with a facility
operator, as well as post-closing adjustments related to the Sturgeon
Lake property sale incurred during the quarter.

General and Administrative Expenses



General and Administrative
Expenses (thousands of
dollars) 2004 2003 2002
--------------------------------------------------------------------
Gross general and
administrative expenses $ 41,007 $ 31,906 $ 30,868
Operating recoveries (15,760) (12,855) (15,238)
--------------------------------------------------------------------
Net general and
administrative expenses $ 25,247 $ 19,051 $ 15,630
--------------------------------------------------------------------
Net general and
administrative expenses
per Boe $ 1.91 $ 1.60 $ 0.95
--------------------------------------------------------------------
--------------------------------------------------------------------


General and administrative expenses, net of operating recoveries,
increased to $25.2 million in 2004 as compared to $19.1 million in 2003
(2002 - $15.6 million). Paramount has increased its head-office staffing
levels to enable the Company to identify and develop new core areas and
build its production portfolio. This initiative has resulted in
Paramount advancing its long-term projects such as Colville Lake,
Northeast Alberta bitumen and coal bed methane, and developing
successful new fields in existing core areas within Grande Prairie and
Northwest Alberta. The Company has also increased administrative staff
levels to ensure compliance with new corporate and reporting obligations
in Canada and the United States; certain of these are a result of the US
debt offerings closed in 2004. Paramount does not capitalize any general
and administrative expenses with the exception of overhead recoveries.

Stock-Based Compensation

Prior to 2004, the Company accounted for its stock option plan using the
fair value method. In 2004, the Company prospectively adopted the
intrinsic value method to account for the Company's stock-based
compensation plan. For 2004, the Company recorded a $41.2 million
non-cash expense using the intrinsic value method compared to the $1.2
million non-cash expense recorded in 2003 (2002 - $0.6 million) using
the fair value method.

Interest Expense



Interest Expense
(thousands of dollars) 2004 2003 2002
--------------------------------------------------------------------
Interest expense $ 25,399 $ 19,214 $ 23,943
Total debt, December 31 $ 459,141 $ 287,237 $ 539,270
Average debt outstanding
for the period $ 443,156 $ 340,919 $ 448,951
--------------------------------------------------------------------
--------------------------------------------------------------------


Interest expense increased to $25.4 million in 2004 from $19.2 million
in 2003 (2002 - $23.9 million). The increase reflects higher average
debt levels for the Company in 2004 as a result of acquisitions made in
the current year.

Dry Hole Costs

Under the successful efforts method of accounting, costs of drilling
exploratory wells are initially capitalized and, if subsequently
determined to be unsuccessful, are charged to dry hole expense. Other
exploration costs, including geological and geophysical costs and annual
lease rentals, are charged to exploration expense as incurred. For 2004,
dry hole costs amounted to $24.7 million as compared to $36.6 million in
2003 (2002 - $120.1 million). The 2004 provision includes $5.8 million
of costs associated with wells drilled in the current year and $18.9
million associated with exploratory wells drilled in previous years.

Geological and geophysical expenses increased during 2004 to $8.7
million from $8.5 million in the previous year (2002 - $9.3 million).

Depletion, Depreciation and Amortization

The current year provision for depletion and depreciation expense
totaled $191.6 million as compared to $165.1 million in 2003 (2002 -
$169.4 million). Depletion and depreciation expense includes expired
lease costs of $12.9 million. On a units-of-production basis, depletion
and depreciation costs averaged $14.48/Boe as compared to $13.86/Boe in
2003 (2002 - $10.11/Boe).

Capital costs associated with undeveloped land of $164 million and
non-producing petroleum and natural gas properties of $136 million
totaling $300 million are excluded from capital costs subject to
depletion in 2004 (2003 - $209 million).

Asset Retirement Obligations

Effective January 1, 2004, the Company retroactively adopted, with
restatement, the Canadian Institute of Chartered Accountants ("CICA")
recommendation on Asset Retirement Obligations, which requires liability
recognition for the fair value of retirement obligations associated with
long-lived assets. Prior to January 1, 2004, the estimated future
dismantlement and site restoration costs of natural gas and crude oil
assets were provided for using the unit-of-production method.

As a result of this change, net earnings for the year ended December 31,
2003 decreased by $1.5 million ($0.02 per share). The asset retirement
obligations liability as at December 31, 2003 increased by $40.4
million, property, plant and equipment, net of accumulated depletion,
increased by $31.1 million, and future income tax liability decreased
$3.7 million. Opening 2003 retained earnings decreased by $4.1 million
to reflect the cumulative impact of depletion expense and accretion
expense, net of the previously recognized cumulative site restoration
provision and net of related future income taxes on the asset retirement
obligations, recorded retroactively.

On an annual basis the Company reviews the liability for asset
retirement obligations. For 2004, accretion expense for asset retirement
obligations totaled $6.9 million as compared to $4.0 million in 2003. At
December 31, 2004, the Company had recorded an asset retirement
obligation liability for its petroleum and natural gas properties of
$101.5 million (2003 - $61.6 million). The majority of the increase is
due to the obligations associated with additional acquired properties
purchased during the year.

Income Taxes

In 2004, Paramount recorded Large Corporations and other tax expense of
$6.8 million as compared to $2.7 million in 2003.

The future income tax expense recorded for 2004 totaled $40.7 million,
as compared to $63.5 million recovery in 2003.



Estimated Income Tax Pools
(millions of dollars) December 31, 2004 December 31, 2003
--------------------------------------------------------------------
--------------------------------------------------------------------
Undepreciated capital
costs (UCC) $ 257 $ 215
Canadian oil and gas
property expenses (COGPE) 422 25
Canadian development
expenses (CDE) 203 166
Canadian exploration
expenses (CEE) 158 68
Other 33 21
--------------------------------------------------------------------
Total estimated income
tax pools $ 1,073 $ 495
--------------------------------------------------------------------
--------------------------------------------------------------------


Paramount has available approximately $1,073 million of unutilized tax
pools at December 31, 2004. These tax pools will be available for
deduction in 2005 in accordance with Canadian income tax regulations at
varying rates of amortization.



Cash Flow and Earnings

(thousands of dollars) 2004 2003 2002
------------------------------------------------------------------------
Cash flow from operations $ 295,566 $ 167,276 $ 259,916
Cash flow from operations per share
- basic $ 4.95 $ 2.78 $ 4.37
- diluted $ 4.84 $ 2.77 $ 4.36
------------------------------------------------------------------------
Net earnings before discontinued
operations $ 34,895 $ 1,208 $ 11,132
Net earnings (loss) from discontinued
operations $ 6,279 $ (57) $ (825)
------------------------------------------------------------------------
Net earnings $ 41,174 $ 1,151 $ 10,307
------------------------------------------------------------------------
Earnings before discontinued operations
per share - basic $ 0.58 $ 0.02 $ 0.19
- diluted $ 0.57 $ 0.02 $ 0.19
------------------------------------------------------------------------
Earnings per share - basic $ 0.69 $ 0.02 $ 0.17
- diluted $ 0.67 $ 0.02 $ 0.16
------------------------------------------------------------------------
------------------------------------------------------------------------


Paramount's cash flow from operations increased 77 percent to $295.6
million from $167.3 million in 2003. The increase in cash flows was a
result of a reduction in realized financial instrument losses in 2004 as
compared to 2003, and an increase in revenues due to higher commodity
prices and production. This was partially offset by higher operating
costs, general and administrative expenses and interest.

Fourth quarter cash flow totaled $92.1 million, an increase of 113
percent from $43.2 million during the same period in 2003 (2002 - $62.1
million). The increase in cash flow is a result of higher production
levels and increased commodity prices as compared to the fourth quarter
of 2003.

The Company recorded net earnings of $41.2 million for the year ended
2004, as compared to net earnings of $1.2 million in 2003. The higher
earnings in 2004 are primarily due to an increase in petroleum and
natural gas sales resulting from higher production and commodity prices,
financial instrument gains in 2004 as opposed to 2003 losses, and
unrealized foreign exchange gains on US debt. This was partially offset
by higher non-cash stock based compensation expense, depletion and
depreciation expense, and future income tax expense.



Quarterly Information

Historical quarterly information, prepared by the Company in Canadian
dollars and in accordance with GAAP, is as follows:

Fiscal 2004 Three Months Ended
(thousands of dollars, December September
except per share amounts) 31 30 June 30 March 31
------------------------------------------------------------------------
Net revenues $ 162,880 $ 127,192 $ 95,767 $ 79,179
Net earnings (loss) before
discontinued operations $ (18,873) $ 40,599 $ 10,331 $ 2,838
Net earnings (loss) from
discontinued operations $ 1,120 $ 5,213 $ (395) $ 341
------------------------------------------------------------------------
Net earnings (loss) $ (17,753) $ 45,812 $ 9,936 $ 3,179
------------------------------------------------------------------------
Net earnings (loss) before
discontinued operations
per common share - basic $ (0.30) $ 0.69 $ 0.18 $ 0.05
- diluted $ (0.29) $ 0.68 $ 0.17 $ 0.05
------------------------------------------------------------------------
Net earnings (loss) per
common share - basic $ (0.28) $ 0.78 $ 0.17 $ 0.05
- diluted $ (0.28) $ 0.76 $ 0.17 $ 0.05
------------------------------------------------------------------------
------------------------------------------------------------------------

Fiscal 2003 Three Months Ended
(thousands of dollars, December September
except per share amounts) 31 30 June 30 March 31
------------------------------------------------------------------------
Net revenues $ 76,945 $ 65,415 $ 65,101 $ 91,446
Net earnings (loss) before
discontinued operations $ 10,899 $ (8,491) $ (1,105) $ (95)
Net earnings (loss) from
discontinued operations $ 209 $ 108 $ (783) $ 409
------------------------------------------------------------------------
Net earnings (loss) $ 11,108 $ (8,383) $ (1,888) $ 314
------------------------------------------------------------------------
Net earnings (loss) before
discontinued operations
per common share - basic $ 0.18 $ (0.14) $ (0.02) $ -
- diluted $ 0.18 $ (0.14) $ (0.02) $ -
------------------------------------------------------------------------
Net earnings (loss) per
common share - basic $ 0.18 $ (0.14) $ (0.03) $ 0.01
- diluted $ 0.18 $ (0.14) $ (0.03) $ 0.01
------------------------------------------------------------------------
------------------------------------------------------------------------


Quarterly net revenues have continued to increase since June 30, 2003,
primarily as a result of an increase in production levels and higher
commodity prices. The decrease in net revenue between March 31, 2003 and
June 30, 2003 is primarily due to lower production volumes resulting
from the disposition of assets to Paramount Energy Trust in the first
quarter of 2003. The third and fourth quarter net revenues for 2004
reflect increased production resulting from the acquisition of assets in
the Kaybob, East Liard, and Marten Creek areas.

Quarterly net earnings are generally lower in 2003 due to lower
production levels, combined with higher financial instrument losses
incurred during 2003. The net loss in the fourth quarter of 2004 is
primarily due to the Company prospectively adopting the intrinsic value
method to account for stock based compensation expense and an increase
in future tax expense.

Capital Expenditures



Capital Expenditures
(thousands of dollars) 2004 2003 2002
--------------------------------------------------------------------
Land $ 37,919 $ 22,288 $ 6,410
Geological and geophysical 8,728 8,450 9,303
Drilling 184,466 123,455 124,076
Production equipment and
facilities 85,171 69,560 77,407
--------------------------------------------------------------------
Exploration and
development expenditures 316,284 223,753 217,196
--------------------------------------------------------------------
Summit Resources Limited
acquisition - - 251,422
Property acquisitions 322,598 937 28,610
Proceeds on property
dispositions (61,806) (371,601) (5,042)
Other 1,938 1,933 2,349
--------------------------------------------------------------------
Net capital expenditures $ 579,014 $ (144,978) $ 494,535
--------------------------------------------------------------------
Property, plant and
equipment, net, December 31 $ 1,345,806 $ 1,037,307 $ 1,411,961
--------------------------------------------------------------------
Total assets, December 31 $ 1,542,786 $ 1,177,130 $ 1,526,786
--------------------------------------------------------------------
--------------------------------------------------------------------


During 2004, expenditures for exploration and development activities
totaled $316.3 million as compared to $223.8 million in 2003 (2002 -
$217.2 million). The increase in the capital expenditures program in
2004 resulted in a total of 271 gross (180 net) wells drilled during the
year, compared to 211 gross (139 net) wells in 2003 (2002 - 135 gross,
99 net).

Net capital expenditures totaled $579.0 million in 2004 as compared to a
recovery of $145 million in 2003 (2002 - $494.5 million). The Company
acquired a number of properties totaling $322.6 million in 2004 offset
by the disposition of certain non-core properties.

Paramount has budgeted a total of $340 million for capital expenditures
for 2005; $100 million of which is to be directed to the Trilogy assets
and the remaining $240 million will be directed to the properties
retained by Paramount Resources Ltd. The 2005 capital expenditure
program is expected to be funded through the Company's 2005 cash flow.

Investments

The Company has the following short-term investments:



Opening Acquired Closing
2004 Shares (Divested) 2004 Shares Investment
---------------------------------------------------------------------
Investments
Fox Creek
Petroleum Corp. 2,325,162 - 2,325,162 $2,538,000
Invertek(1) - - - 560,114
Trinidad Drilling
Ltd.(1)(2) - 820,513 820,513 6,400,001
Arctos Petroleum
Corp.(6) - - - 2,116,945
Harvest Energy Trust 200,000 (200,000) - -
Jurassic Oil and
Gas Ltd.(3) 850,000 - 850,000 -
Jurassic Oil and
Gas Ltd. - Demand
Note(4) - - - 100,000
USD short-term
deposits(5) - - - 13,268,200
---------------------------------------------------------------------
3,375,162 620,513 3,995,675 $24,983,260
---------------------------------------------------------------------
---------------------------------------------------------------------
(1) Investment in Invertek and Trinidad Drilling Ltd. is through
Wilson Drilling Ltd.
(2) Investment is in the form of Exchangeable Shares which can be
redeemed for trust units in Trinidad Energy Services Income
Trust.
(3) The Company wrote off its investment in Jurassic Oil and Gas Ltd.
in 2003 but has retained the shares.
(4) Bears interest at 6 percent per annum.
(5) US $5 million matures January 4, 2005 and bears interest at 2.15
percent per annum. US $6 million matures January 14, 2005 and
bears interest at 2.23 percent per annum.
(6) Investment is in the form of convertible debentures maturing
March 1, 2005 bearing interest at 8 percent per annum


Liquidity and Capital Resources

Paramount's capital structure as at December 31, 2004, was as
follows:

(thousands of dollars,
except per share amounts) Amount % $/Share(1)
--------------------------------------------------------------------
Debt
US$ senior notes $ 257,836 24 $ 4.08
Credit facility 201,305 19 3.19
Working capital surplus (7,954) (1) (0.13)
--------------------------------------------------------------------
Net debt 451,187 42 7.14
Shareholders' equity 625,039 58 9.89
--------------------------------------------------------------------
Total capitalization $ 1,076,226 100% $ 17.03
--------------------------------------------------------------------
--------------------------------------------------------------------
(1)At December 31, 2004- 63,185,600 basic common shares outstanding.


Debt

US$ SENIOR NOTES

The Company issued US $175 million of 7 7/8 percent Senior Notes due
2010 on October 27, 2003. Interest on the notes is payable
semi-annually, beginning in 2004. The Company may redeem some or all of
the notes at any time after November 1, 2007 at redemption prices
ranging from 100 percent to 103.938 percent of the principal amount,
plus accrued and unpaid interest to the redemption date, depending on
the year in which the notes are redeemed. In addition, the Company may
redeem up to 35 percent of the notes prior to November 1, 2006 at
107.875 percent of the principal amount, plus accrued interest to the
redemption date, using the proceeds of certain equity offerings. The
notes are unsecured and rank equally with all of the Company's existing
and future senior unsecured indebtedness.

On June 29, 2004, the Company issued US $125 million of 8 7/8 percent
senior notes due 2014. Interest on the notes is payable semi-annually,
beginning in 2005. The Company may redeem some or all of the notes at
any time after July 15, 2009 at redemption prices ranging from 100
percent to 104.438 percent of the principal amount, plus accrued and
unpaid interest to the redemption date, depending on the year in which
the notes are redeemed. In addition, the Company may redeem up to 35
percent of the notes prior to July 15, 2007 at 108.875 percent of the
principal amount, plus accrued interest to the redemption date, using
the proceeds of certain equity offerings. The notes are unsecured and
rank equally with all of the Company's existing and future senior
unsecured indebtedness.

On December 30, 2004, the Company redeemed US $41.7 million principal of
its 7 7/8 percent senior notes due 2010 and US $43.8 million principal
of its 8 7/8 percent senior notes due 2014. The aggregate redemption
price was US $45.0 million and US $47.6 million plus accrued and unpaid
interest for the 7 7/8 percent senior notes and 8 7/8 percent senior
notes respectively.

CREDIT FACILITY

As at December 31, 2004, the Company had a $270 million committed
revolving/non-revolving term facility with a syndicate of Canadian
chartered banks. Borrowings under the facility bear interest at the
lenders' prime rate, bankers' acceptance or LIBOR rates plus an
applicable margin, dependent on certain conditions. The revolving nature
of the facility is due to expire on March 31, 2005. The Company has
requested and received approval for an extension on the revolving credit
facility of 364 days. Advances drawn on the facility are secured by a
fixed charge over the assets of the Company.

In February 2005, the Company's borrowing capacity under this facility
was increased to $330 million as a result of the Company's senior note
redemption on December 31, 2004, and an increase in its oil and natural
gas reserves.

WORKING CAPITAL

The Company's working capital surplus at December 31, 2004 was $8.0
million (2003 - $10.5 million deficiency).

FUTURE COMMITMENTS

Future commitments, as at December 31, 2004, are as follows:



Expected Payment Date
Less
Contractual Obligations than 2-3 4-5 After
(thousands of dollars) Total 1 year years years 5 years
---------------------------------------------------------------------
US$ 7.875% senior
notes due 2010 $ 160,174 - - - $ 160,174
US$ 8.875% senior
notes due 2014 97,662 - - - 97,662
Pipeline
commitments 237,205 22,015 42,504 42,075 130,611
---------------------------------------------------------------------
Total $ 495,041 $ 22,015 $ 42,504 $ 42,075 $ 388,447
---------------------------------------------------------------------
---------------------------------------------------------------------


SHARE CAPITAL

As at December 31, 2004, the Company's issued share capital consisted of
63,185,600 common shares (December 31, 2003 - 60,094,600 common shares).
Changes in share capital were as follows:



Consideration
Common shares Number (thousands of dollars)
--------------------------------------------------------------------
Balance December 31, 2002 59,458,600 $ 190,193
--------------------------------------------------------------------
Stock options exercised 710,000 10,317
Expenses recognized in
respect of stock-based
compensation (74,000) (236)
--------------------------------------------------------------------
Balance December 31, 2003 60,094,600 $ 200,274
--------------------------------------------------------------------
Shares repurchased - at
carrying value (1,629,500) (5,322)
Stock options exercised 220,500 3,057
Common shares issued,
net of issuance 2,500,000 54,901
Flow-through shares issued 2,000,000 57,981
Tax adjustment on share
issuance costs and
flow-through share
renunciations (7,959)
--------------------------------------------------------------------
Balance December 31, 2004 63,185,600 $ 302,932
--------------------------------------------------------------------
--------------------------------------------------------------------


Between January 1 and May 14, 2004 the Company repurchased 1,629,500
shares at a carrying value of $5.3 million for $19.4 million.

During the year, employees of the Company exercised 220,500 stock
options for total consideration of $3.1 million.

In October 2004, Paramount completed a public offering of 2.5 million
common shares at $23.00 per share and a private placement of 2.0 million
"flow through" common shares at $29.50 per share. Aggregate gross
proceeds from these two offerings were $116.5 million. As at December
31, 2004, the Company had made renunciations of $23.7 million.

Stock Options

The Company has an Employee Incentive Stock Option plan (the "plan").
Under the plan, stock options are granted at the current market price on
the day prior to issuance. Participants in the plan, upon exercising
their stock options, may request to receive either a cash payment equal
to the difference between the exercise price and the market price of the
Company's common shares or common shares issued from Treasury.
Irrespective of the participant's request, the Company may choose to
only issue common shares. Cash payments made in respect of the plan are
charged to general and administrative expenses when incurred. Options
granted vest over four years and have a four and a half year contractual
life.

As at December 31, 2004, 5.0 million shares were reserved for issuance
under the Company's Employee Incentive Stock Option Plan, of which 3.2
million options are outstanding, exercisable to May 31, 2009, at prices
ranging from $8.91 to $26.29 per share.



Stock options 2004 2003
-----------------------------------------------------------------------
Average Average
Grant Price Options Grant Price Options
-----------------------------------------------------------------------
Balance, beginning
of year $ 9.64 3,632,000 $14.25 1,949,500
Granted 17.09 348,000 9.66 2,998,000
Exercised 9.97 (618,500) 14.29 (791,000)
Cancelled 9.09 (149,000) 10.30 (524,500)
-----------------------------------------------------------------------
Balance, end
of year $10.41 3,212,500 $ 9.64 3,632,000
-----------------------------------------------------------------------
Options exercisable,
end of year $10.26 1,282,875 $10.72 1,087,875
-----------------------------------------------------------------------
-----------------------------------------------------------------------


Risks and Uncertainties

Companies involved in the exploration for and production of oil and
natural gas face a number of risks and uncertainties inherent in the
industry. The Company's performance is influenced by commodity pricing,
transportation and marketing constraints and government regulation and
taxation.

Natural gas prices are influenced by the North American supply and
demand balance as well as transportation capacity constraints. Seasonal
changes in demand, which are largely influenced by weather patterns,
also affect the price of natural gas.

Stability in natural gas pricing is available through the use of short
and long-term contract arrangements. Paramount utilizes a combination of
these types of contracts, as well as spot markets, in its natural gas
pricing strategy. As the majority of the Company's natural gas sales are
priced to US markets, the Canada/US exchange rate can strongly affect
revenue.

Oil prices are influenced by global supply and demand conditions as well
as for worldwide political events. As the price of oil in Canada is
based on a US benchmark price, variations in the Canada/US exchange rate
further affect the price received by Paramount for its oil.

The Company's access to oil and natural gas sales markets is restricted,
at times, by pipeline capacity. In addition, it is also affected by the
proximity of pipelines and availability of processing equipment.
Paramount attempts to control as much of its marketing and
transportation activities as possible in order to minimize any negative
impact from these external factors.

The oil and gas industry is subject to extensive controls, royalties,
regulatory policies and income taxes imposed by the various levels of
government. These controls and policies, as well as income tax laws and
regulations, are amended from time to time. The Company has no control
over government intervention or taxation levels in the oil and gas
industry; however, it operates in a manner intended to ensure that it is
in compliance with all regulations and is able to respond to changes as
they occur.

Paramount's operations are subject to the risks normally associated with
the oil and gas industry including hazards such as unusual or unexpected
geological formations, high reservoir pressures and other conditions
involved in drilling and operating wells. The Company attempts to
minimize these risks using prudent safety programs and risk management,
including insurance coverage against potential losses.

The Company recognizes that the industry is faced with an increasing
awareness with respect to the environmental impact of oil and gas
operations. Paramount has reviewed the environmental risks to which it
is exposed and has determined that there is no current material impact
on the Company's operations; however, the cost of complying with
environmental regulations is increasing. Paramount intends to ensure
continued compliance with environmental legislation.

2005 Outlook and Sensitivity Analysis

The Company's earnings and cash flow are highly sensitive to changes in
commodity prices, exchange rates and other factors that are beyond the
control of the Company. Current volatility in commodity prices creates
uncertainty as to Paramount's cash flow and capital expenditure budget.
The Company will therefore assess results throughout the year and revise
estimates as necessary to reflect most current information. The
following analysis assesses the magnitude of these sensitivities on the
Company's 2005 cash flow using the following base assumptions:



--------------------------------------------------------------------
2005 Average Production
Natural gas 210 MMcf/d
Crude oil/liquids 10,000 Bbl/d

2005 Average Prices
Natural gas $6.50/Mcf
Crude oil (WTI) US$42.00/Bbl

2005 Exchange Rate (C$/US$) $ 0.81
--------------------------------------------------------------------
--------------------------------------------------------------------


The following analysis assesses the estimated impact on cash flow
with variations in production, prices, interest and exchange rates:

Sensitivity Cash Flow Effect
(millions of dollars)
--------------------------------------------------------------------
Gas sales change of 10 MMcf/d $ 18.98
Gas price change of $0.10/Mcf $ 6.13
Oil and natural gas liquids sales
change of 100 Bbl/d $ 1.27
Oil and natural gas liquids price
change of $1.00/Bbl (W.T.I) $ 3.60
Sensitivity to Canada/US exchange
rate fluctuation of $0.01 CDN $ 1.21
Average interest rate change of 1% $ 0.62
--------------------------------------------------------------------
--------------------------------------------------------------------


Critical Accounting Estimates

The MD&A is based on the Company's consolidated financial statements,
which have been prepared in Canadian dollars in accordance with GAAP.
The application of GAAP requires management to make estimates, judgments
and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities, if any,
at the date of the financial statements, and the reported amounts of
revenues and expenses during the reporting period. Paramount bases its
estimates on historical experience and various other assumptions that
are believed to be reasonable under the circumstances. Actual results
could differ from these estimates under different assumptions or
conditions.

The following is a discussion of the critical accounting estimates that
are inherent in the preparation of the Company's consolidated financial
statements and notes thereto.

ACCOUNTING FOR PETROLEUM AND NATURAL GAS OPERATIONS

Under the successful efforts method of accounting, the Company
capitalizes only those costs that result directly in the discovery of
petroleum and natural gas reserves, including acquisitions, successful
exploratory wells, development costs and the costs of support equipment
and facilities. Exploration expenditures, including geological and
geophysical costs, lease rentals, and exploratory dry holes are charged
to earnings in the period incurred. Certain costs of exploratory wells
are capitalized pending determination that proved reserves have been
found. Such determination is dependent upon, among other things, the
results of planned additional wells and the cost of required capital
expenditures to produce the reserves found.

The application of the successful efforts method of accounting requires
management's judgment to determine the proper designation of wells as
either developmental or exploratory, which will ultimately determine the
proper accounting treatment of the costs incurred. The results of a
drilling operation can take considerable time to analyze, and the
determination that proved reserves have been discovered requires both
judgment and application of industry experience. The evaluation of
petroleum and natural gas leasehold acquisition costs requires
management's judgment to evaluate the fair value of exploratory costs
related to drilling activity in a given area.

RESERVE ESTIMATES

Estimates of the Company's reserves included in its consolidated
financial statements are prepared in accordance with guidelines
established by the Alberta Securities Commission. Reserve engineering is
a subjective process of estimating underground accumulations of
petroleum and natural gas that cannot be measured in an exact manner.
The process relies on interpretations of available geological,
geophysical, engineering and production data. The accuracy of a reserve
estimate is a function of the quality and quantity of available data,
the interpretation of that data, the accuracy of various mandated
economic assumptions and the judgment of the persons preparing the
estimate.

Paramount's reserve information is based entirely on estimates prepared
by its independent petroleum consultants. Estimates prepared by others
may be different than these estimates. Because these estimates depend on
many assumptions, all of which may differ from actual results, reserve
estimates may be different from the quantities of petroleum and natural
gas that are ultimately recovered. In addition, the results of drilling,
testing and production after the date of an estimate may justify
revisions to the estimate.

The present value of future net revenues should not be assumed to be the
current market value of the Company's estimated reserves. Actual future
prices, costs and reserves may be materially higher or lower than the
prices, costs and reserves used for the future net revenue calculations.

The estimates of reserves impact depletion, dry hole and site
restoration expenses. If reserve estimates decline, the rate at which
the Company records depletion and site restoration expenses increases,
reducing net earnings. In addition, changes in reserve estimates may
impact the outcome of Paramount's assessment of its petroleum and
natural gas properties for impairment.

IMPAIRMENT OF PETROLEUM AND NATURAL GAS PROPERTIES

The Company reviews its proved properties for impairment annually on a
field basis. For each field, an impairment provision is recorded
whenever events or circumstances indicate that the carrying value of
those properties may not be recoverable. The impairment provision is
based on the excess of carrying value over fair value. Fair value is
defined as the present value of the estimated future net revenues from
production of total proved and probable petroleum and natural gas
reserves, as estimated by the Company on the balance sheet date. Reserve
estimates, as well as estimates for petroleum and natural gas prices and
production costs, may change and there can be no assurance that
impairment provisions will not be required in the future.

Unproved leasehold costs and exploratory drilling in progress are
capitalized and reviewed periodically for impairment. Costs related to
impaired prospects or unsuccessful exploratory drilling are charged to
earnings. Acquisition costs for leases that are not individually
significant are charged to earnings as the related leases expire.
Further impairment expense could result if petroleum and natural gas
prices decline in the future or if negative reserve revisions are
recorded, as it may be no longer economic to develop certain unproved
properties. Management's assessment of, among other things, the results
of exploration activities, commodity price outlooks and planned future
development and sales impacts the amount and timing of impairment
provisions.

ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations recorded in the consolidated financial
statements are based on estimated total costs of such obligations
related to the Company's petroleum and natural gas properties. This
estimate is based on management's analysis of production structure,
reservoir characteristics and depth, market demand for equipment,
currently available procedures and discussions with construction and
engineering consultants. Estimating these future costs requires
management to make estimates and judgments that are subject to future
revisions based on numerous factors, including changing technology and
political and regulatory environments.

Beginning in 2004, the Company adopted the Canadian Institute of
Chartered Accountants ("CICA") Handbook section 3110 - Asset Retirement
Obligation, which will result in changes in accounting for asset
retirement obligations. See "Recent Accounting Pronouncements" section.

INCOME TAXES

The Company records future tax assets and liabilities to account for the
expected future tax consequences of events that have been recorded in
its consolidated financial statements and its tax returns. These amounts
are estimates; the actual tax consequences may differ from the estimates
due to changing tax rates and regimes, as well as changing estimates of
cash flows and capital expenditures in current and future periods. We
periodically assess the realizability of our future tax assets. If the
Company concludes that it is more likely than not that some portion or
all of the deferred tax assets will not be realized under accounting
standards, the tax asset will be reduced by a valuation allowance.

Recent Accounting Pronouncements

IMPAIRMENT OF LONG-LIVED ASSETS

The CICA recently issued Handbook Section 3063 - Impairment of
Long-Lived Assets. This new section establishes standards for the
recognition, measurement and disclosure of the impairment of long-lived
assets by profit-oriented enterprises. The section is effective for
fiscal years beginning on or after April 1, 2003.

Under the new section, impairment of long-lived assets held for use is
determined by a two-step process, with the first step determining when
an impairment is recognized and the second step measuring the amount of
the impairment. To test for and measure impairment, long-lived assets
are grouped at the lowest level for which identifiable cash flows are
largely independent. An impairment loss is recognized when the carrying
amount of a long-lived asset exceeds the sum of the undiscounted cash
flows expected to result from its use and eventual disposition. An
impairment loss is measured as the amount by which the long-lived
asset's carrying amount exceeds its fair value. This represents a
significant change to Canadian GAAP, which previously measured the
amount of the impairment as the difference between the long-lived
asset's carrying value and its net recoverable amount (i.e. undiscounted
cash flows plus residual value).

DISPOSAL OF LONG-LIVED ASSETS AND DISCONTINUED OPERATIONS

The CICA recently issued Handbook Section 3475 - Disposal of Long-Lived
Assets and Discontinued Operations, which establishes standards for the
recognition, measurement, presentation and disclosure of the disposal of
long-lived assets by profit-oriented enterprises. It also establishes
standards for the presentation and disclosure of discontinued operations.

Although earlier adoption is encouraged, Section 3475 applies to
disposal activities initiated by a company's commitment to a plan on or
after May 1, 2003.

VARIABLE INTEREST ENTITIES

The CICA recently issued Accounting Guideline 15 - Consolidation of
Variable Interest Entities. The guideline requires the consolidation of
entities in which an enterprise absorbs a majority of the entity's
expected losses, receives a majority of the entity's expected residual
returns, or both, as a result of ownership, contractual or other
financial interests in the entity. Currently, entities are generally
consolidated by an enterprise when it has a controlling financial
interest through ownership of a majority voting interest in the entity.
The guideline applies to annual and interim periods beginning on or
after November 1, 2004, except for certain disclosure requirements.
Entities should provide disclosures about variable interest entities in
which they hold significant interests for periods beginning on or after
January 1, 2004.

ASSET RETIREMENT OBLIGATIONS

The CICA recently issued Handbook Section 3110 - Asset Retirement
Obligation which addresses statutory, regulatory, contractual and other
legal obligations associated with the retirement of a long-lived asset
that results from its acquisition, construction, development or normal
operation.

Under Section 3110, asset retirement obligations are initially measured
at fair value at the time the obligation is incurred with a
corresponding amount capitalized as part of the asset's carrying value
and depreciated over the asset's useful life using a systematic and
rational allocation method.

On initial recognition, the fair value of an asset retirement obligation
is determined based upon the expected present value of future cash
flows. In subsequent periods, the carrying amount of the liability would
be adjusted to reflect (a) the passage of time, and (b) revisions to
either the timing or the amount of the original estimate of undiscounted
cash flows.

The change in liability due to the passage of time is measured by
applying an interest method of allocation to the opening liability and
is recognized as an increase in the carrying value of the liability and
an expense. The expense must be recorded as an operating item in the
income statement, not as a component of interest expense. A change in
the liability resulting from revisions to either the timing or the
amount of the original estimate of undiscounted cash flows is recognized
as an increase or decrease in the carrying amount of the liability with
an offsetting increase or decrease in the carrying amount of the
associated asset.



Paramount Resources Ltd.
Consolidated Balance Sheets (unaudited)
(thousands of dollars)
December 31 December 31
2004 2003
------------------------------------------------------------------------
(restated -
notes 2
and 5)
ASSETS (note 8)
Current Assets

Short-term investments
(market value: 2004 - $27,149; 2003 - $17,265)$ 24,983 $ 16,551
Accounts receivable 107,843 80,710
Financial instruments (note 11) 21,564 -
Prepaid expenses 3,260 2,255
Assets of discontinued operations (note 5) - 1,680
------------------------------------------------------------------------
157,650 101,196
------------------------------------------------------------------------
Property, Plant and Equipment
Property, plant and equipment, at cost (note 6) 1,933,104 1,444,139
Accumulated depletion and depreciation (note 6) (587,298) (418,225)
Assets of discontinued operations, net (note 5) - 11,393
------------------------------------------------------------------------
1,345,806 1,037,307
------------------------------------------------------------------------
Goodwill 31,621 31,621
Other assets 7,709 7,006
------------------------------------------------------------------------
$ 1,542,786 $ 1,177,130
------------------------------------------------------------------------
------------------------------------------------------------------------

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities $ 147,508 $ 109,334
Financial instruments (note 11) 2,188 -
Liabilities of discontinued operations (note 5) - 2,455
------------------------------------------------------------------------
149,696 111,789
------------------------------------------------------------------------
Long-term debt (note 8) 459,141 287,237
Asset retirement obligations (note 7) 101,486 61,554
Deferred revenue - 3,959
Stock based compensation liability (note 9) 41,044 -
Future income taxes (note 10) 166,380 206,684
Liabilities of discontinued operations (note 5) - 9,874
------------------------------------------------------------------------
768,051 569,308
------------------------------------------------------------------------

Commitments and Contingencies
(note 11 and 14)

Shareholders' Equity
Share capital (note 9)
Issued and outstanding 63,185,600 common
shares (2003 - 60,094,600 common shares) 302,932 200,274
Contributed surplus - 746
Retained earnings 322,107 295,013
------------------------------------------------------------------------
625,039 496,033
------------------------------------------------------------------------
$ 1,542,786 $ 1,177,130
------------------------------------------------------------------------
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.


Paramount Resources Ltd.
Consolidated Statements of Earnings (Loss)
and Retained Earnings (unaudited)
(thousands of dollars except per share amounts)

Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
-------------------------------------------
unaudited unaudited

(restated (restated
- notes - notes
2 and 5) 2 and 5)
Revenue
Petroleum and natural
gas sales $ 173,931 $ 93,679 $ 581,901 $ 464,558
Transportation costs (note 2) (8,087) (7,611) (31,285) (30,499)
Gain (loss) on financial
instruments (note 11) 27,419 1,541 18,693 (53,204)
Royalties (net of Alberta
Royalty Tax Credit) (30,383) (10,664) (105,046) (82,512)
Loss on sale of investments - - (34) (1,020)
------------------------------------------------------------------------
162,880 76,945 464,229 297,323
------------------------------------------------------------------------

Expenses
Operating 30,896 22,287 95,767 81,193
Interest 7,534 5,312 25,399 19,214
General and administrative 8,251 4,881 25,247 19,051
Stock based compensation
expense (note 9) 39,353 1,214 41,195 1,214
Bad debt expense (recovery) (416) - (5,523) 5,977
Lease rentals 299 1,027 3,546 3,574
Geological and geophysical 2,203 3,208 8,728 8,450
Dry hole costs (note 6) 15,648 15,618 24,676 36,600
(Gain) loss on sales of
property, plant
and equipment (754) (15,841) (16,255) 3,640
Accretion of asset
retirement obligations 2,654 1,011 6,920 4,044
Depletion and depreciation 54,821 47,471 191,578 165,098
Writedown of petroleum
and natural gas
properties (note 6) - 550 - 10,418
Unrealized foreign exchange
gain on US debt (7,798) (1,566) (24,188) (1,566)
Realized foreign exchange
gain on US debt (note 8) (7,161) - (7,161) -
Premium on redemption
of US debt (note 8) 11,950 - 11,950 -
------------------------------------------------------------------------
157,480 85,172 381,879 356,907
------------------------------------------------------------------------
Earnings (loss) before
income taxes 5,400 (8,227) 82,350 (59,584)
------------------------------------------------------------------------
Income and other taxes (note 10)
Large Corporations Tax
and other 3,284 994 6,795 2,689
Future income tax
(recovery) expense 20,989 (20,120) 40,660 (63,481)
------------------------------------------------------------------------
24,273 (19,126) 47,455 (60,792)
------------------------------------------------------------------------
Net earnings (loss) from
continuing operations (18,873) 10,899 34,895 1,208
Net earnings (loss) from
discontinued operations
(note 5) 1,120 209 6,279 (57)
------------------------------------------------------------------------
Net earnings (loss) (17,753) 11,108 41,174 1,151
------------------------------------------------------------------------
Retained earnings,
beginning of period 339,860 289,440 295,013 355,912
Adjustment on disposition
of assets to Paramount
Energy Trust (note 4) - (5,535) - (6,923)
Dividends declared (note 4) - - - (51,000)
Purchase and cancellation
of share capital (note 9) - - (14,080) -
Change in accounting
policy (note 2) - - - (4,127)
------------------------------------------------------------------------
Retained earnings,
end of period $ 322,107 $ 295,013 $ 322,107 $ 295,013
------------------------------------------------------------------------
------------------------------------------------------------------------
Net earnings (loss) from
continuing operations
per common share
- basic $ (0.30) $ 0.18 $ 0.58 $ 0.02
- diluted $ (0.29) $ 0.18 $ 0.57 $ 0.02
------------------------------------------------------------------------
Net earnings (loss) from
discontinued operations
(note 5)
- basic $ 0.02 $ - $ 0.11 $ -
- diluted $ 0.02 $ - $ 0.10 $ -
------------------------------------------------------------------------
Net earnings (loss)
per common share
- basic $ (0.28) $ 0.18 $ 0.69 $ 0.02
- diluted $ (0.28) $ 0.18 $ 0.67 $ 0.02
------------------------------------------------------------------------
Weighted average common
shares outstanding
(thousands)
- basic 62,341 60,168 59,755 60,098
- diluted 64,194 60,340 61,026 60,472
------------------------------------------------------------------------
See accompanying notes to consolidated financial statements.


Paramount Resources Ltd.
Consolidated Statements of Cash Flows (unaudited)
(thousands of dollars except per share amounts)

Three Months Ended Year Ended
December 31 December 31
2004 2003 2004 2003
------------------------------------------------------------------------
unaudited unaudited

(restated (restated
- notes - notes
2 and 5) 2 and 5)
Operating activities
Net earnings (loss) from
continuing operations $ (18,873) $ 10,899 $ 34,895 $ 1,208
Add (deduct) non-cash items
Depletion and depreciation 54,821 47,471 191,578 165,098
Writedown of petroleum and
natural gas properties - 550 - 10,418
(Gain) loss on sales of
property, plant and
equipment (754) (15,841) (16,255) 3,640
Accretion of asset
retirement obligations 2,654 1,011 6,920 4,044
Future income tax
(recovery) expense 20,989 (20,120) 40,660 (63,481)
Amortization of
other assets 385 161 1,277 161
Non-cash stock based
compensation expense 39,353 1,214 41,195 1,214
Non-cash (gain) loss on
financial instruments (22,563) - (19,376) -
Unrealized foreign
exchange gain on US debt (7,798) (1,566) (24,188) (1,566)
Realized foreign
exchange gain on US debt (7,161) - (7,161) -
Premium on redemption
of US debt 11,950 - 11,950 -
Dry hole costs 15,648 15,618 24,676 36,600
Geological and
geophysical costs 2,203 3,208 8,728 8,450
------------------------------------------------------------------------
Cash flow from continuing
operations 90,854 42,605 294,899 165,786
Cash flow from
discontinued operations 1,263 552 667 1,490
------------------------------------------------------------------------
Cash flow from operations 92,117 43,157 295,566 167,276
------------------------------------------------------------------------
Increase (decrease)
in deferred revenue - 3,218 (3,959) (3,845)
Asset retirement
obligations expenditure (779) - (1,214) -
Increase (decrease)
in other assets 241 (161) - (161)
Change in non-cash
operating working capital
from continuing operations
(note 12) 2,627 (20,595) (27,320) (33,582)
Change in non-cash
operating working capital
from discontinued operations - 64 - 201
------------------------------------------------------------------------
94,206 25,683 263,073 129,889
------------------------------------------------------------------------
Financing activities
Bank loans - draws 123,238 32,933 431,951 42,933
Bank loans - repayments (93,201) (242,019) (298,173) (477,338)
Shareholder loan - - - (33,000)
Proceeds from US debt
offering, net of
issuance costs (54) 221,447 162,917 221,447
Redemption of US debt (105,686) - (105,686) -
Premium on redemption
of US debt (8,864) - (8,864) -
Realized foreign exchange
gain on US debt 7,161 - 7,161 -
Capital stock - issued,
net of issuance costs 114,515 - 115,043 10,317
Capital stock - purchased
and cancelled - (705) (19,401) (705)
Discontinued operations (6,499) 1,038 (11,301) (190)
------------------------------------------------------------------------
30,610 12,694 273,647 (236,536)
------------------------------------------------------------------------
Cash flow (used in) provided
by operating and financing 124,816 38,377 536,720 (106,647)
------------------------------------------------------------------------
Investing activities
Property, plant and
equipment expenditures (107,112) (86,320) (315,698) (224,229)
Petroleum and natural
gas property acquisitions (50,814) (228) (322,598) (228)
Proceeds on sale of property,
plant and equipment 14,240 45,937 61,939 317,792
Change in non-cash investing
working capital (note 12) 18,916 2,347 27,349 14,828
Discontinued operations (46) (113) 12,288 (1,516)
------------------------------------------------------------------------
Cash flow used in
investing activities (124,816) (38,377) (536,720) 106,647
------------------------------------------------------------------------
Increase (decrease) in cash - - - -
Cash, beginning of period - - - -
------------------------------------------------------------------------
Cash, end of period $ - $ - $ - $ -
------------------------------------------------------------------------
------------------------------------------------------------------------

See accompanying notes to consolidated financial statements.


NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited as at and for the three months ended December 31, 2004)
(all tabular amounts expressed in thousands of dollars)


1. Summary of Significant Accounting Policies

Paramount Resources Ltd. ("Paramount" or the "Company") is an
independent Canadian energy company involved in the exploration,
development, production, processing, transportation and marketing of
natural gas and oil. The Company's principal properties are located in
Alberta, the Northwest Territories and British Columbia in Canada. The
Company also has properties in Saskatchewan and offshore the East Coast
in Canada, and in Montana and North Dakota in the United States. The
consolidated financial statements are stated in Canadian dollars and
have been prepared by management in accordance with Canadian generally
accepted accounting principles (GAAP), which differ in some respects
from GAAP in the United States. These differences are quantified in note
17.

The timely preparation of the financial statements in conformity with
GAAP requires that Management make estimates and assumptions and use
judgment regarding assets, liabilities, revenue and expenses. Such
estimates primarily relate to unsettled transactions and events as of
the date of the financial statements. Accordingly, actual results could
differ from those estimates.

(a) PRINCIPLES OF CONSOLIDATION

The Consolidated Financial Statements include the accounts of Paramount
Resources Ltd. and its subsidiaries, and are presented in accordance
with Canadian generally accepted accounting principles.

Investments in jointly controlled companies, jointly controlled
partnerships (collectively called "affiliates") and unincorporated joint
ventures are accounted for using the proportionate consolidation method,
whereby the Company's proportionate share of revenues, expenses, assets
and liabilities are included in the accounts.

Investments in companies and partnerships in which the Company does not
have direct or joint control over the strategic operating, investing and
financing decisions, but does have significant influence on them, are
accounted for using the equity method.

(b) JOINT OPERATIONS

Certain of the Company's exploration, development and production
activities related to petroleum and natural gas are conducted jointly
with others. These consolidated financial statements reflect only the
Company's proportionate interest in such activities.

(c) REVENUE RECOGNITION

Revenues associated with the sale of natural gas, crude oil, and natural
gas liquids ("NGLs") owned by the Company are recognized when title
passes from the Company to its customer.

Revenues from oil and natural gas production from properties in which
the Company has an interest with other producers are recognized on the
basis of the Company's net working interest.

(d) SHORT-TERM INVESTMENTS

Short-term investments are carried at the lower of cost and market
value. Included in short-term investments are short term deposits
bearing interest between 2.15% to 2.23%, debentures and convertible
debentures bearing interest between 6% to 8% and investments in the
common shares and Trust units.

(e) PROPERTY, PLANT AND EQUIPMENT

Cost

Property, plant and equipment are recorded at cost. The Company follows
the successful efforts method of accounting for petroleum and natural
gas operations. Under this method the Company capitalizes only those
costs that result directly in the discovery of petroleum and natural gas
reserves.

Exploratory well costs are capitalized pending further evaluation of
whether economically recoverable reserves have been found of a
sufficient quantity to justify completion of the find as a producing
well. If economically recoverable reserves are not found, exploratory
well costs are expensed as dry holes. Exploratory wells in areas not
requiring major capital expenditures are evaluated for economic
viability within one year of well completion. This determination of the
success of drilling results corresponds with the time period of
reporting proved oil and gas reserves for the find. Exploratory wells
that discover economic reserves that are in areas where a major
infrastructure capital expenditure (e.g., a pipeline) would be required
before production could begin, or where the economic viability of that
major capital expenditure depends upon the successful completion of
further exploratory drilling work in the area, remain capitalized as
long as the additional exploratory drilling work is under way or firmly
planned. In these situations, the well is considered to have found
economic reserves if recoverable reserves have been found of a
sufficient quantity to justify completion of the find as a producing
well, assuming that the major infrastructure capital expenditure had
already been made. Once all additional exploratory drilling and testing
work has been completed on projects requiring major infrastructure
capital expenditures, the economic viability of the overall project is
evaluated within one year of the last exploratory well completion. If
considered to be economically viable, internal company approvals are
then obtained to move the project into the development stage. Often, the
ability to move the project into the development phase and record proved
reserves is dependent on obtaining permits and government or co-venturer
approvals, the timing of which is ultimately beyond the Company's
control. Exploratory well costs remain suspended as long as the Company
is actively pursuing such approvals and permits, and believes they will
be obtained. Once all required approvals and permits have been obtained,
the projects are moved into development stage, which corresponds with
the time period of reporting proved oil and gas reserves for the find.
For complex exploratory discoveries, it is not unusual to have
exploratory wells remain suspended on the balance sheet for several
years while the Company performs additional drilling work on the
potential oil and gas field, or seeks government or co-venturer approval
of development plans or environmental permitting.

Costs incurred to drill and equip development wells, including
unsuccessful development wells, are capitalized.

Exploration expenses, including geological and geophysical costs, lease
rentals and exploratory dry hole costs, are charged to earnings as
incurred. Leasehold acquisition costs, including costs of drilling and
equipping successful wells, are capitalized. The net costs of
unproductive exploratory wells, abandoned wells and surrendered leases
are charged to earnings in the year of abandonment or surrender. Gains
or losses are recognized on the disposition of property, plant and
equipment.

Depletion and Depreciation

Capitalized costs of proved oil and gas properties are depleted using
the unit of production method. For purposes of these calculations,
production and reserves of natural gas are converted to barrels on an
energy equivalent basis.

Successful exploratory wells and development costs are depleted over
proved developed reserves while acquired resource properties with proved
reserves are depleted over proved reserves. Acquisition costs of
probable reserves are not depleted or amortized while under active
evaluation for commercial reserves. Costs are transferred to depletable
costs as proved reserves are recognized. At the date of acquisition, an
evaluation period is determined after which any remaining probable
reserve costs associated with producing fields are transferred to
depletable costs.

Costs associated with significant development projects are not depleted
until commercial production commences. Depreciation of production
equipment, gas plants and gathering systems is provided on a
straight-line basis over their estimated useful life varying from 12 to
40 years. Depreciation of other equipment is provided on a declining
balance method at rates varying from 4 to 30 percent.

Impairment

Producing areas and significant unproved properties are assessed
annually or as economic events dictate for potential impairment. Any
impairment loss is the difference between the carrying value of the
asset and its discounted net recoverable amount.

(f) ASSET RETIREMENT OBLIGATIONS

The Company recognizes the fair value of an asset retirement obligation
in the period in which it is incurred or when a reasonable estimate of
the fair value can be made. The asset retirement costs equal to the
fair-value of the retirement obligations are capitalized as part of the
cost of the related long-lived asset and allocated to expense on a basis
consistent with depreciation and depletion. The liability associated
with the asset retirement costs is subsequently adjusted for the passage
of time which is recognized as accretion expense in the consolidated
statement of earnings. The liability is also adjusted due to revisions
in either the timing or the amount of the original estimated cash flows
associated with the liability. Actual costs incurred upon settlement of
the asset retirement obligations will reduce the asset retirement
liability to the extent of the liability recorded. Differences between
the actual costs incurred upon settlement of the asset retirement
obligations and the liability recorded are recognized in the Company's
earnings in the period in which the settlement occurs.

(g) GOODWILL

Goodwill, which represents the excess of purchase price over fair value
of net assets acquired, is not amortized and is assessed by the Company
for impairment at least annually. Goodwill has been allocated to
reporting units within the Company. Impairment is assessed based on a
comparison of the fair value of the reporting units compared to the
carrying value of the reporting units, including goodwill. Any excess of
the carrying value of the reporting units, including goodwill, over and
above its fair value is the impairment amount, and is charged to
earnings in the period identified.

(h) FOREIGN CURRENCY TRANSLATION

The Company's foreign operations are considered integrated and are
translated into Canadian dollars using the temporal method.

Monetary assets and liabilities denominated in US dollars are translated
into Canadian dollars at exchange rates in effect at the balance sheet
date. Other assets and liabilities are translated at the rates
prevailing at the respective transaction dates. Revenues and expenses
are translated at the average monthly rates prevailing during the year.
Translation gains and losses are reflected in income when incurred.

(i) FINANCIAL INSTRUMENTS

The Company periodically utilizes derivative financial instrument
contracts such as forwards, futures, swaps and options to manage its
exposure to fluctuations in petroleum and natural gas prices, the
Canadian/US dollar exchange rate and interest rates.

The Company's policy is to account for those derivative financial
instruments in which management has formally documented its risk
objectives and strategies for undertaking the hedged transaction as
hedges. For these instruments, the Company has determined that the
derivative financial instruments are effective as hedges, both at
inception and over the term of the hedging relationship, as the term to
maturity, the notional amount, the commodity price, exchange rate, and
interest rate basis of the instruments, all match the terms of the
transaction being hedged. The Company assesses the effectiveness of the
derivatives on an ongoing basis to ensure that the derivatives entered
into are highly effective in offsetting changes in fair values or cash
flows of the hedged items. The fair values of derivative financial
instruments designated as hedges are not reflected in the consolidated
financial statements. Derivative financial instruments not formally
designated as hedges are measured at fair value and recognized on the
consolidated balance sheet with changes in the fair value recognized in
earnings during the period.

(j) MEASUREMENT UNCERTAINTY

The amounts recorded for depletion and depreciation and impairment of
petroleum and natural gas properties and equipment, and for asset
retirement obligations are based on estimates of reserves, future costs,
petroleum and natural gas prices and other relevant assumptions. By
their nature, these estimates and those related to the future cash flows
used to assess impairment are subject to measurement uncertainty, and
the impact on the consolidated financial statements of future periods
could be material.

(k) INCOME TAXES

The Company follows the liability method of accounting for income taxes.
Under this method, future tax assets and liabilities are determined
based on differences between financial reporting and income tax basis of
assets and liabilities, and are measured using the enacted tax rates and
laws that will be in effect when the differences are expected to
reverse. The effect on future tax assets and liabilities of a change in
tax rates is recognized in net earnings in the period in which the
change occurs.

(l) FLOW-THROUGH SHARES

Share capital includes flow-through shares issued pursuant to certain
provisions of the Income Tax Act (Canada) (the "Act"). Under the Act,
where the proceeds are used for eligible expenditures, the related
income tax deductions may be renounced to subscribers.

As the eligible expenditures are renounced, share capital is reduced by
an amount equal to the estimated future income taxes payable by the
Company, and the estimated future income tax payable is recorded as an
increase to the future income tax liability.

(m) STOCK OPTION PLAN

The Company has a stock-based compensation plan consisting of a stock
option plan that is described in note 9.

Options granted under the Company's employee stock option plan are
issued at the current market price on the day prior to issuance. The
Company uses the intrinsic value method to account for its stock-based
compensation. Applying the intrinsic value method to account for
stock-based compensation, a liability for expected cash settlement under
the stock-based compensation plan is accrued over the vesting period of
the options, based on the difference between the exercise price of the
options and the market price of the Company's common shares. The
liability is revalued at the end of each reporting period to reflect
changes in the market price of the Company's common shares and the net
change is recognized in earnings. When options are surrendered for cash,
the cash settlement paid reduces the outstanding liability. When options
are exercised for common shares, consideration paid by the option
holders and the previously recognized liability associated with the
options are recorded as share capital.

(n) AMORTIZATION OF OTHER ASSETS

Amortization of deferred items included in Other Assets is provided for
where applicable, on a straight-line basis over their estimated useful
life.

(o) PER COMMON SHARE AMOUNTS

The Company uses the treasury stock method to determine the dilutive
effect of stock options and other dilutive instruments. This method
assumes that proceeds received from the exercise of in-the-money stock
options and other dilutive instruments are used to purchase common
shares at the average market price during the period.

2. Changes in Accounting Policies

ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2004, the Company retroactively adopted, with
restatement, the Canadian Institute of Chartered Accountants ("CICA")
recommendation on Asset Retirement Obligations, which requires liability
recognition for the fair value of retirement obligations associated with
long-lived assets. Prior to January 1, 2004, the estimated future
dismantlement and site restoration costs of natural gas and crude oil
assets were provided for using the unit-of-production method.

As a result of this change, net earnings for the year ended December 31,
2003 decreased by $1.5 million ($0.02 per share). The asset retirement
obligations liability as at December 31, 2003 increased by $40.4
million, property, plant and equipment, net of accumulated depletion,
increased by $31.1 million, and future income tax liability decreased
$3.7 million. Opening 2003 retained earnings decreased by $4.1 million
to reflect the cumulative impact of depletion expense and accretion
expense, net of the previously recognized cumulative site restoration
provision and net of related future income taxes on the asset retirement
obligations, recorded retroactively.

FINANCIAL INSTRUMENTS

The Company periodically utilizes derivative financial instrument
contracts such as forwards, futures, swaps and options to manage its
exposure to fluctuations in petroleum and natural gas prices, the
Canadian/US dollar exchange rate and interest rates. Emerging Issues
Committee Abstract 128, "Accounting for Trading, Speculative or
Non-Hedging Derivative Financial Instruments" ("EIC 128") establishes
accounting and reporting standards requiring that every derivative
instrument that does not qualify for hedge accounting be recorded in the
consolidated balance sheet as either an asset or liability measured at
fair value. Accounting Guideline 13, Hedging Relationships, ("AcG 13"),
which was effective for years beginning on or after July 1, 2003,
establishes the need for companies to formally designate, document and
assess the effectiveness of relationships that receive hedge accounting
treatment.

Prior to January 1, 2004, Paramount had designated its derivative
financial instruments as hedges. As at January 1, 2004, the Company had
elected not to designate any of its financial instruments as hedges
under AcG 13 and has fair-valued the derivatives and recognized the
gains and losses on the consolidated balance sheet and statement of
earnings. The impact on the Company's consolidated financial statements
at January 1, 2004, resulted in the recognition of financial instrument
assets with a fair value of $3.3 million, a financial instrument
liability of $1.8 million for a net deferred gain on financial
instruments of $1.5 million (note 11).

TRANSPORTATION COSTS

Effective for fiscal years beginning on or after October 1, 2003, the
CICA issued Handbook Section 1100 "Generally Accepted Accounting
Principles", which defines the sources of GAAP that companies must use
and effectively eliminates industry practice as a source of GAAP. In
prior years, it had been industry practice for companies to net
transportation charges against revenue rather than showing
transportation as a separate expense on the income statement. Beginning
January 1, 2004, the Company has recorded revenue gross of
transportation charges and a transportation expense on the statement of
earnings. Prior periods have been reclassified for comparative purposes.
This adjustment has no impact on net income or cash flow.

STOCK-BASED COMPENSATION AND OTHER STOCK-BASED PAYMENTS

The Company has an Employee Incentive Stock Option plan (the "plan").
Prior to 2004, the Company applied the fair value method to account for
its stock based compensation plan. In 2004, the Company has
prospectively adopted the intrinsic value method to account for its
stock-based compensation (see note 9).

3. Acquisition of Oil and Gas Properties

$185 MILLION ASSET ACQUISITION

On June 30, 2004, the Company completed an agreement to acquire oil and
natural gas assets for $185.1 million, after adjustments. The assets
acquired by the Company are located in the Kaybob area in central
Alberta, in the Fort Liard area in the Northwest Territories and in
northeast British Columbia. The properties acquired are adjacent to, or
nearby, the Company's existing properties in Kaybob and Fort Liard. The
Company has assigned the entire amount of the purchase price to
property, plant and equipment and has recognized a $26.8 million asset
retirement obligation liability related to those properties.



The following table summarizes the fair value of the net assets
acquired:

------------------------------------------------------------------------
Property, plant and equipment $ 211,947
Less: Asset retirement obligation 26,847
------------------------------------------------------------------------
$ 185,100
------------------------------------------------------------------------
------------------------------------------------------------------------


$87 MILLION ASSET ACQUISITION

On August 16, 2004, Paramount completed the acquisition of assets in the
Marten Creek area in Grande Prairie for $86.9 million, after
adjustments. The asset retirement obligations associated with these
assets is $2.1 million. In accounting for the acquisition, the Company
recorded a future tax asset in the amount of $89.0 million.

4. Disposition Of Assets To Paramount Energy Trust

During the first quarter of 2003, the Company completed the formation
and structuring of Paramount Energy Trust (the "Trust") through the
following transactions:

a) On February 3, 2003, Paramount transferred to the Trust natural gas
properties in the Legend area of Northeast Alberta for net proceeds of
$28 million and 9,907,767 units of the Trust.

b) On February 3, 2003, Paramount declared a dividend-in-kind of $51
million, consisting of an aggregate of 9,907,767 units of the Trust. The
dividend was paid to shareholders of Paramount's common shares of record
on the close of business on February 11, 2003.

c) On March 11, 2003, in conjunction with the closing of a rights
offering by the Trust, Paramount disposed of additional natural gas
properties in Northeast Alberta to Paramount Operating Trust for net
proceeds of $167 million.

As the transfer of the Initial Assets and the Additional Assets
(collectively the "Trust Assets") represented a related party
transaction not in the normal course of operations involving two
companies under common control, the transaction has been accounted for
at the net book value of the Trust Assets as recorded in the Company.
Details are as follows:



------------------------------------------------------------------------
Natural gas properties $ 244,433
Future income tax liability 4,070

Site restoration liability (5,900)
Costs of disposition 10,430

Charge to retained earnings (6,638)
------------------------------------------------------------------------
Net proceeds on disposition $ 246,395
------------------------------------------------------------------------
------------------------------------------------------------------------


In connection with the creation and financing of the Trust and the
transfer of natural gas properties to the Trust, the Company incurred
costs of approximately $10.4 million. These costs have been included as
a cost of disposition.

During 2003, the Company disposed of a minor non-core property to the
Trust. The related party transaction was accounted for at the net book
value of the assets, with a charge to retained earnings of $0.3 million.

5. Discontinued Operations

On July 27, 2004, Wilson Drilling Ltd. ("Wilson"), a private drilling
company in which Paramount owns a 50 percent equity interest, closed the
sale of its drilling assets for $32 million to a publicly traded Income
Trust. The gross proceeds were $19.2 million cash with the balance in
exchangeable shares. The exchangeable shares are valued at the fair
market value of the purchasers' shares and can be redeemed for trust
units in the Income Trust subject to customary securities laws and
regulations. In connection with the closing of the sale, certain
indebtedness related to these operations has been extinguished. For
reporting purposes, the results of operations, property, plant and
equipment, and the current and long-term debt have been presented as
discontinued operations. Prior period financial statements have been
reclassified to reflect this change.

On September 10, 2004, Paramount completed the disposition of its 99
percent interest in Sheetah Wilson Drilling Partnership for
approximately $1.0 million. For reporting purposes, the drilling
partnership has been accounted for as discontinued operations.

On December 13, 2004, Paramount completed the disposition of a building
acquired as part of the Summit acquisition, for approximately $10.5
million, inclusive of the mortgage assumed by the purchaser of $6.4
million.

Selected financial information of the discontinued operations for the
year ended December 31, 2004:



Wilson Shehtah Wilson
Drilling Drilling
Ltd. Partnership
2004 2003 2004 2003
------------------------------------------------------------------------
Revenue
Other Income $ 908 $ 1,390 $ 327 $ 622
------------------------------------------------------------------------
Expenses
Interest 250 319 - -
General and administrative 642 270 384 496
Depreciation 655 898 6 6
(Gain) loss on sale of
property and equipment (6,659) 20 (27) -
------------------------------------------------------------------------
(5,112) 1,507 363 502
------------------------------------------------------------------------
Net earnings (loss) before
income tax 6,020 (117) (36) 120
Large Corporation Tax and other 1,857 - - -
Future income tax expense
(recovery) 94 324 - -
------------------------------------------------------------------------
Net earnings (loss) from
discontinued operations $ 4,069 $ (441) $ (36) $ 120
------------------------------------------------------------------------
------------------------------------------------------------------------


Building Total
2004 2003 2004 2003
------------------------------------------------------------------------
Revenue
Other Income $ - $ - $ 1,235 $ 2,012
------------------------------------------------------------------------
Expenses -
Interest 367 383 617 702
General and administrative (308) (1,133) 718 (367)
Depreciation 278 300 939 1,204
(Gain) loss on sale of
property and equipment (2,569) - (9,255) 20
------------------------------------------------------------------------
(2,232) (450) (6,981) 1,559
------------------------------------------------------------------------
Net earnings (loss) before
income tax 2,232 450 8,216 453
Large Corporation Tax and other (34) 186 1,823 186
Future income tax expense
(recovery) 20 - 114 324
------------------------------------------------------------------------
Net earnings (loss) from
discontinued operations $ 2,246 $ 264 $ 6,279 $ (57)
------------------------------------------------------------------------
------------------------------------------------------------------------

Selected financial information of the discontinued operations for the
three months ended December 31, 2004:

Wilson Shehtah Wilson
Drilling Drilling
Ltd. Partnership
2004 2003 2004 2003
------------------------------------------------------------------------
Revenue
Other Income $ 10 $ 476 $ - $ 276
------------------------------------------------------------------------
Expenses
Interest - 188 - -
General and administrative 477 (26) - 89
Depreciation 3 228 - 2
(Gain) loss on sale of
property and equipment 78 20 7 -
------------------------------------------------------------------------
558 410 7 91
------------------------------------------------------------------------
Net earnings (loss) before
income tax (548) 66 (7) 185
Large Corporation Tax and other 320 - - -
Future income tax expense
(recovery) - 90 - -
------------------------------------------------------------------------
Net earnings (loss) from
discontinued operations $ (868) $ (24) $ (7) $ 185
------------------------------------------------------------------------
------------------------------------------------------------------------


Building Total
2004 2003 2004 2003
------------------------------------------------------------------------
Revenue
Other Income $ - $ - $ 10 $ 752
------------------------------------------------------------------------
Expenses
Interest 66 103 66 291
General and administrative 474 (326) 951 (263)
Depreciation 51 76 54 306
(Gain) loss on sale of
property and equipment (2,569) - (2,484) 20
------------------------------------------------------------------------
(1,978) (147) (1,413) 354
------------------------------------------------------------------------
Net earnings (loss) before
income tax 1,978 147 1,423 398
Large Corporation Tax and other (29) 171 291 171
Future income tax expense
(recovery) 12 (72) 12 18
------------------------------------------------------------------------
Net earnings (loss) from
discontinued operations $ 1,995 $ 48 $ 1,120 $ 209
------------------------------------------------------------------------
------------------------------------------------------------------------


Wilson Shehtah Wilson
Drilling Drilling
Ltd. Partnership
Dec-31 Dec-31 Dec-31 Dec-31
2004 2003 2004 2003
------------------------------------------------------------------------
Current Assets
Accounts Receivable $ - $ - $ - $ 1,653
Prepaid Expenses - - - 27
Property, plant and equipment, net - 3,234 - 62
Current Liabilities
Accounts payable and accrued
liabilities - - - 1,005
Current portion of long-term debt - 1,138 - -
Long-term debt $ - $ 3,456 $ - $ -
------------------------------------------------------------------------
------------------------------------------------------------------------


Building Total
Dec-31 Dec-31 Dec-31 Dec-31
2004 2003 2004 2003
------------------------------------------------------------------------
Current Assets
Accounts Receivable $ - $ - $ - $ 1,653
Prepaid Expenses - - - 27
Property, plant and equipment, net - 8,097 - 11,393
Current Liabilities
Accounts payable and accrued
liabilities - - - 1,005
Current portion of long-term debt - 312 - 1,450
Long-term debt $ - $ 6,418 $ - $ 9,874
------------------------------------------------------------------------
------------------------------------------------------------------------


6. Property Plant and Equipment

2004 2003

Accumulated Accumulated
Depletion and Depletion and
Cost Depreciation Cost Depreciation
------------------------------------------------------------------------
(restated - note 2 and 5)
Petroleum and
natural gas
properties $ 1,351,950 $ 450,518 $ 986,919 $ 307,156
Gas plants,
gathering
systems and
production
equipment 548,838 127,724 436,772 101,120

Other 32,316 9,056 20,448 9,949
Assets held
for sale - - 14,865 3,472
------------------------------------------------------------------------
$ 1,933,104 $ 587,298 $ 1,459,004 $ 421,697
------------------------------------------------------------------------
Net book value $ 1,345,806 $ 1,037,307
------------------------------------------------------------------------
------------------------------------------------------------------------


Capital costs associated with non-producing petroleum and natural gas
properties totaling approximately $300 million (2003 - $209 million) are
currently not subject to depletion.

For the year ended December 31, 2004, the Company expensed $24.7 million
in dry hole costs (2003 - $36.6 million). A portion of the dry hole
costs expensed related to prior year capital projects that were
determined in the current year to have no future economic value.

For the year ended December 31, 2004, the Company recorded a provision
of $ nil (2003 - $10.4 million) in respect of impairment of petroleum
and natural gas properties.

7. Asset Retirement Obligations

The following table presents the reconciliation of the beginning and
ending aggregate carrying amount of the obligation associated with the
retirement of the Company's oil and gas properties.



Year Ended Year Ended
December 31, 2004 December 31, 2003
------------------------------------------------------------------------
Asset Retirement Obligations,
Beginning of Year $ 61,554 53,625
Liabilities Incurred 36,812 3,885
Liabilities Settled (3,800) -
Accretion Expense 6,920 4,044
------------------------------------------------------------------------
Asset Retirement Obligations,
End of Year $ 101,486 61,554
------------------------------------------------------------------------
------------------------------------------------------------------------


The undiscounted asset retirement obligations at December 31, 2004 are
$136.2 million (December 31, 2003 - $104.8 million). The Company's
credit-adjusted risk-free rate is 7.875 percent. These obligations will
be settled based on the useful life of the underlying assets, the
majority of which are not expected to be paid for several years, or
decades, in the future and will be funded from general company resources
at the time of removal.



8. Long-Term Debt

As at December 31, long-term debt was comprised of:

2004 2003
------------------------------------------------------------------------
(restated -
notes 2 and 5)
7 7/8% U.S. Senior Notes due 2010
(US $133.3 million) $ 160,174 $ 226,887
8 7/8% US Senior Notes due 2014
(US $81.3 million) 97,662 -
Credit facility - current interest rate of
3.8% (2003 - 4.5%) 201,305 60,350
------------------------------------------------------------------------
$ 459,141 $ 287,237
------------------------------------------------------------------------
------------------------------------------------------------------------


Senior Notes

The Company issued US $175 million of 7 7/8 percent Senior Notes due
2010 on October 27, 2003. Interest on the notes is payable
semi-annually, beginning in 2004. The Company may redeem some or all of
the notes at any time after November 1, 2007 at redemption prices
ranging from 100 percent to 103.938 percent of the principal amount,
plus accrued and unpaid interest to the redemption date, depending on
the year in which the notes are redeemed. In addition, the Company may
redeem up to 35 percent of the notes prior to November 1, 2006 at
107.875 percent of the principal amount, plus accrued interest to the
redemption date, using the proceeds of certain equity offerings. The
notes are unsecured and rank equally with all of the Company's existing
and future senior unsecured indebtedness. The Company incurred $7.4
million of financing charges related to the issuance of the Senior
Notes. The financing charges are capitalized to other assets and
amortized straight line over the term of the notes.

On June 29, 2004, the Company issued US $125 million 8 7/8 percent
Senior Notes due 2014. Interest on the notes is payable semi-annually,
beginning in 2005. The Company may redeem some or all of the notes at
any time after July 15, 2009, at redemption prices ranging from 100
percent to 104.438 percent of the principal amount, plus accrued and
unpaid interest to the redemption date, depending on the year in which
the notes are redeemed. In addition, the Company may redeem up to 35
percent of the notes prior to July 15, 2007, at 108.875 percent of the
principal amount, plus accrued interest to the redemption date, using
the proceeds of certain equity offerings. The notes are unsecured and
rank equally with all the Company's existing and future senior unsecured
indebtedness. The Company incurred $4.8 million of financing charges
related to the issuance of the Senior Notes. The financing charges
related to the issuance of the Senior Notes are capitalized to other
assets and amortized straight line over the term of the notes.

On December 30, 2004, pursuant to Paramount's 7 7/8 percent and 8 7/8
percent Senior Notes, Paramount redeemed US $41.7 million aggregate
principal amount of its 7 7/8 percent Senior Notes due 2010 and US $43.8
million aggregate principal amount of its 8 7/8 percent Senior Notes due
2014. The redemption price was US $1,078.75 per US $1,000 principal
amount of the 7 7/8 percent Senior Notes and US $1,088.75 per US $1,000
principal amount of the 8 7/8 percent Senior Notes plus, in each case,
accrued and unpaid interest on the amount being redeemed to the
redemption date. The premium paid on redemption of the notes of US $7.2
million was charged to earnings. The realized foreign exchange gain on
redemption was $7.2 million. Other assets decreased by $3.1 million to
reflect the reduction in deferred financing costs upon redemption of the
Senior Notes.

Credit Facility

As at December 31, 2004, the Company had a $270 million committed
revolving/non-revolving term facility with a syndicate of Canadian
banks. Borrowings under the facility bear interest at the lender's prime
rate, banker's acceptance, or LIBOR rate plus an applicable margin
dependent on certain conditions. The revolving nature of the facility is
due to expire on March 31, 2005. The Company has requested and received
approval for an extension on the revolving credit facility of 364 days.
Advances drawn on the facility are secured by a fixed charge over the
assets of the Company.

In February 2005, the Company's borrowing capacity under this facility
was increased to $330 million as a result of the Company's Senior Notes
redemption on December 30, 2004, and an increase in the value of its oil
and natural gas reserves.

The Company has letters of credit totaling $28.1 million (December 31,
2003 - $10.3 million) outstanding with a Canadian chartered bank. These
letters of credit reduce the amount available under the Company's
working capital facility.

9. Share Capital

AUTHORIZED CAPITAL

The authorized capital of the Company is comprised of an unlimited
number of non-voting preferred shares without nominal or par value,
issuable in series, and an unlimited number of common shares without
nominal or par value.



Common Shares Number Consideration
------------------------------------------------------------------------
Balance December 31, 2002 59,458,600 $ 190,193
------------------------------------------------------------------------
Stock options exercised during the year 710,000 10,317
Shares repurchased - at carrying value (74,000) (236)
------------------------------------------------------------------------
Balance December 31, 2003 60,094,600 $ 200,274
------------------------------------------------------------------------
Shares repurchased - at carrying value (1,629,500) (5,322)
Stock options exercised 220,500 3,057
Common shares issued, net of issuance costs 2,500,000 54,901
Flow through shares issued, net of issuance
costs 2,000,000 57,981
Tax adjustment on share issuance costs and
flow-through share renunciations - (7,959)
------------------------------------------------------------------------
Balance December 31, 2004 63,185,600 $ 302,932
------------------------------------------------------------------------
------------------------------------------------------------------------


ISSUED CAPITAL

The Company instituted a Normal Course Issuer Bid to acquire a maximum
of five percent of its issued and outstanding shares which commenced May
15, 2003 and expired May 14, 2004. Between January 1, 2004 and May 14,
2004, 1,629,500 shares were purchased pursuant to the plan at an average
price of $11.91 per share. For the year ended December 31, 2004, $14.1
million has been charged to retained earnings related to the share
repurchase price in excess of the carrying value of the shares.

On October 15, 2004, Paramount completed the private placement of
2,000,000 common shares issued on a "flow-through" basis at $29.50 per
share. The gross proceeds of the issue were $59 million. As at December
31, 2004, the Company had made renunciations of $23.7 million.

On October 26, 2004, Paramount completed the issuance of 2,500,000
common shares at a price of $23.00 per share. The gross proceeds of the
issue were $57.5 million.

Between January 1, 2005 and February 25, 2005, 70,200 stock options
exercised for cash consideration of $1.8 million. Another 707,200 stock
options were exercised for shares which will reduce the stock based
compensation liability by approximately $10.4 million.

STOCK OPTION PLAN

The Company has an Employee Incentive Stock Option plan (the "plan").
Under the plan, stock options are granted at the current market price on
the day prior to issuance. Participants in the plan, upon exercising
their stock options, may request to receive either a cash payment equal
to the difference between the exercise price and the market price of the
Company's common shares or common shares issued from Treasury.
Irrespective of the participant's request, the Company may choose to
only issue common shares. Cash payments made in respect of the plan are
charged to general and administrative expenses when incurred. Options
granted vest over four years and have a four and a half year contractual
life.

As at December 31, 2004, 5.0 million shares were reserved for issuance
under the Company's Employee Incentive Stock Option Plan, of which 3.2
million options are outstanding, exercisable to May 31, 2009, at prices
ranging from $8.91 to $26.29 per share.



Stock options 2004 2003
------------------------------------------------------------------------
Average Average
Grant Price Options Grant Price Options
------------------------------------------------------------------------
Balance, beginning
of year $ 9.64 3,632,000 $ 14.25 1,949,500
Granted 17.09 348,000 9.66 2,998,000
Exercised 9.97 (618,500) 14.29 (791,000)
Cancelled 9.09 (149,000) 10.30 (524,500)
------------------------------------------------------------------------
Balance, end of year $ 10.41 3,212,500 $ 9.64 3,632,000
------------------------------------------------------------------------
Options exercisable,
end of year $ 10.26 1,282,875 $ 10.72 1,087,875
------------------------------------------------------------------------
------------------------------------------------------------------------


The formation of Paramount Energy Trust (note 4) resulted in the Company
re-pricing stock options. 941,500 stock options issued in 2001, the
majority of which were at exercise prices of $14.50 and $13.35 per
option, were re-priced to exercise prices of $10.22 and $9.07 per
option, respectively.



The following summarizes information about stock options outstanding
at December 31, 2004:

Weighted Weighted Weighted
Average Average Average
Exercise Contractual Exercise Exercisable Exercise
Prices Number Life Price Number Price
------------------------------------------------------------------------
$8.91-9.80 2,088,000 3 $ 9.02 561,375 $ 9.00
$10.01-12.02 820,500 1 11.04 721,500 11.25
$12.51-26.29 304,000 4 18.01 - -
------------------------------------------------------------------------
Total 3,212,500 2 $ 10.41 1,282,875 $ 10.26
------------------------------------------------------------------------
------------------------------------------------------------------------


During 2004, the Company paid $2.9 million (2003 - less than $0.1
million) related to stock options exercised for cash.

FAIR VALUES

In 2004, the Company prospectively adopted the intrinsic value method to
account for its stock-based compensation. The Company recognized
compensation costs related to stock options issued and outstanding of
$41.2 million (2003 - $1.2 million).

Prior to 2004, the fair values of common share options granted were
estimated as at the grant date using the Black-Scholes option pricing
model. The weighted average fair value of the options granted during
2003 was $3.42, calculated using a risk-free rate of 5.8 percent, an
estimated life of 4 years and an estimated volatility of 39 percent.

PER SHARE INFORMATION

Basic earnings per share are calculated based on a weighted average
number of common shares of 59,755,480 (2003 - 60,098,447). There are no
anti-dilutive options at December 31, 2004.



10. Income Taxes

The income tax provision differs from the expected income taxes
obtained by applying the Canadian corporate tax rate to earning (loss)
before taxes as follows:

2004 2003
------------------------------------------------------------------------
Corporate tax rate 39.04% 40.67%
Calculated income tax expense (recovery) $ 32,150 $ (24,233)
Increase (decrease) resulting from:
Non-deductible Crown charges,
net of Alberta Royalty Tax Credit 25,455 21,991
Federal resource allowance (21,787) (17,124)
Federal and provincial income tax
rate adjustment 481 (30,257)
Attributed Canadian Royalty Income recognized (1,469) (5,228)
Large Corporations Tax and other 6,795 2,875
Non-taxable portion of gain on sale of
investments (4,301) -
Stock based compensation 3,205 -
Recognition of tax pools not previously
recognized - (3,343)
Other 6,926 (5,473)
------------------------------------------------------------------------
Income tax expense (recovery) $ 47,455 $ (60,792)
------------------------------------------------------------------------
------------------------------------------------------------------------

COMPONENTS OF FUTURE INCOME TAXES

The net future tax liability comprises: 2004 2003
------------------------------------------------------------------------
Differences between tax base and reported
amounts of depreciable assets $ 215,583 $ 227,697
Asset retirement obligation (34,281) (23,486)
Stock-based compensation liability (12,405)
Other (2,517) 2,473
------------------------------------------------------------------------
$ 166,380 $ 206,684
------------------------------------------------------------------------
------------------------------------------------------------------------


11. Financial Instruments

As disclosed in note 2, on January 1, 2004, the fair value of all
outstanding financial instruments that were no longer designated as
accounting hedges, were recorded on the consolidated balance sheet with
an offsetting net deferred gain. The net deferred gain is recognized
into net earnings over the life of the associated contracts.

The changes in fair value associated with the financial instruments are
recorded on the consolidated balance sheets with the associated
unrealized gain or loss recorded in net earnings. The estimated fair
value of all financial instruments is based on quoted prices or, in the
absence of quoted prices, third party market indications and forecasts.



The following tables present a reconciliation of the change in the
unrealized and realized gains and losses on financial instruments from
January 1, 2004 to December 31, 2004.

December 31, 2004
------------------------------------------------------------------------
Financial instrument asset $ 21,564
Financial instrument liability (2,188)
------------------------------------------------------------------------
Net financial instrument asset $ 19,376
------------------------------------------------------------------------
------------------------------------------------------------------------



Three Months Ended Year Ended
December 31, 2004 December 31, 2004
------------------------------------------------------------------------
Net Mark-to Net Mark-to
Deferred Market Deferred Market
Amounts on Gain Amounts on Gain
Transition (Loss) Total Transition (Loss) Total
------------------------------------------------------------------------
Fair value of
contracts,
January 1,
2004 $ - $ - $ - $ (1,450) $ 1,450 $ -
------------------------------------------------------------------------
Change in
fair value of
contracts
recorded on
transition,
still
outstanding
at December
31, 2004 - 8,469 8,469 - 1,301 1,301
------------------------------------------------------------------------
Amortization
of the fair
value of
contracts as
at December
31, 2004 267 - 267 (196) - (196)
------------------------------------------------------------------------
Fair value
of contracts
entered into
during the
period - 13,827 13,827 - 18,271 18,271
------------------------------------------------------------------------
Unrealized gain
on financial
instruments $ 267 $22,296 $22,563 $ (1,646) $21,022 $19,376
------------------------------------------------------------------------
Realized gain
(loss) on
financial
instruments
for the period
ended December
31, 2004 4,856 (683)
------------------------------------------------------------------------
Net gain on
financial
instruments
for the
period ended
December
31, 2004 $27,419 $18,693
------------------------------------------------------------------------
------------------------------------------------------------------------


(a) INTEREST RATE CONTRACTS

On June 6, 2004, the Company entered into a fixed to floating interest
rate swap. The fair value of this contract as at December 31, 2004, was
a gain of $3.3 million.

Description
of Swap Maturity Notional Indenture Effective
Transaction Date Amount Interest Swap to Rate
------------------------------------------------------------------------
Swap of 7.875 November US$175 US$ fixed US$ US$ LIBOR
percent US$ 1, 2010 million floating plus 320
Senior Notes Basis Points
------------------------------------------------------------------------
------------------------------------------------------------------------


(b) FOREIGN EXCHANGE CONTRACTS

The Company has entered into the following currency index swap
transactions, fixing the exchange rate on receipts of US $1 million each
month at CDN $1.4337, expiring December 31, 2005. The US$/CDN$ closing
exchange rate was 1.2020 as at December 31, 2004 (December 31, 2003 -
1.2965).



Year of settlement US dollars Weighted average exchange rate
------------------------------------------------------------------------
2005 12,000 1.4337
------------------------------------------------------------------------
------------------------------------------------------------------------


At January 1, 2004, the Company recorded a deferred gain on financial
instruments of $3.3 million related to existing foreign exchange
contracts. The fair value of these contracts at December 31, 2004, was a
gain of $2.7 million. The change in fair value, a $0.6 million loss, and
$1.6 million amortization of the deferred gain have been recorded in the
consolidated statement of earnings.

During November 2004, the Company entered into a series of US$/CDN$
put/call options. The fair value of these contracts as at December 31,
2004 was a gain of $0.8 million.



Foreign Exchange
Put/Call Strike Option Currencies Notional - CDN$ Expiry Date
------------------------------------------------------------------------
Put 1.2048 USD/CDN $ 60,240,000 January 12, 2005
Call 1.1765 USD/CDN $ 58,825,000 January 12, 2005
Put 1.1976 USD/CDN $ 59,880,000 January 10, 2005
Call 1.1628 USD/CDN $ 58,140,000 January 10, 2005
------------------------------------------------------------------------

(c) COMMODITY PRICE CONTRACTS

At December 31, 2004, the Company has entered into financial forward
contracts as follows:

Amount Price Term
------------------------------------------------------------------------
Sales Contracts

NYMEX Fixed Price 10,000 MMbtu/d US $6.41 November 2004 - March 2005
NYMEX Fixed Price 10,000 MMbtu/d US $7.46 November 2004 - March 2005
NYMEX Fixed Price 10,000 MMbtu/d US $7.95 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $7.90 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $8.03 November 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $7.60 November 2004 - March 2005
NYMEX Call Option 20,000 MMbtu/d US $10.00
Strike December 2004 - March 2005
AECO Fixed Price 20,000 GJ/d $6.28 April 2005 - June 2005
AECO Fixed Price 20,000 GJ/d $6.30 April 2005 - June 2005
AECO Fixed Price 20,000 GJ/d $6.80 April 2005 - June 2005


Purchase Contracts

AECO Fixed Price 20,000 GJ/d $6.76 November 2004 - March 2005
------------------------------------------------------------------------


The fair values of these contracts as at December 31, 2004 was a $14.2
million gain.

At January 1, 2004, the Company recorded a deferred loss on financial
instruments of $1.8 million related to existing forward commodity price
contracts. The deferred loss has been fully amortized as at December 31,
2004.

(d) FAIR VALUES OF FINANCIAL ASSETS AND LIABILITIES

Borrowings under bank credit facilities and the issuance of commercial
paper are for short periods and are market rate based, thus, carrying
values approximate fair value. Fair values for derivative instruments
are determined based on the estimated cash payment or receipt necessary
to settle the contract at year-end. Cash payments or receipts are based
on discounted cash flow analysis using current market rates and prices
available to the Company.

(e) CREDIT RISK

The Company is exposed to credit risk from financial instruments to the
extent of non-performance by third parties, and non-performance by
counterparties to swap agreements. The Company minimizes credit risk
associated with possible non-performance by financial instrument
counterparties by entering into contracts with only highly rated
counterparties and controls third party credit risk with credit
approvals, limits on exposures to any one counterparty, and monitoring
procedures. The Company sells production to a variety of purchasers
under normal industry sale and payment terms. The Company's accounts
receivable are with customers and joint venture partners in the
petroleum and natural gas industry and are subject to normal credit risk.

(f) INTEREST RATE RISK

The Company is exposed to interest rate risk to the extent that changes
in market interest rates will impact the Company's debts that have a
floating interest rate.

12. Change In Non-Cash Working Capital



2004 2003
------------------------------------------------------------------------
Change in non-cash working capital:
Short-term investments $ (10,532) $ (283)
Accounts receivable (25,480) 6,859
Prepaid expenses (978) 1,829
Accounts payable and accrued liabilities 37,019 (26,958)
Discontinued operations - (201)
------------------------------------------------------------------------
29 (18,754)
------------------------------------------------------------------------
Operating activities (27,320) (33,582)
Investing activities 27,349 14,828
------------------------------------------------------------------------
$ 29 $(18,754)
------------------------------------------------------------------------
------------------------------------------------------------------------


Certain changes in non-cash working capital which were incurred as a
result of asset dispositions during the year have been excluded from the
above amounts.

Amounts paid during the year related to interest and Large Corporations
and other taxes were as follows:



2004 2003
------------------------------------------------------------------------
Interest paid $ 18,951 $ 17,497
Large Corporations and other taxes paid including
settlements $ 31,021 $ 2,395
------------------------------------------------------------------------
------------------------------------------------------------------------


13. Related Party Transactions

DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST

On December 13, 2004, the Company completed the disposition of a
building to Paramount Energy Trust. The transaction has been recorded at
the exchange amount. The Company received proceeds of $10.5 million,
inclusive of the mortgage assumed by the purchaser of $6.4 million.

In the first quarter of 2003, the Company sold certain natural gas
assets in Northeast Alberta to the Trust, a related party. The
transaction (see note 4), was accounted for at the net book value of the
assets as recorded in the Company.

14. Contingencies And Commitments

CONTINGENCIES

The Company is party to various legal claims associated with the
ordinary conduct of business. The Company does not anticipate that these
claims will have a material impact on the Company's financial position.

The Company indemnifies its directors and officers against any and all
claims or losses reasonably incurred in the performance of their service
to the Company to the extent permitted by law. The Company has acquired
and maintains liability insurance for its directors and officers.

COMMITMENTS

As at December 31, 2004, the Company has the following pipeline
transportation commitments:



Year Commitment
------------------------------------------------------------------------
2005 $ 22,015
2006 21,252
2007 21,252
2008 21,252
2009 20,823
Thereafter 130,611
------------------------------------------------------------------------
$ 237,205
------------------------------------------------------------------------
------------------------------------------------------------------------


At December 31, 2004, the Company has entered into the following
physical delivery natural gas contracts:



Amount Price Term
------------------------------------------------------------------------
Sales Contracts
Station 2 Fixed Price 8,000 GJ/d $7.99 November 2004 - March 2005
Station 2 Fixed Price 12,000 GJ/d $8.00 November 2004 - March 2005
------------------------------------------------------------------------
------------------------------------------------------------------------


15. Comparative Figures

Certain comparative figures have been reclassified to conform to the
current year's financial statement presentation.

16. Subsequent Events

TRUST SPINOUT

On September 27, 2004, the Board of Directors of Paramount authorized
management of Paramount to undertake an examination of possible
corporate restructuring alternatives available to Paramount to increase
shareholder value, including but not limited to: maintaining the status
quo and continuing Paramount's strategic direction as an independent oil
and natural gas exploration and development company, and reorganizing
Paramount, either in whole or in part, into an energy trust.

On December 13, 2004, Paramount announced that its board of directors
had unanimously approved a proposed reorganization which would result in
Paramount's shareholders receiving in exchange for their Common Shares,
one New Common Share of Paramount and one Trust Unit of the Trust,
Trilogy Energy Trust ("Trilogy").

Trilogy will indirectly own certain of Paramount's existing assets. The
assets intended to become indirectly owned by Trilogy, referred to as
the "Spinout Assets," are located in the Kaybob and Marten Creek areas
of Alberta.

In order to implement any proposed reorganization of Paramount, the
Company required the consent of the majority holders of each of its 2010
Notes in the aggregate principal amount of US $175 million and its 2014
Notes in the aggregate principal amount of US $125 million. Consent from
note holders was obtained on February 7, 2005.

A special meeting of securityholders required for approval of the
spinout transaction has been scheduled on March 28, 2005. The Trust
Spinout is to be effected through an arrangement under the Business
Corporations Act (Alberta) and Paramount obtained an interim order from
the Court of Queen's Bench of Alberta regarding the meeting on February
28, 2005.

NOTES OFFERING

On February 7, 2005, Paramount completed the Notes Offer, as amended,
issuing US $213,593,000 principal amount of 2013 Notes and paying
aggregate cash consideration of approximately US $36.2 million in
exchange for approximately 99.31 percent of the outstanding 2010 Notes
and 100 percent of the outstanding 2014 Notes. As a result, US $913,000
principal amount of the 2010 Notes and no 2014 Notes remain outstanding.

The 2013 Notes bear interest at a rate of 8 1/2 percent per year and
mature on January 31, 2013. The 2013 Notes will be secured by
approximately 80 percent of the Trust Units that will be owned by
Paramount following the completion of the Trust Spinout; however,
Paramount may sell such Trust Units provided it makes an offer to the
holders of the 2013 Notes to purchase 2013 Notes with the next proceeds
of any sales at par plus a redemption premium of up to 4 1/4 percent
depending on when the offer is made. The 2013 Notes cannot be redeemed
with proceeds of equity offerings, but Paramount may, at its option,
redeem all or part of the 2013 Notes after January 31, 2007 at par plus
a redemption premium up to 4 1/4 percent depending on when the notes are
redeemed. If holders of a majority in aggregate principal amount of the
2013 Notes provide notice on September 30, 2005 that they elect to
increase the interest rate on the 2013 Notes to 10 1/2 percent per year,
Paramount may, at its option, at any time on or prior to January 31,
2006, redeem all of the 2013 Notes at par.

GAS MARKETING LIMITED PARTNERSHIP

Paramount closed a transaction in March 2005 whereby it acquired an
indirect 25 percent ownership interest in a gas marketing limited
partnership for US$5 million. In conjunction with the acquisition of the
ownership interest, Paramount will make available for delivery an
average of 150 million GJ/d of natural gas over a five year term, to be
marketed on Paramount's behalf by the gas marketing limited partnership.

17. Reconciliation Of Financial Statements To United States Generally
Accepted Principles

The consolidated financial statements have been prepared in accordance
with Canadian GAAP. Any differences in accounting principles as they
pertain to the accompanying financial statements are not material except
as described below. The application of US GAAP would have the following
effects on the Company's historical net earnings (loss) as reported:



Year ended Year ended
December 31, 2004 December 31, 2003
------------------------------------------------------------------------
(restated - note 2
and 5)
Net earnings for the year as
reported $ 41,174 $ 1,151
Adjustments, net of tax
Forward foreign exchange
contracts and other financial
instruments(a) (1,053) 3,411
Impairments and related change
in depletion(c) 5,385 11,546
General and administrative(i) - 703
Short-term investments(f) 929 428
Future income taxes(b) (5,633)
Earnings from discontinued
operations(e) - (8,593)
------------------------------------------------------------------------
Earnings before discontinued
operations and change in
accounting policy $ 40,802 $ 8,646
------------------------------------------------------------------------
Earnings from discontinued
operations(e) - 8,593
Change in accounting policy
- Asset Retirement Obligation(d) - (4,127)

------------------------------------------------------------------------
Net earnings for the year
- US GAAP $ 40,802 $ 13,112
------------------------------------------------------------------------

Net earnings per common share
before discontinued operations
and change in accounting policy
- US GAAP
Basic $ 0.68 $ 0.14
Diluted $ 0.67 $ 0.14

Net earnings per common share
- US GAAP
Basic $ 0.68 $ 0.22
Diluted $ 0.67 $ 0.22
------------------------------------------------------------------------
------------------------------------------------------------------------


The application of US GAAP would have the following effect on the
balance sheet at December 31:



2004 2003
As Reported US GAAP As Reported US GAAP
------------------------------------------------------------------------
(restated -
notes 2 and 5)
Assets
Short-term
investments(f) $ 24,983 $ 27,149 $ 16,551 $ 17,265
Financial instrument
assets(a) 21,564 18,271 - -
Property, plant and
equipment(c)(d) 1,345,806 1,350,286 1,037,307 1,033,373

Liabilities
Accounts payable and
accrued liabilities(b) 147,508 152,893 109,334 109,334
Deferred hedging loss
(gain)(a) - - - 1,726
Financial instrument
liability(a) 2,188 542 - -
Deferred Revenue(a) - - 3,959 -
Future income
taxes(a)(b)(c)(f) 166,380 167,587 206,684 206,570

Shareholders' equity
Common shares(b) 302,932 303,180 200,274 200,274
Retained earnings $ 322,107 $ 324,253 $ 295,013 $ 298,295
------------------------------------------------------------------------
------------------------------------------------------------------------


(a) FORWARD FOREIGN EXCHANGE CONTRACTS AND OTHER FINANCIAL INSTRUMENTS

Prior to January 1, 2004, Paramount had designated, for Canadian GAAP
purposes, its derivative financial instruments as hedges of anticipated
revenue and expenses. In accordance with Canadian GAAP, payments or
receipts on these contracts were recognized in income concurrently with
the hedged transaction. Accordingly, the fair value of contracts deemed
to be hedges was not previously reflected in the balance sheet, and
changes in fair value were not reflected in earnings. As disclosed in
note 2 of the unaudited consolidated financial statements as at and for
the year ended December 31, 2004, effective January 1, 2004, the Company
has elected not to designate any of its financial instruments as hedges
for Canadian GAAP purposes, thus eliminating this US/Canadian GAAP
difference in future periods.

For US purposes, the Company has adopted Statement of Financial
Accounting Standards (''SFAS'') No. 133, as amended, "Accounting for
Derivative Instruments and Hedging Activities". With the adoption of
this standard, all derivative instruments are recognized on the balance
sheet at fair value. The statement requires that changes in the
derivative instrument's fair value be recognized currently in earnings
unless specific hedge accounting criteria are met.

Under US GAAP for the year ended December 31, 2004, the deferred
financial instrument asset of $3.3 million and the deferred financial
instrument liability of $1.8 million described in note 2 of the
consolidated financial statements as at December 31, 2004 would not be
recorded for US GAAP purposes. Amortization of the deferred financial
instrument asset and liability would be recognized in earnings under
Canadian GAAP. The remaining unamortized amount of $1.6 million (net of
tax - $1.1 million) has been reflected as a retained earnings adjustment
as this has been reflected in earnings in prior years US GAAP
reconciliations.

Under US GAAP for the year ended December 31, 2004, an additional
expense of $1.6 million (net of tax - $1.1 million) would have been
recorded to adjust for the deferred financial instruments assets and
liabilities amortization.

Under US GAAP for the year ended December 31, 2003, additional income of
$5.7 million (net of tax - $3.4 million) would have been recorded.

(b) FUTURE INCOME TAXES

The Canadian liability method of accounting for income taxes is similar
to the United States Statement of Financial Accounting Standard No. 109
''Accounting for Income Taxes'', which requires the recognition of
future tax assets and liabilities for the expected future tax
consequences of events that have been recognized in the Company's
financial statements or tax returns. Pursuant to US GAAP, enacted tax
rates are used to calculate future taxes, whereas Canadian GAAP uses
substantively enacted rates. For the years ended December 31, 2004 and
2003, this difference did not impact the Company's financial position or
results of operations except for the Company's accounting for a
flow-through share issuance in October 2004. For Canadian GAAP, upon
renunciation of tax pools, an adjustment is made to share capital and
future income tax liabilities. Under SFAS 109, the proceeds from the
issuance of flow through shares should be allocated between the offering
of shares and the sale of tax benefits. The allocation is made based on
the difference between the quoted price of the existing shares and the
amount the investor pays for the shares. A liability is recognized for
this difference. The liability is reversed when tax benefits are
renounced and a deferred tax liability is recognized at the time. Income
tax expense is the difference between the amount of the future tax
liability and the liability recognized on issuance. As at and for the
year ended December 31, 2004, share capital would increase by $0.2
million, accounts payable and accrued liabilities would increase $5.4
million, and future income tax expense would increase $5.6 million.

(c) PROPERTY, PLANT AND EQUIPMENT

Under both US and Canadian GAAP, property, plant and equipment must be
assessed for potential impairments. Under US GAAP, if the sum of the
expected future cash flows (undiscounted and without interest charges)
is less than the carrying amount of the asset, then an impairment loss
(the amount by which the carrying amount of the asset exceeds the fair
value of the asset) should be recognized. Fair value is calculated as
the present value of estimated expected future cash flows. Prior to
January 1, 2004, under Canadian GAAP, the impairment loss was the
difference between the carrying value of the asset and its net
recoverable amount (undiscounted). Effective January 1, 2004, the CICA
implemented a new pronouncement on impairment of long-lived assets,
which eliminated the US/Canadian GAAP difference going forward. For the
year ended December 31, 2004, no impairment change would be recorded and
a reduction in depletion expense of $8.4 million (net of tax - $5.4
million) would be recorded due to impairment charges recorded in fiscal
2002 and 2001. For the year ended December 31, 2003, no impairment
charge would be recorded and a reduction in depletion expense of $19.2
million (net of tax - $11.5 million) would be recorded due to impairment
charges recorded in fiscal 2002 and 2001 under US GAAP. The resulting
differences in recorded carrying values of impaired assets result in
further differences in depreciation, depletion and amortization expense
in subsequent years.

Suspended Wells

In September 2004, the EITF discussed Issue No. 04-9, "Accounting for
Suspended Well Costs," as it relates to SFAS No. 19, "Financial
Accounting and Reporting by Oil and Gas Producing Companies." SFAS No.
19 requires that the costs of exploratory wells be capitalized, or
"suspended," on the balance sheet, pending a determination of whether
potentially economic oil and gas reserves have been discovered. The
discussion centered on whether certain circumstances would permit the
continued capitalization of the costs for an exploratory well beyond one
year, in the absence of plans for another exploratory well. The EITF
removed the issue from its agenda, and requested that the FASB consider
an amendment to SFAS No. 19 to clarify when it is permissible to
continue to capitalize exploratory well costs beyond one year if (a) the
well had found a sufficient quantity of reserves to justify its
completion as a producing well, assuming the required capital
expenditures would be made, and (b) the company was making sufficient
progress assessing the reserves and the economic and operating viability
of the project. In February 2005, the FASB posted FASB Staff Position
(FSP) FAS No. 19-a, "Accounting for Suspended Well Costs," on its Web
site for comment. The proposed FSP provides for continued capitalization
past one year if a company is making sufficient progress on assessing
the reserves and the economic and operating viability of the project.
The proposed FSP also provides disclosure requirements about capitalized
exploratory well costs. We estimate that if the proposed FSP were
adopted prospectively on January 1, 2003, net income would not have
changed in 2004 or 2003. We believe that the adoption of the FSP as
proposed would not result in the write-off of any well suspended as of
December 31, 2004. We plan to continue to monitor the deliberations of
the FASB on this issue.

The following table reflects the net changes in suspended exploratory
well costs during 2004 and 2003.



(millions of dollars) 2004 2003
------------------------------------------------------------------------
Beginning balance at January 1 $ 46 $ 99
Additions pending the determination of proved reserves 110 15
Reclassifications to proved properties (24) (18)
Charged to dry hole expense (14) (23)
Wells sold during the period - (27)
------------------------------------------------------------------------
Ending balance at December 31 $ 118 $ 46
------------------------------------------------------------------------
------------------------------------------------------------------------


The following table provides an aging of capitalized exploratory well
costs based on the date the drilling was completed and the number of
wells for which exploratory well costs have been capitalized for a
period greater than one year since the completion of drilling.



(millions of dollars) 2004 2003
------------------------------------------------------------------------
Capitalized exploratory costs that have been
capitalized for a period of one year or less $ 86 $ 19
Capitalized exploratory costs that have been
capitalized for a period of greater that one year 32 27
------------------------------------------------------------------------
Balance at December 31 $ 118 $ 46
------------------------------------------------------------------------
Number of exploratory wells that have costs
capitalized for a period greater than one year 23 29
------------------------------------------------------------------------
------------------------------------------------------------------------


Included in total suspended well costs at year-end 2004 were 23 wells
totaling $32 million related to areas where major capital expenditures
and further exploratory drilling is required to classify the reserves as
proved. These costs were suspended between 1999 and 2003. At December
31, 2004, $12 million of the costs related to Colville Lake in the
Northwest Territories. The commerciality of the gas is being evaluated
in conjunction with the upcoming drilling program and the completion of
the Mackenzie Valley Gas Pipeline. The remaining $20 million relate to
projects where infrastructure decisions are dependent on environmental
permitting and production capacity, or where we are continuing to assess
reserves and their potential development. At December 31, 2004, we did
not have any amounts suspended that were associated with areas not
requiring major capital expenditures before production could begin,
where more than one year had elapsed since the completion of drilling.

(d) ASSET RETIREMENT OBLIGATIONS

Effective January 1, 2004, the Company has retroactively adopted, with
restatement, the CICA recommendations on Asset Retirement Obligations.
For US GAAP purposes, the Company has adopted SFAS No. 143, "Accounting
for Asset Retirement Obligations", effective January 1, 2003. For US
GAAP, the cumulative impact upon adoption of SFAS No. 143 for the year
ended December 31, 2003, is a $6.9 million (net of tax - $4.1 million)
charge to earnings (loss) or $0.07 per basic and diluted common share.
For Canadian GAAP purposes, upon adoption on January 1, 2004, the
retroactive effect of this pronouncement on prior years was reflected in
opening retained earnings for the earliest period presented.

(e) DISCONTINUED OPERATIONS

Under US GAAP, the transaction resulting in the disposal of the Trust
Assets to Paramount Energy Trust as described in note 4 of the
consolidated financial statements for the year-ended December 31, 2003
would be accounted for as discontinued operations as the applicable
criteria set out in SFAS 144, ''Accounting for Impairment or Disposal of
Long-Lived Assets'' had been met. Accordingly, the carrying value of the
Trust Assets is separately presented in the consolidated balance sheet.
Net income from discontinued operations for the year ended December 31,
2003 would have been $12.9 million (net of tax - $8.6 million), or $0.14
per basic and diluted common share.

(f) SHORT-TERM INVESTMENTS

Under US GAAP, equity securities that are bought and sold in the short
term are classified as trading securities. Unrealized holding gains and
losses related to trading securities are included in earnings as
incurred. Under Canadian GAAP, these gains and losses are not recognized
in earnings until the security is sold. As at December 31, 2004, the
Company had unrealized holding gains of $2.2 million (net of tax - $1.4
million). As at December 31, 2003, the Company had unrealized holding
gains of $0.7 million (net of tax - $0.4 million).

(g) OTHER COMPREHENSIVE INCOME

Under US GAAP, certain items such as the unrealized gain or loss on
derivative instrument contracts designated and effective as cash flow
hedges are included in other comprehensive income. In these financial
statements, there are no comprehensive income items other than net
earnings.

(h) STATEMENTS OF CASH FLOW

The application of US GAAP would not change the amounts as reported
under Canadian GAAP for cash flows provided by (used in) operating,
investing or financing activities, except that the consolidated
statements of cash flow include, under investing activities, changes in
working capital for items not affecting cash, such as accounts payable
related to the non-cash elements of property and equipment. For the year
ended December 31, 2004, for investing activities, there would be an
addition of $27.3 million (2003 - reduction of $14.8 million). The
presentation of cash flow from operations is a non US GAAP terminology.

(i) STOCK-BASED COMPENSATION

The Company has granted stock options to selected employees, directors
and officers. For US GAAP purposes, SFAS 123, "Accounting for
Stock-Based Compensation", requires that an enterprise recognize, or at
its option, disclose the impact of the fair value of stock options and
other forms of stock-based compensation cost.

The following table summarizes the pro forma effect on earnings had the
Company recorded the fair value of options granted:



Year ended
December 31, 2003
------------------------------------------------------------------------
Net earnings (loss) for the period - US GAAP $ 13,112
Stock-based compensation expense determined under
the fair value based method for all awards, net of
related tax effects (703)
------------------------------------------------------------------------
Pro forma net earnings - US GAAP $ 12,409
------------------------------------------------------------------------
Net earnings (loss) per common share
Basic
- as reported $ 0.22
- pro forma $ 0.21
Diluted
- as reported $ 0.22
- pro forma $ 0.21
------------------------------------------------------------------------
------------------------------------------------------------------------


Under APB Opinion 25, the re-pricing of outstanding stock options under
a fixed price stock option plan results in these options being accounted
for as variable price options from the date of the modification until
they are exercised, forfeited or expire. For the year ended December 31,
2004, there would be no impact as the Company has prospectively applied
the intrinsic value method to account for its stock based compensation.
For the year ended December 31, 2003, an additional income of $0.7
million would have been recorded as general and administrative expense
related to the re-pricing of outstanding stock options and for the year
ended December 31, 2003, $1.2 million of general and administrative
expenses related to stock options under Canadian GAAP would be reversed
as the Company has chosen not to fair value account for its options
using the fair value method under SFAS 123.

(j) BUY/SELL ARRANGEMENTS

For US GAAP, buy/sell arrangements are reported on a gross basis. For
the year ended December 31, 2004, the Company had sales of $22.2 million
(2003 - $57.5 million) and purchases of $22.0 million (2003 - $63.1
million), related to buy/sell arrangements. The net gain of $0.2 million
(2003 - $5.6 million loss) has been reflected in revenue for Canadian
GAAP purposes.



Paramount Resources Ltd,
Pro-forma Supplemental Oil and Gas Operating Statistics - unaudited
For the Period Ended December 31, 2004
(Note 1)

Sales Volumes 2004 2003
------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Gas (MMcf/d) 198 196 157 141 141 136 142 143
Oil and Natural
Gas Liquids
(Bbl/d) 8,903 8,446 6,134 5,675 5,877 7,461 7,465 7,892
------------------------------------------------------------------------
Total Sales
Volumes
(Boe/d) (6:1) 41,878 41,072 32,354 29,178 29,353 30,098 31,129 31,711
------------------------------------------------------------------------
------------------------------------------------------------------------



Per-unit Results 2004 2003
------------------------------------------------------------------------
Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1
------------------------------------------------------------------------
Produced Gas ($/Mcf)
Price, before
transporation
and selling 7.38 6.77 7.52 7.08 5.69 6.29 6.45 7.50
Transporation 0.41 0.41 0.51 0.54 0.55 0.55 0.54 0.59
Royalties 1.27 1.26 1.33 1.33 0.55 1.30 1.14 1.43
Operating
expenses, net of
processing
revenue 1.23 1.16 1.03 1.08 1.26 1.19 0.95 0.73
------------------------------------------------------------------------
Cash netback
before realized
financial
instruments 4.47 3.94 4.65 4.13 3.33 3.25 3.82 4.75
Realized
financial
instruments 0.57 (0.13) (0.31) 0.42 0.25 (0.72) (1.07) (1.62)
------------------------------------------------------------------------
Cash netback
including
realized
financial
instruments 5.04 3.81 4.34 4.55 3.58 2.53 2.75 3.13
------------------------------------------------------------------------
------------------------------------------------------------------------

Produced Oil & Natural Gas Liquids ($/Bbl)
Price, before
transporation
and selling 48.30 50.97 46.17 42.70 37.00 37.17 37.64 43.69
Transportation 0.71 0.71 0.80 0.83 0.98 0.69 0.70 0.71
Royalties 8.82 10.02 7.58 7.52 6.64 6.75 7.28 9.04
Operating
expenses, net
of processing
revenue 10.49 8.04 8.14 8.87 11.01 10.01 8.90 6.96
------------------------------------------------------------------------
Cash netback
before realized
financial
instruments 28.28 32.20 29.65 25.48 18.37 19.72 20.76 26.98
Realized
financial
instruments (3.53) (0.18) (2.75) (4.93) (3.13) (2.27) (1.67) (4.03)
------------------------------------------------------------------------
Cash netback
including
realized
financial
instruments 24.75 32.02 26.90 20.55 15.24 17.45 19.09 22.95
------------------------------------------------------------------------
------------------------------------------------------------------------

Total Produced ($/Boe)
Price, before
transporation
and selling 45.15 42.78 45.31 42.52 34.69 37.59 38.47 44.69
Transportation 2.10 2.12 2.64 2.79 2.82 2.64 2.63 2.84
Royalties 7.89 8.07 7.89 7.88 3.95 7.56 6.95 8.70
Operating
expenses, net
of processing
revenue 8.02 7.18 6.54 6.96 8.25 7.85 6.46 5.02
------------------------------------------------------------------------
Cash netback
before realized
financial
instruments 27.14 25.41 28.24 24.89 19.67 19.54 22.43 28.13
Realized
financial
instruments 1.26 (0.67) (2.03) 1.07 0.57 (3.76) (5.37) (8.33)
------------------------------------------------------------------------
Cash netback
including
realized
financial
instruments 28.40 24.74 26.21 25.96 20.24 15.78 17.06 19.80
------------------------------------------------------------------------
------------------------------------------------------------------------


Note 1 - Pro-forma is presented on the basis of removing the results
associated with the properties that were part of the Trust Disposition
for periods or as of dates prior to the Trust Disposition.

Note 2 - Q3 2004 and subsequent periods includes the major asset
acquisitions.

Note 3 - The Alberta Securities Commission released National Instrument
51-101 (the "Instrument") in 2003, with an effective date of September
30, 2003. The instrument requires all reported petroleum and natural gas
production to be measured in marketable quantities with adjustments for
heat content included in the commodity price reported. The Company has
adopted the Instrument prospectively. As such, commencing with the
fourth quarter of 2003, natural gas production volumes are measured in
marketable quantities, with adjustments for heat content and
transportation reflected in the reported natural gas price.

-30-

Contact Information

  • FOR FURTHER INFORMATION PLEASE CONTACT:
    Paramount Resources Ltd.
    C. H. (Clay) Riddell
    Chairman and Chief Executive Officer
    (403) 290-3600
    (403) 262-7994 (FAX)
    or
    Paramount Resources Ltd.
    J. H. T. (Jim) Riddell
    President and Chief Operating Officer
    (403) 290-3600
    (403) 262-7994 (FAX)
    or
    Paramount Resources Ltd.
    B. K. (Bernie) Lee
    Chief Financial Officer
    (403) 290-3600
    (403) 262-7994 (FAX)
    Website: www.paramountres.com