Paramount Resources Ltd. Annual Report 2004

FY2004 Annual Report · Paramount Resources Ltd.

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2004 Annual report

President’s Message
Core Producing Areas
Review of Operations
Areas of Interest
Management’s Discussion & Analysis
Management’s and Auditors’ Report
Financial Statements
Notes to Financial Statements
Corporate Information
Analyst supplement

03
06
11
20
26
44
45
48
68

ANNUAL AND SPECIAL MEETING

Shareholders are cordially invited to attend the
Annual Meeting to be held May 26, 2005, at 4:00 p.m.
Calgary Petroleum Club
Devonian Room
319 Fifth Avenue S. W.
Calgary, Alberta

LETTER TO SHAREHOLDERS
CORE PRODUCING AREAS

FINANCIAL HIGHLIGHTS

($ thousands except per share amounts and where stated otherwise)
FINANCIAL
Petroleum and natural gas sales, net of transportation costs
Cash flow (1)
From operations
Per share - basic

- diluted

Earnings
Net earnings (loss)
Per share - basic

- diluted
Capital expenditures (2)
Exploration and development
Acquisitions, dispositions and other (3)
Net capital expenditures
Total assets
Net debt (4)
Shareholders’ equity
Weighted average common shares outstanding (thousands)
Common shares outstanding at year end (thousands)
Common shares outstanding at March 8, 2005 (thousands)

OPERATING
Production
Natural gas (MMcf/d)
Crude oil and liquids (Bbl/d)
Total production (Boe/d) @ 6:1
Average prices (5)
Natural gas (pre-financial instruments) ($/Mcf)
Natural gas ($/Mcf) (6)
Crude oil and liquids (pre-financial instruments) ($/Bbl)
Crude oil and liquids ($/Bbl) (6)
Reserves (proved plus probable)
Natural gas (Bcf)
Crude oil and liquids (MBbl)
Estimated present value before tax (discounted @ 10% using

forecasted prices and costs)
Proved ($ millions)
Proved and probable ($ millions)

Land (thousands of acres)
Total net land holdings
Net undeveloped land holdings
Drilling activity (gross)
Gas
Oil
Oilsands evaluation (7)
D&A
Total wells
Success rate (7)

Year Ended December 31

2004

2003

% Change

550,616

434,059

295,566
4.95
4.84

41,174
0.69
0.67

167,276
2.78
2.77

1,151
0.02
0.02

316,284
262,730
579,014
1,542,786
451,187
625,039
59,755
63,186
63,899

223,753
(368,731)
(144,978)
1,177,130
297,055
496,033
60,098
60,095

173
7,297
36,150

6.72
6.86
46.80
44.13

568.6
20,461

1,156.0
1,659.3

4,082
3,442

229
12
17
13
271
95%

153
7,169
32,630

5.99
5.16
38.27
35.50

329.4
12,513

597.4
733.6

3,386
2,800

180
16
-
15
211
93%

27%

77%
78%
75%

3,477%
3,350%
3,250%

41%
171%
498%
31%
52%
26%
(1)%
5%

13%
2%
11%

12%
33%
22%
24%

73%
64%

94%
126%

21%
23%

27%
(25)%
100%
(13)%
28%
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 geo-
physical 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.

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 1

2 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

LETTER TO SHAREHOLDERS

LETTER to SHAREHOLDERS

Paramount and its shareholders enjoyed an exceptional year in 2004 as the Company experienced one of the
most active years in our 26 year history in virtually every aspect of our business. A review of the signiﬁcant events
throughout the year will show that the Company’s exploration and development program was one of the largest
ever undertaken by the Company. We also executed a series of signiﬁcant acquisitions which have added to the
production base as well as the exploration and development inventory. Financing these activities was achieved
through a combination of different debt and equity instruments which maximized Paramount’s return. Paramount is
now poised on the brink of completing the spinout to its shareholders of its second distribution generating trust in as
many years, (“Trilogy Energy Trust”), for the beneﬁts of its shareholders. We are executing the business plan we laid
out and the results are providing shareholders with superior, if not extraordinary returns.

The focus of Paramount’s activity is the exploration and development program which in 2004 totalled $316.3
million. The majority of the activities were spread amongst the ﬁve main operating units in Kaybob, Grande Prairie,
Northwest Alberta/Cameron Hills, Northwest Territories, Northeast British Columbia/Liard, Northwest Territories,
and Southern Alberta. Additional spending was directed to furthering the long-term projects Paramount is pursuing
in the Colville Lake area in the northern part of the Northwest Territories, and in the Athabasca Oil Sands area of
northeast Alberta.

In Kaybob, Paramount started to see the results of years of work discovering, consolidating and developing the
Lower Cretaceous Gething resource play. The initial program to downspace these gas pools, started in 2004, and the
results of these inﬁll drilling programs into these Gething pools have been superior. Wells drilled into existing gas
pools have for the most part found virgin, or near virgin, reservoir pressures conﬁrming Paramount’s vision that we
would be ﬁnding new reserves and increasing substantially the recoveries of these pools. Paramount’s success rate
for adding new producing gas wells was over 95 percent in 2004. It is this play type which will be the cornerstone
of Trilogy Energy Trust. The extensive inventory of development opportunities is expected to provide stability
and sustainability of reserves and production, and ultimately per unit distributions for the Trust. The extension of
Paramount’s activities to the west of Kaybob into the Deep Basin play also occurred with material additions to the
land and prospect inventory in 2004 in what is now referred to as the West Kaybob area.

In the Grande Prairie Operating Unit, Paramount continued the development of our shallow Dunvegan discoveries
at Mirage, extending this play substantially. As well, the tie in of the discovery at Marten Creek was completed in
April, 2004 adding the ﬁrst production from this area to Paramount. The acquisition of assets in this area in July was
complimentary to our original discovery and has established Marten Creek as an area of material value. This area in
the Marten Creek asset will comprise close to 11 percent of the initial production base of Trilogy Energy Trust.

The Northwest Alberta/Cameron Hills, Northwest Territories Operating Unit saw the follow-up development and tie
in of the prior-year discovery at Haro, extending the pool boundary, increasing reserves and adding deliverability
to the operating unit. Additional drilling and seismic activities in 2005 will build on this drilling success as well as
further develop existing production in this area.

In Northeast British Columbia/Liard, Northwest Territories, the acquisition of the majority of the working interest and
assumption of operatorship at West Liard has made Paramount the dominant producer in the North. Paramount’s
expertise is expected to provide the basis for leading development of the western Canadian Sedimentary Basin
northward with Paramount realizing many of the opportunities in this new frontier.

In the Southern Operating Unit, Paramount initiated and completed the ﬁrst delineation phase of the Coalbed
Methane evaluation program. We drilled 20 wells for this resource at our Chain/Craigmyle property with results that
have exceeded our expectations. Paramount is moving forward to fully develop Phase One of the Coalbed Methane
program which includes up to an additional 88 wells and forecasts initial production of approximately 10 MMcf/d.

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 3

In the fall of 2004, Paramount released an update of the results of our exploration activities in the Colville Lake area
of the Northwest Territories. Paramount’s two initial discovery wells at Nogha tested natural gas at rates of 3 to 5
MMcf/d and the pool has been independently estimated to contain some 250 Bcf of possible reserves. Paramount is
continuing with exploration activities in 2005 at Nogha, Maunoir Ridge and a new prospect at Turton Lake. We are
exploring our options for bringing this gas to market.

In the Athabasca Oil Sands area, Paramount added a large amount of additional acreage and conducted a drilling
program to reﬁne our understanding of the bitumen accumulations on our lands. This program has continued into
the current year to the point where Paramount hopes to be in a position to select the location of the Company’s ﬁrst
prototype plant for SAG-D development and to submit the application for this project.

Acquisitions and divestitures played an important role in the growth of Paramount’s production base and added
to future growth opportunities. The Kaybob acquisition added production, a large land base and seismic inventory
which we believe will be instrumental in growing the remaining assets of the West Kaybob Operating Unit into
a substantial entity of its own. Two separate transactions in the Liard area allowed Paramount to consolidate its
interests in its current production as well as become the largest working interest owner and operator of the Liard
Nahanni discovery from 2000. Finally, the Marten Creek acquisition added production to our original discovery which
has grown the area to a signiﬁcant asset in itself. The acquisition also added some control to plant capacity and
further drilling opportunities which will be pursued over the next several years.

These combined activities of exploration, acquisitions and development provided Paramount with exceptional
growth in both production and reserves. Paramount’s production in the fourth quarter of 2004 grew 43 percent
when compared with the same period in the prior year. As well, Paramount replaced our 2004 production 4.6 times,
and increased our overall reserves by 71 percent to 115 million barrels of oil equivalent for a cost of ﬁnding and
development of $9.49 per barrel of oil equivalent. The net asset value of the Company, calculated using conservative
estimates and historical costs, reﬂected these results with a 141 percent increase to $25.01 per share.

To ﬁnance our capital spending program and acquisition activities, Paramount has been active on both debt and
equity fronts. In late 2003, Paramount completed its ﬁrst debt issue raising US$175 million which gave us
the ﬂexibility to initiate the inﬁll drilling program at Kaybob as well as repurchase approximately 1.6 million of
common shares through our normal course issuer bid. A second debt issue was completed in June, 2004 raising
US$ 125 million which was used to ﬁnance the acquisitions at Kaybob and Liard. Later in the year, Paramount
completed an equity issue selling 4.5 million shares for gross proceeds of $116.5 million. Finally, the Company
redeemed US$85.4 million of the Senior Notes debt under the equity claw provision of the debt indentures.

Late in the year, after reviewing the options available to Paramount, the Directors of Paramount unanimously
approved management’s recommendation to pursue the spinout of Trilogy Energy Trust. Upon completion of the
Trust spinout, Paramount shareholders will own 100 percent of the 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

4 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

LETTER TO SHAREHOLDERS

Trilogy, unitholders will receive regular distributions of cash derived from the cash ﬂow produced by Trilogy’s low-
risk development assets. The ﬁrst cash distribution of the Trust, expected to be $0.16 per Trust Unit, is expected to
be paid on May 15, 2005 to unitholders of record on May 2, 2005. 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 in order to maintain and grow distributions. 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.

Looking forward to 2005, we are striving for similar success to that which we enjoyed this past year. We continue
to follow the business plan which we have developed, combining short-term growth from a lower risk prospect
inventory and longer term larger developments which we expect to translate into material value for shareholders in
the future. The current commodity environment for energy is very good and has easily kept pace with the increased
costs in the business. 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. Trilogy’s capital program is intended to entirely replace production and
reserves. 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 of the combined entities is estimated to be approximately $425 million or approximately
$6.66 per share.

signed

Jim Riddell
President and Chief Operating Ofﬁcer
March 24, 2005

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 5

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6 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

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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 15,704 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 1.25 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 (46.4 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 125 percent to average 27 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 natural gas liquids 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

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 7

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 natural gas liquids. 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 in 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 natural gas liquids.
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 natural gas liquids, 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, Northwest Territories, 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, Northwest Territories, 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

8 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

CORE PRODUCING AREAS

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) wells in 2003. The average production
for the year was 11 MMcf/d of gas, with 1,798 Bbl/d of oil and natural gas liquids as compared to 10 MMcf/d of gas
and 2,457 Bbl/d of oil and natural gas liquids 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 natural gas liquids. 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) Coalbed 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 multi-year 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.

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 9

10 PARAMOUNT RESOURCES LTD. 20 0 4 ANNUA L RE P ORT

REVIEW OF OPERATIONS

REVIEW of OPERATIONS

PRODUCTION
Paramount’s production proﬁle continued to be signiﬁcantly weighted to natural gas.
Natural gas production made up 80 percent of the Company’s total production in 2004
compared to 78 percent in 2003.

Paramount’s production for the year ended December 31, 2004 was 36,150 Boe/d, up
11 percent from 32,630 Boe/d in 2003. Natural gas production increased 13 percent from
152.8 MMcf/d in 2003 to 173.1 MMcf/d in 2004. Crude oil and natural gas liquids production
increased 2 percent from 7,169 Bbl/d in 2003 to 7,297 Bbl/d in 2004. This increase in
production is attributable to the 2004 acquisitions in the Kaybob, Fort Liard and Marten
Creek areas and a successful capital program.

The following table summarizes the average daily production per core area.

Natural Gas Production (MMcf/d)
East Kaybob
Marten Creek
Total Trust Properties
West Kaybob
Grande Prairie (excluding Marten Creek)
Northwest Alberta / Cameron Hills, Northwest Territories
Northwest Territories / Northeast British Columbia
Southern
Other
Total Paramount (excluding Trust Properties)
Total Paramount

Crude Oil & NGL Production (Bbl/d)
East Kaybob
Marten Creek
Total Trust Properties
West Kaybob
Grande Prairie (excluding Marten Creek)
Northwest Alberta / Cameron Hills, Northwest Territories
Northwest Territories / Northeast British Columbia
Southern
Other
Total Paramount (excluding Trust Properties)
Total Paramount

Total Production (Boe/d)
East Kaybob
Marten Creek
Total Trust Properties
West Kaybob
Grande Prairie (excluding Marten Creek)
Northwest Alberta / Cameron Hills, Northwest Territories
Northwest Territories / Northeast British Columbia
Southern
Other
Total Paramount (excluding Trust Properties)
Total Paramount

2004
89.7
8.6
98.3
6.7
18.2
20.2
16.2
10.8
2.7
74.8
173.1

3,874
-
3,874
217
585
797
12
1,798
14
3,423
7,297

18,817
1,432
20,249
1,340
3,621
4,165
2,710
3,596
469
15,901
36,150

2003
77.6
-
77.6
1.9
12.4
22.3
11.6
9.5
17.5
75.2
152.8

2,184
-
2,184
267
1,767
448
9
2,457
37
4,985
7,169

15,112
-
15,112
592
3,831
4,165
1,942
4,048
2,940
17,518
32,630

NATURAL GAS SALES
(MMcf/d)

173

250

200

150

100

03 04

CRUDE OIL and
LIQUIDS SALES (Bbl/d)

7,297

8,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

03 04

PRODUCTION
(Boe/d @ 6:1)

50,000

40,000

30,000

20,000

10,000

36,150

03 04

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 11

PROFITABILITY
Paramount continues to focus its efforts on the control of factors directly related to proﬁtability. Production volumes,
operating costs, general and administrative costs, and capital spending are all factors that are within our control and
remain closely monitored. The mandate of every employee is to turn ideas into value. This strategy has resulted in a
history of increased shareholder value.

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. Natural gas prices after ﬁnancial
instruments in 2004 increased 33 percent to $6.86/Mcf from $5.16/Mcf in 2003. In 2004, Paramount recorded a
$18.7 million gain on ﬁnancial instruments as compared to a loss of $53.2 million in 2003. The 2003 ﬁnancial
instruments were initiated in order to reduce cash ﬂow risk with respect to the Summit acquisition as the bridge
loan used to ﬁnance the acquisition was extended due to unexpected delays in closing the Paramount Energy Trust
disposition. Oil and natural gas liquids (“NGL”) prices before ﬁnancial instruments increased 22 percent to average
$46.80/Bbl in 2004, as compared to $38.27/Bbl in 2003.

OPERATING COSTS
Paramount’s total operating costs increased 18 percent to $95.8 million in 2004 as compared to $81.2 million in 2003.
Costs on a unit-of-production basis increased 6 percent to $7.24/Boe from $6.82/Boe in 2003. 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.

ROYALTIES
For 2004, net royalties increased to $105.0 million from $82.5 million in 2003 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.

GENERAL AND ADMINISTRATIVE COSTS
General and administrative expenses, net of operating recoveries, increased to $25.2 million in 2004 as compared
to $19.1 million in 2003. 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 Coalbed Methane, and developing

8.00

7.00

6.00

5.00

4.00

3.00

2.00

1.00

6.86

NATURAL GAS PRICE
(after realized
financial instruments)
($/Mcf)

50.00

40.00

30.00

20.00

10.00

44.13

CRUDE OIL and
LIQUIDS PRICE
(after realized
financial instruments)
($/Bbl)

50.00

40.00

30.00

20.00

10.00

41.61

GROSS REVENUE
(before financial
instruments)
($/Boe)

03 04

12 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

REVIEW OF OPERATIONS

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.

CASH FLOW AND EARNINGS
Paramount’s cash ﬂow from operations increased 77 percent to $295.6 million in 2004 from $167.3 million in 2003.
The increase in cash ﬂow 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. Net earnings totaled
$41.2 million 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.

Cash Flow Reconciliation
Volume (Boe) (1)
Petroleum & natural gas revenue, net of transportation
Gain (loss) on sale of investments
Royalties (net of ARTC)
Operating costs
Operating netback
Realized financial instruments
Interest on long-term debt (excluding non-cash interest)
General and administrative
Bad debt recovery (expense)
Lease rentals
Current and Large Corporations Tax
Cash flow from continuing operations
Cash flow from discontinued operations
Cash flow from operations
Weighted average shares (millions)
Cash flow per basic share ($/share)

(1) Barrels of oil equivalent calculated on the basis of 1 barrel = 6 Mcf.

($ million)
550.6
-
(105.1)
(95.8)
349.7
(0.7)
(24.1)
(25.2)
5.5
(3.5)
(6.8)
294.9
0.7
295.6
59.8
4.95

2004

2003

($ million)
434.1
(1.0)
(82.5)
(81.2)
269.4
(53.2)
(19.0)
(19.1)
(6.0)
(3.6)
(2.7)
165.8
1.5
167.3

$/Boe
36.45
(0.09)
(6.93)
(6.82)
22.61
(4.47)
(1.60)
(1.60)
(0.50)
(0.30)
(0.23)
13.91
0.13
14.04

$/Boe
41.61
-
(7.94)
(7.24)
26.43
(0.05)
(1.82)
(1.91)
0.42
(0.27)
(0.51)
22.29
0.05
22.34
60.1
2.78

26.43

OPERATING
NETBACK
($/Boe)

30.00

25.00

20.00

15.00

10.00

5.00

6.00

5.00

4.00

3.00

2.00

1.00

4.95

CASH FLOW
PER SHARE
($/share, basic)

2.00

1.50

1.00

0.50

EARNINGS
PER SHARE
($/share, basic)

0.69

03 04

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 13

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

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

Capital Expenditures ($millions)
Land
Geological and geophysical
Drilling
Production equipment and facilities
Exploration and development expenditures
Property acquisitions
Proceeds received on property dispositions
Other
Net capital expenditures

2004
37.9
8.7
184.5
85.2
316.3
322.6
(61.8)
1.9
579.0

2003
22.3
8.4
123.5
69.6
223.8
0.9
(371.6)
1.9
(145.0)

LAND
The Company’s net land holdings increased 20 percent to 4,082 thousand acres from 3,386 thousand acres in
2003. Net undeveloped lands increased 23 percent to 3,442 thousand acres from 2,800 thousand acres in 2003.
Paramount’s undeveloped land inventory was increased partially as a result of acquisition and as a result of
$37.9 million spent at Crown land sales.

The following table summarizes the Company’s acreage position at December 31, 2004:

Land (thousand acres)

Land assigned reserves
Undeveloped land
Total
Fair market value
of undeveloped land ($millions)

Gross
1,098
5,536
6,634

185.4

2004

Net
640
3,442
4,082

Average
Working
Interest
58%
62%
62%

Gross
981
4,756
5,737

98.20

2003

Net
586
2,800
3,386

Average
Working
Interest
60%
59%

350

300

250

200

150

100

316.3

37.9

EXPLORATION and
DEVELOPMENT
EXPENDITURES
($ millions)

85.2

184.5

8.7

2004 EXPLORATION
and DEVELOPMENT
EXPENDITURES
($ millions)

03 04

Drilling and completion
Geological & geophysical
Plant gathering equipment
Land purchases

14 PARAMOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT

REVIEW OF OPERATIONS

DRILLING
Paramount participated in the drilling of 271 (180.3 net) wells in 2004 with a success rate of 96 percent. A total of
229 (145.6 net) gas wells, 12 (9.5 net) oil wells, 17 (17.0 net) heavy oil wells and 13 (8.2 net) dry and abandoned wells
were drilled. The highest number of net drills was in the Kaybob Operating Unit, 75 (52.2 net ) wells drilled. Grande
Prairie Drilled 57 (46.4 net) wells, Northwest Alberta drilled 22, (14.5 Net) wells, Liard drilled 18 (9.4 net) wells and
Southern Alberta drilled 82 (40.8 net) wells. The Company also drilled 17 (17.0 net) heavy oil evaluation wells in
northeast Alberta.

The following table summarizes the Company’s 2004 drilling results:

Gas
Oil
D&A
Heavy Oil
Total
Total All Wells
Success

2004

2003

Development

Exploration

Development

Exploration

Gross
164
11
9
17
201
271

Net
102.8
8.6
4.9
17.0
133.3
180.3

Gross
65
1
4
-
70

95%

Net
42.8
0.9
3.3
-
47.0

Gross
135
13
7

Net
90.0
10.4
3.5

Gross
45
3
8

Net
30.7
2.1
2.2

155
211

103.9
138.9

93%

35.0

RESERVES AND RESERVES REPLACEMENTS
Paramount’s reserves for the year ended December 31, 2004, were evaluated by McDaniel and Associates
Consultants Ltd. (“McDaniel”) and by Paddock Lindstrom and Associates Ltd. (“Paddock Lindstrom”). Paramount’s
reserves have been calculated in compliance with the national Instrument 51-101. Natural gas reserves for the year
ended 2004 were 568.6 Bcf as compared to 329.4 Bcf for the year ended 2003. This represents a 73 percent increase
in natural gas reserves. The crude oil and natural gas liquids reserves for the year ended 2004 were 20,461 MBbl, a
64 percent increase over the year end 2003 reported 12,513 MBbl. Crude oil reserves increased from 8,106 MBbl to
12,031 MBbl while natural gas liquids reserves increased from 4,407 MBbl to 8,430 MBbl.

DRILLING
DISTRIBUTION

Kaybob
Grande Prairie
Northwest Alberta
Liard
Southern Alberta
Heavy Oil

271

WELLS
DRILLED
(gross)

300

250

200

150

100

DRILLING
SUCCESS
RATE (%)

100

03 04

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 15

The following table summarizes the reserves evaluated as at December 31, 2004, using McDaniel’s and Paddock’s
forecast prices and cost cases:

Gross Proved and Probable Reserves

Before Tax Net
Present Value ($millions)

Reserve Category

Canada
Proved

Developed Producing
Developed Non-Producing
Undeveloped

Total Proved
Probable
Total Proved Plus Probable Canada
United States
Proved

Developed Producing
Developed Non-Producing
Undeveloped

Total Proved
Probable
Total Proved Plus Probable US
Total Proved
Total Probable
Total Reserves

(Columns may not add due to rounding)

Light and
medium Natural
Gas
Liquids
(MBbl)

Crude
Oil
(MBbl)

Natural
Gas
(Bcf)

Boe
(MBoe)

Discount Rate
5%

10%

254.5
52.4
39.9
346.9
221.3
568.2

0.4
-
-
0.4
-
0.4
347.2
221.4
568.6

5,615
667
308
6,590
2,901
9,492

2,108
-
-
2,108
431
2,539
8,698
3,332
12,031

5,552
501
289
6,342
2,087
8,430

-
-
-
-
-
-
6,342
2,087
8,430

53,592
9,898
7,251
70,741
41,882
112,622

2,169
-
-
2,169
437
2,606
72,910
42,319
115,230

1,266.6
205.7
142.8
1,615.2
950.6
2,565.8

1,063.9
166.1
91.2
1,321.2
663.5
1,984.7

929.5
140.8
64.0
1,134.3
500.7
1,635.0

29.8
(0.4)
-
29.5
6.0
35.5
1,644.7
956.6
2,601.3

25.3
(0.3)
-
25.0
3.9
28.8
1,346.2
667.4
2,013.6

21.9
(0.3)
-
21.6
2.7
24.3
1,156.0
503.4
1,659.3

RESERVE RECONCILIATION FOR YEAR-END 2004
Total proved reserves at year end 2004 were approximately 347 Bcf and 15.0 MMBbl or 73 MMBoe and proved plus
probable reserves were 569 Bcf and 20.5 MMBbl or 115.2 MMBoe. On a barrel equivalent basis, reserves increased
approximately 71 percent or 48 MMBoe over year end 2003. This growth in reserves replaces 2004 production of
13 MBoe by over four times.

800

700

600

500

400

300

200

100

568.6

NATURAL GAS
RESERVES
PROVED and PROBABLE
(gross before royalties)
(Bcf)

25,000

20,000

15,000

10,000

5,000

20,461

CRUDE OIL and
NGL RESERVES
PROVED and PROBABLE
(gross before royalties)
(MBbl)

150,000

120,000

90,000

60,000

30,000

115,230

RESERVES
(MBoe)

03 04

16 PARAMOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT

REVIEW OF OPERATIONS

The Company’s new reserves and extensions to existing proved plus probable reserves totaled 27.9 MMBoe,
acquisitions increased reserves by 26.1 MMBoe. Further development and additional production information
enabled positive reserve revisions of 8.4 MMBoe. The Company’s divestitures of certain non-core properties
accounted for 1.2 MMBoe.

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)

Gas
Bcf
Total Reserves Jan 1, 2004 241.7
Total 2004 Divestments(1)
(0.2)
Total 2004 acquisitions(1)
63.1
2004 Capital Program
83.3
Additions(1)
(63.4)
Total 2004 Production
Technical Revisions(1)
22.6
Total Reserves Jan. 1, 2005 347.2

Proved Reserves
Oil &
Boe
NGL
MBbl MBoe
50,900
10,617
(1,042)
(1,021)
15,951
5,426

Probable Reserves
Oil &
Boe
NGL
MBbl MBoe
16,513
1,896
(176)
(176)
10,108
1,505

Gas
Bcf
87.7
-
51.6

Proved + Probable Reserves
Oil &
Boe
NGL
MBbl MBoe
67,413
(1,224)
26,059

Gas
Bcf
329.4
(0.2)
114.8

12,513
(1,196)
6,931

1,624
(2,671)
1,066
15,041

15,510
(13,231)
4,830
72,910

64.9
-
17.2
221.4

1,532
-
662
5,420

12,346
-
3,525
42,319

148.2
(63.4)
39.8
568.6

3,156
(2,671)
1,727

27,856
(13,231)
8,355
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 for new reserves additions were calculated to
be $13.57/Boe for proved reserves and $9.48/Boe for proved plus probable reserves.

Finding and Development Capital
2004 Working Interest Capital Expenditures

($ millions)
Land
Seismic
Exploration and development
Facilities
Total net capital expenditures
Less increase in value of undeveloped land
Less 2004 Colville expenditures
Less 2004 Bitumen evaluation expenditures
2004 F&D net capital expenditures

2004
Capital
38.0
8.9
184.5
91.4
322.8
(45.1)
(29.3)
(8.3)
240.1

Future Capital New Additions

Total F&D Capital

Proved
-
-
20.2
16.0
36.2
-
-
-
36.2

Proved Plus
Probable
-
-
77.3
25.9
103.2
-
-
-
103.2

Proved
38.0
8.9
204.7
107.4
359.0
(45.1)
(29.3)
(8.3)
276.3

Proved Plus
Probable
38.0
8.9
261.8
117.3
426.0
(45.1)
(29.3)
(8.3)
343.3

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 17

Proved
Capital
($MM)

Proved
Reserves
(MBoe)

Proved Plus Proved Plus Proved Plus
Probable
F&D
($/Boe)

Probable
Reserves
(MBoe)

Probable
Capital
($MM)

Proved
F&D
($/Boe)

Finding and Development Costs
Extensions and discoveries
(including technical revisions)

276.3

20,360

13.57

343.3

36,231

9.48

ACQUISITION AND DIVESTMENT ACTIVITIES (“A&D”)
In 2004, Paramount acquired properties in Alberta and the Northwest Territories with 15,951 MBoe of proved
reserves, or 26,059 MBoe proved plus probable reserves as well as undeveloped land valued at $35.0 million, at
a total cost of $322.6 million. Paramount also divested of non-core properties in Alberta and Saskatchewan with
reserves of 1,042 MBoe proved, or 1,224 MBoe proved plus probable reserves as well as undeveloped land valued at
$1.0 million, for total divestment proceeds of $52.1 million. In aggregate, Paramount increased total proved reserves
by 14,909 MBoe for a net unit cost of $15.86/Boe, and increased proved plus probable reserves by 24,835 MBoe for a
net unit cost of $9.52/Boe through acquisition and divestment activity.

2004 Working Interest Capital Expenditures ($ millions)
Capital Expenditures for Acquisitions
Fair Market Value of Undeveloped Land Acquired
Proceeds of Dispositions of P&NG assets
Fair Market Value of Undeveloped Land Divested
Net A&D Capital for Reserves

322.6
(35.0)
(52.1)
1.0
236.5

Net 2004 A&D Expenditures
Less: Net Value of A&D
Undeveloped Land
2004 Net A&D Cost of Reserves

Proved
Capital
($MM)
270.5

34.0
236.5

Proved
Reserves
(MBoe)

Proved Plus Proved Plus Proved Plus
Probable
A&D
($/Boe)

Probable
Reserves
(MBoe)

Proved
A&D
($/Boe)

Probable
Capital
($MM)
270.5

14,909

15.86

34.0
236.5

24,835

9.52

TOTAL RESERVE GROWTH COST (F&D Cost plus Acquisitions and Divestments)
Paramount’s 2004 F&D related activities, when combined with its acquisition and divestment program resulted in
total reserve growth of 35,269 MBoe total proved reserves ($14.53/Boe unit cost) and 61,066 MBoe of proved plus
probable reserves ($9.49/Boe unit cost).

Total Reserve Growth (F&D + A&D)

512.8

35,269

14.53

579.8

61,066

9.49

18 PARAMOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT

REVIEW OF OPERATIONS

NET ASSET VALUE
The net asset value of Paramount at year end has increased 141 percent from $10.38 in 2003 to $25.01 in 2004.
One of the main components of the increase was the 126 percent increase in value of reserves and the 89 percent
increase in the appraised value of undeveloped land.

The following table summarizes the Company’s net asset value:

Net Asset Value ($ millions of dollars as at December 31, 2004)
Present value of appraised reserves (1)
Value of short-term investments
Appraised value of undeveloped land
Seismic (at cost)
Projects under evaluation (at cost)
Building (at cost)
Other
Total assets
Bank loans
Senior notes
Working capital deficiency (2)
Drilling rig indebtedness
Mortgage
Total liabilities
Net asset value
Net asset value per basic common share (3)

2004
1,659.3
27.1
185.4
55.4
117.8
-
11.3
2,056.3
201.3
257.8
17.0
-
-
476.1
1,580.2
25.01

$
$

2003
733.6
17.3
98.2
37.6
42.1
8.5
10.6
947.9
60.4
226.9
25.7
4.6
6.7
324.3
623.6
10.38

(1) Proved plus probable reserves discounted at 10 percent before income tax used for 2004.
(2) Excludes short-term investments.
(3) Outstanding shares: 2004 – 63,185,600 (2003: 60,094,600).

NOTES TO NET ASSET VALUE
i)

Reserve values were determined by McDaniel and Paddock Lindstrom as at December 31, 2004, using their
forecast prices and costs cases.

ii) No value has been assigned to tangible assets other than those associated with proved producing reserves.

iii)

Paramount’s hedging activities, which extend past December 31, 2004, have not been valued by McDaniel or
Paddock Lindstrom.

iv) Reserve values have been evaluated under a blow-down scenario.

25.01

NET ASSET
VALUE
($/share)

30.00

25.00

20.00

15.00

10.00

5.00

03 04

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 19

Coalbed Methane, southern Alberta

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20 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

AREAS OF INTEREST

AREAS of INTEREST

COALBED METHANE
Coalbed Methane (CBM) or natural gas from Coal (NGC) is an ‘unconventional’ source of
natural gas. In southern Alberta the Horseshoe Canyon coals of the Edmonton group has
become one of the hottest land and drilling plays on the continent. Historically, CBM has
been produced from wet coal seams, where huge amounts of water are removed to allow
natural gas to desorb and produce from the coal. This is the case in the San Juan, Powder
River and Black Warrior basins in the United States. In Southern Alberta however, the
Horseshoe Canyon coals do not contain water, they are dry, and therefore the natural gas
produces from the coal seams immediately after stimulation with no appreciable water
production. The rates and reserves from these wells are similar to that from the Medicine
Hat and Milk River formation wells which have been the mainstay of Alberta production for
the last century. These wells typically produce at steady rates of natural gas with minimum
declines and have a long reserve life.

The producing region for the Horseshoe Canyon stretches along the central part of Alberta
from Calgary to just south of Edmonton. Paramount’s land holdings in Chain/Craigmyle are
located on the eastern edge of this fairway. In 2004 Paramount participated in 20 wells and
completions targeting the Horseshoe Canyon coals. The wells produce gas from the zone at
depths between 80 and 350 meters with rates of over 100 Mcf/d.

Paramount will be drilling 88 wells in 2005 for CBM in what is the second year of a
multi-year exploration and development program. Paramount will be drilling up to 4 wells
per section depending on drainage and reserves from each well, and have applied to the
Alberta Energy and Utility Board for reduced drill spacing to achieve this in 2005.

As part of this program, we are also building a production system which will utilize large
diameter pipelines and centrally located compressors to maximize deliverability and
reserve recovery of the gas ﬁeld and reduce the proliferation of multiple small wellhead
compressors. This is in keeping with the production philosophy we pioneered 26 years ago
producing shallow gas in northeast Alberta. With a streamlined production system such
as this, though up front costs may be higher, long term operating costs and environmental
impact are kept to a minimum. This is an area which has seen oil and gas development in
a variety of different plays for the last 60 years, as well as constituting the main agricultural
region of Alberta. Paramount is well aware of the responsibility of operating in such an
area, and is working with the surface land owners to achieve seamless operations to the
beneﬁt of all.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 21

Colville Lake, Northwest Territories

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22 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

AREAS OF INTEREST

AREAS of INTEREST

COLVILLE LAKE
The Colville Lake development is situated at the Arctic Circle, 1850 kilometres north of
Calgary, within the Sahtu settlement region in the Northwest Territories. The area was
recognized by Paramount as having signiﬁcant potential for large scale hydrocarbon
reserves within the Cambrian-aged Mount Clark and overlying Mount Cap sandstones.
Previous National Energy Board (NEB) Signiﬁcant Discovery Licenses recognize over
400 Bcf in the area. In 2004 Paramount and its 50 percent partner, Apache Canada, increased
our already signiﬁcant land position in the Sahtu, to over 940,000 acres (over 40 Alberta
townships) in three distinct areas; the Nogha gas discovery, Maunoir Ridge, and Turton
Lake.

In 2003, Paramount and Apache drilled and cased two wells in the Nogha prospect, the
Nogha C-49 discovery well and Nogha M-17 down structure. These wells were cased and
tested, ﬂowing at between 3 and 5 MMcf/d. In 2004 wells K-14 and B-23 were drilled and
cased, further delineating the discovery. McDaniel and Associates have independently
reviewed the Nogha exploration results and assigned possible raw gas reserves of 250 Bcf
to a 17,000 acre area deﬁned by the C-49 and M-17 wells. During the 2005 winter season
Paramount and Apache will re-complete K-14 and B-23 to conﬁrm well deliverability.

In 2004, Paramount and Apache drilled and cased Maunoir C-34 as part of the federal
exploration commitments on Exploration License (EL) 399. During the 2005 winter drilling
season we will drill three additional wells at Maunoir A-67, E-35 and L-80. Successful drilling
at Maunoir would signiﬁcantly improve the economic viability of development in the Sahtu.

Paramount and Apache will also drill the G-47 well at Turton Lake (on EL 414) to validate the
Federal Exploration license acquired in 2003.

In late 2004 Imperial Oil Resources Ventures Limited ﬁled application with the NEB to
construct the Mackenzie Valley Pipeline (MVPL). If approved and completed on schedule,
the pipeline would start up in 2009, delivering gas from the Mackenzie Delta and Valley to
the existing pipeline infrastructure in northern Alberta. Several gathering and development
scenarios are being considered to deliver Colville gas to the MVPL, and upon successful
completion of this year’s program. Paramount will commence conceptual development
planning. Paramount’s goal is to complete the area’s initial development in time to make
gas deliveries at MVPL start-up.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 23

Oil Sands, northeast Alberta

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24 PARAMOUNT RESOU RCES LTD. 20 04 A NNUA L R EP ORT

AREAS OF INTEREST

AREAS of INTEREST

STEAM ASSISTED GRAVITY DRAINAGE (SAGD) OIL SANDS
The Alberta Oil Sands are the largest single deposit of hydrocarbons in the world. The
recoverable heavy oil from Alberta’s Oil Sands is second only to Saudi Arabia in terms of
total proven crude oil reserves. Alberta’s Oil Sands underlie 140,800 square kilometers, an
area larger than the state of Florida.

Paramount Resources holds 120,000 acres of oil sands rights in the Athabasca Oil Sands
area. The recoverable heavy oil, also called bitumen, is located in the Lower Cretaceous
McMurray sands of the Manville group.

During 2004 Paramount Resources increased our oil sands holdings by 70 percent, acquiring
51,000 acres of oil sands rights. Paramount now holds over 180 sections of oil sands
centered in the areas of Surmont and Leismer of northeast Alberta. In 2004 Paramount
drilled 10 Oil Sands Evaluation (OSE) wells to identify bitumen in place. An aggressive OSE
program in 2005 is expected to lead to a SAGD prototype facility application in late 2005.

Paramount will recover bitumen using Steam Assisted Gravity Drainage – also know as
“SAGD”. In SAGD two parallel 800 meter horizontal wells are drilled in at the bottom of the
reservoir, one 5 meters higher than the other. About 2000 Bbl/d of steam is injected in the
upper well, the bitumen is heated, and then drains by gravity into the lower well at rates of
about 750 Bbl/d.

Conventional SAGD plants burn natural gas to generate the steam used to recover bitumen.
Paramount Resources is committed to develop fuels other than natural gas for use in
its commercial oil sands plants. Paramount is conducting an alternate fuel research and
development program in 2005 to commercialize another fuel, which could signiﬁcantly
lower our long term cost of bitumen recovery.

Paramount’s development prospects are in four distinct areas. At Leismer Paramount holds
37 sections estimated to hold over a billion barrels of bitumen in place. In 2005 Paramount
will drill about 15 wells in Leismer to identify an initial commercial development area. Upon
conﬁrmation of commercial potential, Paramount will commence the design and regulatory
process necessary to start-up a 3,000 Bbl/d prototype project in 2006. The successful
demonstration project could lead to a 30,000 Bbl/d commercial project for start-up as early
as 2008 or 2009.

At Surmont Paramount has 11 sections of land directly offsetting the Surmont Commercial
Project. In 2005 Paramount will continue OSE drilling and complete a conceptual design,
leading to development of a commercial recovery scheme following Leismer.

At Corner and Thornbury, Paramount holds additional potential resources which position
the Company with heavy oil opportunities which extend through 2025.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 25

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=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

26 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A
FINANCIAL STATEMENTS

comparative ﬁgures shown in this MD&A report contains the results of these assets and should be read and
interpreted with this understanding.

As of March 8, 2005 Paramount had 63.9 million common shares outstanding.

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

REORGANI ZAT ION
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

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 27

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 I SSUANCE
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.

DIS POSITIO N OF ASSET S
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.

$8 7 MILLION ASSET ACQUIS IT ION
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.

$1 85 MILLIO N ASSET A CQUISIT ION
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;

28 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

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 L ON G- TER M S ENIO R 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)
Natural gas, net of transportation
Oil and natural gas liquids, net of transportation
Petroleum and natural gas revenue
Realized financial instrument gain (loss)
Unrealized financial instrument gain
Gain (loss) on investments
Gross revenue before royalties

2004
$ 425,626
124,990
550,616
(683)
19,376
(34)
$ 569,275

2003
$ 333,924
100,135
434,059
(53,204)
-
(1,020)
$ 379,835

2002
$ 311,438
72,750
384,188
46,813
-
40,830
$ 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 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 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 NGLs 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 NGLs production during the fourth quarter of 2004 is
mainly the result of increased NGLs production associated with the properties acquired combined with a decrease in oil
and NGLs production resulting from the sale of Sturgeon Lake in October 2003.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 29

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
NYMEX Fixed Price
NYMEX Fixed Price
AECO Fixed Price
AECO Fixed Price
AECO Fixed Price
NYMEX Call Option
AECO Fixed Price
AECO Fixed Price
AECO Fixed Price
Purchase Contracts
AECO Fixed Price

10,000 MMbtu/d
10,000 MMbtu/d
10,000 MMbtu/d
20,000 GJ/d
20,000 GJ/d
20,000 GJ/d
20,000 MMbtu/d
20,000 GJ/d
20,000 GJ/d
20,000 GJ/d

6.41
US$
7.46
US$
7.95
US$
7.90
$
8.03
$
$
7.60
US$ 10.00 Strike
6.28
$
6.30
$
6.80
$

November 2004 - March 2005
November 2004 - March 2005
November 2004 - March 2005
November 2004 - March 2005
November 2004 - March 2005
November 2004 - March 2005
December 2004 - March 2005
April 2005 - June 2005
April 2005 - June 2005
April 2005 - June 2005

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
Station 2 Fixed Price

Amount

8,000 GJ/d
12,000 GJ/d

Price

$
$

7.99
8.00

Term

November 2004 - March 2005
November 2004 - March 2005

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

Sales Contracts
NYMEX Fixed Price
NYMEX Fixed Price
NYMEX Fixed Price
AECO Fixed Price
AECO Fixed Price

Amount

Price

Term

1,000 Bbl/d
1,000 Bbl/d
1,000 Bbl/d
10,000 GJ/d
10,000 GJ/d

US$ 46.77
US$ 47.30
US$ 53.26
7.06
7.10

$
$

March 2005 - December 2005
March 2005 - September 2005
April 2005 - September 2005
April 2005 - October 2005
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

30 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

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.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 31

NETBACKS

Netbacks ($/Boe)
P&NG revenue, net of transportation
Royalties
Operating costs
Operating netback
Realized financial instrument loss (gain)
General and administrative
Bad debt expense (recovery)
Lease rentals
Interest on long-term debt (1)
Current and Large Corporations Tax
Cash flow netback

(1) Net of non-cash interest expense.

ROYALTIES

Royalties (thousands of dollars)
Crown royalties (net of ARTC)
Other royalties
Net royalties
Average corporate royalty rate as a percentage of petroleum
and natural gas revenue before financial instruments

2004
41.61
7.94
7.24
26.43
0.05
1.91
(0.42)
0.27
1.82
0.51
22.29

2004
99,298
5,748
$ 105,046

2003
36.36
6.93
6.82
22.61
4.47
1.60
0.50
0.30
1.60
0.23
13.91

2003
78,996
3,516
82,512

2002
25.50
4.44
5.14
15.92
(2.79)
0.95
-
0.27
1.43
0.55
15.51

2002
70,786
3,658
74,444

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)
Operating expenses
Net operating expenses per Boe

2004
95,767
7.24

$
$

2003
81,193
6.82

$
$

2002
86,067
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.

32 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

GENERAL AND ADMINISTRATIVE EXPENSES

General and Administrative Expenses (thousands of dollars)
Gross general and administrative expenses
Operating recoveries
Net general and administrative expenses
Net general and administrative expenses per Boe

2004
41,007
(15,760)
25,247
1.91

$
$

2003
31,906
(12,855)
19,051
1.60

$
$

2002
30,868
(15,238)
15,630
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)
Interest expense
Total debt, December 31
Average debt outstanding for the period

2004
$
25,399
$ 459,141
$ 443,156

2003
$
19,214
$ 287,237
$ 340,919

2002
$
23,943
$ 539,270
$ 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).

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 33

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)
Undepreciated capital costs (UCC)
Canadian oil and gas property expenses (COGPE)
Canadian development expenses (CDE)
Canadian exploration expenses (CEE)
Other
Total estimated income tax pools

December 31, 2004 December 31, 2003
215
25
166
68
21
495

257
422
203
158
33
1,073

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.

34 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

CASH FLOW AND EARNINGS

(thousands of dollars)
Cash flow from operations
Cash flow from operations per share

Net earnings before discontinued operations
Net earnings (loss) from discontinued operations
Net earnings
Earnings before discontinued operations per share

Earnings per share

- basic
- diluted

- basic
- diluted
- basic
- diluted

2004
$ 295,566
4.95
$
4.84
$
34,895
$
6,279
$
41,174
$
0.58
$
0.57
$
0.69
$
0.67
$

2003
167,276
2.78
2.77
1,208
(57)
1,151
0.02
0.02
0.02
0.02

$
$
$
$
$
$
$
$
$
$

2002
$ 259,916
4.37
$
4.36
$
11,132
$
(825)
$
10,307
$
0.19
$
0.19
$
0.17
$
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 ﬂow 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:

(thousands of dollars, except per share amounts)
Net revenues
Net earnings (loss) before discontinued operations
Net earnings (loss) from discontinued operations
Net earnings (loss)
Net earnings (loss) before discontinued operations
per common share

Net earnings (loss) per common share

- basic
- diluted
- basic
- diluted

Fiscal 2004 Three Months Ended

Dec. 31
162,880
(18,873)
1,120
(17,753)

(0.30)
(0.29)
(0.28)
(0.28)

$
$
$
$

Sep. 30
127,192
40,599
5,213
45,812

0.69
0.68
0.78
0.76

June 30
95,767
10,331
(395)
9,936

0.18
0.17
0.17
0.17

$
$
$
$

Fiscal 2003 Three Months Ended

Dec. 31
76,945
10,899
209
11,108

0.18
0.18
0.18
0.18

Sept. 30
65,415
(8,491)
108
(8,383)

(0.14)
(0.14)
(0.14)
(0.14)

$
$
$
$

June 30
65,101
(1,105)
(783)
(1,888)

(0.02)
(0.02)
(0.03)
(0.03)

$
$
$
$

Mar. 31
79,179
2,838
341
3,179

0.05
0.05
0.05
0.05

Mar. 31
91,446
(95)
409
314

-
-
0.01
0.01

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 35

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)
Land
Geological and geophysical
Drilling
Production equipment and facilities
Exploration and development expenditures
Summit Resources Limited acquisition
Property acquisitions
Proceeds on property dispositions
Other
Net capital expenditures
Property, plant and equipment, net, December 31
Total assets, December 31

2004
37,919
8,728
184,466
85,171
316,284
-
322,598
(61,806)
1,938
$ 579,014
$ 1,345,806
$ 1,542,786

2003
22,288
8,450
123,455
69,560
223,753
-
937
(371,601)
1,933
$
(144,978)
$ 1,037,307
$ 1,177,130

2002
6,410
9,303
124,076
77,407
217,196
251,422
28,610
(5,042)
2,349
$ 494,535
$ 1,411,961
$ 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.

36 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

INVESTMENTS

The Company has the following short-term investments:

Investments
Fox Creek Petroleum Corp.
Invertek (1)
Trinidad Drilling Ltd. (1)(2)
Arctos Petroleum Corp. (6)
Harvest Energy Trust
Jurassic Oil and Gas Ltd. (3)
Jurassic Oil and Gas Ltd. - Demand Note (4)
USD short-term deposits (5)

Opening
2004 Shares
2,325,162
-
-
-
200,000
850,000
-
-
3,375,162

Closing
Acquired
(Divested) 2004 Shares
2,325,162
-
820,513
-
-
850,000
-
-
3,995,675

-
-
820,513
-
(200,000)
-
-
-
620,513

Investment
$ 2,538,000
560,114
6,400,001
2,116,945
-
-
100,000
13,268,200
$ 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)
Debt
US$ senior notes
Credit facility
Working capital surplus
Net debt
Shareholders’ equity
Total capitalization

(1) At December 31, 2004 – 63,185,600 basic common shares outstanding.

DEBT

Amount

$/Share(1)

$ 257,836
201,305
(7,954)
451,187
625,039
$ 1,076,226

24
19
(1)
42
58
100%

4.08
3.19
(0.13)
7.14
9.89
17.03

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.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 37

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.

CR ED IT 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.

WO RKI NG CAPITAL
The Company’s working capital surplus at December 31, 2004 was $8.0 million (2003 - $10.5 million deﬁciency).

FU TUR E CO MMITMENTS
Future commitments, as at December 31, 2004, are as follows:

Contractual Obligations (thousands of dollars)
US$ 7 7/8% Senior Notes due 2010
$
US$ 8 7/8% Senior Notes due 2014
Pipeline commitments
Total

Total
160,174
97,662
237,205
495,041

Less than
1 year
-
-
22,015
22,015

Expected Payment Date

2-3
years
-
-
42,504
42,504

4-5
years
-
-
42,075
42,075

After
5 years
160,174
97,662
130,611
388,447

SH AR E 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:

Common shares
Balance December 31, 2002
Stock options exercised
Expenses recognized in respect of stock-based compensation
Balance December 31, 2003
Shares repurchased - at carrying value
Stock options exercised
Common shares issued
Flow-through shares issued
Tax adjustment on share issuance costs and flow-through share renunciations
Balance December 31, 2004

Number
59,458,600
710,000
(74,000)
60,094,600
(1,629,500)
220,500
2,500,000
2,000,000

63,185,600

Consideration
(thousands of dollars)
$ 190,193
10,317
(236)
$ 200,274
(5,322)
3,057
54,901
57,981
(7,959)
$ 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.

38 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

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

Balance, beginning of year
Granted
Exercised
Cancelled
Balance, end of year
Options exercisable, end of year

RISKS AND UNCERTAINTIES

2004

2003

Average
Grant Price
9.64
$
17.09
9.97
9.09
10.41
10.26

$
$

Options
3,632,000
348,000
(618,500)
(149,000)
3,212,500
1,282,875

Average
Grant Price
14.25
$
9.66
14.29
10.30
9.64
10.72

$
$

Options
1,949,500
2,998,000
(791,000)
(524,500)
3,632,000
1,087,875

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

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 39

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
Crude oil/liquids

2005 Average Prices
Natural gas
Crude oil (WTI)

2005 Exchange Rate (C$/US$)

210 MMcf/d
10,000 Bbl/d

$6.50/Mcf
US$42.00/Bbl

$0.81

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

Sensitivity
Gas sales change of 10 MMcf/d
Gas price change of $0.10/Mcf
Oil and natural gas liquids sales change of 100 Bbl/d
Oil and natural gas liquids price change of $1.00/Bbl (WTI)
Sensitivity to Canada/US exchange rate fluctuation of $0.01 CDN
Average interest rate change of 1%

CRITICAL ACCOUNTING ESTIMATES

Cash Flow Effect
(millions of dollars)
18.98
6.13
1.27
3.60
1.21
0.62

$
$
$
$
$
$

The MD&A is based on the Company’s consolidated ﬁnancial statements, which have been prepared in Canadian dollars
in accordance with Canadian GAAP. The application of Canadian 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.

AC C OUNTIN G FOR PET ROL EUM A ND NA T UR A L GA S O PER A TIONS
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

40 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

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 ESTIMATE S
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.

IMPAI RMENT OF PETROLEUM A ND N A TUR A L GA S PR OP ER TIES
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.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 41

AS S ET RETIREM ENT OBLIGAT IONS
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.

I NCOME 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

I MPA IRMENT OF LO NG-LIVED A S S ET S
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).

DIS POSAL OF LONG-LIVED A S S ET S A ND D IS C ON TINUE D OPER A TIONS
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.

VA RIA BLE IN TEREST ENTITIE S
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.

42 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

MD&A

ASSET RETIREMENT OBLIGAT IONS
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.

FINANCIAL INS TRUMENTS, OT H ER C OM P R EH EN S IV E I NC OM E A ND EQU ITY
The CICA is expected to adopt a new standard in 2005 that sets-out comprehensive requirements for recognition and
measurement of ﬁnancial instruments. Under this new standard, an entity would recognize a ﬁnancial asset or liability only
when the entity becomes a party to the contractual provisions of the ﬁnancial instrument. Financial assets and ﬁnancial
liabilities would, with certain exceptions, be initially measured at fair value. After initial recognition, the measurement of
ﬁnancial assets would vary depending on the category of the asset: ﬁnancial assets held for trading (at fair value with the
unrealized gains and losses on assets recorded in income), held-to-maturity investments (at amortized cost), loans and
receivables (at amortized cost), and available-for-sale ﬁnancial assets (at fair value with the unrealized gains and losses on
assets recorded in comprehensive income). Financial liabilities held for trading would be subsequently measured at fair
value while all other ﬁnancial liabilities would be subsequently measured at amortized cost using the effective interest
method.

In conjunction with the proposed new standard on ﬁnancial instruments as discussed above, a new standard on reporting
and display of comprehensive income is also expected. A statement of comprehensive income would be included in
a full set of ﬁnancial statements for both interim and annual periods under this new standard. Comprehensive income
is deﬁned as the change in equity (net assets) of an enterprise during a period from transactions and other events and
circumstances from non-owner sources. The new statement would present net income and each component to be
recognized in other comprehensive income. Likewise, the CICA is expected to adopt a new standard on Equity that would
require the separate presentation of: the components of equity (retained earnings, accumulated other comprehensive
income, the total of retained earnings and accumulated other comprehensive income, contributed surplus, share capital
and reserves); and the changes in equity arising from each of these components of equity.

These new standards are expected to be effective for the year ending December 31, 2006 for the Company.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 43

MANAGEMENT’S REPORT

The accompanying consolidated ﬁnancial statements of Paramount Resources Ltd. and all the information in this Annual
Report are the responsibility of management and have been approved by the Board of Directors.

The consolidated ﬁnancial statements have been prepared by management in accordance with Canadian generally
accepted accounting principles. When alternative accounting methods exist, management has chosen those it deems
most appropriate in the circumstances. Financial statements are not precise since they include certain amounts based
on estimates and judgments. Management has determined such amounts on a reasonable basis in order to ensure that
the consolidated ﬁnancial statements are presented fairly, in all material respects. The ﬁnancial information contained
elsewhere in this report has been reviewed to ensure consistency with the consolidated ﬁnancial statements.

Management maintains systems of internal accounting and administrative controls of high quality, consistent with
reasonable cost. Such systems are designed to provide reasonable assurance that the ﬁnancial information is relevant,
reliable and accurate and that the Company’s assets are appropriately accounted for and adequately safeguarded.

The Audit Committee of the Board of Directors is comprised of non-management directors. The Audit Committee meets
quarterly with management as well as the external auditors to discuss auditing matters and ﬁnancial reporting issues
and to satisfy itself that each party is properly discharging its responsibility. The Audit Committee also meets with
management and the external auditors to discuss internal controls over the ﬁnancial reporting process and to review the
Annual Report. The Audit Committee reports its ﬁndings to the Board of Directors for consideration when approving the
consolidated ﬁnancial statements for issuance to the shareholders. The Audit Committee also considers, for review by the
Board of Directors and approval by the shareholders, the engagement or re-appointment of the external auditors.

The consolidated ﬁnancial statements have been audited by Ernst & Young LLP, the external auditors. Ernst & Young LLP
have full and free access to the Audit Committee and management.

signed

Clayton H. Riddell
Chief Executive Ofﬁcer

signed

Bernard K. Lee
Chief Financial Ofﬁcer

AUDITORS’ REPORT

March 7, 2005

To the Shareholders of Paramount Resources Ltd.
We have audited the consolidated balance sheets of Paramount Resources Ltd. as at December 31, 2004 and 2003 and
the consolidated statements of earnings and retained earnings and cash ﬂows for the years then ended. These ﬁnancial
statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these
ﬁnancial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards and the standards of the
Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit
to obtain reasonable assurance whether the ﬁnancial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in the ﬁnancial statements. An audit also
includes assessing the accounting principles used and signiﬁcant estimates made by management, as well as evaluating
the overall ﬁnancial statement presentation.

In our opinion, these consolidated ﬁnancial statements present fairly, in all material respects, the ﬁnancial position of the
Company as at December 31, 2004 and 2003 and the results of its operations and its cash ﬂows for the years then ended
in accordance with Canadian generally accepted accounting principles. We also report that, in our opinion, these principles
have been applied, except for the change in the method of accounting for Asset Retirement Obligations, Financial
Instruments, and Stock-Based Compensation and Other Stock-Based Payments as explained in note 2 to the consolidated
ﬁnancial statements, on a basis consistent with that of the preceding year.

Ernst & Young LLP
Chartered Accountants

Calgary, Canada

March 7, 2005

44 PARAMOUNT RESOURCE S LTD. 20 04 ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

FINANCIAL STATEMENTS

As at December 31 (thousands of dollars)
ASSETS (note 8)
Current Assets
Short-term investments (market value: 2004 - $27,149; 2003 - $17,265)
Accounts receivable
Financial instruments (note 11)
Prepaid expenses
Assets of discontinued operations (note 5)

Property, Plant and Equipment
Property, plant and equipment, at cost (note 6)
Accumulated depletion and depreciation (note 6)
Assets of discontinued operations, net (note 5)

Goodwill
Other assets

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities
Financial instruments (note 11)
Liabilities of discontinued operations (note 5)

Long-term debt (note 8)
Asset retirement obligations (note 7)
Deferred revenue
Stock based compensation liability (note 9)
Future income taxes (note 10)
Liabilities of discontinued operations (note 5)

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)

Contributed surplus
Retained earnings

See accompanying notes to consolidated financial statements.

On behalf of the Board

signed

C.H. Riddell
Director

signed

J.B. Roy
Director

2004

2003

(restated - notes 2 and 5)

24,983
107,843
21,564
3,260
-
157,650

1,933,104
(587,298)
-
1,345,806
31,621
7,709
$ 1,542,786

16,551
80,710
-
2,255
1,680
101,196

1,444,139
(418,225)
11,393
1,037,307
31,621
7,006
$ 1,177,130

$ 147,508
2,188
-
149,696
459,141
101,486
-
41,044
166,380
-
768,051

$ 109,334
-
2,455
111,789
287,237
61,554
3,959
-
206,684
9,874
569,308

302,932
-
322,107
625,039
$ 1,542,786

200,274
746
295,013
496,033
$ 1,177,130

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN NUAL REP ORT 45

CONSOLIDATED STATEMENTS of
EARNINGS and RETAINED EARNINGS

Year Ended December 31 (thousands of dollars except per share amounts)
Revenue
Petroleum and natural gas sales
Transportation costs (note 2)
Gain (loss) on financial instruments (note 11)
Royalties (net of Alberta Royalty Tax Credit)
Loss on sale of investments

Expenses
Operating
Interest

General and administrative
Stock based compensation expense (note 9)
Bad debt expense (recovery)
Lease rentals
Geological and geophysical
Dry hole costs (note 6)

(Gain) loss on sales of property, plant and equipment

Accretion of asset retirement obligations
Depletion and depreciation
Writedown of petroleum and natural gas properties (note 6)
Unrealized foreign exchange gain on US debt
Realized foreign exchange gain on US debt (note 8)
Premium on redemption of US debt (note 8)

Earnings (loss) before income taxes
Income and other taxes (note 10)
Large Corporations Tax and other
Future income tax expense (recovery)

Net earnings from continuing operations
Net earnings (loss) from discontinued operations (note 5)
Net earnings
Retained earnings, beginning of period
Adjustment on disposition of assets to Paramount Energy Trust (note 4)
Dividends declared (note 4)
Purchase and cancellation of share capital (note 9)
Change in accounting policy (note 2)
Retained earnings, end of the year

Net earnings from continuing operations per common share

- basic
- diluted

Net earnings (loss) from discontinued operations per common share

- basic
- diluted

Net earnings per common share

- basic
- diluted

Weighted average common shares outstanding (thousands)

- basic
- diluted

See accompanying notes to consolidated financial statements.

46 PARAMOUNT RESOURCES LTD. 20 04 A NNUAL R EP ORT

2004

2003

(restated - notes 2 and 5)

$ 581,901
(31,285)
18,693
(105,046)
(34)
464,229

$ 464,558
(30,499)
(53,204)
(82,512)
(1,020)
297,323

95,767
25,399
25,247
41,195
(5,523)
3,546
8,728
24,676
(16,255)
6,920
191,578
-
(24,188)
(7,161)
11,950
381,879
82,350

81,193
19,214
19,051
1,214
5,977
3,574
8,450
36,600
3,640
4,044
165,098
10,418
(1,566)
-
-
356,907
(59,584)

6,795
40,660
47,455
34,895
6,279
41,174
295,013
-
-
(14,080)
-
$ 322,107

2,689
(63,481)
(60,792)
1,208
(57)
1,151
355,912
(6,923)
(51,000)
-
(4,127)
$ 295,013

$
$

0.58
0.57

0.11
0.10

0.69
0.67

$
$

0.02
0.02

-
-

0.02
0.02

59,755
61,026

60,098
60,472

CONSOLIDATED
STATEMENTS of CASH FLOWS

Year Ended December 31 (thousands of dollars except per share amounts)
Operating activities
Net earnings from continuing operations
Add (deduct)
Depletion and depreciation
Writedown of petroleum and natural gas properties

(Gain) loss on sales of property, plant and equipment

Accretion of asset retirement obligations
Future income tax (recovery) expense
Amortization of other assets
Non-cash stock based compensation expense
Non-cash gain on financial instruments
Unrealized foreign exchange gain on US debt
Realized foreign exchange gain on US debt
Premium on redemption of US debt
Dry hole costs
Geological and geophysical costs
Cash flow from continuing operations
Cash flow from discontinued operations
Cash flow from operations
Decrease in deferred revenue
Asset retirement obligations expenditures

Increase in other assets

Change in non-cash operating working capital from continuing operations (note 12)
Change in non-cash operating working capital from discontinued operations

Financing activities
Bank loans - draws
Bank loans - repayments
Shareholder loan
Proceeds from US debt offering, net of issuance costs
Redemption of US debt
Premium on redemption of US debt
Realized foreign exchange gain on US debt
Capital stock - issued, net of issuance costs
Capital stock - purchased and cancelled
Discontinued operations

Cash flow (used in) provided by operating and financing activities
Investing activities
Property, plant and equipment expenditures
Petroleum and natural gas property acquisitions
Proceeds on sale of property, plant and equipment
Change in non-cash investing working capital (note 12)
Discontinued operations
Cash flow used in investing activities

Increase (decrease) in cash
Cash, beginning of the year
Cash, end of the year

See accompanying notes to consolidated financial statements.

FINANCIAL STATEMENTS

2004

2003

(restated - notes 2 and 5)

34,895

1,208

191,578
-
(16,255)
6,920
40,660
1,277
41,195
(19,376)
(24,188)
(7,161)
11,950
24,676
8,728
294,899
667
295,566
(3,959)
(1,214)
-
(27,320)
-
263,073

431,951
(298,173)
-
162,917
(105,686)
(8,864)
7,161
115,043
(19,401)
(11,301)
273,647
536,720

(315,698)
(322,598)
61,939
27,349
12,288
(536,720)
-
-
-

165,098
10,418
3,640
4,044
(63,481)
161
1,214
-
(1,566)
-
-
36,600
8,450
165,786
1,490
167,276
(3,845)
-
(161)
(33,582)
201
129,889

42,933
(477,338)
(33,000)
221,447
-
-
-
10,317
(705)
(190)
(236,536)
(106,647)

(224,229)
(228)
317,792
14,828
(1,516)
106,647
-
-
-

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 47

NOTES to CONSOLIDATED
FINANCIAL STATEMENTS

(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 ) PRI NCI PLES OF CONSOL ID A TION
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) J OINT O PERATIONS
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 RE COGNITION
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 INVES TMENTS
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 percent to 2.23 percent, debentures and convertible debentures bearing
interest between 6 percent to 8 percent and investments in the common shares and Trust units.

(E) PRO PERTY, PLANT AND EQUIP ME NT

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

48 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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 years to 40 years. Depreciation of other equipment is provided on a declining balance
method at rates varying from 4 percent 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 OB LIGA TION S
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

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 49

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 ) F OREIGN CURR ENCY TRA NSL A T ION
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.

F INANCI AL INSTRUMENT S

(I)
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 UNC ER T A INTY
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.

INCOME T AXES

(K)
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.

F LOW-THROUGH S HARE S

(L )
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.

50 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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 PL AN
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 OTH E R A S SE TS
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 SH AR E A MOUNT S
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 OBLIGAT IONS
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.

FINANCIAL INS TRUMENTS
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

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 51

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).

TRA NS PO RTATION COS TS
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.

STO CK -BASED COMPENSATION A ND OTH E R S TOC K -B A SED PA Y M ENTS
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. During 2004, the Company reviewed its historical practices and
determined that the Company has generally settled in cash when the option holder requested cash upon exercise of their
options. Accordingly, 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

$1 85 MILLIO N ASSET A CQUISIT ION
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
Less: Asset retirement obligations

$ 211,947
26,847
$ 185,100

$8 7 MILLION ASSET ACQUIS IT ION
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:

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.

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.

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.

52 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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
Future income tax liability
Site restoration liability
Costs of disposition
Charge to retained earnings
Net proceeds on disposition

$ 244,433
4,070
(5,900)
10,430
(6,638)
$ 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 Shehtah 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:

Shehtah Wilson

Wilson Drilling Ltd. Drilling Partnership
2003

2003

2004

Building

Total

2004

2003

2004

2003

908

$ 1,390

327

622

$ 1,235

Revenue
Other Income
Expenses
Interest

General and administrative
Depreciation

250
642
655

319
270
898

(Gain) loss on sale of
property and equipment (6,659)
(5,112)

20
1,507

-
384
6

(27)
363

-
496
6

367
(308)
278

383
(1,133)
300

617
718
939

$ 2,012
-
702
(367)
1,204

-
502

(2,569)
(2,232)

-
(450)

(9,255)
(6,981)

20
1,559

Net earnings (loss)
before income tax
Large Corporation
Tax and other
Future income tax expense
Net earnings (loss) from
discontinued operations

6,020

(117)

(36)

120

2,232

450

8,216

1,857
94

-
324

-
-

(34)
20

186
-

1,823
114

453

186
324

$ 4,069

(441) $

(36) $

120

$ 2,246

264

$ 6,279

(57)

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 53

Shehtah Wilson

Wilson Drilling Ltd. Drilling Partnership
Dec-31
Dec-31
2003
2004

Dec-31
2004

Dec-31
2003

Building

Total

Dec-31
2004

Dec-31
2003

Dec-31
2004

Dec-31
2003

Current Assets
Accounts Receivable
Prepaid Expenses
Property, plant and
equipment, net
Current Liabilities
Accounts payable and
accrued liabilities

Current portion of
long-term debt

Long-term debt

-
-

3,234

1,138
$ 3,456

-
-

$ 1,653
27

1,005

-
-

8,097

-
-

$ 1,653
27

11,393

1,005

312
$ 6,418

-
-

1,450
$ 9,874

6. PROPERTY PLANT AND EQUIPMENT

Petroleum and natural gas properties
Gas plants, gathering systems and
production equipment
Other
Assets held for sale

Net book value

2004

Cost Accumulated
Depletion and
Depreciation

2003

Cost

1,351,950

450,518

(restated - notes 2 and 5)
986,919

Accumulated
Depletion and
Depreciation
(restated - notes 2 and 5)
307,156

548,838
32,316
-
1,933,104
$

127,724
9,056
-
587,298

436,772
20,448
14,865
1,459,004
$

$
1,037,307

101,120
9,949
3,472
421,697

$
1,345,806

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.

54 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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 December 31

Asset retirement obligation, beginning of year
Liabilities incurred
Liabilities settled
Accretion expense
Asset retirement obligation, end of year

2004

2003
(restated - notes 2 and 5)

$ 61,554
36,812
(3,800)
6,920
$ 101,486

$ 53,625
3,885
-
4,044
$ 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:

7 7/8% US Senior Notes due 2010 (US$133.3 million)
8 7/8% US Senior Notes due 2014 (US$81.3 million)
Credit facility – current interest rate of 3.8% (2003 - 4.5%)

2004

$ 160,174
97,662
201,305
$ 459,141

2003
(restated - notes 2 and 5)
$ 226,887
-
60,350
$ 287,237

SENIOR N OTES
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

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 55

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.

CR ED IT 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

AUTH ORIZED 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
Balance December 31, 2002
Stock options exercised during the year
Shares repurchased - at carrying value
Balance December 31, 2003
Shares repurchased - at carrying value
Stock options exercised
Common shares issued, net of issuance costs
Flow through shares issued, net of issuance costs
Tax adjustment on share issuance costs and flow-through share renunciations
Balance December 31, 2004

Number Consideration
$ 190,193
10,317
(236)
$ 200,274
(5,322)
3,057
54,901
57,981
(7,959)
$ 302,932

59,458,600
710,000
(74,000)
60,094,600
(1,629,500)
220,500
2,500,000
2,000,000
-
63,185,600

I SSUE D CAPIT AL
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 March 7, 2005, 101,050 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.

56 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

STOCK OPTION PL AN
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.

Stock options

2004

2003

Balance, beginning of year
Granted
Exercised
Cancelled
Balance, end of year
Options exercisable, end of year

Average
Grant Price
9.64
17.09
9.97
9.09
10.41
10.26

$
$

Options
3,632,000
348,000
(618,500)
(149,000)
3,212,500
1,282,875

Average
Grant Price
14.25
9.66
14.29
10.30
9.64
10.72

$
$

Options
1,949,500
2,998,000
(791,000)
(524,500)
3,632,000
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:

Exercise
Prices
$8.91-9.80
$10.01-12.02
$12.51-26.29
Total

Outstanding

Number
2,088,000
820,500
304,000
3,212,500

Weighted Average Weighted Average
Exercise Price
9.02
11.04
18.01
$ 10.41

Contractual Life
3
1
4
2

Exercisable
Exercisable Weighted Average
Exercise Price
9.00
11.25
-
$ 10.26

Number
561,375
721,500
-
1,282,875

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.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 57

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:

Corporate tax rate
Calculated income tax expense (recovery)
Increase (decrease) resulting from:
Non-deductible Crown charges, net of Alberta Royalty Tax Credit
Federal resource allowance
Federal and provincial income tax rate adjustment
Attributed Canadian Royalty Income recognized
Large Corporations Tax and other
Non-taxable portion of gain on sale of investments
Stock based compensation
Recognition of tax pools not previously recognized
Other
Income tax expense (recovery)

COMPONENTS OF FUTURE INC OME TA X E S

The net future tax liability comprises:
Differences between tax base and reported amounts of depreciable assets
Asset retirement obligations
Stock-based compensation liability
Other

2004
39.04%
32,150

2003
40.67%
(24,233)

25,455
(21,787)
481
(1,469)
6,795
(4,301)
3,205
-
6,926
47,455

21,991
(17,124)
(30,257)
(5,228)
2,875
-
-
(3,343)
(5,473)
(60,792)

2004
$ 215,583
(34,281)
(12,405)
(2,517)
$ 166,380

2003
$ 227,697
(23,486)
-
2,473
$ 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
Financial instrument asset
Financial instrument liability
Net financial instrument asset

2004
21,564
(2,188)
19,376

58 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

Year Ended December 31, 2004
Fair value of contracts, January 1, 2004
Change in fair value of contracts recorded on transition,
still outstanding at December 31, 2004
Amortization of the fair value of contracts as at December 31, 2004
Fair value of contracts entered into during the period
Unrealized gain (loss) on financial instruments
Realized loss on financial instruments

for the year ended December 31, 2004

Net gain on financial instruments

for the year ended December 31, 2004

Net Deferred
Amounts on

Mark-to
Market
Transition Gain (Loss)
1,450
$

(1,450)

Total
-

-
(196)
-
(1,646)

1,301
-
18,271
$ 21,022

1,301
(196)
18,271
$ 19,376

(683)

$ 18,693

INTEREST RATE CONTRA C TS

(A)
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
Transaction
Swap of 7 7/8%
US$ Senior Notes

Maturity Date
November 1, 2010

Notional
Amount
US$175
million

Indenture
Interest
US$ fixed

Swap to
US$ floating

Effective Rate
US$ LIBOR plus
320 Basis Points

(B) FOREIGN EXC HANGE CONTR A C TS
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
2005

US dollars
12,000

Weighted average exchange rate
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.

Put/Call
Put
Call
Put
Call

Strike
1.2048
1.1765
1.1976
1.1628

Foreign Exchange Option Currencies
USD/CDN
USD/CDN
USD/CDN
USD/CDN

Notional - CDN$
$ 60,240,000
$ 58,825,000
$ 59,880,000
$ 58,140,000

Expiry Date
January 12, 2005
January 12, 2005
January 10, 2005
January 10, 2005

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 59

(C) COMMO DITY PRICE CONT R A C T S
At December 31, 2004, the Company has entered into ﬁnancial forward contracts as follows:

Amount

Price

Term

10,000 MMbtu/d
10,000 MMbtu/d
10,000 MMbtu/d
20,000 GJ/d
20,000 GJ/d
20,000 GJ/d
20,000 MMbtu/d
20,000 GJ/d
20,000 GJ/d
20,000 GJ/d

6.41
US$
7.46
US$
7.95
US$
7.90
$
8.03
$
$
7.60
US$ 10.00 Strike
6.28
$
6.30
$
6.80
$

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 ) F AI R VALUES OF FINANCIA L A SS ET S A ND L IA B IL ITI ES
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) CREDI T 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.

INTEREST RATE RISK

(F )
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.

60 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

12. CHANGE IN NON-CASH WORKING CAPITAL

Change in non-cash working capital:
Short-term investments
Accounts receivable
Prepaid expenses
Accounts payable and accrued liabilities
Discontinued operations

Operating activities
Investing activities

FINANCIAL STATEMENTS

2004

2003

(10,532)
(25,480)
(978)
37,019
-
29
(27,320)
27,349
29

(283)
6,859
1,829
(26,958)
(201)
(18,754)
(33,582)
14,828
(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:

Interest paid
Large Corporations and other taxes paid, including settlements

13. RELATED PARTY TRANSACTIONS

2004
18,951
31,021

$
$

2003
17,497
2,395

$
$

DISPOSITION OF ASSET S TO P A RA MOU NT E NER G Y T R US T
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

CONT ING ENCIES
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.

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

Year
2005
2006
2007
2008
2009
Thereafter

Commitment
22,015
21,252
21,252
21,252
20,823
130,611
$ 237,205

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 61

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

Sales Contracts
Station 2 Fixed Price
Station 2 Fixed Price

15. COMPARATIVE FIGURES

Amount

Price

Term

8,000 GJ/d
12,000 GJ/d

$
$

7.99
8.00

November 2004 - March 2005
November 2004 - March 2005

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

16. SUBSEQUENT EVENTS

TRU ST 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 PA R TNER SH IP
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.

62 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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 December 31

Net earnings for the year as reported
Adjustments, net of tax
Forward foreign exchange contracts and other financial instruments (a)
Impairments and related change in depletion (c)
General and administrative (i)
Short-term investments (f)
Future income taxes (b)
Earnings from discontinued operations (e)
Earnings before discontinued operations and change in accounting policy
Earnings from discontinued operations (e)
Change in accounting policy - Asset Retirement Obligation (d)
Net earnings for the year - US GAAP

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

Net earnings per common share - US GAAP
Basic
Diluted

2004

41,174

2003
(restated - notes 2 and 5)
1,151

(1,053)
5,385
-
929
(5,633)
-
40,802
-
-
40,802

0.68
0.67

3,411
11,546
703
428
-
(8,593)
8,646
8,593
(4,127)
13,112

0.14
0.14

0.22
0.22

$
$

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

Assets
Short-term investments (f)
Financial instrument assets (a)
Property, plant and equipment (c)(d)

Liabilities
Accounts payable and accrued liabilities (b)
Deferred hedging loss (a)
Financial instrument liability (a)
Deferred revenue (a)
Future income taxes (a)(b)(c)(f)

Shareholders’ equity
Common shares (b)
Retained earnings

2004

2003

As Reported

US GAAP

24,983
21,564
1,345,806

27,149
18,271
1,350,286

As Reported
(restated - notes 2 and 5)
16,551
-
1,037,307

US GAAP

17,265
-
1,033,373

147,508
-
2,188
-
166,380

152,893
-
542
-
167,587

109,334
-
-
3,959
206,684

109,334
1,726
-
-
206,570

302,932
322,107

303,180
324,253

200,274
295,013

200,274
298,295

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 63

(A )

F ORWARD FOREIGN EX C H A NGE C ONT R A C TS A ND
OTHER FINAN CIAL INST RUME NT S

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 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) F UTU RE 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) PRO PERTY, PLANT AND EQUIP ME NT
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.

64 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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)
Beginning balance at January 1
Additions pending the determination of proved reserves
Reclassifications to proved properties
Charged to dry hole expense
Wells sold during the period
Ending balance at December 31

2004
46
110
(24)
(14)
-
118

2003
99
15
(18)
(23)
(27)
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)
Capitalized exploratory costs that have been capitalized for a period of one year or less
Capitalized exploratory costs that have been capitalized for a period of greater that one year
Balance at December 31
Number of projects that have exploratory well costs that have been
capitalized for a period greater than one year

2004
86
32
118

2003
19
27
46

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.

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 65

(D ) A SSET RETIREMENT OB LIGA TIONS
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) D ISCONTINUED OPERA T IONS
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 INVES TMENTS
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 COM PREHENS IV E INC OME
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 ) STATEMENT S OF CASH F LOW
The application of US GAAP would change the amounts as reported under Canadian GAAP for cash ﬂows provided by
(used in) operating, investing or ﬁnancing activities. For US GAAP, dry hole costs of $24.7 million (2003 - $36.6 million)
are not added back in calculating cash ﬂow from operations. For Canadian GAAP, 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 US GAAP, for the year ended December 31, 2004,
there would be a reduction of $27.3 million (2003 – reduction of $14.8 million). The presentation of cash ﬂow from
operations is a non US GAAP terminology.

STO CK-BASED COMPENSA T ION

(I)
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.

66 PARAMOUNT RESOURCE S LTD. 20 04 A NNUA L R EP ORT

FINANCIAL STATEMENTS

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

Year ended December 31
Net earnings for the period – US GAAP
Stock-based compensation expense determined under the fair value
based method for all awards, net of related tax effects
Pro forma net earnings – US GAAP
Net earnings per common share
Basic

- as reported
- pro forma

Diluted

- as reported
- pro forma

2003
13,112

(703)
12,409

0.22
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/SEL L AR RA NGE ME NT S
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

PARAMOUN T RES OU RCE S LTD. 2 0 0 4 AN N UA L REP ORT 67

CORPORATE INFORMATION

OFFICERS

C. H. Riddell
Chairman of the Board and
Chief Executive Ofﬁcer

B. K. Lee
Chief Financial Ofﬁcer

J. H. T. Riddell
President and Chief Operating Ofﬁcer

C. E. Morin
Corporate Secretary

L. M. Doyle
Corporate Operating Ofﬁcer

C. G. Folden
Corporate Operating Ofﬁcer

J. S. McDougall
Corporate Operating Ofﬁcer

G. W. P. McMillan
Corporate Operating Ofﬁcer

J. B. Williams
Corporate Operating Ofﬁcer

L. A. Friesen
Assistant Corporate Secretary

DIRECTORS

C. H. Riddell(3)
Chairman of the Board and
Chief Executive Ofﬁcer
Paramount Resources Ltd.
Calgary, Alberta

J. H. T. Riddell
President and
Chief Operating Ofﬁcer
Paramount Resources Ltd.
Calgary, Alberta

J. C. Gorman(1) (4)
Retired
Calgary, Alberta

D. Jungé, C.F.A(4)
Chairman of the Board
Pitcairn Financial Group
Jenkintown, Pennsylvania
Calgary, Alberta

D. M. Knott
General Partner
Knott Partners, L.P.
Syosset, New York
Calgary, Alberta

W. B. MacInnes, Q.C.(1) (2) (3) (4)
Retired
Calgary, Alberta

V. S. A. Riddell
Business Executive
Calgary, Alberta

S. L. Riddell Rose
President and
Chief Operating Ofﬁcer
Paramount Energy Trust
Calgary, Alberta

J. B. Roy(1) (2) (3) (4)
Independent Businessman
Calgary, Alberta

A. S. Thomson(1) (4)
President
Touche, Thomson & Yeoman
Investment Consultants Ltd.
Calgary, Alberta

B. M. Wylie(2)
Business Executive
Calgary, Alberta

(1) Member of Audit Committee
(2) Member of Environmental, Health and

Safety Committee

(3) Member of Compensation Committee
(4) Member of Corporate Governance

Committee

HEAD OFFICE

4700 Bankers Hall West
888 Third Street S. W.
Calgary, Alberta
Canada T2P 5C5
Telephone: (403) 290-3600
Facsimile: (403) 262-7994
www.paramountres.com

CONSULTING
ENGINEERS

McDaniel & Associates
Consultants Ltd.
Calgary, Alberta
Paddock Lindstrom
& Associates Ltd.
Calgary, Alberta

AUDITORS

Ernst & Young LLP
Calgary, Alberta

BANKERS

Bank of Montreal
Calgary, Alberta
Canadian Imperial Bank of
Commerce
Calgary, Alberta
The Bank of Nova Scotia
Calgary, Alberta
UBS AG Canada Branch
Toronto, Ontario

REGISTRAR AND
TRANSFER AGENT

Computershare Investor Services
Canada
Calgary, Alberta
Toronto, Ontario

STOCK EXCHANGE
LISTING

The Toronto Stock Exchange
(‘POU’)

68 PARAMOUNT RESOURCES LTD. 20 04 A NNUAL R EP ORT

ANALYST SUPPLEMENT

This handbook has been prepared by Paramount Resources Ltd. to
address the special information needs of the investment community and
the sophisticated investor. The handbook provides detailed performance
data and key ratios. For additional information please contact:

B.K. (Bernard) Lee, Chief Financial Officer
Paramount Resources Ltd.
Suite 4700 Bankers Hall West, 888 Third Street S.W.
Calgary, Alberta, Canada T2P 5C5
Tel (403) 290-3600 Fax (403) 262-7994 www.paramountres.com

C O R P O R AT E P R O F I L E

C O N S O L I D AT E D E A R N I N G S & C A S H F L O W D ATA

Paramount Resources Ltd. is a Canadian energy company with its
revenue derived primarily from natural gas sales. The Company explores
for, develops, produces and markets natural gas, crude oil and natural gas
liquids. Paramount has an aggressive, focused exploration and
development strategy, concentrated on acquiring land and establishing
reserves throughout the Western Canadian Sedimentary Basin.

26 years old

277 employees (171 head office, 106 field)

Listed on the Toronto Stock Exchange; symbol “POU”

Part of the S&P/TSX Composite Index

63.2 million shares outstanding at December 31, 2004

Market capitalization: $1.7 billion (December 31, 2004)

Year
2002
2003
2004

Basic
Cash Flow per Share
$ 4.37
$ 259.9 million
$ 2.78
$ 167.3 million
$ 4.95
$ 295.6 million

Basic
Earnings per Share
$ 0.17
$ 0.02
$ 0.69

$ 10.3 million
$
1.1 million
$ 41.2 million

Average number of common shares outstanding for 2004 was 59.8 million.

U N I Q U E T R A I T S

80 percent of 2004 production is natural gas.

“Successful efforts” accounting policy results in conservative net

earnings.

High management ownership (53 percent).

Successful full cycle exploration and development creates shareholder

value.

Proven performance record through 26 years of commodity price cycles.

Exposure to high impact exploration plays in Colville Lake and Northeast

Alberta bitumen project.

1 PARAMOUNT RESOURCES LTD. 20 0 4 ANNUA L RE P ORT

($ millions except per share amounts)
Year ended December 31

2004

2003 Change (%)

Revenue
Natural gas, net of transportation
$ 425.6
Crude oil and liquids, net of transportation 124.9
18.7
Gain (loss) on financial instruments
Royalties (net of Alberta Royalty Tax Credit) (105.0)
-
Loss on sale of investments
464.2
Net revenue

Expenses
Operating
Interest
General and administrative
Stock based compensation expense
Bad debt expense (recovery)
Lease rentals
Geological and geophysical
Dry hole costs
(Gain) loss on sales of property,
land and equipment

Accretion of asset retirement obligations
Depletion and depreciation
Write-down of petroleum and

95.8
25.4
25.2
41.2
(5.5)
3.5
8.7
24.7

(16.3)
6.9
191.6

$ 333.9
100.1
(53.2)
(82.5)
(1.0)
297.3

81.2
19.2
19.1
1.2
6.0
3.6
8.5
36.6

3.6
4.0
165.1

27
25
(135)
27
(100)
56

18
32
32
3,333
(192)
(3)
2
(33)

(553)
73
16

natural gas properties

Unrealized foreign exchange
gain on US debt
Realized foreign exchange
gain on US debt

Premium on redemption of US debt
Large Corporation Tax and other
Future income tax (recovery) expense

Net earning from continuing operations
Net earnings (loss)
from discontinued operations
Net earnings

10.4

(100)

(24.2)

(1.6)

1,413

(7.2)
12.0
6.8
40.7
429.3

34.9

-
-
2.7
(63.5)
296.1

-
-
152
(164)
45

1.2

2,808

6.3
$ 41.2

(0.1)
1.1

(6,400)
3,645

Net earnings per common share - basic $ 0.69

$ 0.02

3,350

C A S H F L O W R E C O N C I L I AT I O N

($ millions)
Year ended December 31
Net revenue (1)
Operating costs
Interest on long-term debt (excluding non-cash interest)
General and administrative
Bad debt recovery (expense)
Lease rentals
Current and Large Corporation Tax
Cash flow from continuing operations
Cash flow from discontinued operations
Cash flow from operations

2004
444.8
(95.8)
(24.1)
(25.2)
5.5
(3.5)
(6.8)
249.9
0.7
295.6

2003
297.4
(81.2)
(19.0)
(19.1)
(6.0)
(3.6)
(2.7)
165.8
1.5
167.3

Cash flow per common share – basic

4.95

2.78

(1) Net of realized financial instrument gains and losses, royalties, transportation costs,

and gains on sale of investments.

ANALYST SUPPLEMENT

M A J O R P R O D U C I N G P R O P E R T I E S

C A P I TA L E X P E N D I T U R E S

($ millions)

Drilling
Seismic
Facilities and equipment
Land acquisitions
Property acquisitions
Other

Property dispositions

Net capital expenditures

2004

2003

$ 184.5
8.7
85.2
37.9
322.6
1.9

$ 123.4
8.5
69.6
22.3
0.9
1.9

640.8
(61.8)

226.6
(371.6)

$ 579.0

$ (145.0)

The following table summarizes average production volumes from
Paramount’s major producing properties, for each of the last five fiscal years.

Natural Gas (MMcf/d)
Kaybob
Grande Prairie
Northwest Alberta
Liard – Northeast BC/NWT
Southern
Northeast Alberta
Other
Total

Crude Oil and Liquids (Bbl/d)
Kaybob
Grande Prairie
Northwest Alberta
Liard - Northeast BC/NWT
Southern
Other
Total

Total Production (Boe/d @ 6:1)
Kaybob
Grande Prairie
Northwest Alberta
Liard - Northeast BC/NWT
Southern
Northeast Alberta
Other
Total

2004
96.4
26.8
20.2
16.2
10.8
1.6
1.1
173.1

4,091
585
797
12
1,798
14
7,297

2003
79.5
12.4
22.3
11.6
9.5
16.2
1.3
152.8

2,451
1,767
448
9
2,457
37
7,169

2002
87.5
7.0
30.4
12.3
5.4
96.9
1.9
241.4

2.291
1.353
35
15
1,732
237
5,663

2001
65.3
3.1
29.2
9.3
–
108.7
9.4
225.0

1,855
–
–
21
130
159
2,165

2000
63.7
–
26.1
5.4
–
119.0
5.8
220.0

1,258
–
–
95
218
–
1,571

20,157 15,704 16,874 12,738 11,875
–
2,520
3,831
4,350
5,102
4,165
995
2,065
1,942
4,048
218
2,632
2,700 16,150 18,117 19,833
967
36,150 32,630 45,898 39,665 38,238

5,053
4,165
2,710
3,596
252
217

517
4,867
1,571
130

1,725

240

555

C O R E P R O D U C I N G P R O P E R T I E S

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PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL RE PORT 2

ANALYST SUPPLEMENT

B A L A N C E S H E E T I N F O R M AT I O N

NET ASSET VALUE PER COMMON SHARE

As at December 31 ($ millions)

2004

2003 Change (%)

As at December 31, 2004 ($ millions except per share amount)

Assets
Current assets
Property, plant and equipment, net
Other assets

158
1,346
39

1,543

Liabilities and Shareholders’ Equity
$
Current liabilities
Long-term debt
Asset retirement obligations
Deferred revenue
Stock based compensation liability
Future income taxes
Liabilities of discontinued operations
Shareholders’ equity

150
459
102
–
41
166
–
625

101
1,037
39

1,177

112
287
62
4
–
207
10
496

1,543

1,177

56
30
2

34
60
65
(100)
–
(19)
(100)
26

Discount rate

Present value of reserves (1,2)
Market value of short-term investments
Fair market value of undeveloped land
Other assets (3)
Subtotal
Working capital deficiency (4)
Debt

10%

$ 1659.3
27.1
185.4
184.5
2056.3
(17.0)
(459.1)

Net asset value
Net asset value per common share (5)
(1) Proved plus probable discounted at 10 percent, includes benefit of ARTC with

$ 1580.2
$ 25.01

no allowance for income tax.

(2) Based on Forecast Prices and Costs Assumptions.
(3) Includes seismic, projects under evaluation and other assets (all at cost).
(4) Excludes short-term investments.
(5) Based on outstanding common shares of 63,185,600 at December 31, 2004.

C A P I TA L S T R U C T U R E

The following table outlines Paramount’s capital structure since 2000.

($ thousands)

Debt
Common share equity
Retained earnings

2004

2003

2002

2001

2000

$ 459,141
302,932
322,107

$ 287,237
200,274
295,013

$ 539,270
190,193
355,912

$ 316,600
189,320
346,064

$ 315,000
189,320
228,934

$ 1,084,180

$ 782,524

$ 1,085,375

$ 851,984

$ 733,254

N E T D E B T

At December 31 ($ thousands)

Current assets (1)
Current liabilities (1)

Working capital (surplus) deficiency
Debt (1)

Net debt

(1) Excludes discontinued operations.

2004

2003

$ 157,650
149,696

(7,954)
459,141

$ 99,516
109,334

9,818
287,237

$ 451,187

$ 297,055

K E Y R AT I O S

The following key ratios to “fundamental analysis” have been calculated to
accompany the Cash Flow Reconciliation.

Cash Flow per Share

Share Price to Cash Flow Multiple

Debt to Cash Flow Ratio

Debt to Equity Ratio

Earnings per Share

E S T I M AT E D F U T U R E P R E - TA X C A S H F L O W

Rate of Return on Shareholders’ Equity

Reserves

Present Value of
Estimated Pre-tax

Before Royalty Cash Flow Discounted at:

Gas Oil/liquids
(MBbl)
(Bcf)

347.2
221.4

15,042
5,419

568.6

20,461

(millions of dollars)
15%

10%

1,156
503

1,022
398

1,659

1,420

Per share amounts for 2004 utilize the weighted average number of
common shares outstanding of 59,755,480.

Cash Flow
Paramount calculates its cash flow;

net of all lease rentals of both producing and non-producing properties

net of all cash general and administrative costs

net of all marketing costs which are currently expensed

net of all interest expenses, none of which are capitalized

Proved
Probable

Total

The discounted net present values of the estimated pre-tax cash flow
expected during the economic life of all reserves are based on estimates
using escalating price assumptions at rates of 10 percent and 15 percent
per annum compounded annually. They are calculated prior to the
consideration of income taxes but include ARTC, and are not to be
construed as representing the fair market value of properties. The fair
market value of the properties and such net present values will depend
upon the subjective considerations inherent to each property.

Net Earnings
Paramount further calculates its net earnings;

net of dry hole costs

net of geological and geophysical costs

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 3

ANALYST SUPPLEMENT

C A S H F L O W R E C O N C I L I AT I O N

E A R N I N G S P E R S H A R E

($ millions)

Gross revenue (1)
Net royalties (2)

Net revenue
Expenses
Operating

2004

549.9
(105.1)

December 31
2002

2003

2001

2000

379.9
(82.5)

473.9
(74.4)

528.4
(99.7)

391.5
(80.6)

444.8

297.4

399.5

428.7 310.9

Cash G&A

95.8
25.2
3.5
Lease rentals
Cash interest
24.1
Bad debt expense (recovery) (5.5)
Current income taxes
and other
Discontinued operations

6.8
(0.7)

81.2
19.1
3.6
19.0
6.0

2.7
(1.5)

86.1
15.9
4.6
23.9
–

9.1
–

61.1
12.4
4.3
19.3
–

27.7
–

48.0
9.7
5.2
22.3
–

2.3
–

Cash flow

295.6

167.3

259.9

303.9 223.4

(1) Includes realized financial instrument gains and losses on sale of investments,

and net of transportation.

(2) Net of ARTC.

C A S H F L O W A N D C A S H F L O W / S H A R E

Fiscal
year

2000
2001
2002
2003
2004

Cash
Flow
($ 000s)

223,446
303,937
259,916
167,276
295,566

Trend(1)

100
136
116
75
132

Shares(2)
(000s)

59,454
59,454
59,458
60,098
59,755

Cash
Flow per
Share ($) Trend(1)

3.76
5.11
4.37
2.78
4.95

100
136
116
74
132

(1) Trend with base year 2000, with a nominal value of 100.
(2) Weighted average shares outstanding.

S H A R E P R I C E T O C A S H F L O W M U LT I P L E

Fiscal
Year

2000
2001
2002
2003
2004

Share
Low

10.50
12.00
13.00
8.51
10.50

Price ($)
High

20.00
18.75
17.60
16.95
27.00

Cash
Flow per
Share ($)

3.76
5.11
4.37
2.78
4.95

Multiple
Low High

2.8x
2.3x
3.0x
3.1x
2.1x

5.3x
3.7x
4.0x
6.1x
5.5x

N E T D E B T T O C A S H F L O W R AT I O

Fiscal
year

2000
2001
2002
2003
2004

Net Debt
($ 000s)

Cash Flow
($ 000s)

Debt/cash
Flow Ratio

Flow

Trend(1)

292,360
290,698
555,243
297,055
451,187

223,446
303,937
259,916
167,276
295,566

1.3:1
1.0:1
2.1:1
1.8:1
1.5:1

100
73
163
136
117

(1) Trend with base year 2000 with a nominal value of 100.

D E B T T O E Q U I T Y R AT I O

Fiscal
Year
2000
2001
2002
2003 (2)
2004 (2)

Operating Shareholders’
Equity
($ 000s)
418,254
535,384
546,105
496,033
625,039

Debt
($ 000s)
315,000
316,600
539,270
287,237
459,141

Debt/
Equity
Ratio
0.75:1
0.59:1
0.99:1
0.60:1
0.73:1

Trend(1)
100
79
131
77
98

(1) Trend with base year 2000 with a nominal value of 100.
(2) Excludes discontinued operations.

Paramount’s earnings are net of dry hole costs, geological/
geophysical costs and all lease rentals.

Fiscal
year

2000
2001
2002
2003
2004

Net
Earnings
($ 000s)

86,062
118,902
10,307
1,151
41,174

Net
Shares(2) Earnings per

Trend(1)

100
138
12
1
48

(000s)

59,454
59,454
59,458
60,098
59,755

Share ($) Trend(1)

1.45
2.00
0.17
0.02
0.69

100
138
12
1
48

(1) Trend with base year 2000 with a nominal value of 100.
(2) Weighted average shares outstanding.

R ATE OF RE T UR N ON SHAR E HO LDE R ’S E Q UIT Y

Paramount has earned a weighted average after-tax rate of return
of 11.5 percent as computed on a book basis, based upon the weighted
average shareholders’ equity invested over the past five years.

($ thousands)

2004

2003

2002

2001

2000

Net earnings
Weighted average
Shareholders’ equity

After-tax rate

41,174

1,151 10,307 118,902 86,062

560,536 521,069 540,745 476,819 373,623

of return (%)

7.3

0.2

1.9

24.9

23.0

U N D E V E L O P E D L A N D

(thousands of acres)

Alberta
British Columbia
Saskatchewan
Northwest Territories
Montana, North Dakota
Other

Total Undeveloped Land

Net land

Proved
Undeveloped

Total net land

Gross

Net

2,190
348
17
1,235
102
1,644

1,649
258
13
661
39
822

5,536

3,442

2004

2003

640
3,442

586
2,800

4,082

3,386

Appraised value of undeveloped land (1)

$ 185.4 $ 98.2

(1) Millions of dollars.

Appraised value is an estimate of the fair market value of acreage based
upon current analogous sales. Approximately 84 percent of the total net
2004 land inventory of 4.1 million acres is undeveloped.

PARAMOUN T RES OURCE S LT D. 2 0 0 4 A N N UAL R E PORT 4

ANALYST SUPPLEMENT

O I L & G A S S A L E S A N D G R O S S P R O F I T

This illustrates oil and gas sales since 2000 and converts the oil sales into barrels of equivalent (Boe) on an industry standard basis of one barrel
of crude oil/liquids equals 6 Mcf of natural gas.

P&NG Revenue
(after financial instruments
and transportation costs)

Fiscal year(1)

($ 000s)

Trend

2000
2001
2002
2003
2004

391,470
525,686
431,001
380,855
569,309

100
134
110
97
145

Oil & Liquids
Gas Production
(MMcf) Trend

80,520
82,125
88,111
55,760
63,360

100
102
109
69
79

(1) Trend with base year 2000, with nominal value of 100

O P E R AT I N G C A S H N E T B A C K S

Production
(Bbl) Trend

574,986
790,225
2,066,995
2,616,706
2,670,794

100
137
359
455
464

Average Price
(after realized
financial instruments)
Gas ($) Oil ($)

4.59
6.12
4.08
5.16
6.86

37.80
35.48
34.64
35.50
44.13

Barrel of
Equivalent
Production
(MBoe) Trend

13,995
14,478
16,753
11,910
13,231

100
103
120
85
95

Fiscal Year(1)

2000
2001
2002
2003
2004

Royalties (net ARTC)
($/Boe)

Trend

($ 000s)

Operating Costs

Operating Cash Netback(2)

($ 000s)

($/Boe)

Trend

($ 000s) ($/Boe)

Trend % of Revenue

80,541
99,706
74,444
82,512
105,046

5.75
6.89
4.44
6.93
7.94

100
124
92
102
130

47,974
61,045
86,067
81,193
95,767

3.43
4.22
5.14
6.82
7.24

100
127
179
169
200

262,955
18.79
351,814 24.29
266,618
15.92
269,334 22.60
349,769 26.44

100
129
85
120
141

67.2
66.9
61.9
70.7
61.4

(1) Trend with base year 2000, with nominal value of 100.
(2) Operating cash netback = oil & gas and other revenue – royalty – operating cost.

R E V E N U E / E X P E N S E S / C A S H F L O W N E T B A C K / N E T E A R N I N G S

The table calculates revenue, expenses and net earnings converted into dollars per thousand cubic feet gas equivalent (1 barrel = 6 Mcf).

($/Boe)

Annual production (MBoe)
Gross revenue before financial instruments, net of transportation
Gain (loss) on sale of investments
Royalties
Operating costs
Operating netback
Realized financial instruments gain (loss)
General and administrative
Bad debt recovery (expense)
Cash interest
Lease rentals
Current income tax
Large corporation tax and other
Other
Cash flow netback
Unrealized financial instrument gain (loss)
Stock based compensation expense
Non-cash interest
Depletion and depreciation
Accretion of asset retirement obligations
Surmont compensation
Gain (loss) on sale of properties
Dry hole costs
Write-down of petroleum and natural gas properties
Geological and geophysical
Unrealized foreign exchange gain on US debt
Realized foreign exchange gain on US debt
Premium on redemption of US debt
Other
Future income taxes recovery (expense)
Net earnings
Net earnings trend (1)

(1) Trend with base year 2000, with nominal value of 100.

H I S T O R I C A L S U M M A R Y

Gas production (MMcf/d)
Crude oil and liquids production (Bbl/d)

Gas proved reserves (Bcf)
Crude oil and liquids proved reserves (MBbl)
Total proved and probable reserves (MMBoe) 6:1

Cash flow ($ millions)
Cash flow per share (basic)
Net earnings ($ millions)
Net earnings per share (basic)

2004

13,231
41.61
–
(7.94)
(7.24)
26.43
(0.05)
(1.91)
0.42
(1.82)
(0.27)
–
(0.51)
0.05
22.34
1.46
(3.11)
(0.10)
(14.48)
(0.52)
–
1.23
(1.87)
–
(0.66)
1.83
0.54
(0.90)
0.42
(3.07)
3.11
50

2004

173.1
7,297

568.6
20,461
115.2

295.6
4.95
41.2
0.69

$
$
$
$

2003

2002

2001

2000

11,910
$ 36.45
(0.09)
(6.93)
(6.82)
22.61
(4.47)
(1.60)
(0.50)
(1.60)
(0.30)
–
(0.23)
0.13
14.04
–
(0.10)
(0.01)
(13.86)
(0.34)
–
(0.31)
(3.07)
(0.87)
(0.71)
0.13
–
–
(0.13)
5.33
0.10
2

2003

152.8
7,169

241.7
10,617
67.4

$ 167.3
$ 2.78
1.1
$
$ 0.02

16,753
$ 23.06
2.44
(4.44)
(5.14)
15.92
2.79
(0.95)
–
(1.43)
(0.27)
–
(0.55)
–
15.51
–
(0.02)
–
(10.11)
(0.21)
2.23
–
(7.17)
(1.87)
(0.56)
–
–
–
–
2.80
0.60
10

14,478
$ 35.20
0.20
(6.89)
(4.22)
24.29
1.09
(0.85)
–
(1.33)
(0.30)
(1.73)
(0.19)
–
20.98
–
–
–
(7.28)
(0.17)
–
(0.11)
(0.62)
–
(0.74)
–
–
–
–
(3.87)
8.19
133

2002

241.4
5,663

446.5
17,545
125.9

2001

225.0
2,165

437.7
6,339
101.9

$ 259.9
4.37
$
10.3
$
0.17
$

$ 303.9
5.11
$
118.9
$
2.00
$

13,995
$ 27.97
–
(5.75)
(3.43)
18.79
–
(0.69)
–
(1.59)
(0.37)
–
(0.16)
–
15.98
–
–
–
(3.61)
(0.12)
–
0.05
(0.50)
–
(0.48)
–
–
–
–
(5.14)
$ 6.18
100

2000

220.0
1,571

518.1
4,709
115.5

$ 223.4
$
3.76
$ 86.1
1.45
$

5 PARAMOUNT RESOURCES LTD. 20 04 A N N UAL R EP ORT

ANALYST SUPPLEMENT

C O M P A N Y F O R E C A S T 2 0 0 5

D I R E C T O R S A N D O F F I C E R S

Production / Pricing

Gas
(MMcf/d) ($/Mcf)
Oil/liquids (Bbl/d) ($/Bbl)
Cash flow ($MM)
Cash flow per share
Capital budget ($MM)

210 @ $ 6.50
10,000 @ US$ 42.00
425
6.66
340

C O M M O N S H A R E D ATA

Shares of Paramount Resources Ltd. trade on The Toronto Stock Exchange
under the symbol “POU” (Oil and Gas Producers Sub Index) and is part of the
S&P/TSX Composite Index.

At December 31

2004

2003

Outstanding shares (000s)
Public float(1)

– shares (000s)
– % of total shares

Trading volume (000s)
Trading value (000s)
Trading range

High
Low
Close

Weighted average trading price
Market capitalization at year end ($ millions)

63,186
29,697
47%
38,489
$ 719,743

$
$
$
$

27.90
10.41
26.90
18.70
1,700

60,095
27,818
46%
34,335
$ 431,533

$
$
$
$
$

16.95
8.51
10.45
12.57
628.0

(1) Public float is all outstanding shares less shares owned/controlled by officers/directors.

C.H. (Clay) Riddell (3)
Director, Chairman
and Chief Executive Officer

B.K. (Bernard) Lee
Chief Financial Officer

J.H.T. (Jim) Riddell
Director, President
and Chief Operating Officer

C.E. (Chuck) Morin
Corporate Secretary

L.M. (Lloyd) Doyle
Corporate Operating Officer

C.G. (Cal) Folden
Corporate Operating Officer

J.S. (Scott) McDougall
Corporate Operating Officer

G.W.P. (Geoff) MacMillan
Corporate Operating Officer

J.B. (John) Williams
Corporate Operating Officer

L.A. (Laurel) Friesen
Assistant Corporate Secretary

J.C. (John) Gorman (1 (4)
Director

D. (Dirk) Jungé, C.F.A. (4)
Director

D.M. (David) Knott
Director

W.B. (Wally) MacInnes, Q.C. (1) (2) (3) (4)
Director

V.S.A. (Vi) Riddell
Director

S.L. (Sue) Riddell Rose
Director

J.B. (John) Roy(1) (2) (3) (4)
Director

A.S. (Alistair) Thomson (1) (4)
Director

B.M. (Bernie) Wylie(2)
Director

(1) Member of Audit Committee.
(2) Member of Environmental, Health and Safety Committee.
(3) Member of Compensation Committee.
(4) Member of Corporate Governance Committee.

F I V E - Y E A R S H A R E P R I C E A N D T R A D I N G V O L U M E

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6 PARA MOUNT RESOURCES LTD. 20 0 4 A NNUA L R EP ORT

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Trilogy Energy Trust (1) (TET.UN): is a Canadian energy trust formed through the
spinout of a portion of Paramount Resources assets in the Kaybob and Marten Creek
areas of central Alberta. These assets are primarily low-risk, high working interest,
lower-decline properties that are geographically concentrated with many inﬁll drilling
opportunities, good access to infrastructure and processing facilities that are operated
and controlled by the Trust. By operating the wells and production infrastructure, we can
control two variables that aﬀect the cash ﬂow and revenues of the Trust.

The Trust will employ a strategy to provide Unitholders
with: a competitive annual yield by making monthly
cash distributions to Unitholders, maintain the Trilogy
assets at a level that provides stable production, and
continue to expand the business of the Trust through the
development of growth opportunities that will provide
long-term stable cash ﬂows.

The technical expertise that has been employed at
Paramount will continue to develop and exploit the
land and reserves in Kaybob and Marten Creek. The
ﬁeld operation has been growing and developing
the operational expertise to operate eﬀectively and
eﬃciently in the Kaybob area and will continue to be an
intregal part of the exploitation and production of the
assets. The Trust’s inﬁll drilling opportunities and large
undeveloped land base are expected to make it less reliant
on the acquisition market to maintain distributions. The
management of Trilogy Energy Ltd., the Administrator
of the Trust, will consider strategic asset acquisitions
that would be accretive to the production, reserves and
cash ﬂow of the Trust and provide undeveloped potential
that can be exploited to increase the value of the Trust.

(1) References to the Trust in this summary include, where the context requires, the trusts, corporations and partnerships directly or indirectly owned by the Trust.

Marten
Creek

East
Kaybob

TR IL OG Y ENER GY TRUST 1

Letter to Unitholders

Paramount’s management continually reviews all options available to it to ensure that Paramount’s capital structure is eﬃcient
and that shareholder value is being enhanced. In this regard, in 2004, certain senior management of Paramount conducted
a preliminary review of possible restructuring alternatives available to Paramount to increase shareholder value. The Board
of Directors, after considering the alternatives presented to it and after receiving advice from its legal and ﬁnancial advisors,
approved a reorganization of a portion of Paramount’s assets into an energy trust (the “Trust Spinout”).

The Beneﬁts of Forming the Trust

Paramount believes 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 the Trust,
which will pay regular cash distributions; and (ii) the predominantly growth oriented assets which 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 mature 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. This new structure should provide greater
aggregate access to capital to fund the growth of the businesses of each of Paramount and the Trust; and a more active and liquid
market for the new Common Shares and the Trust Units.

The Process of Restructuring

In order to implement any proposed reorganization of Paramount, Paramount required the consent of the majority of the holders
of each of its 7 7/8% Notes due 2010 and its 8 7/8% Notes due 2014. On February 7, 2005, Paramount obtained consent from
the note holders and completed, as amended, the Notes Oﬀer issuing U.S.$213,593,000 principal amount of 8 1/2% Notes due
2013 and paying aggregate cash consideration of approximately U.S.$36.2 million in exchange for approximately 99.31% of the
outstanding 2010 Notes and 100% of the outstanding 2014 Notes. This cleared the way to continue with the Trust Spinout.

The Plan

The Trust Spinout resulted in the shareholders receiving one new Paramount Resources Ltd. Common Share and one Unit
of the Trust in exchange for each Paramount Resources Ltd. Common Share held. Upon completion of the Trust Spinout,
Paramount shareholders owned 100 percent of post-reorganization Paramount and 81 percent of the outstanding units of
Trilogy. Paramount owned the remaining 19 percent of the outstanding units of the Trust. Through Trilogy, the unitholders will
receive regular monthly cash distributions from the cash ﬂow produced by the Trust’s developed assets. Through Paramount,
shareholders will participate in the potential upside of Paramount’s remaining predominately growth-oriented assets.

2 TRILOGY ENERGY TRU ST

The following diagram illustrates the organizational structure of Paramount Resources Ltd. and Trilogy Energy Trust:

Shareholders

Unitholders

����

Paramount
Resources Ltd.

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�������������������������

Trilogy Energy Ltd.
(General Partner)

���

Trilogy
Energy
Trust

����

Trilogy
Holding
Trust

��������
���������

�����

������

Paramount Resources
(General Partnership)

Trilogy Energy LP
(Limited Partnership)

Assets

Spinout Assets

������
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�����������������������������������������������������������������������������������������������������������������������������
� ������������������������������������������

TR IL OG Y ENER GY TRUST 3

The Assets

The East Kaybob and Marten Creek properties held by Trilogy Energy Trust are geographically concentrated in central Alberta.
These are developed, high working interest, lower decline properties with many inﬁll drilling opportunities and good access
to owned infrastructure and processing facilities. The Trilogy assets are currently producing approximately 25,000 Boe/d,
comprised of approximately 120 MMcf/d of natural gas and 5,000 Bbl/d of crude oil and natural gas liquids. A report of
Paddock Lindstrom & Associates Ltd., independent petroleum engineers, dated eﬀective December 31, 2004 assigned
44,722 MBoe of Proved Reserves and 64,254 MBoe of Proved plus Probable Reserves to these properties.

The East Kaybob properties represent approximately 89 percent of the production and 93 percent of the Proved plus Probable
Reserves of the Trust Spinout assets as at December 31, 2004. The production at the end of March 2005 averaged approximately
22,200 Boe/d (approximately 103 MMcf/d of natural gas and 5,000 Bbl/d of crude oil and natural gas liquids). The natural
gas produced from the East Kaybob area is typically liquid-rich with a high heat content which translates into a premium
price relative to AECO gas. The Paddock Lindstrom report has assigned 41,714 MBoe of Proved Reserves and 60,008 MBoe
of Proved plus Probable Reserves to this area. The assets in East Kaybob also include, as at December 31, 2004, 356,927
(333,203 net) developed acres and 373,362 (206,558 net) undeveloped acres of land.

This area is known for its multi-zone potential. The wells in this area produce from the Viking, Spirit River, Bluesky, Gething,
Nordegg, Montney and Swan Hills formations which have well depths between 1,500 to 3,500 metres. Approximately
58 percent of the natural gas production from these properties will be processed at three Trilogy-operated natural gas plants
with an average 75 percent working interest. Approximately 64 percent of the oil and natural gas liquids production in this area
is treated at Trilogy-operated oil batteries with an average working interest of 65 percent.

The Marten Creek property represents approximately 11 percent of the production and 7 percent of the Proved plus Probable
Reserves attributable to the Trust Spinout assets as at December 31, 2004. The production at the end of March 2005 averaged
approximately 17 MMcf/d of natural gas or approximately 2,800 Boe/d. The Paddock Lindstrom report has assigned
3,008 MBoe of Proved Reserves and 4,246 MBoe of Proved plus Probable Reserves to this area. As at December 31, 2004
Marten Creek had 26,880 (26,880 net) developed acres and 117,120 (115,200 net) undeveloped acres of land. The wells in this
area produce primarily from the Viking, Clearwater and Wabiskaw formations which have well depths of between 300-500
metres. The main gathering system and processing plant in Marten Creek is operated by a midstream processing company.

4 TRILOGY ENERGY TRU ST

Simonette A&B
�����������

Karr
���������

Fox Creek
�����������

Kaybob North
BHL #1
�����������

Marten Creek
�����������

Kaybob North
�����������

Kaybob South
BHL Unit #1
���������

Kaybob South
BHL Unit #2
���������

Kaybob South
BHL Unit #3
���������

Two Creek
�����������

Clover
�����������

Pine Creek
�����������

Edson
���������

Other
�����������

TR IL OG Y ENER GY TRUST 5

The People

Dedicated Paramount staﬀ involved in the development and implementation of the technical fundamentals responsible for
the successful exploitation of the Trust assets will continue their employment with Trilogy, employed by Trilogy Energy LP.
The management will consider strategic asset acquisitions that would be accretive to the production, reserves and per unit cash
ﬂow of the Trust and provide undeveloped potential that can be exploited to add additional value.

The ﬁeld operation has been growing and developing the operational expertise to operate eﬀectively and eﬃciently in the
Kaybob area and will continue to be a part of the exploitation and production of the assets. The Trust will ensure that the ﬁeld
employees are trained, qualiﬁed and suﬃciently experienced to perform the assigned task in a competent manner.

It is the tenet of the Trust to create a corporate culture that attracts and rewards employees who are passionate, innovative and
inspired to add to the value of the Trust. The Trust culture will support continuous improvement, resulting in better performance
and more free cash ﬂow for distributions.

The Outlook

The success of Trilogy Energy Trust will be contingent on the implementation of a strategy that will result in a stable production
proﬁle, provide steady cash ﬂow and ultimately, stable distributions for unitholders. We are excited to go forward with a capital
program to replace reserves and production. The assets will provide a growth platform for successful ongoing development of
this tight gas resource play. We are conﬁdent in the vast array of currently identiﬁed development opportunities. There exists a
large, as yet, undeveloped resource in the central Alberta area that will fuel future growth and add tremendous value for Trilogy
Unitholders and Paramount Shareholders.

The ﬁrst monthly distribution of the Trust is targeted to occur on May 15, 2005 to unitholders of record on May 2, 2005.
Successful production replacement, prudent asset management, strong commodity prices and continued eﬃcient control of
operations will support a stable distribution. We are conﬁdent in our management, our high quality assets and our proven
expertise. We believe the Trust will be a rewarding investment for our unitholders.

signed

Jim Riddell
President & Chief Executive Oﬃcer

6 TRILOGY ENERGY TRU ST

Ofﬁcers and Directors of Trilogy Energy Ltd.,
the Administrator of the Trust

OFFICERS

DIRECTORS

J. H. T. Riddell
President and Chief Executive Oﬃcer

B. K. Lee
Chief Financial Oﬃcer

J. B. Williams
Chief Operating Oﬃcer

C. E. Morin
Corporate Secretary

C. H. Riddell
Non Executive Chairman of the Board
Calgary, Alberta

J. H. T. Riddell
President and Chief Executive Oﬃcer
Calgary, Alberta

R.M. MacDonald
Independent Businessman
Calgary, Alberta

D.F. Textor
Retired
Locust Valley, New York

E.M.Shier
Partner Heenan Blaikie LLP
Calgary, Alberta

TR IL OG Y ENER GY TRUST 7

4100, 350 Seventh Avenue, S.W.
Calgary, Alberta
Canada T2P 3N9
Telephone: (403) 290-2900
Facsimile: (403) 263-8915

The Toronto Stock Exchange Listing:
“TET.UN”

ABBREVIATIONS

barrels
barrels per day
billion cubic feet
billion cubic feet of gas equivalent
barrels of oil equivalent
gigajoules
gigajoules per day
thousand cubic feet
thousand cubic feet of gas equivalent
thousand cubic feet per day
million cubic feet

Bbl
Bbl/d
Bcf
Bcfe
Boe
GJ
GJ/d
Mcf
Mcfe
Mcf/d
MMcf
MMcf/d million cubic feet per day
MBbl
thousands of barrels
MMbtu millions of British Thermal Units
MBoe
MMcfe/d million cubic feet of gas equivalent per day

thousands of barrels of oil equivalent

4700 Bankers Hall West
888 Third Street S. W.
Calgary, Alberta
Canada T2P 5C5
Telephone: (403) 290-3600
Facsimile: (403) 262-7994
www.paramountres.com