Exhibit 1

PARAMOUNT RESOURCES LTD.
Calgary, Alberta
August 4, 2004

NEWS RELEASE: PARAMOUNT RESOURCES LTD.
Financial and Operating Results
for the Second Quarter Ended June 30, 2004

CALGARY, ALBERTA — Paramount Resources Ltd. (“Paramount” or the “Company”) is pleased to announce its financial and operating results for the quarter ended June 30, 2004.

Financial Highlights
($ thousands except per share amounts and where stated otherwise)

	Three Months Ended June 30								Six Months Ended June 30
	2004			2003			% Change		2004			2003			% Change
FINANCIAL
Petroleum and natural gas sales		125,616			101,512			24%		231,120			251,217			-8%
Cash flow (1)
From operations		69,515			36,697			89%		128,592			94,877			36%
Per share – basic		1.19			0.61			94%		2.18			1.58			38%
– diluted		1.17			0.61			92%		2.15			1.57			37%
Earnings
Net earnings (loss)		9,936			(1,888	)		626%		13,115			(1,574	)		933%
Per share – basic and diluted		0.17			(0.03	)		667%		0.22			(0.03	)		833%
Capital expenditures
Exploration and development		45,916			50,586			-9%		156,331			103,068			52%
Acquisitions, dispositions and other		183,182			(38,434	)		577%		180,243			(260,991	)		169%
Net capital expenditures		229,098			12,152			1785%		336,574			(157,923	)		313%
Total assets (3)										1,469,943			1,177,130			25%
Net debt (2) (3)										560,866			303,110			85%
Shareholders’ equity (3)										490,942			496,033			-1%
Common shares outstanding (thousands)
– June 30										58,465			60,095			-3%
– July 31										58,481
OPERATING
Production
Natural gas (MMcf/d)		157			142			11%		149			167			-11%
Crude oil and liquids (Bbl/d)		6,134			7,465			-18%		5,905			7,677			-23%
Total production (Boe/d) @ 6:1		32,354			31,129			4%		30,766			35,584			-14%
Average prices
Natural gas (pre-hedge) ($/Mcf)		7.01			5.91			19%		6.78			6.45			5%
Natural gas ($/Mcf) (4)		6.70			4.84			38%		6.82			5.13			33%
Crude oil and liquids (pre-hedge) ($/Bbl)		45.37			36.94			23%		43.69			40.03			9%
Crude oil and liquids ($/Bbl) (4)		42.62			35.27			21%		39.89			37.15			7%
Drilling activity (gross)
Gas		24			29			-17%		102			96			6%
Oil		—			5			-100%		5			10			-50%
Oilsands evaluation (5)		—			—			—		17			—			—
D&A		—			3			-100%		6			8			-25%
Total wells		24			37			-35%		130			114			14%
Success rate (5)		100	%		92%			9%		95	%		93%			2%

(1)	Cash flow from operations is a non-GAAP term that represents net earnings adjusted for non-cash items, dry hole costs and geological and geophysical costs. The Company considers cash flow from operations a key measure as it demonstrates the Company’s ability to generate the cash necessary to fund future growth through capital investment and to repay debt.
(2)	Net debt is equal to long-term debt including working capital excluding the current liabilities of discontinued operations.
(3)	Comparative figures are as at December 31, 2003.
(4)	Excludes non-cash gains and losses on financial instruments.
(5)	Success rate excludes oilsands evaluation wells.

Review of Operations

The 2004 second quarter daily production for Paramount Resources Ltd. (“Paramount” or the “Company”) averaged 157 MMcf/d of natural gas and 6,134 Bbl/d of oil and natural gas liquids. Total production for the quarter was 32,354 Boe/d, an 11 percent increase compared to 29,178 Boe/d in first quarter of 2004. Drilling was less active in the second quarter as a result of spring break up with a total of 24 wells (17 net) drilled, resulting in 24 gross gas wells (17 net) for a 100 percent success rate.

Kaybob
Natural gas production volumes were up 6 MMcf/d, an eight percent increase from the first quarter, averaging 90 MMcf/d in the second quarter. The higher production volumes were the result of improved on-stream performance in the second quarter compared to the operational difficulties caused by the cold weather during the first three months of the year. Oil and natural gas liquids volumes averaged 2,543 Bbl/d in the second quarter versus 2,454 Bbl/d in the first quarter as the result of higher natural gas production.

Second quarter 2004 capital expenditures were approximately $10 million, bringing year-to-date capital spending to $40 million for the Kaybob Operating Unit. Third and fourth quarter capital expenditures are expected to be around $60 million, reflecting the increase in drilling, completion and construction activities.

Field activities in Kaybob resumed in late May after being shut down for most of the quarter due to the early spring break up. Paramount participated in the drilling of 8 (5.0 net) wells in the quarter; all were cased for gas potential. These wells will be completed in the third quarter and are forecast to be on production prior to the end of the year. Construction was also completed on the pipelines to tie in 4 MMcf/d of natural gas that was stranded at the end of the first quarter; an additional 4 MMcf/d will also be on-stream in the third quarter.

With the closing of the Kaybob asset acquisition on June 30, production in Kaybob is forecast to be significantly higher for the remainder of the year. The acquisition will add approximately 20 MMcf/d and 3,300 Bbl/d of oil and natural gas liquids or approximately 6,600 Boe/d to the Kaybob Operating Unit. Third and fourth quarter production volumes including the newly acquired assets are expected to be in the 25,000 Boe/d range. Field operations associated with the acquired assets are currently being integrated into the existing Paramount operations.

Exploitation, development and exploration operations in the Kaybob area will increase in the third and fourth quarters. Paramount currently has two drilling rigs and three service rigs active in Kaybob and anticipates this to increase to four drilling rigs and four service rigs by the end of the year. Operations will continue to be focused on down-spacing opportunities and optimization of existing well bores and infrastructure. The acquisition will provide additional opportunities that will be funded from the existing 2004 Kaybob capital budget of approximately $100 million.

Grande Prairie
Production averaged 21 MMcf/d and 579 Bbl/d for a total of 4,093 Boe/d, a one percent increase from the first quarter production of 4,058 Boe/d. Four wells were turned on in the second quarter resulting in an additional 3 MMcf/d (initial rate) of production. The third-party facility limitations at Berry Lake will be mitigated by an expansion to be completed in the third quarter. This should further increase production by

about 3 MMcf/d. At Mirage, the third-party pipeline will be looped in the third quarter to remove the current bottleneck which will allow further production increases.

To avoid higher drilling costs associated with wet weather, most activities in the Grande Prairie area were deferred to late in the second quarter and early in the third quarter. The major accomplishments for the second quarter were the drilling of 5 (4.4 net) wells, completing 2 (2.0 net) wells, the tie in of 3 (3.0 net) wells and the installation of a compressor.

Paramount is currently drilling a 3,800 metre exploratory well in Valhalla. Some new gas discoveries have been made in the Mirage area. The Company is continuing to develop the shallow gas resource play with 20 wells planned at Mirage. This drilling program is to follow up primarily on the success in the shallow Dunvegan gas play but is also targeting deeper zones. Completions of the second quarter new drills are ongoing and early indications are that they have been successful.

Land acquisitions through Crown land sales and farm-ins have significantly added to Paramount’s position on key play types in the Saddle Hills and Mirage areas. The acquisition at Kaybob also included some assets in the Elmworth area and has also added non-operated production and undeveloped land position in this classic deep basin area.

Northwest Alberta
Northwest Alberta’s second quarter production averaged 23 MMcf/d of natural gas and 967 Bbl/d of liquids, for a total of 4,731 Boe/d, a 52 percent increase over first quarter production of 3,114 Boe/d which was hampered by the extended turnaround. The expanded Haro facility came on-stream during the first week of June. This expansion has allowed the Company to increase its production from 1.8 MMcf/d to 5 MMcf/d. Efforts are ongoing to match production throughput to the facility ownership capacity of 6 MMcf/d.

Capital expenditures to the end of the second quarter amounted to $29 million. No drilling or completion activities were undertaken in Northwest Alberta and Cameron Hills in the second quarter due to winter-only access in the area. Evaluations of 2D and 3D seismic acquired during the winter in Bistcho and Cameron Hills are ongoing in an effort to firm up drilling locations for the coming winter season targeting middle Devonian opportunities. Follow-up drilling locations in Haro are also being developed targeting Mississippian subcrop objectives.

Northwest Territories/Northeast British Columbia
Production from the four producing properties in this area remained steady at 10 MMcf/d for the second quarter of 2004. Paramount acquired the operator’s interest in the Nahanni pool at Fort Liard and has assumed the operatorship of this facility. The acquisition adds 20 MMcf/d of natural gas production commencing the second half of 2004. The acquisition also added undeveloped land totaling 61,173 net hectares in the Patry/Maxhamish area. Over 1,700 kilometers of seismic data covering portions of northeast British Columbia and the Northwest Territories were included and will be used to delineate additional exploration prospects in the Liard basin area.

During the second quarter, the 2M-25 location at Fort Liard was drilled and cased with completion and testing operations currently underway. It is anticipated that 2M-25 will be tied in and on production in the third quarter. Additional workover activities at M-25 and 2K-29 will also be completed later this year.

At Colville Lake, two parcels of land were purchased in June. Paramount acquired a 50 percent working interest in Exploration License 426 which offsets the Nogha discovery and covers 36,728 hectares. Further to the south, Paramount acquired a 100 percent interest in Exploration License 424 which is adjacent to EL 414 and covers 80,608 hectares.

Southern
Production in the second quarter of 2004 from the Southern Operating Unit averaged 11 MMcf/d and 2,065 Bbl/d or 3,845 Boe/d. This is a seven percent increase over the first quarter production of 3,579 Boe/d. Production increases in the quarter can be attributed to new production which was tied in at Chain, de-bottlenecking operations in Chain and Retlaw, and successful recompletions in Sylvan Lake and Beaver Creek, North Dakota.

Paramount participated in 10 (7.1 net) exploration wells, seven of which were 100 percent operations, four in Saskatchewan, two in Chain, and one at Enchant. All wells were cased for evaluation. The Company also participated in 5 (4.3 net) completion wells, three in Chain/Craigmyle, one in Sylvan Lake, and one in Beaver Creek, North Dakota.

The Horseshoe Canyon coal gas play has continued to gather steam throughout south central Alberta with a multitude of companies announcing projects and new production coming on daily. We are well placed in Chain to take advantage of this play with our land base and infrastructure.

Northeast Alberta
Paramount has submitted an AEUB application for a Gas Re-Injection & Production Experiment at Surmont in order to initiate production from natural gas pools which are in potential communication to the commercial bitumen resources. This experiment involves the collection and re-injection of up to 4 MMcf/d of compressor exhaust gases to maintain reservoir pressure while producing a similar volume of natural gas. The pilot is expected to start-up in the second quarter of 2005. This experiment could also offer the opportunity to sequester other green house gases such as carbon dioxide.

Acquisitions and Divestitures
On June 30, 2004, Paramount closed the acquisition of oil and natural gas assets in the Kaybob area in central Alberta and in the Fort Liard area in the Northwest Territories and northeast British Columbia for $189 million, before customary adjustments. The properties are 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. The proved reserves attributable to the properties as of the effective date, June 1, 2004, are estimated to be approximately 47.2 Bcf of natural gas and 4.4 million Bbl of oil and natural gas liquids, or a total of 12.3 million Boe; and proved plus probable reserves of approximately 93.6 Bcf of natural gas and 6.7 million Bbl of oil and natural gas liquids, or a total of 22.2 million Boe.

Subsequent to the end of the second quarter, Paramount entered into an agreement to acquire assets in our Marten Creek producing area in Grande Prairie for $83.7 million, subject to adjustments. The assets to be acquired are currently 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, and proved plus probable reserves of approximately 22.2 Bcf or 3.7 million Boe. Closing is expected to occur in mid August.

Paramount has also entered into agreements to divest approximately 1,000 Boe/d of non-core oil and gas assets for $42.2 million. In addition, the Company is also divesting its investment in Wilson Drilling Ltd.,

a private drilling company in which Paramount owns a 50 percent equity interest for $32 million, $16 million net to Paramount. Since the second quarter of this year, the Company has liquidated all or part of its investments in Harvest Energy Trust, Altius Energy Corporation and Spearhead Resources Inc., receiving a total of approximately $13 million. The Company is also investigating the possibility of disposing of its commercial real estate.

The proceeds from the disposition of these non-core assets are expected to total in excess of $80 million which funds the acquisition of the strategic oil and gas assets in Marten Creek. The result of all of these transactions is a net increase of approximately 1,300 Boe/d in production.

Financing
On June 29, 2004, Paramount issued US $125 million of 8 7/8 percent Senior Notes due 2014 and used the proceeds from the offering to finance the Company’s acquisition of oil and natural gas assets in the Kaybob and Fort Liard areas. On July 20, 2004, Paramount’s borrowing capacity under its credit facility was increased to $250 million. The combined debt financing available is now approximately $650 million.

Financial
Petroleum and natural gas sales before hedging totaled $125.6 million for the three months ended June 30, 2004 as compared to $101.5 million for the comparable period in 2003. The increase is due to higher production as a result of the Company’s successful exploration and development activities as well as higher natural gas prices as compared to the second quarter of 2003.

Cash flow from operations for the three months ended June 30, 2004 totaled $69.5 million or $1.17 per diluted common share as compared to $36.7 million or $0.61 per diluted common share for the second quarter of 2003. The 89 percent increase resulted primarily from higher petroleum and natural gas revenues due to increased production and higher commodity prices.

Paramount recorded net earnings for the current quarter of $9.9 million or $0.17 per diluted common share as compared to a net loss of $1.9 million or $0.03 per diluted common share for the comparable period in 2003. The increase in earnings is primarily the result of higher petroleum and natural gas revenues due to increased production and higher commodity prices as well as decreased financial instrument losses.

Capital expenditures in the second quarter of 2004 were $45.9 million comprised of $18.7 million for drilling and completions, $15.6 million for facilities expenditures, $9.8 million for land and $1.8 million for geological and geophysical expenditures. Net debt at the end of the second quarter was $560.9 million and will continue to be reduced through the remainder of the year as Paramount expects cash flow for operations will exceed capital expenditures.

Outlook
Paramount now forecasts its production to average 180 MMcf/d of natural gas and 7,500 Bbl/d of oil and natural gas liquids, or a total of 37,500 Boe/d for all of 2004. Current production, including the acquisition, is approximately 200 MMcf/d and over 9,000 Bbl/d, or in excess of a total of 42,500 Boe/d. Paramount forecasts cash flow in 2004 to be about $300 million or approximately $5.00/share and net capital expenditures to total $460 million. Net debt levels at year end giving effect to the acquisition are projected to be around $480 million which would equate to a debt to cash flow ratio of approximately 1.6 times.

A conference call will be held with the senior management of Paramount Resources Ltd. to answer questions with respect to the second quarter results on Thursday, August 5, 2004 at 9:00 a.m. MST. To participate please call 1-877-211-7911 or 1-416-405-9310 approximately 15 minutes before the call is to begin.

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

A replay of the conference call will be available from an hour after the call until August 12, 2004. The number for the replay is 1-800-408-3053 or 1-416-695-5800 with passcode number 3085676.

The conference call will be available for replay on the Company website, www.paramountres.com within two hours of the webcast. Paramount is a Canadian oil and natural gas exploration, development and production company with operations focused in Western Canada. Paramount’s common shares are listed on the Toronto Stock Exchange under the symbol “POU”.

For further information, please contact:
          C. H. (Clay) Riddell, Chairman and Chief Executive Officer
          J. H. T. (Jim) Riddell, President and Chief Operating Officer
          B. K. (Bernie) Lee, Chief Financial Officer

Phone:     (403) 290-3600
Fax:          (403) 262-7994

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 six months ended June 30, 2004.

The following discussion of financial position and results of operations should be read in conjunction with the interim unaudited consolidated financial statements and related notes for the three and six months ended June 30, 2004, as well as the audited consolidated financial statements and related notes and MD&A for the year ended December 31, 2003.

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, reserve estimates, production estimates, hedging policies, asset retirement costs, the size of available income tax pools, 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 dismantlement and asset retirement, 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.

The date of this MD&A is July 30, 2004.

Additional information on the Company can be found on the SEDAR website at www.sedar.com.

Paramount is an exploration, development and production company with established operations in Alberta, British Columbia, Saskatchewan, the Northwest Territories, Montana, North Dakota and California. 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

$189 MILLION ASSET ACQUISITION

On June 30, 2004, Paramount completed the acquisition of assets in the Kaybob area of central Alberta and the Fort Liard area of the Northwest Territories for $185.1 million, after adjustments. The properties to be acquired are currently 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 (“NGL”). The reserves attributable to the properties as of June 1, 2004 are estimated by Paramount to consist of proved reserves of approximately 47.2 Bcf of natural gas and 4.4 million Bbl of oil and NGL, or a total of 12.3 million Boe, and proved plus probable reserves of approximately 93.6 Bcf of natural gas and 6.7 million Bbl of oil and NGL, or a total of 22.2 million Boe.

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

On June 29, 2004, the Company issued US $125 million 8 7/8 percent Senior Notes due 2014. Proceeds from the Senior Notes issuance were used to finance the $189 million asset acquisition. Interest on the note 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.

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 Wilson’s drilling assets for $32 million to a publicly traded Income Trust. The 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 will be extinguished. For reporting purposes, $6.2 million of capital assets, $4.4 million of current and long-term debt, and a $0.1 million loss have been classified as discontinued operations as at, and for the six months ended, June 30, 2004.

REVENUE AND PRODUCTION

	Three months ended June 30						Six months ended June 30
Revenue (thousands of dollars)	2004			2003			2004			2003
Natural gas	$	100,288		$	76,418		$	184,167		$	195,596
Oil and natural gas liquids		25,328			25,094			46,953			55,621
Petroleum and natural gas revenue		125,616			101,512			231,120			251,217
(Loss) on financial instruments		(6,297	)		(15,218	)		(12,759	)		(44,322	)
(Loss) on sale of short-term investments		(34	)		(1,020	)		(34	)		(1,020	)
Other		(283	)		(478	)		199			225
Gross revenue	$	119,002		$	84,796		$	218,526		$	206,100

Natural gas revenue for the six months ended June 30, 2004 decreased six percent to $184.2 million as compared to $195.6 million for the comparable period in 2003. The decrease in natural gas revenue results primarily from lower production levels partially offset by higher natural gas prices received during the period. Natural gas production volumes for the six month period ended June 30, 2003 decreased 11 percent to 149 MMcf/d as compared to 167 MMcf/d for the comparable period in the prior year, primarily as a result of the disposition of natural gas assets in Northeast Alberta (the “Trust assets”) to Paramount Energy Trust (the “Trust”) in the first quarter of 2003, as well as other property dispositions during 2003. This decrease was partially offset by new production in the Kaybob area.

Paramount’s average year-to-date natural gas sales price before hedging increased five percent to $6.78/Mcf as compared to $6.45/Mcf for the comparable period in 2003.

Natural gas revenue for the three months ended June 30, 2004 increased 31 percent to $100.3 million as compared to $76.4 million for the same period in 2003. The increase in natural gas revenue resulted primarily from an increase in production levels combined with higher natural gas prices.

Total natural gas production volumes for the three months ended June 30, 2004 increased 11 percent to average 157 MMcf/d as compared to 141 MMcf/d in the first quarter of 2004. The increase in natural gas volumes were primarily the result of new natural gas production from the Kaybob area combined with Northwest Alberta returning to normal production levels, as the first quarter production was affected by a scheduled, maintenance-related facility shut-down.

Oil and NGL revenue during the six months ended June 30, 2004, decreased 15 percent to $47.0 million as compared to $55.6 million for the comparable period in 2003, primarily due to lower production levels partially offset by higher commodity prices received during the period. Oil and NGL sales volumes decreased 23 percent to average 5,905 Bbl/d for the six months ended June 30, 2004 as compared to 7,677 Bbl/d for the comparable six months in 2003, primarily as a result of the sale of Sturgeon Lake and other minor oil properties in 2003, partially offset by new oil production at Cameron Hills. Paramount’s average year to date oil and NGL sales price before hedging was $43.69/Bbl for the period as compared to $40.03/Bbl in the comparable period in 2003.

Oil and NGL revenue for the three months ended June 30, 2004 increased one percent to $25.3 million as compared to $25.1 million for the same period in 2003. The increase in oil and NGL revenue resulted primarily from the higher oil and NGL prices received during the period offset by lower production volumes. Current quarter production was 6,134 Bbl/d compared to 7,465 Bbl/d in the comparable period in 2003. Second quarter oil and NGL production increased eight percent as compared to 5,675 Bbl/d of production for the first quarter of 2004. The increase is the result of Northwest Alberta returning to normal production levels.

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 forward commodity price contracts. This risk management program is generally for periods of less than one year and would not exceed 50 percent of Paramount’s average annual production volumes.

At June 30, 2004, Paramount had the following forward commodity price contracts in place:

AECO	Price	Term
10,000 GJ/d	$5.51	April 2004 - October 2004
10,000 GJ/d	$5.55	April 2004 - October 2004
20,000 GJ/d	$5.80	April 2004 - October 2004
10,000 GJ/d	$5.81	April 2004 - October 2004
10,000 GJ/d	$5.86	April 2004 - October 2004
10,000 GJ/d	$5.25-$6.80 collar	April 2004 - October 2004
10,000 GJ/d	$5.25-$6.75 collar	April 2004 - October 2004
20,000 GJ/d	$7.90	November 2004 - March 2005
20,000 GJ/d	$8.03	November 2004 - March 2005

WTI
1,000 Bbl/d	US$25.00-$30.25 collar	January 2004 - December 2004

The Company also has in place foreign exchange forward contracts, which have fixed the exchange rate on US $18.0 million for CDN $25.8 million over the next two years at CDN $1.4337.

On June 6, 2004, the Company entered into a fixed to floating interest rate swap. The Company swapped US$7.875 percent fixed interest for US$ LIBOR plus 320 basis points on the Company’s US $175 million Senior Notes.

On January 1, 2004, the Company adopted the recommendations set out by the Canadian Institute of Chartered Accountants (“CICA”) in Accounting Guideline (“AcG”) 13 — Hedging Relationships and Emerging Issues Committee Abstract 128 — Accounting for Trading, Speculative or Non-Hedging Derivative Financial Instruments. According to the recommendations, financial instruments that do not qualify as a hedge under AcG 13 or are not designated as a hedge are recorded in the consolidated balance sheet 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 six months ended June 30, 2004 totaled $1.5 million for the deferred financial instrument loss and $0.8 million for the deferred financial instrument gain, for a net decrease in earnings before tax of $0.7 million.

In addition, the Company recorded a financial instrument liability at June 30, 2004 with a fair value of $10.3 million. This amount reflects the unrealized changes in fair value of Paramount’s financial instruments.

The total loss on financial instruments for the quarter of $12.8 million is comprised of the afore-mentioned mark-to-market before tax loss on forward contracts of $10.3 million, net amortization expense of $0.7 million, and cash losses on financial instruments of $1.7 million related to monthly settlements with counterparties. The $1.7 million realized cash losses on financial instruments for the six months ended June 30, 2004 is a 96 percent decrease from the $44.3 million of realized cash losses on financial instruments for the 2003 comparative period.

	Three months ended June 30					Six months ended June 30
Cash Netbacks Per Unit of Production ($/Boe)	2004			2003		2004			2003
Gross revenue before financial instruments	$	42.56		$	35.31	$	41.30		$	38.88
Royalties		7.89			6.95		7.89			7.90
Operating costs		6.54			6.46		6.74			5.77
Operating netback		28.13			21.90		26.67			25.21
Loss on financial instruments(1)		1.86			5.37		0.31			6.88
General and administration(2)		1.69			1.59		1.82			1.43
Interest(3)		1.81			1.47		1.66			1.74
Lease rentals		0.30			0.25		0.38			0.23
Bad debt (recovery)		(1.73	)		—		(0.91	)		—
Current and Large Corporations tax		0.60			0.26		0.46			0.20
Cash flow netback	$	23.60		$	12.96	$	22.95		$	14.73

(1)	Excluding unrealized gains and losses on financial instruments.
(2)	Excluding non-cash general and administrative expenses.
(3)	Excluding non-cash interest expense.

ROYALTIES

Royalties, net of ARTC, totaled $44.2 million for the six months ended June 30, 2004, as compared to $50.9 million for the comparable period in 2003, due largely to decreased petroleum and natural gas revenues as a result of lower production during the period. As a percentage of petroleum and natural gas sales, royalties averaged 19 percent in the current period as compared to 20 percent for 2003.

For the three months ended June 30, 2004, royalties totaled $23.2 as compared to $19.7 million during the same period a year earlier. The increase is primarily the result of increased petroleum and natural gas revenues during the period.

OPERATING COSTS

For the six months ended June 30, 2004, operating costs totaled $37.8 million compared to $37.2 million during the same period a year earlier. On a unit-of-production basis, average operating costs increased 17 percent to $6.74/Boe from $5.77/Boe. The increase reflects a general increase in the cost of field services and supplies, as compared to the prior year. For the three months ended June 30, 2004, average operating costs on a unit-of-production basis, decreased six percent to average $6.54/Boe as compared to $6.96/Boe for the first quarter of 2004. Unit costs for the first quarter of 2004 were affected by scheduled, facility maintenance and repair costs in the Northwest Alberta area.

GENERAL AND ADMINISTRATIVE EXPENSES

	Three months ended June 30					Six months ended June 30
General and Administrative Expenses (thousands of dollars)	2004		2003			2004		2003
General and administrative expenses	$	5,334	$	4,637		$	10,201	$	9,179
Stock-based compensation expensed		240		(141	)		1,196		—
Total general and administrative expenses	$	5,574	$	4,496		$	11,397	$	9,179

General and administrative expenses totaled $11.4 million for the six months ended June 30, 2004, as compared to $9.2 million recorded for the same period a year earlier. On a unit-of-production basis, general and administrative expenses before costs associated with stock-based compensation increased to $1.82/Boe as compared to $1.43/Boe for the six month period ended June 30, 2003. Paramount has increased its head-office staffing levels in the past year in order to enable the Company to identify and develop new core areas and build its production portfolio, as well as to ensure compliance with the new corporate and reporting obligations in Canada and the United States. Paramount does not capitalize any general and administrative expenses.

INTEREST EXPENSE

Interest expense for the six months ended June 30, 2004, decreased 13 percent to $9.8 million from $11.2 million for the same period in 2003, as a result of lower debt levels resulting from the Trust disposition. Interest expense for the three months ended June 30, 2004 was $5.6 million, a 30 percent increase from $4.3 million in the previous quarter. The Company’s second quarter average debt level was higher as a result of the first quarter capital expenditure program and the $189 million asset acquisition. During the first quarter, capital expenditures exceeded cash flow from operations and the Company drew down its credit facility to finance the cash short falls. For the remainder of the year, cash from operations is expected to exceed the Company’s capital expenditure program. It is anticipated the excess will be used to pay down the debt.

DEPLETION AND DEPRECIATION

Depletion and depreciation (“D&D”) expense increased to $84.5 million from $84.2 million for the six months ended June 30, 2004, primarily due to a higher depletion and depreciation rate. On a unit-of-production basis, depletion and depreciation costs increased to $15.09/Boe as compared to $13.07/Boe for the first six months of 2003, due primarily to the addition of capital costs previously excluded from the depletable base, as well as the addition to capital costs resulting from the implementation of CICA Handbook Section 3110 — Asset Retirement Obligations described in note 2 to the unaudited consolidated financial statements. Expired mineral leases included in D&D expense for the three-month and six-month period ended June 30, 2004 totaled $2.0 million and $4.9 million, respectively (2003 — $0.7 million and $3.4 million respectively).

Capital costs associated with undeveloped land and exploratory, non-producing petroleum and natural gas properties of $257.7 million are excluded from costs subject to depletion (2003 — $286 million).

INCOME TAX

At December 31, 2003, the Company had accumulated tax pools of approximately $495 million, which will be available for deduction in 2004 in accordance with Canadian income tax regulations at varying rates of amortization. Paramount does not expect to pay current income taxes in 2004.

CASH FLOW AND EARNINGS

	Three months ended June 30					Six months ended June 30
(thousands of dollars, except per share amounts)	2004		2003			2004		2003
Cash flow from operations	$	69,515	$	36,697		$	128,592	$	94,877
Per share – basic	$	1.19	$	0.61		$	2.18	$	1.58
– diluted	$	1.17	$	0.61		$	2.15	$	1.57
Net earnings (loss)	$	9,936	$	(1,888	)	$	13,115	$	(1,574	)
Per share – basic	$	0.17	$	(0.03	)	$	0.22	$	(0.03	)
– diluted	$	0.17	$	(0.03	)	$	0.22	$	(0.03	)

Cash flow from operations totaled $128.6 million for the six months ending June 30, 2004, representing a 36 percent increase from the $94.9 million for the comparable period in 2003. The increase is due to a $31.6 million reduction of financial instrument losses, and a net $5.1 million recovery of bad debts, partially offset by lower revenue as a result of the Trust disposition.

For the three months ended June 30, 2004, cash flow from operations totaled $69.5 million as compared to $36.7 million in the comparable period in 2003. The 89 percent increase in cash flow resulted from higher revenues due to increased production and higher commodity prices, the bad debt recovery and the reduction in financial instrument losses.

Net earnings for the six months ended June 30, 2004 totaled $13.1 million compared to a net loss of $1.6 million for the comparable period in 2003. The increase in earnings is a result of decreased financial instrument losses.

QUARTERLY INFORMATION

	Three months ended
(thousands of dollars, except per share amounts)	Jun 30, 2004		Mar 31, 2004		Dec 31, 2003		Sep 30, 2003
Net revenues	$	95,767	$	79,179	$	77,697	$	66,004
Net earnings (loss)	$	9,936	$	3,179	$	11,296	$	(7,851	)
Net earnings (loss) per share – basic	$	0.17	$	0.05	$	0.18	$	(0.13	)
– diluted	$	0.17	$	0.05	$	0.18	$	(0.13	)

	Three months ended
(thousands of dollars, except per share amounts)	Jun 30, 2003			Mar 31, 2003		Dec 31, 2002			Sep 30, 2002
Net revenues	$	65,101		$	91,446	$	110,180		$	95,780
Net earnings (loss)	$	(1,888	)	$	314	$	(41,399	)	$	6,180
Net earnings (loss) per share – basic	$	(0.03	)	$	0.01	$	(0.70	)	$	0.10
– diluted	$	(0.03	)	$	0.01	$	(0.70	)	$	0.10

Quarterly net revenues have continued to increase since June 2003 as the Company has steadily increased production and commodity prices continue to remain high. As a result of the disposition of the Trust assets in the first quarter of 2003, quarterly net revenue in prior periods were higher due to higher production, partially offset by generally lower commodity prices.

The net loss of $41.4 million in the fourth quarter of 2002 was primarily due to dry hole costs and impairment charges on non-core properties recorded in the quarter.

CAPITAL EXPENDITURES

	Three months ended June 30								Six months ended June 30
	2004				2003				2004				2003
Wells Drilled	Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Natural Gas		24		17		29		27		102		72		96		75
Oil		—		—		5		4		5		5		10		9
Oilsands evaluation		—		—		—		—		17		17		—		—
Dry		—		—		3		2		6		3		8		6
Total		24		17		37		33		130		97		114		90

(1)	“Gross” wells means the number of wells in which Paramount has a working interest or a royalty interest that may be convertible to a working interest.
(2)	“Net” wells means the aggregate number of wells obtained by multiplying each gross well by Paramount’s percentage working interest therein.

During the six months ended June 30, 2004, Paramount participated in the drilling of 130 gross wells (97 net) including 24 gross wells (17 net) in the second quarter, compared to 114 gross wells (90 net) for the comparable period in 2003.

	Three months ended June 30						Six months ended June 30
Capital Expenditures (thousands of dollars)	2004			2003			2004			2003
Land	$	9,803		$	5,235		$	17,803		$	7,441
Geological and geophysical		1,841			3,423			5,833			4,171
Drilling		18,704			16,128			87,626			55,435
Production equipment and facilities		15,568			25,800			45,069			36,021
Exploration and development expenditures	$	45,916		$	50,586		$	156,331		$	103,068
Proceeds received on property dispositions		(2,448	)		(38,649	)		(5,613	)		(261,481	)
Property acquisitions		185,117			—			185,117			—
Other		513			215			739			490
Net capital expenditures	$	229,098		$	12,152		$	336,574		$	(157,923	)

For the six months ended June 30, 2004, exploration and development expenditures totaled $156.3 million, as compared to $103.1 million for the comparable period in 2003. Higher capital expenditures are due to a larger number of net wells drilled, including a larger number of deep wells in the Grande Prairie area. Capital additions for the six month period were concentrated in the Kaybob and Grande Prairie core areas.

Property dispositions in 2003 include the disposition of the Trust assets for net consideration of $246.4 million.

LIQUIDITY AND CAPITAL RESOURCES

Debt

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.

As at June 30, 2004, the Company has a $203 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 may request an extension on the revolving

credit facility of up to 364 days, subject to the approval of the lenders. To the extent that any lenders participating in the syndicate do not approve the 364-day extension, the amount due to those lenders will convert to a one-year non-revolving term loan with principal due in full on March 31, 2006. Advances drawn on the facility are secured by a fixed charge over the assets of the Company.

On July 20, 2004, the Company’s borrowing capacity under this facility was increased from $203 million to $250 million as a result of the Company’s $189 million asset acquisition of oil and natural gas assets.

The Company has an office building which was acquired as a result of the acquisition of Summit Resources Limited. The building is mortgaged at an interest rate of 6.15 percent over a term of 5 years ending December 31, 2007.

Long-term debt, including current portion, increased to $570.6 million at June 30, 2004, compared to $346.4 million at March 31, 2004, primarily as a result of the US $125 million Senior Notes issued to finance the $189 million asset acquisition. Paramount’s capital program is generally at its highest level during the first three months of the year, as certain of the Company’s core areas are only accessible during the winter months. Accordingly, the Company drew down its credit facility to fund the first quarter capital expenditure program which was in excess of cash flow from operations. For the remainder of 2004, Paramount expects that cash flow from operations will continue to exceed capital expenditures, excluding any major acquisitions.

The Company’s working capital at June 30, 2004, excluding the current portion of long-term debt, was $9.7 million (March 31, 2004 and December 31, 2003 — $36.5 million and $9.1 million working capital deficiency, respectively). The change in working capital reflects the high level of capital expenditures in the first quarter.

Share Capital

For the three months ended June 30, 2004, 42,500 stock options were exercised for cash consideration of $0.1 million; this amount was charged to general and administrative expenses.

Pursuant to its Normal Course Issuer Bid, Paramount repurchased 1,629,500 common shares for cancellation for the six months ended June 30, 2004 at an average price of $11.91 per common share.

OFF-BALANCE SHEET ARRANGEMENTS

The Company has a 99 percent interest in a drilling partnership, which has a long-term operating lease on two drilling rigs operating in western Canada. The Company entered into the partnership to secure access to drilling rigs during peak demand periods.

Paramount’s share of net operating income from the partnership amounted to $0.1 million for the six months ended June 30, 2004 (2003 — $0.1 million), which has been recorded in Paramount’s consolidated statement of earnings.

RELATED PARTY TRANSACTIONS

In the first quarter of 2003, the Company transferred certain natural gas assets in Northeast Alberta to the Trust, a related party. The transaction is described in note 4 to the unaudited interim consolidated financial statements.

RISKS AND UNCERTAINTIES

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

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

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

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

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

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

CRITICAL ACCOUNTING ESTIMATES

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

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

Accounting for Petroleum and Natural Gas Operations

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

The application of the successful efforts method of accounting requires management’s judgment to determine the proper designation of wells as either developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. The results of a drilling operation can take considerable time to analyze,

and the determination that proved reserves have been discovered requires both judgment and application of industry experience. The evaluation of petroleum and natural gas leasehold acquisition costs requires management’s judgment to evaluate the fair value of exploratory costs related to drilling activity in a given area.

Reserve Estimates

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

Paramount’s reserve information is based 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 expenses and asset retirement obligations. If reserve estimates decline, the rate at which the Company records depletion increases, reducing net earnings. In addition, changes in reserve estimates may impact the outcome of Paramount’s assessment of its petroleum and natural gas properties for impairment.

Impairment of Petroleum and Natural Gas Properties

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

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

Asset Retirement Obligations

The asset retirement obligations recorded in the consolidated financial statements are based on an estimate of the fair value of the total costs for future site restoration and abandonment of 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, the timing of asset retirement expenditures 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.

Income Taxes

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

RECENT ACCOUNTING PRONOUNCEMENTS

Variable Interest Entities

The CICA recently issued a draft of 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. The Company does not expect the implementation of this guideline to have a material impact on its consolidated financial statements.

Consolidated Balance Sheets (unaudited)
(thousands of dollars)

	June 30			December 31
	2004			2003
				Restated
				(notes 2 & 5)
ASSETS (note 6)
Current Assets
Short-term investments (market value: 2004 – $10,078; 2003 – $17,265)	$	10,078		$	16,551
Accounts receivable		94,856			82,363
Financial instruments (notes 2 and 8)		3,614			—
Prepaid expenses		3,314			2,282
		111,862			101,196
Property, Plant and Equipment
Property, plant and equipment, at cost		1,804,043			1,452,749
Accumulated depletion and depreciation		(494,456	)		(418,676	)
Assets of discontinued operations (note 5)		6,208			3,234
		1,315,795			1,037,307
Goodwill		31,621			31,621
Other assets		10,665			7,006
	$	1,469,943		$	1,177,130
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	87,514		$	110,339
Financial instruments (notes 2 and 8)		14,654			—
Current portion of long-term debt (note 6)		322			312
Liabilities of discontinued operations (note 5)		1,509			1,138
		103,999			111,789
Long-term debt (note 6)		570,238			293,655
Asset retirement obligations (note 2)		94,400			61,554
Deferred revenue		—			3,959
Future income taxes		207,469			206,684
Liabilities of discontinued operations (note 5)		2,895			3,456
		875,002			569,308
Commitments and Contingencies (note 8)
Shareholders’ Equity
Share capital (note 7)
Issued and outstanding
58,465,100 common shares (2003 – 60,094,600 common shares)		194,952			200,274
Contributed surplus		1,942			746
Retained earnings		294,048			295,013
		490,942			496,033
	$	1,469,943		$	1,177,130

See accompanying notes to consolidated financial statements

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

	Three months ended June 30						Six months ended June 30
	2004			2003			2004			2003
				restated						restated
				(notes 2 and 5)						(notes 2 and 5)
Revenue
Petroleum and natural gas sales	$	125,616		$	101,512		$	231,120		$	251,217
(Loss) on financial instruments (note 8)		(6,297	)		(15,218	)		(12,759	)		(44,322	)
Royalties (net of ARTC)		(23,235	)		(19,695	)		(44,170	)		(50,912	)
Loss on investments		(34	)		(1,020	)		(34	)		(1,020	)
Other income		(283	)		(478	)		199			225
		95,767			65,101			174,356			155,188
Expenses
Operating		19,264			18,302			37,751			37,168
Interest		5,579			4,163			9,821			11,199
General and administrative		5,574			4,496			11,397			9,179
Bad debt recovery (note 9)		(5,107	)		—			(5,107	)		—
Lease rentals		872			702			2,106			1,477
Geological and geophysical		1,841			3,423			5,833			4,171
Dry hole costs		1,171			10,558			4,186			19,449
(Gain) loss on sales of property, plant and equipment		(30	)		21,065			(521	)		20,794
Accretion asset retirement obligations (note 2)		1,292			965			2,538			2,022
Depletion and depreciation		42,577			40,609			84,476			84,180
Writedown of petroleum and natural gas properties		—			9,868			—			9,868
Unrealized foreign exchange loss on US debt		2,680			—			5,270			—
		75,713			114,151			157,750			199,507
Earnings (loss) before taxes from continuing operations		20,054			(49,050	)		16,606			(44,319	)
Income and other taxes
Large Corporations Tax and other		1,773			741			2,549			1,288
Future income tax (recovery) expense (note 10)		8,180			(48,128	)		828			(44,426	)
		9,953			(47,387	)		3,377			(43,138	)
Net earnings from continuing operations		10,101			(1,663	)		13,229			(1,181	)
Net earnings from discontinued operations (note 5)		(165	)		(225	)		(114	)		(393	)
Net earnings (loss)		9,936			(1,888	)		13,115			(1,574	)
Retained earnings, beginning of period		291,866			299,711			295,013			355,912
Adjustment on disposition of assets to a related party (note 4)		—			—			—			(1,388	)
Dividends (note 4)		—			—			—			(51,000	)
Redemption of share capital (note 7)		(7,754	)		—			(14,080	)		—
Adoption of new accounting policy (note 2)		—			—			—			(4,127	)
Retained earnings, end of period	$	294,048		$	297,823		$	294,048		$	297,823
Net earnings (loss) from continuing operations per common share
– basic	$	0.17		$	(0.03	)	$	0.22		$	(0.02	)
– diluted	$	0.17		$	(0.03	)	$	0.22		$	(0.02	)
Net earnings (loss) from discontinued operations per common share
– basic	$	—		$	—		$	—		$	(0.01	)
– diluted	$	—		$	—		$	—		$	(0.01	)
Net earnings (loss) per common share
– basic	$	0.17		$	(0.03	)	$	0.22		$	(0.03	)
– diluted	$	0.17		$	(0.03	)	$	0.22		$	(0.03	)
Weighted average common shares outstanding (thousands)
– basic		58,626			60,169			59,085			60,084
– diluted		59,558			60,244			59,868			60,343

See accompanying notes to consolidated financial statements

Consolidated Statements of Cash Flows (unaudited)
(thousands of dollars)

	Three months ended June 30						Six months ended June 30
	2004			2003			2004			2003
				restated						restated
				(notes 2 and 5)						(notes 2 and 5)
Operating activities
Net earnings (loss) from continuing operations	$	10,101		$	(1,663	)	$	13,229		$	(1,181	)
Add (deduct) non-cash items
Depletion and depreciation		42,577			40,609			84,476			84,180
Writedown of petroleum and natural gas properties		—			9,868			—			9,868
(Gain) loss on sales of property, plant and equipment		(30	)		21,065			(521	)		20,794
Accretion of asset retirement obligations		1,292			965			2,538			2,022
Future income tax (recovery) expense		8,180			(48,128	)		828			(44,426	)
Amortization of other assets		259			—			517			—
Non-cash general and administrative expense		609			—			1,196			—
Non-cash loss on financial instruments (note 8)		835			—			11,040			—
Unrealized foreign exchange loss on US debt		2,680			—			5,270			—
Add items not related to operating activities
Dry hole costs		1,171			10,558			4,186			19,449
Geological and geophysical costs		1,841			3,423			5,833			4,171
Cash flow from operations		69,515			36,697			128,592			94,877
Decrease in deferred revenue		—			(2,380	)		(3,959	)		(4,840	)
Asset retirement obligations expenditure		(173	)		—			(236	)		—
Decrease in other assets		(45	)		—			(240	)		—
Change in non-cash operating working capital from continuing operations		(9,231	)		19,577			(41,430	)		(8,950	)
		60,066			53,894			82,727			81,087
Financing activities
Current and long-term debt – draws		65,828			—			135,817			10,000
Current and long-term debt – repayments		(7,991	)		(21,238	)		(32,478	)		(232,874	)
Shareholder loan		—			—			—			(33,000	)
Proceeds from US debt, net of issuance costs		164,047			—			164,047			—
Share capital – issued		—			—			—			10,317
Share capital – repurchased		(10,503	)		—			(19,401	)		—
		211,381			(21,238	)		247,985			(245,557	)
Cash flow (used in) provided by operating and financing activities		271,447			32,656			330,712			(164,470	)
Investing activities
Property, plant and equipment expenditures		(46,484	)		(50,861	)		(157,127	)		(102,548	)
Petroleum and natural gas property acquisitions (note 3)		(185,117	)		—			(185,117	)		—
Proceeds on sale of property, plant and equipment (note 4)		2,448			38,649			5,613			261,481
Change in non-cash investing working capital		(39,891	)		(19,908	)		9,453			7,093
Discontinued operations (note 5)		(2,403	)		(536	)		(3,534	)		(1,556	)
Cash flow (provided by) used in investing activities		(271,447	)		(32,656	)		(330,712	)		164,470
Decrease (increase) in cash		—			—			—			—
Cash, beginning of period		—			—			—			—
Cash, end of period	$	—		$	—		$	—		$	—
Income taxes paid	$	1,353		$	—		$	19,230		$	5,466
Interest paid	$	10,617		$	3,572		$	12,172		$	10,987

See accompanying notes to consolidated financial statements

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
(all tabular amounts expressed in thousands of dollars)

Paramount Resources Ltd. (“Paramount” or the “Company”) is involved in the exploration and development of petroleum and natural gas primarily in western Canada. The interim consolidated financial statements are stated in Canadian dollars and have been prepared by management in accordance with Canadian generally accepted accounting principles (“GAAP”). Certain information and disclosures normally required to be included in notes to annual consolidated financial statements have been condensed or omitted. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto in Paramount’s Annual Report for the year ended December 31, 2003.

The preparation of interim consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the interim consolidated financial statements and the reported amounts of revenues and expenses during the period. Actual results could differ from those estimates.

1.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

The interim consolidated financial statements have been prepared in a manner consistent with accounting policies utilized in the consolidated financial statements for the year ended December 31, 2003, except as noted below:

2.     CHANGES IN ACCOUNTING POLICIES

Asset Retirement Obligations
Effective January 1, 2004, the Company retroactively adopted, with restatement, the Canadian Institute of Chartered Accountants recommendation on Asset Retirement Obligations, which requires liability recognition for fair value of retirement obligations associated with long-lived assets.

Under this new recommendation, the Company recognizes the fair value of an asset retirement obligations 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, and is recognized as accretion expense in the consolidated statement of earnings. The liability is also adjusted due to revisions in either the timing or the amount of the original estimated cash flows associated with the liability. Actual costs incurred upon settlement of the asset retirement obligations will reduce the asset retirement liability to the extent of the liability recorded. Differences between the actual costs incurred upon settlement of the asset retirement obligations and the liability recorded are recognized in the Company’s earnings in the period in which the settlement occurs.

As a result of this change, net earnings for the three and six months ended June 30, 2003 decreased by $0.5 million and $0.8 million ($nil and $0.01 per share), respectively. The asset retirement obligations liability as at December 31, 2003 increased by $40.4 million and property, plant and equipment, net of accumulated depletion, increased by $31.1 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 obligation, recorded retroactively.

The undiscounted asset retirement obligations at June 30, 2004 is $141.0 million (December 31, 2003 — $104.8 million). The Company’s credit adjusted risk free rate is 7.875 percent.

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

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, including 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 derivative 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 value 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.

As at January 1, 2004, the Company had elected not to designate any of its financial instruments as hedges under AcG 13 and has fair-valued the derivatives and recognized the gains and losses on the consolidated balance sheet and statement of earnings. The impact on the Company’s consolidated financial statements at January 1, 2004, resulted in the recognition of financial instrument assets with a fair value of $3.3 million, a financial instrument liability of $1.8 million for a net deferred gain on financial instruments of $1.5 million (note 8).

3.     ACQUISITION OF OIL AND GAS PROPERTIES

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, and 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 liability related to asset retirement obligations, related to those properties.

4.     DISPOSITION OF ASSETS TO PARAMOUNT ENERGY TRUST

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

a)	On February 3, 2003, Paramount transferred to the Trust natural gas properties in the Legend area of Northeast Alberta for net proceeds of $28 million and 9,907,767 units of the Trust.
b)	On February 3, 2003, Paramount declared a dividend-in-kind of $51 million, consisting of an aggregate of 9,907,767 units of the Trust. The dividend was paid to shareholders of Paramount’s common shares of record on the close of business on February 11, 2003.
c)	On March 11, 2003, in conjunction with the closing of a rights offering by the Trust, Paramount disposed of additional natural gas properties in Northeast Alberta to Paramount Operating Trust for net proceeds of $167 million.

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

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 were included as a cost of disposition.

During the first six months of 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 an adjustment 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 Wilson’s drilling assets for $32 million to a publicly traded Income Trust. The 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 will be extinguished. For reporting purposes, the results of operations, capital assets, and the current and long-term debt have been presented as discontinued operations. Prior period financial statements have been reclassified to reflect this change.

Selected financial information of the discontinued operations:

	Three months ended June 30						Six months ended June 30
	2004			2003			2004			2003
Revenue
Other Income	$	225		$	26		$	815		$	446
Expenses
Interest		121			71			217			97
General and administrative		110			93			128			178
Depreciation		312			224			553			447
(Gain) loss on sale of property and equipment		(27	)		—			19			—
		516			388			917			722
Net (loss) before income tax		(291	)		(362	)		(102	)		(276	)
Future income tax expense (recovery)		(126	)		(137	)		12			117
Net (loss) from discontinued operations	$	(165	)	$	(225	)	$	(114	)	$	(393	)

	June 30,		December 31,
	2004		2003
Property, plant and equipment, net	$	6,208	$	3,234
Current liabilities
Current portion of long-term debt	$	1,509	$	1,138
Long-term debt	$	2,895	$	3,456

6.     LONG-TERM DEBT

Current portion of long-term debt as at:

	June 30,		December 31,
	2004		2003
Mortgage – interest rate of 6.15 percent	$	322	$	312

Long-term debt as at:

	June 30,		December 31,
	2004		2003
US $175 million Senior Notes – interest rate of 7.875 percent	$	233,415	$	226,887
US $125 million Senior Notes – interest rate of 8.875 percent		166,725		—
Credit facility – current interest rate of 3.3 percent (2003 – 4.5 percent)		163,843		60,350
Mortgage – interest rate of 6.15 percent		6,255		6,418
	$	570,238	$	293,655

On June 29, 2004, the Company issued US $125 million 8 7/8 percent Senior Notes due 2014. Interest on the note 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.

As at June 30, 2004, the Company has a $203 million committed revolving/non-revolving term facility with a syndicate of Canadian chartered 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 may request an extension on the revolving credit facility of up to 364 days, subject to the approval of the lenders. To the extent that any lenders participating in the syndicate do not approve the 364-day extension, the amount due to those lenders will convert to a one-year non-revolving term loan with principal due in full on March 31, 2006. Advances drawn on the facility are secured by a fixed charge over the assets of the Company.

On July 20, 2004, the Company’s borrowing capacity under this facility was increased from $203 million to $250 million as a result of the Company’s $189 million asset acquisition of oil and natural gas assets (note 3).

The Company has letters of credit totaling $19.9 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.

The Company has an office building that is mortgaged at an interest rate of 6.15 percent over a term of 5 years ending December 31, 2007.

7.     SHARE CAPITAL

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

Issued Capital

Common Shares	Number			Consideration
Balance December 31, 2002		59,458,600		$	190,193
Stock options exercised during the year		710,000			10,317
Shares repurchased – at carrying value		(74,000	)		(236	)
Balance December 31, 2003		60,094,600		$	200,274
Shares repurchased – at carrying value		(803,700	)		(2,572	)
Balance March 31, 2004		59,290,900		$	197,702
Shares repurchased at carrying value		(825,800	)		(2,750	)
Balance June 30, 2004		58,465,100		$	194,952

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. During the six months ended June 30, 2004, 1,629,500 shares were purchased pursuant to the plan at an average price of $11.91 per share. For the three and six-month period ended June 30, 2004, $7.8 million and $14.1 million, respectively, has been charged to retained earnings related to the share repurchase price in excess of the carrying value of the shares.

Stock Option Plan
As at June 30, 2004, 5.9 million shares were reserved for issuance under the Company’s Employee Incentive Stock Option Plan, of which 3.5 million options are outstanding, exercisable to December 31, 2008, at prices ranging from $8.91 to $13.94 per share.

Stock options	Six months ended June 30, 2004
	Average grant price		Options
Balance, beginning of period	$	9.64		3,632,000
Granted		12.23		142,000
Exercised		9.98		(188,750	)
Cancelled		9.16		(89,000	)
Balance, end of period	$	9.74		3,496,250
Options exercisable, end of period	$	10.81		943,625

During the three months ended June 30, 2004, 42,500 stock options were exercised for cash consideration of $0.1 million, which has been charged to general and administrative expense (2003 — $nil).

The following table summarizes information about stock options outstanding at June 30, 2004:

			Outstanding						Exercisable
			Weighted		Weighted				Weighted
			Average		Average				Average
			Contractual		Exercise		Exercisable		Exercise
Exercise Prices	Number		Life		Price		Number		Price
$    8.91-9.80		2,357,250		3	$	9.02		267,125	$	9.00
$10.01-13.94		1,139,000		1	$	11.24		676,500	$	11.52
Total		3,496,250		3	$	9.74		943,625	$	10.81

8.     FINANCIAL INSTRUMENTS

As disclosed in note 2, on January 1, 2004, the fair value of all outstanding financial instruments that are not designated as accounting hedges, was 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. Changes in fair value associated with those financial instruments are recorded on the consolidated balance sheet 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, 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 June 30, 2004.

	June 30,
	2004
Financial instrument asset	$	3,614
Financial instrument liability		(14,654	)
Net financial instrument liability	$	(11,040	)

	Three months ended June 30, 2004									Six months ended June 30, 2004
	Net deferred									Net deferred
	amounts on			Mark-to-market						amounts on			Mark-to-market
	transition			gain (loss)			Total			transition			gain (loss)			Total
Fair value of contracts, January 1, 2004	$	—		$	—		$	—		$	(1,450	)	$	1,450		$	—
Change in fair value of contracts recorded on transition, still outstanding at June 30, 2004		—			(3,747	)		(3,747	)		—			(8,474	)		(8,474	)
Amortization of the fair value of contracts as at June 30, 2004		(480	)		—			(480	)		(698	)		—			(698	)
Fair value of contracts entered into during the period		—			3,392			3,392			—			(1,868	)		(1,868	)
Unrealized loss on financial instruments	$	(480	)	$	(355	)	$	(835	)	$	(2,148	)	$	(8,892	)	$	(11,040	)
Realized (loss) on financial instruments for the period ended June 30, 2004								(5,462	)								(1,719	)
Net (loss) on financial instruments for the period ended June 30, 2004							$	(6,297	)							$	(12,759	)

For the three and six months ended June 30, 2004, the Company has realized losses on financial instruments of $5.5 million and $1.7 million, respectively, compared to $15.2 million and $44.3 million of realized losses on financial instruments for the same period in 2003.

(a)     INTEREST RATE CONTRACTS

On June 6, 2004, the Company entered into a fixed to floating interest rate swap. The fair value of this contract as at June 30, 2004, was a loss of $1.0 million.

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

(b)     FOREIGN EXCHANGE CONTRACTS

The Company has entered into the following currency index swap transactions, fixing the exchange rate on receipts of US $18.0 million for CDN $25.8 million over the next two years at CDN $1.4337. The US$/CDN$ closing exchange rate was 1.3338 as at June 30, 2004 (December 31, 2003 — 1.2965).

			Weighted average
Year of settlement	US dollars		exchange rate
2004	$	6,000		1.4337
2005		12,000		1.4337
	$	18,000		1.4337

At January 1, 2004, the Company recorded a deferred gain on financial instruments of $3.3 million related to existing foreign exchange contracts. The fair value of these contracts at June 30, 2004, was a loss of $1.7 million. The change in fair value, a $5.0 million loss, and $0.8 million amortization of the deferred gain have been recorded in the consolidated statement of earnings.

(c)     COMMODITY PRICE CONTRACTS

At June 30, 2004, the Company has entered into financial forward sales arrangements as follows:

AECO	Price	Term
10,000 GJ/d	$5.51	April 2004 - October 2004
10,000 GJ/d	$5.55	April 2004 - October 2004
20,000 GJ/d	$5.80	April 2004 - October 2004
10,000 GJ/d	$5.81	April 2004 - October 2004
10,000 GJ/d	$5.86	April 2004 - October 2004
10,000 GJ/d	(collar) $5.25-$6.80	April 2004 - October 2004
10,000 GJ/d	(collar) $5.25-$6.75	April 2004 - October 2004
20,000 GJ/d	$7.90	November 2004 - March 2005
20,000 GJ/d	$8.03	November 2004 - March 2005

WTI
1,000 Bbl/d	(collar) US$25.00-$30.25	January 2004 - December 2004

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 fair value of these contracts at June 30, 2004, was a loss of $4.1 million. The change in fair value, a $3.5 million loss, and $1.5 million amortization of the deferred loss have been recorded in the consolidated statement of earnings. At June 30, 2004, a $0.9 million loss was recorded in the consolidated statement of earnings related to the fair value of financial contracts entered into after January 1, 2004. No deferred gains or losses were recorded related to these financial contracts.

9.     BAD DEBT RECOVERY

During 2003, one of the Company’s customers filed for bankruptcy protection under the Companies Credit Arrangement Act. The Company was owed approximately $8 million for which a $6 million bad debt provision was recorded during 2003.

On April 22, 2004, a settlement negotiated with the customer was approved by the Creditor Committee of the customer, and the Plan of Arrangement was approved by the Court of Queen’s Bench. The Company received approximately $7 million on settlement and has been recorded as a bad debt recovery in the period.

10.     INCOME TAXES

In 2004, the Government of Alberta reduced its corporate income tax rate by one percent. As a result, the Company’s future income tax liability has been reduced by $5.2 million and recognized in the future income tax provision for the six month period ended June 30, 2004.

11.     COMPARATIVE FIGURES

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

Paramount Resources Ltd.
Pro-forma Supplemental Oil and Gas Operating Statistics – unaudited
For the Period Ended June 30, 2004
(Note 1)

Sales Volumes	2004				2003								2002
	Q2		Q1		Q4		Q3		Q2		Q1		Q4		Q3
Gas (MMcf/d)		157		141		141		136		142		143		172		162
Oil and Natural Gas Liquids (Bbl/d)		6,134		5,675		5,877		7,461		7,465		7,892		8,552		7,832
Total Sales Volumes (Boe/d) (6:1)		32,354		29,178		29,353		30,098		31,129		31,711		37,243		34,756

Per-unit Results	2004						2003												2002
	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Produced Gas ($/Mcf)
Price, net of transportation and selling		7.01			6.54			5.14			5.74			5.91			6.91			4.15			3.16
Royalties		1.33			1.33			0.55			1.30			1.14			1.43			0.92			0.65
Operating expenses, net of processing revenue		1.03			1.08			1.26			1.19			0.95			0.73			0.64			0.70
Cash netback before realized commodity hedge		4.65			4.13			3.33			3.25			3.82			4.75			2.59			1.81
Realized commodity hedge		(0.31	)		0.42			0.25			(0.72	)		(1.07	)		(1.62	)		0.29			0.67
Cash netback including realized commodity hedge		4.34			4.55			3.58			2.53			2.75			3.13			2.88			2.48
Produced Oil & Natural Gas Liquids ($/Bbl)
Price, net of transportation and selling		45.37			41.87			36.02			36.48			36.94			42.98			36.03			37.47
Royalties		7.58			7.52			6.64			6.75			7.28			9.04			6.83			8.71
Operating expenses, net of processing revenue		8.14			8.87			11.01			10.01			8.90			6.96			5.72			8.40
Cash netback before realized commodity hedge		29.65			25.48			18.37			19.72			20.76			26.98			23.48			20.36
Realized commodity hedge		(2.75	)		(4.93	)		(3.13	)		(2.27	)		(1.67	)		(4.03	)		(0.76	)		(0.76	)
Cash netback including realized commodity hedge		26.90			20.55			15.24			17.45			19.09			22.95			22.72			19.60
Total Produced ($/Boe)
Price, net of transportation and selling		42.67			39.73			31.87			34.95			35.84			41.85			27.44			23.14
Royalties		7.89			7.88			3.95			7.56			6.95			8.70			5.80			4.99
Operating expenses, net of processing revenue		6.54			6.96			8.25			7.85			6.46			5.02			4.29			5.15
Cash netback before realized commodity hedge		28.24			24.89			19.67			19.54			22.43			28.13			17.35			13.00
Realized commodity hedge		(2.03	)		1.07			0.57			(3.76	)		(5.37	)		(8.33	)		1.15			2.96
Cash netback including realized commodity hedge		26.21			25.96			20.24			15.78			17.06			19.80			18.50			15.96

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

Note 2 –   The Alberta Securities Commission released National Instrument 51-101 (the “Instrument”) in 2003, with an effective date of September 30, 2003. The instrument requires all reported petroleum and natural gas production to be measured in marketable quantities with adjustments for heat content included in the commodity price reported. The Company has adopted the Instrument prospectively. As such, commencing with the fourth quarter of 2003, natural gas production volumes are measured in marketable quantities, with adjustments for heat content and transportation reflected in the reported natural gas price.

Paramount Resources Ltd.
Pro-forma Quarterly Condensed Financial Statements – unaudited
For Q3-Q4 2002, 2003 and Q1-Q2 2004
(thousands of dollars except for per share amounts)
(Note 1)

	2004						2003												2002
	Q2			Q1			Q4			Q3			Q2			Q1			Q4			Q3
Net revenue, before hedging	$	102,064		$	85,641		$	76,156		$	76,427		$	80,319		$	101,989		$	77,000		$	58,046
Financial instruments gain (loss)		(6,297	)		(6,462	)		1,541			(10,423	)		(15,218	)		(29,100	)		3,925			9,466
		95,767			79,179			77,697			66,004			65,101			72,889			80,925			67,512
Operating expenses		19,264			18,487			22,287			21,738			18,302			14,338			14,709			16,468
Interest		5,579			4,338			5,604			3,017			4,163			5,415			9,367			4,670
General and administrative		5,574			5,840			5,832			4,709			4,496			4,513			4,850			3,821
Lease rentals		872			1,234			1,027			1,070			702			775			899			1,343
Geological and geophysical		1,841			3,992			3,208			1,071			3,423			748			1,182			1,238
Dry hole costs		1,171			3,015			5,750			1,533			10,558			5,821			115,909			963
Depletion and depreciation		42,577			42,140			47,055			33,175			40,609			42,551			49,726			33,975
Other		(1,000	)		3,391			(5,550	)		5,512			32,123			528			(8,126	)		1,114
		75,878			82,437			85,213			71,825			114,376			74,689			188,516			63,592
Earnings (loss) before taxes		19,889			(3,258	)		(7,516	)		(5,821	)		(49,275	)		(1,800	)		(107,591	)		3,920
Current and large corporations tax		1,773			776			1,165			422			741			547			1,989			(479	)
Future tax (recovery)		8,180			(7,213	)		(19,977	)		1,608			(48,128	)		163			(74,272	)		333
Net earnings (loss)	$	9,936		$	3,179		$	11,296		$	(7,851	)	$	(1,888	)	$	(2,510	)	$	(35,308	)	$	4,066
Net earnings (loss) per common share
– basic	$	0.17		$	0.05		$	0.19		$	(0.13	)	$	(0.03	)	$	(0.04	)	$	(0.59	)	$	0.07
– diluted	$	0.17		$	0.05		$	0.19		$	(0.13	)	$	(0.03	)	$	(0.04	)	$	(0.59	)	$	0.07
Cash flow from operations	$	69,515		$	59,554		$	43,157		$	29,071		$	36,697		$	47,301		$	49,111		$	41,689
Cash flow from operations per common share
– basic	$	1.19		$	1.00		$	0.72		$	0.48		$	0.61		$	0.79		$	0.83		$	0.70
– diluted	$	1.17		$	0.99		$	0.72		$	0.48		$	0.61		$	0.79		$	0.82		$	0.70
WA shares o/s (basic)		58,626			59,560			60,168			60,169			60,169			59,998			59,458			59,459
WA shares o/s (diluted)		59,558			60,209			60,340			60,287			60,244			60,072			59,581			59,616

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