NEWS RELEASE

Paramount Resources Ltd.: Financial and Operating Results for the Third Quarter Ended September 30, 2004
Calgary, Alberta
November 3, 2004

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

Financial Highlights

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

	Three Months Ended September 30									Nine Months Ended September 30
	2004			2003			% Change			2004			2003			% Change
FINANCIAL
Petroleum and natural gas sales		153,652			96,774			59	%		384,772			347,991			11	%
Cash flow (1)
From operations		75,679			28,568			165	%		204,045			123,181			66	%
Per share — basic		1.29			0.47			174	%		3.47			2.05			69	%
— diluted		1.26			0.47			168	%		3.40			2.04			67	%
Earnings
Net earnings (loss)		45,812			(8,383	)		646	%		58,927			(9,957	)		692	%
Per share — basic		0.78			(0.14	)		657	%		1.00			(0.17	)		688	%
— diluted		0.76			(0.14	)		643	%		0.98			(0.16	)		713	%
Capital expenditures
Exploration and development		51,101			36,185			41	%		207,433			139,253			49	%
Acquisitions, dispositions and other		45,006			(10,062	)		547	%		225,250			(271,053	)		183	%
Net capital expenditures		96,107			26,123			268	%		432,683			(131,800	)		428	%
Total assets (3)											1,429,533			1,175,310			22	%
Net debt (2)(3)											535,511			295,375			81	%
Shareholders’ equity (3)											537,928			496,033			8	%
Common shares outstanding (thousands)
– September 30											58,522			60,169			-3	%
– October 31											63,041
OPERATING
Production
Natural gas (MMcf/d)		196			136			44	%		165			157			5	%
Crude oil and liquids (Bbl/d)		8,446			7,461			13	%		6,758			7,605			-11	%
Total production (Boe/d) @ 6:1		41,072			30,098			36	%		34,226			33,735			1	%
Average prices
Natural gas (pre-hedge) ($/Mcf)		6.36			5.74			11	%		6.62			6.25			6	%
Natural gas ($/Mcf) (4)		6.23			5.02			24	%		6.58			5.10			29	%
Crude oil and liquids (pre-hedge) ($/Bbl)		50.26			36.48			38	%		46.45			38.85			20	%
Crude oil and liquids ($/Bbl) (4)		50.08			34.21			46	%		44.17			36.18			22	%
Drilling activity (gross)
Gas		38			26			46	%		141			122			16	%
Oil		2			2			—			7			12			-42	%
Oilsands evaluation (5)		—			—			—			17			—			—
D&A		1			2			-50	%		6			10			-40	%
Total wells		41			30			37	%		171			144			19	%
Success rate (5)		98	%		93	%		5	%		96	%		93	%		3	%

(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 third quarter daily production for Paramount Resources Ltd. (“Paramount” or the “Company”) averaged 196 MMcf/d of natural gas and 8,446 Bbl/d of oil and natural gas liquids. Average daily production for the quarter was 41,072 Boe/d, a 27 percent increase over the prior quarter and a 36 percent increase over the same period in 2003. The increase in production was primarily due to the Company’s major asset acquisitions. Drilling activity consisted of 41 (32.9 net) wells drilled, resulting in 38 (30.5 net) gas wells and 2 (2.0 net) oil wells (2.0 net) and 1 (0.4 net) dry hole for a 99 percent success rate. Field activity in general was curtailed as a result of wet weather which left surface access conditions difficult for the majority of locations.

Kaybob

Natural gas production volumes increased 17 percent to 105 MMcf/d in the third quarter compared to 90 MMcf/d in the second quarter. Oil and natural gas liquids production increased 113 percent to 5,421 Bbl/d in the third quarter compared to 2,543 Bbl/d in the second quarter. Total production was 22,950 Boe/d as compared to 17,550 Boe/d in the previous quarter, a 31 percent increase. The increase in gas and liquids production is primarily attributed to the Kaybob assets acquired at the end of June. Excluding the impact of the acquisition, production volumes were essentially unchanged from second quarter production despite reduced activity resulting from wet weather conditions and problems at third party facilities.

Third quarter capital expenditures, excluding acquisitions and land, totaled $18 million, bringing year-to-date capital spending to $55 million. Capital spending during the quarter continued to be focused on drilling and completions work including workover and production optimization projects.

Paramount participated in the drilling of 16 (11.6 net) wells in the third quarter, resulting in 12 (9.4 net) gas wells, 2 (2.0 net) oil wells, and 2 (0.2 net) standing wells. Wet summer conditions have restricted construction and tie-in operations. The successful gas and oil wells are expected to be onstream by year end.

Paramount had two drilling rigs operating in the Kaybob area during the third quarter, and plans to have five drilling rigs active in the area by year end. In addition, there are currently four service rigs operating in the area, working on new completions, workover and optimization projects. As a result of the major acquisition earlier in the year, the Company has expanded its position in the Kakwa area and plans to use two of the five drilling rigs to exploit identified opportunities.

Paramount has been incorporating the newly acquired assets into integrated field operations, and the staff associated with the asset acquisitions have been instrumental in providing continuity during the transition period. The Company has also identified optimization opportunities that have started adding production and reserves during the quarter.

The fourth quarter will be busy with drilling and service rig activities peaking during the winter months. The construction group will also be extremely active this winter to get caught up for work that was delayed due to the wet summer.

Grande Prairie

Third quarter production volumes averaged 32 MMcf/d and 525 Bbl/d for a total of 5,829 Boe/d, a 42 percent increase over second quarter production of 4,093 Boe/d. The increase in production volumes is due to the Marten Creek asset acquisition. Pre-acquisition volumes decreased four percent to 3,915 Boe/d for the third quarter due to a one week facility turnaround at Mirage, downtime in Saddle Hills caused by facility modifications and weather related delays in bringing on new wells. Four wells were turned on in the third quarter resulting in an additional 1.5 MMcf/d of initial production rate.

Facility and infrastructure issues identified earlier in the year are expected to be resolved during the fourth quarter. The third-party facility limitations at Marten Creek will be mitigated by an expansion scheduled to be completed by the end of October and production should increase by about 3 MMcf/d. At Mirage, work continues on the third-party pipeline that will be looped to remove the current bottleneck which will allow further increases in production.

Drilling, completion and construction operations were hampered by wet weather conditions leaving approximately 5 MMcf/d of gas to be tied-in during the fourth quarter. The major accomplishment for the third quarter was the drilling of 14 (13.4 net) wells, completing 16 (15.8 net) wells and the tie-in of 4 (3.5 net) wells.

Northwest Alberta / Cameron Hills, Northwest Territories

Northwest Alberta’s third quarter production remained steady averaging 854 Bbl/d of liquids and 22 MMcf/d of natural gas, for a total of 4,530 Boe/d. Liquids production fell short of the 1,293 Bbl/d target, the result of not realizing production from the Cameron Hills wells drilled in the first quarter. Gas production exceeded the target of 19.4 MMcf/d, predominately the result of better than expected performance from existing wells.

Third quarter activities were focused on the technical development of workover and drilling opportunities that will be undertaken in the first quarter of 2005. Surveying activities of new drill sites are ongoing and surface access applications have also been prepared. A total of 22 high working interest drilling locations are planned for 2005, of which 19 will be operated and 3 will be non-operated.

The expanded Haro facility that came on line during the first week of June has facilitated a net production increase from 1.8 MMcf/d to an average of 4.9 MMcf/d for the third quarter. Efforts to match production throughput to the facility ownership capacity of 5.6 MMcf/d have been delayed as the result of lower facility operating suction pressure.

Liard, Northwest Territories / Northeast British Columbia

Production for the third quarter averaged 23 MMcf/d, a 13 MMcf/d increase from second quarter production of 10 MMcf/d. The Liard assets acquired at the end of the second quarter contributed to the production increase. Subsequent to quarter end, Paramount has purchased additional working interests in 3 of the 4 producing properties in the Liard Basin which will add 14 MMcf/d of production.

During the third quarter, the 2M-25 well in Fort Liard was completed and flow-tested raw natural gas at rates in excess of 25 MMcf/d. Workover operations are currently underway on M-25 which is capable of producing up to 10 MMcf/d of raw gas but was shut-in due to accessibility. Both wells are anticipated to be on production by the end of October. Workovers on the 2K-29 and K-29 wells are scheduled for completion during the fourth quarter.

At Colville Lake, Paramount (50% working interest) has drilled 3 wells on the Nogha prospect with very positive results; Nogha C-49, Nogha M-17 and Nogha B-23. The first 2 wells, C-49 and M-17, were cased, completed and flow tested as successful Mt. Clark sweet gas wells and are currently shut-in. Post stimulation flow rates in the wells ranged from 3 to 5 MMcf/d. The B-23 well was cased and completed but due to spring break up was not flow tested. McDaniel and Associates have independently reviewed the exploration results to date and have assigned Possible Raw Gas Reserves in the range of 250 Bcf based on a 6,800 — hectare area covered by the Nogha C-49 and M-17 wells.

Paramount has drilled further exploratory wells targeting the basal Cambrian at Lac Maunoir C-34 which was successfully drilled and tested last year; and a separate structure was tested at West Nogha K-14 which was successfully drilled and cased. Due to spring break up, the K-14 well will not be evaluated until the upcoming winter season. The results of these wells were very positive but details have not be released at this time for reasons of confidentiality.

The Company continues to mobilize materials and equipment in advance of the planned winter operations at Colville Lake. Paramount plans to drill between three and five wells this winter to follow up on last winter’s successes as well as evaluate new exploratory prospects. Based on the positive results so far, several scenarios to bring this gas to market are being investigated.

Southern

Third quarter production averaged 11 MMcf/d of natural gas and 1,611 Bbl/d of liquids for a total of 3,476 Boe/d. This 10 percent decrease over second quarter production of 3,845 Boe/d is the result of the divestment of 540 Bbls/d of non-core oil assets in southeast Saskatchewan.

Capital expenditures during the quarter resulted in 10 (7.5 net) wells drilled, for which 3 (2.4 net) wells are in the Chain area. The Company also participated in three completion wells, all successful, two of which were in the Chain/Craigmyle area.

In the Chain/Craigmyle area, Paramount presently has 5 (2.5 net) Horseshoe Canyon CBM wells on production at a total gross rate of 0.6 MMcf/d (0.2 MMcf/d net). The Company has commenced a 20 well development project which will proceed throughout the fourth quarter and into the first quarter of 2005. These wells are expected to be on production by the end of the first quarter in 2005.

Financial

Petroleum and natural gas sales before hedging totaled $153.7 million for the three months ended September 30, 2004, as compared to $96.8 million for the comparable period in 2003. The increase in revenue is a result of a 36 percent increase in average production to 41,072 Boe/d in the current quarter as compared to 30,098 Boe/d in the third quarter of 2003, combined with higher commodity prices. Cash flow from operations for the three months ended September 30, 2004 was $75.7 million or $1.26 per diluted common share as compared to $28.6 million or $0.47 per diluted common share for the same period in 2003. Net income for the three months ended September 30, 2004 totaled $45.8 million or $0.76 per diluted common share as compared to a net loss of $8.4 million or $0.14 loss per diluted common share for the comparable period in 2003. Current quarter earnings were impacted by higher production levels combined with higher commodity prices, a $21.7 million unrealized foreign exchange gain on US debt and a $15.0 million gain on the disposition of non-core assets in southeast Saskatchewan. Net debt decreased by $25.4 million from June 30, 2004 to $535.5 million primarily due to a $21.7 million unrealized foreign exchange gain on US debt. Capital expenditures, including acquisitions net of proceeds from dispositions, during the third quarter were $96.1 million, bringing the year to date total capital expenditures to $432.7 million.

Equity Issue

On October 26, 2004, Paramount completed its public offering of 2,500,000 common shares at a price of $23.00 per share for gross proceeds of $57.5 million. Paramount also issued 2,000,000 common shares on a “flow-through” basis at $29.50 per share for gross proceeds of $59.0 million by way of private placement. 1,020,000 of the flow-through shares were subscribed by directors, management and employees of Paramount. The $113.0 million net proceeds from the issuances will be used to repay existing indebtedness and for general corporate purposes including ongoing exploration activities.

Strategic Alternatives Process

The Board of Directors of Paramount Resources Ltd. has authorized management of Paramount to undertake an examination of possible corporate restructuring alternatives available to Paramount to increase shareholder value. No decision on any particular alternative has been reached at this time and there can be no assurance that the Board of Directors will determine to undertake any transaction identified and presented to it by management.

Management of Paramount has been asked to consider strategic options available to Paramount, including but not limited to: maintaining the status quo and continuing Paramount’s strategic direction as an independent oil and natural gas exploration and development company, and reorganizing Paramount, either in whole or in part, into an energy trust. Any restructuring initiatives identified by management will be subject to review by, and approval of, the Board of Directors and will also be subject to the receipt of all required shareholder and regulatory approvals. In addition, depending on the alternative chosen, Paramount may be required to seek the consents of the holders of its outstanding 7 7/8 percent Senior Notes and 8 7/8 percent Senior Notes or otherwise deal with the outstanding Senior Notes in a manner acceptable to each of Paramount and the holders of such Senior Notes.

Outlook

Paramount continues to forecast production to average 180 MMcf/d of natural gas and 7,500 Bbl/d of oil and NGL’s, or a total of 37,500 Boe/d, for 2004. Current production including the acquisition is approximately 210 MMcf/d of natural gas and over 8,500 Bbl/d of liquids, or 43,500 Boe/d. Paramount forecasts cash flow in 2004 to be approximately $300 million or $5.00/share, after adjusting for the equity issuances. Capital expenditures for the year are estimated to be $550 million, including acquisitions net of proceeds from dispositions. Net debt levels at year end, giving effect to the acquisitions, dispositions and the recent equity offerings, are projected to be approximately $440 million.

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 nine months ended September 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 nine months ended September 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 November 3, 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

EQUITY ISSUANCE

On October 15, 2004, Paramount completed the private placement of 2,000,000 common shares issued on a “flow-through” basis at $29.50 per share. The gross proceeds of the issue are $59 million. On October 25, 2004, Paramount completed the issuance of 2,500,000 common shares at a price of $23.00 per share. The gross proceeds of the issue are $57.5 million.

The proceeds from the equity issuances were used to repay existing indebtedness and for general corporate purposes including ongoing exploration activities.

$84 MILLION ASSET ACQUISITION

On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for $83.7 million, subject to adjustments. The assets acquired were producing approximately 14 MMcf/d of natural gas, or 2,300 Boe/d. The reserves attributable to the properties as of July 1, 2004, as estimated by McDaniel and Associates, consist of proved reserves of approximately 17.4 Bcf of natural gas, or 2.9 million Boe; proved plus probable reserves of approximately 22.2 Bcf or 3.7 million Boe. In accounting for this acquisition, the Company recorded a future tax asset in the amount of $96.5 million and a deferred credit of $7.7 million.

$185 MILLION ASSET ACQUISITION

On June 30, 2004, Paramount completed the acquisition of assets in the Kaybob area of central Alberta and the Fort Liard area of the Northwest Territories for $185.1 million, after adjustments. The properties acquired 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; 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.

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

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

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

DISCONTINUED OPERATIONS

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

On September 10, 2004, Paramount completed the disposition of its 99 percent interest in a drilling partnership for approximately $1 million. For reporting purposes, the drilling partnership has been accounted for as discontinued operations.

Paramount intends to sell a building acquired as a result of the 2002 Summit acquisition, in the fourth quarter of 2004. For reporting purposes, $7.9 million of property, plant and equipment, $6.5 million of current and long-term debt, and $0.2 million of earnings have been classified as discontinued operations as at, and for the nine months ended, September 30, 2004.

Revenue and Production

	Three Months Ended					Nine Months Ended
	September 30					September 30
Revenue (thousands of dollars)	2004		2003			2004			2003
Natural gas	$	114,598	$	71,734		$	298,765		$	267,330
Oil and natural gas liquids		39,054		25,040			86,007			80,661
Petroleum and natural gas revenue		153,652		96,774			384,772			347,991
Gain (Loss) on financial instruments		4,033		(10,423	)		(8,726	)		(54,745	)
(Loss) on investments		—		—			(34	)		(1,020	)
Gross revenue	$	157,685	$	86,351		$	376,012		$	292,226

Natural gas revenue for the nine months ended September 30, 2004 increased 12 percent to $298.8 million as compared to $267.3 million for the comparable period in 2003. The increase in natural gas revenue resulted from higher natural gas prices received during the period, combined with higher production levels. Paramount’s average year-to-date natural gas sales price before hedging increased six percent to $6.62/Mcf as compared to $6.25/Mcf for the comparable period in 2003. Natural gas production volumes for the nine-month period ended September 30, 2004 increased five percent to 165 MMcf/d as compared to 157 MMcf/d for the same period in the prior year. The increase in natural gas production volumes is primarily the result of the Company’s capital expenditure programs. Production from the 2004 acquisitions offset the decreases in production from the disposition of natural gas assets in Northeast Alberta (the “Trust assets”) to Paramount Energy Trust (the “Trust”) in the first quarter of 2003.

Natural gas revenue for the three months ended September 30, 2004 increased 60 percent to $114.6 million as compared to $71.7 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. Gas production for the three months ended September 30, 2004 increased 44 percent to average 196 MMcf/d as compared to 136 MMcf/d in the third quarter of 2003. The 2004 asset Acquisition contributed 45 MMcf/d of the increase in gas production while the other 15 MMcf/d production growth was the result of the Company’s capital expenditure programs.

Oil and NGL revenue during the nine months ended September 30, 2004, increased seven percent to $86.0 million as compared to $80.7 million for the comparable period in 2003, primarily due to higher commodity prices received during the period partially offset by lower production volumes. Paramount’s average year to date oil and NGL sales

price before hedging was $46.45/Bbl for the period as compared to $38.85/Bbl in the comparable period in 2003. Oil and NGL sales volumes decreased 11 percent to average 6,758 Bbl/d for the nine months ended September 30, 2004 as compared to 7,605 Bbl/d for the same period in 2003, primarily as a result of the sale of Sturgeon Lake in 2003 and the sale of properties in southeast Saskatchewan, partially offset by production from asset acquisitions.

Oil and NGL revenue for the three months ended September 30, 2004 increased 56 percent to $39.1 million as compared to $25.0 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 combined with higher production volumes. During the current quarter, production increased 13 percent to 8,446 Bbl/d compared to 7,461 Bbl/d in the comparable period in 2003. The increase is primarily a result of the asset acquisitions and partially offset by the disposition of Sturgeon Lake in 2003 and the disposition of the southeast Saskatchewan properties in 2004.

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 September 30, 2004, Paramount had the following forward financial contracts in place:

	Amount	Price	Term
Sales Contracts
AECO Fixed Price	10,000 GJ/d	$5.51	April 2004 - October 2004
AECO Fixed Price	10,000 GJ/d	$5.55	April 2004 - October 2004
AECO Fixed Price	20,000 GJ/d	$5.80	April 2004 - October 2004
AECO Fixed Price	10,000 GJ/d	$5.81	April 2004 - October 2004
AECO Fixed Price	10,000 GJ/d	$5.86	April 2004 - October 2004
AECO Collars	10,000 GJ/d	$5.25 - $6.75 collar	April 2004 - October 2004
AECO Collars	10,000 GJ/d	$5.25 - $6.80 collar	April 2004 - October 2004
AECO Fixed Price	20,000 GJ/d	$6.82	September 2004 - October 2004
NYMEX Fixed Price	10,000 MMbtu/d	US $6.41	November 2004 - March 2005
NYMEX Fixed Price	10,000 MMbtu/d	US $7.46	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$7.60	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$7.90	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$8.03	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$6.28	April 2005 - June 2005
AECO Fixed Price	20,000 GJ/d	$6.30	April 2005 - June 2005
AECO Fixed Price	20,000 GJ/d	$6.80	April 2005 - June 2005
WTI Collars	1,000 Bbl/d	US $25.00 - 30.25 collar	January 2004 - December 2004
Purchase Contracts
AECO Fixed Price	20,000 GJ/d	$6.76	November 2004 - March 2005

The Company also has in place foreign exchange forward contracts, which have fixed the exchange rate on US $15.0 million for CDN $21.5 million over the next two years at CDN $1.4337.

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 sheets as either an asset or a liability, with changes in fair value recorded in net earnings. The Company has chosen not to designate any of its financial instruments as hedges and accordingly, has used mark-to-market accounting for these instruments.

As a result of applying these recommendations, the Company recorded deferred financial instrument gains and losses at January 1, 2004 of $3.3 million and $1.8 million, respectively, representing the fair values of financial contracts outstanding at the beginning of the fiscal year. These deferred gains and losses are being recognized in the earnings over the term of the related contracts. Amortization for the nine months ended September 30, 2004 totaled $1.7 million for the deferred financial instrument loss and $1.2 million for the deferred financial instrument gain, for a net decrease in earnings before tax of $0.5 million.

In addition, the Company recorded a financial instrument liability at September 30, 2004 with a fair value of $2.7 million. This amount reflects the unrealized changes in fair value of Paramount’s financial instruments.

The total loss on financial instruments for the period of $8.7 million is comprised of the aforementioned mark-to-market before tax loss on forward contracts of $2.7 million, net amortization expense of $0.5 million and cash losses on financial instruments of $5.5 million related to monthly settlements with counterparties. The $5.5 million realized cash losses on financial instruments for the nine months ended September 30, 2004 is a 90 percent decrease from the $54.7 million of realized cash losses on financial instruments for the 2003 comparative period.

	Three Months Ended				Nine Months Ended
	September 30				September 30
Cash Netbacks Per Unit of Production ($/Boe)	2004		2003		2004			2003
Gross revenue before financial instruments	$	40.66	$	34.95	$	41.03		$	37.67
Royalties		8.07		7.56		7.96			7.80
Operating costs		7.18		7.85		6.92			6.40
Operating netback		25.41		19.54		26.15			23.47
Loss on financial instruments(1)		1.01		3.76		0.59			5.94
General and administration(2)		1.71		1.72		1.81			1.54
Interest(3)		2.08		1.04		1.81			1.51
Lease rentals		0.30		0.39		0.35			0.28
Bad debt (recovery)		—		2.16		(0.54	)		0.65
Current and Large Corporations tax		0.29		0.15		0.37			0.18
Cash flow netback	$	20.02	$	10.32	$	21.76		$	13.37

(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 $74.7 million for the nine months ended September 30, 2004, as compared to $71.8 million for the comparable period in 2003. The increase is due to higher petroleum and natural gas revenues partially offset by higher gas cost allowance credits from prior years capital expenditures adjustments. As a percentage of petroleum and natural gas sales, royalties averaged 19 percent in the current period as compared to 21 percent for 2003.

For the three months ended September 30, 2004, royalties totaled $30.5 million as compared to $20.9 million during the same period a year earlier. The increase is primarily the result of increased petroleum and natural gas revenues during the period. As a percentage of petroleum and natural gas sales, royalties averaged 20 percent compared to 22 percent for the comparable three month period in 2003.

Operating Costs

For the nine months ended September 30, 2004, operating costs totaled $64.9 million compared to $58.9 million during the same period a year earlier. On a unit-of-production basis, average operating costs increased eight percent to $6.92/Boe from $6.40/Boe, reflecting a general increase in the cost of field services and supplies and the higher operating costs related to the asset acquisitions. For the three months ended September 30, 2004, average per-unit operating costs decreased nine percent to average $7.18/Boe as compared to $7.85/Boe for the comparable period in 2003. The decrease is primarily due to the disposition of the high operating costs of the Sturgeon Lake property in 2003.

General and Administrative Expenses

	Three Months Ended				Nine Months Ended
	September 30				September 30
General and Administrative Expenses (thousands of dollars)	2004		2003		2004		2003
General and administrative expenses	$	5,864	$	4,764	$	16,021	$	14,170
Stock-based compensation expensed		1,227		—		2,817		—
Total general and administrative expenses	$	7,091	$	4,764	$	18,838	$	14,170

General and administrative expenses totaled $18.8 million for the nine months ended September 30, 2004, as compared to $14.2 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 $1.71/Boe as compared to $1.54/Boe for the nine-month period ended September 30, 2003. Paramount has increased its head-office staffing levels due to the major acquisitions during the year, as well as to enable the Company to identify and develop new core areas and build its production portfolio, and 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 nine months ended September 30, 2004, increased 29 percent to $17.9 million from $13.9 million for the same period in 2003. The increase is attributed to higher debt levels resulting from the major acquisitions in 2004. Interest expense for the three months ended September 30, 2004 was $8.2 million, a 186 percent increase from $2.9 million for the same period in 2003.

Depletion and Depreciation

Depletion and depreciation (“D&D”) expense increased to $136.8 million from $117.6 million for the nine months ended September 30, 2004, primarily due to a larger asset base with the major acquisitions, combined with a higher

depletion and depreciation rate. On a unit-of-production basis, depletion and depreciation costs increased to $14.58/Boe as compared to $12.77/Boe for the first nine 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 and nine month period ended September 30, 2004 totaled $3.1 million and $7.8 million, respectively, (2003 — $2.4 million and $5.8 million, respectively).

Capital costs associated with undeveloped land and exploratory, non-producing petroleum and natural gas properties of $264 million are excluded from costs subject to depletion at September 30, 2004 (September 30, 2003 — $274 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

Cash flow from operations totaled $204.0 million for the nine months ended September 30, 2004, representing a 66 percent increase from the $123.2 million for the comparable period in 2003. The increase is due to a $49.2 million reduction of realized financial instrument losses, and a $36.8 million increase in petroleum and natural gas sales as a result of higher commodity prices and increased production volumes.

For the three months ended September 30, 2004, cash flow from operations totaled $75.7 million as compared to $28.6 million in the comparable period in 2003. The 165 percent increase in cash flow is attributed to increased higher petroleum and natural gas sales given increased production volumes and higher commodity prices.

Net earnings for the nine months ended September 30, 2004 totaled $58.9 million compared to a net loss of $10.0 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)		Sep 30, 2004		Jun 30, 2004		Mar 31, 2004		Dec 31, 2003
Net revenues		$	127,192	$	95,767	$	79,179	$	77,697
Net earnings (loss)		$	45,812	$	9,936	$	3,179	$	11,296
Net earnings (loss) per share	— basic	$	0.78	$	0.17	$	0.05	$	0.18
	— diluted	$	0.76	$	0.17	$	0.05	$	0.18

		Three Months Ended
(thousands of dollars, except per share amounts)		Sep 30, 2003			Jun 30, 2003			Mar 31, 2003		Dec 31, 2002
Net revenues		$	65,415		$	65,101		$	91,446	$	110,180
Net earnings (loss)		$	(8,383	)	$	(1,888	)	$	314	$	(41,399	)
Net earnings (loss) per share	— basic	$	(0.14	)	$	(0.03	)	$	0.01	$	(0.70	)
	— diluted	$	(0.14	)	$	(0.03	)	$	0.01	$	(0.70	)

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 periods prior to March 31, 2003 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								Nine Months Ended
	September 30								September 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		38		31		26		10		141		103		122		85
Oil		2		2		2		1		7		6		12		11
Oilsands evaluation		—		—		—		—		17		17		—		—
Dry		1		—		2		—		6		4		10		3
Total		41		33		30		11		171		130		144		99

(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 nine months ended September 30, 2004, Paramount participated in the drilling of 171 gross wells (130 net) including 41 gross wells (33 net) in the third quarter, compared to 144 gross wells (99 net) for the comparable nine month period in 2003.

	Three Months Ended						Nine Months Ended
	September 30						September 30
Capital Expenditures (thousands of dollars)	2004			2003			2004			2003
Land	$	9,363		$	5,082		$	27,166		$	12,523
Geological and geophysical		692			1,071			6,525			5,242
Drilling		28,930			19,558			116,556			74,993
Production equipment and facilities		12,116			10,474			57,186			46,495
Exploration and development expenditures	$	51,101		$	36,185		$	207,433		$	139,253
Proceeds received on property dispositions		(42,087	)		(10,374	)		(47,699	)		(271,855	)
Property acquisitions		86,667			—			271,784			—
Other		426			312			1,165			802
Net capital expenditures	$	96,107		$	26,123		$	432,683		$	(131,800	)

For the nine months ended September 30, 2004, exploration and development expenditures totaled $207.4 million, as compared to $139.3 million for the same period in 2003. The increase is due to a higher number of net wells were drilled in 2004, including a larger number of deep wells in the Grande Prairie area. The Company has also increased land expenditures to $27.2 million from $12.5 million as Paramount continues to build its strategic land inventory.

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 September 30, 2004, the Company had a $250 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 October 12, 2004, the Company’s borrowing capacity under this facility was increased from $250 million to $270 million as a result of the Company’s $84 million acquisition of oil and natural gas assets.

Long-term debt from continuing operations increased to $542.6 million at September 30, 2004, compared to $272.0 million at September 30, 2003, primarily as a result of the asset acquisition.

The Company’s working capital at September 30, 2004, excluding the current portion of long-term debt and liabilities of discontinued operations, was a $7.1 million surplus compared to a $18.4 million deficit at September 30, 2003. The change in working capital is a result of higher cash flows resulting from higher commodity prices and increased production in 2004.

SHARE CAPITAL

For the three and nine months ended September 30, 2004, 121,750 and 310,500 stock options were exercised for cash consideration of $0.6 million and $1.0 million, respectively; 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 at an average price of $11.91 per common share.

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

ASSET RETIREMENT OBLIGATIONS

The asset retirement obligations recorded in the consolidated financial statements are based on 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 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)

	September 30			December 31
(thousands of dollars)	2004			2003
				(restated - notes 2 and 5)
ASSETS (note 6)
Current Assets
Short-term investments (market value: 2004 — $12,700; 2003 — $17,265)	$	11,715		$	16,551
Accounts receivable		96,387			78,890
Financial instruments (notes 2 and 8)		3,438			—
Prepaid expenses		3,016			2,255
Assets of discontinued operations (note 5)		—			1,680
		114,556			99,376
Property, Plant and Equipment
Property, plant and equipment, at cost (note 3)		1,800,447			1,444,139
Accumulated depletion and depreciation		(536,327	)		(418,225	)
Assets of discontinued operations (note 5)		7,869			11,393
		1,271,989			1,037,307
Goodwill		31,621			31,621
Other assets		11,367			7,006
	$	1,429,533		$	1,175,310
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	100,853		$	107,514
Financial instruments (notes 2 and 8)		6,625			—
Liabilities of discontinued operations (note 5)		327			2,455
		107,805			109,969
Long-term debt (note 6)		542,589			287,237
Asset retirement obligations (note 2)		97,449			61,554
Deferred credit (note 3 and 10)		7,369			—
Deferred revenue		—			3,959
Future income taxes		130,222			206,684
Liabilities of discontinued operations (note 5)		6,171			9,874
		783,800			569,308
Commitments and Contingencies (note 8 and 11)
Shareholders’ Equity
Share capital (note 7)
Issued and outstanding 58,521,600 common shares (2003 — 60,094,600 common shares)		195,480			200,274
Contributed surplus		2,588			746
Retained earnings		339,860			295,013
		537,928			496,033
	$	1,429,533		$	1,175,310

See accompanying notes to consolidated financial statements.

Consolidated Statements of Earnings (Loss) and Retained Earnings (unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30
(thousands of dollars except per share amounts)	2004			2003			2004			2003
				(restated -						(restated -
				notes 2 and 5)						notes 2 and 5)
Revenue
Petroleum and natural gas sales	$	153,652		$	96,774		$	384,772		$	347,991
Gain (loss) on financial instruments (note 8)		4,033			(10,423	)		(8,726	)		(54,745	)
Royalties (net of ARTC)		(30,493	)		(20,936	)		(74,663	)		(71,848	)
Loss on investments		—			—			(34	)		(1,020	)
		127,192			65,415			301,349			220,378
Expenses
Operating		27,120			21,738			64,871			58,906
Interest		8,246			2,879			17,865			13,902
General and administrative		7,091			4,764			18,838			14,170
Bad debt expense (recovery) (note 9)		—			5,977			(5,107	)		5,977
Lease rentals		1,141			1,070			3,247			2,547
Geological and geophysical		692			1,071			6,525			5,242
Dry hole costs		4,842			1,533			9,028			20,982
(Gain) loss on sales of property, plant and equipment		(14,980	)		(1,313	)		(15,501	)		19,481
Accretion asset retirement obligations (note 2)		1,728			1,011			4,266			3,033
Depletion and depreciation		52,438			33,596			136,757			117,627
Writedown of petroleum and natural gas properties		—			—			—			9,868
Unrealized foreign exchange (gain) on US debt		(21,660	)		—			(16,390	)		—
		66,658			72,326			224,399			271,735
Earnings (loss) before taxes from continuing operations		60,534			(6,911	)		76,950			(51,357	)
Income and other taxes
Large Corporations Tax and other		1,083			419			3,511			1,695
Future income tax (recovery) expense (note 10)		18,852			1,161			19,671			(43,361	)
		19,935			1,580			23,182			(41,666	)
Net earnings (loss) from continuing operations		40,599			(8,491	)		53,768			(9,691	)
Net earnings (loss) from discontinued operations (note 5)		5,213			108			5,159			(266	)
Net earnings (loss)		45,812			(8,383	)		58,927			(9,957	)
Retained earnings, beginning of period		294,048			297,823			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)		—			—			(14,080	)		—
Adoption of new accounting policy (note 2)		—			—			—			(4,127	)
Retained earnings, end of period	$	339,860		$	289,440		$	339,860		$	289,440
Net earnings (loss) from continuing operations per common share
— basic	$	0.69		$	(0.14	)	$	0.91		$	(0.16	)
— diluted	$	0.68		$	(0.14	)	$	0.90		$	(0.16	)
Net earnings (loss) from discontinued operations per common share
— basic	$	0.09		$	—		$	0.09		$	-
— diluted	$	0.09		$	—		$	0.09		$	-
Net earnings (loss) per common share
— basic	$	0.78		$	(0.14	)	$	1.00		$	(0.17	)
— diluted	$	0.76		$	(0.14	)	$	0.98		$	(0.16	)
Weighted average common shares outstanding (thousands)
— basic		58,496			60,169			58,887			60,112
— diluted		60,003			60,287			59,945			60,520

See accompanying notes to consolidated financial statements.

Consolidated Statements of Cash Flows (unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30
(thousands of dollars)	2004			2003			2004			2003
				(restated -						(restated -
				notes 2 and 5)						notes 2 and 5)
Operating activities
Net earnings (loss) from continuing operations	$	40,599		$	(8,491	)	$	53,768		$	(9,691	)
Add (deduct) non-cash items
Depletion and depreciation		52,438			33,596			136,757			117,627
Writedown of petroleum and natural gas properties		—			—			—			9,868
(Gain) loss on sales of property, plant and equipment		(14,980	)		(1,313	)		(15,501	)		19,481
Accretion of asset retirement obligations		1,728			1,011			4,266			3,033
Future income tax (recovery) expense		18,852			1,161			19,671			(43,361	)
Amortization of other assets		375			—			892			—
Non-cash general and administrative expense		646			—			1,842			—
Non-cash (gain) loss on financial instruments (note 8)		(7,853	)		—			3,187			—
Unrealized foreign exchange (gain) on US debt		(21,660	)		—			(16,390	)		—
Dry hole costs		4,842			1,533			9,028			20,982
Geological and geophysical costs		692			1,071			6,525			5,242
Cash flow from operations		75,679			28,568			204,045			123,181
Decrease in deferred revenue		—			(2,223	)		(3,959	)		(7,063	)
Asset retirement obligations expenditure		(199	)		—			(435	)		—
Decrease in other assets		(1	)		—			(241	)		—
Change in non-cash operating working capital from continuing operations		11,516			(4,247	)		(29,947	)		(12,987	)
		86,995			22,098			169,463			103,131
Financing activities
Current and long-term debt — draws		172,896			—			308,713			10,000
Current and long-term debt — repayments		(172,647	)		(2,769	)		(204,971	)		(235,319	)
Shareholder loan		—			—			—			(33,000	)
Proceeds from US debt, net of issuance costs		(1,076	)		—			162,971			—
Share capital — issued		528			—			528			10,317
Share capital — repurchased		—			—			(19,401	)		—
		(299	)		(2,769	)		247,840			(248,002	)
Cash flow (used in) provided by operating and financing activities		86,696			19,329			417,303			(144,871	)
Investing activities
Property, plant and equipment expenditures		(51,461	)		(35,477	)		(208,587	)		(137,909	)
Petroleum and natural gas property acquisitions (note 3)		(86,667	)		—			(271,784	)		—
Proceeds on sale of property, plant and equipment (note 4)		42,087			10,374			47,699			271,855
Change in non-cash investing working capital		(1,020	)		5,388			8,433			12,481
Discontinued operations (note 5)		10,365			386			6,936			(1,556	)
Cash flow (provided by) used in investing activities		(86,696	)		(19,329	)		(417,303	)		144,871
Decrease (increase) in cash		—			—			—			—
Cash, beginning of period		—			—			—			—
Cash, end of period	$	—		$	—		$	—		$	—
Income taxes paid	$	10,135		$	—		$	29,365		$	5,466
Interest paid	$	1,421		$	3,169		$	13,593		$	13,798

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

(all tabular amounts expressed in thousands of dollars except as otherwise noted)

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 obligation in the period in which it is incurred or when a reasonable estimate of the fair value can be made. The asset retirement costs equal to the fair-value of the retirement obligations are capitalized as part of the cost of the related long-lived asset and allocated to expense on a basis consistent with depreciation and depletion. The liability associated with the asset retirement costs is subsequently adjusted for the passage of time which is recognized as accretion expense in the consolidated statement of earnings (loss). 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 (loss) in the period in which the settlement occurs.

As a result of this change, net earnings for the three and nine months ended September 30, 2003 decreased by $0.5 million and $1.3 million ($0.01 and $0.02 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 September 30, 2004 are $146.0 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 derivatives on an ongoing basis to ensure that the derivatives entered into are highly effective in offsetting changes in fair values or cash flows of the hedged items. The fair values of derivative financial instruments designated as hedges are not reflected in the consolidated financial statements. Derivative financial instruments not formally designated as hedges are measured at fair value and recognized on the consolidated balance sheet with changes in the fair value recognized in earnings during the period.

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 sheets and statement of earnings (loss). 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

$185 MILLION ASSET ACQUISITION

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

$84 MILLION ASSET ACQUISITION

On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for $83.7 million, subject to adjustments. The assets acquired were producing approximately 14 MMcf/d of natural gas, or 2,300 Boe/d. The reserves attributable to the properties as of July 1, 2004, as estimated by McDaniel and Associates, consist of proved reserves of approximately 17.4 Bcf of natural gas, or 2.9 million Boe; proved plus probable reserves of approximately 22.2 Bcf or 3.7 million Boe. In accounting for the acquisition, the Company recorded a future tax asset in the amount of $96.5 million and a deferred credit of $7.7 million (note 10).

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 nine 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 its drilling assets for $32 million to a publicly traded Income Trust. The gross proceeds were $19.2 million cash with the balance in exchangeable shares. The exchangeable shares are valued at the fair market value of the purchasers’ shares and can be redeemed for trust units in the Income Trust subject to customary securities laws and regulations. In connection with the closing of the sale, certain indebtedness related to these operations has been extinguished. For reporting purposes, the results of operations, property, plant and equipment, and the current and long-term debt have been presented as discontinued operations. Prior period financial statements have been reclassified to reflect this change.

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

Paramount has reclassified a building (910083 Alberta Ltd.) acquired as a result of the Summit acquisition as an asset held for sale. For reporting purposes, $7.9 million of property, plant and equipment, $6.5 million of current and long-term debt, and $0.2 million of earnings have been classified as discontinued operations as at, and for the nine months ended, September 30, 2004.

Selected financial information of the discontinued operations for the nine months ended September 30, 2004:

	Wilson						Shehtah Wilson						910083
	Drilling						Drilling						Alberta
	Ltd.						Partnership						Ltd.						Total
	2004			2003			2004			2003			2004			2003			2004			2003
Revenue
Other Income		897			914			327			346			—			—			1,224			1,260
Expenses																							—
Interest		247			131			—			—			301			280			548			411
General and administrative		165			296			384			407			(782	)		(807	)		(233	)		(104	)
Depreciation		652			670			6			4			228			224			886			898
(Gain) loss on sale of property and equipment		(6,737	)		—			(34	)		—			—			—			(6,771	)		—
		(5,673	)		1,097			356			411			(253	)		(303	)		(5,570	)		1,205
Net income (loss) before income tax		6,570			(183	)		(29	)		(65	)		253			303			6,794			55
Large Corporation Tax and other		1,537			—			—			—			(5	)		15			1,532			15
Future income tax expense (recovery)		94			234			—			—			9			72			103			306
Net income (loss) from discontinued operations		4,939			(417	)		(29	)		(65	)		249			216			5,159			(266	)

Selected financial information of the discontinued operations for the three months ended September 30, 2004:

	Wilson						Shehtah Wilson					910083
	Drilling						Drilling					Alberta
	Ltd.						Partnership					Ltd.						Total
	2004			2003			2004			2003		2004			2003			2004			2003
Revenue
Other Income		83			468			125			121		—			—			208			589
Expenses
Interest		30			34			—			—		99			104			129			138
General and administrative		37			118			115			89		(163	)		(262	)		(11	)		(55	)
Depreciation		99			223			2			2		76			76			177			301
(Gain) loss on sale of property and equipment		(6,757	)		—			(34	)		—		—			—			(6,791	)		—
		(6,591	)		375			83			91		12			(82	)		(6,496	)		384
Net income (loss) before income tax		6,674			93			42			30		(12	)		82			6,704			205
Large Corporation Tax and other		1,537			—			—			—		(127	)		3			1,410			3
Future income tax expense (recovery)		81			117			—			—		—			(23	)		81			94
Net income (loss) from discontinued operations		5,056			(24	)		42			30		115			102			5,213			108

	Wilson				Shehtah Wilson				910083
	Drilling				Drilling				Alberta
	Ltd.				Partnership				Ltd.				Total
	Sep-30		Dec-31		Sep-30		Dec-31		Sep-30		Dec-31		Sep-30		Dec-31
	2004		2003		2004		2003		2004		2003		2004		2003
Current Assets
Accounts Receivable		—		—		—		1,653		—		—		—		1,653
Prepaid Expenses		—		—		—		27		—		—		—		27
Property, plant and equipment, net		—		3,234		—		62		7,869		8,097		7,869		11,393
Current Liabilities
Accounts payable and accrued liabilities		—		—		—		1,005		—		—		—		1,005
Current portion of long-term debt		—		1,138		—		—		327		312		327		1,450
Long-term debt		—		3,456		—		—		6,171		6,418		6,171		9,874

6.     Long-Term Debt

Long-term debt as at:

	September 30, 2004		December 31, 2003
US $175 million Senior Notes — interest rate of 7.875 percent	$	220,780	$	226,887
US $125 million Senior Notes — interest rate of 8.875 percent		157,700		—
Credit facility — current interest rate of 3.5 percent (2003 — 4.5 percent)		164,109		60,350
	$	542,589	$	287,237

On June 29, 2004, the Company issued US $125 million 8 7/8 percent Senior Notes due 2014. Interest on the notes is payable semi-annually, beginning in 2005. The Company may redeem some or all of the notes at any time after July 15, 2009, at redemption prices ranging from 100 percent to 104.438 percent of the principal amount, plus accrued and unpaid interest to the redemption date, depending on the year in which the notes are redeemed. In addition, the Company may redeem up to 35 percent of the notes prior to July 15, 2007, at 108.875 percent of the principal amount, plus accrued interest to the redemption date, using the proceeds of certain equity offerings. The notes are unsecured and rank equally with all the Company’s existing and future senior unsecured indebtedness. The 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 September 30, 2004, the Company had a $250 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 October 12, 2004, the Company’s borrowing capacity under this facility was increased from $250 million to $270 million as a result of the Company’s $84 million acquisition of oil and natural gas assets (note 3).

The Company has letters of credit totaling $26.7 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.

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
Stock options exercised		56,500			528
Balance September 30, 2004		58,521,600		$	195,480

The Company instituted a Normal Course Issuer Bid to acquire a maximum of five percent of its issued and outstanding shares which commenced May 15, 2003 and expired May 14, 2004. Between January 1, 2004 and May 14, 2004, 1,629,500 shares were purchased pursuant to the plan at an average price of $11.91 per share. For the three and nine-month periods ended September 30, 2004, $nil 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.

Subsequent to September 30, 2004, the Company issued 2,500,000 common shares and 2,000,000 common shares on a “flow- through” basis (note 13).

STOCK OPTION PLAN

As at September 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 $19.51 per share.

	Nine Months Ended September 30, 2004
	Average
Stock Options	Grant Price		Options
Balance, beginning of period	$	9.64		3,632,000
Granted		14.86		274,000
Exercised		10.01		(310,500	)
Cancelled		9.12		(115,000	)
Balance, end of period	$	10.04		3,480,500
Options exercisable, end of period	$	10.75		919,375

During the three and nine month periods ended September 30, 2004, 121,750 and 310,500 stock options were exercised for cash consideration of $0.6 million and $1.0 million respectively, which has been charged to general and administrative expense (2003 — $nil).

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

			Outstanding						Exercisable
			Weighted		Weighted				Weighted
			Average		Average				Average
Exercise			Contractual		Exercise		Exercisable		Exercise
Prices	Number		Life		Price		Number		Price
$8.91-9.80		2,265,500		3	$	9.02		283,875	$	9.04
$10.01-19.51		1,215,000		2	$	11.94		635,500	$	11.52
Total		3,480,500		2	$	10.04		919,375	$	10.75

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 sheets with an offsetting net deferred gain. The net deferred gain is recognized into net earnings (loss) over the life of the associated contracts.

The changes in fair value associated with the financial instruments are recorded on the consolidated balance sheets with the associated unrealized gain or loss recorded in net earnings (loss). 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 September 30, 2004.

	September 30, 2004
Financial instrument asset	$	3,438
Financial instrument liability		(6,625	)
Net financial instrument liability	$	(3,187	)

	Three Months Ended							Nine Months Ended
	September 30, 2004							September 30, 2004
	Net Deferred		Mark-to					Net Deferred			Mark-to
	Amounts on		Market					Amounts on			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 September 30, 2004		—		1,307		1,307			—			(7,168	)		(7,168	)
Amortization of the fair value of contracts as at September 30, 2004		234		—		234			(464	)		—			(464	)
Fair value of contracts entered into during the period		—		6,312		6,312			—			4,445			4,445
Unrealized loss on financial instruments		234		7,619		7,853			(1,914	)		(1,273	)		(3,187	)
Realized (loss) on financial instruments for the period ended September 30, 2004		—		—		(3,820	)		—			—			(5,539	)
Net (loss) on financial instruments for the period ended September 30, 2004		—		—		4,033			—			—			(8,726	)

For the three and nine months ended September 30, 2004, the Company has realized losses on financial instruments of $3.8 million and $5.5 million, respectively, compared to $10.4 million and $54.7 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 September 30, 2004, was a gain of $5.8 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 $15.0 million for CDN $21.5 million over the next two years at CDN $1.4337. The US$/CDN$ closing exchange rate was 1.2616 as at September 30, 2004 (December 31, 2003 — 1.2965).

Year of settlement	US dollars		Weighted average exchange rate
2004	$	3,000		1.4337
2005		12,000		1.4337
	$	15,000		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 September 30, 2004, was a loss of $2.5 million. The change in fair value, a $5.8 million loss, and $1.2 million amortization of the deferred gain have been recorded in the consolidated statement of earnings.

(c)     COMMODITY PRICE CONTRACTS

At September 30, 2004, the Company has entered into financial forward contracts as follows:

	Amount	Price	Term
Sales Contracts
AECO Fixed Price	10,000 GJ/d	$5.51	April 2004 - October 2004
AECO Fixed Price	10,000 GJ/d	$5.55	April 2004 - October 2004
AECO Fixed Price	20,000 GJ/d	$5.80	April 2004 - October 2004
AECO Fixed Price	10,000 GJ/d	$5.81	April 2004 - October 2004
AECO Fixed Price	10,000 GJ/d	$5.86	April 2004 - October 2004
AECO Collars	10,000 GJ/d	$5.25 - $6.75 collar	April 2004 - October 2004
AECO Collars	10,000 GJ/d	$5.25 - $6.80 collar	April 2004 - October 2004
AECO Fixed Price	20,000 GJ/d	$6.82	September 2004 - October 2004
NYMEX Fixed Price	10,000 MMbtu/d	US $6.41	November 2004 - March 2005
NYMEX Fixed Price	10,000 MMbtu/d	US $7.46	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$7.60	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$7.90	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$8.03	November 2004 - March 2005
AECO Fixed Price	20,000 GJ/d	$6.28	April 2005 - June 2005
AECO Fixed Price	20,000 GJ/d	$6.30	April 2005 - June 2005
AECO Fixed Price	20,000 GJ/d	$6.80	April 2005 - June 2005
WTI Collars	1,000 Bbls	US $25.00-30.25 collar	January 2004 - December 2004
Purchase Contracts
AECO Fixed Price	20,000 GJ/d	$6.76	November 2004 - March 2005

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 September 30, 2004, was a loss of $2.0 million. The change in fair value, a $1.4 million loss, and $1.7 million amortization of the deferred loss have been recorded in the consolidated statement of earnings. At September 30, 2004, a $1.3 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

On August 16, 2004, Paramount completed the acquisition of assets in the Marten Creek area in Grande Prairie for $83.7 million, subject to adjustments. In accounting for the acquisition, the Company recorded a future tax asset in the amount of $96.5 million and a deferred credit of $7.7 million. The future tax asset will be realized as deductions associated with the tax pools are claimed for income tax purposes. The deferred credit is amortized in proportion to the realization of the future tax asset.

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 nine month period ended September 30, 2004.

11.     Commitments

At September 30, 2004, the Company has entered into the following physical delivery contracts:

	Amount	Price		Term
Sales Contracts
NIT Fixed Price	20,000 GJ/d	$	6.22	October 2004
NIT Fixed Price	10,000 GJ/d	$	6.71	October 2004
NIT Fixed Price	20,000 GJ/d	$	7.32	November 2004
NIT Fixed Price	10,000 GJ/d	$	7.16	September 2004 - October 2004
NIT Fixed Price	10,000 GJ/d	$	7.22	September 2004 - October 2004
Station 2 Fixed Price	15,000 GJ/d	$	7.24	July 2004 - October 2004
Station 2 Fixed Price	10,000 GJ/d	$	7.30	June 2004 - October 2004
Station 2 Fixed Price	8,000 GJ/d	$	7.99	November 2004 - March 2005
Station 2 Fixed Price	12,000 GJ/d	$	8.00	November 2004 - March 2005

12.     Comparative Figures

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

13.     Subsequent Events

On October 25, 2004, Paramount completed the issuance of 2,500,000 common shares at a price of $23.00 per share. The gross proceeds of the issue are $57.5 million.

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