Exhibit 1

FORM 51-102F4
BUSINESS ACQUISITION REPORT

Item 1.	Identity of Company
1.1	Name and Address of Company
	Paramount Resources Ltd. (“Paramount”) 4700 – 888 Third Street S.W. Calgary, Alberta T2P 5C5
1.2	Executive Officer
	The name and business telephone number of an executive officer of Paramount who is knowledgeable about the business acquisition and this report, and who may be contacted in connection with this report is James H. T. Riddell, President and Chief Operating Officer of Paramount, at (403) 290-3600.
Item 2.	Details of Acquisition
2.1	Nature of Business Acquired
	On June 30, 2004, Paramount completed the acquisition from Enerplus Commercial Trust of oil and natural gas assets in the Kaybob area of central Alberta (the “Kaybob Acquired Properties”) and in the Fort Liard area of the Northwest Territories and northeast British Columbia (the “Fort Liard Acquired Properties” and with the Kaybob Acquired Properties collectively the “Acquired Properties”), for $185.1 million, after adjustments. The Acquired Properties are producing approximately 10,000 Boe/d, comprised of 40 MMcf/d natural gas and 3,300 Bbl/d of oil and natural gas liquids. The proved reserves attributable to the Acquired Properties as of the effective date of June 1, 2004, on a forecast prices and costs basis, are estimated to be approximately 47.2 Bcf of natural gas and 4.4 million Bbl of oil and natural gas liquids, or a total of 12.3 million Boe; and proved plus probable reserves of approximately 93.6 Bcf of natural gas and 6.7 million Bbl of oil and natural gas liquids, or a total of 22.2 million Boe. Additional information regarding the Acquired Properties, including reserves information prepared in accordance with National Instrument 51-101, is contained in Appendix A.
2.2	Date of Acquisition
	The acquisition was completed on June 30, 2004 with an effective date of June 1, 2004.

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2.3	Consideration
	The purchase price for this acquisition was $185.1 million, after adjustments, paid in cash. The transaction was financed through a public offering of US $125 million principal amount of 8 7/8 percent Senior Notes due 2014 under Paramount’s prospectus supplement dated June 24, 2004 to Paramount’s base short form shelf prospectus dated June 17, 2004. The remaining purchase price was provided by an existing credit facility.
2.4	Effect on Financial Position
	The acquisition of the Acquired Properties is not anticipated to result in any material change to the business affairs of Paramount or the Acquired Properties. The Acquired Properties are adjacent to or near Paramount’s existing properties at Kaybob, Fort Liard and northeast British Columbia. Kaybob is Paramount’s largest core area. The acquisition will complement Paramount’s existing production in those areas and provide additional facility synergies and development drilling opportunities.
2.5	Prior Valuations
	None
2.6	Parties to Transaction
	Not applicable
2.7	Date of Report
	September 10, 2004

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Item 3.

Financial Statements

Appendix B contains Schedules of Revenues, Royalties, and Operating Expenses and Auditor’s Reports of PricewaterhouseCoopers LLP thereon for the Acquired Properties for the year ended December 31, 2003 and unaudited Schedules of Revenues, Royalties and Operating Expenses for the Acquired Properties for the three months ended March 31, 2004 and 2003. Appendix C contains unaudited pro forma consolidated financials statements of Paramount Resources Ltd. and a compilation report of Ernst & Young LLP giving effect to the acquisition of the Acquired Properties.

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APPENDIX A

INFORMATION RELATING TO THE ACQUIRED PROPERTIES

A-1

INFORMATION RELATING TO THE ACQUIRED PROPERTIES

Definitions and Important Notice

In this Appendix A and the Business Acquisition Report to which this Appendix A is attached, the following terms and phrases have the meanings indicated:

“bbl”, “bbls”, “Mbbls” and “MMbbls” mean barrel, barrels, thousand barrels and million barrels, respectively;

“bbls/d” means barrels per day;

“Boe” and “Boe/d” means barrels of oil equivalent and barrels of oil equivalent per day, respectively;

“developed acreage” means acreage on which we have a productive well;

“Mcf”, “MMcf” and “Bcf” mean thousand cubic feet, million cubic feet and billion cubic feet, respectively;

“Mcfe”, “MMcfe” and “Bcfe” mean thousand cubic feet equivalent, million cubic feet equivalent and billion cubic feet equivalent, respectively;

“MMBtu/d” means millions of British thermal units per day;

“MMcf/d” means million cubic feet per day;

“MMcfe/d” means million cubic feet equivalent per day;

“production” means production attributable to our working interest in a property after deducting royalties;

“reserves” means proved reserves attributable to our working interest in a property after deducting royalties;

“undeveloped acreage” means acreage on which we do not have a productive well and includes exploratory acreage; and

“WTI” means West Texas Intermediate grade oil at a reference sales point in Cushing, Oklahoma, a common benchmark for oil.

The gross number of wells drilled by us means the total number of wells drilled on properties in which we have a working interest.

The net number of wells drilled means the product of the total number of wells drilled on properties in which we have a working interest multiplied by our working interests in such wells.

Productive wells are producing wells and wells capable of production. Our gross productive wells means the total number of productive wells in which we have a working interest.

A-2

Our net productive wells means the product of the total number of productive wells in which we have a working interest multiplied by our working interests in such wells.

Our gross acreage means the total acreage in which we have an interest and our net acreage means the product of the total acreage in which we have an interest multiplied by our interest in such acreage.

This Appendix A and the Business Acquisition Report to which this Appendix A is attached contains disclosure respecting oil and gas production expressed as Boe, Boe/d, “Mcfe”, “MMcfe”, “MMcfe/d” or “Bcfe” (see definitions above). All oil and natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalence conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

DESCRIPTION OF ACQUIRED PROPERTIES

Kaybob

The interests in the Kaybob Acquired Properties have current production of approximately 20 MMcf/d of natural gas and approximately 3,300 bbls/d of crude oil and natural gas liquids. The oil and gas properties in the area are primarily mature producing properties. Through the acquisition we acquired working interests ranging from 10%-50% in the pools associated with the Kaybob Acquired Properties. These Kaybob assets will provide us with a number of properties that we expect will permit us to exploit the expertise that we have developed in the area.

Liard, Northwest Territories/Northeast British Columbia

The Fort Liard Acquired Properties have four producing wells in the Northwest Territories which are currently producing approximately 20 MMcf/d of natural gas. Through the acquisition we acquired working interests of 43% in three of the wells and 15% in one of the wells. Prior to the acquisition, we had working interests of 2.8% and 6.9% in the three wells and one well referred to above, respectively. In addition, a new well was drilled and completed in June 2004 on the Fort Liard Acquired Properties, which well reached a total depth of 4,324 meters, and a stimulation and testing program is now underway. With the acquisition now completed, we currently have a 46.2% interest in this well.

In northeast British Columbia, the acquisition consisted of undeveloped lands in the Maxhamish area with no production or reserves currently assigned to these properties. The working interests acquired in the lands range from 25%-100%.

A-3

OIL AND NATURAL GAS RESERVES

The reserves attributable to the Acquired Properties have been evaluated in accordance with National Instrument 51-101 by Sproule Associates Limited (“Sproule”), a firm of independent petroleum engineers, in a report of Sproule dated June 3, 2004 and effective June 1, 2004. The following is a summary of the oil, natural gas liquids and natural gas reserves attributable to the Acquired Properties and the estimated net present values of future net revenues associated with such reserves, on both a constant and forecast prices and costs basis, as evaluated by Sproule. The tables summarize the data contained in the evaluations and as a result may contain slightly different numbers than the evaluations due to rounding. Additionally, the numbers in the tables may not add due to rounding.

     All future net revenues are stated prior to provision for interest, general and administrative expenses and after deduction of royalties and estimated future capital expenditures. It should not be assumed that the present worth of estimated future cash flows shown below is representative of the fair market value of the reserves. There is no assurance that such price and cost assumptions will be attained and variances could be material. The recovery and reserve estimates of the oil, natural gas liquids and natural gas reserves provided below are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates provided below. Readers should read the definitions and information contained in this Appendix A in conjunction with the following tables and notes.

A-4

Summary of Oil and Gas Reserves on a Constant Prices and Costs basis
As of June 1, 2004

					Light and				Natural Gas
	Natural Gas(a)				Medium Crude Oil				Liquids(b)				Total
Reserves Category	Gross(d)		Net(e)		Gross(d)		Net(e)		Gross(d)		Net(e)		Gross(d)		Net(e)
	(MMcf)		(MMcf)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcfe)		(MMcfe)
Proved
Developed producing		49,446		37,303		2,943		2,424		2,233		1,416		80,506		60,344
Developed non-producing		2,304		1,690		—		—		—		—		2,305		1,691
Undeveloped		—		43		—		—		—		—		—		43
Total proved(c)		51,750		39,036		2,943		2,424		2,233		1,416		82,810		62,078

(a)	Natural gas includes sulphur and solution gas equivalents.
(b)	Natural gas liquids includes propane, butane and pentaneplus equivalents.
(c)	Columns may not add due to rounding.
(d)	Gross means company interest reserves before royalties.
(e)	Net means company interest reserves after royalties.

Net Present Value of Future Net Revenues—Constant Prices and Costs

	Net Present Value of Future Revenue
	Before Income Taxes Discounted at										After Income Taxes Discounted at
Reserves Category ($ millions)	0%		5%		10%		15%		20%		0%		5%		10%		15%		20%
Proved
Developed producing		286		245		215		192		174		233		196		171		151		137
Developed non-producing		6		5		5		5		5		3		3		3		3		3
Undeveloped		—		—		—		—		—		—		—		—		—		—
Total proved(a)		292		250		220		197		179		236		200		174		154		139

(a) Columns may not add due to rounding.

Notes:

(1)	The estimated net present value of future net revenue does not include the Alberta Royalty Tax Credit.
(2)	Natural gas reserves are reported at a base pressure of 14.65 pounds per square inch and a base temperature of 60ºF.
(3)	Prices for oil F.O.B. Edmonton are based upon 40º to 45º API having less than 0.5% sulphur. Prices for natural gas are based upon a base pressure of 14.65 pounds per square inch and base temperature of 60ºF. The wellhead oil prices were adjusted for quality and transportation to reflect the actual price to be received. The natural gas prices were adjusted, where necessary, only for heating values and the differing costs of service applied by various purchasers. The natural gas liquids prices were adjusted to reflect current prices received.

A-5

(4) The constant price and costs case assumes the continuance of product prices at June 1, 2004, and operating costs projected for 2004, and the continuance of current laws and regulations. Product prices have not been escalated beyond this date nor have operating and capital costs been increased on an inflationary basis. The future net revenue to be received from the production for the reserves was based on an exchange rate of Cdn$1.00=US$0.734 and the following prices:

Edmonton

Alberta

B.C.

Pentanes

Par Price

AECO-C Spot

Westcoast

Propanes

Butanes

Plus

Sulphur

($/stb)(a)

($/mcf)

($/mcf)

($/bbl)

($/bbl)

($/bbl)

($/lt)(b)

June 1, 2004

52.72

7.33

7.13

33.18

41.29

56.10

40.00

(a)	“stb” means stock tank barrel.
(b)	“lt” means long tons.

(5) The undiscounted total future net revenue for Proved reserves as of June 1, 2004, using constant price and costs, is set forth below:

Future

Future

Net

Net

Revenue

Revenue

Well

Before

After

Reserves Category

Operating

Development

Abandonment

Income

Income

Income

($ millions)

Revenue

Royalties

Costs

Costs

Costs

Taxes

Taxes

Taxes

Proved

628

146

174

12

3

292

56

237

(6) The net present value of future net revenue for proved reserves by production group as of June 1, 2004, using constant price and costs and discounted at 10% per year, is set forth below:

		Future Net Revenue
		Before Income Taxes
Reserves Category ($ millions)	Production Group	(discounted at 10%)
Proved	Natural gas(a)	$	144
	Light and medium crude oil(b)	$	72

(a)	Natural gas includes associated sulphur, natural gas liquids, propane, butane and pentaneplus, but excludes solution gas from oil wells.
(b)	Light and medium crude oil includes solution gas and associated natural gas liquids.

A-6

(7) The volume of gross and net company Proved production estimated by Sproule for the period from June 1, 2004 to December 31, 2004 in preparing the estimated net present values of future net revenue is as follows:

	Proved
Gross(a)
Natural gas (MMcf)(c)		7,801
Light and medium crude oil (Mbbl)		368
Natural gas liquids (Mbbl)(d)		258
Total Gross (MMcfe)(e)		11,557
Net(b)
Natural gas (MMcf)(c)		5,826
Light and medium crude oil (Mbbl)		269
Natural gas liquids (Mbbl)(d)		167
Total Net (MMcfe)(e)		8,433

(a)	Gross means company interest before royalties.
(b)	Net means company interest after royalties.
(c)	Natural gas includes sulphur and solution gas equivalents.
(d)	Natural gas liquids includes propane, butane and pentaneplus equivalents.
(e)	Column may not add due to rounding.

(8) The amount of development costs deducted in the estimation of net present value of future net revenue is as follows:

	2004E				2005E				2006E				2007E				2008E
Reserve Category ($ millions)	0%		10%		0%		10%		0%		10%		0%		10%		0%		10%
Proved
Constant Price Case		3.5		3.4		1.4		1.2		0.7		0.5		0.7		0.5		0.6		0.4

Summary of Oil and Gas Reserves on a Forecast Prices and Costs basis
As of June 1, 2004

					Light and				Natural Gas
	Natural Gas(a)				Medium Crude Oil				Liquids(b)				Total
Reserves Category	Gross(d)		Net(e)		Gross(d)		Net(e)		Gross(d)		Net(e)		Gross(d)		Net(e)
	(MMcf)		(MMcf)		(Mbbl)		(Mbbl)		(Mbbl)		(Mbbl)		(MMcfe)		(MMcfe)
Proved
Developed producing		45,341		34,612		2,536		2,071		1,874		1,209		71,801		54,288
Developed non-producing		2,289		1,692		—		—		—		—		2,290		1,692
Undeveloped		—		43		—		—		—		—		—		43
Total proved(c)		47,630		36,347		2,536		2,071		1,874		1,209		74,091		56,023

(a)	Natural gas includes sulphur and solution gas equivalents.
(b)	Natural gas liquids includes propane, butane and pentaneplus equivalents.

A-7

(c)	Columns may not add due to rounding.
(d)	Gross means company interest reserves before royalties.
(e)	Net means company interest reserves after royalties.

Net Present Value of Future Net Revenues—Forecast Prices and Costs

	Net Present Value of Future Revenue
	Before Income Taxes Discounted at										After Income Taxes Discounted at
Reserves Category ($ millions)	0%		5%		10%		15%		20%		0%		5%		10%		15%		20%
Proved
Developed producing		173		156		143		133		124		146		130		118		109		101
Developed non-producing		5		5		5		4		4		3		3		2		2		2
Undeveloped		—		—		—		—		—		—		—		—		—		—
Total proved(a)		178		161		148		137		128		149		133		120		111		103

(a) Columns may not add due to rounding.

Notes:

(1)	The estimated net present value of future net revenue does not include the Alberta Royalty Tax Credit.
(2)	Natural gas reserves are reported at a base pressure of 14.65 pounds per square inch and a base temperature of 60ºF.
(3)	Prices for oil F.O.B. Edmonton are based upon 40º to 45º API having less than 0.5% sulphur. Prices for natural gas are based upon a base pressure of 14.65 pounds per square inch and base temperature of 60ºF. The wellhead oil prices were adjusted for quality and transportation to reflect the actual price to be received. The natural gas prices were adjusted, where necessary, only for heating values and the differing costs of service applied by various purchasers. The natural gas liquids prices were adjusted to reflect current prices received.
(4)	The forecast price and cost case assumes the continuance of current laws and regulations, and any increase in selling prices also takes inflation into account. The estimated future net revenue to be received from the production of the reserves was based on an inflation rate of 1.5% per year, an exchange rate Cdn $1.00 = US$0.75 and the following price forecasts supplied by Sproule and effective June 1, 2004:

Forecast Prices and Costs

	Oil				Gas		NGL's and Sulphur
			Edmonton		Natural		Pentanes Plus		Butanes		Propane
	WTI Cushing		Par Price		Gas AECO		F.O.B.		F.O.B.		F.O.B.		Plant Gate
	Oklahamon		40 Degree API		Gas Prices		Field Gate		Field Gate		Field Gate		Sulphur
	($US/bbl)		($Cdn/bbl)		($Cdn/MMBtu)		($Cdn/bb)		($Cdn/bb)		($Cdn/bbl)		($Cdn/lt)
2004 (5 month estimate)		37.87		48.99		7.66		50.17		36.51		32.28		40.00
2005		33.87		43.68		6.96		44.73		32.55		28.78		30.45
2006		28.27		36.22		5.76		37.09		25.65		22.67		20.60
2007		26.14		33.37		4.91		34.17		23.63		20.89		15.69
2008		26.53		33.87		4.98		34.69		23.98		21.20		15.92

(a) “lt” means long tons.

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(5) The undiscounted total future net revenue for Proved reserves as of June 1, 2004, using forecast price and costs, is set forth below:

Future

Future

Net

Net

Revenue

Revenue

Well

Before

After

Reserves Category

Operating

Development

Abandonment

Income

Income

Income

($ millions)

Revenue

Royalties

Costs

Costs

Costs

Taxes

Taxes

Taxes

Proved

436

101

142

10

4

179

30

149

(6) The net present value of future net revenue for proved reserves by production group as of June 1, 2004, using forecast prices and costs and discounted at 10% per year, is set forth below:

		Future Net Revenue
		Before Income Taxes
Reserves Category ($ millions)	Production Group	(discounted at 10%)
Proved	Natural gas(a)	$	101
	Light and medium crude oil(b)	$	44

(a)	Natural gas includes associated sulphur, natural gas liquids, propane, butane and pentaneplus, but excludes solution gas from oil wells.
(b)	Light and medium crude oil includes solution gas and associated natural gas liquids.

(7) The volume of gross and net company Proved production estimated by Sproule for the period from June 1, 2004 to December 31, 2004 in preparing the estimated net present values of future net revenue is as follows:

	Proved
Gross(a)
Natural gas (MMcf)(c)		7,801
Light and medium crude oil (Mbbl)		368
Natural gas liquids (Mbbl)(d)		258
Total Gross (MMcfe)(e)		11,557
Net(b)
Natural gas (MMcf)(c)		5,815
Light and medium crude oil (Mbbl)		265
Natural gas liquids (Mbbl)(d)		168
Total Net (MMcfe)(e)		8,409

(a)	Gross means company interest before royalties.
(b)	Net means company interest after royalties.
(c)	Natural gas includes sulphur and solution gas equivalents.
(d)	Natural gas liquids includes propane, butane and pentaneplus equivalents.
(e)	Column may not add due to rounding.

A-9

(8) The amount of development costs deducted in the estimation of net present value of future net revenue is as follows:

	2004E				2005E				2006E				2007E				2008E
Reserve Category ($ millions)	0%		10%		0%		10%		0%		10%		0%		10%		0%		10%
Proved
Forecast Price Case		3.5		3.4		1.4		1.2		0.7		0.5		0.6		0.4		0.6		0.4

A-10

APPENDIX B

AUDITORS REPORTS OF PRICEWATERHOUSECOOPERS LLP AND
SCHEDULES OF REVENUES, ROYALTIES AND OPERATING EXPENSES

B-1

April 2, 2004

Auditors’ Report

To the Management of
Chevron Canada Resources

At the request of Chevron Canada Resources, we have audited the schedule of revenues, royalties and operating expenses for the year ended December 31, 2003 for the Kaybob properties. This financial information is the responsibility of management. Our responsibility is to express an opinion on this financial information based on our audits.

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

In our opinion, the schedule of revenues, royalties and operating expenses presents fairly, in all material respects, the revenues, royalties and operating expenses for the Kaybob properties for the year ended December 31, 2003 in accordance with the basis of accounting disclosed in the notes.

“PricewaterhouseCoopers LLP”

Chartered Accountants

Calgary, Alberta

B-2

Chevron Canada Resources

Kaybob Properties
Schedule of Revenues, Royalties and Operating Expenses

(in thousands of Canadian dollars)

				Three Months Ended
	Year Ended December 31			March 31
	2003			2004			2003
				(unaudited)
Revenues	$	162,391		$	38,782		$	52,435
Royalties		(44,483	)		(11,002	)		(12,892	)
		117,908			27,780			39,543
Operating Expenses		(23,928	)		(6,050	)		(6,165	)
Excess of Revenue Over Operating Expenses		93,980			21,730			33,378

See accompanying notes to schedule of Revenues, Royalties, and Operating Expenses for the Properties.

B-3

Chevron Canada Resources

Kaybob Properties

Notes to Schedule of Revenues, Royalties and Operating Expenses
Year ended December 31, 2003

1.	Basis of Presentation
	The Schedule of Revenues, Royalties, and Operating Expenses includes the operating results relating to Chevron Canada Resource’s interest in the following properties, which are collectively referred to as the Kaybob properties:

Kaybob Operated:	Simonette (A pool and B pool), Karr, Bluesky, Fox Creek Viking, Kaybob North BHL Unit #1, Kaybob South BHL Unit #3
Kaybob Non operated:	Kaybob Notikewan Gas Unit, Kaybob North BHL Gas Plant #2, Triassic Unit, Kaybob South BHL Unit #1, Kaybob South BHL Unit #2, Simonette Suncor, West Kaybob Pinto, West Kaybob Musereau, West Kaybob Cecilia, West Kaybob Elmworth, West Kaybob Kakwa
GORR:	Kaybob, West Kaybob and Simonette

	The Schedule of Revenues, Royalties, and Operating Expenses includes only those revenues and operating expenses which are directly related to the properties and does not include any expenses related to exploration, development, general and administrative costs, interest, and income taxes or any provision for depletion, depreciation, amortization, site restoration and abandonment costs.
2.	Significant Accounting Policies
	Revenue (includes incidental fee income)
	Revenue amounts are calculated by multiplying the sales volume by a deemed price realization for each product as defined below:

Crude and condensate:	Established posted prices less transportation and quality adjustments.
Gas:	Either aggregator contract or average pool price across the entire marketing portfolio less transportation and related costs.
Natural Gas Liquids:	Established posted prices by component less transportation and fractionation costs.

Operating expenses

Operating expenses include property and mineral taxes and licenses as well as all costs related to lifting, field gathering and transporting of products.

Excluded from operating expenses is own use fuel and Central Alberta Midstream gas processing costs. These costs do not necessarily reflect an industry rate.

B-4

Royalties

Royalties are recorded at the time the product is produced. Royalties are calculated in accordance with the applicable regulations and / or the terms of individual royalty agreements.

B-5

April 2, 2004

Auditors’ Report

To the Management of
Chevron Canada Resources

At the request of Chevron Canada Resources, we have audited the schedule of revenues, royalties and operating expenses for the year ended December 31, 2003 for the Fort Liard properties. This financial information is the responsibility of management. Our responsibility is to express an opinion on this financial information based on our audits.

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

In our opinion, the schedule of revenues, royalties and operating expenses presents fairly, in all material respects, the revenues, royalties and operating expenses for the Fort Liard properties for the year ended December 31, 2003 in accordance with the basis of accounting disclosed in the notes.

“PricewaterhouseCoopers LLP”

Chartered Accountants

Calgary, Alberta

B-6

Chevron Canada Resources

Fort Liard Properties

Schedule of Revenues, Royalties and Operating Expenses
(in thousands of Canadian dollars)

				Three Months Ended
	Year Ended December 31			March 31
	2003			2004			2003
				(unaudited)
Revenues	$	34,851		$	6,870		$	9,438
Royalties		(4,407	)		(1,148	)		(1,312	)
		30,444			5,722			8,126
Operating Expenses		(8,347	)		(1,801	)		(2,187	)
Excess of Revenue Over Operating Expenses		22,097			3,921			5,939

See accompanying notes to schedule of Revenues, Royalties, and Operating Expenses for the Properties.

B-7

Chevron Canada Resources

Fort Liard Properties

Notes to Schedule of Revenues, Royalties and Operating Expenses
Year ended December 31, 2003

1.	Basis of Presentation
	The Schedule of Revenues, Royalties, and Operating Expenses includes the operating results relating to Chevron Canada Resource’s interest in the following properties, which are collectively referred to as the Fort Liard properties:

Operated:	Fort Liard PL9
Non operated:	Fort Liard PL11

	The Schedule of Revenues, Royalties, and Operating Expenses includes only those revenues and operating expenses which are directly related to the properties and does not include any expenses related to exploration, development, general and administrative costs, interest, and income taxes or any provision for depletion, depreciation, amortization, site restoration and abandonment costs.
2.	Significant Accounting Policies
	Revenue (including incidental fee income)
	Revenue amounts are calculated by multiplying the sales volume by a deemed price realization for the product as defined below:

Gas: either aggregator contract or average pool price across the entire marketing portfolio less transportation and related costs.

Operating expenses

Operating expenses include property and mineral taxes and licenses as well as all costs related to lifting, field gathering and transportation, and processing of products. Own use fuel is excluded from operating expenses.

Royalties

Royalties are recorded at the time the product is produced. Royalties are calculated in accordance with the applicable regulations and / or the terms of individual royalty agreements.

B-8

APPENDIX C

COMPILATION REPORT OF ERNST & YOUNG LLP AND
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

COMPILATION REPORT
ON PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

To the Board of Directors of Paramount Resources Ltd.

We have read the accompanying unaudited pro forma consolidated balance sheet of Paramount Resources Ltd. (“the Company”) as at March 31, 2004 and unaudited pro forma consolidated statements of earnings for the three months then ended and for the year ended December 31, 2003, and have performed the following procedures.

1.	Compared the figures in the columns captioned “Paramount Resources Ltd.” to the unaudited interim consolidated financial statements of the Company as at March 31, 2004 and for the three months then ended, and compared the figures in the column captioned “Paramount Resources Ltd. as Previously Reported” to the audited consolidated financial statements of the Company for the year ended December 31, 2003, as appropriate, and found them to be in agreement.
2.	Compared the figures in the columns captioned “Proposed Acquisition” to the unaudited schedules of revenues, royalties and operating expenses for the Kaybob properties and to the schedules of revenues, royalties and operating expenses for the Fort Liard properties, for the three months ended March 31, 2004 or the audited schedules of revenues, royalties and operating expenses for the assets to be acquired in the Kaybob area in central Alberta and to the schedules of revenues, royalties and operating expenses for the assets to be acquired in the Fort Liard area in the Northwest Territories and northeast British Columbia for the year ended December 31, 2003, as appropriate, adjusted for the individual working interest ownership percentage to be acquired by the Company, and found them to be in agreement.
3.	Compared the figures in the columns captioned “Trust Transaction” to the Company’s accounting records and found them to be in agreement.
4.	Compared the figures in the column captioned “Effect of Recent Accounting Pronouncement” to the Company’s accounting records and found them to be in agreement.
5.	Made enquiries of certain officials of the Company who have responsibility for financial and accounting matters about:

C-1

(a)	the basis for determination of the pro forma adjustments; and
(b)	whether the pro forma consolidated financial statements comply as to form in all material respects with the applicable regulatory requirements.
The officials:
(a)	described to us the basis for determination of the pro forma adjustments; and
(b)	stated that the pro forma statements comply as to form in all material respects with the applicable regulatory requirements.

6.

Read the notes to the unaudited pro forma consolidated financial statements, and found them to be consistent with the basis described to us for determination of the pro forma adjustments.

7.

Recalculated the application of the pro forma adjustments to the aggregate of the amounts in the columns captioned “Paramount Resources Ltd.”, “Effect of Recent Accounting Pronouncement”, “Proposed Acquisition” and “Trust Transaction” as at March 31, 2004 and for the three months then ended, and for the year ended December 31, 2003, as appropriate, and found the amounts in the columns captioned “Paramount Resources Ltd. Restated” and “Pro forma consolidated” to be arithmetically correct.

A pro forma financial statement is based on management assumptions and adjustments which are inherently subjective. The foregoing procedures are substantially less than either an audit or a review, the objective of which is the expression of assurance with respect to management’s assumptions, the pro forma adjustments, and the application of the adjustments to the historical financial information. Accordingly, we express no such assurance. The foregoing procedures would not necessarily reveal matters of significance to the pro forma financial statements, and we therefore make no representation about the sufficiency of the procedures for the purposes of a reader of such statements.

Calgary, Canada
June 17, 2004 /s/ Ernst & Young LLP
Chartered Accountants

C-2

COMMENTS FOR UNITED STATES READERS ON DIFFERENCES BETWEEN
CANADIAN AND UNITED STATES REPORTING STANDARDS

The above report, provided solely pursuant to Canadian requirements, is expressed in accordance with standards of reporting generally accepted in Canada. United States standards do not provide for the issuance of such a report on the compilation of pro forma financial statements. To report in conformity with United States standards on the pro forma adjustments and their application to the pro forma financial statements would require an examination or review which would be substantially greater in scope than the procedures contemplated in the compilation report. Consequently, under United States standards, we would be unable to issue such a compilation report on the accompanying unaudited pro forma consolidated financial statements.

Calgary, Canada
June 17, 2004 /s/ Ernst & Young LLP
Chartered Accountants

C-3

Paramount Resources Ltd.
Pro Forma Consolidated Balance Sheet
(Unaudited) As at March 31, 2004
(in thousands of dollars, except per share amounts)

	Paramount			Proposed			Pro Forma
	Resources Ltd.			Acquisition		Note	Consolidated
Assets
Current assets
Short-term investments	$	17,652		$	—		$	17,652
Accounts receivable		82,434			—			82,434
Financial instruments		4,095			—			4,095
Prepaid expenses		2,298			—			2,298
		106,479			—			106,479
Property, plant and equipment
Property, plant and equipment, at cost		1,557,191			215,847	2(a)		1,773,038
Accumulated depletion and depreciation		(457,075	)		—			(457,075	)
		1,100,116			215,847			1,315,963
Goodwill		31,621			—			31,621
Other assets		6,943			3,000	2(a)		9,943
	$	1,245,159		$	218,847		$	1,464,006
Liabilities
Current liabilities
Accounts payable and accrued liabilities	$	128,672		$	3,000	2(a)	$	131,672
Financial instruments		14,300			—			14,300
Current portion of long-term debt		1,468			—			1,468
		144,440			3,000			147,440
Long-term debt		344,930			189,000	2(a)		533,930
Asset retirement obligations		65,417			26,847	2(a)		92,264
Future income taxes		199,471			—			199,471
		609,818			215,847			825,665
Shareholders’ Equity
Share capital		197,702			—			197,702
Contributed surplus		1,333			—			1,333
Retained earnings		291,866			—			291,866
		490,901			—			490,901
	$	1,245,159		$	218,847		$	1,464,006

See accompanying notes to the unaudited interim pro forma consolidated financial statements.

C-4

Paramount Resources Ltd.
Pro Forma Consolidated Statement of Earnings
(Unaudited) For the three month period ended March 31, 2004
(in thousands of dollars, except per share amounts)

	Paramount			Proposed				Pro Forma
	Resources Ltd.			Acquisition			Note	Consolidated
Revenue
Petroleum and natural gas sales	$	105,504		$	30,435		2(a)(i)	$	135,939
Loss on financial instruments		(6,462	)		—				(6,462	)
Royalties (net of ARTC)		(20,935	)		(7,789	)	2(a)(i)		(28,724	)
Other income		1,072			—				1,072
		79,179			22,646				101,825
Expenses
Operating		18,487			5,397		2(a)(i)		23,884
Interest		4,338			2,473		2(a)(iv)		6,811
General and administrative		5,840			—				5,840
Lease rentals		1,234			—				1,234
Geological and geophysical		3,992			—				3,992
Dry hole costs		3,015			—				3,015
Gain on sales of property and equipment		(445	)		—				(445	)
Accretion of asset retirement obligations		1,246			529		2(a)(ii)		1,775
Depletion and depreciation		42,140			10,460		2(a)(iii)		52,600
Unrealized foreign exchange loss on US debt		2,590			—				2,590
		82,437			18,859				101,296
(Loss) earnings before taxes		(3,258	)		3,787				529
Income and other taxes
Large corporations tax and other		776			98		2(a)(v)		874
Future income tax (recovery) expense		(7,213	)		1,922		2(a)(vi)		(5,291	)
		(6,437	)		2,020				(4,417	)
Net earnings for the period	$	3,179		$	1,767			$	4,946
Net earnings per common share
Basic	$	0.05						$	0.08
Diluted	$	0.05						$	0.08
Weighted average common shares outstanding (thousands of shares)
Basic		59,560							59,560
Diluted		60,209							60,209

See accompanying notes to the unaudited pro forma consolidated financial statements.

C-5

Paramount Resources Ltd.
Pro Forma Consolidated Statement of Earnings
(Unaudited) For the year ended December 31, 2003
(in thousands of dollars, except per share amounts)

	Paramount
	Resources			Effect			Paramount
	Ltd. As			of Recent			Resources
	Previously			Accounting			Ltd.			Proposed				Trust				Pro Forma
	Reported			Pronouncement			Restated			Acquisition			Note	Transaction			Note	Consolidated
				(Note 3)
Revenue
Petroleum and natural gas sales	$	434,059		$	—		$	434,059		$	139,181		2(a)(i)	$	(33,725	)	2(b)(iii)	$	539,515
Commodity hedging loss		(53,204	)		—			(53,204	)		—				5,341		2(b)(vi)		(47,863	)
Royalties (net of ARTC)		(82,512	)		—			(82,512	)		(31,903	)	2(a)(i)		2,217		2(b)(iii)		(112,198	)
Loss on sale of investments		(1,020	)		—			(1,020	)		—				—				(1,020	)
Other income		2,012			—			2,012			—				—				2,012
		299,335			—			299,335			107,278				(26,167	)			380,446
Expenses
Operating		81,193			—			81,193			22,331		2(a)(i)		(5,158	)	2(b)(iii)		98,366
Interest		19,917			—			19,917			9,893		2(a)(iv)		(2,586	)	2(b)(i)		27,224
General and administrative		19,898			—			19,898			—				(255	)	2(b)(ii)		19,643
Bad debt expense		5,977			—			5,977			—				—				5,977
Lease rentals		3,574			—			3,574			—				—				3,574
Geological and geophysical		8,450			—			8,450			—				—				8,450
Dry hole costs		36,600			—			36,600			—				—				36,600
Loss on sales of property and equipment		3,660			—			3,660			—				—				3,660
Provision for future site restoration and abandonment costs		4,462			(418	)		4,044			2,114		2(a)(ii)		(258	)	2(b)(iv)		5,900
Depletion and depreciation		163,413			2,889			166,302			35,821		2(a)(iii)		(5,024	)	2(b)(iv)		197,099
Write down of petroleum and natural gas properties		10,418			—			10,418			—				—				10,418
Unrealized foreign exchange gain on US debt		(1,566	)		—			(1,566	)		—				—				(1,566	)
		355,996			2,471			358,467			70,159				(13,281	)			415,345
(Loss) earnings before taxes		(56,661	)		(2,471	)		(59,132	)		37,119				(12,886	)			(34,899	)
Income and other taxes
Large corporations tax and other		2,875			—			2,875			467		2(a)(v)		—				3,342
Future income tax (recovery) expense		(62,169	)		(1,031	)		(63,200	)		16,058		2(a)(vi)		(4,293	)	2(b)(v)		(51,435	)
		(59,294	)		(1,031	)		(60,325	)		16,525				(4,293	)			(48,093	)
Net earnings (loss) for the year	$	2,633		$	(1,440	)	$	1,193		$	20,594			$	(8,593	)		$	13,194
Net earnings per common share
Basic	$	0.04		$	(0.02	)	$	0.02										$	0.22
Diluted	$	0.04		$	(0.02	)	$	0.02										$	0.22
Weighted average common shares outstanding (thousands of shares)
Basic		60,098						60,098											60,098
Diluted		60,472						60,472											60,472

See accompanying notes to the unaudited pro forma consolidated financial statements.

C-6

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

1.	Basis of Presentation
	The accompanying unaudited pro forma consolidated balance sheet and unaudited pro forma consolidated statements of earnings of Paramount Resources Ltd. (“Paramount” or the “Company”) have been prepared for inclusion in this prospectus and US registration statement (collectively the “Prospectus”) to reflect both the acquisition of certain oil and natural gas properties in Western Canada and Northwest Territories (the “Proposed Acquisition”), as described in note 2(a), and the disposition of assets to Paramount Energy Trust (the “Trust”), as described in note 2(b) (the “Trust Transaction”).
	The unaudited pro forma consolidated balance sheet and unaudited pro forma consolidated statements of earnings have been prepared by management based upon information derived from the audited consolidated financial statements of Paramount for the year ended December 31, 2003, the unaudited consolidated financial statements of Paramount as at and for the three month period ended March 31, 2004, the unaudited schedules of revenues, royalties and operating expenses for the Kaybob properties and the unaudited schedules of revenues, royalties and operating expenses for the Fort Liard properties for the three months ended March 31, 2004, and the audited schedules of revenues, royalties and operating expenses for the Kaybob properties and the audited schedules of revenues, royalties and operating expenses for the Fort Liard properties for the year ended December 31, 2003. In the opinion of management of Paramount, the unaudited pro forma consolidated balance sheet and unaudited pro- forma consolidated statements of earnings have been prepared in accordance with Canadian generally accepted accounting principles (“Canadian GAAP”) and include all adjustments necessary for the fair presentation of the transactions described in notes 2 and 3. The unaudited pro forma consolidated statements of earnings for the three month period ended March 31, 2004 and the year ended December 31, 2003 give effect to the Proposed Acquisition and the Trust Transaction as if they had taken place on January 1, 2003. The unaudited pro forma consolidated balance sheet as at March 31, 2004 gives effect to the Proposed Acquisition as if it had taken place on March 31, 2004.
	Accounting policies used in the preparation of the unaudited pro forma consolidated balance sheet and the unaudited pro forma consolidated statements of earnings are consistent with those used in the historical financial statements of Paramount except as described in note 3. Accordingly, they should be read in conjunction with Paramount’s unaudited consolidated financial statements as at and for the three months ended March 31, 2004 and its audited consolidated financial statements as at and for the year ended December 31, 2003.
	The unaudited pro forma consolidated balance sheet and the unaudited pro forma consolidated statements of earnings may not be indicative of the results of the operations that would have occurred if the events reflected therein had been in effect on the dates indicated or of the results that may be obtained in the future.
2.	Pro Forma Adjustments and Assumptions

(a)

Proposed Acquisition

On May 25, 2004, Paramount announced that it had entered into an agreement to complete the Proposed Acquisition for $189 million, subject to adjustments. The acquisition is expected to be completed on or about June 30, 2004. The Company has arranged for a $180 million non-revolving bridge financing with a Canadian chartered bank. The bridge financing and the Company’s existing credit facility will be used to finance the Proposed Acquisition of $189 million. $3.0 million of financing charges related to the bridge financing have been capitalized to other assets and will be amortized over 5 years.

C-7

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

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

Property, plant, and equipment	$	215,847
Less: Asset retirement obligation		26,847
	$	189,000

The unaudited pro forma consolidated statements of earnings for the three months ended March 31, 2004 and the year ended December 31, 2003, give effect to the Proposed Acquisition and take into account the following adjustments:

(i) Revenues, royalties and operating expenses that relate to the oil and natural gas properties being acquired have been added for the three month period ended March 31, 2004 and the year ended December 31, 2003. These amounts have been determined by applying the working interest being acquired by the Company in the Proposed Acquisition to the relevant schedules of revenue, royalties and operating expenses for the Kaybob and Fort Liard properties prepared by Chevron Canada Limited and Chevron Canada Reserves as follows:

Three Months Ended March 31, 2004
(in thousands of dollars)

													Paramount’s
	Chevron			Paramount’s									Net Share of
	Kaybob			Net Share			Chevron			Fee Income			Kaybob and
	(Gross)			of Kaybob			Fort Liard			Reclass			Fort Liard
Revenues	$	38,782		$	24,285		$	6,870		$	(720	)	$	30,435
Royalties		(11,002	)		(6,641	)		(1,148	)					(7,789	)
		27,780			17,644			5,722			(720	)		22,646
Operating expenses		(6,050	)		(4,316	)		(1,801	)		720			(5,397	)
Excess of revenues over operating expenses	$	21,730		$	13,328		$	3,921		$	—		$	17,249

Year Ended December 31, 2003
(in thousands of dollars)

													Paramount’s
	Chevron			Paramount’s									Net Share of
	Kaybob			Net Share			Chevron			Fee Income			Kaybob and
	(Gross)			of Kaybob			Fort Liard			Reclass			Fort Liard
Revenues	$	162,391		$	106,914		$	34,851		$	(2,584	)	$	139,181
Royalties		(44,483	)		(27,496	)		(4,407	)					(31,903	)
		117,908			79,418			30,444			(2,584	)		107,278
Operating expenses		(23,928	)		(16,568	)		(8,347	)		2,584			(22,331	)
Excess of revenues over operating expenses	$	93,980		$	62,850		$	22,097		$	—		$	84,947

C-8

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

(ii)	Asset retirement obligations assumed as a result of the Proposed Acquisition, have resulted in accretion of asset retirement obligations increasing by $0.5 million and $2.1 million for the three month period ended March 31, 2004 and the year ended December 31, 2003, respectively.
(iii)	For the three months ended March 31, 2004 and the year ended December 31, 2003, depletion and depreciation expense has been increased by $10.5 million and $35.8 million, respectively, to reflect the pro forma increase in the carrying value of property, plant and equipment of $215.8 million as a result of the Proposed Acquisition.
(iv)	Interest expense has been increased by $2.5 million and $9.9 million for the three month period ended March 31, 2004 and the year ended December 31, 2003, respectively, as a result of the interest on $189 million increase in Paramount’s debt to fund the Proposed Acquisition and amortization of $3.0 million of other assets. Interest has been recorded at 5.0% per annum on the $180 million bridge financing and 3.25% per annum on the $9 million increase in the Company’s existing credit facility.
(v)	Large corporations tax has been increased by $0.1 million and $0.5 million for the three month period ended March 31, 2004 and the year ended December 31, 2003, respectively, as a result of the increase in Paramount’s long-term debt.
(vi)	Future income tax recovery has decreased by $1.9 million and $16.1 million for the three months ended March 31, 2004 and the year ended December 31, 2003, respectively, to reflect the tax effect of the pro forma adjustments described above.

(b)	Trust Transaction
	During 2003, Paramount completed the formation and restructuring of the Trust through the following transactions:

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

• On February 3, 2003, Paramount declared a dividend-in-kind of $51 million, consisting of an aggregate of 9,907,767 units of the Trust. The dividend was paid to all holders of Paramount common             shares of record on the close of business on February 11, 2003. The dividend was declared after the Trust received all regulatory clearances with respect to its final prospectus and registration statement in the United States. The final prospectus and registration statement qualified and registered (i) the Dividend Trust Units, (ii) rights to purchase further Trust Units, and (iii) the Trust Units issuable upon exercise of the Rights.

• 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.

The unaudited pro forma consolidated statement of earnings for the year ended December 31, 2003 gives effect to the Trust Transaction and takes into account the following adjustments:

C-9

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

(i)	Decrease in interest expense of $2.6 million due to the assumed reduction in Paramount’s debt of $250 million resulting from the cash consideration received. Interest has been recorded at 11.5% per annum on Paramount’s bridge facility of $61.9 million and 6% per annum on the decrease in Paramount’s production facility of $188.1 million.
(ii)	General and administrative expenses have been decreased by $0.3 million as a result of the disposition of assets to the Trust. General and administrative expenses were allocated to the Trust based on the proportion of Paramount employees that were associated with the Trust assets.
(iii)	Revenues, royalties and operating expenses that related specifically to the Trust assets have been removed as follows:

	Year ended
	December 31,
	2003
Petroleum and natural gas sales	$	33,725
Royalties (net of ARTC)	$	2,217
Operating expenses	$	5,158

(iv)	The provisions for depletion and depreciation, and accretion of asset retirement obligations for the year ended December 31, 2003 have been reduced by $5.0 million and $0.3 million, respectively, due to lower production levels as a result of the disposition of the Trust assets. The reduction was determined based on proportionate oil and gas production levels of the Trust assets as compared to the remainder of Paramount’s oil and gas assets.
(v)	Future income tax has been adjusted to account for the Trust transaction. For the year ended December 31, 2003, the increase in future income tax recovery was $4.3 million and the reduction in large corporations tax and other tax expense was $nil.
(vi)	Commodity hedging losses have been allocated to the Trust based on proportionate oil and gas revenues for the Trust assets as compared to oil and gas revenues for the remainder of Paramount’s assets. For the year ended December 31, 2003, the commodity hedging losses allocated to the Trust were $5.3 million.

3.

Effect of recent accounting pronouncements

On January 1, 2004, Paramount retroactively adopted, with restatement, the Canadian Institute of Chartered Accountants, (“CICA”) recommendations on Asset Retirement Obligations, which requires liability recognition for fair value of retirement obligations associated with long-lived assets. As a result of the retroactive adoption of this recommendation, the following adjustments have been applied to Paramount’s unaudited pro forma consolidated statement of earnings for the years ended December 31, 2003 and 2002: Paramount’s accretion of asset retirement obligations has decreased by $0.4 million and $1.1 million, respectively; depletion and depreciation has increased by $2.9 million and $4.6 million, respectively; and future income tax recovery has increased by $1.0 million and $2.4 million, respectively.

C-10

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

4.	Reconciliation of pro forma financial statements to United States generally accepted accounting principles
	The application of United States generally accepted accounting principles (“US GAAP”) would have the following effects on Paramount’s unaudited pro forma consolidated net earnings:

	Three month
	period ending			Year ended
	March 31, 2004			December 31, 2003
Pro forma net earnings for the period	$	4,946		$	13,194
Adjustments, net of tax
Forward foreign exchange contracts and other financial instruments (a)		—			3,411
Impairments and related change in depletion and depreciation (c)		1,088			6,762
Short-term investments (d)		112			428
General and administrative (f)		(101	)		1,049
Earnings from discontinued operations (g)		—			(8,593	)
Earnings before discontinued operations and change in accounting policy for the period — US GAAP	$	6,045		$	16,251
Earnings from discontinued operations (g)		—			8,593
Change in accounting policy — asset retirement obligations (h)		—			(4,127	)
Net earnings for the period — US GAAP	$	6,045		$	20,717
Net earnings before discontinued operations and change in accounting policy per common share — US GAAP
Basic	$	0.10		$	0.27
Diluted	$	0.10		$	0.27
Net earnings per common share — US GAAP
Basic	$	0.10		$	0.34
Diluted	$	0.10		$	0.34

C-11

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

The application of US GAAP would have the following effect on the unaudited pro forma consolidated balance sheet at March 31, 2004:

	Canadian GAAP		US GAAP
Assets
Short-term investments (d)	$	17,652	$	18,552
Property, plant and equipment (c)		1,315,963		1,213,063
Liabilities
Financial instruments (a)		14,300		12,632
Future income taxes (c)(d)(f)		199,471		161,338
Shareholder’s Equity
Contributed surplus (f)		—		101
Retained earnings(c)(d)(f)	$	291,866	$	230,273

a)	Forward foreign exchange contracts and other financial instruments
	Prior to January 1, 2004, Paramount had designated, for Canadian GAAP purposes, its derivative financial instruments as hedges of anticipated revenue and expenses. In accordance with Canadian GAAP, payments or receipts on these contracts were recognized in income concurrently with the hedged transaction. Accordingly, the fair value of contracts deemed to be hedges was not previously reflected in the statements of earnings. As disclosed in Note 2 of the unaudited interim consolidated financial statements as at and for the three months ended March 31, 2004, effective January 1, 2004, the Company has elected not to designate any of its financial instruments as hedges for Canadian GAAP purposes thus eliminating a US GAAP/Canadian GAAP difference in future periods.
	For US purposes, the Company has adopted Statement of Financial Accounting Standards (“SFAS”) No. 133, as amended, Accounting for Derivative Instruments and Hedging Activities. With the adoption of this standard, all derivative instruments are recognized on the consolidated balance sheet at fair value. The statement requires that changes in the derivative instrument’s fair value be recognized currently in earnings unless specific hedge accounting criteria are met.
	Management has not designated any of the currently held financial instruments as hedges for US GAAP purposes and accordingly, these derivatives have been recognized on the pro forma consolidated balance sheet at fair value with the change in their fair value recognized in earnings.
	Under US GAAP for the three month period ending March 31, 2004, the deferred financial instrument asset of $3.3 million and the deferred financial instrument liability of $1.8 million described in note 2 of the unaudited interim consolidated financial statements as at March 31, 2004 and for the three months then ended would not be recorded for US GAAP purposes. For the year ended December 31, 2003, additional income of $5.7 million (net of tax — $3.4 million) would have been recorded for US GAAP purposes.
b)	Future income taxes
	The Canadian liability method of accounting for income taxes is similar to the provisions of US SFAS No. 109 “Accounting for Income Taxes”, which requires the recognition of future tax assets

C-12

Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

	and liabilities for the expected future tax consequences of events that have been recognized in Paramount’s pro forma financial statements or tax returns. Pursuant to US GAAP, enacted tax rates are used to calculate future taxes, whereas Canadian GAAP uses substantively enacted rates. For the three month period ending March 31, 2004 and the year ended December 31, 2003, this difference did not impact Paramount’s financial position or results of operations.
c)	Impairments
	Under both US and Canadian GAAP, property, plant and equipment must be assessed for potential impairments. Under US GAAP, if the sum of the expected future cash flows (undiscounted and without interest charges) is less than the carrying amount of the asset, then an impairment loss (the amount by which the carrying amount of the asset exceeds the fair value of the asset) should be recognized. Fair value is calculated as the present value of estimated expected future cash flows. Prior to January 1, 2004, under Canadian GAAP, the impairment loss was the difference between the carrying value of the asset and its net recoverable amount (undiscounted). Effective January 1, 2004, the CICA implemented a new pronouncement on impairment of long-lived assets which eliminated this US/Canadian GAAP difference going forward. For the three month period ending March 31, 2004, and the year ended December 31, 2003, no impairment charge would be recorded and a reduction in depletion and depreciation expense of $1.8 million (net of tax — $1.1 million) and $11.3 million (net of tax — $6.8 million), respectively, would be recorded due to impairment charges recorded in fiscal 2002 and 2001 under US GAAP. The resulting differences in recorded carrying values of impaired assets result in further differences in depletion and depreciation expense in subsequent periods.
d)	Short-term investments
	Under US GAAP, equity securities that are bought and sold in the short-term are classified as trading securities. Unrealized holding gains and losses related to trading securities are included in earnings as incurred. Under Canadian GAAP , these gains and losses are not recognized in earnings until the security is sold. As at March 31, 2004 and December 31, 2003, the Company had unrealized holding gains of $0.9 million (net of tax — $0.5 million) and $0.7 million (net of tax — $0.4 million), respectively. The net increase of $0.2 million (net of tax — $0.1 million) has been recorded for US GAAP purposes for the three months ended March 31, 2004.
e)	Other comprehensive income
	Under US GAAP, certain items such as the unrealized gain or loss on derivative instrument contracts designated and effective as cash flow hedges are included in other comprehensive income. In these unaudited pro forma consolidated financial statements, there are no comprehensive income items other than net earnings.
f)	Stock-based compensation
	The Company has granted stock options to selected employees, directors and officers. For US GAAP purposes, SFAS 123, “Accounting for Stock-Based Compensation”, requires that an enterprise recognize, or at its option, disclose the impact of the fair value of stock options and other forms of stock-based compensation cost.

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Notes to the Pro Forma Consolidated Financial Statements
Unaudited
(all tabular amounts expressed in thousands of dollars unless otherwise noted, except per share amounts)

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

	Three month
	period ending		Year ended
	March 31, 2004		December 31, 2003
Net earnings for the period — US GAAP	$	6,045	$	20,717
Stock-based compensation determined under the fair value based method for all awards, net of related tax effects		101		(1,049	)
Pro forma net earnings — US GAAP		6,146		19,668
Net earnings per common share
Basic
As reported		0.10		0.34
Pro forma		0.10		0.34
Diluted
As reported		0.10		0.33
Pro forma		0.10		0.33

	Under APB Opinion 25, the re-pricing of outstanding stock options under a fixed price stock option plan results in these options being accounted for as variable price options from the date of the modification until they are exercised, forfeited or expire. For the three months ended March 31, 2004, an additional $0.7 million (year ended December 31, 2003 — $0.2 million) would have been recorded as general and administrative expense related to the re-pricing of outstanding stock options and for the three months ended March 31, 2004, $0.6 million (year ended December 31, 2003 — $1.2 million) of general and administrative expenses related to stock options under Canadian GAAP would be reversed as the Company has chosen not to account for its options using the fair value method under SFAS 123.
g)	Discontinued operations
	Under US GAAP, the Trust Transaction as described in note 2(b) would be accounted for as discontinued operations as the applicable criteria set out in SFAS 144 “Accounting for the Impairment or Disposal of Long-Lived Assets” had been met. Accordingly, net earnings from discontinued operations would have totalled $nil for the three months ended March 31, 2004 and $12.9 million (net of tax — $8.6 million), or $0.14 per basic and diluted common share for the year ended December 31, 2003.
h)	Asset retirement obligations
	The Company has retroactively adopted, with restatement, the CICA recommendations on Asset Retirement Obligations, see note 2 of the unaudited interim consolidated financial statements as at and for the three months ended March 31, 2004. For US GAAP purposes, the Company has adopted SFAS No. 143, Accounting for Asset Retirement Obligations effective January 1, 2003. For US GAAP, the cumulative impact upon adoption of SFAS No. 143 for the year ended December 31, 2003, is a $6.8 million (net of tax — $4.1 million) charge to earnings or $0.07 per basic and diluted common share. For Canadian GAAP purposes, upon adoption on January 1, 2004, the retroactive effect of this pronouncement on prior years was reflected in opening retained earnings for the earliest period presented.

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