Financial and Operating Results For the Three Months and Six Months Ended June 30, 2006

EX-99.1 2 ex99_1.htm FINANCIAL AND OPERATING RESULTS FOR THE THREE MONTHS AND SIX MONTHS ENDED JUNE 30, 2006 Financial and Operating Results For the Three Months and Six Months Ended June 30, 2006

PARAMOUNT RESOURCES LTD.

Calgary, Alberta

August 7, 2006

NEWS RELEASE:

PARAMOUNT RESOURCES LTD.

Financial and Operating Results for the Three Months and Six Months Ended June 30, 2006

CALGARY, ALBERTA - Paramount Resources Ltd. (“Paramount” or the “Company”) is pleased to announce its financial and operating results for the three months and six months ended June 30, 2006.

Financial and Operating Highlights
(thousands of dollars except per share amounts and where stated otherwise)

	Three Months Ended
	June 30, 2006			March 31, 2006			% Change
FINANCIAL

Petroleum and natural gas sales		73,681			87,909			(16	)
Funds flow from operations⁽¹⁾		65,835			42,412			55
Per share - diluted		0.95			0.63			51
Net earnings⁽²⁾		111,874			7,764			1,341
Per share - diluted		1.61			0.12			1,242
Capital expenditures, excluding acquisitions
Total		94,827			168,084			(44	)
Oil Sands Properties⁽³⁾		--			33,447			(100	)
Excluding Oil Sands Properties		94,827			134,637			(30	)
Petroleum and natural gas property acquisitions
Total		10,535			24,523			(57	)
Oil Sands Properties⁽³⁾		--			23,900			(100	)
Excluding Oil Sands Properties		10,535			623			1,591
Market value of long-term investments ⁽⁴⁾		694,240			293,060			137
Total assets		1,380,756			1,272,677			8
Net debt ⁽⁵⁾		499,640			486,289			3
Common shares outstanding (thousands)		68,005			67,934			--
Market capitalization ⁽⁶⁾		2,448,165			2,829,463			(13	)
OPERATING
Natural gas sales volumes (MMcf/d)		83.2			82.9			--
Oil and natural gas liquid sales volumes (BBl/d)		3,423			3,339			3
Total sales (Boe/d)		17,297			17,152			1
Gas weighting		80	%		81	%		(1	)
Total wells drilled (gross)		41			213			(81	)
Success rate ⁽⁷⁾		100	%		95	%		5

⁽¹⁾Readers are referred to the advisories concerning forward-looking statements, non-GAAP measures, and barrels of oil equivalent conversions under the heading "Advisories".

⁽²⁾Net earnings for the three months ended June 30, 2006 includes a dilution gain on our investment in North American Oil Sands Corporation ("North American") of $84.6 million, net of tax, and a tax recovery of $17.8 million. At June 30, 2006 Paramount's investment in North American had a market value of approximately $409 million, based on the latest private placement for North American, and a carrying value of approximately $148 million on Paramount's balance sheet.

⁽³⁾During the second quarter of 2006, Paramount vended its interest in certain oil sands properties to North American (the "Oil Sands Properties") in exchange for approximately 50 percent of the then outstanding common shares of North American and cash consideration of $17.5 million. First quarter 2006 capital expenditures, including acquisitions, relating to the Oil Sands Properties totaled $57.3 million (inception-to-date capital expenditures, including acquisitions - $80.9 million).

⁽⁴⁾Based on the period-end closing prices of Trilogy Energy Trust on the Toronto Stock Exchange, latest private placement pricing for North American and book value of the remaining long-term investments.

⁽⁵⁾Net debt is equal to the sum of long-term debt, working capital deficit (surplus) and stock-based compensation liability, excluding the stock-based compensation liability associated with Paramount Options of $50.1 million at June 30, 2006 ($55.9 million at March 31, 2006). See Liquidity and Capital Resources section of Paramount's MD&A.

⁽⁶⁾Based on the period-end closing prices of Paramount Resources Ltd. on the Toronto Stock Exchange.

⁽⁷⁾Success rate excludes oil sands wells.

Significant Events - Q2 2006

We achieved a key strategic milestone with the commencement of unlocking value from Paramount’s oil sands assets by completing a transaction with North American Oil Sands Corporation (“North American”), exchanging Paramount’s 50 percent interest in certain oil sands assets in the Leismer, Corner, Hangingstone and Thornbury areas in Northeast Alberta, for approximately 50 percent of the then outstanding shares of North American. As a result of the transaction with North American, Paramount posted record net earnings of approximately $111.9 million during the second quarter of 2006. Paramount retained the potential to participate in the future upside of the oil sands assets while eliminating the need to directly fund their development costs. Paramount continues to retain its 100 percent interest in oil sands assets in the Surmont area.

Despite wet weather delays and additional third party processing constraints, we were able to bring on over 50 percent of production that was behind pipe at the end of the first quarter of 2006. Approximately 6,500 Boe/d of production remains behind pipe at June 30, 2006. We expect to bring these volumes on production during the third and fourth quarter of 2006, when natural gas prices are typically higher than the summer months.

To date, we have identified over 80 locations to be drilled in North Dakota on predominantly 100 percent working interest lands. The limited supply of drilling rigs has delayed our ability to pursue these opportunities, including the twelve wells planned to be drilled in 2006. To mitigate this business risk and the risk of inflationary drilling costs, we became a 50 percent shareholder of a company in the United States (“Drillco”) to supply drilling services to Paramount. Drillco has entered into contracts for the construction of two drilling rigs, with completion expected near the end of the fourth quarter of 2006. The drilling rigs are expected to be placed into service by the first quarter of 2007.

Review of Operations

The following table summarizes Paramount’s average sales volumes by corporate operating unit (“COU”) for the three months ended June 30, 2006 and March 31, 2006:

Natural Gas Sales (MMcf/d)	Q2 2006		Q1 2006		Change (%)
Kaybob		14.0		13.5		4
Grande Prairie		14.6		15.4		(5	)
Northwest Alberta / Cameron Hills, Northwest Territories		25.6		22.5		14
Northwest Territories / Northeast British Columbia		11.6		12.1		(4	)
Southern		15.1		16.5		(9	)
Northeast Alberta		2.3		2.9		(21	)
Total		83.2		82.9		—

Crude Oil and Natural Gas Liquids Sales (Bbl/d)
Kaybob		511		333		54
Grande Prairie		532		398		34
Northwest Alberta / Cameron Hills, Northwest Territories		979		1,038		(6	)
Northwest Territories / Northeast British Columbia		20		21		(5	)
Southern		1,370		1,544		(11	)
Northeast Alberta		11		5		120
Total		3,423		3,339		3

Total Sales (Boe/d)
Kaybob		2,850		2,581		10
Grande Prairie		2,968		2,960		—
Northwest Alberta / Cameron Hills, Northwest Territories		5,253		4,783		10
Northwest Territories / Northeast British Columbia		1,954		2,034		(4	)
Southern		3,885		4,296		(10	)
Northeast Alberta		387		498		(22	)
Total		17,297		17,152		1

Kaybob

Second quarter 2006 sales volumes for the Kaybob Operating Unit averaged 2,850 Boe/d; comprised of 14.0 MMcf/d of natural gas and 511 Bbl/d of oil and natural gas liquids (“NGLs”). Average sales volumes were up 10 percent from first quarter 2006 average sales volumes of 2,581 Boe/d.

Kaybob’s second quarter capital spending of $32.8 million was focused primarily on drilling, completion and facility work, bringing capital expenditures for the Operating Unit to $91.4 million for the six months ended June 30, 2006. During the second quarter, Paramount participated in the drilling of 3 (0.8 net) wells, all of which were cased for potential gas production and are awaiting pipeline tie ins.

Expansions to the Smoky gas plant and the Musreau gas plant were completed during the second quarter, as planned, allowing additional gas to be brought on production during the quarter. The capacity of the Smoky gas plant was expanded to 100 MMcf/d (10 MMcf/d net). This expansion adds to our available processing capacity in the area which also includes the 25 MMcf/d (12.5 MMcf/d net) Resthaven plant. Paramount has also secured access for up to 25 MMcf/d of capacity at the expanded third party owned Musreau gas plant to process our production from surrounding areas. We expect further volumes will be brought onstream through these plants once gas gathering and lease facility work is completed, and when required regulatory approvals are received to allow for the commingling of natural gas from more than one producing formation.

The Kaybob Operating Unit expects a significant amount of drilling, completion and construction activity for the remainder of the year. We will continue to invest in the gathering systems and processing facilities to secure adequate capacity to process our gas.

Paramount’s strategy for the Kaybob Operating Unit is to continue our focus in areas that offer multi-zone drilling potential and large resource development opportunities. We plan to maintain high working interests in large contiguous land blocks, gas gathering systems and processing plants where possible. We believe that once fully onstream, the production results from the last several months of drilling will show the benefits of exploring in the Deep Basin, where the drilling prospects target multi-zone, large reserve potential assets. With Crown land sale prices at near record levels, our land is a valuable asset. We are actively managing our activities to limit expiries, and developing some of the new pools that have been discovered. We will also continue to monitor the industry’s success on the deeper, higher risk prospects.

Grande Prairie

Second quarter 2006 sales volumes for the Grande Prairie Operating Unit averaged 2,968 Boe/d; comprised of 14.6 MMcf/d of natural gas and 532 Bbl/d of oil and NGLs. Average sales volumes were close to first quarter 2006 average sales volumes of 2,960 Boe/d.

During the second quarter, Paramount drilled 8 (4.4 net) wells in the Grande Prairie area comprised of 5 (3.9 net) gas wells and 3 (0.5 net) oil wells. Gross test rates for new drills were as high as 6 MMcf/d and 3,600 Bbl/d. Other activity included the tie in of 7 (3 net) wells that were drilled from new field discoveries at Crooked Creek and Ante Creek during the latter part of the second quarter, at an aggregate rate of approximately 680 Boe/d (net), offsetting declines on existing properties. Production behind pipe caused by plant capacity restrictions, wet weather issues and regulatory approvals are expected to come on over the next three months. Additional production is anticipated to come on as a result of additional compression being installed.

Grande Prairie’s second quarter 2006 capital spending of $18.9 million was primarily focused on drilling, completions and facilities work. Eleven wells are being completed and are expected to add production volumes in the latter part of the third quarter and during the fourth quarter of 2006.

Paramount plans to drill up to an additional 12 (7.6 net) wells before yearend to follow up on recent successes and pursue new opportunities.

Northwest Alberta / Cameron Hills, Northwest Territories

Second quarter 2006 sales volumes for the Northwest Alberta Operating Unit averaged 5,253 Boe/d; comprised of 25.6 MMcf/d of natural gas and 979 Bbl/d of oil and NGLs. Average sales volumes were up 10 percent from first quarter 2006 average sales volumes of 4,783 Boe/d. Increases in sales volumes during the second quarter were a result of our successful winter drilling and maintenance programs.

Capital expenditures for the second quarter of 2006 totaled $8.3 million and were predominately spent on drilling activities and facilities improvement. Capital expenditures for the remainder of the year will be focused on land and trade seismic purchases in order to finalize plans for our winter drilling program in the first quarter of 2007.

Northwest Territories / Northeast British Columbia

Second quarter 2006 sales volumes for the Northwest Territories / Northeast British Columbia Operating Unit averaged 1,954 Boe; comprised of 11.6 MMcf/d of natural gas and 20 Bbl/d of oil and NGLs. Average sales volumes were down four percent from first quarter 2006 average sales volumes of 2,034 Boe/d. Production gains achieved from the first quarter 2006 activities were more than offset by operational downtime at the Maxhamish facility and the temporary shut-in of the 2K-29 well at West Liard.

Capital expenditures for the second quarter of 2006 totaled $7.3 million. Compression facilities were installed at West Liard allowing the 2K-29 well to resume production in early June 2006. Gas production from this well has been steadily increasing while water production has been declining since the start-up of the compressor subsequent to the second quarter.

A planned 19-day shutdown/turnaround at a third-party operated gas plant in July 2006 was completed as scheduled allowing Paramount to complete well and plant maintenance at all four Paramount producing areas. During the shutdown, a new compressor was also installed at Maxhamish which we expect to optimize field production by lowering gathering system operating pressures. Depending on the results, up to four wells are expected to be drilled at Clarke Lake in the third quarter of 2006 with the potential for tie in before yearend.

Southern

Second quarter 2006 sales volumes for the Southern Operating Unit averaged 3,885 Boe/d; comprised of 15.1 MMcf/d of natural gas and 1,370 Bbl/d of oil and NGLs. Average sales volumes were down 10 percent from first quarter 2006 average sales volumes of 4,296 Boe/d primarily due to a pipeline curtailment at the beginning of the second quarter, casing problems incurred on two oil wells in North Dakota and natural declines.

Capital expenditures for the Southern Operating Unit totaled $15.2 million during the second quarter of 2006 and were focused on drilling both conventional and coal bed methane (“CBM”) wells in the Chain area and re-entry drilling in North Dakota for oil.

In the Chain region, we continue our CBM program which started in 2004. This year we plan to drill 100 (83 net) CBM wells and in the first half of the year have drilled 37 (25 net) CBM wells; 82 (68 net) wells as of August 2, 2006. These wells will be tied into our extensive low pressure gathering system which we began constructing in 2005. This year, we have made some modifications to our plans based on past experience, primarily with all CBM wells being drilled to the base of the Belly River formation. With the new regulations allowing four shallow gas wells per section in southern Alberta, this gives us the flexibility to choose between completing Horseshoe Canyon coals and Belly River sands in each well bore and thus maximize the reserve and production gains. Since 2002, Paramount has increased both conventional and non-conventional production in the Chain region from 600 Boe/d to 1,700 Boe/d. As we proceed with our 2006 program we are enthused at the number of opportunities still to be realized in this region.

In North Dakota, we plan to participate in the drilling of 4 (1.5 net) wells targeting the Birdbear A dolomite in the Beaver Creek field this year. In the second quarter, we operated 1 (net 0.38) re-entry horizontal well targeting the Birdbear A. This well is anticipated to ultimately produce over 250,000 Bbl (gross) of 46 degree API (American Petroleum Institute) crude oil. Over the past year, we have been accumulating acreage on the Bakken and Birdbear trends, and to date have accumulated over 35,000 net acres.

To date, we have identified over 80 locations to be drilled in North Dakota on predominantly 100 percent working interest lands. The limited supply of drilling rigs has delayed our ability to pursue these opportunities, including the twelve wells planned to be drilled in 2006. To mitigate this business risk and the risk of inflationary drilling costs we became a 50 percent shareholder of a company in the United States (“Drillco”) to supply drilling services to Paramount. Drillco has entered into contracts for the construction of two drilling rigs, with completion expected near the end of the fourth quarter of 2006. The drilling rigs are expected to be placed into service by the first quarter of 2007.

Northeast Alberta / Sahtu / Oil Sands

Second quarter 2006 sales volumes for Northeast Alberta averaged 387 Boe/d, a 22 percent decrease from first quarter 2006 average sales volumes of 498 Boe/d. The decline in sales volume was due to unplanned pipeline downtime at Chandler, unscheduled downtime at the Gas Re-Injection & Production Experiment (GRIPE), and a plant turnaround at Kettle River, where GRIPE production is processed for sale.

GRIPE has now been in operation for six months with no sign of nitrogen breakthrough at the gas producing wells. The pilot has achieved 73 percent uptime. These two key indicators of commercial success, gas recovery and reliability, continue to show positive results. Paramount is now studying the next phases of the pilot expansion for implementation either in 2007 or 2008.

In Sahtu, Northwest Territories, Paramount acquired the Great Bear River exploration license (EL 440) with an area of approximately 87,872 hectares for a work commitment of $6.3 million. This land south of Norman Wells lies directly on the Norman Wells oil pipeline and the path of the proposed Mackenzie Valley Pipeline, which is anticipated to facilitate the marketing arrangements for any discoveries on the parcel. Paramount is currently reviewing options for a seismic program in Sahtu at Kelly Lake and Nogha/Colville Lake for the first quarter of 2007.

Paramount has initiated a Front End Engineering Design (FEED) of the Surmont Oil Sands Project. The central pilot plant, named Surmont Cottonwood, is expected to be able to generate steam and re-use water to produce up to 10,000 Bbl/d of bitumen. Paramount plans to complete an oil sands evaluation drilling and seismic program in early 2007 and submit an application for the project to the Alberta Energy Utilities Board in the second quarter of 2007.

Financial

For the second quarter of 2006, Paramount is reporting record net earnings of $111.9 million, $1.61 per share diluted; primarily a result of recognizing a dilution gain on our investment in North American of $84.6 million net of tax and recognizing a future tax asset of $17.8 million.

Funds flow from operations for the second quarter of 2006 totaled $65.8 million, $0.95 per share diluted, $23.4 million higher than first quarter 2006; primarily a result of the termination of financial hedge contracts prior to their maturities during the quarter.

On August 4, 2006, the Company engaged an investment bank to arrange a Term Loan B facility (the “Facility”) in the U.S. market for up to US$150 million to refinance existing indebtedness and for general corporate use. The Facility is expected to have a six year term and there is no scheduled amortization prior to maturity. The Facility will be secured by a pledge of the common shares of North American (the “NAOSC Shares”) currently held by Paramount. It is expected that the Facility will have to be prepaid with 100 percent of the net proceeds received from any sale or other disposition of all or any part of the NAOSC Shares. The interest rate on the Facility will be set upon finalization of the ratings process and completion of the syndication process.

2006 Outlook

Paramount's exit production rate for the second quarter of 2006 was approximately 18,200 Boe/d, with approximately 6,500 Boe/d behind pipe. Despite our successful 2006 drilling program, delays in bringing planned production additions on-stream have resulted in us revising our 2006 outlook.

Paramount now estimates 2006 average annual production to be approximately 19,000 Boe/d and the 2006 exit rate to be approximately 23,000 Boe/d. We expect that our 2006 E&P capital expenditures will be about $370 million excluding land, capital expenditures on oil sands properties disposed to North American, acquisitions and dispositions.

MANAGEMENT'S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (“MD&A”) should be read in conjunction with Paramount’s unaudited Interim Consolidated Financial Statements as at and for the three and six months ended June 30, 2006 and Paramount’s audited Consolidated Financial Statements for the year ended December 31, 2005. The unaudited Interim Consolidated Financial Statements and the audited Consolidated Financial Statements have been prepared in Canadian dollars and in accordance with Canadian generally accepted accounting principles (“GAAP”).

This MD&A contains forward-looking statements, non-GAAP measures, and disclosures of barrels of oil equivalent volumes. Readers are referred to the advisories concerning forward-looking statements, non-GAAP measures, and barrels of oil equivalent conversions contained under the heading “Advisories”.

This MD&A is dated August 7, 2006. Additional information concerning Paramount, including its Annual Information Form, can be found on the SEDAR website at www.sedar.com.

Paramount is an independent Canadian energy company involved in the exploration, development, production, processing, transportation and marketing of petroleum and natural gas. Paramount’s principal properties are located in Alberta, the Northwest Territories and British Columbia in Canada. Paramount also has properties in Saskatchewan and offshore the East Coast in Canada, and in California, Montana and North Dakota in the United States. Management’s strategy is to maintain a balanced portfolio of opportunities to grow reserves and production in Paramount’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.

Business Environment

The table below shows key commodity price benchmarks for the three and six months ended June 30, 2006 and June 30, 2005:

Three Months Ended

Six Months Ended

June 30

2005

2006

2005

2006

Crude Oil

West Texas Intermediate monthly average (US$/Bbl)

53.17

70.70

51.51

67.09

Natural Gas

NYMEX (Henry Hub Close) monthly average

(US$/MMbtu)

6.73

6.79

6.50

7.88

AECO monthly average (Cdn$/GJ)

6.99

5.95

6.67

7.37

Canadian Dollar – US Dollar Exchange Rate

Quarterly and six months average with Company’s banker (Cdn$/US$)

1.2439

1.1224

1.2355

1.1384

Key Operating Results

SECOND QUARTER 2006 vs. FIRST QUARTER 2006

	Q1 2006		Change			Q2 2006
Sales volumes
Natural gas (MMcf/d)		82.9		0.3			83.2
Oil and NGLs (Bbl/d)		3,339		84			3,423
Combined (Boe/d)		17,152		145			17,297

Average prices⁽¹⁾
Natural gas ($/Mcf)		9.39		(2.41	)		6.98
Oil and NGLs ($/Bbl)		59.39		7.40			66.79

			Change in			Change in
($ thousands)	Q1 2006		Price/Cost			Volume		Q2 2006
Revenue⁽¹⁾
Natural gas sales		70,063		(18,001	)		816		52,878
Oil and NGLs sales		17,846		2,224			733		20,803
		87,909		(15,777	)		1,549		73,681

Royalties		16,779		(7,195	)		189		9,773
Operating costs		18,131		200			361		18,692
Transportation costs		3,652		(232	)		67		3,487
Operating Netback		49,347		(8,550	)		932		41,729

⁽¹⁾ Before transportation and financial instruments.

Sales volumes - Natural gas sales volumes for the second quarter remained unchanged with first quarter of 2006 as production increases from Bistcho and Cameron Hills in the Northwest Alberta area offset declines in the Southern area. Paramount continued to experience operational constraints causing delays in bringing on production behind pipe. These constraints included wet weather delays in Southern Alberta and facility constraints in the Northwest Territories and Northeast British Columbia. Paramount was able to offset its natural decline by bringing on sufficient volumes to keep production consistent with the first quarter of 2006. Paramount’s exit production rate at June 30, 2006 was approximately 18,200 Boe/day.

Average Prices - Average realized natural gas sales prices declined by 26 percent since the first quarter of 2006, a result of the cooler than anticipated temperatures during May and June causing reduced demand for natural gas. In addition, natural gas storage levels in North America have stayed above the 5 year average inventory level causing downward pressure on natural gas prices. A heat wave in North America experienced during the beginning of the third quarter of 2006 has caused increased demand for natural gas for power generation, and has resulted in recent increases in natural gas prices in July.

On average, oil and NGL prices increased by 12 percent in the second quarter of 2006, amid growing concerns on political instability in the Middle East, and continued strong demand for gasoline during the summer driving season beginning each May.

Royalties - Royalties expense of $9.8 million was $7.0 million lower in the second quarter as compared to the first quarter of 2006. The decrease is mainly the result of lower average natural gas prices during the second quarter, causing a drop in the Alberta gas reference price. The Alberta gas reference price is used to calculate royalties on

Paramount’s natural gas production in Alberta, which comprises approximately 80 percent of Paramount’s total gas sales. Paramount’s average royalty rate declined to 13 percent of sales revenue in the second quarter as opposed to 19 percent in the previous quarter.

Operating costs - Operating costs for the first and second quarters of 2006 remained relatively unchanged as total production for the two quarters did not change materially. New compressors were added during the second quarter in the Kaybob and Grande Prairie areas, partially offsetting a reduction in operating costs from the first quarter completion of winter maintenance projects.

Transportation Costs - Transportation costs for the second quarter of 2006 were relatively unchanged compared to the first quarter of 2006.

SECOND QUARTER 2005 VS. SECOND QUARTER 2006

	Q2 2005		Change			Q2 2006
Sales volumes
Natural gas (MMcf/d)		97.7		(14.5	)		83.2
Oil and NGLs (Bbl/d)		3,407		16			3,423
Combined (Boe/d)		19,685		(2,388	)		17,297

Average prices⁽¹⁾
Natural gas ($/Mcf)		8.20		(1.22	)		6.98
Oil and NGLs ($/Bbl)		61.16		5.63			66.79

($ thousands)	Q2 2005		Change in Price/Cost			Change in Volume			Q2 2006
Revenue⁽¹⁾
Natural gas sales		72,890		(10,851	)		(9,161	)		52,878
Oil and NGLs sales		18,958		1,748			97			20,803
		91,848		(9,103	)		(9,064	)		73,681

Royalties		9,340		1,782			(1,349	)		9,773
Operating costs		13,700		7,572			(2,580	)		18,692
Transportation costs		5,376		(1,408	)		(481	)		3,487
Operating netback		63,432		(17,049	)		(4,654	)		41,729

⁽¹⁾ Before transportation and financial instruments.

Sales volumes - Natural gas sales volumes for the second quarter declined by 15 percent compared to the second quarter of 2005. The decrease was primarily the result of natural declines at Liard and Liard West, partially offset by new production brought on as a result of Paramount’s Northwest Alberta’s winter drilling and maintenance programs.

Crude oil and natural gas liquids production remained consistent in the second quarter of 2006 as compared to the second quarter of 2005, as Paramount was able to offset its natural decline with new liquids production from Kaybob and Grande Prairie.

Average prices - Natural gas prices before financial instruments declined by 15 percent in the second quarter of 2006 as compared to 2005, consistent with the general decrease in AECO gas prices. On average, oil and natural gas liquids prices increased 9 percent when comparing the second quarter of 2006 to the same quarter in 2005.

Strong demand for gasoline, and increasing concerns over political instability in the Middle East in 2006 contributed to the increase in oil prices.

Royalties - Royalties as a percentage of revenue were higher at 13 percent in the second quarter of 2006 as compared to 10 percent in the second quarter of 2005. Certain properties in the Northwest Territories had low royalty rates in 2005 as they were subject to a minimum royalty before payout.

Operating costs - Upward inflationary pressure continues to impact operating costs as evidenced by the increase in operating costs during the second quarter of 2006 in comparison to the second quarter of 2005. Higher water disposal costs were incurred in the Northwest Territories during 2006 as Paramount encountered greater than anticipated water production. New compressors put into production in the Kaybob and Grande Prairie areas also contributed to higher operating costs during the second quarter of 2006.

Transportation costs - Transportation costs were lower during the second quarter of 2006 following the termination of fixed price transportation contracts that were in place during the second quarter of 2005.

YEAR-TO-DATE JUNE 30, 2006 VS. YEAR-TO-DATE JUNE 30, 2005

Spinout Assets - On April 1, 2005, Paramount completed a reorganization pursuant to a plan of arrangement under the Business Corporations Act (Alberta), resulting in the creation of Trilogy Energy Trust (“Trilogy”) as a new publicly-traded energy trust (the “Spinout”). Through the Trilogy Spinout, certain properties owned by Paramount that were located in the Kaybob and Marten Creek areas of Alberta, and three natural gas plants operated by Paramount became the property of Trilogy (the “Spinout Assets”). The transfer of the Spinout Assets to Trilogy caused decreases in Paramount’s production, revenue, royalties, operating costs and transportation costs.

Paramount’s unaudited Interim Consolidated Financial Statements for the six months ended June 30, 2005 include the results of operations and cash flows of the Spinout Assets for the three months ended March 31, 2005. The following table shows Paramount’s reported results for the six months ended June 30, 2006 and June 30, 2005, separating the results of the Spinout Assets from Paramount’s other properties and assets (“PRL Properties”) for the six months ended June 30, 2005:

Six Months Ended June 30	2005		Spinout			PRL					2006
	Reported		Assets ⁽²⁾			Properties		Change			Reported
Sales volumes
Natural gas (MMcf/d)		150.0		(60.0	)		90.0		(6.9	)		83.1
Oil and NGLs (Bbl/d)		5,654		(2,461	)		3,193		188			3,381
Combined (Boe/d)		30,639		(12,526	)		18,113		(888	)		17,225

Average prices⁽¹⁾
Natural gas ($/Mcf)		7.71		7.46			7.88		0.30			8.18
Oil and NGLs ($/Bbl)		57.79		54.77			60.12		3.03			63.15

Six Months Ended June 30	2005		Spinout			PRL		Change in			Change in			2006
($ thousands)	Reported		Assets ⁽²⁾			Properties		Price/Cost			Volume			Reported
Revenue⁽¹⁾
Natural gas sales		209,223		(81,569	)		127,654		4,860			(9,573	)		122,941
Oil and NGLs sales		59,133		(24,399	)		34,734		1,751			2,164			38,649
		268,356		(105,968	)		162,388		6,611			(7,409	)		161,590

Royalties		44,544		(25,269	)		19,275		8,645			(1,368	)		26,552
Operating costs		41,685		(16,123	)		25,562		13,160			(1,897	)		36,825
Transportation costs		14,541		(4,805	)		9,736		(2,229	)		(368	)		7,139
Operating netback		167,586		(59,771	)		107,815		(12,965	)		(3,776	)		91,074

⁽¹⁾ Before transportation and financial instruments.

⁽²⁾ These values are presented in order to isolate the variance in the reported results relating to the Spinout Assets. The daily sales volumes for the Spinout Assets were computed by dividing total sales volumes from the Spinout Assets for the three months ended March 31, 2005 by 181 days.

Sales volumes - Excluding the impact of the Trilogy Spinout, natural gas sales volumes decreased for the six months ended June 30, 2006 as compared to the same period in 2005. Declines resulting from an increase in water production at properties in the Northwest Territories were partially offset by new natural gas production from the Southern area. Liquids sales volumes increased for the same comparative period from additions in the Kaybob and Grande Prairie areas.

Average prices - Average natural gas prices for the six months ended June 30, 2006 were higher than the average natural prices during the same period in 2005 consistent with changes in market prices for natural gas. Average oil and NGL prices were also higher, consistent with the change in world crude oil prices.

Royalties - After adjusting for the Spinout Assets, royalties as a percentage of petroleum and natural gas sales were higher at 16 percent for the six months ended June 30, 2006 as compared to 12 percent in 2005, mainly as a result of higher average commodity prices for the comparative period. Also, certain properties in the Northwest Territories had low royalty rates in 2005 as they were subject to a minimum royalty before payout.

Operating costs - After adjusting for the Spinout Assets, operating costs were higher in the first half of 2006 as compared to the same quarter of 2005 primarily as a result of industry-wide inflation, and additional operating costs incurred in an attempt to reduce the decline rate for certain properties in the Northwest Territories.

Transportation costs - Transportation costs were lower during the six months ended June 30, 2006 following the termination of fixed price transportation contracts that were in place during the comparable period in 2005.

NETBACKS

	Three Months Ended June 30						Six Months Ended June 30
	2005			2006			2005			2005			2006
								As Reported			PRL Properties⁽²	⁾
Produced gas ($/Mcf)
Revenue⁽¹⁾		7.62			6.55			7.20			7.30			7.73
Royalties		(0.45	)		(0.93	)		(1.23	)		(0.85	)		(1.46	)
Operating costs		(1.10	)		(2.01	)		(1.17	)		(1.25	)		(2.00	)
Operating netback		6.07			3.61			4.80			5.20			4.27

Conventional oil ($/Bbl)
Revenue⁽¹⁾		62.23			64.71			60.39			60.38			61.48
Royalties		(6.82	)		(7.14	)		(9.00	)		(5.76	)		(6.20	)
Operating costs		(14.78	)		(11.19	)		(11.03	)		(11.76	)		(11.20	)
Operating netback		40.63			46.38			40.36			42.86			44.08

Natural gas liquids ($/Bbl)
Revenue⁽¹⁾		55.44			70.96			51.43			58.03			66.23
Royalties		(14.43	)		(14.24	)		(14.64	)		(23.14	)		(12.43	)
Operating costs		(5.89	)		(10.64	)		(7.00	)		(8.33	)		(10.54	)
Operating netback		35.12			46.08			29.79			26.56			43.26

All products ($/Boe)
Revenue⁽¹⁾		48.27			44.59			45.77			46.61			49.54
Royalties		(5.21	)		(6.21	)		(8.03	)		(5.88	)		(8.52	)
Operating costs		(7.65	)		(11.88	)		(7.52	)		(8.12	)		(11.81	)
Operating netback		35.41			26.50			30.22			32.61			29.21

⁽¹⁾ Revenue is presented net of transportation costs and does not include gain / loss on financial instruments.

⁽²⁾ These values are presented in order to isolate the netbacks relating to properties retained by Paramount, and exclude the results of the Spinout Assets for the three months ended March 31, 2005.

	Three Months Ended						Six Months Ended
Funds Flow Netback per Boe	June 30						June 30
($/Boe)	2005			2006			2005			2006
Operating netback	35.41			26.50			30.22			29.21
Realized gain (loss) on		(2.07	)		19.26			1.26			9.42
financial instruments
Realized foreign exchange gain		-			0.29			-			0.23
Gain on sale of investments		0.26			-			0.51			0.40
General and administrative⁽¹⁾		(3.05	)		(6.87	)		(2.45	)		(6.74	)
Interest ⁽²⁾		(3.40	)		(4.45	)		(2.41	)		(4.33	)
Lease rentals		(0.35	)		(0.13	)		(0.29	)		(0.30	)
Asset retirement obligation expenditures		(0.03	)		(0.11	)		(0.04	)		(0.11	)
Distributions from equity investments		4.03			6.21			1.30			6.75
Current and Large Corporations Tax		(1.07	)		1.08			(0.50	)		0.19
Funds flow netback ($/Boe) ⁽³⁾		29.73			41.78			27.60			34.72

⁽¹⁾ Excluding non-cash general and administrative expense.

⁽²⁾ Excluding non-cash interest expense.

⁽³⁾ Funds flow netback is equal to funds flow from operations divided by Boe production for the relevant period.

Other Operating Items

DEPLETION and Depreciation Expense

Three Months Ended

June 30

Six Months Ended

June 30

2005

2006

2005

2006

$ thousands

34,718

31,587

98,075

64,641

$/Boe

19.38

20.06

17.68

20.75

Depletion and depreciation expense decreased by $33.4 million for the six months ended June 30, 2006 as compared to the same period in 2005 mainly as a result of the Trilogy Spinout. Excluding the impact of the Trilogy Spinout, depletion and depreciation expense for the first six months of 2006 decreased by $2.3 million in comparison to the first six months of 2005 due to lower gas production.

For the three months ended June 30, 2006 depletion decreased by $3.1 million in comparison to the same period of 2005. The decrease was due to lower sales volumes during the quarter ended June 30, 2006.

DRY HOLE COSTS

Under the successful efforts method of accounting for petroleum and natural gas properties, costs of drilling exploratory wells are initially capitalized and, if subsequently determined to be unsuccessful, are charged to dry hole expense. Other exploration costs, including geological and geophysical costs and annual lease rentals on non-producing properties, are charged to exploration expense as incurred. The dry hole costs for the second quarter of 2006 amounted to $12.2 million related mainly to the write off costs of two wells drilled in the Colville Lake area in the Northwest Territories.

GEOLOGICAL AND GEOPHYSICAL EXPENSE

Geological and geophysical expenses decreased during the quarter ended June 30, 2006 to $0.6 million from $1.6 million in the same period during 2005 as a result of reduced seismic activity.

GENERAL AND ADMINISTRATIVE EXPENSE

Three Months Ended

Six Months Ended

June 30

($ thousands)

2005

2006

2005

2006

General and administrative expense

before stock-based compensation expense

5,250

7,131

11,372

14,284

Stock-based compensation expense (recovery)

8,007

(2,789

)

11,700

17,602

General and administrative expense

13,257

4,342

23,072

31,886

General and administrative expense before stock-based compensation expense for the six months ended June 30 totaled $14.3 million in 2006 as compared to $11.4 million in 2005. The increase in general and administrative expense before stock-based compensation expense is primarily due to higher salary costs in 2006 from hiring additional employees. In comparison to the three months ended June 30, 2006 versus the same period in 2005 the $1.9 million increase in general and administrative expenses were similarly the result of higher salary costs.

Stock-based compensation during the second quarter of 2006 was a $2.8 million recovery as compared to a $8.0 million expense in the same period in 2005. The recovery reflects the decrease in Paramount’s share price, and decrease in the unit price of Trilogy Energy Trust units during the second quarter of 2006.

INTEREST EXPENSE

Interest expense for the six months ended June 30, 2006 was $13.8 million, a three percent increase from $13.4 million in the same period of 2005. The increase is mainly attributable to higher average credit facility borrowing levels during the second quarter of 2006 as compared to the same period of 2005. For the three months ended June 30, 2006 the increase in interest expense was also the result of higher average borrowing levels as compared to the same period in 2005.

INCOME ON EQUITY INVESTMENTS

On April 11, 2006 Paramount closed a transaction whereby it vended its interest in certain oil sands properties and other assets to North American Oil Sands Corporation (“North American”) for approximately 50 percent of the then outstanding common shares of North American and aggregate cash consideration of approximately $17.5 million. The transaction was measured at the historical cost of the properties transferred of $63.1 million, including a deferred credit of $6.5 million. A gain of approximately $1.2 million was recorded. The remainder of the cash consideration was recognized as a return of Paramount’s investment in North American. Paramount’s investment in North American is accounted for using the equity method.

Paramount records its share of North American’s equity income (loss) net of tax because North American is a corporation and is liable for the tax on this income (loss). Paramount records its share of Trilogy’s equity income (loss) on a before-tax basis and the tax expense (recovery) on that equity income (loss) is presented as a component of Paramount’s tax expense (recovery) because Trilogy is a trust and Paramount’s share of Trilogy’s income (loss) is ultimately taxable to Paramount.

As a result of equity issuances completed by North American in the second quarter, Paramount’s interest in North American was reduced from approximately 50 percent to approximately 36 percent, resulting in Paramount recording a dilution gain of approximately $101.0 million before tax.

As a result of equity issuances completed by Trilogy during the three-month period ended March 31, 2006, Paramount’s equity interest in Trilogy was reduced from approximately 17.7 percent at the beginning of the year to approximately 16.4 percent, resulting in Paramount recording a dilution gain of $16.4 million before tax in the first quarter.

INCOME TAXES

For the six months ended June 30, 2006, Paramount’s current and Large Corporation Tax recovery totaled $0.6 million as compared to an expense of $2.8 million in the same period of 2005. The future income tax recovery recorded in the second quarter of 2006 totaled $0.4 million (future income tax expense of $8.7 million for the six months ended 2006) as compared to an expense of $5.0 million during the same period of 2005 (future income tax recovery of $19.5 million for the six months ended June 30, 2005). The future income tax expense in 2006 was the result of non-deductible stock-based compensation expense incurred during the period. Also, during the second quarter of 2006, the Canadian federal government, and Alberta and Saskatchewan provincial governments enacted reductions in corporate tax rates. These changes to corporate tax rates resulted in an increase in Paramount’s future income tax expense as the values of the company’s future tax assets were reduced by $3.3 million.

Risk Management

Paramount’s financial success is dependent upon the discovery, development and production of petroleum and natural gas reserves and the economic environment that creates a demand for petroleum and natural gas. Paramount’s ability to execute its strategy is dependent on the amount of cash flow that can be generated and reinvested into its capital program. To protect cash flow against commodity price volatility, Paramount will, from time to time, enter into financial and/or physical commodity price hedges. Any such hedging transactions are restricted for periods of one year or less and the aggregate volumes under such hedging transactions are limited to a cumulative maximum of 50 percent of Paramount’s forecast production for the duration of the relevant period, determined on a barrel of oil equivalent basis.

Paramount’s outstanding forward financial contracts are set out in the unaudited Interim Consolidated Financial Statements in Note 9 - Financial Instruments and Note 13 - Subsequent Events. Paramount has chosen not to designate any of the forward financial contracts as hedges. As a result, such instruments are recorded using the mark-to-market method of accounting whereby instruments are recorded in the Consolidated Balance Sheet as either an asset or liability with changes in the fair value recognized in net earnings. The impact of fixed price physical sales contracts are reflected in petroleum and natural gas sales.

Paramount recorded a gain on financial instruments during the second quarter of 2006 of $8.3 million, a decrease of $20.2 million from the total gain on financial instruments report during the first quarter of 2006 ($28.5 million). Certain financial instruments were terminated during the second quarter prior to their maturity resulting in an increase to cash flow from operations of $20.4 million during the quarter. See Note 9 - Financial Instruments in the notes to the unaudited Interim Consolidated Financial Statements.

Capital Expenditures

Three Months Ended

Six Months Ended

June 30

Non-Oil

Sands

Oil Sands

Total

($ thousands)

2005

2006

2005

2006

Land

13,203

10,409

30,950

22,547

Geological and geophysical

1,649

1,263

7,162

6,061

6,294

12,355

Drilling and completions

26,428

41,195

146,383

128,435

24,489

152,924

Production equipment and facilities

18,622

30,229

61,784

60,550

2,664

63,214

Exploration and development expenditures

59,902

83,096

246,279

217,593

33,447

251,040

Property acquisitions

1,166

10,535

11,087

11,158

23,900

35,058

Proceeds from property dispositions

(712

)

(2,142

)

(723

)

(763

)

(1,750

)

(2,513

)

Other

306

11,730

1,311

11,871

Net capital expenditures

60,662

103,219

257,954

239,859

55,597

295,456

For the six months ended June 30, 2006, exploration and development expenditures totaled $251.0 million as compared to $246.3 million in the same period of 2005. A comparison of the number of wells drilled for the six months ended June 30, 2006 and June 30, 2005 is as follows:

	Three Months Ended								Six Months Ended
	June 30								June 30
(wells drilled)		2005			2006					2005				2006
		Gross ⁽¹⁾	Net⁽²	⁾	Gross⁽¹	⁾	Net⁽²	⁾		Gross⁽¹	⁾	Net⁽²	⁾	Gross⁽¹	⁾	Net⁽²	⁾
Natural gas		56	33		37		26			148		92		121		70
Oil		2	1		3		1			11		6		6		3
Oil sands evaluation		2	-		1		1			23		14		122		61
Dry holes		-	-		-		-			11		7		5		4
Total		60	34		41		28			193		119		254		138

⁽¹⁾“Gross” wells means the number of wells in which Paramount has a working interest or a royalty interest that may be converted to a working interest.

⁽²⁾“Net” wells means the aggregate number of wells obtained by multiplying each gross well by Paramount’s percentage of working interest therein.

Paramount’s asset profile includes winter only access locations, where Paramount historically commits the majority of its first quarter capital budget towards drilling activities.

Relative to the second quarter of 2005, Paramount drilled 19 fewer gross wells (6 net) during the three months ended June 30, 2006. A shortened winter drilling season in 2006 from early spring break up reduced the number of wells drilled.

For the second half of 2006 Paramount will not incur additional capital expenditures related to the oil sands interests transferred to North American, as additional expenditures required to develop these oil sands assets will be borne solely by North American. Paramount’s total expenditures on these oil sands assets in 2006 were approximately $33.4 million. Future capital expenditures towards development of oil sands will be focused on our 100 percent owned oil sands leases in the Surmont area of Northeast Alberta.

Quarterly Information

	Three Months Ended
	Jun 30		Mar 31		Dec 31		Sep 30
($ thousands, except per share amounts)	2006		2006		2005		2005
Petroleum & natural gas sales		73,681		87,909		115,126		99,187
Revenue, net⁽¹⁾		72,246		100,865		112,422		36,526
Net earnings (loss)		111,874		7,764		37,758		(69,066	)
Net earnings (loss) per common share
- basic		1.65		0.12		0.57		(1.05	)
- diluted		1.61		0.12		0.56		(1.05	)

	Three Months Ended
	Jun 30	Mar 31		Dec 31		Sep 30
($ thousands, except per share amounts)	2005	2005		2004		2004
Petroleum & natural gas sales	91,848	176,508		115,127		164,903
Revenue, net⁽¹⁾	96,581	115,741		174,067		138,443
Net earnings (loss) before discontinued operations	12,934	(45,558	)	(18,873	)	40,599
Net earnings (loss) from discontinued operations	-	-		1,120		5,213
Net earnings (loss)	12,934	(45,558	)	(17,753	)	45,812
Net earnings (loss) before discontinued operations per common share
- basic	0.20	(0.72	)	(0.30	)	0.69
- diluted	0.20	(0.72	)	(0.30	)	0.68
Net earnings (loss) per common share
- basic	0.20	(0.72	)	(0.28	)	0.78
- diluted	0.20	(0.72	)	(0.28	)	0.76

⁽¹⁾Represents revenue after gain/loss on financial instruments, royalties and gain on sale of investments and other.

Lower realized natural gas prices were the primary factor causing the decline in net revenue between the second quarter and first quarter of 2006. The increase in net earnings between the second quarter and first quarter of 2006 was primarily the result of dilution gains recorded on our equity investment of North American. See Second Quarter 2006 vs. First Quarter 2006 comparison under “Key Operating Results”.

Liquidity and Capital Resources

($ thousands)	June 30		December 31
	2006		2005
Working capital deficit ⁽¹⁾	$	112,056	$	70,683
Credit facility		145,971		105,479
US notes		238,413		248,409
Stock-based compensation liability⁽²⁾		3,200		4,105
Net debt⁽³⁾		499,640		428,676
Share capital		267,844		198,417
Retained earnings		358,452		238,404
Total	$	1,125,936	$	865,497

⁽¹⁾ Includes current portion of stock-based compensation liability of $17.8 million at June 30, 2006 ($27.3 million at December 31, 2005).

⁽²⁾ Since August 2005, Paramount has generally declined an optionholder’s request for a cash payment relating to vested Paramount Options, thereby necessitating optionholders to exercise their vested Paramount Options, and to pay the aggregate exercise price of their stock options to Paramount as consideration for the issuance by Paramount of Common Shares. Paramount expects that this will continue. As a result, the stock-based compensation liability associated with Paramount Options amounting to $50.1 million has been excluded from the computation of Net Debt at June 30, 2006 ($46.6 million at December 31, 2005).

⁽³⁾ Net debt includes the stock-based compensation liability associated with Holdco Options totaling $21.0 million at June 30, 2006 ($31.4 million at December 31, 2005) as Paramount has accepted optionholders’ requests for cash payments, and expects that this will continue.

WORKING CAPITAL

Paramount’s working capital position at June 30, 2006 was a $112.1 million deficit as compared to a $91.5 million deficit at March 31, 2006.

The impact of lower natural gas prices in 2006 and our growth oriented capital program resulted in an increase in Paramount’s working capital deficit.

CREDIT FACILITY

Effective March 30, 2006, the revolving nature of Paramount’s credit facility was extended for a further 364 days. The size of Paramount’s credit facility is based on among other things, the value of Paramount’s petroleum and natural gas assets reserves.

Bank debt outstanding as at June 30, 2006 was $146.0 million.

US SENIOR NOTES

At June 30, 2006 Paramount had $238.4 million (US $213.6 million) outstanding principal amount of 8 1/2 percent Senior Notes due 2013 (the “Senior Notes”). The Senior Notes are secured by 12,755,845 Trilogy trust units owned by Paramount, which had a market value of $241.1 million at June 30, 2006.¹ These Trilogy trust units are reflected in Long-term investments and other assets in Paramount’s Consolidated Balance Sheet. In addition, there are 2,279,500 Trilogy trust units held by Paramount relating to its obligations under Holdco Options, have a market value of $21.0 million at June 30, 2006 on Paramount’s Consolidated Balance Sheet. Paramount’s obligations respecting its previously existing 77/8 percent US Senior Notes due 2010 and 87/8 percent US Senior Notes due 2014 were extinguished during 2005 as a result of a notes exchange offer and open market re-purchases.

____________________

⁽¹⁾ Based on the closing price of Trilogy trust units on the Toronto Stock Exchange on June 30, 2006.

SHARE CAPITAL

On March 30, 2006, Paramount completed a private placement of 600,000 common shares issued on a flow through basis at $52.00 per share, and a private placement of 600,000 common shares at $41.72 per share for total gross proceeds of $56.2 million.

At August 4, 2006, Paramount had 68,024,575 Class A Common Shares outstanding. At August 4, 2006 there were 4,741,325 Paramount Options outstanding (363,650 exercisable) and 1,551,875 Holdco Options outstanding (586,250 exercisable).

FUNDING OF 2006 CAPITAL PROGRAM

Paramount anticipates that its planned 2006 capital program will be funded from cash flows from operations, borrowings under its credit facilities, the March 30, 2006 share issues, and through other sources of funds which may include incurring additional debt, issuing additional equity, or disposing of mature or non-core assets. Subsequent to June 30, 2006 Paramount commenced a transaction through which it expects to raise US $150 million in the US Term Loan B market. This transaction is expected to close on or about August 25, 2006.

In the event of significantly lower cash flow, Paramount would be able to defer certain of its projected capital expenditures without penalty. Also, following the transaction with North American, Paramount is no longer obligated to directly fund development of oil sands leases previously owned jointly with the company.

Related Party Transactions

TRILOGY ENERGY TRUST

At June 30, 2006, Paramount held approximately 15 million trust units of Trilogy representing 16.4 percent of the issued and outstanding trust units of Trilogy at such time. In addition to the Trilogy trust units held by Paramount, Trilogy and Paramount have certain common members of management and directors. The following transactions have been recorded at the exchange amounts:

Paramount provided certain operational, administrative, and other services to Trilogy Energy Ltd., a wholly-owned subsidiary of Trilogy, pursuant to a services agreement dated April 1, 2005 (the “Services Agreement”). The Services Agreement had an initial term ending March 31, 2006. The Services Agreement was renewed on the same terms and conditions to March 31, 2007. Under the Services Agreement, Paramount is reimbursed for all reasonable costs (including expenses of a general and administrative nature) incurred by Paramount in providing the services. The reimbursement of expenses is not intended to provide Paramount with any financial gain or loss. For the six months ended June 30, 2006, the amount of costs subject to reimbursement under the Services Agreement was $1.2 million, which has been reflected as a reduction in Paramount’s general and administrative expenses.

·	At June 30, 2006 Paramount owed Trilogy $2.4 million, which balance includes a Crown royalty deposit claim of $5.5 million which, when refunded to Paramount, will be paid to Trilogy.

As a result of the Trilogy Spinout, certain employees and officers of Trilogy hold Paramount Options and Holdco Options. The stock-based compensation expense relating to these options for the six months ended June 30, 2006 amounted to $1.1 million, of which $0.9 million was charged to general and administrative expense and $0.2 million was recognized in equity in net earnings of Trilogy.

·	Paramount recorded distributions from Trilogy Energy Trust totaling $21.0 million for the six months ended June 30, 2006. Distributions receivable of $3.0 million relating to distributions declared by Trilogy in June 2006 were accrued at June 30, 2006 and received in July 2006.

·	During the six months ended June 30, 2006, Paramount also had other transactions in the normal course of business with Trilogy.

DRILLING COMPANY

During the second quarter of 2006, Paramount and a private company controlled by a majority shareholder, director and officer of Paramount (the “Private Company”) formed a company in the United States (“Drillco”) to supply drilling services to a United States subsidiary of Paramount; Paramount owns 50 percent of Drillco, and the Private Company owns 50 percent of Drillco. Drillco has entered into a contract for the purchase of two drilling rigs, the first of which we anticipate to be available near the end of the fourth quarter of 2006. In connection with the purchase of the drilling rigs, the Private Company extended a demand loan totaling US$7.6 million to Drillco. The loan bears interest at a US bank’s Prime interest rate plus 0.5 percent. The amount of the loan, plus accrued interest is included in the Due to Related Parties balance in the consolidated financial statements.

DIRECTORS AND EMPLOYEES

Drillco has entered into a contract for the construction of two drilling rigs under a cost-plus fee arrangement with a company whose part-owner is a director of a company affiliated with Paramount. Estimated costs to construct the two drilling rigs total US$18.0 million; including a US$2.0 million fee due and payable to the supplier upon delivery.

During the second quarter of 2006 two officers and a director of Paramount participated in private equity placements undertaken by North American Oil Sands Corporation; purchasing an aggregate 146,667 shares of North American for $1.8 million.

Companies controlled by a director and officer of Paramount purchased an aggregate 600,000 common shares for gross proceeds to Paramount of $25.0 million on March 30, 2006. Also, during the first quarter of 2006 certain employees, officers, and directors of Paramount purchased an aggregate 8,500 flow-through common shares issued by Paramount for gross proceeds to Paramount of $0.4 million.

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. Paramount's performance is influenced by commodity prices, 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 Paramount’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.

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

The oil and gas industry is subject to extensive controls, royalties, regulatory policies and income taxes imposed by the various levels of government. These controls and policies, as well as income tax laws and regulations, are amended from time to time. Paramount is unable to control 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 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. Paramount attempts to minimize these risks using prudent safety programs and risk management, including insurance coverage against potential losses.

Paramount 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 Paramount's operations; however, the cost of complying with environmental regulations is increasing. Paramount intends to ensure continued compliance with all environmental legislation.

Financial Instruments

In May 2006, Paramount terminated the following forward financial commodity contracts prior to their maturity and received an approximate net settlement of $20.4 million:

	Amount	Price	Original Term
*Sales Contracts*
AECO Fixed Price	10,000 GJ/d	$10.60	April 2006 – October 2006
AECO Fixed Price	10,000 GJ/d	$10.75	April 2006 – October 2006
*Purchase Contracts*
AECO Fixed Price	10,000 GJ/d	$6.01	June 2006 - October 2006
AECO Fixed Price	10,000 GJ/d	$5.98	June 2006 - October 2006
*Option Contract*
AECO Put Option	10,000 GJ/d	$9.00	April 2006 – October 2006

Refer to the unaudited Interim Consolidated Financial Statements - Note 9 - Financial Instruments for a listing of all forward financial instruments outstanding at June 30, 2006.

Subsequent Events

Subsequent to June 30, 2006, Paramount entered into the following forward commodity contracts:

		Amount	Price	Term
*Physical Sales Contract*
	AECO Fixed Price	10,000 GJ/d	$6.25	August 2006 - October 2006
*Physical Purchase Contracts*
	AECO Fixed Price	20,000 GJ/d	$5.37	September 2006 - October 2006
	AECO Fixed Price	20,000 GJ/d	$5.1725	July 2006 - August 2006
*Financial Sales Contract*
	NYMEX Fixed Price	10,000 MMBtu/d	US$10.00	November 2006 - March 2007
	NYMEX Fixed Price	10,000 MMBtu/d	US$10.875	November 2006 - March 2007

In addition, Paramount entered into a financial contract to purchase 10,000 MMBtu/d from November 2006 to March 2007 for a NYMEX fixed price of US$9.41/MMBtu. This contract was entered into to settle a financial contract outstanding at June 30, 2006 to sell 10,000 MMBtu/d from November 2006 to March 2007 for a NYMEX fixed price of US$10.28/MMBtu which resulted in a net payment of US$1.3 million to Paramount in July.

On August 4, 2006, the Company engaged an investment bank to arrange a Term Loan B facility (the “Facility”) in the U.S. market for up to US$150 million to refinance existing indebtedness and for general corporate use. The Facility is expected to have a six year term and there is no scheduled amortization prior to maturity. The Facility will be secured by a pledge of the common shares of North American (the “NAOSC Shares”) currently held by the Company. It is expected that the Facility will have to be prepaid with 100% of the net proceeds received from any sale or other disposition of all or any part of the NAOSC Shares. The interest rate will be set upon finalization of the ratings process and completion of the syndication process.

2006 Outlook and Sensitivity Analysis

The following table sets forth Paramount’s current estimate of 2006 production and capital expenditures:


Production (Boe/d)
2006 Average			19,000
2006 Exit			23,000

E&P Capital Expenditures ⁽¹⁾ ($ millions)
2006 Conventional & Coal Bed Methane			370
2006 Oil Sands			45

⁽¹⁾ Excludes expenditures on land and acquisitions

Paramount’s results are affected by external market factors, such as fluctuations in the price of crude oil and natural gas, foreign exchange rates, and interest rates. The following table provides projected estimates of the sensitivity of Paramount’s funds flow from operations for the remaining six months ending December 31, 2006 to changes in commodity prices, the Canadian/US dollar exchange rate and interest rates:

Sensitivity ⁽¹⁾⁽²⁾	Funds Flow Effect
	($ millions)
$0.25/GJ change in AECO gas price	2.6
US$1.00 change in the WTI oil price	0.4
$0.01 change in the Canadian/US dollar exchange rate	1.3
1 percent change in prime rate of interest	0.7

⁽¹⁾Includes the impact of financial and physical hedge contracts existing at August 4, 2006, and includes the impact of the settlement of certain forward commodity contracts - see Subsequent Events.

⁽²⁾Based on forward curve commodity price and forward curve estimates dated June 30, 2006.

The following assumptions were used in the sensitivity (above):


2006 Annual Average Production
Natural gas	100 MMcf/d
Crude oil/liquids	4,100 Bbl/d

2006 Average Prices
Natural gas	$6.96/Mcf
Crude oil (WTI)	US$64.98/Bbl

2006 Exchange Rate (C$/US$)	$1.14

Cash taxes	Nil

Critical Accounting Estimates

The preparation of the Consolidated Financial Statements in accordance with 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 factors that are believed by management to be reasonable under the circumstances. Actual results could differ materially from these estimates.

Readers are referred to Paramount’s Management’s Discussion and Analysis for the year ended December 31, 2005 for a discussion of critical accounting estimates relating to (i) successful efforts accounting; (ii) reserves estimates; (iii) impairment of petroleum and natural gas properties; (iv) asset retirement obligations; (v) purchase price allocations; and (vi) income taxes and royalty matters.

Recent Accounting Pronouncements

NON-MONETARY TRANSACTIONS

On January 1, 2006, Paramount prospectively adopted Section 3831 “Non-monetary Transactions” of the CICA Handbook issued by the Canadian Institute of Chartered Accountants. Under this standard, a commercial substance test replaced the culmination of the earnings process test as the criteria for fair value measurement, and fair value measurement was clarified. Adoption of this new accounting standard did not have a material impact on the unaudited Interim Consolidated Financial Statements as at and for the period ended June 30, 2006.

Paramount Resources Ltd.

Interim Consolidated Financial Statements (Unaudited)

As at and for the Three and Six Months Ended June 30, 2006

Paramount Resources Ltd.
Consolidated Balance Sheets (Unaudited)
(thousands of dollars)		As at			As at
		June 30			December 31
		2006			2005
ASSETS
Current Assets
Short-term investments (Market value: June 30, 2006 - $5,175; December 31, 2005 - $16,176)	$	4,014		$	14,048
Accounts receivable		100,703			92,772
Distributions receivable from Trilogy Energy Trust (Note 10)		3,007			12,028
Financial instruments (Note 9)		6,777			2,443
Prepaid expenses and other		6,613			3,869
		121,114			125,160
Property, Plant and Equipment (Note 3)
Property, plant and equipment, at cost		1,485,593			1,314,651
Accumulated depletion and depreciation		(456,484	)		(400,072	)
		1,029,109			914,579
Goodwill		12,221			12,221
Long-term investments and other assets (Note 4)		218,312			56,467
Future income taxes		-			2,923
	$	1,380,756		$	1,111,350

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable and accrued liabilities	$	200,376		$	155,076
Due to related parties (Note 10)		11,048			6,439
Financial instruments (Note 9)		3,914			7,056
Current portion of stock-based compensation liability (Note 8)		17,832			27,272
		233,170			195,843
Long-term debt (Note 5)		384,384			353,888
Asset retirement obligations (Note 6)		67,093			66,203
Deferred credit (Note 4)		-			6,528
Stock-based compensation liability (Note 8)		53,336			50,729
Non-controlling interest		588			1,338
Future income taxes (Note 11)		15,889			-
		521,290			478,686

Commitments and Contingencies (Notes 5, 9, 12 and 13)

Shareholders' Equity
Share capital (Note 7)
Issued and outstanding: 68,004,575 common shares
(December 31, 2005 - 66,221,675 common shares)		267,844			198,417
Retained earnings		358,452			238,404
		626,296			436,821
	$	1,380,756		$	1,111,350
See accompanying notes to Consolidated Financial Statements.

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

		Three Months Ended						Six Months Ended
		June 30						June 30
		2006			2005			2006			2005
Revenue
Petroleum and natural gas sales	$	73,681		$	91,848		$	161,590		$	268,356
Gain (loss) on financial instruments (Note 9)		8,338			13,610			36,835			(14,320	)
Royalties		(9,773	)		(9,340	)		(26,552	)		(44,544	)
Gain on sale of investments and other		-			463			1,238			2,830
		72,246			96,581			173,111			212,322
Expenses
Operating		18,692			13,700			36,823			41,685
Transportation		3,487			5,376			7,139			14,541
Interest on long-term debt		7,153			6,089			13,802			13,435
General and administrative (Notes 8 and 10)		4,342			13,257			31,886			23,072
Lease rentals		198			632			947			1,591
Geological and geophysical		579			1,649			11,671			7,162
Dry hole costs		12,189			520			18,943			5,503
Gain on sale of property, plant and equipment (Note 4)		(1,765	)		(15	)		(1,973	)		(1,000	)
Accretion of asset retirement obligations		1,433			811			2,886			2,781
Depletion and depreciation		31,587			34,718			64,641			98,075
Write-down of petroleum and natural gas properties		1,334			-			1,334			-
Unrealized foreign exchange loss (gain)		(11,212	)		3,389			(9,966	)		19,211
Realized foreign exchange gain		(450	)		-			(721	)		(14,191	)
Premium on redemption of US Notes		-			-			-			53,114
		67,567			80,126			177,412			264,979
Income (loss) from equity investments
Equity income (Note 4)		3,955			3,405			14,585			3,314
Dilution gain (Note 4)		101,036			-			117,419			-
Non-controlling interest		10			(17	)		17			(2	)
Earnings (loss) before income taxes		109,680			19,843			127,720			(49,345	)
Income and other taxes (Note 11)
Current and large corporations tax expense (recovery)		(1,750	)		1,924			(626	)		2,765
Future income tax expense (recovery)		(444	)		4,985			8,708			(19,486	)
		(2,194	)		6,909			8,082			(16,721	)
Net earnings (loss)		111,874			12,934			119,638			(32,624	)
Retained earnings, beginning of period		246,168			276,549			238,404			322,107
Adjustment due to Trilogy Spinout		-			54,488			-			54,488
Share in equity investee capital transactions		410			-			410			-
Retained earnings, end of period	$	358,452		$	343,971		$	358,452		$	343,971
Net earnings (loss) per common share
- basic	$	1.65		$	0.20		$	1.78		$	(0.51	)
- diluted	$	1.61		$	0.20		$	1.74		$	(0.51	)
Weighted average common shares outstanding (thousands)
- basic		67,981			64,103			67,243			63,835
- diluted		69,658			65,820			68,788			63,835
See accompanying notes to Consolidated Financial Statements.

Paramount Resources Ltd.
Consolidated Statements of Cash Flows (Unaudited)
(thousands of dollars)
		Three Months Ended						Six Months Ended
		June 30						June 30
		2006			2005			2006			2005
Operating activities
Net earnings (loss)	$	111,874		$	12,934		$	119,638		$	(32,624	)
Add (deduct) non-cash and other items:
Unrealized loss (gain) on financial instruments		21,982			(17,313	)		(7,476	)		21,326
Amortization of other assets		148			-			295			96
Non-cash general and administrative expense		(6,462	)		7,801			10,873			9,474
Geological and geophysical		579			1,649			11,671			7,162
Dry hole costs		12,189			520			18,943			5,503
Gain on sale of property, plant and equipment		(1,765	)		(15	)		(1,973	)		(1,000	)
Accretion of asset retirement obligations		1,433			811			2,886			2,781
Asset retirement obligations paid		(179	)		(62	)		(354	)		(214	)
Depletion and depreciation		31,587			34,718			64,641			98,075
Write-down of petroleum and natural gas properties		1,334			-			1,334			-
Unrealized foreign exchange (gain) loss on US Notes		(11,212	)		3,389			(9,966	)		19,211
Realized foreign exchange gain on US Notes		-			-			-			(14,191	)
Premium on redemption of US Notes		-			-			-			53,114
Equity income (Note 4)		(3,955	)		(3,405	)		(14,585	)		(3,314	)
Distributions from equity investments		9,772			7,217			21,049			7,217
Dilution gain (Note 4)		(101,036	)		-			(117,419	)		-
Non-controlling interest		(10	)		17			(17	)		2
Future income tax expense (recovery)		(444	)		4,985			8,708			(19,486	)
Funds flow from operations		65,835			53,246			108,248			153,132
Net change in operating working capital		44,480			7,536			44,807			20,958
		110,315			60,782			153,055			174,090
Financing activities
Bank loans - draws		47,645			60,099			181,675			224,900
Bank loans - repayments		(43,609	)		(228,471	)		(141,234	)		(323,428	)
Debt exchange issuance costs (recovery)		-			285			-			(4,782	)
Premium on redemption of US Notes		-			-			-			(45,077	)
Cost of reorganization		-			-			-			(4,000	)
Receipt of funds from Trilogy Spinout		-			220,000			-			220,000
Common shares issued, net of issuance costs		463			85			58,028			9,580
		4,499			51,998			98,469			77,193
Cash flows provided by operating and financing activities		114,814			112,780			251,524			251,283
Investing activities
Property, plant and equipment expenditures		(94,827	)		(60,208	)		(262,911	)		(247,590	)
Petroleum and natural gas property acquisitions		(10,535	)		(1,166	)		(35,058	)		(11,087	)
Proceeds on sale of property, plant and equipment		2,142			712			2,513			723
Cost of equity investments		(475	)		(1	)		(475	)		(6,215	)
Return of capital received, net of non-controlling interest		16,104			-			19,761			-
Net change in investing working capital		(27,223	)		(52,117	)		24,646			12,886
Cash flows used in investing activities		(114,814	)		(112,780	)		(251,524	)		(251,283	)
Cash, end of period	$	-		$	-		$	-		$	-
Interest paid	$	2,480		$	443		$	14,938		$	4,619
Current and large corporation taxes paid	$	4,170		$	2,246		$	4,545		$	2,911
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 an independent Canadian energy company that explores for, develops, processes, transports and markets petroleum and natural gas. Paramount’s principal properties are located in Alberta, the Northwest Territories and British Columbia.

On April 1, 2005, Paramount completed a reorganization pursuant to a plan of arrangement under the Business Corporations Act (Alberta), resulting in the creation of Trilogy Energy Trust (“Trilogy”) as a new publicly-traded energy trust (the “Trilogy Spinout”). Through the Trilogy Spinout, among other things:

·	Certain properties owned by Paramount that were located in the Kaybob and Marten Creek areas of Alberta and three natural gas plants operated by Paramount became property of Trilogy (“Spinout Assets”); and

Paramount received an aggregate $220 million in cash (including a $30 million settlement of working capital accounts) and 79.1 million units of Trilogy (64.1 million units being ultimately received by Paramount shareholders) as consideration for the Spinout Assets and related working capital adjustments.

Paramount’s comparative unaudited Interim Consolidated Financial Statements for the six months ended June 30, 2005 include the results of operations and cash flows relating to the Spinout Assets for the period January 1, 2005 to March 31, 2005.

1. Summary of Significant Accounting Policies

The unaudited Interim Consolidated Financial Statements of Paramount are stated in Canadian dollars and have been prepared following the same accounting policies and methods of their application as Paramount’s audited consolidated financial statements for the year ended December 31, 2005, except as disclosed in Note 2. The financial statements of a 50 percent-owned development stage company established during the three months ended June 30, 2006 to supply drilling services have been consolidated into Paramount’s financial statements as a variable interest entity. Any expected accumulated losses of this entity cannot be determined at the present time.

Certain information and disclosures normally required to be included in notes to annual consolidated financial statements have been condensed or omitted. Accordingly, these unaudited Interim Consolidated Financial Statements should be read in conjunction with Paramount’s audited consolidated financial statements for the year ended December 31, 2005.

The timely preparation of the unaudited Interim Consolidated Financial Statements in conformity with Canadian generally accepted accounting principles requires that management make estimates and assumptions and use judgment that affects the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reported period. Such estimates primarily relate to unsettled transactions and events as of the date of the unaudited Interim Consolidated Financial Statements. Accordingly, actual results could differ materially from those estimates.

2. Change in Accounting Policy

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

3. Property, Plant and Equipment

June 30

December 31

2006

2005

Cost

Accumulated Depletion and Depreciation

Net Book

Value

Net Book Value

Petroleum and natural gas properties

1,028,308

353,282

675,026

606,185

Gas plants, gathering systems

and production equipment

429,293

90,225

339,068

303,871

Other

27,992

12,977

15,015

4,523

Total

1,485,593

456,484

1,029,109

914,579

Capital costs associated with non-producing petroleum and natural gas properties and equipment under construction totaling approximately $310 million (December 31, 2005 - $320 million) are currently not subject to depletion.

4. Long-term Investments and Other Assets

	June 30		December 31
	2006		2005
Equity accounted investments:
Trilogy Energy Trust
(market value: June 30, 2006 - $284.2 million; December 31, 2005 - $357.8 million)	$	65,479	$	51,665
North American Oil Sands Corporation ("North American")		148,324		-
Private oil and gas company		623		623
		214,426		52,288
Deferred financing costs, net of amortization		3,886		4,179
	$	218,312	$	56,467

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

The following table provides a continuity of Paramount’s equity accounted investments:

	Six Months Ended June 30, 2006
	Trilogy Energy Trust			North American			Private Oil & Gas Company		Total
Opening balance	$	51,665		$	-		$	623	$	52,288
Initial carrying value of investment		-			46,932			-		46,932
Share in investee's other
capital transactions		-			410			-		410
Equity income (loss) for the period		14,639			(54	)		-		14,585
Future income tax recovery
on equity income		3,641			-			-		3,641
Distributions		(21,049	)		-			-		(21,049	)
Dilution gain (see below)		16,383			101,036			-		117,419
Stock-based compensation
expense - Trilogy employees		200			-			-		200
Closing balance	$	65,479		$	148,324		$	623	$	214,426

On April 11, 2006 Paramount closed a transaction whereby it vended its interest in certain oil sands properties and other assets to North American for approximately 50 percent of the then outstanding common shares of North American and aggregate cash consideration of approximately $17.5 million. The transaction was measured at the historical cost of the properties transferred of $63.1 million, including a deferred credit of $6.5 million. A gain of approximately $1.2 million was recorded. The remainder of the cash consideration was recognized as a return of Paramount’s investment in North American. Paramount’s investment in North American is accounted for using the equity method.

As a result of equity issuances completed by North American in the second quarter, Paramount’s equity interest in North American was reduced from approximately 50 percent to approximately 36 percent, resulting in Paramount recording a dilution gain of approximately $101.0 million before tax.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

5. Long-Term Debt

	June 30, 2006		December 31, 2005
Credit facility - interest rate of 5.5 percent as at June 30, 2006
(December 31, 2005 - 4.9 percent)	$	145,971	$	105,479
8 1/2 percent US Senior Notes due 2013 (US $213.6 million)		238,413		248,409
	$	384,384	$	353,888

CREDIT FACILITIES

At June 30, 2006 Paramount had a $200 million committed credit facility with a syndicate of Canadian banks, $183 million after adjustment for US Notes service costs. Borrowings under the facility bear interest at either the lenders’ prime rate, bankers’ acceptance rate or LIBOR, at the discretion of Paramount, plus an applicable margin depending on certain conditions. The facilities are available on a revolving basis for a period of 364 days from March 30, 2006 and can be extended a further 364 days upon request, subject to approval by the lenders. In the event the revolving period is not extended, the facility would be available on a non-revolving basis for a one year term, at the end of which time the facility would be due and payable. Advances drawn on Paramount’s credit facility are secured by a fixed and floating charge over the assets of the Company, excluding 12,755,845 of the Trilogy units owned by Paramount.

Paramount had letters of credit outstanding totaling $26.0 million at June 30, 2006. These letters of credit have not been drawn; however they reduce the amount available to the Company under the credit facility.

6. Asset Retirement Obligations

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

	Six Months Ended			Year Ended
	June 30, 2006			December 31, 2005
Asset retirement obligations, beginning of period	$	66,203		$	101,486
Adjustment resulting from the Trilogy Spinout		-			(65,076	)
Liabilities incurred		4,305			3,614
Reduction on disposal of properties		(5,947	)		-
Revisions in estimated cost of abandonment		-			22,113
Liabilities settled		(354	)		(990	)
Accretion expense		2,886			5,056
Asset retirement obligations, end of period	$	67,093		$	66,203

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

7. Share Capital

Class A Common Shares	Shares		Amount
Balance at December 31, 2005		66,221,675	$	198,417
Issued on exercise of stock options		582,900		21,027
Issued for cash		1,200,000		56,232
Share issuance costs, net of tax benefit		-		(938	)
Tax adjustment on flow-through share renunciations		-		(6,894	)
Balance at June 30, 2006		68,004,575	$	267,844

On March 30, 2006, Paramount completed the private placement of 600,000 Common Shares issued on a flow-through basis at a price of $52.00 per share. The gross proceeds of this issue were $31.2 million. Paramount also completed the private placement of 600,000 Common Shares at a price of $41.72 per share on the same day to companies controlled by Paramount’s Chairman and Chief Executive Officer. The gross proceeds of this issue were $25.0 million.

8. Stock-based Compensation

The following table provides a continuity of Paramount’s stock options for the six months ended June 30, 2006:

	Paramount Options					Holdco Options
	Weighted Average Exercise Price		Options			Weighted Average Exercise Price		Options
Balance, beginning of period	$	10.22		3,910,175		$	5.79		1,985,375
Granted		34.79		1,568,500			-		-
Exercised		5.44		(583,150	)		5.18		(383,000	)
Cancelled		21.30		(126,200	)		10.28		(19,500	)
Balance, end of period	$	18.59		4,769,325		$	5.89		1,582,875
Options exercisable, end of period	$	5.25		375,650		$	5.24		581,250

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

Additional information concerning Paramount’s stock options outstanding as at June 30, 2006 is as follows:

	Outstanding						Exercisable
			Weighted
			Average		Weighted				Weighted
			Contractual		Average				Average
			Life		Exercise				Exercise
Exercise Prices	Number		(In Years)		Price		Number		Price
Paramount Options
$4.33-$10.00		1,231,725		1.7	$	4.83		324,100	$	4.91
$10.01-$30.00		1,935,100		3.4		14.00		27,500		13.76
$30.01-$43.25		1,602,500		4.1		34.71		24,050		-
Total		4,769,325		3.2	$	18.59		375,650	$	5.25

Holdco Options
$4.58-$6.00		1,279,875		1.6	$	4.67		529,750	$	4.65
$6.01-$10.00		106,500		2.4		7.17		18,500		6.84
$10.01-$16.37		196,500		3.0		13.15		33,000		13.79
Total		1,582,875		1.8	$	5.89		581,250	$	5.24

For the six months ended June 30, 2006, 383,000 Holdco Options were surrendered in exchange for cash payments from Paramount of $6.8 million which reduced the related stock-based compensation liability.

The current portion of stock-based compensation liability of $17.8 million at June 30, 2006 (December 31, 2005 - $27.3 million) represents the value, using the intrinsic value method, of vested Holdco Options and Holdco Options vesting within the next twelve months.

For the six months ended June 30, 2006, Paramount recognized compensation costs of $21.1 million for the Paramount Options and a recovery of $3.5 million for the Holdco Options relating to the mark-to-market valuation and time-based vesting of the options. For the three months ended June 30, 2006, Paramount recorded a $3.3 million recovery of stock-based compensation expense related to the decrease in market value of Paramount stock. The recovery of compensation costs is presented as a reduction of general and administrative expense in the Consolidated Statements of Earnings (Loss) and Retained Earnings.

9. Financial Instruments

Paramount has elected not to designate any of its financial instruments as hedges under Accounting Guideline 13 Hedging Relationships (“AcG-13”), and therefore has recognized the fair value of its financial instruments in the unaudited Interim Consolidated Financial Statements.

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

The following tables present a reconciliation of the change in the unrealized and realized gains and losses on financial instruments:

Three Months Ended	June 30, 2006			June 30, 2005
		Total			Net Deferred Amounts on Transition		Mark-to Market Gain (Loss)			Total
Change in fair value of contracts recorded on transition	$	-		$	-	$	(757	)	$	(757	)
Amortization of deferred fair value of contracts		-			413		-			413
Net change in fair value of contracts entered into after transition (mark-to-market gain (loss))		(21,983	)		-		17,657			17,657
Unrealized gain (loss) on financial instruments		(21,983	)	$	413	$	16,900		$	17,313
Realized gain (loss) on financial instruments		30,321								(3,703	)
Net gain on financial instruments	$	8,338							$	13,610

Six Months Ended	June 30, 2006		June 30, 2005

	Total		Net Deferred Amounts on Transition		Mark-to Market Loss			Total
Change in fair value of contracts recorded on transition	$	-	$	-	$	(2,033	)	$	(2,033	)
Amortization of deferred fair value of contracts		-		823		-			823
Net change in fair value of contracts entered into after transition (mark-to-market gain (loss))		7,475		-		(20,116	)		(20,116	)
Unrealized gain (loss) on financial instruments		7,475	$	823		(22,149	)		(21,326	)
Realized gain on financial instruments		29,360							7,006
Net gain (loss) on financial instruments	$	36,835						$	(14,320	)

At June 30, 2006, Paramount was a party to the following forward financial commodity contracts:

	Amount	Price	Term
*Sales Contracts*
NYMEX Fixed Price	10,000 MMBtu/d	US$10.14	November 2006 – March 2007
NYMEX Fixed Price	10,000 MMBtu/d	US$10.37	November 2006 – March 2007
NYMEX Fixed Price	10,000 MMBtu/d	US$11.15	November 2006 – March 2007
NYMEX Fixed Price	10,000 MMBtu/d	US$10.28	November 2006 – March 2007
WTI Fixed Price	1,000 Bbl/d	US$66.04	February 2006 – December 2006
WTI Fixed Price	1,000 Bbl/d	US$65.64	February 2006 – December 2006
AECO Costless Collar	20,000 GJ/d	$9.00 floor	July 2006
		$12.50 ceiling
*Option Contract*
AECO Call Option	20,000 GJ/d	$12.50	April 2006 - October 2006

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

Paramount also entered into a currency forward contract to purchase US$3.5 million at the rate of CDN$1.1216/US$1 for settlement on July 28, 2006. The US$/CDN$ closing exchange rate was 1.1162 as at June 30, 2006.

The aggregate fair value of above contracts as at June 30, 2006 was a $2.9 million gain.

During the three months ended June 30, 2006 Paramount terminated the following forward financial commodity contracts prior to their maturity and received an approximate $20.4 million net settlement:

			Amount	Price	Original Term
*Sales Contracts*
	AECO Fixed Price		10,000 GJ/d	$10.600	April 2006 - October 2006
	AECO Fixed Price		10,000 GJ/d	$10.745	April 2006 - October 2006
*Purchase Contracts*
		AECO Fixed Price	10,000 GJ/d	$6.010	June 2006 - October 2006
		AECO Fixed Price	10,000 GJ/d	$5.975	June 2006 - October 2006
*Option Contract*
		AECO Put Option	10,000 GJ/d	$9.000	April 2006 - October 2006

10. Related Party Transactions

TRILOGY ENERGY TRUST

·	At June 30, 2006 Paramount owed Trilogy $2.4 million, which balance includes a Crown royalty deposit claim of $5.5 million which, when refunded to Paramount, will be paid to Trilogy.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

·	Paramount recorded distributions from Trilogy Energy Trust totaling $21.0 million for the six months ended June 30, 2006. Distributions receivable of $3.0 million relating to distributions declared by Trilogy in June 2006 were accrued at June 30, 2006 and received in July 2006.

·	During the six months ended June 30, 2006, Paramount also had other transactions in the normal course of business with Trilogy.

DRILLING COMPANY

During the second quarter of 2006, Paramount and a private company controlled by a majority shareholder, director and officer of Paramount (the “Private Company”) formed a company in the United States (“Drillco”) to supply drilling services to a United States subsidiary of Paramount. Paramount owns 50 percent of Drillco, and the Private Company owns 50 percent of Drillco. Drillco has entered into a contract for the purchase of two drilling rigs. In connection with the purchase of the drilling rigs, the Private Company extended a demand loan totaling US$7.6 million to Drillco. The loan bears interest at a US bank’s Prime interest rate plus 0.5 percent. The amount of the loan, plus accrued interest is included in the Due to Related Parties balance in the consolidated financial statements.

DIRECTORS AND EMPLOYEES

Drillco has entered into a contract for the construction of two drilling rigs under a cost-plus fee arrangement with a company whose part-owner is a director of a company affiliated with Paramount. Estimated costs to construct the two drilling rigs total US$18 million, including a US$2 million fee due and payable to the supplier upon delivery.

During the second quarter of 2006 two officers and a director of Paramount participated in private equity placements undertaken by North American; purchasing an aggregate 146,667 shares of North American for $1.8 million.

DUE TO RELATED PARTIES

Due to related parties represent the amounts owing to the following related parties:

	June 30, 2006		December 31, 2005
Trilogy Energy Trust	$	2,406	$	6,439
Private Company		8,642		-
	$	11,048	$	6,439

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

11. Income Taxes

The following table reconciles income taxes calculated at the Canadian statutory rate with the actual income taxes:

	Six Months Ended June 30, 2006
Net Earnings Before Income Tax	$	127,720
Canadian Statutory Rate		34.8	%
Expected Income Tax		44,418

Effect on Taxes Resulting from:
Other current and large corporation tax		(626	)
Non-deductible Canadian crown payments		203
Canadian resource allowance		(252	)
Recognition of future tax asset		(18,973	)
Statutory and other rate differences		(978	)
Effect of tax rate changes		(308	)
Non-taxable capital gains		(19,778	)
Stock-based compensation		4,311
Other		65
	$	8,082
Effective Tax Rate		6.3	%

During the second quarter, the Canadian federal and Alberta governments substantively enacted income tax rate reductions.

12. Commitments

At June 30, 2006, Paramount was a party to the following physical commodity contracts:

	Amount		Price		Term
AECO Fixed Price		10,000 GJ/d		$6.40		July 2006 - October 2006
AECO Fixed Price		10,000 GJ/d		$6.58		July 2006 - October 2006

During the three months ended June 30, 2006, Paramount acquired an exploration license for a parcel of land in the Northwest Territories requiring a work commitment amounting to $6.3 million from Paramount.

As of July 1, 2006, Paramount acquired a right to use up to 25 MMcf/d capacity of a processing plant for a fee. Under the contract, Paramount has a use-or-pay obligation for 65 percent of the 25 MMcf/d capacity, 16.25 MMcf/d net.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

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

13. Subsequent Events

Subsequent to June 30, 2006, Paramount entered into the following forward commodity contracts:

		Amount	Price	Term
*Physical Sales Contract*
	AECO Fixed Price	10,000 GJ/d	$6.25	August 2006 - October 2006
*Physical Purchase Contracts*
	AECO Fixed Price	20,000 GJ/d	$5.37	September 2006 - October 2006
	AECO Fixed Price	20,000 GJ/d	$5.1725	July 2006 - August 2006
*Financial Sales Contract*
	NYMEX Fixed Price	10,000 MMBtu/d	US$10.00	November 2006 - March 2007
	NYMEX Fixed Price	10,000 MMBtu/d	US$10.875	November 2006 - March 2007

Advisories

Information included or incorporated be reference in this Press Release and the unaudited Interim Consolidated Financial Statements are presented in Canadian dollars unless otherwise stated.

FORWARD-LOOKING STATEMENTS AND ESTIMATES

Certain statements included or incorporated by reference in this Press Release constitute forward-looking statements under applicable securities legislation. Forward-looking statements or information typically contain statements with words such as "anticipate", "believe", "expect", "plan", "intend", "estimate", "propose", “forecast”, “opportunities”, “projects” or similar words suggesting future outcomes or statements regarding an outlook. Forward-looking statements or information in this document include but are not limited to estimates of future capital expenditures, business strategy and objectives, reserve quantities, net revenue, estimated future production levels, exploration, development and production plans and the timing thereof, operating and other costs, royalty rates, expectations of the timing and quantum of future cash income taxes, expectations as to how Paramount’s working capital deficit and planned 2006 capital program will be funded, expectations concerning the closing of the Facility and the expected timing thereof, the proceeds available under the Facility and the use thereof and the terms of the Facility, sensitivities to Paramount’s funds flow from changes in commodity prices, future exchange rates and rates of interest, estimated quantities and net present value of oil sands resources, the anticipated timing for seeking regulatory approvals, and expectations of growth in production reserves, undeveloped land and timing thereof.

Such forward-looking statements or information are based on a number of assumptions which may prove to be incorrect. In addition to other assumptions identified in this Press Release, assumptions have been made regarding, among other things:

·	the ability of Paramount to obtain equipment, services and supplies in a timely manner to carry out its activities;

·	the ability of Paramount to market oil and natural gas successfully to current and new customers;

·	the timing and costs of pipeline and storage facility construction and expansion and the ability to secure adequate product transportation;

·	the timely receipt of required regulatory approvals;

·	the ability of Paramount to obtain financing on acceptable terms;

·	currency, exchange and interest rates;

·	future oil and gas prices; and

·	that no significant cash taxes will be paid by Paramount in 2006.

Although Paramount believes that the expectations reflected in such forward-looking statements or information are reasonable, undue reliance should not be placed on forward-looking statements because Paramount can give no assurance that such expectations will prove to be correct. Forward-looking statements or information are based on current expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking statements or information. These risks and uncertainties include but are not limited to:

·	the ability of management to execute its business plan;

·	the risks of the oil and gas industry, such as operational risks in exploring for, developing and producing crude oil and natural gas and market demand;

·	risks and uncertainties involving geology of oil and gas deposits;

·	risks inherent in Paramount's marketing operations, including credit risk;

·	the uncertainty of reserves estimates and reserves life;

·	imprecision of resource estimates and life;

·	the uncertainty of estimates and projections relating to production, costs and expenses;

·	potential delays or changes in plans with respect to exploration or development projects or capital expenditures;

·	Paramount's ability to enter into or renew leases;

·	fluctuations in oil and gas prices, foreign currency exchange rates and interest rates;

·	health, safety and environmental risks;

·	uncertainties as to the availability and cost of financing;

·	the ability of Paramount to add production and reserves through development and exploration activities;

weather;

·	general economic and business conditions;

·	the possibility that government policies or laws may change or governmental approvals may be delayed or withheld;

·	uncertainty in amounts and timing of royalty payments;

·	change in taxation laws and regulations and the interpretation thereof;

·	risks associated with existing and potential future lawsuits and regulatory actions against Paramount; and

·	other risks and uncertainties described elsewhere in this document or in Paramount's other filings with Canadian securities authorities.

The forward-looking statements or information contained in this Press Release are made as of the date hereof and Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise, unless so required by applicable securities laws.

NON-GAAP MEASURES

In this Press Release, Paramount uses the term "funds flow from operations", “funds flow from operations per share - basic”, “funds flow from operations per share - diluted”, “operating netback”, “funds flow netback per Boe” and “net debt”, collectively the “Non-GAAP measures”, as indicators of Paramount's financial performance. The Non-GAAP measures do not have standardized meanings prescribed by GAAP and, therefore, are unlikely to be comparable to similar measures presented by other issuers.

“Funds flow from operations” is commonly used in the oil and gas industry to assist management and investors in measuring the Company’s ability to finance capital programs and meet financial obligations, and refers to cash flows from operating activities before net changes in operating working capital. “Funds flow from operations” includes distributions and dividends received on securities held by Paramount. The most directly comparable measure to “funds flow from operations” calculated in accordance with GAAP is cash flows from operating activities. “Funds flow from operations” can be reconciled to cash flows from operating activities by adding (deducting) the net change in operating working capital as shown in the consolidated statements of cash flows. “Funds flow netback per Boe” is calculated by dividing “funds flow from operations” by the total sales volume in Boe. “Operating netback” equals petroleum and natural gas sales less royalties, operating costs and transportation. “Net debt” is calculated as current liabilities minus current assets plus long-term debt and stock-based compensation liability associated with Holdco Options. Management of Paramount believes that the Non-GAAP measures provide useful information to investors as indicative measures of performance.

Investors are cautioned that the Non-GAAP Measures should not be considered in isolation or construed as alternatives to their most directly comparable measure calculated in accordance with GAAP, as set forth above, or other measures of financial performance calculated in accordance with GAAP.

BARRELS OF OIL EQUIVALENT CONVERSIONS

This Press Release contains disclosure expressed as “Boe”, “Boe/d”, “Mcf”, “MMcf/d”, “Bbl”, “Bbl/d”, “Bbls/d” and “MMBbl”. 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 equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head.

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

For further information, please contact:

Paramount Resources Ltd.

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

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

B.K. (Bernie) Lee, Chief Financial Officer

Phone: (403) 290-3600

Fax: (403) 262-7994