Paramount Resources Ltd. Announces Second Quarter 2023 Results

CALGARY, AB, Aug 2, 2023 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce second quarter 2023 financial and operating results.

HIGHLIGHTS

• Second quarter sales volumes averaged 88,243 Boe/d (45% liquids), reflecting an estimated 12,000 Boe/d impact of the Alberta wildfires. ⁽¹⁾
• Grande Prairie Region sales volumes averaged 66,950 Boe/d (51% liquids). Despite the wildfires, Karr achieved record quarterly sales volumes of approximately 44,000 Boe/d and Grande Prairie Region sales volumes exceeded 80,000 Boe/d on multiple days.
• Kaybob Region sales volumes averaged 13,238 Boe/d (24% liquids).
• Central Alberta and Other Region sales volumes averaged 8,055 Boe/d (30% liquids).
• Cash from operating activities was $172 million ($1.20 per basic share) in the second quarter. Adjusted funds flow was $179 million ($1.25 per basic share). ⁽²⁾
• Free cash flow was $31 million ($0.21 per basic share) in the second quarter. ⁽²⁾
• Capital expenditures in the quarter totaled $140 million. Activities were focused on development in the Grande Prairie Region where Paramount drilled nine (9.0 net) Montney wells, completed three (3.0 net) Montney wells and brought ten (10.0 net) Montney wells on production and in the Kaybob Region where the Company drilled and completed three (3.0 net) Duvernay wells.
• Abandonment and reclamation expenditures in the second quarter totaled $6 million. Activities in the quarter included the abandonment of 28 wells and reclamation of 18 well sites.
• At June 30, 2023, Paramount held $39 million in cash and cash equivalents and its revolving credit facility remained undrawn.
• The carrying value of the Company's investments in securities at June 30, 2023 was $490 million.

__________________________
(1)	In this press release, "liquids" refers to NGLs (including condensate) and oil combined, "natural gas" refers to shale gas and conventional natural gas combined, "condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude oil combined and "other NGLs" refers to ethane, propane and butane. See the "Product Type Information" section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil, tight oil and heavy crude oil. See also "Oil and Gas Measures and Definitions" in the Advisories section.
(2)	Adjusted funds flow and free cash flow are capital management measures used by Paramount. Cash from operating activities per basic share, adjusted funds flow per basic share and free cash flow per basic share are supplementary financial measures. Refer to the "Specified Financial Measures" section for more information on these measures.

UPDATED GUIDANCE

Paramount's operations in the Grande Prairie and Kaybob Regions were significantly interrupted by wildfires in the second quarter that necessitated the temporary shut-in of a number of fields and facilities. Although the wildfires did not result in any material property damage to Company owned assets or third-party infrastructure and have been extinguished, they had an estimated 6,000 Boe/d impact on first half 2023 sales volumes. This, combined with the impacts of other unplanned third-party facility downtime and the rescheduling of planned maintenance activities, resulted in first half 2023 sales volumes of 92,731 Boe/d (45% liquids) compared to prior guidance of 96,000 to 101,000 Boe/d (45% liquids).

The wildfires will have a residual effect on second half 2023 sales volumes as the Company restores the last of the 2,500 Boe/d of production in the Kaybob Region that remained curtailed at quarter end and the operators of third-party processing facilities proceed with turnarounds that were rescheduled from the second quarter, including an 11-day planned outage in Wapiti. In addition, the onstream timing of nine (9.0 net) Duvernay wells on two separate pad sites at Kaybob North has been delayed, on average, by approximately four weeks due to second quarter evacuation orders associated with the wildfires.

The Company is revising its 2023 second half and annual sales volumes guidance to account for the impacts of the wildfires and the temporary shut-in of low margin dry natural gas production and its 2023 free cash flow guidance to reflect the revised sales volumes. 2023 capital expenditure guidance remains unchanged.

2023 Guidance
	Prior Guidance	Revised Guidance
Annual average sales volumes (Boe/d)	100,000 to 105,000 (46% liquids)	95,000 to 98,000 (46% liquids)
Second half average sales volumes (Boe/d)	104,000 to 109,000 (47% liquids)	98,000 to 102,000 (47% liquids)
Capital expenditures	$700 to $750 million (~50% to growth)	No change
Abandonment and reclamation expenditures	$55 million	No change
Free cash flow ^(1)	$335 million	$185 million

The Company is reaffirming its preliminary 2024 sales volumes, capital expenditure and free cash flow guidance.

Preliminary 2024 Guidance^(2)
Annual average sales volumes (Boe/d)	110,000 to 120,000 (48% liquids)
Capital expenditures	$700 to $800 million (~50% to growth)
Abandonment and reclamation expenditures	$40 million
Free cash flow^(3)	$445 million

________________________________________
(1)	Free cash flow is a capital management measure used by Paramount. Refer to "Advisories - Specified Financial Measures" for more information on this measure. The stated free cash flow forecast is based on the following assumptions for 2023: (i) the midpoint of stated capital expenditures and annual sales volumes, (ii) $55 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $53.55/Boe (US$77.48/Bbl WTI, US$3.14/MMBtu NYMEX, $3.11/GJ AECO), (v) a $US/$CAD exchange rate of $0.749, (vi) royalties of $7.90/Boe, (vii) operating costs of $12.60/Boe and (vii) transportation and processing costs of $4.00/Boe. Assumed pricing of US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX and $3.08/GJ AECO and an assumed $US/$CAD exchange rate of $0.755 for the second half of 2023 is unchanged from previous guidance, but the stated amounts have been adjusted to incorporate actual results for the first half of 2023.
(2)	All 2024 guidance is based on preliminary planning and current market conditions and is subject to change.
(3)	The stated free cash flow estimate is based on the following assumptions for 2024: (i) the midpoint of stated capital expenditures and sales volumes, (ii) $40 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $53.60/Boe (US$75.00/Bbl WTI, US$3.50/MMBtu NYMEX, $3.08/GJ AECO), (v) a $US/$CAD exchange rate of $0.755, (vi) royalties of $8.10/Boe, (vii) operating costs of $11.20/Boe and (vii) transportation and processing costs of $3.60/Boe.

Paramount continues to expect that capital expenditures in 2023 and 2024 will be evenly split between sustaining and maintenance capital and growth capital. If required, the Company will utilize available capacity under its $1.0 billion senior secured credit facility, which was undrawn at quarter end, to fund any portion of the 2023 growth capital not funded from adjusted funds flow. In 2024, based on forecast assumptions, the Company's total preliminary midpoint 2024 capital program, abandonment and reclamation expenditures, geological and geophysical expenses and regular monthly dividend would be fully funded from adjusted funds flow with an estimated excess of approximately $230 million. 

Paramount remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices, inflationary cost pressures and other factors.

AUGUST DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.125 per Common Share that will be payable on August 31, 2023 to shareholders of record on August 15, 2023. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

Sales volumes and netbacks in the Grande Prairie Region are summarized below:

		Q2 2023				Q1 2023		% Change
Sales Volumes
Natural gas (MMcf/d)		196.4				204.4		(4)
Condensate and oil (Bbl/d)		30,205				31,367		(4)
Other NGLs (Bbl/d)		4,012				4,074		(2)
Total (Boe/d)		66,950				69,507		(4)
% liquids		51 %				51 %
Netback ^(1)	($ millions)		($/Boe)		($ millions)		($/Boe)	Change in $ millions (%)
Natural gas revenue ^(2)	43.3		2.42		79.4		4.31	(45)
Condensate and oil revenue	260.5		94.76		286.9		101.64	(9)
Other NGLs revenue	11.7		31.99		16.9		46.21	(31)
Royalty and other revenue	0.3		–		–		–	NM
Petroleum and natural gas sales	315.8		51.83		383.2		61.26	(18)
Royalties	(39.3)		(6.45)		(56.7)		(9.07)	(31)
Operating expense	(70.7)		(11.61)		(70.3)		(11.24)	1
Transportation and NGLs processing	(27.2)		(4.47)		(28.7)		(4.58)	(5)
	178.6		29.30		227.5		36.37	(21)

(1)	"Netback" is a Non-GAAP financial measure. When presented on a $/Boe or $/Mcf basis, each of the components of Netback is a supplementary financial measure and Netback is a non-GAAP ratio. Refer to the "Specified Financial Measures" section for more information on these measures.
(2)	Per unit natural gas revenue presented as $/Mcf.
NM means not meaningful

Second quarter 2023 sales volumes in the Grande Prairie Region averaged 66,950 Boe/d (51% liquids) compared to 69,507 Boe/d (51% liquids) in the first quarter of 2023. 

Wildfires impacted Grande Prairie Region sales volumes by an estimated 6,000 Boe/d in the second quarter, including full shutdowns at Wapiti that lasted a total of approximately two weeks as well as other wildfire-related curtailments at Karr. Second quarter sales volumes were also impacted by an eight-day 50% maintenance-related curtailment at the third-party operated Wapiti natural gas processing plant (the "Wapiti Plant"), which had originally been scheduled for the fourth quarter, as well as unplanned downtime at the third-party Karr facility late in the quarter to accommodate maintenance activities. Notwithstanding these challenges, Karr achieved record quarterly sales volumes of approximately 44,000 Boe/d and Grande Prairie Region sales volumes exceeded 80,000 Boe/d on multiple days in the quarter.

Development activities in the Grande Prairie Region in the second quarter included the drilling of nine (9.0 net) Montney wells and the completion of three (3.0 net) Montney wells.

At Karr, all ten (10.0 net) wells on the 4-2 pad were brought on production in the second quarter. Production results from these wells are ahead of expectations, averaging gross peak 30-day production per well of 2,078 Boe/d (5.4 MMcf/d of shale gas and 1,174 Bbl/d of NGLs) with an average CGR of 217 Bbl/MMcf. ⁽¹⁾

The Company finished drilling three wells on the five (5.0 net) well 7-33 South pad at Karr in the second quarter. Completion operations commenced in July and all five wells are expected to be brought on production in the third quarter. Drilling of the three (3.0 net) well 6-36 pad at Karr commenced in the third quarter and these wells are now expected to be brought onstream in the fourth quarter.

At Wapiti, Paramount completed the three (3.0 net) well 1-27 pad in the second quarter and these wells are expected to be brought onstream in the third quarter. The Company also finished drilling the eight (8.0 net) well 8-15 pad in the second quarter and these wells are expected to be brought onstream in the fourth quarter. Drilling of the eight (8.0 net) well 14-5 pad that is expected to be brought onstream in 2024 also commenced in the second quarter.

The 11-day planned outage at the Wapiti Plant that was previously scheduled for the second quarter has now been deferred to the fourth quarter due to the wildfires.

KAYBOB REGION

Kaybob Region sales volumes averaged 13,238 Boe/d (24% liquids) in the second quarter of 2023 compared to 19,201 Boe/d (29% liquids) in the first quarter of 2023. Wildfires impacted second quarter Kaybob Region sales volumes by an estimated 6,000 Boe/d. Approximately 750 Boe/d of the 2,500 Boe/d Kaybob Region production that remained curtailed at quarter end has now been restored, with the remaining production expected to be back online prior to the end of September as third-party power line repairs are completed.

Development activities in the second quarter included the completion of three (3.0 net) Duvernay wells on the Kaybob North Duvernay 4-13 pad. The wells on this pad have the longest average well length by measured depth in the Company's history and include the single longest well at approximately 7,800 meters of total measured depth. All three wells, which were delayed by wildfire related evacuation orders, were recently brought on production at initial rates significantly exceeding expectations.

The Company has elected to drill an additional well at the Kaybob North Duvernay 15-7 pad, bringing the total number of wells to be drilled on the pad in 2023 to six (6.0 net). As a result of delays caused by the wildfires and the addition of this well, the 15-7 pad is now anticipated to be brought onstream in the first quarter of 2024, approximately two months later than previously planned.

______________________________________

(1)

Production measured at the wellhead. Natural gas sales volumes were lower by approximately 11% and liquids sales volumes were lower by approximately 6% due to shrinkage. Excludes days when the wells did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See "Oil and Gas Measures and Definitions" in the Advisories section.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 8,055 Boe/d (30% liquids) in the second quarter of 2023 compared to 8,561 Boe/d (32% liquids) in the first quarter 2023.

The drilling of four (4.0 net) Duvernay wells at Willesden Green commenced late in the second quarter. The Company plans to complete all four wells over the second half of 2023 and bring the wells on production in the first quarter of 2024 to coincide with the start-up of the planned liquids handling expansion at the Leafland natural gas processing plant. Paramount continues to anticipate commencing the drilling of an additional four Duvernay wells late in the fourth quarter at Willesden Green. 

HEDGING

The Company's current commodity and foreign exchange contracts are summarized below:

Q3 2023

Q4 2023

2024

Average Price ^(1)

Oil

Sweet Crude Oil – Basis (Physical Sale) (Bbl/d) ^(2)

3,078

3,078

­–

WTI – US$3.73/Bbl

Natural Gas

AECO – Basis (Physical Sale) (MMBtu/d)

50,000

16,848

–

NYMEX – US$0.93/MMBtu

Dawn – Basis (Physical Sale) (MMBtu/d)

25,000

8,424

–

NYMEX – US$0.20/MMBtu

Foreign Currency Exchange

Swaps (US$MM/Month)

$40

$40

–

1.3427 CAD$ / US$

Swaps (US$MM/Month)

–

–

$20

1.3425 CAD$ / US$

(1)	Average price is calculated using a weighted average of notional volumes and prices. "NYMEX" refers to NYMEX pricing at Henry Hub.
(2)	Sweet crude oil located at the Peace Pipeline at Edmonton.

ABOUT PARAMOUNT

Paramount is an independent, publicly traded, liquids-rich natural gas focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's Common Shares are listed on the Toronto Stock Exchange under the symbol "POU".

Paramount's second quarter 2023 results, including Management's Discussion and Analysis and the Company's Consolidated Financial Statements, can be obtained on SEDAR at www.sedar.com or on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.

A summary of historical financial and operating results is also available on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.

Financial and operating results ⁽¹⁾

($ millions, except as noted)		Q2 2023			Q1 2023			Q2 2022
Net income		74.2			197.0			182.2
per share – basic ($/share)		0.52			1.39			1.29
per share – diluted ($/share)		0.50			1.33			1.24
Cash from operating activities		172.2			271.4			318.9
per share – basic ($/share)		1.20			1.91			2.26
per share – diluted ($/share)		1.16			1.84			2.16
Adjusted funds flow		178.7			268.2			258.3
per share – basic ($/share)		1.25			1.89			1.83
per share – diluted ($/share)		1.21			1.81			1.75
Free cash flow		30.5			59.8			68.3
per share – basic ($/share)		0.21			0.42			0.48
per share – diluted ($/share)		0.21			0.40			0.46
Total assets		4,106.6			4,114.6			4,076.2
Investments in securities		489.9			498.3			468.8
Long-term debt		–			–			227.7
Net (cash) debt		2.3			(43.6)			374.0
Common shares outstanding (millions) ^(2)		143.1			142.4			141.2
Sales volumes ^(3)
Natural gas (MMcf/d)		290.2			320.6			267.2
Condensate and oil (Bbl/d)		34,230			37,916			27,750
Other NGLs (Bbl/d)		5,648			5,916			5,021
Total (Boe/d)		88,243			97,269			77,312
% liquids		45 %			45 %			42 %
Grande Prairie Region (Boe/d)		66,950			69,507			48,736
Kaybob Region (Boe/d)		13,238			19,201			21,642
Central Alberta & Other Region (Boe/d)		8,055			8,561			6,934
Total (Boe/d)		88,243			97,269			77,312
Netback			($/Boe) ^(4)			($/Boe) ^(4)			($/Boe) ^(4)
Natural gas revenue	64.1		2.43	122.0		4.23	164.0		6.75
Condensate and oil revenue	294.1		94.42	343.5		100.66	340.0		134.65
Other NGLs revenue	15.9		30.86	23.4		43.93	28.7		62.80
Royalty and other revenue	0.3		–	0.8		–	3.5		–
Petroleum and natural gas sales	374.4		46.63	489.7		55.94	536.2		76.22
Royalties	(41.2)		(5.12)	(69.1)		(7.90)	(85.2)		(12.11)
Operating expense	(104.6)		(13.03)	(108.8)		(12.43)	(88.7)		(12.61)
Transportation and NGLs processing	(33.6)		(4.19)	(36.3)		(4.15)	(30.8)		(4.37)
Sales of commodities purchased ^(5)	47.7		5.94	115.1		13.15	42.7		6.06
Commodities purchased ^(5)	(49.3)		(6.15)	(114.3)		(13.05)	(41.1)		(5.84)
Netback	193.4		24.08	276.3		31.56	333.1		47.35
Risk management contract settlements	(2.7)		(0.33)	6.1		0.70	(61.9)		(8.79)
Netback including risk management contract settlements	190.7		23.75	282.4		32.26	271.2		38.56
Capital expenditures
Grande Prairie Region		66.0			121.1			107.2
Kaybob Region		45.5			39.0			57.9
Central Alberta & Other Region		17.1			5.6			0.8
Fox Drilling and Cavalier Energy		7.6			12.7			3.7
Corporate		4.0			5.7			14.5
Total		140.2			184.1			184.1
Asset retirement obligations settled		5.9			21.8			4.0

(1)	Adjusted funds flow, free cash flow and net (cash) debt are capital management measures used by Paramount. Netback and netback including risk management contract settlements are non-GAAP financial measures. Netback and Netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each measure, other than net income, that is presented on a per share, $/Mcf or $/Boe basis is a supplementary financial measure. Refer to the "Specified Financial Measures" section for more information on these measures.
(2)	Common shares are presented net of shares held in trust under the Company's restricted share unit plan: Q2 2023: 0.4 million, Q1 2023: 0.8 million, Q2 2022: 0.8 million.
(3)	Refer to the Product Type Information section of this document for a complete breakdown of sales volumes for applicable periods by specific product type.
(4)	Natural gas revenue presented as $/Mcf.
(5)	Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties

PRODUCT TYPE INFORMATION

This press release includes references to sales volumes of "natural gas", "condensate and oil", "NGLs", "Other NGLs" and "liquids". "Natural gas" refers to shale gas and conventional natural gas combined. "Condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude oil combined. "NGLs" refers to condensate and Other NGLs combined. "Other NGLs" refers to ethane, propane and butane. "Liquids" refers to condensate and oil and Other NGLs combined. Below is a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil, tight oil and heavy crude oil. Numbers may not add due to rounding.

	Total Company by Product Type
	Q2 2023		Q1 2023		Q2 2022
Shale gas (MMcf/d)	246.0		265.2		203.7
Conventional natural gas (MMcf/d)	44.2		55.4		63.5
Natural gas (MMcf/d)	290.2		320.6		267.2
Condensate (Bbl/d)	32,341		34,706		25,374
Other NGLs (Bbl/d)	5,648		5,916		5,021
NGLs (Bbl/d)	37,989		40,622		30,395
Light and medium crude oil (Bbl/d)	942		2,151		1,974
Tight oil (Bbl/d)	538		599		402
Heavy crude oil (Bbl/d)	409		460		–
Crude oil (Bbl/d)	1,889		3,210		2,376
Total (Boe/d)	88,243		97,269		77,312

	Grande Prairie Region						Kaybob Region						Central Alberta and Other Region
	Q2 2023		Q1 2023		Q2 2022		Q2 2023		Q1 2023		Q2 2022		Q2 2023		Q1 2023		Q2 2022
Shale gas (MMcf/d)	196.1		204.0		138.8		21.7		31.8		37.9		28.2		29.4		27.0
Conventional natural gas (MMcf/d)	0.3		0.4		1.0		38.4		49.6		56.7		5.5		5.4		5.8
Natural gas (MMcf/d)	196.4		204.4		139.8		60.1		81.4		94.6		33.7		34.8		32.8
Condensate (Bbl/d)	30,046		31,367		22,511		1,301		2,315		2,092		994		1,024		771
Other NGLs (Bbl/d)	4,012		4,074		2,914		891		988		1,585		745		854		522
NGLs (Bbl/d)	34,058		35,441		25,425		2,192		3,303		3,677		1,739		1,878		1,293
Light and medium crude oil (Bbl/d)	–		–		5		914		2,121		1,946		28		30		23
Tight oil (Bbl/d)	159		–		–		115		206		253		264		393		149
Heavy crude oil (Bbl/d)	–		–		–		–		–		–		409		460		–
Crude oil (Bbl/d)	159		–		5		1,029		2,327		2,199		701		883		172
Total (Boe/d)	66,950		69,507		48,736		13,238		19,201		21,642		8,055		8,561		6,934

The Company forecasts that 2023 annual sales volumes will average between 95,000 Boe/d and 98,000 Boe/d (54% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% other NGLs). Second half 2023 sales volumes are expected to average between 98,000 Boe/d and 102,000 Boe/d (53% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% other NGLs). The Company's preliminary 2024 guidance provides for annual sales volumes that will average between 110,000 Boe/d and 120,000 Boe/d (52% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% other NGLs).

SPECIFIED FINANCIAL MEASURES

Non-GAAP Financial Measures

Netback and netback including risk management contract settlements are non-GAAP financial measures. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.

Netback equals petroleum and natural gas sales (the most directly comparable measure disclosed in the Company's primary financial statements) plus sales of commodities purchased less royalties, operating expense, transportation and NGLs processing expense and commodities purchased. Sales of commodities purchased and commodities purchased are treated as Corporate items and not are allocated to individual regions or properties. Netback is used by investors and Management to compare the performance of the Company's producing assets between periods.

Netback including risk management contract settlements equals netback after including (or deducting) risk management contract settlements received (paid). Netback including risk management contract settlements is used by investors and Management to assess the performance of the producing assets after incorporating Management's risk management strategies.

Refer to the table under the heading "Financial and Operating Results" in this press release for the calculation of netback and netback including risk management contract settlements for the three months ended June 30, 2023, March 31, 2023 and June 30, 2022.

Non-GAAP Ratios

Netback and netback including risk management contract settlements presented on a $/Boe basis are non-GAAP ratios as they each have a non-GAAP financial measure (netback and netback including risk management contract settlements, respectively) as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.

Netback on a $/Boe basis is calculated by dividing netback for the applicable period by the total production during the period in Boe. Netback including risk management contract settlements on a $/Boe basis is calculated by dividing netback including risk management contract settlements for the applicable period by the total production during the period in Boe. These measures are used by investors and management to assess netback and netback including risk management contract settlements on a unit of production basis.

Capital Management Measures

Adjusted funds flow, free cash flow and net (cash) debt are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities.  Refer to Note 15 – Capital Structure in the unaudited Interim Condensed Consolidated Financial Statements of Paramount as at and for the three and six months ended June 30, 2023 for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three and six months ended June 30, 2023 and 2022 and (iii) a calculation of net (cash) debt as at June 30, 2023 and December 31, 2022.

Supplementary Financial Measures

This press release contains supplementary financial measures expressed as: (i) cash from operating activities, adjusted funds flow and free cash flow on a per share – basic and per share – diluted basis and (ii) petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf basis.

Cash from operating activities, adjusted funds flow and free cash flow on a per share – basic basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average basic shares outstanding during the period determined under IFRS. Cash from operating activities, adjusted funds flow and free cash flow on a per share – diluted basis are calculated by dividing cash from operating activities, adjusted funds flow or free cash flow, as applicable, over the referenced period by the weighted average diluted shares outstanding during the period determined under IFRS.

Petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf basis are calculated by dividing the petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expense, sales of commodities purchased or commodities purchased, as applicable, over the referenced period by the aggregate units (Boe or Mcf) produced during such period.

ADVISORIES

Forward-looking Information

Certain statements in this press release constitute forward-looking information under applicable securities legislation. Forward-looking information typically contains statements with words such as "anticipate", "believe", "estimate", "will", "expect", "plan", "schedule", "intend", "propose", or similar words suggesting future outcomes or an outlook. Forward-looking information in this press release includes, but is not limited to:

• forecast sales volumes for 2023 and certain periods therein;
• planned capital expenditures in 2023;
• planned abandonment and reclamation expenditures in 2023;
• forecast free cash flow in 2023;
• preliminary 2024 sales volumes, capital expenditures, abandonment and reclamation expenditures and free cash flow guidance;
• the expectation that capital expenditures in 2023 and 2024 will be evenly split between sustaining and maintenance capital and growth capital;
• the statement that the Company will, if required, utilize available capacity under the Company's $1.0 billion senior secured credit facility to fund any portion of the 2023 growth capital not funded from adjusted funds flow;
• the statement that, based on forecast assumptions, the Company's total preliminary midpoint 2024 capital program, abandonment and reclamation expenditures, geological and geophysical expenses and regular monthly dividend would be fully funded from adjusted funds flow with an estimated excess of $230 million;
• planned exploration, development and production activities, including the expected timing of drilling, completing and bringing new wells on production, and the expected timing of a planned outage at the Wapiti Plant;
• the expectation that the remaining production at Kaybob curtailed as a result of the wildfires will be back online prior to the end of September; and
• the potential payment of future dividends.

Such forward-looking information is based on a number of assumptions which may prove to be incorrect. Assumptions have been made with respect to the following matters, in addition to any other assumptions identified in this press release:

• future commodity prices;
• the impact of the Russian invasion of the Ukraine;
• royalty rates, taxes and capital, operating, general & administrative and other costs;
• foreign currency exchange rates, interest rates and the rate and impacts of inflation;
• general business, economic and market conditions;
• the performance of wells and facilities;
• the availability to Paramount of the required capital to fund its exploration, development and other operations and meet its commitments and financial obligations;
• the ability of Paramount to obtain equipment, materials, services and personnel in a timely manner and at expected and acceptable costs to carry out its activities;
• the ability of Paramount to secure adequate processing, transportation, fractionation and storage capacity on acceptable terms and the capacity and reliability of facilities;
• the ability of Paramount to market its production successfully;
• the ability of Paramount and its industry partners to obtain drilling success (including in respect of anticipated production volumes, reserves additions, product yields and resource recoveries) and operational improvements, efficiencies and results consistent with expectations;
• the timely receipt of required governmental and regulatory approvals, including approvals required for the expansion and construction of facilities at Willesden Green;
• the application of regulatory requirements respecting abandonment and reclamation; and
• anticipated timelines and budgets being met in respect of drilling programs and other operations (including well completions and tie-ins, the construction, commissioning and start-up of new and expanded facilities, including facilities at Willesden Green, and facility turnarounds and maintenance).

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct. Forward-looking information is based on 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 information. The material risks and uncertainties include, but are not limited to:

• fluctuations in commodity prices;
• changes in capital spending plans and planned exploration and development activities;
• the potential for changes to preliminary 2024 sales volumes, capital expenditures, abandonment and reclamation expenditures and free cash flow guidance prior to finalization;
• changes in foreign currency exchange rates, interest rates and the rate of inflation;
• the uncertainty of estimates and projections relating to production, future revenue, free cash flow, reserve additions, product yields (including condensate to natural gas ratios), resource recoveries, royalty rates, taxes and costs and expenses;
• the ability to secure adequate processing, transportation, fractionation, and storage capacity on acceptable terms;
• operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts;
• the ability to obtain equipment, materials, services and personnel in a timely manner and at expected and acceptable costs, including the potential effects of inflation and supply chain disruptions;
• potential disruptions, delays or unexpected technical or other difficulties in designing, developing, expanding or operating new, expanded or existing facilities (including third-party facilities);
• processing, pipeline, and fractionation infrastructure outages, disruptions and constraints;
• risks and uncertainties that may result in changes to the planned expansion and construction of facilities at Willesden Green, including the potential for changes to facility design or the timelines for construction prior to finalization or the failure to obtain required governmental and regulatory approvals;
• risks and uncertainties involving the geology of oil and gas deposits;
• the uncertainty of reserves estimates;
• general business, economic and market conditions;
• the ability to generate sufficient cash from operating activities to fund, or to otherwise finance, planned exploration, development and operational activities and meet current and future commitments and obligations (including processing, transportation, fractionation and similar commitments and obligations);
• changes in, or in the interpretation of, laws, regulations or policies (including environmental laws);
• the ability to obtain required governmental or regulatory approvals in a timely manner, and to obtain and maintain leases and licenses;
• the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access;
• uncertainties as to the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination;
• uncertainties regarding Indigenous claims and in maintaining relationships with local populations and other stakeholders;
• the outcome of existing and potential lawsuits, insurance claims, regulatory actions, audits and assessments; and
• other risks and uncertainties described elsewhere in this document and in Paramount's other filings with Canadian securities authorities.

There are risks that may result in the Company changing, suspending or discontinuing its monthly dividend program, including changes to free cash flow, operating results, capital requirements, financial position, market conditions or corporate strategy and the need to comply with requirements under debt agreements and applicable laws respecting the declaration and payment of dividends. There are no assurances as to the continuing declaration and payment of future dividends by the Company or the amount or timing of any such dividends.

The foregoing list of risks is not exhaustive. For more information relating to risks, see the section titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2022, which is available on SEDAR at www.sedar.com or on the Company's website at www.paramountres.com. The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, 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.

Certain forward-looking information in this press release, including forecast free cash flow in 2023 and future periods, may also constitute a "financial outlook" within the meaning of applicable securities laws. A financial outlook involves statements about Paramount's prospective financial performance or position and is based on and subject to the assumptions and risk factors described above in respect of forward-looking information generally as well as any other specific assumptions and risk factors in relation to such financial outlook noted in this press release. Such assumptions are based on management's assessment of the relevant information currently available and any financial outlook included in this press release is provided for the purpose of helping readers understand Paramount's current expectations and plans for the future. Readers are cautioned that reliance on any financial outlook may not be appropriate for other purposes or in other circumstances and that the risk factors described above or other factors may cause actual results to differ materially from any financial outlook.

Oil and Gas Measures and Definitions

Liquids						Natural Gas
Bbl			Barrels			GJ	Gigajoules
Bbl/d			Barrels per day			GJ/d	Gigajoules per day
MBbl			Thousands of barrels			MMBtu	Millions of British Thermal Units
NGLs			Natural gas liquids			MMBtu/d	Millions of British Thermal Units per day
Condensate			Pentane and heavier hydrocarbons			Mcf	Thousands of cubic feet
WTI			West Texas Intermediate			MMcf	Millions of cubic feet
						MMcf/d	Millions of cubic feet per day
Oil Equivalent						AECO	AECO-C reference price
Boe		Barrels of oil equivalent
MBoe		Thousands of barrels of oil equivalent
MMBoe	Millions of barrels of oil equivalent
Boe/d	Barrels of oil equivalent per day

This press release contains disclosures expressed as "Boe", "$/Boe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. 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. For the six months ended June 30, 2023, the value ratio between crude oil and natural gas was approximately 31:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.

Additional information respecting the Company's oil and gas properties and operations is provided in the Company's annual information form for the year ended December 31, 2022 which is available on SEDAR at www.sedar.com.

SOURCE Paramount Resources Ltd.

Paramount Resources Ltd., J.H.T. (Jim) Riddell, President and Chief Executive Officer and Chairman, Paul R. Kinvig, Chief Financial Officer; Rodrigo (Rod) Sousa, Executive Vice President, Corporate Development and Planning, www.paramountres.com, Phone: [phone]