Paramount Resources Ltd. Announces First Quarter 2024 Results and 20% Dividend Increase

CALGARY, AB, May 2, 2024 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its first quarter 2024 financial and operating results, highlighted by strong contributions from its Duvernay developments at Kaybob North and Willesden Green. The Company is also pleased to announce that it is increasing its regular monthly dividend by 20% from $0.125 per class A common share ("Common Share") to $0.15 per Common Share beginning May 2024.

HIGHLIGHTS

• First quarter sales volumes averaged 100,977 Boe/d (47% liquids). ⁽¹⁾
  • Grande Prairie Region sales volumes averaged 67,163 Boe/d (50% liquids). As previously disclosed, first quarter production was impacted by cold weather, intermittent run time at key facilities and other operational challenges. Production has since been largely restored and the Company has begun to realize benefits from the aggressive well optimization program it initiated in March 2024.
  • Kaybob Region sales volumes increased to 22,353 Boe/d (42% liquids), driven by a new six well Duvernay pad brought onstream at Kaybob North in the first quarter that more than offset the impact of the previously disclosed non-core asset disposition (the "2024 Kaybob Disposition").
  • Central Alberta and Other Region sales volumes increased to 11,461 Boe/d (44% liquids) as a result of production from four Duvernay wells brought onstream in late-2023 and January 2024.
  • Combined, the Company's Duvernay sales volumes in the Kaybob Region and at Willesden Green increased to over 12,000 Boe/d in the first quarter, more than double fourth quarter 2023 Duvernay sales volumes. This production is approximately 70% liquids and is processed through Company owned facilities, resulting in the highest per Boe netback corporately.
• Cash from operating activities was $201 million ($1.39 per basic share) in the first quarter. Adjusted funds flow was $226 million ($1.56 per basic share). Free cash flow was ($10) million (($0.07) per basic share). ⁽²⁾

__________________________
(1)	In this press release, "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, "Other NGLs" refers to ethane, propane and butane and "liquids" refers to condensate and oil and Other NGLs combined.  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.

• First quarter capital expenditures totaled $214 million. Significant activities included:
  • Grande Prairie Region (Montney) – nine (9.0 net) wells drilled, four (4.0 net) wells brought on production and ongoing construction of a new compressor node;
  • Kaybob Region (Duvernay) – four (4.0 net) wells drilled and six (6.0 net) wells brought on production; and
  • Central Alberta and Other Region (Duvernay) – two (2.0 net) wells drilled, two (2.0 net) wells brought on production and commenced construction of the Company's second natural gas processing plant at Willesden Green.
• Asset retirement obligations settled in the first quarter totaled $17 million, on track with budget. Activities in the quarter included the abandonment of 26 wells and the reclamation of 17 sites.
• Paramount closed the 2024 Kaybob Disposition in February 2024 for cash proceeds of $46 million while retaining a 2% no-deduction gross overriding royalty on the undeveloped Montney acreage forming part of the assets.
• At March 31, 2024, net debt was $68 million and Paramount's $1.0 billion revolving credit facility was undrawn. ⁽¹⁾
• The carrying value of the Company's investments in securities at March 31, 2024 was $569 million. In April 2024, Paramount sold 6 million common shares of NuVista Energy Ltd. for cash proceeds of $75 million.
• In April 2024, Paramount hedged 14,250 Bbl/d of liquids sales volumes for the remainder of 2024 at an average WTI price of CAD$111.67/Bbl, re-establishing a hedging position similar to that monetized for approximately $45 million in the fourth quarter of 2023.

INCREASED DIVIDEND

Paramount's Board of Directors has approved a 20% increase in the regular monthly dividend from $0.125 to $0.15 per Common Share.  The Company continues to prioritize the delivery of shareholder returns through a combination of dividends and organic growth while maintaining a strong balance sheet.  This is the fifth increase in the regular monthly dividend since it was implemented in July 2021.

• The first increased dividend of $0.15 per Common Share will be payable on May 31, 2024 to shareholders of record on May 15, 2024.  The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

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(1)	Net (cash) debt is a capital management measure used by Paramount.  This capital management measure has been expressed as net debt in this instance for simplicity as the amount referenced is a positive number.  Refer to the "Specified Financial Measures" section for more information on this measure.

GUIDANCE

Paramount is reaffirming its 2024 sales volumes, capital expenditure and abandonment and reclamation expenditure guidance.  The Company is updating its forecast of 2024 free cash flow from $235 million to $205 million to reflect first quarter results.  Pricing assumptions for the final three quarters of 2024 remain unchanged at US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX and $2.84/GJ AECO. 

	2024 Guidance
Annual average sales volumes (Boe/d)	100,000 to 106,000 (47% liquids)
First half 2024 (Boe/d)	96,000 to 100,000 (47% liquids)
Second half 2024 (Boe/d)	104,000 to 112,000 (47% liquids)
Capital expenditures	$830 to $890 million
Sustaining and Maintenance	$415 to $445 million
Growth	$415 to $445 million
Abandonment and reclamation expenditures	$40 million
Free cash flow ^(1)	$205 million

The Company's midpoint 2024 capital program, abandonment and reclamation expenditures and increased regular monthly dividend is more than fully funded under the above forecast, when combined with cash proceeds from dispositions realized year-to-date. The Company's midpoint 2024 sustaining and maintenance capital program, abandonment and reclamation expenditures and increased regular monthly dividend would remain fully funded down to an average WTI price for the remaining three quarters of 2024 of about US$45/Bbl, assuming no changes to the other forecast assumptions. See "Advisories – Pricing Sensitivity" for additional sensitivities of 2024 free cash flow to changes in commodity price assumptions.

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(1)

Free cash flow is a capital management measure used by Paramount.  Refer to the " Specified Financial Measures" section for more information on this measure. The stated free cash flow forecast 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) $10 million in geological and geophysical expenses, (iv) realized pricing of $55.85/Boe; (v) a $US/$CAD exchange rate of $0.737, (vi) royalties of $8.10/Boe, (vii) operating costs of $13.30/Boe and (vii) transportation and NGLs processing costs of $3.65/Boe.  Assumed pricing of US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX and $2.84/GJ AECO and an assumed $US/$CAD exchange rate of $0.735 for the remaining three quarters of 2024 is unchanged from previous guidance, but the stated amounts have been adjusted to incorporate actual results for the first quarter of 2024.

REVIEW OF OPERATIONS

Grande Prairie Region

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

	Q1 2024		Q4 2023		% Change
Sales Volumes
Natural gas (MMcf/d)	201.8		214.4		(6)
Condensate and oil (Bbl/d)	29,202		32,382		(10)
Other NGLs (Bbl/d)	4,334		4,742		(9)
Total (Boe/d)	67,163		72,860		(8)
% liquids	50 %		51 %
Netback ^(1)	($ millions)	($/Boe)	($ millions)	($/Boe)	Change in $ millions (%)
Natural gas revenue ^(2)	53.0	2.89	56.2	2.85	(6)
Condensate and oil revenue	248.0	93.32	295.0	99.00	(16)
Other NGLs revenue	15.7	39.70	16.1	36.95	(2)
Royalty income and other revenue	–	–	0.1	–	NM
Petroleum and natural gas sales	316.7	51.81	367.4	54.81	(14)
Royalties	(50.8)	(8.32)	(56.8)	(8.47)	(11)
Operating expense	(80.1)	(13.11)	(84.1)	(12.54)	(5)
Transportation and NGLs processing	(22.6)	(3.69)	(26.0)	(3.88)	(13)
	163.2	26.69	200.5	29.92	(19)

(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

Sales volumes in the Grande Prairie Region averaged 67,163 Boe/d (50% liquids) in the first quarter of 2024 compared to 72,860 Boe/d (51% liquids) in the fourth quarter of 2023.  As previously disclosed, first quarter production was impacted by cold weather, intermittent run time at key facilities and other operational challenges that significantly affected production from a number of wells, including the five well Karr 07-33S pad.  New well production that came onstream in early March partly offset these impacts.

Paramount commenced an aggressive well optimization program in the Grande Prairie Region in March 2024 to increase production from shut-in wells and wells that would benefit from intervention.  This has included, among other well interventions, workover operations on the Karr 07-33S pad that have yielded positive initial results.

Average gross 30-day peak production per well from the eight (8.0 net) well Montney pad at Wapiti that came onstream in November 2023 was 1,164 Boe/d (2.7 MMcf/d of shale gas and 708 Bbl/d of NGLs) with an average CGR of 259 Bbl/MMcf. ⁽¹⁾  These results are lower than expected primarily due to challenging operating circumstances, including downhole equipment failures and high gathering system pressures, that the Company is addressing.

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(1)

30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well 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.  Natural gas sales volumes were lower by approximately 9% and liquids sales volumes were lower by approximately 2% due to shrinkage.

First quarter development activities in the Grande Prairie Region included the drilling of nine (9.0 net) Montney wells, the completion of four (4.0 net) Montney wells and the bringing onstream of four (4.0 net) Montney wells at Karr.  In addition, construction of a new compressor node in the western portion of Wapiti continues, with commissioning anticipated in the third quarter of 2024. 

Initial production from the four (4.0 net) Montney wells at Karr brought on production in early March has been encouraging, with the wells averaging gross 30-day peak production per well of 1,695 Boe/d (4.8 MMcf/d of shale gas and 896 Bbl/d of NGLs) with an average CGR of 187 Bbl/MMcf. ⁽¹⁾⁽²⁾

The Company continues to expect that its second quarter 2024 sales volumes will be impacted by a 9-day 50% curtailment at the third-party Wapiti natural gas processing plant and its third quarter 2024 sales volumes will be impacted by a 21-day full outage at that plant.

Over the remaining three quarters of 2024, Paramount plans to drill a total of 27 (27.0 net) Montney wells and bring on production a total of 32 (32.0 net) Montney wells in the Grande Prairie Region.

KAYBOB REGION

Kaybob Region sales volumes averaged 22,353 Boe/d (42% liquids) in the first quarter of 2024 compared to 20,324 Boe/d (35% liquids) in the fourth quarter of 2023.  Sales volumes and liquids contributions were higher primarily as a result of new Duvernay well production brought onstream in the first quarter at Kaybob North that more than offset the impact of the 2024 Kaybob Disposition.

In the first quarter, Paramount completed and brought onstream a six (6.0 net) Duvernay well pad and finished drilling a five (5.0 net) Duvernay well pad at Kaybob North that it had begun drilling in the fourth quarter.  The Company anticipates completing and bringing onstream all five of these wells in the second quarter.

Initial production from the six (6.0 net) well pad brought on in the first quarter has exceeded expectations, averaging gross 30-day peak production per well of 1,271 Boe/d (1.8 MMcf/d of shale gas and 980 Bbl/d of NGLs) with an average CGR of 563 Bbl/MMcf. ⁽¹⁾⁽³⁾

Over the remaining three quarters of 2024, Paramount plans to drill ten (10.0 net) Duvernay wells and bring on production eleven (11.0 net) Duvernay wells at Kaybob North.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 11,461 Boe/d (44% liquids) in the first quarter of 2024 compared to 8,164 Boe/d (35% liquids) in the fourth quarter 2023.  New well production from four (4.0 net) Duvernay wells at Willesden Green that came onstream between December 2023 and January 2024 resulted in higher sales volumes and a higher liquids contribution compared to the fourth quarter of 2023.

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(1)	30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well 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.
(2)	Natural gas sales volumes were lower by approximately 10% and liquids sales volumes were lower by approximately 8% due to shrinkage.
(3)	Natural gas sales volumes were lower by approximately 16% and liquids sales volumes were lower by approximately 14% due to shrinkage.

Development activities in the first quarter included the drilling of two (2.0 net) Duvernay wells at a six (6.0 net) well pad at Willesden Green.  Drilling operations on the remaining wells are anticipated to be concluded in the second quarter.  First production from three of the wells on this pad is expected in the third quarter.

Construction of the Company's second natural gas processing plant at Willesden Green commenced in the first quarter with earthworks, the ordering of equipment and offsite construction of equipment modules underway.  The project is progressing as planned and Paramount continues to anticipate start-up of the plant in the fourth quarter of 2025.

Over the remaining three quarters of 2024, the Company plans to drill eight (8.0 net) Duvernay wells and bring on production three (3.0 net) Duvernay wells at Willesden Green.

HEDGING

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

	Q2 2024	Q3 2024	Q4 2024		Average Price ^(1)	-
Oil
NYMEX WTI Swaps (Sale) (Bbl/d) ^(2)	14,250	14,250	14,250		CAD$111.67/Bbl
MSW WTI Differential Swap (Sale) (Bbl/d) ^(3)	3,352	5,000	5,000		WTI less US$2.56/Bbl
Natural gas
AECO – Basis (Physical Sale) (MMBtu/d)	40,000	40,000	13,478		NYMEX less US$0.93/MMBtu ^(4)
Foreign Currency Exchange
Swaps (Sale) (US$MM/Month)	$30	–	–		1.3433 CAD$ / US$
Swaps (Sale) (US$MM/Month)	–	$30	$30		1.3462 CAD$ / US$

(1)	Average price is calculated using a weighted average of notional volumes and prices.
(2)	"NYMEX" means New York Mercantile Exchange and "WTI" means West Texas Intermediate.
(3)	"MSW" means Mix Sweet Blend crude oil at Edmonton.
(4)	"NYMEX" means NYMEX pricing at Henry Hub.

ANNUAL GENERAL MEETING

Paramount will hold its annual general meeting of shareholders on Thursday, May 2, 2024 at 10:30 am (Calgary time) in the Bankers Hall Auditorium located at Level P3, 315 – 8th Avenue S.W., Calgary, Alberta.  A webcast of the meeting will be available at www.paramountres.com/investors/presentations.

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 first quarter 2024 results, including Management's Discussion and Analysis and the Company's Interim Consolidated Financial Statements, can be obtained on SEDAR+ at www.sedarplus.ca 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)	Q1 2024		Q4 2023		Q1 2023
Net income	68.1		111.9		197.0
per share – basic ($/share)	0.47		0.78		1.39
per share – diluted ($/share)	0.46		0.75		1.33
Cash from operating activities	201.3		287.0		271.4
per share – basic ($/share)	1.39		1.99		1.91
per share – diluted ($/share)	1.35		1.93		1.84
Adjusted funds flow	225.6		284.1		268.2
per share – basic ($/share)	1.56		1.97		1.89
per share – diluted ($/share)	1.52		1.91		1.81
Free cash flow	(9.5)		59.7		59.8
per share – basic ($/share)	(0.07)		0.41		0.42
per share – diluted ($/share)	(0.07)		0.40		0.40
Total assets	4,458.9		4,388.7		4,114.6
Investments in securities	568.6		540.9		498.3
Long-term debt	–		–		–
Net (cash) debt	68.4		59.6		(43.6)
Common shares outstanding (millions) ^(2)	145.2		144.2		142.4
Sales volumes ^(3)
Natural gas (MMcf/d)	318.7		326.2		320.6
Condensate and oil (Bbl/d)	40,908		40,290		37,916
Other NGLs (Bbl/d)	6,954		6,698		5,916
Total (Boe/d)	100,977		101,348		97,269
% liquids	47 %		46 %		45 %
Grande Prairie Region (Boe/d)	67,163		72,860		69,507
Kaybob Region (Boe/d)	22,353		20,324		19,201
Central Alberta & Other Region (Boe/d)	11,461		8,164		8,561
Total (Boe/d)	100,977		101,348		97,269
Netback		($/Boe) ^(4)		($/Boe) ^(4)		($/Boe) ^(4)
Natural gas revenue	82.4	2.84	83.7	2.79	122.0	4.23
Condensate and oil revenue	344.8	92.64	363.7	98.12	343.5	100.66
Other NGLs revenue	23.9	37.81	22.2	36.00	23.4	43.93
Royalty income and other revenue	1.2	–	0.9	–	0.8	–
Petroleum and natural gas sales	452.3	49.24	470.5	50.46	489.7	55.94
Royalties	(61.8)	(6.73)	(68.9)	(7.39)	(69.1)	(7.90)
Operating expense	(118.9)	(12.94)	(126.4)	(13.56)	(108.8)	(12.43)
Transportation and NGLs processing	(31.9)	(3.47)	(33.2)	(3.56)	(36.3)	(4.15)
Sales of commodities purchased ^(5)	54.7	5.95	50.2	5.38	115.1	13.15
Commodities purchased ^(5)	(53.4)	(5.81)	(47.4)	(5.08)	(114.3)	(13.05)
Netback	241.0	26.24	244.8	26.25	276.3	31.56
Risk management contract settlements	(0.5)	(0.05)	43.0	4.61	6.1	0.70
Netback including risk management contract settlements	240.5	26.19	287.8	30.86	282.4	32.26
Capital expenditures
Grande Prairie Region	120.2		75.8		121.1
Kaybob Region	56.3		64.5		39.0
Central Alberta & Other Region	39.8		61.7		5.6
Fox Drilling and Cavalier Energy	4.1		3.9		12.7
Corporate ^(6)	(6.5)		3.0		5.7
Total	213.9		208.9		184.1
Asset retirement obligations settled	16.5		12.8		21.8

(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 "Specified Financial Measures".
(2)	Common shares are presented net of shares held in trust under the Company's restricted share unit plan: Q1 2024: 0.4 million, Q4 2023: 0.4 million, Q1 2023: 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.
(6)	Includes transfers between regions.

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
	Q1 2024		Q4 2023		Q1 2023
Shale gas (MMcf/d)	268.5		271.8		265.2
Conventional natural gas (MMcf/d)	50.2		54.4		55.4
Natural gas (MMcf/d)	318.7		326.2		320.6
Condensate (Bbl/d)	38,332		37,522		34,706
Other NGLs (Bbl/d)	6,954		6,698		5,916
NGLs (Bbl/d)	45,286		44,220		40,622
Light and medium crude oil (Bbl/d)	1,595		1,636		2,151
Tight oil (Bbl/d)	592		699		599
Heavy crude oil (Bbl/d)	389		433		460
Crude oil (Bbl/d)	2,576		2,768		3,210
Total (Boe/d)	100,977		101,348		97,269
	Grande Prairie Region						Kaybob Region						Central Alberta and Other Region
	Q1 2024		Q4 2023		Q1 2023		Q1 2024		Q4 2023		Q1 2023		Q1 2024		Q4 2023		Q1 2023
Shale gas (MMcf/d)	201.6		214.1		204.0		30.6		30.2		31.8		36.3		27.5		29.4
Conventional natural gas (MMcf/d)	0.2		0.3		0.4		47.7		49.6		49.6		2.3		4.5		5.4
Natural gas (MMcf/d)	201.8		214.4		204.4		78.3		79.8		81.4		38.6		32.0		34.8
Condensate (Bbl/d)	29,061		32,155		31,367		6,038		4,003		2,315		3,233		1,364		1,024
Other NGLs (Bbl/d)	4,334		4,742		4,074		1,480		1,209		988		1,140		747		854
NGLs (Bbl/d)	33,395		36,897		35,441		7,518		5,212		3,303		4,373		2,111		1,878
Light and medium crude oil (Bbl/d)	–		–		–		1,573		1,602		2,121		22		34		30
Tight oil (Bbl/d)	141		227		–		212		205		206		239		267		393
Heavy crude oil (Bbl/d)	–		–		–		–		–		–		389		433		460
Crude oil (Bbl/d)	141		227		–		1,785		1,807		2,327		650		734		883
Total (Boe/d)	67,163		72,860		69,507		22,353		20,324		19,201		11,461		8,164		8,561

The Company forecasts that 2024 annual sales volumes will average between 100,000 Boe/d and 106,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs).  First half 2024 sales volumes are expected to average between 96,000 Boe/d and 100,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs).  Second half 2024 sales volumes are expected to average between 104,000 Boe/d and 112,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% 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 are not 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 March 31, 2024, December 31, 2023 and March 31, 2023.

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 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 (a non-GAAP financial measure) for the applicable period by the total sales volumes 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 (a non-GAAP financial measure) for the applicable period by the total sales volumes 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 sales volumes 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 in the Interim Consolidated Financial Statements of Paramount as at and for the three months ended March 31, 2024 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 months ended March 31, 2024 and 2023 and (iii) a calculation of net (cash) debt as at March 31, 2024 and December 31, 2023.

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 expenses, sales of commodities purchased and commodities purchased on a $/Boe or $/Mcf basis are calculated by dividing petroleum and natural gas sales, revenue, royalties, operating expenses, transportation and NGLs processing expenses, sales of commodities purchased and commodities purchased, as applicable, over the referenced period by the aggregate units (Boe or Mcf) of sales volumes 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 2024 and certain periods therein;
• planned capital expenditures in 2024 and the allocation thereof between sustaining and maintenance capital and growth capital;
• planned abandonment and reclamation expenditures in 2024;
• forecast free cash flow in 2024;
• planned exploration, development and production activities, including: (i) the expected timing of drilling, completing and bringing new wells on production; (ii) planned workovers; and (iii) the expected timing of completion of planned facilities, including a new natural gas processing facility at Willesden Green;
• the expected impact on sales volumes of outages and curtailments at the third-party Wapiti natural gas processing plant; 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 international conflicts, including in Ukraine and the Middle East;
• 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 funds required for exploration, development and other operations and the meeting of 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, disposal and storage capacity on acceptable terms and the capacity and reliability of facilities;
• the ability of Paramount to obtain the volumes of water required for completion activities;
• 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 sales volumes, reserves additions, product yields and product recoveries) and operational improvements, efficiencies and results consistent with expectations;
• the timely receipt of required governmental and regulatory approvals;
• the application of regulatory requirements respecting abandonment and reclamation; and
• anticipated timelines and budgets being met in respect of: (i) drilling programs and other operations, including well completions and tie-ins, (ii) the construction, commissioning and start-up of new and expanded third-party and Company facilities, including the new natural gas processing facility at Willesden Green, and (iii) 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;
• changes in foreign currency exchange rates, interest rates and the rate of inflation;
• the uncertainty of estimates and projections relating to future production, product yields (including condensate to natural gas ratios), revenue, free cash flow, reserves additions, product recoveries, royalty rates, taxes and costs and expenses;
• the ability to secure adequate processing, transportation, fractionation, disposal 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 and the new natural gas processing facility at Willesden Green;
• processing, transportation, fractionation, disposal and storage outages, disruptions and constraints;
• potential limitations on access to the volumes of water required for completion activities due to drought, conditions of low river flow, government restrictions or other factors;
• 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 asset retirement obligations, 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, including those required for the new natural gas processing facility at Willesden Green;
• 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, 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 its 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 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, 2023, which is available on SEDAR+ at www.sedarplus.ca 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 2024, 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						NYMEX	New York Mercantile Exchange
Boe		Barrels of oil equivalent				AECO	AECO-C reference price
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 three months ended March 31, 2024, the value ratio between crude oil and natural gas was approximately 49:1. 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, 2023 which is available on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com.

Pricing Sensitivity

The below table reflects forecast 2024 free cash flow under the Company's 2024 guidance and, for illustrative comparison, two alternative pricing scenarios for the final three quarters of 2024:

	2024 Guidance	Alternative Scenario 1	Alternative Scenario 2
WTI	US$80.00/Bbl	US$77.50/Bbl	US$75.00/Bbl
NYMEX	US$3.50/MMBtu	US$3.00/MMBtu	US$2.40/MMBtu
AECO	$2.84/GJ	$2.37/GJ	$1.90/GJ
2024 Free Cash Flow	$205 million	$135 million	$65 million

Forecast 2024 free cash flow is forward-looking information.  See "Forward-looking Information" in these Advisories.

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]