Paramount Resources Ltd. Announces Third Quarter 2023 Results, Expansion of Montney Acreage, 2024 Budget and Five-Year Outlook

CALGARY, AB, Nov. 2, 2023 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its third quarter 2023 financial and operating results, which included record production, and an expansion of its Montney acreage in the Grande Prairie Region. The Company is also pleased to announce its 2024 capital expenditure budget and guidance and five-year outlook.

HIGHLIGHTS

• Third quarter sales volumes averaged 98,644 Boe/d (45% liquids), a quarterly record. ⁽¹⁾
  • Grande Prairie Region sales volumes averaged a record 74,381 Boe/d (50% liquids) despite approximately 5,400 Boe/d in unplanned outages and curtailments associated with third-party midstream facilities.
  • Kaybob Region sales volumes increased to 17,027 Boe/d (32% liquids) due to the recovery from the Alberta wildfires. The Company successfully completed the planned turnaround at its Kaybob 8-9 natural gas processing plant in September, which shut-in the majority of Kaybob Region production for approximately three weeks.
  • Central Alberta and Other Region sales volumes averaged 7,236 Boe/d (30% liquids).
• Paramount has expanded its core Montney land position in the Grande Prairie Region through the addition of 10 net sections of new land at Karr and Wapiti. The Company has also disclosed the location of a further 10 net sections at Wapiti that were previously held confidentially. The Company maintains an active exploration program and is pleased with the progress made to date in capturing additional resource.
• Cash from operating activities was $208 million ($1.45 per basic share) in the third quarter. Adjusted funds flow was $234 million ($1.64 per basic share). ⁽²⁾
• Free cash flow was $19 million ($0.13 per basic share) in the third quarter. ⁽²⁾

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(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.

• Third quarter capital expenditures totaled $199 million. Key activities included:
  • Grande Prairie Region (Montney) - nine (9.0 net) wells drilled, five (5.0 net) wells completed and eight (8.0 net) wells brought on production;
  • Kaybob Region (Duvernay) - two (2.0 net) wells drilled and three (3.0 net) wells brought on production; and
  • Central Alberta and Other Region (Duvernay) - three (3.0 net) wells drilled in Willesden Green and advancement of the liquids handling expansion at Paramount's Leafland natural gas processing plant.
• Initial results at two of the Company's most recent pads brought on production, the Karr 7-33S five-well Montney pad and the Kaybob North 4-13S three-well Duvernay pad, have been exceptional, significantly exceeding type curve.
• Asset retirement obligations settled in the third quarter totaled $14 million. Activities in the quarter included the abandonment of seven wells and reclamation of seven well sites.
• At September 30, 2023, net debt was $44 million and Paramount's $1.0 billion revolving credit facility was undrawn. ⁽¹⁾
• The carrying value of the Company's investments in securities at September 30, 2023 was $578 million.
• Subsequent to September 30, 2023, the Company monetized certain WTI liquids hedges that were outstanding at quarter end for cash consideration of approximately $13 million, which will be included in fourth quarter 2023 adjusted funds flow. Paramount also hedged 10,000 Bbl/d of 2024 liquids sales volumes at an average WTI price of CAD$109.50/Bbl.

UPDATED 2023 GUIDANCE

Third quarter sales volumes were in-line with expectations. Paramount expects average fourth quarter 2023 sales volumes to be between 100,000 Boe/d and 103,000 Boe/d (47% liquids), resulting in average second half 2023 and annual 2023 sales volumes in the range of previous guidance. Fourth quarter 2023 sales volumes guidance includes the impact of the previously disclosed 11 day planned outage of the third-party Wapiti natural gas processing plant (the "Wapiti Plant") in October that was rescheduled from earlier in the year due to the Alberta wildfires. 

Third quarter capital expenditures were also in-line with expectations. Paramount is narrowing the range of its 2023 capital expenditure guidance to $725 million to $750 million (~50% to growth) from previous guidance of $700 million to $750 million. The narrowing of the range reflects year-to-date spending and anticipated costs for remaining activities to be completed during the fourth quarter.

The Company is updating its forecast of 2023 free cash flow to approximately $165 million from $185 million to incorporate third quarter results and the slightly higher mid-point of forecast capital expenditures. ⁽²⁾

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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.
(2)	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 sales volumes, (ii) $55 million in abandonment and reclamation costs, (iii) $7 million in geological and geophysical expenses, (iv) realized pricing of $52.60/Boe (US$77.99/Bbl WTI, US$3.34/MMBtu NYMEX, $2.72/GJ AECO), (v) a $US/$CAD exchange rate of $0.746, (vi) royalties of $7.60/Boe, (vii) operating costs of $12.65/Boe and (vii) transportation and NGLs processing costs of $3.90/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 fourth quarter of 2023 is unchanged from previous guidance, but the stated amounts have been adjusted to incorporate actual results for the first three quarters of 2023.

2024 BUDGET AND GUIDANCE

Paramount is budgeting 2024 capital expenditures of between $830 million and $890 million, $60 million at midpoint more than the previous high range of preliminary guidance. This increase is largely related to (i) the addition of a five-well Willesden Green Duvernay pad to be drilled in the fourth quarter of 2024, (ii) the acceleration of the drilling of a four-well Kaybob North Duvernay pad into the fourth quarter of 2024, and (iii) slightly higher budgeted overall drilling, completion, equipping and tie-in costs due to persistent inflationary pressures. 

The Company remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices and other factors.

The 2024 capital budget at midpoint is broken down as follows:

• $415 million (~50%) to sustaining capital and maintenance activities;
• $45 million (~5%) to growth capital associated with production benefits in 2024; and
• $400 million (~45%) to growth capital associated with production benefits largely in 2025 and beyond, including approximately $150 million related to the construction of the Company's new processing facility in Willesden Green.

The breakdown by region at midpoint is as follows:

• Grande Prairie Region − $425 million;
• Kaybob Region − $185 million; and
• Central Alberta and Other Region − $250 million.

The breakdown by category at midpoint is as follows:

• Drilling, completion, equipping and tie-ins − $575 million;
• Facilities and gathering − $280 million; and
• Corporate and other − $5 million.

The majority of the facilities and gathering capital budgeted for 2024 relates to the first phase of the Company's new processing facility in Willesden Green. This first phase will provide an estimated 50 MMcf/d of raw gas and 10,000 Bbl/d of raw liquids handling capacity upon completion to support Paramount's Willesden Green Duvernay development, with start-up expected in the fourth quarter of 2025.

The Company has budgeted $40 million for abandonment and reclamation activities in 2024.

Average sales volumes in 2024 are expected to be between 108,000 Boe/d and 116,000 Boe/d (47% liquids), 3,000 Boe/d lower at midpoint compared to the previous preliminary guidance primarily due to (i) an increase in planned downtime by the third-party operator of the Wapiti Plant, (ii) a reduction in Paramount's assumption for on-time at the Wapiti Plant, (iii) higher than previously forecast gas lift requirements in the Grande Prairie Region, and (iv) a decision to delay the onstream timing of the second four-well pad in Willesden Green. 

First half 2024 average sales volumes are expected to be between 101,000 Boe/d and 111,000 Boe/d (46% liquids), with second quarter sales volumes being impacted by a 21 day planned turnaround at the Wapiti Plant. Second half 2024 average sales volumes are expected to be between 115,000 Boe/d and 121,000 Boe/d (47% liquids).

Paramount is updating its forecast of 2024 free cash flow to approximately $350 million from $445 million to reflect updated capital expenditures, sales volumes, commodity prices and other assumptions.

	Preliminary 2024 Guidance	2024 Budget
Annual average sales volumes (Boe/d)	110,000 to 120,000 (48% liquids)	108,000 to 116,000 (47% liquids)
First half average sales volumes (Boe/d)	—	101,000 to 111,000 (46% liquids)
Second half average sales volumes (Boe/d)	—	115,000 to 121,000 (47% liquids)
Capital expenditures	$700 to $800 million (~50% to growth)	$830 to $890 million (~50% to growth)
Abandonment and reclamation expenditures	$40 million	No change
Free cash flow ^(1)	$445 million	$350 million

The Company's midpoint 2024 sustaining and maintenance capital program and regular monthly dividend would remain fully funded down to an average WTI price in 2024 of about US$55/Bbl. ⁽²⁾ The Company's total midpoint 2024 capital program and regular monthly dividend would remain fully funded down to an average WTI price in 2024 of about US$71/Bbl. ⁽²⁾

FIVE-YEAR OUTLOOK

Paramount is providing its five-year outlook for the period from 2024 through to the end of 2028.⁽³⁾ The Company anticipates midpoint cumulative free cash flow of approximately $2.8 billion (approximately $19.40 per basic share⁽⁴⁾) over the period. Paramount anticipates midpoint annual capital expenditures to range between approximately $850 million and $1.0 billion through the period 2024 to 2028, with sales volumes increasing to between 140,000 Boe/d and 155,000 Boe/d in 2028, representing a compound annual production growth rate of 8% to 10% between 2023 and 2028. With estimated tax pools of almost $4 billion at September 30, 2023, the majority of which are immediately deductible, Paramount does not forecast cash tax in its five-year outlook until 2027.

NOVEMBER DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.125 per Common Share that will be payable on November 30, 2023 to shareholders of record on November 15, 2023. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

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(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 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 $56.40/Boe (US$80/Bbl WTI, US$3.50/MMBtu NYMEX, $2.84/GJ AECO), (v) a $US/$CAD exchange rate of $0.735, (vi) royalties of $8.80/Boe, (vii) operating costs of $12.05/Boe and (vii) transportation and NGLs processing costs of $3.70/Boe. For comparative purposes, the preliminary 2024 free cash flow forecast utilized the following differing assumptions as to the following factors: (i) realized pricing of $53.60/Boe (US$75.00/Bbl WTI, US$3.50/MMBtu NYMEX, $3.08/GJ AECO), (ii) a $US/$CAD exchange rate of $0.755, (iii) royalties of $8.10/Boe, (iv) operating costs of $11.20/Boe and (vi) transportation and NGLs processing costs of $3.60/Boe.
(2)	Assuming no changes to the other forecast assumptions for 2024.
(3)	The five-year outlook is based on preliminary planning and current market conditions and is subject to change. The stated anticipated cumulative free cash flow is based on the following assumptions: (i) the stated midpoint annual capital expenditures; (ii) compound annual production growth in the stated range; (iii) approximately $40 million in 2024 and thereafter approximately $45 million in average annual abandonment and reclamation costs, (iv) approximately $7 million in annual geological and geophysical expenses, (v) 2024 realized pricing of $56.40/Boe (US$80.00/Bbl WTI, US$3.50/MMBtu NYMEX, $2.84/GJ AECO) and thereafter commodity prices of US$75.00/Bbl WTI, US$4.00/MMBtu NYMEX and $3.55/GJ AECO, (vi) a 2024 $US/$CAD exchange rate of $0.735 and thereafter a $US/$CAD exchange rate of $0.74 and (vii) internal management estimates of future royalties, operating costs, transportation and NGLs processing costs and, beginning in 2027, cash taxes.
(4)	Based on 144.3 million outstanding Common Shares as at October 31, 2023.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

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

	Q3 2023		Q2 2023		% Change
Sales Volumes
Natural gas (MMcf/d)	223.2		196.4		14
Condensate and oil (Bbl/d)	32,365		30,205		7
Other NGLs (Bbl/d)	4,815		4,012		20
Total (Boe/d)	74,381		66,950		11
% liquids	50 %		51 %
Netback ^(1)	($ millions)	($/Boe)	($ millions)	($/Boe)	Change in $ millions (%)
Natural gas revenue ^(2)	55.6	2.71	43.3	2.42	28
Condensate and oil revenue	308.7	103.68	260.5	94.76	19
Other NGLs revenue	15.4	34.70	11.7	31.99	32
Royalty income and other revenue	–	–	0.3	–	NM
Petroleum and natural gas sales	379.7	55.48	315.8	51.83	20
Royalties	(64.7)	(9.45)	(39.3)	(6.45)	65
Operating expense	(72.7)	(10.62)	(70.7)	(11.61)	3
Transportation and NGLs processing	(25.6)	(3.75)	(27.2)	(4.47)	(6)
	216.7	31.66	178.6	29.30	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

Sales volumes in the Grande Prairie Region averaged a record 74,381 Boe/d (50% liquids) in the third quarter compared to 66,950 Boe/d (51% liquids) in the second quarter of 2023. The quarter-over-quarter increase was primarily attributable to the recovery from the second quarter wildfire related outages and curtailments along with new well production from the three (3.0 net) well Wapiti 1-27 pad that came onstream in late-July and the five (5.0 net) well Karr 7-33S pad that came onstream in mid-September. A number of unplanned outages and curtailments at third-party operated midstream facilities negatively impacted third quarter sales volumes by approximately 5,400 Boe/d.

Development activities in the Grande Prairie Region in the third quarter included the drilling of nine (9.0 net) Montney wells and the completion of five (5.0 net) Montney wells.

At Karr, all five (5.0 net) wells on the 7-33S pad were brought on production late in the third quarter. Production results from these wells to date have significantly exceeded expectations, averaging gross 30-day peak production per well of 2,554 Boe/d (4.8 MMcf/d of shale gas and 1,749 Bbl/d of NGLs) with an average CGR of 362 Bbl/MMcf. ⁽¹⁾

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(1)

Production measured at the wellhead. Natural gas sales volumes were lower by approximately 10% and liquids sales volumes were lower by approximately 7% 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.

At Wapiti, all three (3.0 net) wells on the 1-27 pad were brought on production in the third quarter. Production results from these wells are in-line with expectations, averaging gross 30-day peak production per well of 1,187 Boe/d (2.7 MMcf/d of shale gas and 730 Bbl/d of NGLs) with an average CGR of 266 Bbl/MMcf. ⁽¹⁾ More recently, Paramount began flow testing the eight (8.0 net) well 8-15 pad at Wapiti. All eight wells are expected to be brought on production through permanent facilities in November. The Company recently finished drilling the three (3.0 net) well 6-36 pad at Karr and is close to concluding drilling operations on the eight (8.0 net) well 14-5 pad at Wapiti. Completion operations at the Karr 6-36 pad have commenced and all three wells are expected to be brought on production in the fourth quarter. Completion operations at the Wapiti 14-5 pad are anticipated to commence in mid-2024. Paramount plans to commence drilling at the four (4.0 net) well Karr 7-33N pad, four (4.0 net) well Karr 15-24S pad and seven (7.0 net) well Wapiti 2-18 pad in the fourth quarter of 2023.

Paramount has expanded its core Montney land position in the Grande Prairie Region through the addition of 10 net sections of new land at Karr and Wapiti. The Company has also disclosed the location of a further 10 net sections at Wapiti that were previously held confidentially. The Company maintains an active exploration program and is pleased with the progress made to date in capturing additional resource.

In 2024, the Company plans to drill 41 (41.0 net) wells and bring on production 36 (36.0 net) wells in the Grande Prairie Region, which is expected to result in annual average sales volumes of between 75,000 Boe/d and 82,000 Boe/d. Over the first half of 2024, Paramount plans to drill 19 (19.0 net) wells, complete 27 (27.0 net) wells and bring onstream eight (8.0 net) wells. In the second half of 2024, Paramount plans to drill 22 (22.0 net) wells, complete 9 (9.0 net) wells and bring onstream 28 (28.0 net) wells. These plans include the commencement of development activities in the western portion of the Wapiti field where a new compressor node is being installed and commissioned to accommodate the tie-in of a seven-well pad in the second half of 2024 as well as future well development in the area. This portion of the Wapiti field is proximal to the Montney lands previously held confidentially.

The third-party operator of the Wapiti Plant has notified Paramount of a planned increase in the frequency of maintenance outages, with the stated objective of reducing the frequency and severity of unplanned outages in the future. This includes two outages in 2024 (a 21 day full outage in the second quarter and an 8 day 50% curtailment in the fourth quarter).  Paramount's 5-year outlook now incorporates a lower on-time factor for the Wapiti Plant, the 2024 planned outages and 15 days of annual planned outages thereafter.

KAYBOB REGION

Kaybob Region sales volumes averaged 17,027 Boe/d (32% liquids) in the third quarter compared to 13,238 Boe/d (24% liquids) in the second quarter of 2023. Sales volumes were higher in the third quarter due to the recovery from the wildfire related outages, including the resumption of production from wells that remained shut-in at the end of the second quarter. Sales volumes in the third quarter also benefited from new well production from the three (3.0 net) well Kaybob North Duvernay 4-13S pad that was brought onstream in July. Third quarter sales volumes were impacted by the planned five-year turnaround at the Company's Kaybob 8-9 natural gas processing plant that lasted approximately three weeks. 

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(1)

Production measured at the wellhead. Natural gas sales volumes were lower by approximately 9% and liquids sales volumes were lower by approximately 2% 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.

Production from the three well 4-13S pad has been very strong, averaging gross 30-day peak production per well of 1,601 Boe/d (1.2 MMcf/d of shale gas and 1,403 Bbl/d of NGLs) with an average CGR of 1,177 Bbl/MMcf.⁽¹⁾ These results are among the best ever recorded for Duvernay wells in the area based on public data, confirming Paramount's decision to begin the active development of its extensive land base. The Company expects to grow Kaybob North Duvernay sales volumes from approximately 2,000 Boe/d in 2023 to as high as 14,000 Boe/d within its five-year outlook.

Development activities in the third quarter included the drilling of two wells on the Kaybob North Duvernay six (6.0 net) well 15-7N pad. Drilling of the remaining four wells is ongoing, with completion operations and tie-ins to commence in the fourth quarter of 2023. The Company continues to apply past learnings from the drilling of long reach lateral wells and has once again set a new company record with one of the wells on the 15-7N pad reaching approximately 8,100 meters of total measured depth with a lateral length of approximately 4,800 meters. All six wells are anticipated to be brought onstream in the first quarter of 2024. 

Paramount expects annual average Kaybob Region sales volumes to exceed 20,000 Boe/d in 2024. The Company's 2024 development plans in the Kaybob North Duvernay area consist of the drilling of 11 (11.0 net) wells, the bringing on production of 11 (11.0 net) wells and the commencement of the drilling of a 4 (4.0 net) well pad that has been accelerated into the fourth quarter of 2024. Paramount also plans to further enhance its existing facility infrastructure in 2024 to support future Duvernay development, maximize field netbacks and enhance full cycle returns.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 7,236 Boe/d (30% liquids) in the third quarter compared to 8,055 Boe/d (30% liquids) in the second quarter 2023.

The drilling of the four (4.0 net) Duvernay wells at the 4-7N pad in Willesden Green was recently concluded. Completion operations have commenced and first production is anticipated to occur in the first quarter of 2024 to coincide with the start-up of the new liquids handling expansion at Paramount's Leafland natural gas processing plant. 

In 2024, the Company plans to grow annual average sales volumes in the Central Alberta and Other Region to over 10,000 Boe/d by bringing eight (8.0 net) Duvernay wells on production in the Willesden Green area. The drilling of an additional four (4.0 net) Duvernay wells off of the existing 4-7 pad is now anticipated to commence in the first quarter of 2024 and all four wells are expected to be brought on production in the second half of 2024. Paramount also plans to commence the drilling of an additional five (5.0 net) Duvernay wells at the 11-1S pad.

Construction of the Company's previously announced second natural gas processing facility at Willesden Green is set to commence in 2024, with start-up expected in the fourth quarter of 2025. The first phase of this new facility will provide an estimated 50 MMcf/d of raw gas and 10,000 Bbl/d of raw liquids handling capacity to support the Willesden Green Duvernay development. It is anticipated that the new facility will ultimately be capable of handling approximately 150 MMcf/d of raw gas and 30,000 Bbl/d of raw liquids, and be constructed in three phases of approximately 50 MMcf/d of raw gas handling and 10,000 Bbl/d of raw liquids handling each.

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(1)

Production measured at the wellhead. Natural gas sales volumes were lower by approximately 16% and liquids sales volumes were lower by approximately 13% 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.

HEDGING

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

Instruments		Aggregate amount / notional		Average price or rate ^(1)		Remaining term
Oil
NYMEX WTI Swaps (Sale)		10,000 Bbl/d		CAD$109.50/Bbl		January 2024 – December 2024
Sweet Crude Oil – Basis (Physical sale) ^(2)		3,078 Bbl/d		WTI – US$3.73/Bbl		October 2023 – December 2023
Natural Gas
AECO – Basis (Physical Sale)		50,000 MMBtu/d		NYMEX – US$0.93/MMBtu		October 2023
Dawn – Basis (Physical Sale)		25,000 MMBtu/d		NYMEX – US$0.20/MMBtu		October 2023
Foreign Currency Exchange
Swaps (sale)		$40MM/Month		1.3427 CAD$ / US$		October 2023 – December 2023
Swaps (sale)		$30MM/Month		1.3448 CAD$ / US$		January 2024 – December 2024

(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 third quarter 2023 results, including Management's Discussion and Analysis and the Company's 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)	Q3 2023		Q2 2023		Q3 2022
Net income	87.2		74.2		221.9
per share – basic ($/share)	0.61		0.52		1.57
per share – diluted ($/share)	0.59		0.50		1.51
Cash from operating activities	207.6		172.2		248.9
per share – basic ($/share)	1.45		1.20		1.76
per share – diluted ($/share)	1.40		1.16		1.69
Adjusted funds flow	234.2		178.7		334.3
per share – basic ($/share)	1.64		1.25		2.37
per share – diluted ($/share)	1.58		1.21		2.27
Free cash flow	18.5		30.5		137.5
per share – basic ($/share)	0.13		0.21		0.97
per share – diluted ($/share)	0.12		0.21		0.93
Total assets	4,305.1		4,106.6		4,261.3
Investments in securities	577.5		489.9		451.3
Long-term debt	–		–		306.3
Net (cash) debt	44.4		2.3		347.0
Common shares outstanding (millions) ^(2)	143.4		143.1		141.2
Sales volumes ^(3)
Natural gas (MMcf/d)	323.1		290.2		315.9
Condensate and oil (Bbl/d)	38,161		34,230		38,804
Other NGLs (Bbl/d)	6,627		5,648		6,144
Total (Boe/d)	98,644		88,243		97,601
% liquids	45 %		45 %		46 %
Grande Prairie Region (Boe/d)	74,381		66,950		65,981
Kaybob Region (Boe/d)	17,027		13,238		24,021
Central Alberta & Other Region (Boe/d)	7,236		8,055		7,599
Total (Boe/d)	98,644		88,243		97,601
Netback		($/Boe) ^(4)		($/Boe) ^(4)		($/Boe) ^(4)
Natural gas revenue	79.3	2.67	64.1	2.43	185.7	6.39
Condensate and oil revenue	362.9	103.36	294.1	94.42	401.8	112.56
Other NGLs revenue	20.5	33.64	15.9	30.86	28.9	51.20
Royalty income and other revenue	1.1	–	0.3	–	2.5	─
Petroleum and natural gas sales	463.8	51.11	374.4	46.63	618.9	68.92
Royalties	(75.2)	(8.28)	(41.2)	(5.12)	(89.4)	(9.96)
Operating expense	(113.9)	(12.55)	(104.6)	(13.03)	(110.0)	(12.25)
Transportation and NGLs processing	(31.2)	(3.44)	(33.6)	(4.19)	(34.4)	(3.83)
Sales of commodities purchased ^(5)	42.1	4.64	47.7	5.94	77.9	8.67
Commodities purchased ^(5)	(39.2)	(4.32)	(49.3)	(6.15)	(76.4)	(8.51)
Netback	246.4	27.16	193.4	24.08	386.6	43.04
Risk management contract settlements	0.2	0.02	(2.7)	(0.33)	(44.4)	(4.94)
Netback including risk management contract settlements	246.6	27.18	190.7	23.75	342.2	38.10
Capital expenditures
Grande Prairie Region	117.6		66.0		133.5
Kaybob Region	41.4		45.5		30.8
Central Alberta & Other Region	35.5		17.1		0.2
Fox Drilling and Cavalier Energy	4.9		7.6		10.8
Corporate	(0.5)		4.0		9.0
Total	198.9		140.2		184.3
Asset retirement obligations settled	14.0		5.9		10.2

(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: Q3 2023: 0.4 million, Q2 2023: 0.4 million, Q3 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
	Q3 2023		Q2 2023		Q3 2022
Shale gas (MMcf/d)	276.7		246.0		253.8
Conventional natural gas (MMcf/d)	46.4		44.2		62.1
Natural gas (MMcf/d)	323.1		290.2		315.9
Condensate (Bbl/d)	35,984		32,341		35,747
Other NGLs (Bbl/d)	6,627		5,648		6,144
NGLs (Bbl/d)	42,611		37,989		41,891
Light and medium crude oil (Bbl/d)	1,154		942		2,608
Tight oil (Bbl/d)	627		538		449
Heavy crude oil (Bbl/d)	396		409		–
Crude oil (Bbl/d)	2,177		1,889		3,057
Total (Boe/d)	98,644		88,243		97,601
	Grande Prairie Region						Kaybob Region						Central Alberta and Other Region
	Q3 2023		Q2 2023		Q3 2022		Q3 2023		Q2 2023		Q3 2022		Q3 2023		Q2 2023		Q3 2022
Shale gas (MMcf/d)	222.8		196.1		188.2		28.0		21.7		38.5		25.9		28.2		27.1
Conventional natural gas (MMcf/d)	0.4		0.3		1.4		41.7		38.4		54.8		4.3		5.5		5.9
Natural gas (MMcf/d)	223.2		196.4		189.6		69.7		60.1		93.3		30.2		33.7		33.0
Condensate (Bbl/d)	32,145		30,046		30,610		2,981		1,301		4,157		858		994		980
Other NGLs (Bbl/d)	4,815		4,012		3,758		1,188		891		1,666		624		745		720
NGLs (Bbl/d)	36,960		34,058		34,368		4,169		2,192		5,823		1,482		1,739		1,700
Light and medium crude oil (Bbl/d)	–		–		5		1,131		914		2,434		23		28		169
Tight oil (Bbl/d)	220		159		–		104		115		208		303		264		241
Heavy crude oil (Bbl/d)	–		–		–		–		–		–		396		409		–
Crude oil (Bbl/d)	220		159		5		1,235		1,029		2,642		722		701		410
Total (Boe/d)	74,381		66,950		65,981		17,027		13,238		24,021		7,236		8,055		7,599

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). Fourth quarter 2023 sales volumes are expected to average between 100,000 Boe/d and 103,000 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).

The Company forecasts that 2024 annual sales volumes will average between 108,000 Boe/d and 116,000 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). First half 2024 sales volumes are expected to average between 101,000 Boe/d and 111,000 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 2024 sales volumes are expected to average between 115,000 Boe/d and 121,000 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 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 September 30, 2023, June 30, 2023 and September 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 nine months ended September 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 nine months ended September 30, 2023 and 2022 and (iii) a calculation of net (cash) debt as at September 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:

• planned capital expenditures in 2023 and 2024 and the allocation thereof;
• forecast sales volumes for 2023 and 2024 and certain periods therein;
• planned abandonment and reclamation expenditures in 2023 and 2024;
• forecast free cash flow in 2023 and 2024;
• the anticipated capacity and timing of startup of the planned new facility at Willesden Green;
• the Company's five-year outlook for capital expenditures, cumulative free cash flow and sales volumes;
• the statement that Paramount does not forecast cash tax in its five-year outlook until 2027;
• planned exploration, development and production activities, including the expected timing of drilling, completing and bringing new wells on production and the expected timing of completion of planned facilities and infrastructure;
• planned outages and downtime of facilities;
• expected Grande Prairie sales volumes in 2024;
• expected Kaybob North Duvernay sales volumes growth;
• the expectation that Kaybob Region sales volumes will exceed 20,000 Boe/d in 2024;
• the Company's plans to grow production in the Central Alberta and Other Region to over 10,000 Boe/d in 2024; 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 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 the Company's five-year outlook for capital expenditures, cumulative free cash flow and sales volumes;
• 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.

With respect to the statement that Paramount does not forecast cash tax in its five-year outlook until 2027, taxable income varies depending on total income and expenses and estimates as to the timing of paying cash tax are sensitive to assumptions regarding commodity prices, production, cash from operating activities, capital spending levels, the allocation of free cash flow and acquisition and disposition transactions. Changes in these factors could result in the Company paying income taxes earlier or later than expected.

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.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 2023 and 2024 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 nine months ended September 30, 2023, the value ratio between crude oil and natural gas was approximately 35:1. 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.sedarplus.ca.

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]