Paramount Resources Ltd. Announces Third Quarter 2024 Results

Nov 07 2024 12:00 GMT

CALGARY, AB , Nov. 7, 2024 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its third quarter 2024 financial and operating results.

HIGHLIGHTS

Third quarter sales volumes averaged 94,892 Boe/d (48% liquids). ⁽¹⁾
- Grande Prairie Region sales volumes averaged 67,635 Boe/d (50% liquids). The planned turnaround at the Wapiti natural gas processing plant (the "Wapiti Plant") and related full Wapiti production outage commenced in mid-September, five days earlier than expected. Prior to the turnaround, Wapiti sales volumes reached over 35,000 Boe/d as two new Montney pads were brought on production.
- Kaybob Region sales volumes averaged 20,894 Boe/d (41% liquids).
- Central Alberta and Other Region sales volumes averaged 6,363 Boe/d (53% liquids).
- 5,600 Boe/d of dry natural gas production was shut-in for the quarter due to low natural gas prices.
Cash from operating activities was $206 million ($1.40 per basic share) in the third quarter. Adjusted funds flow was $201 million ($1.37 per basic share). Free cash flow was ($26) million (($0.18) per basic share). ⁽²⁾
Third quarter capital expenditures totaled $217 million. Significant activities included:
- Grande Prairie Region (Montney) – eight (8.0 net) wells drilled, nineteen (19.0 net) wells brought on production and the successful completion of the new compressor node at Wapiti that was brought onstream in the third quarter, which will support development of the western portion of the field;
- Kaybob Region (Duvernay) – three (3.0 net) wells drilled; and

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(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.

- Central Alberta and Other Region (Duvernay) – three (3.0 net) wells brought on production and the ongoing construction of the Company's second operated natural gas processing plant at Willesden Green (the "Alhambra Plant").
Paramount has recently spud the first of two horizontal appraisal wells at its Sinclair property, where the Company has approximately 107,000 net acres prospective for high-rate gas production from the Montney formation.
Asset retirement obligations settled in the third quarter totaled $7 million.
The carrying value of the Company's investments in securities at September 30, 2024 was $482 million. ⁽¹⁾
At September 30, 2024, net debt was $129 million. ⁽²⁾

UPDATED 2024 GUIDANCE

Third quarter sales volumes averaged 94,892 Boe/d (48% liquids), below prior guidance of between 96,000 Boe/d to 104,000 Boe/d (49% liquids). In addition to the impact from the early start of the Wapiti Plant turnaround, the Company's third quarter sales volumes were affected by numerous curtailments due to high ambient temperatures throughout the summer, unplanned outages at several minor infrastructure sites and the continuing shut-in of dry natural gas production.

Paramount is updating its fourth quarter 2024 sales volumes guidance to a range of 102,000 Boe/d to 109,000 Boe/d (49% liquids). The Company has deferred bringing approximately 4,200 Boe/d of dry natural gas production onstream in the fourth quarter. In addition, fourth quarter sales volumes were impacted by approximately 5,000 Boe/d due to the Wapiti Plant turnaround extending for the equivalent of 6 full days longer than expected in October as well as other disruptions in the month. Annual sales volumes would average 100,000 Boe/d at the upper end of the forecast range of fourth quarter 2024 sales volumes.

With the Wapiti Plant turnaround complete and subsequent disruptions resolved, Grande Prairie Region sales volumes have averaged over 80,000 Boe/d and total Company sales volumes have averaged over 110,000 Boe/d since late-October.

The Company is reaffirming its 2024 guidance for capital expenditures and abandonment and reclamation expenditures.

Paramount is updating its forecast of 2024 free cash flow from $100 million to $10 million to reflect results from the first three quarters, revised fourth quarter forecast production and a lower forecast WTI price of US$70/Bbl (previously US$80/Bbl).

	Prior 2024 Guidance	Revised 2024 Guidance
Fourth quarter average sales volumes (Boe/d)	109,000 to 121,000 (48% liquids)	102,000 to 109,000 (49% liquids)
Capital expenditures	$830 to $890 million	No change
Sustaining and maintenance	$415 to $445 million
Growth	$415 to $445 million
Abandonment and reclamation expenditures	$40 million	No change
Free cash flow ⁽³⁾	$100 million	$10 million

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(1)	Investments in publicly traded securities are carried at their September 30, 2024 closing trading price.
(2)	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.
(3)	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, (ii) the midpoint of fourth quarter sales volumes, (iii) $40 million in abandonment and reclamation costs, (iv) $10 million in geological and geophysical expenses, (v) realized pricing of $48.50/Boe, (vi) a $US/$CAD exchange rate of $0.735, (vii) royalties of $6.25/Boe, (viii) operating costs of $13.30/Boe and (ix) transportation and NGLs processing costs of $3.50/Boe. The stated amounts have been adjusted to incorporate actual results for the first three quarters of 2024.

NOVEMBER DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.15 per class A common share that will be payable on November 29, 2024 to shareholders of record on November 15, 2024. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

REVIEW OF OPERATIONS

GRANDE PRAIRIE REGION

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

	Q3 2024		Q2 2024		% Change
Sales Volumes
Natural gas (MMcf/d)	203.2		187.3		8
Condensate and oil (Bbl/d)	29,047		28,083		3
Other NGLs (Bbl/d)	4,723		4,179		13
Total (Boe/d)	67,635		63,480		7
*% liquids*	50 %		51 %
Netback ⁽¹⁾	($ millions)	($/Boe)	($ millions)	($/Boe)	Change in $ millions (%)
Natural gas revenue ⁽²⁾	25.9	1.38	28.5	1.67	(9)
Condensate and oil revenue	257.4	96.33	264.9	103.63	(3)
Other NGLs revenue	16.1	37.09	12.8	33.77	26
Petroleum and natural gas sales	299.4	48.12	306.2	53.01	(2)
Royalties	(39.9)	(6.40)	(56.9)	(9.86)	(30)
Operating expense	(83.4)	(13.41)	(82.6)	(14.29)	1
Transportation and NGLs processing	(24.8)	(3.99)	(21.9)	(3.80)	13
	151.3	24.32	144.8	25.06	4

(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.

Third quarter 2024 sales volumes in the Grande Prairie Region averaged 67,635 Boe/d (50% liquids) compared to 63,480 Boe/d (51% liquids) in the second quarter. Sales volumes were higher quarter-over-quarter as a result of new well production from 19 (19.0 net) new Montney wells that were brought onstream. The scheduled turnaround of the Wapiti Plant, which began five days earlier than expected, resulted in the shutdown of production from the Wapiti field for the equivalent of 15 full days in the third quarter, impacting average third quarter sales volumes by approximately 5,400 Boe/d. Unplanned maintenance at another third-party processing facility and high ambient temperatures also reduced sales volumes in the quarter. Paramount's aggressive well optimization program initiated in March 2024 is now substantially complete.

The Wapiti Plant turnaround continued into October. In total, the Wapiti Plant turnaround resulted in the shutdown of production from the Wapiti field for the equivalent of 32 full days, 11 more than originally expected.

Initial production from a new 4 (4.0 net) well Montney pad that was brought onstream at Karr in the quarter is in line with expectations, averaging gross 30-day peak production per well of 1,347 Boe/d (2.4 MMcf/d of shale gas and 953 Bbl/d of NGLs) with an average CGR of 403 Bbl/MMcf. ⁽¹⁾

Initial production results from a new 7 (7.0 net) well Montney pad that was brought onstream in the western portion of the Wapiti field in the quarter are encouraging despite the wells being heavily choked to manage temporary facilities constraints. The wells averaged gross 30-day peak production per well of 1,120 Boe/d (4.8 MMcf/d of shale gas and 314 Bbl/d of NGLs) with an average CGR of 65 Bbl/MMcf. ⁽²⁾

Third quarter development activities in the Grande Prairie Region included the drilling of 8 (8.0 net) Montney wells, the completion of 16 (16.0 net) Montney wells and the bringing onstream of 19 (19.0 net) Montney wells. The Company also brought a new compressor node onstream to service the western portion of the Wapiti field.

Paramount plans to drill a total of seven (7.0 net) Montney wells and bring on production a total of eight (8.0 net) Montney wells in the Grande Prairie Region in the fourth quarter of 2024.

The Company has spud the first of two appraisal wells to be drilled in 2024 at Sinclair. Paramount will use the flow test and other data obtained from these wells to continue to advance its development plans for the property, which have included the securing of downstream transportation capacity that would enable the first phase of Sinclair production to commence as early as the fourth quarter of 2027. The Sinclair property is prospective for high-rate gas production from the Montney formation.

KAYBOB REGION

Kaybob Region sales volumes averaged 20,894 Boe/d (41% liquids) in the third quarter of 2024 compared to 23,946 Boe/d (41% liquids) in the second quarter. Sales volumes were lower quarter-over-quarter as a result of natural declines and the previously disclosed shut-in of dry gas production that occurred in mid-June. New well production from 5 (5.0 net) new Duvernay wells that came onstream in May partially offset the decreases.

Development activities in the third quarter included the drilling of three (3.0 net) Duvernay wells at Kaybob North. Paramount plans to drill an additional two (2.0 net) Duvernay wells and bring on production six (6.0 net) Duvernay wells at Kaybob North in the fourth quarter of 2024.

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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 11% and liquids sales volumes were lower by approximately 8% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone.
(2)	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 10% and liquids sales volumes were lower by approximately 2% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone.

CENTRAL ALBERTA AND OTHER REGION

Central Alberta and Other Region sales volumes averaged 6,363 Boe/d (53% liquids) in the third quarter of 2024 compared to 8,183 Boe/d (49% liquids) in the second quarter. Third quarter sales volumes were lower quarter-over-quarter as a result of natural declines, a planned outage at the Company's Leafland facility and the shut-in of certain wells to allow for completion activities on offsetting wells.

Initial production from the three new Duvernay wells that were brought onstream in the quarter is in line with expectations, averaging gross 30-day peak production per well of 1,254 Boe/d (2.3 MMcf/d of shale gas and 865 Bbl/d of NGLs) with an average CGR of 371 Bbl/MMcf. ⁽¹⁾

In addition to the completion and tie-in of the three new Duvernay wells, development activities in the third quarter of 2024 included the ongoing construction of the Alhambra Plant at Willesden Green. The Alhambra Plant will add approximately 18,000 Boe/d of raw handling capacity (comprised of 50 MMcf/d or raw gas handling and 10,000 Bbl/d of raw liquids handling).

The Company has initiated its drilling program that will provide production to the first phase of the Alhambra Plant. Paramount plans to drill five (5.0 net) wells in the fourth quarter of 2024 and complete and tie-in those wells in advance of the planned fourth quarter 2025 start-up of the Alhambra Plant.

HEDGING

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

	Q4 2024	2025	Average Price ⁽¹⁾
Oil
NYMEX WTI Swaps (Sale) (Bbl/d)	5,000	5,000	C$105.00/Bbl

Natural gas
AECO – Basis (Physical Sale) (MMBtu/d)	13,478	–	NYMEX less US$0.93/MMBtu ⁽²⁾
Malin / Citygate Basis Swap (Sale) (MMBtu/d)	10,000	10,000	Citygate less US$1.03/MMBtu⁽³⁾

Foreign Currency Exchange
Swaps (Sale) (US$ million / month)	$30	–	1.3462 C$ / US$

(1)	Average price is calculated using a weighted average of notional volumes and prices.
(2)	"NYMEX" means NYMEX pricing at Henry Hub. The contract has a notional volume of 40,000 MMBtu/d for the final period of the term, October 2024.
(3)	"Malin" refers to Pacific Gas & Electric at Malin and "Citygate" refers to Pacific Gas & Electric Citygate. The remaining term of this contract is October 2024 to October 2027.

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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 13% and liquids sales volumes were lower by approximately 7% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone.

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 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)	Q3 2024		Q2 2024		Q3 2023
Net income	95.8		84.5		87.2
per share – basic ($/share)	0.65		0.58		0.61
per share – diluted ($/share)	0.64		0.57		0.59
Cash from operating activities	205.7		220.5		207.6
per share – basic ($/share)	1.40		1.51		1.45
per share – diluted ($/share)	1.38		1.47		1.40
Adjusted funds flow	200.7		266.2		234.2
per share – basic ($/share)	1.37		1.82		1.64
per share – diluted ($/share)	1.34		1.78		1.58
Free cash flow	(26.3)		20.3		18.5
per share – basic ($/share)	(0.18)		0.14		0.13
per share – diluted ($/share)	(0.18)		0.14		0.12
Total assets	4,544.1		4,589.2		4,305.1
Investments in securities	482.2		579.5		577.5
Long-term debt	44.0		–		–
Net (cash) debt	128.8		29.3		44.4
Common shares outstanding (millions) ⁽²⁾	146.5		146.7		143.4
Sales volumes ⁽³⁾
Natural gas (MMcf/d)	294.5		296.8		323.1
Condensate and oil (Bbl/d)	38,770		39,206		38,161
Other NGLs (Bbl/d)	7,045		6,928		6,627
Total (Boe/d)	94,892		95,609		98,644
% liquids	48 %		48 %		45 %
Grande Prairie Region (Boe/d)	67,635		63,480		74,381
Kaybob Region (Boe/d)	20,894		23,946		17,027
Central Alberta & Other Region (Boe/d)	6,363		8,183		7,236
Total (Boe/d)	94,892		95,609		98,644
Netback		($/Boe) ⁽⁴⁾		($/Boe) ⁽⁴⁾		($/Boe) ⁽⁴⁾
Natural gas revenue	37.2	1.37	45.6	1.69	79.3	2.67
Condensate and oil revenue	342.9	96.15	367.7	103.07	362.9	103.36
Other NGLs revenue	23.5	36.25	20.8	33.07	20.5	33.64
Royalty income and other revenue ⁽⁵⁾	1.2	–	9.5	–	1.1	–
Petroleum and natural gas sales	404.8	46.37	443.6	50.99	463.8	51.11
Royalties	(46.4)	(5.31)	(66.1)	(7.60)	(75.2)	(8.28)
Operating expense	(116.3)	(13.33)	(115.7)	(13.29)	(113.9)	(12.55)
Transportation and NGLs processing	(34.2)	(3.92)	(31.3)	(3.60)	(31.2)	(3.44)
Sales of commodities purchased ⁽⁶⁾	79.6	9.11	84.4	9.70	42.1	4.64
Commodities purchased ⁽⁶⁾	(78.5)	(9.00)	(82.4)	(9.47)	(39.2)	(4.32)
Netback	209.0	23.92	232.5	26.73	246.4	27.16
Risk management contract settlements	2.0	0.23	36.4	4.18	0.2	0.02
Netback including risk management contract settlements	211.0	24.15	268.9	30.91	246.6	27.18
Capital expenditures
Grande Prairie Region	84.6		154.8		117.6
Kaybob Region	56.5		40.9		41.4
Central Alberta & Other Region	73.0		45.9		35.5
Fox Drilling and Cavalier Energy	2.7		0.7		4.9
Corporate ⁽⁷⁾	(0.1)		(1.5)		(0.5)
Total	216.7		240.8		198.9
Asset retirement obligations settled	7.4		2.3		14.0

(1)	Adjusted funds flow, free cash flow and net (cash) debt are capital management measures used by Paramount. Netback and netback including risk management contract settlements are non-GAAP financial measures. Netback and Netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each measure, other than net income, that is presented on a per share, $/Mcf or $/Boe basis is a supplementary financial measure. Refer to "Specified Financial Measures".
(2)	Common shares are presented net of shares held in trust under the Company's restricted share unit plan: Q3 2024: 0.4 million, Q2 2024: 0.2 million, Q3 2023: 0.4 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)	Royalty income and other revenue for the nine months ended September 30, 2024 includes $10.0 million related to an initial payment from insurers for 2023 Alberta wildfire losses. This amount was not allocated to individual Regions or properties. The Company continues to advance its insurance claims process.
(6)	Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual regions or properties.
(7)	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

Q3 2024

Q2 2024

Q3 2023

Shale gas (MMcf/d)

249.0

243.1

276.7

Conventional natural gas (MMcf/d)

45.5

53.7

46.4

Natural gas (MMcf/d)

294.5

296.8

323.1

Condensate (Bbl/d)

36,830

36,825

35,984

Other NGLs (Bbl/d)

7,045

6,928

6,627

NGLs (Bbl/d)

43,875

43,753

42,611

Light and medium crude oil (Bbl/d)

1,235

1,566

1,154

Tight oil (Bbl/d)

368

466

627

Heavy crude oil (Bbl/d)

337

349

396

Crude oil (Bbl/d)

1,940

2,381

2,177

Total (Boe/d)

94,892

95,609

98,644

Grande Prairie Region

Kaybob Region

Central Alberta and Other
Region

Q3 2024

Q2 2024

Q3 2023

Q3 2024

Q2 2024

Q3 2023

Q3 2024

Q2 2024

Q3 2023

Shale gas (MMcf/d)

203.0

187.0

222.8

31.8

35.8

28.0

14.2

20.3

25.9

Conventional natural gas (MMcf/d)

0.2

0.3

0.4

41.6

48.8

41.7

3.7

4.6

4.3

Natural gas (MMcf/d)

203.2

187.3

223.2

73.4

84.6

69.7

17.9

24.9

30.2

Condensate (Bbl/d)

28,924

27,936

32,145

5,943

6,617

2,981

1,963

2,272

858

Other NGLs (Bbl/d)

4,723

4,179

4,815

1,403

1,599

1,188

919

1,150

624

NGLs (Bbl/d)

33,647

32,115

36,960

7,346

8,216

4,169

2,882

3,422

1,482

Light and medium crude oil (Bbl/d)

–

1,224

1,544

1,131

Tight oil (Bbl/d)

123

147

220

104

160

239

303

Heavy crude oil (Bbl/d)

–

337

349

396

Crude oil (Bbl/d)

123

147

220

1,309

1,624

1,235

508

610

722

Total (Boe/d)

67,635

63,480

74,381

20,894

23,946

17,027

6,363

8,183

7,236

Paramount is updating its fourth quarter 2024 sales volumes guidance to a range of 102,000 Boe/d to 109,000 Boe/d (51% shale gas and conventional natural gas combined, 42% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 7% Other NGLs).

SPECIFIED FINANCIAL MEASURES

Non-GAAP Financial Measures

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

Netback equals petroleum and natural gas sales (the most directly comparable measure disclosed in the Company's primary financial statements) plus sales of commodities purchased less royalties, operating expense, transportation and NGLs processing expense and commodities purchased. Sales of commodities purchased and commodities purchased are treated as corporate items and 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 September 30, 2024, June 30, 2024 and September 30, 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 and nine months ended September 30, 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 and nine months ended September 30, 2024 and 2023 and (iii) a calculation of net (cash) debt as at September 30, 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 the fourth quarter of 2024;
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) the expected timing of completion of the Alhambra Plant at Willesden Green and (iii) the expected capacity of the Alhambra Plant upon completion; 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 Alhambra Plant 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;
risks associated with wildfires, including the risk of physical loss or damage to wells, facilities, pipelines and other infrastructure, prolonged disruptions in production, restrictions on the ability to access properties, interruption of electrical and other services and significant delays or changes to planned development activities and facilities maintenance;
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 Alhambra Plant 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 Alhambra Plant 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 nine months ended September 30, 2024, the value ratio between crude oil and natural gas was approximately 73:1. 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.

SOURCE Paramount Resources Ltd.

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