Paramount Resources Ltd. Announces 2023 Annual Results, Non-Core Asset Disposition and Revised 2024 Guidance

CALGARY, AB, March 6, 2024 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its 2023 annual financial and operating results, highlighted by record production, and a $47 million non-core asset disposition.  The Company is also providing a production update and revised 2024 guidance.

2023 HIGHLIGHTS

• The Company achieved record annual sales volumes of 96,393 Boe/d (46% liquids) in 2023. Sales volumes in the fourth quarter were 101,348 Boe/d (46% liquids), of which 72,860 Boe/d (51% liquids) was produced in the Grande Prairie Region. ⁽¹⁾
• Cash from operating activities was $938 million ($6.56 per basic share) in 2023 and $287 million ($1.99 per basic share) in the fourth quarter. ⁽²⁾
• Adjusted funds flow was $965 million ($6.75 per basic share) in 2023 and $284 million ($1.97 per basic share) in the fourth quarter. ⁽²⁾
• Capital expenditures totaled $732 million in 2023, which were largely directed to the Grande Prairie Region Montney development and the Kaybob North and Willesden Green Duvernay developments.
• Asset retirement obligation settlements totaled $55 million in 2023, which included the abandonment of 82 wells and reclamation of 113 sites.
• Free cash flow was $168 million ($1.18 per basic share) in 2023 and $60 million ($0.41 per basic share) in the fourth quarter. ⁽²⁾
• Paramount returned $355 million to shareholders in 2023 comprised of $1.50 per share in regular monthly cash dividends and a special cash dividend of $1.00 per share.
• The Company realized total cash proceeds of approximately $45 million in the fourth quarter from the previously disclosed termination and close out of its 2024 NYMEX WTI swaps.

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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.

• At December 31, 2023, net debt was $60 million and Paramount's $1.0 billion revolving credit facility was undrawn. ⁽¹⁾
• The carrying value of the Company's investments in securities at December 31, 2023 was $541 million. Paramount received total cash dividends of $8 million in 2023 from these investments.

2023 RESERVES

• At December 31, 2023, the Company's: ⁽²⁾
  • proved developed producing ("PDP") reserves were 165 MMBoe with an NPV₁₀ of approximately $2.1 billion ($14.57 per basic share);
  • total proved ("TP") reserves were 415 MMBoe with an NPV₁₀ of approximately $4.5 billion ($31.60 per basic share); and
  • proved plus probable ("P+P") reserves were 761 MMBoe with an NPV₁₀ of approximately $7.9 billion ($55.04 per basic share).
• Paramount's reserves replacement ratios in 2023 were 1.4x for PDP reserves, 1.2x for TP reserves and 2.8x for P+P reserves. ⁽³⁾
• The Company's 2023 and three-year average F&D costs and recycle ratios are as follows: ⁽⁴⁾

	2023		Three-Year Average
	F&D Costs ($/Boe)	Recycle Ratio	F&D Costs ($/Boe)	Recycle Ratio
PDP	$16.58	1.6x	$10.89	3.0x
TP	$16.96	1.6x	$12.39	2.6x
P+P	$12.52	2.2x	$10.57	3.1x

• Dispositions in 2023 resulted in reductions to the Company's PDP reserves of 8.4 MMBoe, TP reserves of 35.6 MMBoe and P+P reserves of 59.8 MMBoe.

NON-CORE ASSET DISPOSTION

The Company sold certain non-core assets in the Kaybob Region in February 2024 for cash proceeds of approximately $47 million and has retained a 2% no-deduction gross overriding royalty on the undeveloped Montney acreage forming part of the assets (the "2024 Kaybob Disposition").  Paramount had previously forecast these assets to generate approximately 1,000 Boe/d of average annual sales volumes for 2024. 

CORPORATE UPDATE

• In the fourth quarter of 2023, Paramount brought on production a total of eleven (11.0 net) wells in the Grande Prairie Region, consisting of a three well pad in Karr and an eight well pad in Wapiti.
• In December, the Company successfully commissioned the liquids handling expansion of its Leafland natural gas processing plant at Willesden Green. The expansion was completed on budget and ahead of the originally scheduled January 2024 startup. The plant now has raw handling capacity of approximately 6,000 Bbl/d of liquids and 22 MMcf/d of natural gas.

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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)	All reserves are gross reserves based on an evaluation prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") dated March 5, 2024 and effective December 31, 2023 (the "McDaniel Report").  "NPV10" refers to the before tax net present value of future net revenue of the applicable reserves, discounted at 10 percent, as estimated in the McDaniel Report.  Such value does not represent fair market value.  Readers are referred to the advisories concerning "Reserves Data".
(3)	See "Oil and Gas Measures and Definitions" in the Advisories section of this document for a description of the calculation and use of reserves replacement ratio.
(4)	F&D costs and recycle ratio are non-GAAP ratios.  Refer to the "Specified Financial Measures" section and "Oil and Gas Measures and Definitions" in the Advisories section for more information on these measures and on the related non-GAAP financial measure of F&D capital.

• Paramount completed all four (4.0 net) Willesden Green Duvernay wells from its 2023 development program in early December.  These wells are all now on production and have exhibited strong results.  Three of the wells averaged gross 30-day peak production per well of 1,873 Boe/d (4.1 MMcf/d of shale gas and 1,195 Bbl/d of NGLs) with an average CGR of 294 Bbl/MMcf.  The fourth well has produced for 27 days and is exhibiting a similar production profile. ⁽¹⁾
• The Company recently commenced construction of its second natural gas processing facility at Willesden Green, with start-up anticipated in the fourth quarter of 2025. This first phase of the new facility will provide an estimated raw handling capacity of 10,000 Bbl/d of liquids and 50 MMcf/d of natural gas.
• All six (6.0 net) Kaybob North Duvernay wells that were drilled in 2023 were recently brought on production and have exhibited strong initial production rates.

PRODUCTION UPDATE AND REVISED 2024 GUIDANCE

Paramount is revising its forecast of 2024 sales volumes to a range of 100,000 Boe/d to 106,000 Boe/d (47% liquids), 9,000 Boe/d lower at the midpoint than prior guidance of 108,000 Boe/d to 116,000 Boe/d (47% liquids). 

The significant factors contributing to the revision are described below.

• The 2024 Kaybob Disposition completed in February has reduced forecast 2024 average sales volumes by approximately 1,000 Boe/d.
• Paramount has shut-in dry gas production due to the current natural gas price environment, reducing forecast 2024 average sales volumes by approximately 2,250 Boe/d. The Company continues to closely monitor market conditions and may restore or further reduce production as conditions warrant.
• Sales volumes were approximately 95,000 Boe/d (46% liquids) in January and 103,000 Boe/d (48% liquids) in February based on field estimates, approximately 14,000 Boe/d lower on average across the two months than expected. Cold weather in January resulted in a number of significant production upsets, particularly in the Grande Prairie Region. In addition, production was impacted by intermittent run time at key facilities, an unplanned pipeline outage in the Karr field that shut-in approximately 4,000 Boe/d of production for two weeks and the outage of a water disposal well in the Grande Prairie Region that will continue until the third quarter of 2024.
• 2024 production expectations from the five (5.0 net) well Karr 7-33S pad that was brought onstream in the third quarter of 2023 have been downwardly revised by approximately 3,500 Boe/d (55% liquids). Early production from the wells significantly exceeded type curve expectations and the prior guidance forecasted continued outperformance. The wells, which paid out in approximately three months of being brought onstream, are now performing in line with type curve expectations and the Company has reduced forecast sales volumes for the pad accordingly.
• The Company has benefited from strong new well performance in the Grande Prairie Region in growing its production base and maximizing netbacks, leading to the optimization of production from mature wells being deferred. There are currently 31 wells shut-in and 13 wells that would benefit from intervention in the Grande Prairie Region. The Company will incur incremental operating expenditures to pursue an aggressive well optimization program beginning in 2024 to increase production from these wells, the full benefit of which has not been incorporated into the revised 2024 sales volume forecast.

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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.  Natural gas sales volumes were lower by approximately 8% and liquids sales volumes were lower by approximately 20% due to shrinkage.  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.

• In total, Grande Prairie Region sales volumes are forecast to be approximately 6,000 Boe/d lower in 2024, primarily as a result of the revised Karr 7-33S pad production, earlier than anticipated tubing installations on certain wells at Karr due to higher than expected CGRs and the rescheduling of the 21-day outage at the third-party Wapiti natural gas processing plant from May to September.
• The Company has increased forecasted sales volumes by a total of 1,500 Boe/d in the Kaybob Region and Central Alberta and Other Region, largely due to better than expected Duvernay results.

The table below summarizes significant factors contributing to the revision in Paramount's 2024 sales volumes guidance at the midpoint:

	Midpoint Annual Average Sales Volumes (Boe/d)
Prior 2024 guidance	112,000
2024 Kaybob Disposition	-1,000
Dry gas production shut-ins	-2,250
January and February sales volumes lower than forecast	-1,250
Revisions to Grande Prairie Region forecast	-6,000
Revisions to Kaybob and Central Alberta and Other Region forecasts	+1,500
Revised 2024 guidance	103,000

The Company is updating its forecast of 2024 free cash flow to approximately $235 million from $350 million to reflect revised midpoint 2024 forecast sales volumes of 103,000 Boe/d (47% liquids) and updated operating cost, royalty and other assumptions. Free cash flow does not include the $47 million cash proceeds from the 2024 Kaybob Disposition.

	Prior 2024 Guidance	Revised 2024 Guidance
WTI	US$80.00/Bbl	No change
NYMEX	US$3.50/MMBtu
AECO	$2.84/GJ
Annual average sales volumes (Boe/d)	108,000 to 116,000 (47% liquids)	100,000 to 106,000 (47% liquids)
First half 2024 (Boe/d)	101,000 to 111,000 (46% liquids)	96,000 to 100,000 (47% liquids)
Second half 2024 (Boe/d)	115,000 to 121,000 (47% liquids)	104,000 to 112,000 (47% 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
Free cash flow ^(1)	$350 million	$235 million

The Company's midpoint 2024 capital program, abandonment and reclamation expenditures and regular monthly dividend is fully funded under the above forecast.  The Company's midpoint 2024 sustaining and maintenance capital program, abandonment and reclamation expenditures and regular monthly dividend would remain fully funded down to an average WTI price in 2024 of about US$61/Bbl, assuming no changes to the other forecast assumptions. See "Advisories – Pricing Sensitivity" for additional sensitivities of 2024 free cash flow to changes in commodity price assumptions.

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(1)

Free cash flow is a capital management measure used by Paramount.  Refer to "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) $10 million in geological and geophysical expenses, (iv) realized pricing of $56.90/Boe (reflecting changes to production mix); (v) a $US/$CAD exchange rate of $0.735, (vi) royalties of $8.35/Boe, (vii) operating costs of $12.90/Boe and (vii) transportation and NGLs processing costs of $3.85/Boe.  For comparative purposes, the previous 2024 free cash flow forecast utilized the following differing assumptions as to the following factors: (i) $7 million in geological and geophysical expenses, (ii) realized pricing of $56.40/Boe, (iii) royalties of $8.80/Boe, (iv) operating costs of $12.05/Boe and (v) transportation and NGLs processing costs of $3.70/Boe.

MARCH DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.125 per class A common share that will be payable on March 28, 2024 to shareholders of record on March 15, 2024.  The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

ANNUAL GENERAL MEETING

Paramount will hold its annual general meeting of shareholders on Thursday, May 2, 2024 at 10:30 am (Calgary time) in the Bankers Hall Auditorium located at 315 - 8th Avenue S.W., Calgary, Alberta.

COMPLETE ANNUAL RESULTS

Paramount's: (i) complete annual results, including a review of operations, the Company's audited consolidated financial statements as at and for the year ended December 31, 2023 (the "Consolidated Financial Statements") and the accompanying management's discussion and analysis (the "MD&A"); and (ii) 2023 annual information form, which contains additional important information concerning the Company's reserves, properties and operations, 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.

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".

FINANCIAL AND OPERATING RESULTS ^(1)
($ millions, except as noted)	Three months ended December 31					Year ended December 31
	2023			2022		2023			2022
Net income	111.9			259.9			470.2		680.6
per share – basic ($/share)	0.78			1.83			3.29		4.83
per share – diluted ($/share)	0.75			1.76			3.17		4.63
Cash from operating activities	287.0			306.9			938.2		1,049.6
per share – basic ($/share)	1.99			2.17			6.56		7.45
per share – diluted ($/share)	1.93			2.08			6.32		7.14
Adjusted funds flow	284.1			340.7			965.3		1,171.0
per share – basic ($/share)	1.97			2.40			6.75		8.32
per share – diluted ($/share)	1.91			2.31			6.51		7.97
Free cash flow	59.7			162.0			168.4		471.1
per share – basic ($/share)	0.41			1.14			1.18		3.35
per share – diluted ($/share)	0.40			1.10			1.13		3.20
Total assets							4,388.7		4,337.3
Investments in securities							540.9		557.1
Long-term debt							–		159.4
Net (cash) debt							59.6		161.2
Common shares outstanding (millions) ^(2)							144.2		142.0
Sales volumes ^(3)
Natural gas (MMcf/d)	326.2			321.9		315.1			294.7
Condensate and oil (Bbl/d)	40,290			37,580		37,657			33,908
Other NGLs (Bbl/d)	6,698			6,143		6,226			5,650
Total (Boe/d)	101,348			97,370		96,393			88,672
% liquids	46 %			45 %		46 %			45 %
Grande Prairie Region (Boe/d)	72,860			64,434		70,943			58,519
Kaybob Region (Boe/d)	20,324			24,477		17,449			22,730
Central Alberta & Other Region (Boe/d)	8,164			8,459		8,001			7,423
Total (Boe/d)	101,348			97,370		96,393			88,672
Netback		$/Boe ^(4)			$/Boe ^(4)			$/Boe ^(4)		$/Boe ^(4)
Natural gas revenue	83.7	2.79		194.2	6.56		349.1	3.04	671.1	6.24
Condensate and oil revenue	363.7	98.12		375.1	108.50		1,364.2	99.25	1,448.9	117.07
Other NGLs revenue	22.2	36.00		27.3	48.25		81.9	36.06	114.2	55.37
Royalty income and other revenue	0.9	–		1.1	–		3.3	–	18.2	–
Petroleum and natural gas sales	470.5	50.46		597.7	66.72		1,798.5	51.12	2,252.4	69.60
Royalties	(68.9)	(7.39)		(84.4)	(9.43)		(254.3)	(7.23)	(335.3)	(10.36)
Operating expense	(126.4)	(13.56)		(119.2)	(13.31)		(453.8)	(12.90)	(407.1)	(12.58)
Transportation and NGLs processing	(33.2)	(3.56)		(27.2)	(3.03)		(134.4)	(3.82)	(123.7)	(3.82)
Sales of commodities purchased ^(5)	50.2	5.38		102.7	11.47		255.1	7.25	272.0	8.41
Commodities purchased ^(5)	(47.4)	(5.08)		(100.4)	(11.21)		(250.2)	(7.11)	(267.0)	(8.25)
Netback	244.8	26.25		369.2	41.21		960.9	27.31	1,391.3	43.00
Risk management contract settlements	43.0	4.61		(23.0)	(2.57)		46.7	1.33	(179.0)	(5.53)
Netback including risk management contract settlements	287.8	30.86		346.2	38.64		1,007.6	28.64	1,212.3	37.47
Capital expenditures
Grande Prairie Region	75.8			135.8		380.3			453.3
Kaybob Region	64.5			11.4		190.4			131.2
Central Alberta and Other Region	61.7			1.0		120.0			2.1
Fox Drilling and Cavalier Energy	3.9			12.1		29.2			27.7
Corporate	3.0			9.3		12.2			40.7
Total	208.9			169.6		732.1			655.0
Asset retirement obligations settled	12.8			7.0		54.6			36.1

(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: 2023: 0.4 million, 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.

	Annual
	Total		Grande Prairie Region		Kaybob Region		Central Alberta and Other Region
	2023	2022	2023	2022	2023	2022	2023	2022
Shale gas (MMcf/d)	265.2	232.9	209.3	166.9	28.2	38.5	27.7	27.5
Conventional natural gas (MMcf/d)	49.9	61.8	0.4	1.3	44.6	55.0	4.9	5.5
Natural gas (MMcf/d)	315.1	294.7	209.7	168.2	72.8	93.5	32.6	33.0
Condensate (Bbl/d)	35,148	31,228	31,433	27,095	2,655	3,192	1,060	941
Other NGLs (Bbl/d)	6,226	5,650	4,414	3,394	1,070	1,620	742	636
NGLs (Bbl/d)	41,374	36,878	35,847	30,489	3,725	4,812	1,802	1,577
Light and medium crude oil (Bbl/d)	1,469	2,200	–	4	1,440	2,066	29	130
Tight oil (Bbl/d)	616	480	152	–	158	261	306	219
Heavy crude oil (Bbl/d)	424	–	–	–	–	–	424	–
Crude oil (Bbl/d)	2,509	2,680	152	4	1,598	2,327	759	349
Total (Boe/d)	96,393	88,672	70,943	58,519	17,449	22,730	8,001	7,423

	Q4
	Total		Grande Prairie Region		Kaybob Region		Central Alberta and Other Region
	2023	2022	2023	2022	2023	2022	2023	2022
Shale gas (MMcf/d)	271.8	260.0	214.1	188.4	30.2	41.9	27.5	29.7
Conventional natural gas (MMcf/d)	54.4	61.9	0.3	1.5	49.6	55.0	4.5	5.4
Natural gas (MMcf/d)	326.2	321.9	214.4	189.9	79.8	96.9	32.0	35.1
Condensate (Bbl/d)	37,522	34,616	32,155	29,146	4,003	4,354	1,364	1,116
Other NGLs (Bbl/d)	6,698	6,143	4,742	3,631	1,209	1,671	747	841
NGLs (Bbl/d)	44,220	40,759	36,897	32,777	5,212	6,025	2,111	1,957
Light and medium crude oil (Bbl/d)	1,636	2,335	–	–	1,602	2,045	34	290
Tight oil (Bbl/d)	699	629	227	–	205	262	267	367
Heavy crude oil (Bbl/d)	433	–	–	–	–	–	433	–
Crude oil (Bbl/d)	2,768	2,964	227	–	1,807	2,307	734	657
Total (Boe/d)	101,348	97,370	72,860	64,434	20,324	24,477	8,164	8,459

The Company forecasts that 2024 annual sales volumes will average between 100,000 Boe/d and 106,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs).  First half 2024 sales volumes are expected to average between 96,000 Boe/d and 100,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs).  Second half 2024 sales volumes are expected to average between 104,000 Boe/d and 112,000 Boe/d (53% shale gas and conventional natural gas combined, 41% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% Other NGLs). 

SPECIFIED FINANCIAL MEASURES

Non-GAAP Financial Measures

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

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

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

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

F&D capital is a measure used in determining F&D costs and is comprised of capital expenditures (the most directly comparable measure disclosed in the Company's primary financial statements) for the applicable year, excluding certain expenditures described herein, plus the change from the prior year in estimated future development capital included in the applicable reserves evaluation prepared by McDaniel. Capital expenditures related to Fox Drilling and corporate capital expenditures are excluded in all periods where F&D capital has been calculated.  Capital expenditures related to Cavalier Energy are excluded in all periods were F&D capital has been calculated prior to 2023 as no reserves were attributed to the properties of Cavalier Energy prior to 2023.  F&D capital is used by management and investors, in calculating F&D costs, to represent the amount of capital invested in oil and gas exploration and development projects to generate reserves additions. 

Set out below is the calculation of F&D capital for the years ended December 31, 2023, 2022 and 2021.  Columns may not add due to rounding.

($ millions)	Total Company
Proved Developed Producing	2023	2022	2021	3-year Total
Capital expenditures	732	655	275	1,662
Fox Drilling, Cavalier Energy (2022 and 2021) and corporate	(34)	(69)	(6)	(109)
Change in estimated future development capital	94	(10)	(11)	73
F&D Capital – PDP	792	577	257	1,626
Total Proved	2023	2022	2021	3-year Total
Capital expenditures	732	655	275	1,662
Fox Drilling, Cavalier Energy (2022 and 2021) and corporate	(34)	(69)	(6)	(109)
Change in estimated future development capital	1	1,249	221	1,471
F&D Capital – TP	700	1,835	490	3,025
Proved Plus Probable	2023	2022	2021	3-year Total
Capital expenditures	732	655	275	1,662
Fox Drilling, Cavalier Energy (2022 and 2021) and corporate	(34)	(69)	(6)	(109)
Change in estimated future development capital	516	1,176	(93)	1,599
F&D Capital – P+P	1,214	1,762	176	3,152

Non-GAAP Ratios

F&D costs, recycle ratio, 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.

F&D costs are calculated by dividing: (i) F&D capital (a non-GAAP financial measure) for the applicable reserves category and period; by (ii) the net changes to reserves in such reserves category from the prior period from extensions/improved recovery, technical revisions and economic factors, expressed in Boe.  F&D costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions.  Readers should refer to the information under the heading "Reserves and Other Oil and Gas Information – Reserves Information – Reserves Reconciliation" in the Company's annual information forms for the years ended December 31, 2023, 2022 and 2021, which are available on SEDAR+ at www.sedarplus.ca or on the Company's website at www.paramountres.com, for a description of the net changes to reserves from the prior year.  See "Advisories – Oil and Gas Definitions and Measures" below for more information about this measure.

Recycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per Boe for the period by the F&D costs for the period.  Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production.  See "Advisories – Oil and Gas Definitions and Measures" for more information about this measure.

Set out below are the applicable F&D costs and recycle ratios for 2023, 2022 and 2021. 

	F&D ($/Boe)			Recycle Ratio *
	2023	2022	2021	2023	2022	2021
Proved Developed Producing	$16.58	$9.58	$6.22	1.6x	4.5x	4.3x
Total Proved	$16.96	$14.11	$6.72	1.6x	3.0x	4.0x
Proved plus Probable	$12.52	$14.87	$2.12	2.2x	2.9x	12.6x

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 18 – Capital Structure in the Consolidated Financial Statements of Paramount 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 years ended December 31, 2023 and 2022 and (iii) a calculation of net (cash) debt as at December 31, 2023 and 2022.

The following is a reconciliation of adjusted funds flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three months ended December 31, 2023 and 2022:

Three months ended December 31 ($millions)	2023	2022
Cash from operating activities	287.0	306.9
Change in non-cash working capital	(18.4)	48.7
Geological and geophysical expense	2.7	2.1
Asset retirement obligations settled	12.8	7.0
Closure costs	–	–
Provisions	–	(24.0)
Settlements	–	–
Transaction and reorganization costs	–	–
Adjusted funds flow	284.1	340.7

The following is a reconciliation of free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three months ended December 31, 2023 and 2022:

Three months ended December 31 ($ millions)	2023	2022
Cash from operating activities	287.0	306.9
Change in non-cash working capital	(18.4)	48.7
Geological and geophysical expense	2.7	2.1
Asset retirement obligations settled	12.8	7.0
Closure costs	–	–
Provisions	–	(24.0)
Settlements	–	–
Transaction and reorganization costs	–	–
Adjusted funds flow	284.1	340.7
Capital expenditures	(208.9)	(169.6)
Geological and geophysical expense	(2.7)	(2.1)
Asset retirement obligation settled	(12.8)	(7.0)
Free cash flow	59.7	162.0

Supplementary Financial Measures

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

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

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

ADVISORIES

Forward-looking Information

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

• forecast sales volumes for 2024 and certain periods therein;
• planned capital expenditures in 2024 and the allocation thereof between sustaining and maintenance capital and growth capital;
• planned abandonment and reclamation expenditures in 2024;
• forecast free cash flow in 2024;
• the expected construction of a new natural gas processing facility at Willesden Green and the anticipated timing of start-up and estimated capacity upon completion; and
• the potential payment of future dividends.

Statements relating to reserves are also deemed to be forward looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted or estimated and that the reserves can be profitably produced in the future.

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

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

Although Paramount believes that the expectations reflected in such forward-looking information are reasonable based on the information available at the time of this press release, undue reliance should not be placed on the forward-looking information as Paramount can give no assurance that such expectations will prove to be correct.  Forward-looking information is based on expectations, estimates and projections that involve a number of risks and uncertainties which could cause actual results to differ materially from those anticipated by Paramount and described in the forward-looking information.  The material risks and uncertainties include, but are not limited to:

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

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

The foregoing list of risks is not exhaustive. For more information relating to risks, see the section titled "Risk Factors" in Paramount's annual information form for the year ended December 31, 2023, which is available on SEDAR+ at www.sedarplus.ca or on the Company's website at www.paramountres.com.  The forward-looking information contained in this press release is made as of the date hereof and, except as required by applicable securities law, Paramount undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, future events or otherwise.

Certain forward-looking information in this press release, including forecast free cash flow in 2024, may also constitute a "financial outlook" within the meaning of applicable securities laws. A financial outlook involves statements about Paramount's prospective financial performance or position and is based on and subject to the assumptions and risk factors described above in respect of forward-looking information generally as well as any other specific assumptions and risk factors in relation to such financial outlook noted in this press release. Such assumptions are based on management's assessment of the relevant information currently available and any financial outlook included in this press release is provided for the purpose of helping readers understand Paramount's current expectations and plans for the future. Readers are cautioned that reliance on any financial outlook may not be appropriate for other purposes or in other circumstances and that the risk factors described above or other factors may cause actual results to differ materially from any financial outlook.

Reserves Data

Reserves data set forth in this press release is based upon an evaluation of the Company's reserves prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") dated March 5, 2024 and effective December 31, 2023 (the "McDaniel Report").  The reserves referenced in this press release are gross reserves. The price forecast used in the McDaniel Report is an average of the January 1, 2024 price forecasts for McDaniel and GLJ Petroleum Consultants Ltd. and the December 31, 2023 price forecast of Sproule Associates Ltd.  The estimates of reserves contained in the McDaniel Report and referenced in this press release are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual reserves may be greater than or less than the estimates contained in the McDaniel Report and referenced in this press release.  There is no assurance that the forecast prices and costs assumptions used in the McDaniel Report will be attained, and variances could be material.  Estimated future net revenue does not represent fair market value.  The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties due to the effects of aggregation.  Readers should refer to 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, for a complete description of the McDaniel Report (including reserves by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil, tight oil and heavy crude oil) and the material assumptions, limitations and risk factors pertaining thereto.

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 year ended December 31, 2023, the value ratio between crude oil and natural gas was approximately 36:1. 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 contains metrics commonly used in the oil and natural gas industry. These metrics are "CGR", F&D costs, recycle ratio and reserves replacement ratio.  Each of these metrics is determined by the Company as set out below or elsewhere in this press release.  These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these 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.

"CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes.

Refer to the "Specified Financial Measures" section of this press release for a description of the calculation and use of F&D costs and recycle ratio. 

Reserves replacement ratio is calculated by dividing: (i) the net changes in reserves from the prior year in the applicable category from technical revisions, economic factors and extensions/improved recovery, by (ii) the aggregate production during the year.  Reserves replacement ratio is a measure commonly used by management and investors to assess the rate at which reserves depleted by production are being replaced.

Additional information respecting the Company's oil and gas properties and operations is provided in the Company's annual information form for the year ended December 31, 2023 which is available on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com.

Pricing Sensitivity

The below table reflects forecast 2024 free cash flow under the revised 2024 guidance and, for illustrative comparison, two alternative pricing scenarios:

	Revised 2024 Guidance	Alternative Scenario 1	Alternative Scenario 2
WTI	US$80.00/Bbl	US$77.50/Bbl	US$75.00/Bbl
NYMEX	US$3.50/MMBtu	US$3.00/MMBtu	US$2.40/MMBtu
AECO	$2.84/GJ	$2.37/GJ	$1.90/GJ
2024 Free Cash Flow	$235 million	$135 million	$25 million

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

SOURCE Paramount Resources Ltd.

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