Paramount Resources Ltd. Announces 2024 Annual Results

Company Announcements

Paramount Resources Ltd. Announces 2024 Annual Results

Mar 05 2025 12:00 GMT

CALGARY, AB , March 5, 2025 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its 2024 annual financial and operating results.

RECENT EVENTS

On January 31, 2025, Paramount closed the sale of its Karr, Wapiti and Zama properties to a wholly-owned subsidiary of Ovintiv Inc. ("Ovintiv") for cash proceeds of approximately $3.3 billion, after adjustments, plus certain Horn River Basin properties of Ovintiv (the "Grande Prairie Disposition").
The Company used a portion of the proceeds of the Grande Prairie Disposition to pay a special cash distribution (the "Special Distribution") of $15.00 per class A common share ("Common Share") to shareholders on February 14, 2025 comprised of a return of capital of $12.00 per Common Share and a special dividend of $3.00 per Common Share.
Paramount repurchased a total of 5.7 million Common Shares under its normal course issuer bid between late-November 2024 and early-February 2025 at a total cost of $177 million.

2024 HIGHLIGHTS

The Company achieved record annual sales volumes of 98,490 Boe/d (48% liquids) in 2024 and record quarterly sales volumes of 102,477 Boe/d (48% liquids) in the fourth quarter. ⁽¹⁾
Sales volumes excluding Karr and Wapiti were 31,178 Boe/d (44% liquids) in 2024 and 31,425 Boe/d (45% liquids) in the fourth quarter. Duvernay production accounted for approximately 15,000 Boe/d (64% liquids) of these sales volumes in 2024.
Cash from operating activities was $815 million ($5.58 per basic share) in 2024 and $188 million ($1.28 per basic share) in the fourth quarter. ⁽²⁾
Adjusted funds flow was $930 million ($6.37 per basic share) in 2024 and $238 million ($1.62 per basic share) in the fourth quarter.

_________________________________________
(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.

Capital expenditures totaled $842 million in 2024, which were largely directed to the Grande Prairie Region Montney development and the Willesden Green and Kaybob North Duvernay developments.
Paramount drilled 58 (58.0 net) wells, brought 59 (58.4 net) wells on production and advanced the construction of the new Alhambra Plant at Willesden Green.
Asset retirement obligation settlements totaled $38 million in 2024, which included the abandonment of 44 wells and reclamation of 119 sites.
Free cash flow was $37 million ($0.25 per basic share) in 2024 and $53 million ($0.36 per basic share) in the fourth quarter.
At December 31, 2024, net debt was $188 million. ⁽¹⁾
The carrying value of the Company's investments in securities at December 31, 2024 was $564 million. Paramount received total cash dividends of $12 million in 2024 from these investments.
In addition to its investment in securities, Paramount'sFox Drilling subsidiary continues to own six triple-sized drilling rigs, four of which are utilized for Company wells and two of which are under contract to a third party.

SHAREHOLDER RETURNS AND LIQUIDITY

Since the start of 2021, Paramount has:
- paid a total of $20.73 per Common Share ($2.97 billion) in regular monthly dividends and special distributions;
- fully repaid its bank credit facility, reducing debt by over $800 million; and
- continued to build material, contiguous, low-cost land positions in key resource plays, including at Willesden Green and Sinclair.
The Company has repurchased a total of 5.7 million Common Shares under its current normal course issuer bid, representing 72% of the maximum number of shares, at an aggregate cost of $177 million.
At February 28, 2025, the Company had approximately $830 million in cash and cash equivalents, investments in securities valued at approximately $470 million and an undrawn $500 million four-year financial covenant-based revolving bank credit facility. This provides Paramount ample liquidity to advance the development of its deep inventory of opportunities.

__________________________________________
(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.

RESERVES

At December 31, 2024, the Company's gross reserves were as follows: ⁽¹⁾

	Total Company		Total Company Excluding Karr & Wapiti ⁽²⁾
	MMBoe	NPV₁₀ ($MM)	MMBoe	NPV₁₀ ($MM)
Proved Developed Producing ("PDP")	167.0	2,308	40.5	429
Total Proved ("TP")	423.1	4,678	140.3	1,411
Total Proved Plus Probable ("P+P")	756.5	7,703	242.5	2,462

The following table summarizes the Company's PDP, TP and P+P gross reserves at December 31, 2024, excluding the Karr and Wapiti properties:

	Gross Reserves
	Proved Developed Producing	Total Proved	Total Proved Plus Probable
Natural gas (Bcf)	143	431	730
NGLs (MBbl)	13,944	65,694	116,854
Crude oil (MBbl)	2,673	2,727	3,889
Total (MBoe)	40,528	140,329	242,479
*% Liquids*	41 %	49 %	50 %

The following table summarizes Paramount's gross proved and proved plus probable developed and undeveloped reserves, excluding the Karr and Wapiti properties, as at December 31, 2024, and the net present value of future net revenue of these reserves before income taxes, undiscounted and discounted at 10%.

	Proved			Proved plus Probable
	Gross Reserves	Future Net Revenue NPV Before Tax ($ millions)		Gross Reserves	Future Net Revenue NPV Before Tax ($ millions)
	(MBoe)	0 %	10 %	(MBoe)	0 %	10 %
Developed	45,603	(126)	441	66,390	311	635
Undeveloped	94,726	2,158	971	176,089	4,737	1,827
Total	140,329	2,032	1,411	242,479	5,048	2,462

__________________________________________
(1)	All reserves in this press release are gross reserves based on an evaluation prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") dated March 4, 2025 and effective December 31, 2024 (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".
(2)	Total Company Excluding Karr & Wapiti has been presented to help readers assess the impact of the sale of Karr and Wapiti on the Company's December 31, 2024 reserves. Reserves associated with additional Horn River Basin properties acquired by Paramount as part of the Grande Prairie Disposition are not included.

2025 GUIDANCE

As previously announced, the Company is budgeting capital expenditures in 2025 of between $760 million and $790 million, focused mainly on its Willesden Green Duvernay and Kaybob North Duvernay developments. Capital has also been allocated to ongoing appraisal activities at Paramount's early-stage assets, including Sinclair.

As previously announced, 2025 average sales volumes are expected to be between 37,500 Boe/d and 42,500 Boe/d (48% liquids), with a 2025 year-end exit rate in excess of 45,000 Boe/d. Revised estimated January sales volumes, which included production from the assets sold pursuant to the Grande Prairie Disposition, averaged approximately 101,500 Boe/d (47% liquids). Sales volumes are anticipated to average between 28,000 Boe/d and 32,000 Boe/d in February to September, with new well activity essentially offsetting declines. With the start-up of the first phase of the new Alhambra Plant at Willesden Green, fourth quarter sales volumes are anticipated to average between 40,000 Boe/d and 45,000 Boe/d.

REVIEW OF OPERATIONS

CENTRAL ALBERTA AND OTHER REGION

The Central Alberta and Other Region includes:

the Willesden Green Duvernay development in central Alberta;
shale gas properties in northeast British Columbia in the Horn River Basin, where the Company holds 113,000 net acres of Muskwa rights (including 68,000 net acres acquired as part of the consideration for the Grande Prairie Disposition), and in the Liard Basin, where the Company holds 179,000 net acres of Besa River rights; and
1.31 million net acres of land that are prospective for cold flow heavy oil and in-situ thermal oil recovery, including 297,000 net acres with Clearwater and Bluesky cold flow heavy oil potential and 71,000 net acres with thermal oil potential at its Hoole Grand Rapids project.

Development activities in the Central Alberta and Other Region in 2024 were focused on Willesden Green, where the Company holds 263,000 net acres of contiguous Duvernay rights, operates and majority owns the Leafland Plant and is in the process of constructing the first phase of its wholly-owned and operated Alhambra Plant. The Leafland Plant has raw handling capacity of approximately 6,000 Bbl/d of liquids and 22 MMcf/d of natural gas. The Alhambra Plant will provide estimated raw handling capacity of 10,000 Bbl/d of liquids and 50 MMcf/d of natural gas upon start-up of the first phase and is designed to be capable of expansion to a total capacity of 30,000 Bbl/d of raw liquids and 150 MMcf/d of raw natural gas through the construction of two additional phases.

Capital expenditures in the Central Alberta and Other Region totaled $238 million in 2024. Development activities included the ongoing construction of the Alhambra Plant, the drilling of 10 (10.0 net) Duvernay wells and the bringing onstream of five (5.0 net) Duvernay wells, all at Willesden Green.

Central Alberta and Other Region sales volumes averaged 8,723 Boe/d (50% liquids) in 2024 compared to 8,001 Boe/d (32% liquids) in 2023. Sales volumes were higher due to production growth from new liquids-rich Duvernay wells at Willesden Green. Lower dry gas sales in northeast British Columbia due to economic shut-ins partially offset this new production.

Approximately $560 million of the Company's planned 2025 capital expenditures at the midpoint are allocated to the Willesden Green Duvernay development, with expenditures anticipated to be evenly weighted between the first and second half of the year. Approximately one third of planned expenditures are related to the buildout of facilities and infrastructure in the area, including the completion of the first phase of the Alhambra Plant, the acceleration of the second phase of the Alhambra Plant, construction of a pipeline interconnect between the Leafland Plant and the Alhambra Plant and installation of additional compression at the Leafland Plant.

Startup of the first phase of the Alhambra Plant is expected in the fourth quarter of 2025. Construction is progressing as planned with all mechanical packages received and set on piles. Engineering and procurement of equipment packages for the second phase of the Alhambra Plant have commenced. The Company anticipates start-up of the second phase in the fourth quarter of 2026.

Paramount anticipates drilling 22 (22.0 net) Duvernay wells and bringing onstream 23 (23.0 net) Duvernay wells at Willesden Green in 2025. Seven wells are expected to feed the Leafland Plant with the remaining 16 wells expected to be brought onstream through the first phase of the Alhambra Plant upon start-up.

KAYBOB REGION

The Kaybob Region, located in west-central Alberta, includes the Kaybob North Duvernay development and other natural gas and oil producing properties. The Company holds 109,000 net acres of Duvernay rights and 179,000 net acres of Montney rights in the Kaybob Region and also owns and operates extensive processing and gathering infrastructure in the region.

Capital expenditures in the Kaybob Region totaled $173 million in 2024 and were focused on the Kaybob North Duvernay development. Development activities included the drilling of 14 (14.0 net) Duvernay wells and the bringing on production of 17 (17.0 net) Duvernay wells at Kaybob North.

Kaybob Region sales volumes averaged 22,404 Boe/d (41% liquids) in 2024 compared to 17,449 Boe/d (31% liquids) in 2023. The increase in sales volumes was primarily the result of new well production from the Kaybob North Duvernay development as well as improved run times compared to 2023 when production was impacted by the Alberta wildfires.

Capital expenditures in the Kaybob Region in 2025 are expected to be approximately $135 million at the midpoint, weighted approximately 65% to the first half of the year. In 2025, the Company anticipates drilling eight (8.0 net) Duvernay wells and bringing onstream nine (9.0 net) Duvernay wells at Kaybob North.

SINCLAIR

Sinclair is an early-stage property comprised of approximately 107,000 net acres of Montney rights located west of Grande Prairie, Alberta that are prospective for high-rate gas production.

The Company has completed its first two appraisal wells at Sinclair and is currently in the process of flow testing the wells. Data obtained from the drilling and completion operations and flow tests will be analyzed to inform future development plans for the property. Paramount is planning to drill an additional two (2.0 net) Montney wells at Sinclair in the fourth quarter of 2025 to further inform its development plans. The Company has secured downstream transportation capacity that would enable the first phase of Sinclair production to commence as early as the fourth quarter of 2027.

GRANDE PRAIRIE REGION

Prior to the Grande Prairie Disposition, Paramount's primary focus in the Grande Prairie Region was its Karr and Wapiti Montney properties, located south of the city of Grande Prairie, Alberta. The Karr and Wapiti properties represented essentially all 2024 Grande Prairie Region sales volumes, which averaged 67,363 Boe/d (50% liquids). Capital expenditures in the Grande Prairie Region totaled $431 million in 2024, the vast majority of which was directed to the Karr and Wapiti properties.

LAND

Paramount's land position as at December 31, 2024 is summarized below.

(thousands of acres)	Gross ⁽¹⁾	Net ⁽²⁾
Acreage assigned reserves	696	533
Acreage not assigned reserves	3,624	2,572
Total	4,320	3,105


(1)	Gross acres means the total acreage in which Paramount has an interest. Gross acreage is calculated only once per lease or license of petroleum and natural gas rights ("Lease") regardless of whether or not Paramount holds a working and/or royalty interest, or whether or not the Lease includes multiple prospective formations. If Paramount holds interests in different formations beneath the same surface location pursuant to separate Leases, the acreage set out in each Lease is counted.
(2)	Net acres means gross acres multiplied by Paramount's working interest therein.

MARCH DIVIDEND

Paramount's Board of Directors has declared a cash dividend of $0.05 per Common Share that will be payable on March 31, 2025 to shareholders of record on March 17, 2025. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.

HEDGING & GAS MARKET DIVERSIFICATION

HEDGING

The Company's current financial commodity contracts are summarized below:

(1)	Average price is calculated using a weighted average of notional volumes and prices.
(2)	"Citygate" refers to Pacific Gas & Electric Citygate and "Malin" refers to Pacific Gas & Electric Malin. Pursuant to the swap transaction Paramount sells at Citygate less US$1.03/MMBtu and buys at Malin. The transaction is financially settled with no physical delivery. The remaining term of this contract is Jan 2025 to Oct 2027.

GAS MARKET DIVERSIFICATION

With the natural gas market diversification contracts currently in place, approximately 70% of the Company's natural gas sales volumes following the closing of the Grande Prairie Disposition will benefit from exposure to markets outside of AECO.

ANNUAL GENERAL MEETING

Paramount will hold its annual general meeting of shareholders on Tuesday, May 13, 2025 at 10:00 a.m. (Mountain Time) in the Doulton Room at Bankers Hall Conference Centre, 400, 315 - 8th Avenue S.W., Calgary, Alberta.

COMPLETE ANNUAL RESULTS

Paramount's: (i) complete annual results, including the Company's audited consolidated financial statements as at and for the year ended December 31, 2024 (the "Consolidated Financial Statements") and the accompanying management's discussion and analysis (the "MD&A"); and (ii) 2024 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
	2024		2023		2024		2023
Net income	87.4		111.9		335.9		470.2
per share – basic ($/share)	0.60		0.78		2.30		3.29
per share – diluted ($/share)	0.59		0.75		2.25		3.17
Cash from operating activities	187.7		287.0		815.3		938.2
per share – basic ($/share)	1.28		1.99		5.58		6.56
per share – diluted ($/share)	1.26		1.93		5.46		6.32
Adjusted funds flow	237.8		284.1		930.3		965.3
per share – basic ($/share)	1.62		1.97		6.37		6.75
per share – diluted ($/share)	1.59		1.91		6.24		6.51
Free cash flow	52.8		59.7		37.3		168.4
per share – basic ($/share)	0.36		0.41		0.25		1.18
per share – diluted ($/share)	0.35		0.40		0.25		1.13
Total assets					4,757.5		4,388.7
Investments in securities					563.9		540.9
Long-term debt					173.0		–
Net (cash) debt					188.4		59.6
Common shares outstanding (millions) ⁽²⁾					146.9		144.2

Sales volumes ⁽³⁾
Natural gas (MMcf/d)	317.3		326.2		306.8		315.1
Condensate and oil (Bbl/d)	42,835		40,290		40,432		37,657
Other NGLs (Bbl/d)	6,753		6,698		6,920		6,226
Total (Boe/d)	102,477		101,348		98,490		96,393
*% liquids*	48 %		46 %		48 %		46 %
Grande Prairie Region (Boe/d)	71,130		72,860		67,363		70,943
Kaybob Region (Boe/d)	22,441		20,324		22,404		17,449
Central Alberta & Other Region (Boe/d)	8,906		8,164		8,723		8,001
Total (Boe/d)	102,477		101,348		98,490		96,393

Netback		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾		$/Boe ⁽⁴⁾
Natural gas revenue	58.0	1.99	83.7	2.79	223.3	1.99	349.1	3.04
Condensate and oil revenue	379.4	96.26	363.7	98.12	1,434.9	96.96	1,364.2	99.25
Other NGLs revenue	21.3	34.32	22.2	36.00	89.6	35.37	81.9	36.06
Royalty income and other revenue⁽⁵⁾	0.6	–	0.9	–	12.4	–	3.3	–
Petroleum and natural gas sales	459.3	48.72	470.5	50.46	1,760.2	48.83	1,798.5	51.12
Royalties	(48.5)	(5.14)	(68.9)	(7.39)	(222.8)	(6.18)	(254.3)	(7.23)
Operating expense	(123.0)	(13.05)	(126.4)	(13.56)	(473.9)	(13.15)	(453.8)	(12.90)
Transportation and NGLs processing	(38.1)	(4.04)	(33.2)	(3.56)	(135.6)	(3.76)	(134.4)	(3.82)
Sales of commodities purchased ⁽⁶⁾	98.7	10.46	50.2	5.38	317.3	8.80	255.1	7.25
Commodities purchased ⁽⁶⁾	(97.7)	(10.36)	(47.4)	(5.08)	(312.0)	(8.65)	(250.2)	(7.11)
Netback	250.7	26.59	244.8	26.25	933.2	25.89	960.9	27.31
Risk management contract settlements	(1.5)	(0.16)	43.0	4.61	36.4	1.01	46.7	1.33
Netback including risk management contract settlements	249.2	26.43	287.8	30.86	969.6	26.90	1,007.6	28.64

Capital expenditures
Grande Prairie Region	71.3		75.8		431.0		380.3
Kaybob Region	18.8		64.5		172.6		190.4
Central Alberta and Other Region	79.5		61.7		238.1		120.0
Fox Drilling and Cavalier Energy	1.2		3.9		8.8		29.2
Corporate⁽⁷⁾	–		3.0		(8.3)		12.2
Total	170.8		208.9		842.2		732.1

Asset retirement obligations settled	11.9		12.8		38.1		54.6

(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: 2024: 0.4 million, 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 year ended December 31, 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 of amounts held in Corporate to and from 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.

	Annual
	Total		Grande Prairie Region		Kaybob Region		Central Alberta and Other Region
	2024	2023	2024	2023	2024	2023	2024	2023
Shale gas (MMcf/d)	257.5	265.2	201.4	209.3	33.5	28.2	22.6	27.7
Conventional natural gas (MMcf/d)	49.3	49.9	0.3	0.4	45.6	44.6	3.4	4.9
Natural gas (MMcf/d)	306.8	315.1	201.7	209.7	79.1	72.8	26.0	32.6
Condensate (Bbl/d)	38,311	35,148	29,317	31,433	6,348	2,655	2,646	1,060
Other NGLs (Bbl/d)	6,920	6,226	4,306	4,414	1,490	1,070	1,124	742
NGLs (Bbl/d)	45,231	41,374	33,623	35,847	7,838	3,725	3,770	1,802
Light and medium crude oil (Bbl/d)	1,296	1,469	–	–	1,277	1,440	19	29
Tight oil (Bbl/d)	454	616	131	152	109	158	214	306
Heavy crude oil (Bbl/d)	371	424	–	–	–	–	371	424
Crude oil (Bbl/d)	2,121	2,509	131	152	1,386	1,598	604	759
Total (Boe/d)	98,490	96,393	67,363	70,943	22,404	17,449	8,723	8,001

	Q4
	Total		Grande Prairie Region		Kaybob Region		Central Alberta and Other Region
	2024	2023	2024	2023	2024	2023	2024	2023
Shale gas (MMcf/d)	269.2	271.8	213.8	214.1	35.7	30.2	19.7	27.5
Conventional natural gas (MMcf/d)	48.1	54.4	0.4	0.3	44.3	49.6	3.4	4.5
Natural gas (MMcf/d)	317.3	326.2	214.2	214.4	80.0	79.8	23.1	32.0
Condensate (Bbl/d)	41,243	37,522	31,330	32,155	6,794	4,003	3,119	1,364
Other NGLs (Bbl/d)	6,753	6,698	3,988	4,742	1,480	1,209	1,285	747
NGLs (Bbl/d)	47,996	44,220	35,318	36,897	8,274	5,212	4,404	2,111
Light and medium crude oil (Bbl/d)	792	1,636	–	–	772	1,602	20	34
Tight oil (Bbl/d)	393	699	113	227	60	205	220	267
Heavy crude oil (Bbl/d)	407	433	–	–	–	–	407	433
Crude oil (Bbl/d)	1,592	2,768	113	227	832	1,807	647	734
Total (Boe/d)	102,477	101,348	71,130	72,860	22,441	20,324	8,906	8,164

Estimated January 2025 sales volumes were approximately 101,500 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).

2025 average sales volumes are expected to be between 37,500 Boe/d and 42,500 Boe/d (52% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 8% 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, 2024 and 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 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, 2024 and 2023 and (iii) a calculation of net (cash) debt as at December 31, 2024 and 2023.

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, 2024 and 2023:

Three months ended December 31 ($millions)	2024	2023
Cash from operating activities	187.7	287.0
Change in non-cash working capital	35.9	(18.4)
Geological and geophysical expense	2.3	2.7
Asset retirement obligations settled	11.9	12.8
Closure costs	–	–
Provisions	–	–
Settlements	–	–
Transaction and reorganization costs	–	–
Adjusted funds flow	237.8	284.1

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, 2024 and 2023:

Three months ended December 31 ($ millions)	2024	2023
Cash from operating activities	187.7	287.0
Change in non-cash working capital	35.9	(18.4)
Geological and geophysical expense	2.3	2.7
Asset retirement obligations settled	11.9	12.8
Closure costs	–	–
Provisions	–	–
Settlements	–	–
Transaction and reorganization costs	–	–
Adjusted funds flow	237.8	284.1
Capital expenditures	(170.8)	(208.9)
Geological and geophysical expense	(2.3)	(2.7)
Asset retirement obligation settled	(11.9)	(12.8)
Free cash flow	52.8	59.7

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:

planned capital expenditures in 2025 and the allocation thereof;
expected average sales volumes for 2025 and certain periods therein;
the expected 2025 exit rate of production; and
planned and potential exploration, development and production activities, including the expected timing of completion of phase one and phase two of the Alhambra Plant and the expected capacity thereof on completion.

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 potential scope and duration of tariffs, export taxes, export restrictions or other trade actions;
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, pipelines and other infrastructure, including the first and second phases of the Alhambra Plant, 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;
changes in political and economic conditions, including risks associated with tariffs, export taxes, export restrictions or other trade actions;
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, pipeline and other infrastructure, including third-party facilities and phase one and phase two of the Alhambra Plant;
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 phase one and phase two of the Alhambra Plant;
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, 2024, 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.

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 4, 2025 and effective December 31, 2024 (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 forecast prices and inflation rate assumptions published by Sproule Associates Ltd. as at December 31, 2024 and GLJ Ltd. and McDaniel as at January 1, 2025 (each of which is available on their respective websites at www.sproule.com, www.gljpc.com and www.mcdan.com). 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, 2024, 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, 2024, the value ratio between crude oil and natural gas was approximately 72:1. 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.

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, 2024 which is available on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com.

SOURCE Paramount Resources Ltd.

Average Price ⁽¹⁾

NYMEX WTI Swaps (Sale)

10,000 Bbl/d

C$105.00/Bbl

Natural gas

Citygate / Malin Basis Swap ⁽²⁾

10,000 MMBtu/d

Citygate less US$1.03/MMBtu (Sell)

Malin (Buy)