Paramount Resources Ltd. Announces First Quarter 2025 Results and Sinclair Update

May 13 2025 12:00 BST

CALGARY, AB , May 13, 2025 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its first quarter 2025 financial and operating results and provide an update respecting its Sinclair Montney property.

HIGHLIGHTS

First quarter sales volumes averaged 54,409 Boe/d (45% liquids). ⁽¹⁾
- Sales volumes from the Central Alberta Region, which includes Willesden Green, averaged 7,929 Boe/d (56% liquids).
- Kaybob Region sales volumes averaged 21,371 Boe/d (36% liquids).
- Sales volumes from the Karr and Wapiti properties that were sold in the quarter averaged 24,704 Boe/d (48% liquids). ⁽²⁾
Cash from operating activities was $150 million ($1.03 per basic share) in the first quarter. Adjusted funds flow was $149 million ($1.03 per basic share). Free cash flow was ($91) million (($0.63) per basic share). ⁽³⁾
First quarter capital expenditures totaled $216 million. Significant activities included:
- Willesden Green Duvernay – one (1.0 net) well drilled, three (3.0 net) wells completed and brought on production and the continuing construction of the Alhambra Plant;
- Kaybob North Duvernay – two (2.0 net) wells drilled and four (4.0 net) wells completed and brought on production; and
- Sinclair Montney – completion and flow testing of the Company's first two (2.0 net) appraisal wells.

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(1)	In this press release, "natural gas" refers to shale gas and conventional natural gas combined, "condensate and oil" refers to condensate, light and medium crude oil, tight oil and heavy crude oil combined, "Other NGLs" refers to ethane, propane and butane and "liquids" refers to condensate and oil and Other NGLs combined. See the "Product Type Information" section for a complete breakdown of sales volumes for applicable periods by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil, tight oil and heavy crude oil. See also "Oil and Gas Measures and Definitions" in the Advisories section.
(2)	Boe/d sales volumes for the Karr and Wapiti properties calculated by dividing aggregate sales volumes from January 1, 2025 to January 30, 2025 by 90 days.
(3)	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.

Paramount closed the sale of its Karr, Wapiti and Zama properties (the "Sold Assets") on January 31, 2025 for cash proceeds of approximately $3.3 billion, plus certain Horn River Basin properties of the acquiror (the "Grande Prairie Disposition"). Concurrently with closing, the Company entered into an amended $500 million four-year financial covenant-based revolving credit facility (the "Paramount Facility").
Following the Grande Prairie Disposition and the assignment of transportation capacity for the Sold Assets to the acquiror, approximately 70 percent of Paramount's expected natural gas sales volumes for the remainder of 2025 are priced at diversified markets outside of AECO.
The Company paid a special cash distribution of $15.00 per class A common share ("Common Share") to shareholders in February 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 4.9 million Common Shares in the first quarter under its normal course issuer bid.
The Company received a second interim payment of $11 million from insurers related to 2023 Alberta wildfire losses. Paramount has received an aggregate of $21 million in interim payments to date and continues to advance its claims process.
Paramount continues to have 10,000 Bbl/d of liquids hedged at a WTI price of C$105.00/Bbl for the remainder of 2025.
The Company realized $7 million on the assignment of a portion of its first quarter 2025 ex-Alberta natural gas transportation capacity.
Asset retirement obligations settled in the first quarter totaled $22 million.
The carrying value of the Company's investments in securities at March 31, 2025 was $523 million.
At March 31, 2025, Paramount had net cash of $638 million and the $500 million Paramount Facility remained undrawn. ⁽¹⁾

SINCLAIR UPDATE

Activities at Sinclair in the first quarter included the completion and flow testing of the Company's first two appraisal wells, testing two distinct benches within the Montney formation. The wells achieved average raw production rates of 24 MMcf/d and 16 MMcf/d of dry gas, respectively, over the final three days of testing. Gas composition monitoring demonstrated lower than expected H₂S content.^⁽²⁾

With these results in hand, Paramount has initiated work for a potential new dry gas processing facility at Sinclair capable of handling up to 400 MMcf/d of raw gas production, including detailed engineering and design, regulatory and other activities. This work is expected to be completed in 2025 at a cost of between $20 million and $50 million and will preserve optionality for the Company to sanction the development of Sinclair in the coming quarters and allow for the possibility of ordering long-lead equipment before year

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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 cash in this instance for simplicity. Refer to the "Specified Financial Measures" section for more information on this measure.
(2)	The well tests were conducted by production testing over periods of approximately 15 days and 9 days, respectively. Stated production rates were measured at the wellhead for a period of three days once the wells were considered stabilized after the flow-back of completion fluids. To date, no pressure transient or well-test interpretation has been finalized on the wells and, as such, the data should be considered preliminary. The production rates stated: (i) are test rates only over a short period of time and are not necessarily indicative of long-term performance or of ultimate recovery from the wells tested or from any other future wells that may be drilled by the Company at Sinclair and (ii) are raw gas volumes and do not represent potential sales volumes after processing and related shrinkage.

end. As previously disclosed, Paramount has secured downstream transportation capacity that would enable the first phase of Sinclair production to commence as early as the fourth quarter of 2027.

Over the remaining three quarters of 2025, the Company plans to drill an additional two Montney appraisal wells. These wells are planned to be completed and flow tested in 2026.

GUIDANCE

Paramount is now expecting 2025 capital expenditures of between $780 million and $840 million (previously $760 million and $790 million), reflecting the additional expenditures associated with the detailed engineering and design, regulatory and other activities related to the potential new dry gas processing facility at Sinclair.

The Company continues to expect annual sales volumes of between 37,500 Boe/d and 42,500 Boe/d (48% liquids). Paramount anticipates: (i) sales volumes of between 28,000 Boe/d and 32,000 Boe/d (46% liquids) until the start-up of the Alhambra Plant at Willesden Green, (ii) fourth quarter 2025 sales volumes of between 40,000 Boe/d and 45,000 Boe/d (52% liquids) and (iii) a 2025 year-end exit rate in excess of 45,000 Boe/d (52% liquids).

Paramount expects to incur abandonment and reclamation expenditures of approximately $20 million over the final three quarters of 2025.

REVIEW OF OPERATIONS

CENTRAL ALBERTA REGION

Central Alberta Region sales volumes averaged 7,929 Boe/d (56% liquids) in the first quarter of 2025 compared to 8,488 Boe/d (55% liquids) in the fourth quarter of 2024.

First quarter development activities were focused on Willesden Green, where the Company brought onstream three (3.0 net) new Duvernay wells halfway through the quarter. Initial production from these wells is in line with expectations, averaging gross 30-day peak production per well of 1,073 Boe/d (1.9 MMcf/d of shale gas and 753 Bbl/d of NGLs) with an average CGR of 393 Bbl/MMcf. ⁽¹⁾ The wells are being produced at restricted rates to optimize both condensate recovery and facility capacity.

Construction of the first phase of Paramount's wholly-owned and operated Alhambra Plant at Willesden Green is progressing as planned and on budget, with start-up expected by the fourth quarter of 2025. This first phase will provide estimated raw handling capacity of 10,000 Bbl/d of liquids and 50 MMcf/d of natural gas. Significant milestones achieved in the first quarter include the delivery of final equipment packages and the construction of gathering pipelines and egress infrastructure. Paramount has commenced operational readiness activities for the new plant, including the hiring and training of personnel to support testing and commissioning activities.

The Company continues to advance the second phase of the Alhambra Plant, which will double raw handling capacity to 20,000 Bbl/d of liquids and 100 MMcf/d of natural gas. All major equipment for the

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(1)

30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See "Oil and Gas Measures and Definitions" in the Advisories section. Natural gas sales volumes were lower by approximately 13% and liquids sales volumes were lower by approximately 12% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone.

second phase has now been ordered and the Company has commenced the construction of additional tankage that will support future phases. Start-up of the second phase of the Alhambra Plant continues to be expected in the fourth quarter of 2026.

Paramount anticipates drilling a total of 25 (25.0 net) wells and bringing onstream a total of 22 (22.0 net) wells at Willesden Green in 2025. Six of these wells will flow to the Leafland Plant and 16 of the wells will flow to the new Alhambra Plant upon start-up.

KAYBOB REGION

Kaybob Region sales volumes averaged 21,371 Boe/d (36% liquids) in the first quarter of 2025 compared to 22,441 Boe/d (41% liquids) in the fourth quarter of 2024. Sales volumes were lower in the first quarter primarily due to natural declines.

Development activities in the first quarter included the drilling of two (2.0 net) Duvernay wells at Kaybob North as well as the completion and tie-in of four (4.0 net) Duvernay wells at Kaybob North that were brought onstream at the end of the quarter. Initial production from these four new wells, which have been significantly choked due to facility gas constraints, averaged gross 30-day peak production per well of 861 Boe/d (0.5 MMcf/d of shale gas and 772 Bbl/d of NGLs) with an average CGR of 1,446 Bbl/MMcf. ⁽¹⁾Initial condensate production is in line with expectations given the restricted rates. Gas production is anticipated to reach peak rates after approximately 90 producing days.

Over the remainder of 2025, Paramount plans to drill and bring onstream five (5.0 net) Duvernay wells at Kaybob North.

HEDGING

The Company's current commodity contracts are summarized below:

	Q2 2025	Q3 2025	Q4 2025	Average Price ⁽¹⁾
Oil
NYMEX WTI Swaps (Sale) (Bbl/d)	10,000	10,000	10,000	C$105.00/Bbl

Natural gas
Citygate / Malin Basis Swap (MMBtu/d)⁽²⁾	10,000	10,000	10,000	Citygate less US$1.03/MMBtu (Sell) Malin (Buy)

(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 April 2025 to October 2027.

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(1)

30-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 30-day period, excluding days when the well did not produce. The production rates and volumes stated are over a short period of time and, therefore, are not necessarily indicative of average daily production, long-term performance or of ultimate recovery from the wells. CGR means condensate to gas ratio and is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. See "Oil and Gas Measures and Definitions" in the Advisories section. Natural gas sales volumes were lower by approximately 14% and liquids sales volumes were lower by approximately 6% due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone.

ANNUAL GENERAL MEETING

Paramount will hold its annual general meeting of shareholders on Tuesday May 13, 2025 at 10:00 am (Mountain time) in the Doulton Room at Bankers Hall Conference Centre, 400, 315 – 8^th Avenue S.W., Calgary Alberta. A webcast will be available at www.paramountres.com/investors/presentations.

ABOUT PARAMOUNT

Paramount is an independent, publicly traded, liquids-rich natural gas focused Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas, including longer-term strategic exploration and pre-development plays, and holds a portfolio of investments in other entities. The Company's principal properties are located in Alberta and British Columbia. Paramount's Common Shares are listed on the Toronto Stock Exchange under the symbol "POU".

Paramount's first quarter 2025 results, including Management's Discussion and Analysis and the Company's Interim Consolidated Financial Statements, can be obtained on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.

A summary of historical financial and operating results is also available on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.

FINANCIAL AND OPERATING RESULTS ⁽¹⁾

($ millions, except as noted)	Q1 2025		Q4 2024		Q1 2024
Net income	1,288.8		87.4		68.1
per share – basic ($/share)	8.90		0.60		0.47
per share – diluted ($/share)	8.74		0.59		0.46
Cash from operating activities	149.9		187.7		201.3
per share – basic ($/share)	1.03		1.28		1.39
per share – diluted ($/share)	1.02		1.26		1.35
Adjusted funds flow	149.1		237.8		225.6
per share – basic ($/share)	1.03		1.62		1.56
per share – diluted ($/share)	1.01		1.59		1.52
Free cash flow	(90.6)		52.8		(9.5)
per share – basic ($/share)	(0.63)		0.36		(0.07)
per share – diluted ($/share)	(0.63)		0.35		(0.07)
Total assets	3,616.4		4,757.5		4,458.9
Investments in securities	522.8		563.9		568.6
Long-term debt	–		173.0		–
Net (cash) debt	(637.9)		188.4		68.4
Common shares outstanding (millions) ⁽²⁾	143.2		146.9		145.2
Sales volumes ⁽³⁾
Natural gas (MMcf/d)	179.6		317.3		318.7
Condensate and oil (Bbl/d)	20,542		42,835		40,908
Other NGLs (Bbl/d)	3,934		6,753		6,954
Total (Boe/d)	54,409		102,477		100,977
% liquids	45 %		48 %		47 %
Central Alberta Region and Other (Boe/d)	8,334		8,972		11,485
Kaybob Region (Boe/d)	21,371		22,441		22,353
Sold Assets (Boe/d)	24,704		71,064		67,139
Total (Boe/d)	54,409		102,477		100,977
Netback		($/Boe) ⁽⁴⁾		($/Boe) ⁽⁴⁾		($/Boe) ⁽⁴⁾
Natural gas revenue	52.6	3.25	58.0	1.99	82.4	2.84
Condensate and oil revenue	180.6	97.70	379.4	96.26	344.8	92.64
Other NGLs revenue	14.3	40.47	21.3	34.32	23.9	37.81
Natural gas transportation assignment income ⁽⁵⁾	7.4	0.46	0.9	0.03	–	–
Royalty income and other revenue ⁽⁵⁾	11.7	–	(0.3)	–	1.2	–
Petroleum and natural gas sales	266.6	54.43	459.3	48.72	452.3	49.24
Royalties	(26.7)	(5.44)	(48.5)	(5.14)	(61.8)	(6.73)
Operating expense	(67.8)	(13.85)	(123.0)	(13.05)	(118.9)	(12.94)
Transportation and NGLs processing	(20.4)	(4.17)	(38.1)	(4.04)	(31.9)	(3.47)
Sales of commodities purchased ⁽⁶⁾	109.7	22.40	98.7	10.46	54.7	5.95
Commodities purchased ⁽⁶⁾	(107.2)	(21.88)	(97.7)	(10.36)	(53.4)	(5.81)
Netback	154.2	31.49	250.7	26.59	241.0	26.24
Risk management contract settlements	1.6	0.32	(1.5)	(0.16)	(0.5)	(0.05)
Netback including risk management contract settlements	155.8	31.81	249.2	26.43	240.5	26.19
Capital expenditures
Central Alberta Region and Other	138.3		95.3		39.9
Kaybob Region	51.0		18.8		56.3
Fox Drilling	3.1		0.9		4.0
Corporate ⁽⁷⁾	2.9		–		(6.5)
Sold Assets	20.4		55.8		120.2
Total	215.7		170.8		213.9
Asset retirement obligations settled	22.2		11.9		16.5

(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 (millions): Q1 2025: 0.3, Q4 2024: 0.4, Q1 2024: 0.4.
(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 and natural gas transportation assignment income presented as $/Mcf.
(5)	Natural gas transportation assignment income for the three months ended March 31, 2025 relates to proceeds realized by the Company on the assignment of a portion of its first quarter 2025 ex-Alberta natural gas transportation capacity to third parties. Royalty income and other revenue for the three months ended March 31, 2025 includes $11.1 million related to a second interim payment from insurers for 2023 Alberta wildfire losses. The Company has realized $21.1 million in aggregate interim payments in respect of its 2023 Alberta wildfire losses to date and continues to advance its insurance claims process. These amounts were not allocated to individual regions or properties.
(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.

Total Company by Product
Type

Central Alberta
Region and Other

Kaybob Region

Q1 2025

Q4 2024

Q1 2024

Q1 2025

Q4 2024

Q1 2024

Q1 2025

Q4 2024

Q1 2024

Shale gas (MMcf/d)

134.2

269.2

268.5

17.6

19.7

36.4

39.7

35.7

30.6

Conventional natural gas (MMcf/d)

45.4

48.1

50.2

3.6

3.7

2.4

41.8

44.3

47.7

Natural gas (MMcf/d)

179.6

317.3

318.7

21.2

23.4

38.8

81.5

80.0

78.3

Condensate (Bbl/d)

18,817

41,243

38,332

2,992

3,120

3,233

5,500

6,794

6,038

Other NGLs (Bbl/d)

3,934

6,753

6,954

1,186

1,296

1,144

1,292

1,480

1,480

NGLs (Bbl/d)

22,751

47,996

45,286

4,178

4,416

4,377

6,792

8,274

7,518

Light and medium crude oil (Bbl/d)

971

792

1,595

943

772

1,573

Tight oil (Bbl/d)

396

393

592

234

220

239

212

Heavy crude oil (Bbl/d)

358

407

389

358

407

389

–

Crude oil (Bbl/d)

1,725

1,592

2,576

620

647

650

1,000

832

1,785

Total (Boe/d)

54,409

102,477

100,977

8,334

8,972

11,485

21,371

22,441

22,353

	Sold Assets
	Q1 2025	Q4 2024	Q1 2024
Shale gas (MMcf/d)	76.9	213.8	201.5
Conventional natural gas (MMcf/d)	–	0.1	0.1
Natural gas (MMcf/d)	76.9	213.9	201.6
Condensate (Bbl/d)	10,325	31,329	29,061
Other NGLs (Bbl/d)	1,456	3,977	4,330
NGLs (Bbl/d)	11,781	35,306	33,391
Tight oil (Bbl/d)	105	113	141
Crude oil (Bbl/d)	105	113	141
Total (Boe/d)	24,704	71,064	67,139

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).

Prior to the start-up of the Alhambra Plant at Willesden Green, sales volumes are expected to average between 28,000 Boe/d and 32,000 Boe/d (54% shale gas and conventional natural gas combined, 37% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 9% Other NGLs).

Fourth quarter 2025 average sales volumes are expected to be between 40,000 Boe/d and 45,000 Boe/d (48% shale gas and conventional natural gas combined, 43% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 9% Other NGLs).

2025 year-end sales volumes exit rate is expected to be in excess of 45,000 Boe/d (48% shale gas and conventional natural gas combined, 43% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 9% Other NGLs).

SPECIFIED FINANCIAL MEASURES

Non-GAAP Financial Measures

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

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

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

Refer to the table under the heading "Financial and Operating Results" in this press release for the calculation of netback and netback including risk management contract settlements for the three months ended March 31, 2025, December 31, 2024 and March 31, 2024.

Non-GAAP Ratios

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

Netback on a $/Boe basis is calculated by dividing netback (a non-GAAP financial measure) for the applicable period by the total sales volumes during the period in Boe. Netback including risk management contract settlements on a $/Boe basis is calculated by dividing netback including risk management contract settlements (a non-GAAP financial measure) for the applicable period by the total sales volumes during the period in Boe. These measures are used by investors and management to assess netback and netback including risk management contract settlements on a unit of sales volumes basis.

Capital Management Measures

Adjusted funds flow, free cash flow and net (cash) debt are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 15 in the Interim Consolidated Financial Statements of Paramount as at and for the three months ended March 31, 2025 for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three months ended March 31, 2025 and 2024 and (iii) a calculation of net (cash) debt as at March 31, 2025 and December 31, 2024.

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;
planned abandonment and reclamation expenditures in 2025;
planned and potential exploration, development and production activities, including: (i) the expected timing of completion of the detailed engineering and design, regulatory and other activities related to the potential new dry gas processing facility at Sinclair and the expected cost thereof and (ii) the expected timing of completion of phase one and phase two of the Alhambra Plant and the expected capacity thereof on completion; and
the expected timing of the four Kaybob North Duvernay wells brought on at the end of the first quarter reaching peak rates of gas production.

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

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.

Oil and Gas Measures and Definitions

Liquids				Natural Gas
Bbl			Barrels	GJ	Gigajoules
Bbl/d			Barrels per day	GJ/d	Gigajoules per day
MBbl			Thousands of barrels	MMBtu	Millions of British Thermal Units
NGLs			Natural gas liquids	MMBtu/d	Millions of British Thermal Units per day
Condensate			Pentane and heavier hydrocarbons	Mcf	Thousands of cubic feet
WTI			West Texas Intermediate	MMcf	Millions of cubic feet
				MMcf/d	Millions of cubic feet per day
Oil Equivalent				NYMEX	New York Mercantile Exchange
Boe		Barrels of oil equivalent		AECO	AECO-C reference price
MBoe		Thousands of barrels of oil equivalent
MMBoe	Millions of barrels of oil equivalent
Boe/d	Barrels of oil equivalent per day

This press release contains disclosures expressed as "Boe", "$/Boe" and "Boe/d". Natural gas equivalency volumes have been derived using the ratio of six thousand cubic feet of natural gas to one barrel of oil when converting natural gas to Boe. Equivalency measures may be misleading, particularly if used in isolation. A conversion ratio of six thousand cubic feet of natural gas to one barrel of oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. For the three months ended March 31, 2025, the value ratio between crude oil and natural gas was approximately 49:1. This value ratio is significantly different from the energy equivalency ratio of 6:1. Using a 6:1 ratio would be misleading as an indication of value.

This press release refers to "CGR", a metric commonly used in the oil and natural gas industry. "CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes. This metric does not have a standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon.

Additional information respecting the Company's oil and gas properties and operations is provided in the Company's annual information form for the year ended December 31, 2024 which is available on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com.

SOURCE Paramount Resources Ltd.