Slides
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May 2025 Corporate Presentation
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Advisories • In the interest of providing information regarding Paramount Resources Ltd. ("Paramount", "PRL" or the "Company") and its future plans and operations, this presentation contains certain forward-looking information and statements. The projections, estimates and forecasts contained in such forward-looking information and statements necessarily involve a number of assumptions and are subject to both known and unknown risks and uncertainties that may cause the Company's actual performance and financial results in future periods to differ materially from these projections, estimates and forecasts. The Advisories Appendix attached hereto lists some of the material assumptions, risks and uncertainties that these projections, estimates and forecasts are based on and are subject to. Readers are encouraged to carefully review the Advisories Appendix. • All dollar amounts in this presentation are expressed in Canadian dollars unless otherwise noted. • Production information is presented in accordance with Canadian standards. • The Advisories Appendix attached hereto contains additional information concerning the oil and gas measures and terms and specified financial measures contained in this presentation. • The forward-looking information and statements contained in this presentation are made effective as of May 12, 2025. Certain internally estimated play data contained in this presentation was prepared effective December 31, 2024. In each case, events or information subsequent to the applicable effective dates have not been incorporated. • This presentation 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 combined. "Liquids" refers to condensate and oil and other NGLs combined. Readers are referred to the Product Type Information section of the Advisories Appendix for more information about sales volumes by the specific product types of shale gas, conventional natural gas, NGLs, light and medium crude oil, tight oil and heavy crude oil. 2
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28,000 40,000 32,000 45,000 - 10,000 20,000 30,000 40,000 50,000 60,000 70,000 Until Alhambra Start-up 4Q25F 2025F Exit 2026F Exit 2025 Guidance Summary (4) Shares Outstanding (MM) 143.5 Market Capitalization ($MM) (2) ~$2,500 Investments in Securities at Mar 31, 2025 ($MM) ~$520 Net Cash at Mar 31, 2025 ($MM) (3) ~$640 Current Monthly Dividend $0.05/sh. 3 Corporate Overview • Founded in 1976 (IPO’d in 1978) • Significant insider ownership (~48%) (1) • Closed ~$3.3 billion asset sale on Jan 31, 2025 • $15.00/share Special Distribution paid in Feb 2025 (~$2.1 bn) • Repurchased 5.7 million Common Shares under NCIB between late-Nov 2024 and early-Feb 2025 Market Snapshot (TSX-POU) (1) Consists of class A common shares ("Common Shares") held by directors, officers and other insiders. (2) 143.5MM Common Shares at $17.11/share. (3) 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 . (4) See Advisories Appendix – Forward Looking Information. (5) Based on regular monthly dividends paid to April 2025 plus a monthly dividend of $0.05 per share for the remaining eight mont hs of 2025 and current shares outstanding. (6) The Company expects that similar levels of capital expenditures in 2026 to those in 2025 would enable it to exit 2026 with pr oduction in excess of 60,000 Boe/d (50% liquids). Paramount has significant land positions in several prolific unconventional resource plays in Canada ~50% Liquids ~52% Liquids 52% Liquids 46%Liquids Willesden Green Duvernay Kaybob North Duvernay Sinclair and Other Region Drilling, Completions, Equip and Tie -ins Category Capital Expenditure Outlook ($MM) Facilities and Other Asset Areas Production Outlook Range (Boe/d) Kaybob Duvernay/Montney Willesden Green Duvernay 2025F (Midpoint) 2025F (Midpoint) Sinclair Montney NE British Columbia Liard/Horn River Basin Shale Gas Central Alberta Clearwater/Bluesky & Thermal Heavy Oil Producing Areas Emerging Areas (6) Sales Volumes (Boe/d) (% Liquids) 37,500 – 42,500 (48%) CapEx ($MM) $780–$840 ARO ($MM) ~$40 Base Dividend ($MM) (5) ~$100
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4 Shareholder Returns Paramount has returned $20.83/share (~$3 billion) to shareholders since the start of 2021 Cumulative Dividends and Special Distributions ($MM) • Paramount’s priorities continue to be the maintenance of a strong balance sheet and the delivery of attractive shareholder returns through a combination of: • Dividends, including the flexibility for incremental returns through further special dividends • Investments in growth opportunities • Opportunistic share buybacks • Since the start of 2021, Paramount has: • paid a total of $20.83 per Common Share (~$3 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 ~$3 Billion ($20.83/sh.)
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- 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 - 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Inventory-Rich Opportunity Set 5 Paramount is allocating capital to its highest risk-adjusted rate of return opportunities while maintaining a strong balance sheet Early Appraisal Develop Harvest Stage KaybobNorth WillesdenGreen Clearwater / Bluesky Exploration team continues toactively identify early-stage assets for potential low-cost capture Sinclair Horn River Liard Stage of Development• Core strategy: • Early identification and low-cost resource capture • Appraise and high-grade top tier economic returns • Develop, refine, optimize • Harvest, monetize • Significant inventory of opportunities across Paramount’s land base at various stages in the development lifecycle • Track record of opportunistic property dispositions with a focus on maximizing value • Measured and focused approach to development • Targeting asset-level plateau production that can be sustained for 20+ years for new plays based on management estimates of recoverable resource • Current capital is weighted towards Duvernay assets at Willesden Green and Kaybob North which have significant growth potential and production that all flows through Company owned and operated infrastructure • The Company is also advancing appraisal of its Sinclair Montney property Potential Plateau Production (Boe/d) Kaybob legacy conventional production Kaybob North Duvernay ~16MBoe/d for 12+ years Willesden Green Duvernay ~50MBoe/d for 20+ yearsAlhambra Phase 1 Alhambra Phase 2 Alhambra Phase 3 Illustrative Potential Sinclair Development ~50+MBoe/d for 20+ years Potential Additional Production from: • Central Alberta – Heavy Oil: • Clearwater/Bluesky, Thermal projects • Liard Basin and Horn River – Shale Gas • Including 40 MMcf/d currently shut-in Thermal Oil (Hoole)
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6 Willesden Green Duvernay Overview Development activities in Paramount's core Duvernay area are progressing with new Alhambra plant onstream by Q4/25 (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 13 percent and liquids sales volumes were lower by approximately 12 percent 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. 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 the condensate to gas ratio calculated by dividing wellhead NGLs volumes by wellhead natural gas volumes. See Advisories Appendix - Oil and Gas Measures and Definitions. • 263,000 net acres of contiguous Duvernay rights • Targeting to grow production from ~7,900 Boe/d (Q1 2025) to a plateau production level of >50,000 Boe/d that can be sustained for 20+ years • Two owned and operated major natural gas processing plants will support the development: • Majority-owned Leafland Plant which is capable of handling ~6,000 Bbl/d of raw liquids and 22 MMcf/d of raw natural gas • Wholly-owned Alhambra Plant currently under construction (see page 8) • First phase expected to start-up by the fourth quarter of 2025 • Will be pipeline connected to the Leafland Plant to enhance operational synergies • The three wells that were brought onstream in the first quarter of 2025 averaged 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) • These wells are being produced at restricted rates to optimize both condensate recovery and facility capacity LEAFLAND PLANT ALHAMBRA PLANT Duvernay Lands Duvernay Hz Well 2024 Duvernay Activity 2025 Duvernay Activity Industry Duvernay Hz Well Leduc Formation
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0 100 200 300 400 0 500 1,000 1,500 2,000 MBbl Producing Days 0 200 400 600 800 0 500 1,000 1,500 2,000 MBoe Producing Days 7 Willesden Green Duvernay Overview Attractive half-cycle economics driven by significant condensate contribution IP 365 (Boe/d) 843 IP 365 CGR (Bbl/MMcf) 237 Sales Volume (MBoe) 1,306 Average CGR (Bbl/MMcf) 178 Sales Gas (Bcf) 3.3 Sales Condensate (MBbl) 554 DCET ($MM) $13.6 Play Data - 4,000m Avg. Lateral Length, 1.7t/m Frac Intensity, 320m Well Spacing (2) • Planned activities in 2025 include: • The drilling of 25 (25.0 net) and bringing onstream of 22 (22.0 net) Duvernay wells • 6 wells are expected to feed the existing Leafland Plant • 16 wells are expected to be brought onstream through the Alhambra Plant upon start-up of the first phase • Completion of the first phase of the Alhambra Plant by the fourth quarter of 2025 • The Company continues its work to optimize well design, including through adjusting frac intensity and well spacing Cumulative Boe (1) Cumulative NGLs (1) Type Curve (2) Type Curve (2) (1) Includes only wells with modern completion techniques since 2021. Production measured at the wellhead. Measured production volumes have been normalized to the lateral length of the wellbore on a 1:1 basis. This approach ensures a consistent framework for evaluating well performance and allows for comparability across wells with varying lateral lengths. Natural gas sales volumes were lower by approximately 13 percent and liquids sales volumes were lower by approximately 12 percent due to shrinkage. In addition, certain liquids entrained in the natural gas stream are only recovered once processed and therefore final sales volumes cannot be imputed from wellhead volumes and shrinkage estimates alone. (2) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data.
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8 Willesden Green Duvernay Overview The next phase of development at Paramount's liquids-rich Willesden Green Duvernay play is progressing well • Construction of the Company's Alhambra Plant in Willesden Green is progressing as planned and on budget • Planned capacity of 150 MMcf/d of raw gas and 30,000 Bbl/d of raw liquids handling being built in three equal phases • First 50 MMcf/d / 10,000 Bbl/d phase expected to start-up by the fourth quarter of 2025 • The second phase is expected to start-up in the fourth quarter of 2026 • Egress secured for all three phases of Duvernay production growth Alhambra Plant Raw Processing Capacity Buildout Phase 1 Phase 2 Phase 3 Alhambra Plant – Phase 1 Under Construction Raw Inlet Gas (Boe/d) (1) Raw Inlet Liquids (Boe/d) Potential to accelerate Phase 3 (1) 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. 50 MMcf/d 100 MMcf/d 150 MMcf/d 10,000 Bbl/d 20,000 Bbl/d 30,000 Bbl/d
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9 Kaybob North Duvernay Overview Production growth is expected to offset natural declines from legacy conventional production in the Kaybob Region • 109,000 net acres of Duvernay rights and 179,000 net acres of Montney rights • Paramount has brought onstream a total of 27 (27.0 net) Duvernay wells in Kaybob North Duvernay to March 31, 2025 • Over the next 5+ years the Company plans to grow Duvernay sales volumes from ~8,500 Boe/d (Q1 2025) to targeted plateau production level of 16,000 Boe/d that can be sustained for 12+ years • Over the remainder of 2025, Paramount plans to drill and bring onstream 5 (5.0 net) Duvernay wells • The Company continues its work to optimize well design, including through adjusting frac intensity and well spacing • Paramount has ownership in strategic facilities and infrastructure including the 8-9 Gas Plant and 12-10 Oil Battery • The Company owns and operates a crude oil terminal capable of capturing incremental value in price differentials with capacity to handle future growth IP 365 (Boe/d) 566 IP 365 CGR (Bbl/MMcf) 477 Sales Volume (MBoe) 788 Average CGR (Bbl/MMcf) 349 Sales Gas (Bcf) 1.5 Sales Condensate (MBbl) 489 DCET ($MM) $12.0 Play Data – 4,200m Avg. Lateral Length, 1.7t/m Frac Intensity, 320m Well Spacing (1) (1) Per well data based on management estimates and price deck. See Advisories Appendix – Play Data. KAYBOB 8-9 GAS PLANT KAYBOB 12-10 OIL BATTERY Duvernay Lands Duvernay Hz Well 2024 Duvernay Activity 2025 Duvernay Activity Industry Duvernay Hz Well
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10 Sinclair Montney Lands Paramount has assembled a large block of wholly-owned Montney rights in Northwest Alberta • Paramount holds approximately 107,000 acres of wholly-owned Montney rights in the Sinclair area of Alberta, prospective for high-rate gas production • In the first quarter of 2025, the Company completed and flow tested its first two Montney appraisal wells, testing two distinct Montney benches (1) • 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 • The Company plans to drill two additional horizontal Montney appraisal wells in 2025 which will be completed and flow tested in 2026 • Paramount has initiated work for a potential new dry gas processing facility, including detailed engineering, design, regulatory and other activities • Up to 400 MMcf/d raw gas handling capacity • Expect work to be completed in 2025, preserving optionality to sanction the development of Sinclair in the coming quarters • Downstream transportation capacity has been secured that would enable the first phase of Sinclair production to commence as early the fourth quarter of 2027 2025 Montney Activity Montney Vertical Penetration Montney Lands Montney Horizontal Well SINCLAIR Achieved average raw production rates of 24 MMcf/d and 16 MMcf/d, respectively, over the final three days of testing (1) 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. Two additional Montney appraisal wells to be drilled in 2025
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11 Central Alberta Heavy Oil Asset Overview Paramount controls significant lands prospective for cold flow heavy oil and in-situ thermal recovery Central Alberta - Clearwater / Bluesky & Thermal Heavy Oil • 1.31 million net acres of lands prospective for cold flow heavy oil and in-situ thermal recovery • 297,000 net acres of Clearwater and Bluesky rights • Opportunity to deploy advancements in multi-lateral drilling techniques • Hoole asset directly offsets CNRL's active Pelican Lake polymer flood development • Also proximal to IPC's Blackrod thermal development that has been sanctioned • Paramount has identified 5 significant thermal oil development opportunities: • Hoole (100% WI) • Dunkirk (100% WI) • Muskwa (100% WI) • Cadotte (100% WI) • Selina (50% WI, operated) Marten Hills NipisiGiftPeavine Seal Godin/McMullen Cadotte CNRL Pelican Lake Wells Clearwater/Bluesky POU thermal opportunities Suncor Greenfire MEG Paramount CNRL Spur IPC RubelliteBaytex Tamarack Valley Cenovus Obsidian Conoco Sunshine Headwater Imperial IPC Blackrod Dunkirk Muskwa Hoole Cadotte Other
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12 Northeast British Columbia Asset Overview Liard and Horn River basins are prolific natural gas development opportunities – prospective feedstock for west coast LNG Liard: • 50% operated interest (Woodside partner) • 179,000 net acres of Besa River rights • Three re-activation well opportunities (capable of ~30 MMcf/d gross sales) • Three DUCs Horn River: • 113,000 net acres of Muskwa rights • 40 MMcf/d net was shut-in in March 2024 • 14 DUCs Significant infrastructure in the area including: • Material processing capacity • Existing trunklines • Market egress Northeast BC – Liard and Horn River Basins Fort St. John Ksi Lisims LNG LNG Canada Woodfibre LNG Cedar LNG LIARD HORN RIVER Liard & Horn River Lands Paramount Hz Well Industry Hz Well Industry Pipelines Paramount Pipelines Fort Nelson South Plant 1 Bcf/d Capacity Fort Nelson North Plant 250 MMcf/d Capacity Cabin Plant 800 MMcf/d Capacity T North NGTL System to Alberta
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Strategic / Long-Term Investments and Risk Management Paramount holds significant positions in a number of public and private entities 13 Summary of Investments & Other Assets Investments in Public Companies (1) ~$430 million Investments in Private Companies (2) ~$90 million Drilling Rigs – Book Value (2) ~$80 million Undeveloped Land Not quantified Total >$600 million (1) Market value of public companies as at March 31, 2025 (includes ~31.3 million shares of NuVista Energy Ltd. @ $13.60/share). (2) Carrying value as at March 31, 2025. Investments in Private Companies include Sultran Ltd. and minor interests in other companies. (3) "Citygate" refers to Pacific Gas & Electric Citygate and "Malin" refers to Pacific Gas & Electric Malin. The transaction is financially settled with no physical delivery. The remaining term of this contract is May 2025 to October 2027. Long-term Unconventional Natural Gas: Mackenzie Delta and Central Mackenzie • ~170,000 net acres Sultran Paramount holds a ~16% ownership • Supply chain and logistics solutions for bulk commodities • Wholly-owned BC terminal facilities (Pacific Coast Terminals Co. Ltd.) Fox Drilling Wholly owned by Paramount • Five triple-sized walking rigs • One conventional triple-sized rig • Bi-fuel capable, reducing costs and emissions compared to diesel 2025 Financial Hedges • 10,000 Bbl/d of liquids hedged at a WTI price of C$105.00/Bbl • 10,000 MMBtu/d Citygate / Malin natural gas basis swap (sell at Citygate price less US$1.03/MMBtu, buy Malin) (3) • 360 MWh/d of electricity hedged at a price of $67.01/MWh 2025 Physical Gas Diversification With the natural gas market diversification contracts currently in place, approximately 70% of the Company’s expected natural gas sales volumes for the remainder of 2025 will benefit from exposure to markets outside of AECO, including at Dawn and Malin Risk Management Canadian Premium Sand Inc. Paramount holds a ~19% ownership • Planning to build an ultra high- clarity patterned solar glass manufacturing facility in North America
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0.00 0.01 0.02 0.03 - 250,000 500,000 750,000 2019 2020 2021 2022 2023 tCO2e/ BoetCO2e Scope 1 Scope 2 Intensity Environmental, Social and Governance ("ESG") 14 Paramount takes pride in responsibly delivering value to all stakeholders • The use of bi-fuel drilling rigs and completions equipment reduce diesel consumption • Equipping new pads with instrument air where possible to minimize methane emissions • Replaced 181 pneumatic chemical pumps with solar in 2024 • Proactively managing decommissioning and reclamation obligations; over 800 wells decommissioned and ~1,600 hectares reclaimed since 2017 • Fosters a safety conscious culture with written policies and procedures to protect the health and safety of those involved with and affected by our operations • Supports a wide range of community and charitable organizations both financially and through volunteer hours • Committed to creating and maintaining an environment that respects diverse traditions, heritages and experiences • 67% independent board members; independent Lead Director • All board committees fully independent • Environmental, Health and Safety Committee of the Board of Directors and senior management provide oversight of ESG related matters • 3 of 9 (33%) board members are women Environmental Social • Minimum shareholding requirements for directors • Officers and directors prohibited from hedging Paramount securities • Loans to officers and directors prohibited • Code of Ethics and Code of Business Conduct Policy • Anonymous Whistleblower Policy and portal Governance 37% Scope 1 + 2 emissions intensity 26% Scope 1 + 2 absolute emissions
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Paramount Investment Attributes • 45+ year history of responsible energy development and environmental stewardship • Extensive portfolio of liquids-rich resource plays in the Duvernay and shale gas plays in the Montney, Horn River and Liard basins • Proven track record of building large, contiguous land positions and developing them into material and sustainable free cash flow engines • Risk adjusted returns-focused capital allocation strategy supported by rigorous full-cycle analysis • Strong liquidity position at March 31, 2025 with (i) ~$640 million of net cash; (ii) investments in securities valued at ~$520 million; and (iii) an undrawn $500 million 4-year financial covenant-based credit facility (1) • Stakeholder-aligned management and board with significant insider ownership • $20.83 per Common Share in regular monthly dividends and special distributions since the start of 2021 • Repurchased 5.7 million Common Shares to March 31, 2025 under current normal course issuer bid • Current monthly dividend of $0.05 per Common Share 15 Paramount offers a unique investment proposition (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.
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Advisories
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Advisories 17 Forward-Looking Information Certain statements in this presentation 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 presentation includes, but is not limited to: (i) expected average sales volumes for 2025; (ii) the expected 2025 exit rate of production and expectations that similar levels of capital expenditures in 2026 to those planned in 2025 would enable it to exit 2026 with production in excess of 60,000 Boe/d (50% liquids); (iii) planned capital expenditures in 2025 and the allocation thereof; (iv) planned abandonment and reclamation expenditures in 2025; (v) planned future production at Willesden Green Duvernay and Kaybob North Duvernay; (vi) targeted potential plateau production rates and the years of production that may be supported at Willesden Green Duvernay, Kaybob North Duvernay and Sinclair; (vii) planned and potential exploration, development and production activities, including: (a) the expected timing of completion of phase one and phase two of the Alhambra Plant and the expected capacity thereof on completion and (b) 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; (viii) the expectation that North Duvernay production growth will offset declines from legacy conventional production in the Kaybob Region; (ix) play data for various properties; and (x) general business strategies and objectives. 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 presentation or Paramount’s continuous disclosure documents: (i) future commodity prices; (ii) the potential scope and duration of tariffs, export taxes, export restrictions or other trade actions; (iii) the impact of international conflicts, including in Ukraine and the Middle East; (iv) royalty rates, taxes and capital, operating, general & administrative and other costs; (v) foreign currency exchange rates, interest rates and the rate and impacts of inflation; (vi) general business, economic and market conditions; (vii) the performance of wells and facilities; (viii) the availability to Paramount of the funds required for exploration, development and other operations and the meeting of commitments and financial obligations; (ix) 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; (x) the ability of Paramount to secure adequate processing, transportation, fractionation, disposal and storage capacity on acceptable terms and the capacity and reliability of facilities; (xi) the ability of Paramount to obtain the volumes of water required for completion activities; (xii) the ability of Paramount to market its production successfully; (xiii) 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; (xiv) the timely receipt of required governmental and regulatory approvals; (xv) the application of regulatory requirements respecting abandonment and reclamation; and (xvi) anticipated timelines and budgets being met in respect of: (a) drilling programs and other operations, including well completions and tie-ins, (b) 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 (c) 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 the preparation of this presentation, 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 current 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. These risks and uncertainties include and/or relate (but are not limited) to: (i) fluctuations in commodity prices; (ii) changes in capital spending plans and planned exploration and development activities; (iii) changes in political and economic conditions, including risks associated with tariffs, export taxes, export restrictions or other trade actions; (iv) changes in foreign currency exchange rates, interest rates and the rate of inflation; (v) 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; (vi) the ability to secure adequate processing, transportation, fractionation, disposal and storage capacity on acceptable terms; (vii) operational risks in exploring for, developing, producing and transporting natural gas and liquids, including the risk of spills, leaks or blowouts; (viii) 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; (ix) 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; (x) 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 the Alhambra Plant; (xi) processing, transportation, fractionation, disposal and storage outages, disruptions and constraints; (xii) 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; (xiii) risks and uncertainties involving the geology of oil and gas deposits; (xiv) the uncertainty of reserves estimates; (xv) general business, economic and market conditions; (xvi) 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); (xvii) changes in, or in the interpretation of, laws, regulations or policies (including environmental laws); (xviii) 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; (xix) the effects of weather and other factors including wildlife and environmental restrictions which affect field operations and access; (xx) uncertainties as to the timing and cost of future abandonment and reclamation obligations and potential liabilities for environmental damage and contamination; (xxi) uncertainties regarding Indigenous claims and in maintaining relationships with local populations and other stakeholders; (xxii) the outcome of existing and potential lawsuits, regulatory actions, audits and assessments; and (xxiii) 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
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Advisories 18 In addition to the above, there are no assurances as to the continuing declaration and payment of future monthly dividends by the Company or the amount or timing of any such dividends. There are risks that may result in the Company changing, suspending or discontinuing its monthly dividend program, including changes to free cash flow, operating results, capital requirements, financial position, market conditions or corporate strategy and the need to comply with requirements under debt agreements and applicable laws respecting the declaration and payment of dividends. The forward-looking information and statements contained in this presentation are made effective as of May 12, 2025. The internally estimated play data information for Willesden Green and Kaybob North Duvernay contained on pages 7 and 9 in this presentation has been prepared effective December 31, 2024. In each case, events or information subsequent to the applicable effective dates have not been incorporated. 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. Specified Financial Measures Capital Management Measures Net (cash) debt is a capital management measure that Paramount utilizes in managing its capital structure. This measure is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 15 – Capital Structure in the interim consolidated financial statements of Paramount as at and for the three months ended March 31, 2025 for a description of the composition and use of this measure. The capital management measure of net (cash) debt has been expressed as net cash in this presentation for simplicity as the applicable amounts referenced are negative numbers. Oil and Gas Measures and Definitions Natural Gas GJ Gigajoules GJ/d Gigajoules per day Mcf Thousands of cubic feet MMcf Millions of cubic feet MMcf/d Millions of cubic feet per day AECO AECO-C reference price Liquids Bbl Barrels Bbl/d Barrels per day MBbl Thousands of barrels NGLs Natural Gas Liquids Condensate Pentane and heavier hydrocarbons WTI West Texas Intermediate Oil Equivalent 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 document contains disclosures expressed as "Boe", "$/Boe", "MBoe", "MMBoe" 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 document contain references to CGR, a metric commonly used in the oil and natural gas industry. CGR means condensate to gas ratio and, except as noted in this Advisories Appendix under "Play Data", is calculated by dividing raw wellhead liquids volumes by raw wellhead natural gas volumes. CGR is a measure commonly used by management and investors to assess the relative liquids production from a well. This metric does not have standardized meaning and may not be comparable to similar measures presented by other companies. As such, it should not be used to make comparisons and should not be unduly relied upon. All information in this presentation respecting acres of land held is effective as of December 31, 2024 unless otherwise stated. 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 the Company’s website at www.paramountres.com.
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Advisories 19 Product Type Information This presentation includes references to forecast sales volumes of "liquids". "Liquids" refers to light and medium crude oil, tight oil, heavy crude oil, condensate and ethane, propane and butane ("Other NGLs") combined. Below is further information respecting the composition of forecast sales volumes for the applicable periods. 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). Play Data The internally estimated play data information for Willesden Green and Kaybob North Duvernay and contained on pages 7 and 9 in this presentation has been prepared effective December 31, 2024 by internal qualified reserves evaluators from Paramount in accordance with COGEH and using commodity prices of US$70/Bbl WTI, $3.08/GJ AECO and an exchange rate of US$0.740 for one Canadian dollar. The play data has been prepared excluding certain wells with significant deviation in completion, lateral length and depletion or infrastructure constraints. The play data contains no adjustments or assumptions respecting unscheduled potential future facility and transportation constraints or outages. Underlying forecast economics are half-cycle economics and include only the cost to drill, complete, tie-in and equip wells. The forecasts do not take into account certain other capital costs, including those required to construct central processing facilities, regional gathering facilities, condensate stabilization facilities and other infrastructure and costs related to water disposal and wellbore optimization. Sales and production volumes presented in the play data have been estimated on the basis of an equal likelihood that actual volumes recovered will be greater or less than those estimated. The metrics and terms "CGR", "IP 365", "IP 365 CGR", "Sales Volumes", "Average CGR", "Sales Gas", "Sales Condensate" and "DCET" are used in presenting play data. "CGR" means condensate to gas ratio and, in the context of play data, is calculated by dividing sales condensate volumes by sales natural gas volumes. "IP 365" means the estimated average daily sales volumes of production over the initial 365 calendar days of production. "IP 365 CGR" means the estimated average CGR over the initial 365 calendar days of production. "Sales Volume" means the estimated aggregate potential sales volumes of production. "Average CGR" means the estimated average CGR over the life of the well. "Sales Gas" means the estimated aggregate potential sales volumes of natural gas. "Sales Condensate" means the estimated aggregate potential sales volumes of condensate. "DCET" means estimated drilling, completion, equip and tie-in costs. The play data contained in this presentation has been included solely to inform readers as to certain assumptions and estimates relied on by management of Paramount as at December 31, 2024 for the purposes of the preparation of its 2025 capital expenditure and production forecasts. The play data: (i) represents an estimate only respecting certain undeveloped locations in 2025 development plans utilizing specific well and completion designs that were anticipated to be employed as of the effective date of the preparation of the play data, (ii) is not applicable to all undeveloped locations and all well and completion designs and (iii) is subject to revision based on a number of factors, including due to changes in development plans, changes to well and completion designs or changes in other underlying assumptions or expectations. Play data should not be relied on as an estimate or evaluation of reserves or resources associated with the Company’s properties and readers are referred to the Company's annual information form for the year ended December 31, 2024, which is available on SEDAR+ at www.sedarplus.ca or at www.paramountres.com, for reserves information respecting the Company.
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Paramount Resources Ltd. 4700 – 888 3rd Street S.W. Calgary, Alberta Canada T2P 5C5 Telephone: 403.290.3600 www.paramountres.com