Paramount Resources Ltd (PK)【PRMRF】株式ニュース

Paramount Resources Ltd. Announces Fourth Quarter and Annual 2025 Results, Increased 2026 Production Guidance and Expanded Land PositionsMarch 3, 2026 7:00 AM
PR Newswire (Canada)

CALGARY, AB, March 3, 2026 /CNW/ - Paramount Resources Ltd. ("Paramount" or the "Company") (TSX: POU) is pleased to announce its fourth quarter and annual 2025 financial and operating results, highlighted by fourth quarter sales volumes of 46,973 Boe/d (53% liquids) and adjusted funds flow of $140 million, annual capital expenditures of $789 million and strong reserves growth. The Company is also pleased to announce that it is increasing 2026 production guidance due to the performance of its Willesden Green Duvernay development. In addition, the Company has significantly expanded its land positions at Willesden Green and at its Sinclair Montney development. 2025 was a transformative year for the Company, marked by the following significant achievements and highlights:Closing the sale of the Karr, Wapiti and Zama properties on January 31 for cash proceeds of $3.243 billion, after adjustments (the "Grande Prairie Disposition");Bringing the first phase of the new Alhambra Plant at Willesden Green onstream in July, ahead of schedule and below budget, and sanctioning the second phase of the plant that is now expected to be brought onstream by early in the third quarter of 2026;Sanctioning the Sinclair Montney natural gas development, planned to be onstream in the fourth quarter of 2027, which is being designed to add over 300 MMcf/d of natural gas sales volumes; Growing sales volumes from approximately 30,000 Boe/d (39% liquids) immediately following the Grande Prairie Disposition to approximately 47,000 Boe/d (53% liquids) in the fourth quarter of 2025;Increasing December 31, 2025 proved developed producing ("PDP") reserves by 46%, total proved ("TP") reserves by 43% and proved plus probable ("P+P") reserves by 115%, after adjusting for the impacts of the Grande Prairie Disposition;Providing $2.4 billion in shareholder returns through a $2.15 billion special cash distribution of $15.00 per class A common share ("Common Share") in February, $101 million in regular monthly dividends totaling $0.70 per Common Share and $155 million in normal course issuer bid purchases of 4.9 million Common Shares;Selling the Company's remaining investment in NuVista Energy for cash proceeds of $519 million;Expanding the Company's core land positions at Willesden Green by approximately 20% to over 500 net sections (320,000 acres) and at Sinclair by approximately 30% to over 220 net sections (140,000 acres); andExiting the year with a strong liquidity position to execute on its Willesden Green Duvernay and Sinclair Montney developments, including $730 million of cash and cash equivalents and undrawn credit facilities totaling $750 million.OPERATIONAL AND FINANCIAL HIGHLIGHTSFourth quarter sales volumes were 46,973 Boe/d (53% liquids), a 30% increase over third quarter sales volumes. Annual sales volumes were 42,238 Boe/d (48% liquids), exceeding the upper end of the Company's guidance range of 41,000 to 42,000 Boe/d (47% liquids) with a higher than forecast liquids contribution.(1)At Willesden Green, the ramp-up of production through the Company's wholly-owned and operated Alhambra Plant continued, with average sales volumes growing to 25,752 Boe/d (62% liquids) in the quarter. The Company continued to achieve high runtime at the Alhambra Plant and strong Duvernay well performance in the fourth quarter. Gross 150-day peak production from the Company's first ten Duvernay wells brought onstream through the Alhambra Plant between late July and early September 2025 averaged approximately 1,250 Boe/d (61% liquids) per well. The four wells with the longest production history have averaged gross 210-day peak production of approximately 1,225 Boe/d (56% liquids) per well, reflecting continued shallow declines. (2)   Willesden Green sales volumes have grown from approximately 7,000 Boe/d (53% liquids) in January 2025 to average over 29,000 Boe/d (62% liquids) in December 2025. At Kaybob, fourth quarter sales volumes were 20,387 Boe/d (41% liquids) and annual sales volumes were 21,216 Boe/d (40% liquids). Kaybob annual sales volumes were 5% lower than 2024.Capital expenditures totaled $789 million in 2025, below the low end of the Company's guidance range of $795 million to $825 million. Paramount's 2025 capital program was largely focused on its Willesden Green Duvernay development, with lesser amounts directed to the Company's Kaybob North Duvernay and Sinclair Montney developments. Key activities included:drilling 40 (40.0 net) wells and bringing 36 (36.0 net) wells on production;completing the construction of the first phase of the Alhambra Plant and advancing construction of the second phase; andadvancing design work and purchasing long-lead items for the Sinclair Plant.Cash from operating activities was $185 million ($1.29 per basic share) in the fourth quarter and $417 million ($2.90 per basic share) in 2025. (3)Adjusted funds flow was $140 million ($0.97 per basic share) in the fourth quarter and $467 million ($3.25 per basic share) in 2025. _________________________________________(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)Gross 150-day and 210-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 150-day period or 210-day period, as applicable, 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. Natural gas sales volumes were lower by approximately 9% and liquids sales volumes were lower by approximately 14% 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.(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, free cash flow per basic share and operating expense per Boe are supplementary financial measures. Refer to the "Specified Financial Measures" section for more information on these measures.Free cash flow was $(85) million ($(0.59) per basic share) in the fourth quarter and $(386) million ($(2.68) per basic share) in 2025.With approximately 71,000 Mcf/d of Paramount's natural gas sales volumes priced at diversified markets outside of AECO in 2025, Paramount's average realized natural gas price in 2025 was $3.02/Mcf. In 2026, approximately 58% of the Company's forecast natural gas sales volumes are expected to be priced at diversified markets outside of AECO, including at Dawn, Malin and Emerson.Operating expenses were $9.84/Boe in the fourth quarter and $11.66/Boe in 2025. Per-unit operating expenses continued to decrease in the fourth quarter as production volumes ramped-up in Willesden Green. Willesden Green operating expenses averaged $4.71/Boe in the fourth quarter and $6.26/Boe in 2025.Asset retirement obligation settlements totaled $39 million in 2025, which included the abandonment of 26 wells, decommissioning of 14 pipeline segments and reclamation of 61 sites.In December 2025, the Company secured a five-year $250 million non-revolving, non-amortizing, delayed draw term loan facility with Export Development Canada and extended the maturity date of its $500 million financial covenant-based senior secured revolving bank credit facility to December 15, 2029.2026 GUIDANCE The Company is increasing its 2026 annual sales volumes guidance by 1,000 Boe/d to between 46,000 Boe/d and 51,000 Boe/d (50% liquids):First half 2026 sales volumes are now expected to average between 39,000 Boe/d and 44,000 Boe/d (47% liquids), a 2,000 Boe/d increase from prior guidance. The increase reflects higher assumed reliability of the Alhambra Plant based on performance to date as well as stronger well productivity. Second quarter sales volumes continue to be expected to be lower than first quarter volumes due to the timing of new well production, as well as a planned one-week outage at the Alhambra Plant in the second quarter to accommodate the expansion of the facility. Third quarter 2026 average sales volumes are expected to be between 46,500 Boe/d and 51,500 Boe/d (51% liquids) as the second phase of the Alhambra Plant comes onstream. A one-month outage at the Leafland Plant is planned starting in July as the interconnection to the Alhambra Plant is put into service. Fourth quarter 2026 average sales volumes are expected to be between 59,000 Boe/d and 64,000 Boe/d (53% liquids). Paramount is reaffirming its 2026 guidance for capital expenditures of between $1,050 million and $1,150 million and abandonment and reclamation expenditures of $35 million.  With cash and cash equivalents of $730 million and $750 million in undrawn credit facilities at December 31, 2025, Paramount is in a strong financial position to advance its planned Willesden Green and Sinclair developments. The Company remains committed to prudently managing its capital resources and has the flexibility to adjust its capital expenditure plans depending on commodity prices and other factors.CAPITAL AND SALES VOLUMES OUTLOOKParamount continues to expect midpoint annual capital expenditures of approximately $1,100 million for each of 2026 and 2027, which will mostly be directed to the Willesden Green Duvernay and Sinclair Montney developments. The Company continues to expect its sales volumes to more than double to over 100,000 Boe/d (35% liquids) by the end of 2027.Outlook20262027Capital expenditures (midpoint)$1,100 million$1,100 millionWillesden Green $630 million$440 millionSinclair $360 million$440 millionSales volumes (annual)Exit rate46,000 – 51,000 Boe/d (50% liquids) 60,000 – 65,000 Boe/d (50% liquids)> 100,000 Boe/d (35% liquids)RESERVES HIGHLIGHTS (1)Paramount added substantial reserves in 2025, driven mainly by its developments at Willesden Green and Sinclair.After adjusting for the impacts of the Grande Prairie Disposition:PDP reserves were up 46% to 59 MMBoe, TP reserves were up 43% to 200 MMBoe and P+P reserves were up 115% to 522 MMBoe.Paramount's reserves replacement ratios were 2.4x for PDP reserves, 5.2x for TP reserves and 21.7x for P+P reserves: (2)additions to TP liquids reserves represented 571% of liquids production and to P+P liquids reserves represented 920% of liquids production; andadditions to TP natural gas reserves represented 479% of natural gas production and to P+P natural gas reserves represented 3,314% of natural gas production.2025 finding and development ("F&D") costs were: (3)$24.42/Boe for PDP reserves (1.2x recycle ratio);$24.15/Boe for TP reserves (1.2x recycle ratio); and$11.67/Boe for P+P reserves (2.5x recycle ratio).The F&D cost calculations include 2025 capital expenditures and changes in future development costs related to the buildout of processing facilities and associated field infrastructure at Willesden Green and Sinclair of an aggregate of approximately $200 million ($2.80/Boe) on a TP basis and approximately $660 million ($2.30/Boe) on a P+P basis. While the inclusion of these costs impacts the calculation of F&D costs in the near term, the Company will benefit from substantially reduced operating costs and operational________________________________________(1)Readers are referred to the advisories concerning "Reserves Data". All reserves in this press release are gross reserves based on an evaluation prepared by McDaniel & Associates Consultants Ltd. ("McDaniel") dated March 2, 2026 and effective December 31, 2025 (the "McDaniel Report"). Estimates of net present value of future net revenue of reserves do not represent fair market value. Readers should refer to the Company's annual information form for the year ended December 31, 2025, 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, tight oil and light and medium crude oil) and the material assumptions, limitations and risk factors pertaining thereto.(2)See "Oil and Gas Measures and Definitions" in the Advisories section of this document for a description of the calculation and use of reserves replacement ratio.(3)Finding and development costs and recycle ratio are non-GAAP ratios. Refer to the "Specified Financial Measures" section and "Oil and Gas Measures and Definitions" in the Advisories section for more information on these measures and on the related non-GAAP financial measure of F&D capital.control over the lifespan of the properties from the wholly-owned facilities and infrastructure that it is constructing compared to reliance on third-party natural gas processing facilities.The Company's reserve life index, calculated excluding the production associated with the assets sold in the Grande Prairie Disposition, is 4.5 years for PDP, 15.2 years for TP and 39.5 years for P+P reserves.(1)The following table summarizes Paramount's gross PDP, TP and P+P reserves at December 31, 2025.
Proved Developed ProducingTotal ProvedTotal Proved Plus ProbableNatural gas (Bcf)2026112,094NGLs (MBbl)23,49295,890168,336Crude oil (MBbl)1,9882,2904,243Total (MBoe)59,151199,989521,518% Liquids43 %49 %33 %Columns may not add due to roundingThe following table summarizes the Company's gross proved and proved plus probable developed and undeveloped reserves at December 31, 2025 and the net present value of future net revenue of these reserves before income taxes, undiscounted and discounted at 10%.
ProvedProved plus Probable
Gross ReservesFuture Net RevenueNPV Before Tax($ millions)Gross ReservesFuture Net RevenueNPV Before Tax($ millions)
(MBoe)0 %10 %(MBoe)0 %10 %Developed70,26635772996,568929972Undeveloped 129,7232,485950424,9517,4012,278Total199,9892,8431,679521,5188,3303,250Columns may not add due to roundingREVIEW OF OPERATIONS WILLESDEN GREENThe Willesden Green Duvernay development is located near Rocky Mountain House, Alberta where the Company holds over 320,000 net acres of Duvernay rights. Paramount produces liquids-rich natural gas at Willesden Green which is handled at its wholly-owned and operated Alhambra Plant and its majority-owned and operated Leafland Plant, with minor volumes being handled at third-party processing facilities. Construction of the first phase of the Alhambra Plant was substantially completed in July 2025 and first sales volumes were achieved in late-July. The first phase of the Alhambra Plant was designed to provide raw handling capacity of approximately 10,000 Bbl/d of liquids and 50 MMcf/d of natural gas. The Alhambra Plant is designed to be capable of expansion to a total raw handling capacity of 30,000 Bbl/d of liquids and 150 MMcf/d of natural gas through the construction of two additional phases. Onsite construction of the second phase of the Alhambra Plant commenced in the third quarter of 2025. ________________________________________(1)See "Oil and Gas Measures and Definitions" in the Advisories section of this document for a description of the calculation and use of reserve life index.The Leafland Plant has raw handling capacity of approximately 6,000 Bbl/d of liquids and 22 MMcf/d of natural gas.Capital expenditures at Willesden Green totaled $570 million in 2025. Development activities were focused on the buildout of area infrastructure and the drilling of wells to fill the associated expanded processing capacity. Infrastructure development was focused on the Alhambra Plant where construction of the first phase was completed and onsite work for the second phase commenced. In addition, the Company began construction of water recycling facilities as well as a pipeline interconnect between the Leafland and Alhambra Plants. Duvernay well development activities in 2025 included the drilling of 27 (27.0 net) wells and the bringing on production of 22 (22.0 net) wells.Willesden Green sales volumes averaged 14,161 Boe/d (60% liquids) in 2025 compared to 7,537 Boe/d (53% liquids) in 2024. Sales volumes were higher in 2025 due to new Duvernay well production that began flowing through the Alhambra Plant in late-July. The Company achieved record quarterly sales volumes at Willesden Green of 25,752 Boe/d (62% liquids) in the fourth quarter as additional Duvernay wells were brought on production.Runtime at the Alhambra Plant has been exceptional in the seven months since start-up. In addition, recent capacity tests of the Alhambra Plant's raw liquids handling processes have demonstrated a functional limit of approximately 10,900 Bbl/d compared to the 10,000 Bbl/d original design specification. The Company plans to conduct tests of the plant's raw natural gas handling capacity in 2026 as plant throughput gradually shifts to include a higher percentage of natural gas. Better than expected performance from the 16 wells flowing through the Alhambra Plant also significantly contributed to higher production. These wells have been and continue to be choked as part of Paramount's well drawdown strategy. This approach has resulted in shallower condensate production declines and higher initial CGRs when compared to Paramount's earlier Willesden Green Duvernay wells. (1) The strategy also maximizes condensate processing utilization while avoiding curtailment due to prematurely reaching natural gas capacity constraints.Gross 150-day peak production from the Company's first ten Duvernay wells brought onstream through the Alhambra Plant between late July and early September 2025 averaged approximately 1,250 Boe/d (61% liquids) per well. The four wells with the longest production history have averaged gross 210-day peak production of approximately 1,225 Boe/d (56% liquids) per well, reflecting continued shallow declines. The six-well Duvernay pad that was brought onstream in the fourth quarter of 2025 is exhibiting similar performance. Paramount continues to evaluate new well performance and will incorporate its findings into future development plans as additional data is obtained. (2) The commissioning of Paramount's water recycling facility at the Alhambra Plant has commenced and is ongoing. Once completed, the Company will begin to redirect treated produced water to engineered containment ponds allowing it to pump recycled water to well sites for use in its completion operations, significantly reducing the amount of fresh water required for completion activities, lowering well capital costs and reducing operating costs associated with water disposal.The expansion of the Alhambra Plant, which is set to double its raw handling capacity, is progressing well. Most mechanical packages have been received and on-site electrical and instrumentation work is well underway. The Company also continues to make good progress on the construction of the pipeline_________________________________________(1)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.(2)Gross 150-day and 210-day peak production is the highest daily average production rate for each well, measured at the wellhead, over a rolling 150-day period or 210-day period, as applicable, 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. Natural gas sales volumes were lower by approximately 9% and liquids sales volumes were lower by approximately 14% 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.connecting the Alhambra and Leafland Plants and preparations to expand inlet compression at the Leafland Plant are ongoing. Combined, these activities will enable the Company to optimize the flow of raw production and the utilization of processing capacities across the field. The Company now expects start-up of the second phase of the Alhambra Plant by early in the third quarter of 2026.Paramount anticipates 2026 midpoint capital expenditures of approximately $630 million at Willesden Green, of which approximately two-thirds is expected to be incurred in the first half of the year for facility expansion activities and drilling, completion and tie-in activities to fill the expanded capacity. The Company continues to expect a one-week outage at the Alhambra Plant in the second quarter to accommodate the expansion of the facility. A one-month outage at the Leafland Plant is planned starting in July as the interconnection to the Alhambra Plant is put into service. In 2026, Paramount plans to drill 29 (29.0 net) Duvernay wells and complete and bring on production 26 (26.0 net) Duvernay wells at Willesden Green. Five wells are expected to be brought onstream in the first half of the year while the remaining 21 wells are anticipated to be brought onstream in the second half of the year as additional processing capacity is made available through the start-up of the second phase of the Alhambra Plant.Paramount has not yet sanctioned the third phase expansion of the Alhambra Plant, which would add an incremental planned 50 MMcf/d of raw gas handling and 10,000 Bbl/d of raw liquids handling capacity. Natural gas and liquids sales egress for the third phase remains contracted for the fourth quarter of 2029. To date, the Company has targeted a plateau production level at Willesden Green of approximately 50,000 Boe/d that can be sustained for a period of over 20 years. The recent substantial additions to the Willesden Green land position will enable Paramount to further increase this targeted plateau production level.SINCLAIR Paramount's Sinclair Montney development is located west of Grande Prairie Alberta where the Company holds over 140,000 net acres of contiguous Montney rights.The Sinclair development is a high-rate, low-cost natural gas project that was sanctioned by the Company in the fourth quarter of 2025. Production will be processed at the Sinclair Plant, which is being designed to handle up to 400 MMcf/d of raw gas production and will be constructed in 2026 and 2027. The Company has contracted 335 MMcf/d of firm service sales egress commencing in the fourth quarter of 2027 to coincide with the planned start-up of the Sinclair Plant.Capital expenditures at Sinclair totaled $65 million in 2025 and were focused on well appraisals, plant engineering and design and the ordering of long-lead items, as well as regulatory and other activities that informed the decision to sanction the Sinclair Montney development. In 2025, Paramount completed and flow-tested two (2.0 net) Montney appraisal wells and drilled two (2.0 net) additional Montney appraisal wells.The Company anticipates 2026 midpoint capital expenditures of approximately $360 million at Sinclair. Activities in 2026 will include flow-testing the two (2.0 net) Montney appraisal wells that were drilled in late-2025, procuring equipment and advancing construction activities related to the Sinclair Plant and other area infrastructure and drilling 15 (15.0 net) Montney wells. Completion and tie-in activities are planned to commence in 2027.KAYBOBThe Company's Kaybob properties are located in the greater Kaybob area near Fox Creek, Alberta and include the Kaybob North Duvernay development and other natural gas and oil producing properties. Paramount's Kaybob land holdings include approximately 110,000 net acres of Duvernay rights and approximately 180,000 net acres of Montney rights. The Company owns and operates extensive processing and gathering infrastructure in the area.Capital expenditures at Kaybob totaled $121 million in 2025 and were focused on the Kaybob North Duvernay development. Development activities included the drilling of eight (8.0 net) Duvernay wells and the bringing on production of nine (9.0 net) Duvernay wells at Kaybob North.Kaybob sales volumes averaged 21,216 Boe/d (40% liquids) in 2025 compared to 22,404 Boe/d (41% liquids) in 2024. The Company anticipates maintaining average production at Kaybob of between 19,000 Boe/d and 20,000 Boe/d (38% liquids) through to 2028.In 2026, the Company plans to drill two (2.0 net) Duvernay wells and bring on production three (3.0 net) Duvernay wells that were drilled last year. Paramount also plans to drill and bring two (2.0 net) Montney oil wells on production.OTHER PROPERTIES AND LAND POSITIONParamount continues to hold material land positions with large-scale future development potential, including:1.3 million net acres of land in Alberta that are prospective for cold flow heavy oil and in-situ thermal oil recovery, including approximately 300,000 net acres with Clearwater and Bluesky cold flow heavy oil potential and approximately 70,000 net acres with thermal oil potential at the Company's Hoole Grand Rapids property;shale gas properties in northeast British Columbia in the Horn River Basin, where the Company holds approximately 110,000 net acres of Muskwa rights, and in the Liard Basin, where the Company holds approximately 195,000 net acres of Besa River rights; andapproximately 170,000 net acres of undeveloped land in the Mackenzie Delta and Central Mackenzie in the Northwest Territories prospective for natural gas and oil production.In addition to minor planned exploration and development activities at its northeast Alberta heavy oil properties in 2026, the Company continues to evaluate opportunities within its portfolio that have the potential for scalable and highly economic development in the medium and long-term term.LAND Paramount's total land position as at December 31, 2025 is summarized below.(thousands of acres)Gross (1)Net (2)Acreage assigned reserves852704Acreage not assigned reserves3,3632,349Total4,2153,053(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. HEDGING & GAS MARKET DIVERSIFICATIONHEDGINGThe Company's current financial commodity and foreign currency exchange contracts are summarized below:Instruments
Aggregate
amount / notional
Average
price or rate (1)
Remaining term

Natural Gas

Citygate / Malin Basis Swap (2)
10,000 MMBtu/d
Citygate less US$0.97/MMBtu (Sell)Malin (Buy)
March 2026 – October 2028

Foreign Currency Exchange

Average Rate Forward
US$10MM/Month
1.3810 CAD$ / US$ (1)
March 2026 – December 2026Average Rate Forward
US$10MM/Month
1.3680 CAD$ / US$ (1)
January 2027 – December 2027(1)Average price is calculated using a weighted average of notional volumes and prices. Foreign currency exchange average rate forward contracts are settled monthly against the average of the CAD$/US$ noon spot rate on each applicable day in that month.(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$0.97/MMBtu and buys at Malin. The transaction is financially settled with no physical delivery.GAS MARKET DIVERSIFICATIONWith the natural gas market diversification contracts currently in place, approximately 58% of the Company's forecast natural gas sales volumes for 2026 will benefit from exposure to markets outside of AECO.MARCH DIVIDENDParamount's Board of Directors has declared a cash dividend of $0.05 per Common Share that will be payable on March 31, 2026 to shareholders of record on March 16, 2026. The dividend will be designated as an "eligible dividend" for Canadian income tax purposes.ANNUAL GENERAL MEETINGParamount will hold its annual general meeting of shareholders on Tuesday, May 12, 2026 at 10:00 a.m. (Mountain Time) in the Doulton Room at Bankers Hall Conference Centre, 400, 315 - 8th Avenue S.W., Calgary, Alberta.COMPLETE ANNUAL RESULTSParamount's: (i) complete annual results, including the Company's audited consolidated financial statements as at and for the year ended December 31, 2025 (the "Consolidated Financial Statements") and the accompanying management's discussion and analysis (the "MD&A"); and (ii) 2025 annual information form, which contains additional important information concerning the Company's reserves, properties and operations, can be obtained on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports. A summary of historical financial and operating results is also available on Paramount's website at www.paramountres.com/investors/financial-shareholder-reports.ABOUT PARAMOUNTParamount is an independent, publicly traded Canadian energy company that explores for and develops both conventional and unconventional petroleum and natural gas, including longer-term strategic exploration and pre-development plays. The Company's principal properties are located in Alberta and British Columbia. Paramount's Common Shares are listed on the Toronto Stock Exchange under the symbol "POU".FINANCIAL AND OPERATING RESULTS (1)
Three months ended December 31Year ended December 31($ millions, except as noted)2025202420252024Net income (loss)(1.9)87.41,288.7335.9per share – basic ($/share)(0.01)0.608.962.30per share – diluted ($/share)(0.01)0.598.782.25Cash from operating activities185.4187.7417.3815.3per share – basic ($/share)1.291.282.905.58per share – diluted ($/share)1.291.262.845.46Adjusted funds flow140.1237.8467.2930.3per share – basic ($/share)0.971.623.256.37per share – diluted ($/share)0.971.593.186.24Free cash flow(84.6)52.8(385.5)37.3per share – basic ($/share)(0.59)0.36(2.68)0.25per share – diluted ($/share)(0.59)0.35(2.63)0.25Total assets

3,587.24,757.5Investments in securities

137.3563.9Long-term debt

–173.0Net (cash) debt

(672.8)188.4Common shares outstanding (millions) (2)

144.2146.9Sales volumes (3)

Natural gas (MMcf/d)133.1317.3131.9306.8Condensate and oil (Bbl/d)19,47242,83516,40240,432Other NGLs (Bbl/d)5,3186,7533,8536,920Total (Boe/d)46,973102,47742,23898,490% liquids53 %48 %48 %48 %Willesden Green (Boe/d)25,7528,48814,1617,537Kaybob (Boe/d)20,38722,44121,21622,404Other (Boe/d)8344847701,226Sold Assets (Boe/d) (4)–71,0646,09167,323Total (Boe/d)46,973102,47742,23898,490Netback
($/Boe) (5)
($/Boe) (5)
($/Boe) (5)
($/Boe) (5)    Natural gas revenue43.83.5858.01.99145.53.02223.31.99    Condensate and oil revenue137.376.66379.496.26511.385.401,434.996.96    Other NGLs revenue13.327.1521.334.3242.830.4689.635.37    Natural gas transportation assignment income (6)4.50.370.90.0318.30.380.90.01    Royalty income and other revenue (6)(0.4)–(0.3)–18.5–11.5–Petroleum and natural gas sales198.545.92459.348.72736.447.771,760.248.83 Royalties(11.3)(2.61)(48.5)(5.14)(51.0)(3.31)(222.8)(6.18) Operating expense(42.5)(9.84)(123.0)(13.05)(179.8)(11.66)(473.9)(13.15) Transportation and NGLs processing(20.8)(4.81)(38.1)(4.04)(68.9)(4.47)(135.6)(3.76) Sales of commodities purchased (7)72.716.8298.710.46280.318.18317.38.80 Commodities purchased (7)(71.6)(16.56)(97.7)(10.36)(275.2)(17.85)(312.0)(8.65)Netback125.028.92250.726.59441.828.66933.225.89 Risk management contract settlements20.44.73(1.5)(0.16)50.83.3036.41.01Netback including risk management contract settlements145.433.65249.226.43492.631.96969.626.90Capital expenditures

Willesden Green158.376.7569.6233.5Sinclair35.013.964.914.5Kaybob20.818.8121.3172.6Fox Drilling2.20.98.58.4Corporate and other (8)(7.7)4.78.2(1.4)Sold Assets (4)–55.816.0414.6Total208.6170.8788.5842.2Asset retirement obligations settled9.411.939.038.1

(1)Adjusted funds flow, free cash flow and net (cash) debt are capital management measures used by Paramount. Netback and netback including risk management contract settlements are non-GAAP financial measures. Netback and Netback including risk management contract settlements presented on a $/Boe or $/Mcf basis are non-GAAP ratios. Each measure, other than net income (loss), 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 cash bonus and restricted share unit plan (millions): 2025: 0.2 million, 2024: 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)"Sold Assets" refers to the Karr, Wapiti and Zama properties that were sold on January 31, 2025.(5)Natural gas revenue and natural gas transportation assignment income presented as $/Mcf.(6)Natural gas transportation assignment income relates to proceeds realized by the Company on the assignment of a portion of its ex-Alberta natural gas transportation capacity to third parties. In 2025, Paramount's insurance claims for 2023 Alberta wildfire business interruption losses were finalized, with an aggregate claim of $26.8 million being agreed by insurers (the "Wildfire Claim"). Royalty income and other revenue in 2025 includes $16.8 million (2024 – $10.0 million) relating to the Wildfire Claim. These amounts were not allocated to individual properties.(7)Sales of commodities purchased and commodities purchased are treated as corporate items and not allocated to individual properties.(8)Includes transfers of amounts held in Corporate to and from properties.PRODUCT TYPE INFORMATIONThis 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 Company by
Product TypeWillesden GreenKaybobOther Properties
20252024202520242025202420252024Shale gas (MMcf/d)90.4257.531.017.838.433.52.04.8Conventional natural gas (MMcf/d)41.549.32.93.438.445.60.20.2Natural gas (MMcf/d)131.9306.833.921.276.879.12.25.0Condensate (Bbl/d)14,63238,3116,0972,6455,9626,34811Other NGLs (Bbl/d) 3,8536,9202,1961,1221,2871,490118NGLs (Bbl/d) 18,48545,2318,2933,7677,2497,838129Light and medium crude oil (Bbl/d)1,1221,29623191,0991,277--Tight oil (Bbl/d)26745420321464109--Heavy crude oil (Bbl/d)381371----381371Crude oil (Bbl/d)1,7702,1212262331,1631,386381371Total (Boe/d)42,23898,49014,1617,53721,21622,4047701,226
Three months ended December 31
Total Company by
Product TypeWillesden GreenKaybobOther Properties
20252024202520242025202420252024Shale gas (MMcf/d)96.5269.256.119.738.135.72.3-Conventional natural gas (MMcf/d)36.648.12.63.433.844.30.20.3Natural gas (MMcf/d)133.1317.358.723.171.980.02.50.3Condensate (Bbl/d)17,77741,24311,8433,1185,9336,79412Other NGLs (Bbl/d) 5,3186,7533,9261,2841,3681,4802412NGLs (Bbl/d) 23,09547,99615,7694,4027,3018,2742514Light and medium crude oil (Bbl/d)1,06579221201,044772--Tight oil (Bbl/d)2383931782206060--Heavy crude oil (Bbl/d)392407----392407Crude oil (Bbl/d)1,6951,5921992401,104832392407Total (Boe/d)46,973102,47725,7528,48820,38722,441834484Paramount is forecasting 2026 annual average sales volumes of between 46,000 Boe/d and 51,000 Boe/d (50% shale gas and conventional natural gas combined, 38% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 12% other NGLs):First half 2026 average sales volumes are expected to be between 39,000 Boe/d and 44,000 Boe/d (53% shale gas and conventional natural gas combined, 37% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 10% other NGLs). Third quarter 2026 average sales volumes are expected to be between 46,500 Boe/d and 51,500 Boe/d (49% shale gas and conventional natural gas combined, 39% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 12% other NGLs).  Fourth quarter 2026 average sales volumes are expected to be between 59,000 Boe/d and 64,000 Boe/d (47% shale gas and conventional natural gas combined, 40% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 13% other NGLs).2027 annual average sales volumes are expected to be between 60,000 Boe/d to 65,000 Boe/d (50% shale gas and conventional natural gas combined, 38% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 12% other NGLs):Year-end 2027 exit sales volumes are expected to be over 100,000 Boe/d (65% shale gas and conventional natural gas combined, 29% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% other NGLs). The Company plans to maintain average sales volumes in Kaybob of between 19,000 Boe/d and 20,000 Boe/d (62% shale gas and conventional natural gas combined, 32% condensate, light and medium crude oil, tight oil and heavy crude oil combined and 6% other NGLs) through to 2028.SPECIFIED FINANCIAL MEASURESNon-GAAP Financial MeasuresNetback 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 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, 2025, and 2024.F&D capital is a measure used in determining F&D costs and is comprised of: (i) capital expenditures (the most directly comparable measure disclosed in the Company's primary financial statements) for 2025, excluding certain expenditures described herein, plus (ii) the change from the prior year in estimated future development capital included in the evaluation of the Company's reserves prepared by McDaniel & Associates Consultants Ltd. dated March 2, 2026 and effective December 31, 2025, excluding changes in future development capital associated with the assets sold in the Grande Prairie Disposition. Capital expenditures associated with the assets sold in the Grande Prairie Disposition, capital expenditures related to Fox Drilling and corporate capital expenditures have been excluded. The composition of F&D capital has changed from that disclosed in prior years to adjust for the effects of the Grande Prairie Disposition by excluding from the calculation capital expenditures and changes in future development capital associated with the assets sold in the Grande Prairie Disposition. F&D capital is used by management and investors, in calculating F&D costs, to represent the amount of capital invested in oil and gas exploration and development projects to generate reserves additions.Set out below is the calculation of F&D capital for the year ended December 31, 2025. Columns may not add due to rounding.($ millions)
Proved Developed Producing 2025Capital expenditures789Grande Prairie Disposition(16)Fox Drilling and corporate(10)Change in estimated future development capital19F&D Capital – PDP782

Total Proved 2025Capital expenditures789Grande Prairie Disposition(16)Fox Drilling and corporate(10)Change in estimated future development capital905F&D Capital – TP1,667

Proved Plus Probable 2025Capital expenditures789Grande Prairie Disposition(16)Fox Drilling and corporate(10)Change in estimated future development capital2,573F&D Capital – P+P3,336Non-GAAP RatiosF&D costs, recycle ratio, netback and netback including risk management contract settlements presented on a $/Boe basis are non-GAAP ratios as they each have a non-GAAP financial measure as a component. These measures are not standardized measures under IFRS and might not be comparable to similar financial measures presented by other issuers. These measures should not be considered in isolation or construed as alternatives to their most directly comparable measure disclosed in the Company's primary financial statements or other measures of financial performance calculated in accordance with IFRS.F&D costs are calculated by dividing: (i) F&D capital (a non-GAAP financial measure) for the applicable reserves category and period; by (ii) the net changes to reserves in such reserves category from the prior period from extensions/improved recovery, technical revisions and economic factors, expressed in Boe. F&D costs are a measure commonly used by management and investors to assess the relationship between capital invested in oil and gas exploration and development projects and reserve additions. Readers should refer to the information under the heading "Reserves – Reserves Reconciliation" in the Company's annual information form for the year ended December 31, 2025, which is available on SEDAR+ at www.sedarplus.ca or on the Company's website at www.paramountres.com, for a description of the net changes to reserves from the prior year. See "Advisories – Oil and Gas Definitions and Measures" below for more information about this measure.The calculation of F&D costs, after adjusting for the impacts of the Grande Prairie Disposition, is as follows:
F&D Capital($ millions)Reserves Additions (1)(MMBoe)F&D Costs($/Boe)Proved Developed Producing7823224.42Total Proved1,6676924.15Total Proved Plus Probable3,33628611.67(1)Reserves additions refers to the net changes to reserves in such reserves category from the prior period from extensions/improved recovery, technical revisions and economic factorsRecycle ratio is calculated by dividing the netback (a non-GAAP financial measure) per Boe from sales volumes, other than those associated with the assets sold in the Grande Prairie Disposition, for the period by the F&D costs for the period. The composition of recycle ratio has changed from that disclosed in prior years to adjust for the effects of the Grande Prairie Disposition by excluding the netback associated with the assets sold in the Grande Prairie Disposition. Recycle ratio is used by investors and management to compare the cost of adding reserves to the netback realized from production. See "Advisories – Oil and Gas Definitions and Measures" for more information about this measure.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 $/Boe basis is calculated by dividing netback including risk management contract settlements (a non-GAAP financial measure) for the applicable period by the total sales volumes during the period in Boe. These measures are used by investors and management to assess netback and netback including risk management contract settlements on a unit of sales volumes basis.Capital Management MeasuresAdjusted funds flow, free cash flow and net (cash) debt are capital management measures that Paramount utilizes in managing its capital structure. These measures are not standardized measures and therefore may not be comparable with the calculation of similar measures by other entities. Refer to Note 18 in the Consolidated Financial Statements of Paramount for: (i) a description of the composition and use of these measures, (ii) reconciliations of adjusted funds flow and free cash flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the years ended December 31, 2025 and 2024 and (iii) a calculation of net (cash) debt as at December 31, 2025 and 2024.The following is a reconciliation of adjusted funds flow to cash from operating activities, the most directly comparable measure disclosed in the Company's primary financial statements, for the three months ended December 31, 2025 and 2024:Three months ended December 31 ($millions)20252024Cash from operating activities185.4187.7Change in non-cash working capital(61.4)35.9Geological and geophysical expense2.62.3Asset retirement obligations settled 9.411.9Provisions settled4.1–Transaction and reorganization costs––Closure costs––Settlements––Adjusted funds flow 140.1237.8The 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, 2025 and 2024:Three months ended December 31 ($ millions)20252024Cash from operating activities185.4187.7Change in non-cash working capital(61.4)35.9Geological and geophysical expense2.62.3Asset retirement obligations settled 9.411.9Provisions settled4.1–Transaction and reorganization costs––Closure costs––Settlements––Adjusted funds flow 140.1237.8Capital expenditures(208.6)(170.8)Geological and geophysical expense(2.6)(2.3)Asset retirement obligation settled(9.4)(11.9)Provisions settled(4.1)–Free cash flow(84.6)52.8Supplementary Financial MeasuresThis 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.ADVISORIESForward-looking InformationCertain 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:the expected timing of completion of phase two of the Alhambra Plant and the expected capacity thereof on completion;the expected timing of completion of the Sinclair Plant and the expected capacity thereof on completion;expected average sales volumes for 2026 and certain periods therein;budgeted capital expenditures in 2026 and the allocation thereof;budgeted abandonment and reclamation expenditures in 2026;the Company's outlook for capital expenditures and sales volumes in 2027 and the year-end 2027 exit rate of sales volumes;the expected benefits of the completion of water recycling facilities and other infrastructure at Willesden Green;the Company's plans to maintain average sales volumes in Kaybob within a certain range through to 2028; andplanned and potential exploration, development and production activities, including the drilling, completion and bringing onstream of new wells, the construction of pipelines and other infrastructure, planned facility capacity testing and planned facility outages.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 (including the construction of the Sinclair Plant and the second phase of the Alhambra Plant) 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, pipelines and other infrastructure;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, including those necessary for the construction of the Sinclair Plant;the application of regulatory requirements respecting abandonment and reclamation; andanticipated 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 Sinclair Plant and the second phase 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, cash flows, 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, blowouts or induced seismicity events;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, commissioning, starting-up or operating new, expanded or existing facilities, including third-party facilities, the Sinclair Plant and 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 (including the construction of the Sinclair Plant and the second phase of the Alhambra Plant and the drilling, completion, equipping and tie-in of new wells necessary to maintain and grow production) 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, including those required for the Sinclair Plant, and to obtain and maintain leases and licenses;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; andother risks and uncertainties described elsewhere in this document and in Paramount's other filings with Canadian securities authorities.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 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, 2025, 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 DataReserves 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 2, 2026 and effective December 31, 2025 (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, 2025 and GLJ Ltd. and McDaniel as at January 1, 2026 (each of which is available on their respective websites at www.sproule-erce.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. Readers should refer to the Company's annual information form for the year ended December 31, 2025, 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 DefinitionsLiquids
Natural GasBblBarrels
GJGigajoulesBbl/dBarrels per day
GJ/dGigajoules per dayMBblThousands of barrels
MMBtuMillions of British Thermal UnitsNGLsNatural gas liquids
MMBtu/dMillions of British Thermal Units per dayCondensatePentane and heavier hydrocarbonsMcfThousands of cubic feetWTIWest Texas Intermediate
MMcfMillions of cubic feet

MMcf/dMillions of cubic feet per dayOil Equivalent
NYMEXNew York Mercantile ExchangeBoeBarrels of oil equivalent
AECOAECO-C reference priceMBoeThousands of barrels of oil equivalent

MMBoeMillions of barrels of oil equivalent

Boe/dBarrels 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, 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 contains metrics commonly used in the oil and natural gas industry. These metrics are "CGR", F&D costs, recycle ratio, reserves replacement ratio and reserve life index. Each of these metrics is determined by the Company as set out below or elsewhere in this press release. These metrics do not have standardized meanings and may not be comparable to similar measures presented by other companies. As such, they should not be used to make comparisons. Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare the Company's performance over time; however, such measures are not reliable indicators of the Company's future performance and future performance may not compare to the performance in previous periods and therefore should not be unduly relied upon."CGR" means condensate to gas ratio and is calculated by dividing wellhead raw liquids volumes by wellhead raw natural gas volumes.Refer to the "Specified Financial Measures" section of this press release for a description of the calculation and use of F&D costs and recycle ratio. Reserves replacement ratio is calculated by dividing: (i) the net changes in reserves from the prior year in the applicable category from extensions/improved recovery, technical revisions and economic factors, by (ii) the aggregate sales volumes during 2025, excluding sales volumes associated with the assets sold in the Grande Prairie Disposition. Reserves replacement ratio is a measure commonly used by management and investors to assess the rate at which reserves depleted by production are being replaced.Reserve life index is calculated by dividing: (i) reserves volumes of the applicable category by (ii) average annual sales volumes for 2025, excluding sales volumes associated with the assets sold in the Grande Prairie Disposition. Reserves life index is a measure commonly used by management and investors to assess the duration of inventory or life of reserves.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, 2025 which is available on SEDAR+ at www.sedarplus.ca or on Paramount's website at www.paramountres.com.SOURCE Paramount Resources Ltd.

Original: Paramount Resources Ltd. Announces Fourth Quarter and Annual 2025 Results, Increased 2026 Production Guidance and Expanded Land Positions