Yangarra Announces 2025 Year End Financial and Operating Results and Reserves

Yangarra Announces 2025 Year End Financial and Operating Results and Reserves Canada NewsWire CALGARY, AB, March 5, 2026 CALGARY, AB, March 5, 2026 /CNW/ - Yangarra Resources Ltd. ("Yangarra" or the "Company") (TSX: YGR) announces its financial and operating results and reserves for the year ended December 31, 2025. 2025 Operations Review Yangarra drilled 14 wells during 2025, spending $43.6 million on drilling & completions. Three of the 14 wells in the program were not on-stream at of year-end During 2025, Yangarra dedicated $8.5 million of strategic capital designed to create long-term value by allowing the Company to access new areas and/or tie-in drilling opportunities that would have required third-party infrastructure, including upgrades to existing facilities and one-time expenditures to reduce long-term operating costs. This included major pipeline work connecting new core areas with existing infrastructure and capital invested in a lower-risk exploration play. Land purchases and acquisitions totaled $6.1 million, adding potential locations targeting both the Cardium and the emerging Belly River play. Yangarra focused on multi-zonal prospects that will allow the Company to leverage existing infrastructure, including surface access. Yangarra spent $1.2 million on abandonment and reclamation activities in 2025, versus the mandatory minimum spend from the AER of $0.6 million. The Company's Board of Directors has approved a capital budget of $60 million for 2026, which is intended to hold production at 10,000 boe/d. In 2025, only 60% of the Company's total capital budget resulted in production additions during the year, with a five-month pause in drilling & completions due to weaker commodity prices. The outlook for 2026 is more positive than 2025, especially for natural gas prices as a result of increasing LNG egress, especially when combined with Yangarra's healthy hedge program. As a result of the 2025 strategic spend, the majority of the 2026 capital program will now be geared towards drilling and completions spread throughout the year with no unexpected pauses in activity other than potentially during spring-break. This program should result in a smoother growth profile of production for the year. 2025 Highlights Average production of 10,003 boe/d (42% liquids), a decrease of 5% from 2024 Oil and gas sales of $115.3 million, a decrease of 14% from 2024 Funds flow from operations of $62.8 million ($0.57 per share – fully diluted) a decrease of 17% from 2024   Adjusted EBITDA of $67.6 million ($0.62 per share – fully diluted) Net income of $15.0 million ($0.14 per share – fully diluted), resulting in an income margin of 13% Return on capital employed of 4% Operating costs of $8.64/boe (including $3.39/boe of transportation costs) Operating netback of $21.27/boe Operating margin of 67% and funds flow from operations margin of 54% G&A costs of $1.55/boe Royalties at 6% of oil and gas revenue Capital expenditures of $64.1 million (including $6.1 of raw land purchases) Adjusted net debt of $106.7 million Retained earnings of $353.0 million Decommissioning liabilities of $17.2 million (discounted) Fourth Quarter Highlights Average production of 9,577 boe/d (44% liquids), a 6% decrease from the same period in 2024 Oil and gas sales of $27.2 million, a decrease of 12% from the same period in 2024 Funds flow from operations of $14.1 million ($0.13 per share – fully diluted), a decrease of 13% from the same period in 2024. Adjusted EBITDA of $15.2 million ($0.14 per share – fully diluted), a decrease of 17% from the same period in 2024 Net income of $0.5 million ($0.01 per share – fully diluted)  Operating costs of $8.68/boe (including $3.70/boe of transportation costs) Operating netback of $20.61/boe Operating margin of 67% and funds flow from operations margin of 52%  G&A costs of $2.06/boe Royalties at 7% of oil and gas revenue All in cash costs of $14.72/boe Capital expenditures of $19.2 million Adjusted net debt to fourth quarter annualized funds flow from operations of 1.89 : 1 Operations Update Reserve Report Highlights All reserves information contained in this press release are based on the Company's 2025 NI 51-101 oil and gas reserve report as prepared by Deloitte LLP (The "2025 Reserve Report"). Summary Yangarra has now been developing the halo Cardium play for a number of years which provides more actual well performance data along with more confidence in spacing units for well placement. As a result, the type curves in the reserve report were adjusted to match actual performance by area and by spacing unit. This long-term lookback on well performance has had no impact on PDP reserves but has resulted in a moderation on proved undeveloped & probable bookings to match actual performance. Oil pricing in the report is down 15% and natural gas pricing is up 10% compared to last year. Proved Developed Producing ("PDP") Reserves 41 million boe (5% increase from 2024) Net present value before tax discounted at 10% ("NPV10") of $454 million (9% decrease from 2024) Yangarra's PDP finding and development ("F&D") cost is $11.95/boe resulting in a recycle ratio of 1.78 times PDP net asset value per fully diluted common share less Asset Retirement Obligations ("NAV per FD Share") of $3.00 PDP Reserve Life Index ("RLI") of 11.80 years PDP additions replaced 149% of 2025 production Total Proved reserves ("1P") 81 million boe (4% decrease from 2024) NPV10 of $825 million (22% decrease from 2024) 1P future development costs of $311 million, a $19 million reduction from 2024 Yangarra's 1P F&D cost over the last three years averaged $6.33/boe resulting in a recycle ratio of 3.78 times 1P NAV (less ARO) per FD Share of $6.35 RLI of 23.05 years Proved plus probable reserves ("2P") 119 million boe (11% decrease from 2024) NPV10 of $1.1 billion (22% decrease from 2024) 2P future development costs of $461 million, a $34 million reduction from 2024 Yangarra's 2P F&D cost over the last three years averaged $5.91/boe resulting in a recycle ratio of 4.05 times 2P NAV (less ARO) per FD Share of $8.95 RLI of 33.93 years Net Asset Value ("NAV") As at December 31, 2025 PDP Total Proved Proved + Probable Present Value Reserves, before tax (discounted at 10%) $454 $825 $1,112 Total Net Debt ($ million) (107) (107) (107) Asset Retirement Obligation (17) (17) (17) Net Asset Value $330 $701 $988 Fully diluted common shares outstanding (million) 110 110 110 Net asset value per share $3.00 $6.35 $8.95 Notes to table: (1) The preceding table shows what is customarily referred to as a "produce out" net asset value calculation under which the current value of Yangarra's reserves would be produced at the Deloitte forecast future prices and costs. The value is a snapshot in time as at December 31, 2025 and is based on various assumptions including commodity prices and foreign exchange rates that vary over time. In this analysis, the present value of the proved and probable reserves is calculated at a before tax 10 percent discount rate (2) Net debt or adjusted working capital (deficit), which represent current assets less current liabilities, excluding current derivative financial instruments, are used to assess efficiency, liquidity and the general financial strength of the Company. There is no IFRS measure that is reasonably comparable to net debt or adjusted working capital (deficit) Financial Summary 2025 2024 Year Ended Q4 Q3 Q4 2025 2024 Statements of Income and Comprehensive Income Petroleum & natural gas sales $        27,197 $        29,507 $        30,961 $       115,252 $       133,364 Income before tax $          3,104 $          9,106 $          2,833 $         22,870 $         32,588 Net income $             564 $          6,773 $          3,884 $         15,019 $         26,228 Net income per share - basic $            0.01 $            0.07 $            0.04 $             0.15 $             0.27 Net income per share - diluted $            0.01 $            0.06 $            0.04 $             0.14 $             0.25 Statements of Cash Flow Funds flow from operations $        14,123 $        15,499 $        16,210 $         62,805 $         75,599 Funds flow from operations per share - basic $            0.14 $            0.15 $            0.16 $             0.62 $             0.77 Funds flow from operations per share - diluted $            0.13 $            0.14 $            0.15 $             0.57 $             0.73 Cash flow from operating activities $        11,204 $        13,907 $        15,293 $         59,078 $         71,037 Weighted average number of shares - basic 101,656 101,193 98,734 101,194 98,096 Weighted average number of shares - diluted 109,743 109,605 104,796 109,283 104,225 December 31, 2025 December 31, 2024 Statements of Financial Position Property and equipment $                 810,189 $             786,521 Total assets $                 894,405 $             860,383 Working capital surplus (deficit) $                   20,537 $                 8,897 Adjusted net debt $                 106,719 $             103,147 Shareholders equity $                 590,468 $             569,628 Company Netbacks ($/boe) 2025 2024 Year Ended Q4 Q3 Q4 2025 2024 Sales price $           30.87 $          27.76 $           32.97 $           31.57 $           34.71    Royalty expense (2.16) (1.27) (2.54) (1.95) (2.25)    Production costs (4.99) (5.47) (5.38) (5.25) (6.30)    Transportation costs (3.70) (3.18) (3.16) (3.39) (2.09) Field operating netback 20.02 17.84 21.89 20.98 24.07   Realized gain (loss) on commodity contract settlement 0.59 1.65 (0.13) 0.30 (0.21) Operating netback 20.61 19.49 21.76 21.28 23.86    G&A (2.06) (1.62) (1.33) (1.55) (1.37)    Cash finance expenses (2.40) (2.63) (3.19) (2.46) (2.94)    Depletion and depreciation (11.65) (9.96) (9.84) (10.41) (9.24)    Non Cash - finance expenses (0.58) (0.36) (0.74) (0.39) (0.35) Abandonment Expenses (0.15) (0.27) - (0.10) (0.02)    Stock-based compensation (1.14) (1.15) (0.89) (1.11) (0.88)    Unrealized gain (loss) on financial instruments 0.89 0.30 (2.74) 1.02 (0.55)    Deferred income tax (2.88) (1.19) 1.12 (2.15) (1.66) Net income netback $            0.64 $            2.61 $            4.15 $            4.12 $            6.85 Business Environment 2025 2024 Year Ended Q4 Q3 Q4 2025 2024 Realized Pricing (Including realized commodity contracts)    Light Crude Oil ($/bbl) $           77.37 $          90.72 $           98.10 $           86.51 $           97.55    NGL ($/bbl) $           34.23 $          38.66 $           36.55 $           39.12 $           43.85    Natural Gas ($/mcf) $             2.61 $            1.26 $             1.65 $             1.95 $             1.58 Realized Pricing (Excluding commodity contracts)    Light Crude Oil ($/bbl) $           77.37 $          90.72 $           99.70 $           86.98 $           99.25    NGL ($/bbl) $           33.31 $          38.26 $           36.55 $           39.20 $           43.85    Natural Gas ($/mcf) $             2.50 $            0.81 $             1.59 $             1.83 $             1.54 Oil Price Benchmarks    West Texas Intermediate ("WTI") (US$/bbl) $           59.64 $          65.74 $           70.69 $           65.46 $           76.55    Edmonton Par ($/bbl) $           75.35 $          85.29 $           94.10 $           84.74 $           97.11    Edmonton Par to WTI differential (US$/bbl) $           (5.62) $          (3.82) $           (3.43) $           (4.68) $           (5.67) Natural Gas Price Benchmarks    AECO (5A - daily) gas ($/mcf) $             2.11 $            0.60 $            1.40 $             1.59 $             1.38 Foreign Exchange    Canadian Dollar/U.S. Exchange 0.72 0.73 0.71 0.72 0.73 Operations Summary Net petroleum and natural gas production, pricing and revenue are summarized below: 2025 2024 Year Ended Q4 Q3 Q4 2025 2024 Daily production volumes    Natural Gas (mcf/d) 32,189 33,435 35,733 34,791 37,308    Light Crude Oil (bbl/d) 1,807 1,641 2,070 1,824 2,150    NGL's (bbl/d) 2,404 2,340 2,182 2,379 2,131    Combined (BOE/d 6:1) 9,577 9,554 10,207 10,003 10,500 Revenue Petroleum & natural gas sales $         27,197 $        24,401 $         30,961 $       115,252 $       133,364 Realized gain (loss) on commodity contract settlement 519 1,452 (121) 1,078 (809) Total sales 27,716 25,853 30,840 116,330 132,555 Royalty expense (1,907) (1,116) (2,389) (7,133) (8,664) Total Revenue - Net of royalties $         25,809 $        24,737 $         28,451 $       109,197 $       123,891 Adjusted Net DebtSummary The following table summarizes the change in adjusted net debt for the years ended December 31, 2025 and 2024:  Year ended Year ended December 31, 2025 December 31, 2024 Adjusted net debt - beginning of period $               (103,147) $            (118,646)  Funds flow from operations $                  62,805 75,599  Additions to property and equipment $                 (57,947) (59,626)  Decommissioning costs incurred $                      (799) (527)  Additions to E&E Assets $                   (6,123) -  Issuance of shares $                       882 2,093  Lease obligation repayment  $                   (1,438) (1,106)  Other $                      (952) (934)  Adjusted net debt - end of period  $               (106,719) $            (103,147) Credit facility limit $                 140,000 $             130,000 Capital Spending Capital spending is summarized as follows: 2025 2024 Year Ended Cash additions Q4 Q3 Q4 2025 2024 Land, acquisitions and lease rentals $            (265) $             176 $              110 $              703 $             323 Drilling and completion 12,986 7,695 17,034 43,617 49,773 Geological and geophysical - - - 105 323 Equipment 3,104 1,480 2,494 12,700 8,051 Other asset additions 161 213 252 821 1,156 $         15,986 $        12,440 $         19,890 $         57,947 $         59,626 Exploration & evaluation assets $           3,247 $          2,876 $                  - $           6,123 $                  - Oil and Gas Reserves The following tables summarize certain information contained in the 2025 Reserve Report. The 2025 Reserve Report encompasses 100% of Yangarra's oil and gas properties and was prepared in accordance with definitions, standards and procedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 - Standards of Disclosure for Oil and Gas Activities ("NI 51-101") by Deloitte. Summary of Oil and Gas Reserves (1)(2) (Company Share Gross volumes based on forecast price and costs) Reserves Category Light and Medium Oil (Mbbl) Natural Gas Liquids (Mbbl) Conventional Gas   (MMcf) Shale  Gas   (MMcf) Total BOE 2025 (Mboe) Total BOE 2024 (Mboe) Proved Developed Producing 5,278 10,372 153,319 368 41,265 39,471 Proved Developed Non-Producing 61 133 1,989 0.0 525 360 Proved Undeveloped 7,853 8,852 132,518 0.0 38,791 44,399 Total Proved 13,192 19,357 287,826 368 80,581 84,229 Probable 7,063 8,885 132,455 90 38,039 48,435 Total Proved Plus Probable 20,255 28,242 420,281 458 118,620 132,664 Notes: (1) Total values may not add due to rounding. (2) BOEs are derived by converting gas to oil equivalent in the ratio of six thousand cubic feet of gas to one barrel of oil (6 Mcf:1 bbl). Summary of Net Present Values of Future Net Revenue (Before Tax) (1)(4) (Based on forecast price and costs) As At December 31, 2025(2) As At December 31, 2024 (3) Reserves Category 0.0% (M$) 5.0% (M$) 10.0% (M$) 15.0% (M$) 20.0% (M$) 10.0% (M$) Proved Developed Producing 920,360 608,203 454,244 365,096 307,490 500,859 Proved Developed Non-Producing 11,555 10,634 9,841 9,155 8,556 6,416 Proved Undeveloped 766,268 505,789 361,108 271,672 211,933 544,213 Total Proved 1,698,183 1,124,626 825,193 645,923 527,978 1,051,488 Probable 957,087 480,357 286,915 190,430 135,420 375,932 Total Proved Plus Probable 2,655,271 1,604,983 1,112,108 836,353 663,398 1,427,419 Notes: (1) Total values may not add due to rounding. (2) Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2025.  (3) Forecast pricing used is based on Deloitte published price forecasts effective December 31, 2024. (4) Cash flows are reduced for future abandonment costs and estimated capital for future development associated with the reserves.   Reserve Definitions: (a) "Proved" reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves. (b) "Probable" reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves. (c) "Developed" reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g. when compared to the cost of drilling a well) to put the reserves on production. (d) "Developed Producing" reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty. (e) "Developed Non-Producing" reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown. (f) "Undeveloped" reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable, possible) to which they are assigned. Reconciliations of Changes in Reserves The following table sets out a reconciliation of the changes in the Corporation's reserves as at December 31, 2025 against such reserves at December 31, 2024 based on forecast prices and cost assumptions: Light and Medium Oil Natural Gas Liquids Gross Proved Gross Probable Gross Proved Plus Probable Gross Proved Gross Probable Gross Proved Plus Probable (Mstb) (Mstb) (Mstb) (Mstb) (Mstb) (Mstb) Opening Balance 15,903 9,670 25,573 17,402 9,862 27,264 Production -627 0 -627 -940 0 -940 Technical Revisions -2505 -2798 -5,303 2,216 -1,128 1,088 Extensions 574 170 744 451 81 531 Acquisitions 24 9 33 341 50 390 Economic Factors -179 10 -169 -183 12 -171 Closing Balance 13,189 7,062 20,251 19,287 8,876 28,163 Conventional Gas Shale Gas Gross Proved Gross Probable Gross Proved Plus Probable Gross Proved Gross Probable Gross Proved Plus Probable (MMcf) (MMcf) (MMcf) (Mboe) (Mboe) (Mboe) Opening Balance 305,176 173,284 478,460 365 135 500 Production -13,512 0 13,512 -40 0 -40 Technical Revisions -11,120 -43,657 -54,777 45 -45 0 Extensions 6,664 1,289 7,953 0 0 0 Acquisitions 3,044 1,030 4,074 0 0 0 Economic Factors -3,319 239 -3,080 -2 0 -2 Closing Balance 286,933 132,186 419,119 368 90 458 MBOE Gross Proved Gross Probable Gross Proved Plus Probable (Mboe) (Mboe) (Mboe) Opening Balance 84,229 48,435 132,664 Production -3,826 0 678 Technical Revisions -2,135 -11,210 -13,345 Extensions 2,136 466 2,601 Acquisitions 872 231 1,102 Economic Factors -916 62 -854 Closing Balance 80,361 37,984 122,846 Forecast Prices Used in Estimates The forecast price and market forecasts prepared by Deloitte are based on information available from numerous government agencies, industry publication, oil refineries, natural gas marketers, and industry trends. The prices are Deloitte's best estimate of how the future will look, based on the many uncertainties that exist in both the domestic Canadian and international petroleum industries. Deloitte considers the current monthly trends, the actual and trends for the year to date, and the prior year actual in determining the forecast. The crude oil and natural gas forecasts are based on yearly variable factors weighted to higher percent in current data and reflecting a higher percent to the prior year historical. These forecasts are Deloitte's interpretation of current available information and while they are considered reasonable, changing market conditions or additional information may require alteration from the indicated effective date. Inflation forecasts and exchange rates, an integral part of the forecast, have also been considered. Price Inflation Rate Cost Inflation Rate Cdn to US Exchange Rate 2026 0.0 % 0.0 % 0.73 2027 2.0 % 2.0 % 0.75 2028 2.0 % 2.0 % 0.75 2029 2.0 % 2.0 % 0.75 2030 beyond 2.0 % 2.0 % 0.75 Oil, NGL, and natural gas base case prices, utilized by Deloitte in the Deloitte Reserve Report were as follows: Oil Natural Gas Natural Gas Liquids Year WTI Cushing (Oklahoma) Edmonton City Gate 40° API Alberta Reference – Gas Prices Alberta AECO – Gas Prices Pentanes + Condensate Edmonton Butanes Edmonton Propane Edmonton ($US/bbl) ($Cdn/bbl) ($Cdn/mcf) ($Cdn/mcf) ($Cdn/bbl) ($Cdn/bbl) ($Cdn/bbl) Forecast 2026 58.00 74.65 2.75 2.95 74.65 33.60 26.15 2027 61.20 76.50 3.35 3.55 76.50 34.45 26.80 2028 67.65 84.65 3.45 3.65 84.65 38.10 29.60 2029 69.00 86.35 3.50 3.70 86.35 38.85 30.20 2030 70.35 88.05 3.55 3.80 88.05 39.60 30.80 Escalation of 2.0% Thereafter Notes: - All prices are in Canadian dollars except WTI which are in U.S. dollars. - Edmonton City Gate prices based on light sweet crude posted at major Canadian refineries (40 Deg. API <0.5% Sulphur). - Natural Gas Liquid prices are forecasted at Edmonton therefore an additional transportation cost must be included to plant gate sales point. - 1 Mcf is equivalent to 1 mmbtu. - Alberta gas prices, except AECO, include an average cost of service to the plant gate. Finding and Development Costs Yangarra's F&D costs for 2025, 2024 are presented in the tables below. The costs used in the F&D calculation are the capital costs related to land acquisition and retention; drilling; completions; tangible well site; tie-ins; and facilities, plus the change in estimated future development costs as per the independent reserve report. Acquisition costs are net of any proceeds from dispositions of properties. Due to the timing of capital costs and the subjectivity in the estimation of future costs, the aggregate of the exploration and development costs incurred in the most recent financial year and the change during that year in estimated future development costs generally will not reflect total finding and development costs related to reserve additions for that year. The reserves used in this calculation are Company net reserve additions, including revisions. Proved Developed Producing Finding & Development Costs ($ millions) 2025 2024 Capital expenditures 65 60 Reserve additions, net production (Mboe) 5,430 5,285 Proved Developed Producing F&D costs – including future capital ($/boe) 11.95 11.28 Proved Recycle Ratio ($21.28/boe annual operating netback) 1.78 2.11 Proved Finding & Development Costs ($ millions) 2025 2024 Capital expenditures 65 60 Change in future capital (19) (91) Total capital for F&D 46 (31) Reserve additions, net production (Mboe) (12) (8,734) Proved F&D costs – including future capital ($/boe) N/A 3.54 Proved F&D costs – excluding future capital ($/boe) N/A N/A Proved Recycle Ratio    Including future capital N/A 6.74    Excluding future capital N/A N/A Proved plus Probable Finding & Development Costs ($ millions) 2025 2024 Capital expenditures 65 60 Change in future capital (34) (137) Total capital for F&D 31 (77) Reserve additions, net production (Mboe) (10,408) (19,197) Proved plus Probable F&D costs – including future capital ($/boe) N/A 4.04 Proved plus Probable F&D costs – excluding future capital ($/boe) N/A N/A Proved plus Probable Recycle Ratio    Including future capital N/A 5.91    Excluding future capital N/A N/A Annual General Meeting of Shareholders The Company's Annual General Meeting of Shareholders is scheduled for 10:00 AM on Friday May 1, 2026 in the Tillyard Management Conference Centre, Main Floor, 715 5th Avenue SW, Calgary, AB.  Year End Disclosure The Company's December 31, 2025 audited consolidated financial statements, management's discussion and analysis and annual information form have been filed on SEDAR+ (www.sedarplus.ca) and are available on the Company's website (www.yangarra.ca).  Oil and Gas Advisories Natural gas has been converted to a barrel of oil equivalent (boe) using 6,000 cubic feet (6 Mcf) of natural gas equal to one barrel of oil (6:1), unless otherwise stated. The boe conversion ratio of 6 Mcf to 1 Bbl is based on an energy equivalency conversion method and does not represent a value equivalency; therefore boes may be misleading if used in isolation. Figures that are presented on a boe basis herein are calculated as the total aggregate amount for the period divided by boe production volumes for the period. References to natural gas liquids ("NGLs") in this news release include condensate, propane, butane and ethane and one barrel of NGLs is considered to be equivalent to one barrel of crude oil equivalent (boe). One ("BCF") equals one billion cubic feet of natural gas. One ("Mmcf") equals one million cubic feet of natural gas. This press release contains metrics commonly used in the oil and natural gas industry which have been prepared by management, such as "operating netback" and "operating margins". These terms do not have a standardized meaning and may not be comparable to similar measures presented by other companies and, therefore, should not be used to make such comparisons. For additional information regarding netbacks and operating margins, see "Non-IFRS Financial Measures". Management uses these oil and gas metrics for its own performance measurements and to provide shareholders with measures to compare Yangarra's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from metrics presented in this press release, should not be relied upon for investment or other purposes. Non-IFRS Financial Measures This press release contains various specified financial measures that do not have standardized meanings as prescribed by International Financial Reporting Standards ("IFRS").  These reported amounts and their underlying calculations are not necessarily comparable or calculated in an identical manner to a similarly titled measure of other companies where similar terminology is used.  Readers are cautioned that such financial measures should not be construed as alternatives to or more meaningful than the most directly comparable IFRS measures as indicators of the Company's performance.  These measures have been described and presented in this press release in order to provide shareholders and potential investors with additional information regarding the Company's liquidity and its ability to generate funds to finance its operations and should not be considered in isolation. Please refer to the management discussion and analysis for the year ended December 31, 2025, for further discussion on the Non-IFRS financial measures presented in this press release. Funds flow from operations Funds flow from operations ("FFO") should not be considered an alternative to, or more meaningful than, cash provided by operating, investing and financing activities or net income as determined in accordance with IFRS, as an indicator of Yangarra's performance or liquidity. Management uses FFO to analyze operating performance and leverage and considers FFO to be a key measure as it demonstrates the Company's ability to generate cash flow necessary to fund future capital investments and to repay debt, if applicable. FFO is calculated using cash flow from operating activities before changes in non-cash working capital and decommissioning costs incurred. The following table reconciles FFO to cash flow from operating activities, which is the most directly comparable measure calculated in accordance with IFRS: 2025 2024 Year Ended Q4 Q3 Q4 2025 2024 Cash flow from operating activities $         11,204 $        14,254 $         15,293 $         59,078 $         71,037 Decommissioning costs incurred 442 357 - 799 527 Changes in non-cash working capital 2,477 (1,430) 917 2,928 4,035 Funds flow from operations $         14,123 $        13,181 $         16,210 $         62,805 $         75,599 Yangarra presents FFO per share whereby per share amounts are calculated using weighted average shares outstanding consistent with the calculation of net income per share.  Funds from operations netback is calculated on a per boe basis. Adjusted EBITDA Yangarra defines Adjusted EBITDA as earnings before interest, taxes, depletion and depreciation, which represents EBITDA, excluding changes in the fair value of commodity contracts. Management believes that Adjusted EBITDA is a useful measure, which provides an indication of the results generated by the Yangarra's primary business activities prior to consideration of how those activities are financed, amortized or taxed. The most directly comparable IFRS financial measure to Adjusted EBITDA is net income (loss). The following table provides a reconciliation of Adjusted EBITDA to net income (loss). 2025 2024 Year Ended Q4 Q3 Q4 2025 2024 Net income for the Period $             564 $          2,294 $           3,884 $         15,019 $         26,228 Finance 2,622 2,627 3,693 10,416 12,657 Deferred tax expense 2,540 1,049 (1,051) 7,851 6,360 Depletion and depreciation 10,268 8,756 9,243 38,012 35,512 Change in fair value of commodity contracts (786) (262) 2,577 (3,735) 2,122 Adjusted EBITDA $         15,208 $        14,464 $         18,346 $         67,563 $         82,879 Adjusted Net Debt Yangarra defines Adjusted net debt as the sum of our existing credit facilities, trade and other payables, and trade receivables and prepaids. Yangarra uses Adjusted net debt to assess efficiency, liquidity and the general financial strength of the Company. The most directly comparable IFRS financial measure to Adjusted net debt is Bank Debt. The following table provides a calculation of adjusted net debt.  Dec 31, 2025 Dec 31, 2024 Bank Debt $       127,666 $       115,785 Accounts receivable (31,748) (28,878) Prepaid expenses and inventory (9,425) (9,223) Accounts payable and accrued liabilities 20,226 25,463 Adjusted net Debt $       106,719 $       103,147 Adjusted net debt to fourth quarter annualized FFO Adjusted net debt to fourth quarter annualized FFO is a non-GAAP financial ratio calculated as adjusted net debt divided by fourth quarter annualized FFO.  Netbacks The Company considers corporate netbacks to be a key measure that demonstrates Yangarra's profitability relative to current commodity prices. Corporate netbacks are comprised of operating, field operating, FFO and net income (loss) netbacks.  Yangarra calculates Field Operating netback as the average sales price of its commodities (including realized gains (losses) on financial instruments) less royalties, operating costs and transportation expenses. Operating netback starts with Field Operating netback and subtracts realized gains (losses) on financial instruments. FFO netback starts with the Operating netback and further deducts general and administrative costs, finance expense and adds finance income. To calculate the net income (loss) netback, Yangarra takes the Operating netback and deducts share-based compensation expense as well as depletion and depreciation charges, accretion expense, unrealized gains (losses) on financial instruments, any impairment or exploration and evaluation expense and deferred income taxes. FFO margins and operating margins FFO margins and operating margins are calculated as the ratio of FFO netbacks to sales price and operating netback to sales price, respectively. Forward Looking Information This press release contains forward-looking statements and forward-looking information (collectively "forward-looking information") within the meaning of applicable securities laws relating to the Company's plans and other aspects of our anticipated future operations, management focus, strategies, financial, operating and production results and business opportunities. Forward-looking information typically uses words such as "anticipate", "believe", "continue", "sustain", "project", "expect", "forecast", "budget", "goal", "guidance", "plan", "objective", "strategy", "target", "intend" or similar words suggesting future outcomes, statements that actions, events or conditions "may", "would", "could" or "will" be taken or occur in the future, including, but not limited to, statements on potential completion techniques being considered. Statements relating to "reserves" are also deemed to be forward-looking statements, 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. The forward-looking information is based on certain key expectations and assumptions made by our management, including expectations and assumptions concerning prevailing commodity prices, exchange rates, interest rates, applicable royalty rates and tax laws; future production rates and estimates of operating costs; performance of existing and future wells; reserve volumes; anticipated timing and results of capital expenditures; the success obtained in drilling new wells; the sufficiency of budgeted capital expenditures in carrying out planned activities; benefits to shareholders of our programs and initiatives, the timing, location and extent of future drilling operations; the state of the economy and the exploration and production business; results of operations; performance; business prospects and opportunities; the availability and cost of financing, labour and services; the impact of increasing competition; ability to efficiently integrate assets and employees acquired through acquisitions, ability to market oil and natural gas successfully and our ability to access capital. Although we believe that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Yangarra can give no assurance that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature they involve inherent risks and uncertainties. Our actual results, performance or achievement could differ materially from those expressed in, or implied by, the forward-looking information and, accordingly, no assurance can be given that any of the events anticipated by the forward-looking information will transpire or occur, or if any of them do so, what benefits that we will derive therefrom. Management has included the above summary of assumptions and risks related to forward-looking information provided in this press release in order to provide security holders with a more complete perspective on our future operations and such information may not be appropriate for other purposes. Readers are cautioned that the foregoing lists of factors are not exhaustive. Additional information on these and other factors that could affect our operations or financial results are included in reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website (www.sedarplus.com). These forward-looking statements are made as of the date of this press release and we disclaim any intent or obligation to update publicly any forward-looking information, whether as a result of new information, future events or results or otherwise, other than as required by applicable securities laws. All reference to $ (funds) are in Canadian dollars. Neither the TSX nor its Regulation Service Provider (as that term is defined in the Policies of the TSX) accepts responsibility for the adequacy and accuracy of this release.   SOURCE Yangarra Resources Ltd. View original content: http://www.newswire.ca/en/releases/archive/March2026/05/c1579.html Contact: For further information, please contact James Evaskevich, President & CEO 403-262-9558.