Slides
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Obsidian Energy Ltd. Corporate Presentation February 2026
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OVERVIEW 2 Q4 2025 Production 27,971 boe/d Q4 2025 Annualized Funds Flow from Operations (FFO) $226 million Q4 2025 Annualized Net Debt to FFO 1.2x Shares Outstanding 67.3 million Market Capitalization $716 million Q4 2025 Net Debt $268 million Enterprise Value $984 million 2P Reserves 158 million boe 2P NPV10% at US$70/bbl WTI $2,088 million 2P Net Asset Value $26.69/sh Focused asset base with experienced team delivering value P E A C E R I V E R 13,741 boe/d Cold flow heavy oil V I K I N G 1,025 boe/d Light oil conventional development W I L L E S D E N G R E E N & P C U # 1 1 Q4 2025 27,971 boe/d 12,968 boe/d Light oil conventional development 2See endnotes and non-gaap measure advisory for additional information.
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High Quality Assets Extensive land base with multiple productive horizons in both our core regions of Peace River and Willesden Green Strong EOR potential to reduce sustaining capital and realize full value from life of assets Grow intrinsic value of business via land sales, farm-ins and targeted bolt-on transactions Operational Excellence Proven technical expertise and knowledge of subsurface assets drives new well designs and improved returns Safety-first culture with strong community engagement Shareholder Focused Focused on per share growth via production additions, share buybacks and debt reduction Return of capital via share repurchases OBSIDIAN ENERGY STRATEGY 3 Focus on superior execution to deliver results and create value for shareholders Unlock the potential of our heavy and light oil assets, maintain operational excellence, and execute on share repurchase program to drive top quartile total shareholder returns
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RETURNING CAPITAL TO SHAREHOLDERS 4 0 5 10 15 20 25 30 35 40 0 5 10 15 20 25 30 35 Q1 21 Q1 22 Q1 23 Q1 24 Q1 25 Production (boe) per share (000s) Production (Mboe/d) CORPORATE PRODUCTION (Excluding fields included in Pembina Disposition) Production excluding Disposition Production per Share Opportunistic share buyback program under NCIB enhances growth profile 8% total production CAGR since Q1 23 18% production per share CAGR since Q1 23 NCIB implemented Feb 2023 • Over 20% of shares repurchased/cancelled (~17.2 million shares) since the implementation of our NCIB program in February 2023 • Fully utilized current NCIB in August 2025, we are in the process of renewing our NCIB in March 2026 67% Utilized 61% Utilized 100% Utilized 0 2 4 6 8 Feb23-Feb24 Feb24-Feb25 Mar25-Mar26 Shares Cancelled (million) NCIB REPURCHASES See endnotes for additional information
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H1 Highlights • Peace River focused $169 million capital program, including ~$27 million for exploration/appraisal and waterflood projects • H1 capital program had 28 (26.4 net) wells rig released in Peace River and 9 (6.2 net) wells rig released in Pembina. This includes exploration/appraisal and waterflood projects • First Clearwater waterflood pilot with strong primary production results on the 3 (3.0 net) producing wells. Water injection initiated in August 2025 on two (2.0 net) injectors 2025 OPERATIONAL HIGHLIGHTS 5 Unlock future asset potential Successful year with expenditures balanced between Peace River and Willesden Green development H2 Highlights • Rig-released 19 (19.0 net) Clearwater development wells and two (2.0 net) Clearwater injector wells to expand our Dawson waterflood pilot. Rig-released 2 (2.0 net) Bluesky development wells • Brought on production 18 (18.0 net) Clearwater wells in Dawson and Peavine with encouraging rates, and 2 (2.0) Bluesky wells • Three (3.0 net) strong Belly River wells drilled, one delineating the Crimson area, and two in Open Creek. • Drilled and completed four (4.0 net) Cardium wells in Open Creek, which came on production in February 2026 • Completion of infrastructure projects in late 2025 to connect the under-exploited Open Creek field into our regional infrastructure system and constructed all-season access into our Nampa field
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Completed Pembina Disposition • Sold operated Pembina assets in April 2025 for proceeds of ~$325 million • In August 2025, sold all IPO shares received as part of consideration in disposition, additional $6 million of value • Reduced inactive and active ARO by 57% and 48%, respectively Refinanced Senior Notes • Closed $175 million senior note issuance at 8.125% due in 2030, significantly lower interest rate than previous notes at 11.95% • Used proceeds to fully repay previous notes and pay down outstanding amount on credit facility 2025 FINANCIAL HIGHLIGHTS 6 Buyback shares and maintain low leverage ratios Significant decrease in net debt in 2025 combined with active share buyback program Renewed Credit Facility • Extended $235 million credit facility into 2027, only $9 million drawn at December 31, 2025 Return of Capital to Shareholders • Fully utilized NCIB program as of August 31, 2025, purchased and cancelling ~7.6 million shares for $54.9 million in 2025 • Company in the process of renewing our NCIB in March 2026 Prepaid Equity Forward Program • In Q3/25, began prepaid equity forward program with total purchases of ~4.3 million shares up to February 18 See endnotes for additional information
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DELIVERING RESULTS 7 Strategy and execution create momentum for long-term value creation 2024 2025* WTI US$/bbl $75.72 $64.81 AECO $/GJ $1.36 $1.59 Production boe/d 37,474 30,624 Capital expenditures $ millions $343.1 $298.9 Decommissioning expenditures $ millions $23.9 $28.8 Net operating costs $/boe $13.85 $14.92 Netback $/boe $35.45 $28.13 General & administrative $/boe $1.50 $1.84 FFO $ millions $432.0 $272.1 FFO/share (basic) $ per share $5.69 $3.92 FCF $ millions $65.0 ($55.6) FCF/share (basic) $ per share $0.86 ($0.80) Net Debt $ millions $411.7 $268.2 Net Debt to FFO times 1.0 1.0 * Sold ~11,000 boe/d of production on April 7, 2025, in Pembina disposition * Sold ~11,000 boe/d of production on April 7, 2025, in Pembina Disposition See endnotes and non-gaap measure advisory for additional information 37 38 29 27 28 0 50 100 150 200 0 10 20 30 40 2024 Q1/25 Q2/25* Q3/25 Q4/25 Ann. Production (boe) per share (000s) Production (Mboe/d) CORPORATE PRODUCTION Production per Share $412 $460 $270 $219 $268 0.0 0.5 1.0 1.5 2.0 2.5 0 100 200 300 400 500 2024 Q1/25 Q2/25* Q3/25 Q4/25 Net Debt / FFO Net Debt ($ million) NET DEBT Net Debt/FFO
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2025 RESERVES HIGHLIGHTS 8 Reserves replacement ratios reflect development program success YEAR -END 2025 RESERVES SUMMARY Reserves are shown on a gross working interest basis; F&D and FD&A costs include changes in future development capital. See endnotes for additional information. 5th Consecutive Year of >100% reserve replacement (PDP,1P & 2P) ___________ 118% to 235% replacement of 2025 production ___________ 6.0 – 13.3 years reserve life index highlighting significant inventory ___________ $243 million average annual FDC over next 5 years Proved Developed Producing (PDP) Total Proved (1P) Total Proved Plus Probable (2P) Light and medium crude oil 12 MMbbl 26 MMbbl 35 MMbbl Heavy crude oil 17 MMbbl 29 MMbbl 54 MMbbl Natural gas liquids 5 MMbbl 13 MMbbl 18 MMbbl Conventional natural gas 120 Bcf 224 Bcf 307 Bcf Total reserves 54 MMboe 105 MMboe 158 MMboe Reserves life index 6.0 years 10.1 years 13.3 years Reserve replacement ratio 118% 185% 235% F&D costs $25.70 $19.44 $20.68 FD&A costs ($0.87) $11.71 $9.09 NPV10% (IC3 deck) $961 million $1,446 million $2,103 million NPV10% (US$60 WTI) $784 million $1,096 million $1,580 million NPV10% (US$70 WTI) $982 million $1,451 million $2,088 million NPV10% (US$80 WTI) $1,171 million $1,800 million $2,577 million
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RESERVES UNDERPIN OUR CURRENT AND FUTURE VALUE 9 Trading at substantial discount on booked reserves basis Focus on growing per share metrics to increase shareholder value $10.64 $8.06 $10.89 $13.59$12.52 $17.60 $22.59 $19.44 $26.69 $33.68 $0 $5 $10 $15 $20 $25 $30 $35 (C$ per share) P R O F O R M A N E T A S S E T V A L U E / S H A R E Current Share Price PDP 1P 2P US$80 WTIUS$60 WTI US$70 WTI See endnotes for additional information 209 108 53 48 318 108 160 50 357 130 180 47 - 50 100 150 200 250 300 350 400 450 Total Willesden Green/PCU #11 Peace River Viking B O O K E D R E S E R V E L O C A T I O N S (number, 2P, net) 2023 2024 2025
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2026 GUIDANCE 10 Advance delineation and development in both our heavy and light oil areas Disciplined approach to 2026 given commodity price volatility with optionality to expand capital program in a higher price environment Heavy Oil Light Oil Based on midpoint Average production boe/d 12,700 16,200 Capital expenditures1 $ millions 80 128 Net operating costs $/boe 20.20 10.05 Netback $/boe 19.00 30.45 Net operating income $ millions 88 180 Asset level FCF $ millions 8 52 2026E Average production boe/d 27,900 – 29,900 Capital expenditures $ millions 190 – 230 Decommissioning expenditures $ millions 7 – 11 Net operating costs $/boe 14.00 – 15.00 General & administrative $/boe 2.00 – 2.10 Based on midpoint of above guidance FFO $ millions 225 FFO per share (basic) $/share 3.35 FCF $ millions 7 FCF per share (basic) $/share 0.10 Net Debt $ millions 272 Net Debt to FFO times 1.2 Pricing assumptions WTI (January – June) US$/bbl 58.00 WTI (July – December) US$/bbl 62.00 Foreign exchange $CAD/$USD 1.38 MSW differential US$/bbl 3.50 WCS differential US$/bbl 13.50 AECO CAD$/GJ 2.75 Sensitivity Range Change in 2026E FFO ($millions) WTI +/- US$1.00/bbl 9.4 Foreign Exchange Rate +/-$0.01/CAD/USD 3.4 MSW differential +/- US$1.00/bbl 3.6 WCS differential +/- US$1.00/bbl 6.1 AECO +/- CAD$0.25/GJ 1.6 1. Excludes environmental and corporate capital at asset level See endnotes for additional information
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2026 CAPITAL PROGRAM 11 Balanced capital program while furthering our waterflood initiatives in Peace River Further delineation in Belly River, while strategically prioritizing Clearwater injectors in H1 and focusing on Bluesky development in H2 1. Including the last well of our 2025 program rig released on January 2, 2026 2. In addition, Obsidian Energy expects to participate in 10 (4.5 net) non-operated wells in 2026 Development Appraisal Injector 2026E Gross (Net) Wells DEVELOPMENT WELLS Heavy Oil Assets H1 Peace River (Bluesky) 1 (1.0) 1 (1.0) - 2 (2.0) H1 Peace River (Clearwater)1 8 (8.0) - 7 (7.0) 15 (15.0) H2 Peace River (Bluesky) 7 (7.0) - - 7 (7.0) H2 Peace River (Clearwater) - 1 (1.0) 1 (1.0) 2 (2.0) Light Oil Assets H1 Willesden Green (Belly River) 5 (5.0) - - 5 (5.0) H1 Willesden Green (Cardium) - - - - H2 Willesden Green (Belly River) 3 (3.0) - - 3 (3.0) H2 Willesden Green (Cardium) 4 (4.0) - - 4 (4.0) Total Operated Wells2 28 (28.0) 2 (2.0) 8 (8.0) 38 (38.0) P E A C E R I V E R W I L L E S D E N G R E E N V I K I N G
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Nampa Cadotte Walrus Seal Main Gift Lake Dawson Peavine West Dawson Peace River T77 R12 W5 HVS • Large, contiguous, long-term land base of >700 sections with Bluesky and Clearwater heavy oil rights • New development fields at Dawson (Clearwater) and Walrus (Bluesky) • Extensive owned infrastructure and multiple sales points • Dominant owned road network and gas infrastructure position with ~70% of available gas facilities • Growing inventory of booked and unrisked locations for future growth • Simultaneous drilling and equipping operations reduce production cycle times Ownership in high-quality Bluesky and Clearwater heavy oil resource provides upside for future growth PEACE RIVER ASSET 12 Highly economic plays with significant scale See endnotes for additional information; see ‘Well Economics’ for area economics <1.2 years Payout (2P) 180 2P locations (2025, net) 10.3 RLI (2P 2025, years) 99% WI (operated) 13,741 boe/d (Q4 2025 production) 25% decline rate (PDP, 3-year average)
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Willesden Green (Cardium/Belly River/Mannville) • A high-grade light oil field with proven Cardium and emerging Belly River success • Significant reserve-based inventory of compelling drilling opportunities across extensive operated land base • Large network of flexible, operated infrastructure provides capacity for development throughout the asset Pembina Cardium Unit #11 (Cardium, Non-operated) • Strong rates and production additions from development programs • Provides FCF and returns for reinvestment in operated properties Viking • Shallow, low-risk, highly economic resource play with high impact development programs • Drill ready inventory provides optionality for our portfolio LIGHT OIL ASSETS 13 Delivering highly economic returns with years of low-risk inventory 10,689 1,025 2,279 LIGHT OIL ASSETS PRODUCTION ( Q 4 2 0 2 5 , b o e / d ) Willesden Green Viking PCU#11 (non-operated) V i k i n g 130 net booked 2P WG/PCU#11 locations 47 net booked 2P Viking locations W i l l e s d e n G r e e n P C U # 1 1 T49 R4 W5 T31 R1 W4 See endnotes for additional information
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Cardium • Open Creek field has limited horizontal Cardium development to date • Capital efficiency increased by sharing pads and infrastructure with Belly River development Belly River • Development is rapidly evolving with widespread industry activity in area • Drilled the first Belly River well at Crimson, which was brought on production in Q4 2025 with strong results. Two additional wells drilled and brought on production at Open Creek in late 2025 • Continuing to focus on the Belly River in 2026, with 8 (8.0) wells planned Infrastructure • Completed project to expand and integrate Open Creek field in late 2025, in service early 2026. New pipeline and facilities will support concurrent and efficient development of Belly River and Cardium WILLESDEN GREEN ASSET 14 Drilling underexploited Cardium at Open Creek and Belly River across the region See endnotes for additional information; see ‘Well Economics’ for area economics Existing Cardium Existing Belly River Proposed H2/25 OBE Open Creek Q4 2025 OBE Belly River Q4 2025 OBE Cardium Q4 2025 OBE Mannville OBE 15-06 Belly River Existing Gas Plant Crimson <0.9 years Payout (2P) 105 2P locations (2025, net) 16.0 RLI (2P 2024, years) INF Project T45 R6 W5 85% WI (operated) 10,689 boe/d (Q4 2025 production) 15% decline rate (PDP, 3-year average) OBE 12-21 Belly River
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13,298 12,800 8,000 2,000 U$62.47 U$64.13 U$64.29 U$63.700 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 Feb-26 Mar-26 Apr-26 May-26 Oil Swaps HEDGING PROGRAM 15 Risk management program to preserve cash flow F X F O R WA R D CO N T R AC T S ( U S D / C A D ) • February 2026 - $19.0M CAD @ $1.3719 • March 2026 - $16.0M CAD @ $1.3686 • April 2026 - $13.5M CAD @ $1.3650 W T I O I L H E D G E S (US$/bbl, bbl/d) 50% hedge level 26,540 35,377 1,896 $3.30 $2.68 $3.73 0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 2025 - 2026 Winter 2026 Summer 2026 - 2027 Winter Gas Swaps A E CO G A S H E D G E S ($/mcf, mcf/d) P R E PA I D E Q U I T Y F O R WA R D CO N T R AC T S • September 2028 – 720,000 @ $8.89 • October 2028 – 1,300,000 @ $8.72 • November 2028 – 550,000 @ $8.43 • December 2028 – 715,000 @ 8.31 • January 2029 – 450,000 @ $8.76 • February 2029 – 555,000 @ $10.10 Disciplined approach to risk management to protect cash flows for capital investment, debt repayment and return of capital 50% hedge level
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WHY INVEST IN OBSIDIAN ENERGY 16 • Strategy directed to unlocking asset potential to drive future production and funds flow per share growth while continuing to return capital to shareholders • Low decline, oil-weighted asset base with significant underlying reserves • Trades at a significant discount in both reserve values and cash flow multiples compared to peers • Substantial share buyback program through the NCIB • Purchased and cancelled >20% of shares outstanding since inception of the NCIB to August 31, 2025 (~17.2 million shares for $143.9 million) • Significant tax pools allow for Obsidian Energy to be a non-cash taxpayer for ~10 years at US$70.00/bbl WTI • Dedicated to making a positive difference to stakeholders and communities where we live and work Peace River growth combined with established light oil assets offers shareholder upside Unlocking asset potential while maintaining operational excellence and returning capital to shareholders FOCUSED STRATEGY SUBSTANTIAL RESERVES & RESULTS DIFFERENTIATED VALUE PROPOSITION RETURNING SHAREHOLDER CAPITAL SIGNIFICANT TAX POOLS STAKEHOLDER FOCUSED OPERATOR See endnotes for additional information
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Appendix 17
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STRATEGIC PEMBINA DISPOSITION 18 • Sold operated Pembina assets in April 2025 for proceeds of $326 million including the monetization of the InPlay share position in August 2025 Sales Metrics • ~10,300 boe/d production (2024 average production) • Received ~$31,600 boe/d on production value and 3.1x 2024 net operating income (prior to adjustments) Pro Forma Reduction of ARO (Q1/25) Rationalizes portfolio at a value accretive to our shareholders Obsidian Energy emerged as a significantly more focused Company with an ability to accelerate the shareholder value creation strategy See endnotes for additional information $415 million $214 million $332 million $143 million $747 million $357 million 52% less ARO Inactive ARO Active ARO T52 R4 W5 PCU #11 Willesden Green Pembina (Disposition)
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T48 R9 W5 • Large non-operated unit with 45% working interest, 35 gross sections • Historically underdeveloped area in the heart of the Pembina Cardium region with multi-year development agreement in place • Proven asset performance with repeatable development potential • Approximately 5x growth since 2022 PEMBINA CARDIUM UNIT #11 ASSET 19 Non-Operated unit with years of low-risk inventory See endnotes for additional information; see ‘Well Economics’ for area economics 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 Jan-22 Jul-22 Jan-23 Jul-23 Jan-24 Jul-24 Jan-25 Gross Production (boe/d) GROSS PCU#11 PRODUCTION 45% WI (non-operated) 2,279 boe/d (Q4 2025 production 21% decline rate (PDP, 3-year average) See endnotes for additional information; see ‘Well Economics’ in Appendix for area economics <1.3 years Payout (2P) 24 2P locations (2025, net) 13.6 RLI (2P 2025, years)
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VIKING ASSET 20 History of unlocking reserves and production value • Sweet, light oil development play with associated natural gas • Significant drilling inventory, including both low risk infill and de-risked step- out development • Superior netbacks due to lower well costs, combined with owned and controlled infrastructure and direct market access • Shallow, low geological risk resource play • 2022/23: Material discovery/results outperform area average Stable returns with development upside Revitalized light oil asset that provides high IP rates, highly economic return and quick payouts 0 50 100 150 1 2 3 4 5 6 7 8 9 10 11 12 OBE PROGRAMS VS AREA AVERAGE (boe/d) AVG (N=245) AVG OBE 2023 (N=19) **Area defined as TWP 30-33, RGE 01-06W4 See endnotes for additional information; see ‘Well Economics’ in Appendix for area economics 86% WI (operated) 1,025 boe/d (Q4 2025 production 16% decline rate (PDP, 3-year average) T31 R6 W4 <1.0 years Payout (2P) 47 2P locations (2025, net) 24.0 RLI (2P 2025, years)
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$1.2 billion $0.1 billion $0.5 billion $0.4 billion TAX POOL COMPOSITION Non-Capital Losses CEE & SR&ED CDE Other Pools (Q4 2025) CONSIDERABLE FUTURE VALUE FROM TAX POOLS 21 $2.2 billion of tax pools in unrecognized value to be leveraged with future growth $1.2 billion of tax pools immediately deductible $2.2 billion of tax pools Amount of Pools Utilized by Year1 Illustrative Value of Tax Pools @ 8% Discount Rate2 $200 million $330 million $4.59/share $300 million $374 million $5.21/share $400 million $399 million $5.56/share $500 million $415 million $5.78/share 1. Refers to an illustrative amount of pools used annually, assuming deductions available, until fully exhausted 2. Tax pool value based on tax rate of 23% (tax pools estimated as at December 31, 2025). Value presented per Obsidian Energy share, using fully diluted shares outstanding as of December 31, 2025 Maximum Theoretical Value1 Total $457 million $6.37/share Immediately deductible $229 million $3.88/share 1. Maximum theoretical value is calculated based on average 2025 tax rate of 23%, applied to Obsidian Energy’s estimated Q4 2025 and immediately deductible tax pools, and using fully diluted shares outstanding as of December 31, 2025
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WELL ECONOMICS 22 HALF CYCLE RESERVE TYPE CURVE ECONOMICS1,2 PEACE RIVER WILLESDEN GREEN VIKING Formation Bluesky3 Clearwater Cardium4 Belly River W. Viking (Esther)5 Well Length 10 legs 8 legs 1.8 mile 2.1 mile 1.8 mile DCET Capex $3.0 million $2.3 million $4.7 million $4.6 million $2.1 million EUR 250 Mboe 189 Mboe 328 Mboe 369 Mboe 120 Mboe Total IP365 182 boe/d 160 boe/d 243 boe/d 285 boe/d 111 boe/d NPV Btax 10% $3.2 million $3.5 million $4.4 million $6.6 million $2.2 million IRR 78% 160% 95% 149% 98% Payout 1.2 years 0.7 years 0.9 years 0.7 years 0.9 years F&D $11.11/boe $12.22/boe $14.22/boe $12.58/boe $17.49/boe Capital efficiency (12-month) $16,681 boe/d $14,452 boe/d $19,171 boe/d $16,246 boe/d $18,983 boe/d 1. Price assumptions: US$70/bbl WTI, US$13.50/bbl WCS, US$3.50/bbl MSW,$2.75/GJ AECO and FX of $1.38 CAD/USD 2. Type curves are derived using two years (or remaining inventory) of type well and input parameters provided by our Independent, Qualified Reserve Evaluator, attributable to the Company’s reserves effective as at December 31, 2025 3. Bluesky type curve economics are based on internal estimates for the Harmon Valley South Field 4. Willesden Green Cardium curve excludes gas wells 5. West Viking defined as OBE operated wells in 32-03 with IRR>25%
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EXPERIENCED TEAM WITH STRONG TECHNICAL SKILLS 23 MANAGEMENT TEAM Stephen E. Loukas President and Chief Executive Officer Peter D. Scott Senior Vice President, Chief Financial Officer Gary Sykes Senior Vice President, Commercial and Development Mark Hawkins Vice President, Legal, General Counsel and Corporate Secretary Cliff Swadling Vice President, Operations Jay McGilvary Vice President, Development Working together as a top tier developer that provides solid returns to stakeholders FINANCIAL AND COMMERCIAL Strong financial, commercial and capital markets experience leading the Company DRILLING, COMPLETIONS AND SUBSURFACE TECHNICAL Strong understanding of geological subsurface, reservoir modelling, advanced design, multi-stage fractured horizontal wells, multi-leg heavy oil wells OPERATIONS Expertise in facility design and construction, automation, production management, field operations, and asset retirement, with a strong focus on safety performance EMPLOYEES Staff & contractors with deep experience in their professions, representing the top tier expertise
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ADVISORY 24 This presentation should be read in conjunction with the Company’s audited consolidated financial statements and MD&A as at and for the year ended December 31, 2025. All dollar amounts contained in this presentation are expressed in millions of Canadian dollars unless otherwise indicated. Certain financial measures included in this presentation do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered Non-GAAP measures, Non-GAAP ratios or supplementary financial measures; accordingly, they may not be comparable to similar measures provided by other issuers. This presentation also contains oil and gas disclosures, various industry terms, and forward-looking statements, including various assumptions on which such forward-looking statements are based and related risk factors. Please see the Company’s disclosures located in the Endnotes at the end of this presentation for further details regarding these and other matters. All slides in this presentation should be read in conjunction with “Definitions and Industry Terms”, “Non-GAAP Measures Advisory”, “Oil and Gas Information Advisory”, “2025 Reserves Disclosure and Definitions” and “Forward-Looking Information Advisory”. All drilling locations are considered to be unbooked unless otherwise noted. Please be advised that the archived releases contained in this presentation are for historical information and reference purposes only. While information contained within the releases was believed to be accurate at the time of issue, this information does not constitute an active representation of Obsidian Energy, and the Company fully disclaims any liability for the use of such information and undertakes no obligation to update such information except as required by applicable law.
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Endnotes
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ENDNOTES 26 Slide 2: Overview Market capitalization determined with share price on the close of business on February 18, 2026, on the TSX ($10.64 per share) and common shares outstanding at December 31, 2025. Enterprise value calculated by adding net debt as at December 31, 2025, to market capitalization. Reserves (2P) are based on 2P reserve numbers as disclosed in our news release dated February 5, 2026, titled “Obsidian Energy Announces Strong 2025 Reserves Results”. Map volumes do not include additional legacy wells outside these core areas (237 boe/d). Slide 4: Returning Capital to Shareholders Percentage of shares purchased and cancelled through the share buyback program calculated based on shares outstanding at December 31, 2022. Slide 6: 2025 Financial Highlights The percent reductions on ARO related to the Pembina disposition was calculated on an uninflated, undiscounted basis. Slide 7: Delivering Results Production per share data based on average boe/d and basic shares for the year, as applicable. Slide 8: 2025 Reserve Highlights Reserves evaluation excludes inactive ARO. Our YE2025 reserves evaluation conforms to the requirements of National Instrument 51-101 and uses definitions and guidelines contained in the COGE Handbook. Obsidian Energy abandonment and reclamation costs associated with active wells, facilities, and pipelines have been included in the Reserves Report as part of future net revenue calculations. The price assumptions in our YE2025 reserves evaluation were based on an average of three independent reserve evaluators’ forecasts (GLJ Ltd., Sproule ERCE. and McDaniel & Associates Consultants). F&D and FD&A costs are non-GAAP measures. See ‘Non-GAAP Measures Advisory’ and ‘2025 Reserves Disclosure and Definitions’ for further details. Reserve replacement ratios are based on proforma production (excluding dispositions) and are used in the calculation of greater than 100% reserve replacement for our “5th consecutive year”. See ‘2025 Reserves Disclosure and Definitions’ for further details. Additional reserve information is available in Appendix A-3 of our Annual Information Form for the year ended December 31, 2025, available at www.obsidianenergy.com. Slide 9: Reserves Underpin our Current and Future Value Reserves evaluation excludes inactive ARO. Our YE2025 reserves evaluation conforms to the requirements of National Instrument 51-101 and uses definitions and guidelines contained in the COGE Handbook. Obsidian Energy abandonment and reclamation costs associated with active wells, facilities, and pipelines have been included in the Reserves Report as part of future net revenue calculations. The price assumptions in our YE2025 reserves evaluation were based on an average of three independent reserve evaluators’ forecasts (GLJ Ltd., Sproule ERCE and McDaniel & Associates Consultants). Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. See ‘2025 Reserves Disclosure and Definitions’ for further details. NAV/share based on YE 2025 reserves run at flat pricing and assumes $268 million Net Debt as at December 31, 2025. Shares outstanding calculated using common shares outstanding as of December 31, 2025, and includes RSUs and exercisable options as at December 31, 2025. Share price depicted is at the close of business on February 18, 2026. See ‘2025 Reserves Disclosure and Definitions’ for further details. Additional reserve information is available in Appendix A-3 of our Annual Information Form for the year ended December 31, 2025, available at www.obsidianenergy.com. Slide 10: 2026 Guidance Further details of production guidance ranges, by product type, are as follows: Asset level capital does not include $1 million in corporate capital. 2026E pricing assumptions include risk management (hedging) adjustments as of January 14, 2026. WTI assumption for H1 2026 (Jan – June) is US$58.00/bbl and H2 2026 (July – December) is US$62.00/bbl. 2026E per share calculations are based on an estimated 67.2 million weighted average shares outstanding, for the year ended December 31, 2026. 2026E Net Debt figures are estimated at December 31, 2026. Slide 12: Peace River Asset Obsidian Energy’s working interest is based on the Company’s PDP reserves. Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. No locations have been assigned to land where Obsidian Energy is not the operator. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Light Oil (bbl/d) Heavy Oil (bbl/d) NGL (bbl/d) Natural Gas (mmcf/d) Total (boe/d 2026E 7,300 11,800 2,000 46.8 28,900
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ENDNOTES, CONT. 27 Slide 13: Light Oil Assets Booked locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Slide 14: Willesden Green Asset Obsidian Energy’s working interest is based on the Company’s PDP reserves. Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Slide 15: Hedging Program In accordance with policies approved by our Board of Directors, the Company may, from time to time, manage commodity price risks through the use of swaps or other financial instruments up to a maximum of 50% of forecast sales volumes, net of royalties, for the balance of any current year plus one additional year forward and up to a maximum of 25%, net of royalties, for one additional year thereafter. The Board of Directors approved the following changes to our hedging policy on a rolling 15-month period: - Allow for hedges up to 50% of net oil production on a rolling 15-month period (up to 80% in near three months); - Allow for hedges up to 80% of net gas production on a rolling basis for the current and next gas season (i.e. current summer plus next winter season); - Allow for hedges on liquid volumes (i.e. oil and natural gas liquids) in Canadian dollars on 80% of the associated direct United States foreign exchange revenue exposure, net of royalties, on a rolling 12-month basis; and 50% on a rolling 13 – 18-month basis. Summer gas season is from April to October, Winter gas season is from November to March. Slide 16: Why Invest in Obsidian Energy Percentage of shares purchased and cancelled through the share buyback program calculated based on shares outstanding at December 31, 2022. Slide 18: Strategic Pembina Asset Disposition Pembina production of 10,300 boe/d based on actual production for 2024 broken down as follows: Light Oil – 5,902 bbl/d, Heavy Oil – 61 bbl/d, NGL – 900 bbl/d, Gas – 20.8 mmcf/d 2024 net operating income calculation reduced for annual decommissioning expenditures. Slide 19: Pembina Cardium Unit #11 Asset Obsidian Energy’s working interest is based on the Company’s PDP reserves. Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Slide 20: Viking Asset Obsidian Energy’s working interest is based on the Company’s PDP reserves. Booked reserve locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Decline rates are based on PDP reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. RLI is based on 2P reserve numbers as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. Payout calculated based on well economics and our internal assessment, which are subject to change without notice. Average Viking well based on data pulled from GeoScout for Viking Sandstone horizontal wells in Township 30-33, Range 1-6W4. Normalized to daily oil rate and condensed to exclude months with zero production.
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NPV or NPV Btax 10% means net present value, before tax discounted at 10% NYSE American means the New York Stock Exchange, American Payout means the time it takes to cover the return of the initial cash outlay PCU#11 means the non-operated Pembina Cardium Unit #11 Pembina Disposition refers to the Pembina Asset Disposition or Transaction, referring to disposition of the Company’s operated Pembina assets for $211 million in cash (after interim closing adjustments), 9.1 million in InPlay shares (post InPlay’s 6:1 share consolidation) and the $15 million estimated value for InPlay’s 34.6% interest in the WGCU#2 Reserves references are based on the report prepared by GLJ Ltd. dated January 23, 2026, (the “Reserves Report”) attributable to the Company’s reserves effective as at December 31, 2025. For additional reserve definitions, see the Release RLI means Reserve Life Index Rig Release refers to the date when drilling is finished at a wellsite and the drilling rig is ‘released’ to go to another site SR&ED is the Scientific Research & Experimental Development program, a government incentive tax credit TSX means the Toronto Stock Exchange Total IP365 means total barrels of oil equivalent produced over the first 365 days of well production, excluding any required cleanup time US or USD means United States Dollar WCS means Western Canadian Select WG means Willesden Green WI means working interest WTI means West Texas Intermediate YE means year-end YoY means year-over-year DEFINITIONS AND INDUSTRY TERMS 28 2026E means the guidance for 2026 for the full year, based on internal assumptions and estimates PDP means proved developed producing reserves as per Oil and Gas Disclosures Advisory 1P means proved reserves as per Oil and Gas Disclosures Advisory 2P means proved plus probable reserves as per Oil and Gas Disclosures Advisory AECO means Alberta benchmark price for natural gas ARO means Asset Retirement Obligation bbl and bbl/d means barrels of oil and barrels of oil per day, respectively BCF means billion cubic feet of natural gas boe and boe/d means barrels of oil equivalent and barrels of oil equivalent per day, respectively CAD means Canadian Dollar CAGR means compound annual growth rate CAPEX means capital expenditures Capital Efficiency is a metric that approximates cash flow generated for each investment dollar, and measures the ratio of how much a company spends growing revenue and how much they get in return CDE means Canadian development expense CEE means Canadian exploration expenses COGE Handbook stands for the Canadian Oil and Gas Evaluation Company, Obsidian Energy or OBE means Obsidian Energy Ltd.; as applicable DCET stands for Drilling, Case, Equip and Tie-in capital, and represents all necessary capital to drill and produce a well into the existing field infrastructure. Value does not include additional field infrastructure or lease construction and acquisition costs Debt is bank debt and senior notes Decommissioning means decommissioning expenditures EOR stands for enhanced oi recovery EUR means expected ultimate recovery, which is the total economic recoverable hydrocarbon F&D means finding and development cost, and refers to costs incurred when a company purchases, researches and develops properties to establish reserves FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates G&A means general and administrative costs GJ means gigajoule H1 means the first half of the year H2 means the second half of the year HVS means Harmon Valley South in Peace River Independent, Qualified Reserve Evaluator refers to GLJ Ltd. IP rates means initial production rates for a well InPlay stands for InPlay Oil Corp. IRR stands for Internal Rate of Return Legacy refers to a collection of all OBE properties outside of our core development areas of Cardium (Central), Peace River, and Viking Liquids means crude oil and NGLs m means metres Mboe means thousand barrels of oil equivalent MMbbl means million barrels of oil MMboe means million barrels of oil equivalent Mcf and mcf/d means thousand cubic feet and thousand cubic feet per day, respectively Mmcf and mmcf/d means million cubic feet and million cubic feet per day, respectively MSW means Mixed Sweet Blend crude oil NCIB means normal course issuer bid
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NON-GAAP MEASURES ADVISORY 29 Asset level FCF is based on net operating income less capital expenditures for the area. Enterprise Value or EV is a measure of total value of the company calculated by aggregating the market value of its common shares at a specific date (share price multiplied by shares outstanding), adding its Net Debt. Free Cash Flow (FCF) is FFO less capital and decommissioning expenditures. Funds Flow from Operations (FFO) is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures, equity forward contracts, onerous office lease settlements, the effects of financing related transactions from foreign exchange contracts and debt repayments, restructuring charges, transaction costs and certain other expenses and is representative of cash related to continuing operations. FFO is used to assess the combined entity’s ability to fund planned capital programs. Netback is production revenues plus sales of commodities purchased from third parties less commodities purchased from third parties (sales), less royalties, net operating costs, transportation expenses and realized risk management gains and losses on commodity contracts, and is used in capital allocation decisions and to economically rank projects. Notice to Shareholders in the United States The financial information presented herein has been prepared in accordance with Canadian GAAP and is subject to Canadian auditing and auditor independence standards, and thus may not be comparable to financial statements of U.S. companies presented in accordance with U.S. GAAP . Throughout this presentation and in other materials disclosed by the Company, we employ certain measures to analyze financial performance, financial position and cash flow. These non-GAAP and other financial measures do not have any standardized meaning prescribed by IFRS and therefore may not be comparable to similar measures provided by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income and cash flow from operating activities as indicators of our performance. The Company’s audited consolidated financial statements and notes and management’s discussion and analysis (“MD&A”) as at and for the year ended December 31, 2025, are available on the Company’s website at www.obsidianenergy.com and under our SEDAR+ profile at www.sedarplus.ca. The disclosure under the section “Non-GAAP and Other Financial Measures” in the MD&A is incorporated by reference into this presentation. Non-GAAP Financial Measures The following measures are non-GAAP financial measures: FCF, FFO, Net Debt; netback, net operating costs and net operating income. These non-GAAP financial measures are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. Non-GAAP Ratios The following measures are non-GAAP ratios: FCF per share which uses FCF as a component; Asset level FCF which uses net operating income as a component; FFO per share which uses FFO as a component; Enterprise Value which uses Net Debt as a component; net operating costs per boe, which uses net operating costs as a component; Net Debt to FFO which uses both Net Debt and FFO as components; . These non-GAAP ratios are not standardized financial measures under IFRS and might not be comparable to similar financial measures disclosed by other issuers. Supplementary Financial Measures G&A per boe uses G&A per boe on a net basis. Net Debt is the amount of long-term debt, comprised of senior notes, term loan and drawings under our syndicated credit facility, plus net working capital (surplus)/deficit. Net Debt is a measure of leverage and liquidity. Net Debt to Funds Flow from Operations is Net Debt divided by funds flow from operations. Net operating costs are calculated by deducting processing income, road use recoveries and realized gains and losses on power risk management hedges from operating costs and is used to assess the Company’s cost position. Processing fees are primarily generated by processing third party volumes at the Company’s facilities. In situations where the Company has excess capacity at a facility, it may agree with third parties to process their volumes to reduce the cost of operating/owning the facility. Road use recoveries are a cost recovery for the Company as we operate and maintain roads that are also used by third parties. Realized gains and losses on power risk management contracts occur upon settlement of our contracts. Net operating income is the absolute value of production revenues plus sales of commodities purchased from third parties less commodities purchased from third parties (sales), less royalties, net operating costs and transportation expenses and is used to determine the profitability of our assets. See the disclosure under the section “Non-GAAP and Other Financial Measures” in our corresponding MD&As for further information.
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OIL AND GAS INFORMATION ADVISORY 30 Barrels of oil equivalent (“boe”) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet of natural gas to one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is misleading as an indication of value. Drilling Locations This presentation discloses drilling locations or inventory in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Reserves Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked drilling locations are internal estimates based on our prospective acreage and an assumption as to the number of wells that can be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of our multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that we will drill all unbooked locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which we actually drill wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results, additional reservoir information that is obtained and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells where management has less information about the characteristics of the reservoir and therefore there is more uncertainty whether wells will be drilled in such locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves or production. Test Results and Initial Production Rates Readers are cautioned that initial production rates and/or production test results disclosed herein, particularly those short in duration, may not necessarily be indicative of long-term performance or of ultimate recovery and therefore should not be relied upon for investment or other purposes. A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered preliminary until such analysis or interpretation has been completed.
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2025 RESERVES DISCLOSURE AND DEFINITIONS 31 Unless otherwise noted, any reference to 2025 reserves in this presentation are based on the report (the “Reserves Report”) prepared by GLJ Ltd. dated January 23, 2026, where they evaluated one hundred percent of the crude oil, natural gas and natural gas liquids reserves of Obsidian Energy and the net present value of future net revenue attributable to those reserves effective as at December 31, 2025. For further information regarding the Reserves Report, see our press release dated February 5, 2026. It should not be assumed that the estimates of future net revenues presented herein represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained, and variances could be material. The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all properties, due to the effects of aggregation. Production and Reserves The use of the word “gross” in this presentation (i) in relation to our interest in production and reserves, means our working interest (operating or non-operating) share before deduction of royalties and without including our royalty interests, (ii) in relation to wells, means the total number of wells in which we have an interest, and (iii) in relation to properties, means the total area of properties in which we have an interest. The use of the word “net” in this presentation (i) in relation to our interest in production and reserves, means our working interest (operating or non-operating) share after deduction of royalty obligations, plus our royalty interests, (ii) in relation to our interest in wells, means the number of wells obtained by aggregating our working interest in each of our gross wells, and (iii) in relation to our interest in a property, means the total area in which we have an interest multiplied by the working interest owned by us. Unless otherwise stated, production volumes and reserves estimates in this presentation are stated on a gross basis. All references to well counts are net to the Company, unless otherwise indicated. Reserve Definitions Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates. • 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. • 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. Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories: 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing. 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. 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. 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 category (proved, probable) to which they are assigned. Finding and development (F&D) costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category, all divided by the change in reserves during the period. F&D costs exclude the impact of acquisitions and divestitures. FD&A costs are the sum of capital expenditures incurred in the period, plus the change in estimated future development capital for the reserves category and including the impact of acquisition and disposition activity, all divided by the change in reserves during the period for the reserve category. Recycle ratio is calculated by dividing the operating netback by the F&D costs for the year. The recycle ratio compares netback from existing reserves to the cost of finding new reserves and may not accurately indicate the investment success unless the replacement reserves are of equivalent quality as the produced reserves. RLI or Reserve Life Index is calculated as total Company gross reserves divided by GLJ’s forecasted 2025 production for the associated reserve category. For additional reserve definitions, see our press release dated February 5, 2026 “Obsidian Energy Announces Strong 2025 Reserve Results”.
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FORWARD-LOOKING INFORMATION ADVISORY 32 Certain statements contained in this document constitute forward-looking statements or information (collectively “forward-looking statements”) within the meaning of the "safe harbour" provisions of applicable securities legislation. Forward-looking statements are typically identified by words such as “anticipate”, “continue”, “estimate”, “expect”, “forecast”, “budget”, “may”, “will”, “project”, “could”, “plan”, “intend”, “should”, “believe”, “outlook”, “objective”, “aim”, “potential”, “target” and similar words suggesting future events or future performance. In addition, statements relating to “reserves” or “resources” are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this document contains forward-looking statements pertaining to, without limitation, the following: how we plan to deliver results and create value for shareholders; that we plan to renew the NCIB in March 2026 and expectations for the program; our expected decline rates, undeveloped 2P reserves locations, RLI, payout timelines and FDC; our corporate guidance for production, capital and decommissioning expenditures, net operating costs, G&A costs, FFO, FFO/share, FCF, FCF/share, net debt and net debt to annualized FFO; our updated asset level guidance for production, capital, net operating costs, netback, net operating income, and asset level FCF; our guidance sensitivities; the reasons to invest in Obsidian Energy; and our anticipated tax pools and savings therefrom; our development and operational programs; how our infrastructure creates optionality in our portfolio; our hedges and strategies for risk management; the reasons to invest in Obsidian Energy; and our anticipated tax pools and savings therefrom. Certain of the foregoing information set forth in this presentation may be considered to be future-oriented financial information (“FOFI”) or a financial outlook for the purposes of applicable Canadian securities laws. This FOFI is related to the Company's prospective results of operations, operating costs and expenditures, capital expenditures, production, general & administrative, decommissioning expenditures; FFO, FFO per share, FCF, FCF per share, asset level FCF, net debt and net debt to FFO ratio, which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth below. The Company's actual results, performance or achievement could differ materially from those expressed in, or implied by, such FOFI, or if any of them do so, what benefits the Company will derive therefrom. The Company has included this FOFI to provide readers with a more complete perspective on the Company's business as of the date hereof and such information may not be appropriate for other purposes. To the extent that such estimates constitute FOFI or a financial outlook, they were approved by management of the Company on the date hereof and are included to provide readers with an understanding of the Company's anticipated plans and financial results based on the capital expenditures and other assumptions described and readers are cautioned that the information may not be appropriate for other purposes. With respect to forward-looking statements contained in this document, the Company has made assumptions regarding, among other things: the duration and impact of tariffs that are currently in effect on goods exported from or imported into Canada, and that other than the tariffs that are currently in effect, neither the U.S. nor Canada (i) increases the rate or scope of such tariffs, reenacts tariffs that are currently suspended, or imposes new tariffs, on the import of goods from one country to the other, including on oil and natural gas, and/or (ii) imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas; that the Company does not dispose of or acquire material producing properties or royalties or other interests therein (except as disclosed herein); that regional and/or global health related events will not have any adverse impact on energy demand and commodity prices in the future; global energy policies going forward, including the continued ability and willingness of members of OPEC and other nations to agree on and adhere to production quotas from time to time; our ability to execute our plans as described herein and in our other disclosure documents, and the impact that the successful execution of such plans will have on our Company and our stakeholders, including our ability to return capital to shareholders and/or further reduce debt levels; future capital expenditure and decommissioning expenditure levels; expectations and assumptions concerning applicable laws and regulations, including with respect to environmental, safety and tax matters; future operating costs and G&A costs and the impact of inflation thereon; future oil, natural gas liquids and natural gas prices and differentials between light, medium and heavy oil prices and Canadian, WTI and world oil and natural gas prices; future hedging activities; future oil, natural gas liquids and natural gas production levels; future exchange rates, interest rates and inflation rates; future debt levels; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including extreme weather events such as wild fires, flooding and drought, infrastructure access (including the potential for blockades or other activism) and delays in obtaining regulatory approvals and third party consents; the ability of the Company's contractual counterparties to perform their contractual obligations; our ability to obtain equipment in a timely manner to carry out development activities and the costs thereof; our ability to market our oil and natural gas successfully to current and new customers; our ability to obtain financing on acceptable terms, including our ability (if necessary) to extend the revolving period and term out period of our credit facility, our ability to maintain the existing borrowing base under our credit facility, our ability (if necessary) to replace our syndicated bank facility and our ability (if necessary) to finance the repayment of our Notes on maturity or pursuant to the terms of the underlying agreement; the accuracy of our estimated reserve volumes; and our ability to add production and reserves through our development and exploitation activities. The future acquisition by the Company of the Company's common shares pursuant to its share buyback program (including through its NCIB), if any, and the level thereof is uncertain. Any decision to acquire common shares of the Company pursuant to the share buyback program will be subject to the discretion of the board of directors of the Company and may depend on a variety of factors, including, without limitation, the Company's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on the Company under applicable corporate law. There can be no assurance of the number of common shares of the Company that the Company will acquire pursuant to its share buyback program, if any, in the future.
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FORWARD-LOOKING INFORMATION ADVISORY (CONT.) 33 Although the Company believes that the expectations reflected in the forward-looking statements contained in this document, and the assumptions on which such forward-looking statements are made, are reasonable, there can be no assurance that such expectations will prove to be correct. Readers are cautioned not to place undue reliance on forward-looking statements included in this document, as there can be no assurance that the plans, intentions or expectations upon which the forward-looking statements are based will occur. By their nature, forward-looking statements involve numerous assumptions, known and unknown risks and uncertainties that contribute to the possibility that the forward-looking statements contained herein will not be correct, which may cause our actual performance and financial results in future periods to differ materially from any estimates or projections of future performance or results expressed or implied by such forward-looking statements. These risks and uncertainties include, among other things: the risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company, including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; the possibility that we change our budgets (including our capital expenditure budgets) in response to internal and external factors, including those described herein; the possibility that the Company will not be able to continue to successfully execute our business plans and strategies in part or in full, and the possibility that some or all of the benefits that the Company anticipates will accrue to our Company and our stakeholders as a result of the successful execution of such plans and strategies do not materialize (such as our inability to return capital to shareholders and/or reduce debt levels to the extent anticipated or at all); the impact on energy demand and commodity prices of regional and/or global health related events and the responses of governments and the public thereto, including the risk that the amount of energy demand destruction and/or the length of the decreased demand exceeds our expectations; the risk that there is another significant decrease in the valuation of oil and natural gas companies and their securities and in confidence in the oil and natural gas industry generally, whether caused by regional and/or global health related events, the worldwide transition towards less reliance on fossil fuels and/or other factors; the risk that the financial capacity of the Company's contractual counterparties is adversely affected and potentially their ability to perform their contractual obligations; the possibility that the revolving period and/or term out period of our credit facility and the maturity date of our Notes is not extended (if necessary), that the borrowing base under our credit facility is reduced, that the Company is unable to renew or refinance our credit facilities on acceptable terms or at all and/or finance the repayment of our Notes when they mature on acceptable terms or at all and/or obtain new debt and/or equity financing to replace our credit facilities and/or Notes or to fund other activities; the possibility that we are unable to complete one or more repurchase offers pursuant to our Notes when otherwise required to do so; the possibility that we are forced to shut-in production, whether due to commodity prices decreasing, extreme weather events such as wild fires, inability to access our properties due to blockades or other activism, or other factors; the risk that OPEC and other nations fail to agree on and/or adhere to production quotas from time to time that are sufficient to balance supply and demand fundamentals for oil; general economic and political conditions in Canada, the U.S. and globally, and in particular, the effect that those conditions have on commodity prices and our access to capital; industry conditions, including fluctuations in the price of oil, natural gas liquids and natural gas, price differentials for oil and natural gas produced in Canada as compared to other markets, and transportation restrictions, including pipeline and railway capacity constraints; fluctuations in foreign exchange, including the impact of the Canadian/ U.S. dollar exchange rate on our revenues and expenses; fluctuations in interest rates, including the effects of interest rates on our borrowing costs and on economic activity, and including the risk that elevated interest rates cause or contribute to the onset of a recession; the risk that our costs increase due to inflation, supply chain disruptions, scarcity of labour and/or other factors, adversely affecting our profitability; unanticipated operating events or environmental events that can reduce production or cause production to be shut-in or delayed (including extreme cold during winter months, wild fires, flooding and droughts (which could limit our access to the water we require for our operations)); the risk that wars and other armed conflicts adversely affect world economies and the demand for oil and natural gas, including the ongoing war between Russian and Ukraine and/or hostilities in the Middle East and Venezuela; the possibility that fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to hydrocarbons, government mandates requiring the sale of electric vehicles and/or electrification of the power grid, and technological advances in fuel economy and renewable energy generation systems could permanently reduce the demand for oil and natural gas and/or permanently impair the Company's ability to obtain financing and/or insurance on acceptable terms or at all, and the possibility that some or all of these risks are heightened as a result of the response of governments, financial institutions and consumers to a regional and/or global health related event and/or the influence of public opinion and/or special interest groups. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's Annual Information Form (see ’Risk Factors’ and ’Forward-Looking Statements’ therein) which may be accessed through the SEDAR+ website (www.sedarplus.ca), EDGAR website (www.sec.gov) or Obsidian Energy's website. Readers are cautioned that this list of risk factors should not be construed as exhaustive. Unless otherwise specified, the forward-looking statements contained in this document speak only as of February 18, 2026. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements. The forward-looking statements contained in this document are expressly qualified by this cautionary statement. All figures are in Canadian dollars unless otherwise stated.