Slides
Page 1
Obsidian Energy Ltd. Corporate Presentation July 2026
Page 2
OVERVIEW 2 Q2 2026 Production 28,200 boe/d Q2 2026 Annualized Adjusted Funds flow from Operations (AFFO) $294 million Net Debt to Q2 2026 Annualized AFFO 1.2x Shares Outstanding 66.7 million Market Capitalization $924 million Q2 2026 Net Debt $354 million Enterprise Value $1,278 million 2P Reserves 158 million boe 2P NPV10% at US$75/bbl WTI $2,309 million 2P Net Asset Value $31.52/sh Focused asset base with experienced team delivering value P E A C E R I V E R 11,734 boe/d Cold flow heavy oil Q2 2026 28,200 boe/d 15,393 boe/d Light oil conventional development 2See endnotes and non-gaap measure advisory for additional information. W I L L E S D E N G R E E N & P C U # 1 1 V I K I N G 778 boe/d Light oil conventional development
Page 3
OBSIDIAN ENERGY VALUE PROPOSITION 3 HIGH QUALITY ASSETS • Extensive land position, substantial growth capacity in Clearwater and Belly River plays • Balanced portfolio of light and heavy oil production • EOR potential to maximize value of assets OPERATIONAL EXCELLENCE • Safety driven culture with solid polices & practices in place • Proven technical expertise and knowledge to drive new well designs & improve returns • Strong engagement with the communities in which we operate SHAREHOLDER FOCUSED • Focused on per share growth via production additions and return of capital • Active share repurchase program since 2023 • Maintain solid leverage metrics, allowing financial flexibility Focus on superior execution to deliver results and create value for shareholders Unlock asset potential, deliver operational excellence, and execute on share buybacks to drive top quartile returns
Page 4
RETURNING CAPITAL TO SHAREHOLDERS 0 5 10 15 20 25 30 35 40 45 0 5 10 15 20 25 30 35 Q1 21 Q1 22 Q1 23 Q1 24 Q1 25 Q1 26 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 ~23% of shares repurchased/cancelled (~18.9 million shares at $8.72/share) since the implementation of our NCIB program in February 2023 14% CAGR per share vs. 7% corporate production CAGR NCIB launched Feb 2023 • Since renewing our NCIB in March 2026, we have repurchased and cancelled ~1.7 million shares 67% Utilized 61% Utilized 100% Utilized 0 2 4 6 8 10 12 2023/24 2024/25 2025/26 2026/27 (in progress) NCIB REPURCHASES Shares cancelled (million) 26% Utilized ~18.9 million shares cancelled See endnotes for additional information 4
Page 5
DELIVERING RESULTS 5 Strategy and execution create momentum for long-term value creation * Sold ~11,000 boe/d of production on April 7, 2025, in Pembina disposition See endnotes and non-gaap measure advisory for additional information Q3 2025 Q4 2025 Q1 2026 Q2 2026 WTI US$/bbl $64.93 $59.14 $71.93 $92.79 AECO $/mcf $0.60 $2.23 $2.01 $1.63 Production boe/d 27,316 27,971 28,733 28,200 Capital expenditures $ millions $65.3 $65.0 $79.7 $39.1 Decommissioning expenditures $ millions $7.9 $10.3 $1.7 $1.3 Net operating costs $/boe $15.01 $15.19 $14.60 $14.49 Netback $/boe $24.90 $25.64 $26.76 $33.22 General & administrative $/boe $1.95 $1.98 $2.12 $2.05 AFFO $ millions $55.2 $56.3 $59.0 $73.6 AFFO/share (basic) $ per share $0.82 $0.84 $0.88 $1.10 FFO $ millions $49.7 $56.6 $61.0 $67.8 FFO/share (basic) $ per share $0.74 $0.84 $0.91 $1.02 FCF $ millions ($18.0) ($19.0) ($22.4) $33.2 FCF/share (basic) $ per share ($0.27) ($0.28) ($0.33) $0.50 Net Debt $ millions $211.9 $240.1 $279.8 $353.6 Net Debt to AFFO (annualized) times 1.0 1.1 1.2 1.2 Q2 Financial Highlights • Rig released 8 (8.0 net) wells, including waterflood 4 (4.0) net injector wells, brought on production 8 (8.0 net) wells • Completed $98 million Belly River asset acquisition, strengthening our Willesden Green light oil platform • Increased syndicated credit facility by $40 million, to $275 million • Subsequent to June 30, 2026, successfully completed a $75 million add-on to existing Senior Notes, for a total of $250 million outstanding
Page 6
Acquired WI Land Obsidian WI Land Belly River Oil Fairway Alberta BELLY RIVER OIL FAIRWAY Crimson STRATEGIC WILSON CREEK ASSET ACQUISITION 6 Oil weighted acreage increasing scale of Belly River land base Expands scale, inventory and production in the core Belly River fairway 1. Thresholds for CVP: US$85.00/bbl (Q3/26 ), US$80.00/bbl (Q4/26), US$75.00/bbl (Q1/27), US$72.50/bbl (Q2/27). Transaction Overview • Closed transaction to acquire Wilson Creek assets from Highwood Asset Management on June 30, 2026 • $98 million cash consideration (including closing adjustments), plus a contingent value payment (CVP) of up to $7 million • Up to $1.75 million payable quarterly from Q3 2026 to Q2 2027 if WTI exceeds specified thresholds(1) • Effective date April 1, 2026 Metrics • $39,200 per flowing boe/d (based on May production of 2,500 boe/d) • 3.4x acquisition multiple based on H2 2026 NOI • $32,700 per flowing boe/d (2027E production of 3,000 boe/d) • 2.2x acquisition multiple based on 2027E NOI Pembina Willesden Green Ferrier Gilby See endnotes for additional information Wilson Creek
Page 7
WILSON CREEK TRANSACTION HIGHLIGHTS 7 Acquisition further strengthens Willesden Green position Large, contiguous position at Willesden Green with over 14,000 boe/d of pro forma high netback production Highlights • Establishes OBE as the largest Belly River producer in the Central Alberta Oil Fairway with >4,000 boe/d • ~2,500 boe/d of incremental production (based on May 2026) • Liquids weighting increases to 55% from 49% in Willesden Green • 36 identified development locations with further reserve and inventory potential • Adds 35 net sections and establishes a leading Belly River position SIGNIFICANT SYNERGIES & GROWTH POTENTIAL OBE INFRASTRUCTURE UNLOCKS GROWTH • Broader midstream network, take away capacity and greater scale support growth 6 WELL PROGRAM PLANNED IN 2027 • 3,000 boe/d average production in 2027 • $45 million NOI and $15 million of FCF Willesden Green (Current) Wilson Creek Acquisition Willesden Green (Pro Forma) Production boe/d ~11,900 ~2,500 ~14,400 Oil & Liquids % 49% 76% 55% Land Sections 254 35 289 2P Reserves Mmboe 78 14 92 2P Locations # Gross 106 36 142 2P Belly River Locations # Gross 14 36 50 2P RLI Years 18 15 17 See endnotes for additional information
Page 8
- 1,000 2,000 3,000 4,000 5,000 Jan/24 Jul/24 Jan/25 Jul/25 Jan/26 4,370 2,410 2,350 1,340 1,320 960 830 620 590 580 450 -- 1,000 2,000 3,000 4,000 5,000 Peer 1 Peer 3 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 BELLY RIVER SCALE ADVANTAGE 8 Pro-forma OBE leads the emerging Belly River play Establishes a clear leadership position in the Belly River fairway PRO-FORMA BELLY RIVER PRODUCTION PRO-FORMA BELLY RIVER LANDSCAPE (boe/d) (Q1 2026 average production, boe/d) Transaction Effective Date Wilson Creek Acquisition OBE Belly River Largest Belly River Producer Pro Forma See endnotes for additional information
Page 9
2026 GUIDANCE 9 Accelerated development program supported by constructive oil prices Incremental capital directed to high-return light oil and waterflood development is expected to deliver meaningful 2027 growth while maintaining balance sheet strength 2026 Guidance Average production boe/d 29,000 – 31,000 % Oil and NGLs % 72% Capital expenditures $ millions 300 – 325 Decommissioning expenditures $ millions 7 –11 Net operating costs $/boe 14.00 – 15.00 General & administrative $/boe 1.95 – 2.05 Pricing assumptions WTI US$/bbl 75.00 Foreign Exchange Rate CAD/USD 1.40 MSW Differential US$/bbl 2.50 WCS Differential US$/bbl 13.75 AECO $/GJ 2.25 Based on midpoint of above guidance FFO $ millions 310 FFO per share (basic) $/share 4.64 FCF $ millions (14) FCF per share (basic) $/share (0.20) Net debt $ millions 395 Net debt to FFO (at June 30/27) times 0.8 See endnotes for additional information 2026 Guidance Based on midpoint of guidance Heavy Oil Light Oil Average production boe/d 12,700 17,300 % Oil and NGLs % 92% 57% Capital expenditures $ millions 110 200 Net operating costs $/boe 19.80 10.40 Netback $/boe 36.20 37.05 Net operating income $ millions 168 234 Asset level FCF $ millions 58 33 Sensitivity Range Change in 2026 Guidance FFO ($ millions) WTI +/- US$1.00/bbl 4.0 Foreign Exchange Rate +/-$0.01/CAD/USD 2.8 MSW differential +/- US$1.00/bbl 1.8 WCS differential +/- US$1.00/bbl 2.3 AECO +/- CAD$0.25/GJ 0.9 1. Includes hedge positions and H1/26 realized prices
Page 10
HEDGING PROGRAM 10 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 ) W T I O I L H E D G E S A E CO G A S H E D G E S 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 WTI Swaps WTI Collars Term % Hedged (net) Volumes Avg. Price Volumes Floor Ceiling July 2026 72% 10,982 US$76.86 - - - August 2026 65% 2,450 US$81.40 7,500 US$79.50 US$87.66 September 2026 19% 1,500 US$82.46 1,350 US$80.00 US$87.42 Term % Hedged (net) Forward Rate Notional Amount (CAD$) July 2026 56% $1.3729 $21,300,000 August 2026 57% $1.3739 $21,300,000 September 2026 33% $1.3866 $11,700,000 AECO Swaps Term % Hedged (net) Volumes (mcf/d) Avg. Price (per mcf) Summer 2026 (July – Oct) 72% 35,077 $2.69 Winter 2027 (Nov/26 – Mar/27) 19% 9,479 $2.95 Expiry Date Avg. Share Price No. of Shares September 2028 $8.89 720,000 October 2028 $8.72 1,300,000 November 2028 $8.43 550,000 December 2028 $8.31 715,000 January 2029 $8.76 450,000 February 2029 $10.18 680,000 April 2029 $13.82 710,000 June 2029 $15.10 85,000 Total $9.65 5,210,000 See endnotes for additional information
Page 11
Light Oil • Accelerating high-return production growth through a two-rig Willesden Green program supported by approximately $65 million of incremental capital • Total 2026 light oil investment of approximately $200 million supports average production of 17,300 boe/d and meaningful year-over-year growth Heavy Oil • Advancing drilling and waterflood development to enhance long-term recovery and increase capital efficiencies • Approximately $110 million of capital expenditures for 2026, supports a two-rig program and stable production of 12,700 boe/d New Ventures • Approximately $10 million allocated to H2 2026 exploration, including the Pekisko subcrop, to advance future inventory and growth opportunities H2 2026 DEVELOPMENT PROGRAM HIGHLIGHTS 11 Accelerated Belly River development with continued waterflood focus Strategic capital allocation accelerates production growth while advancing waterflood and exploration opportunities. See endnotes for additional information
Page 12
2026 CAPITAL PROGRAM 12 Balanced capital program while furthering our waterflood initiatives in Peace River Active H2 program accelerating Belly River development and advancing Clearwater waterflood initiatives through incremental injectors 1. Including the last well of our 2025 program rig released on January 2, 2026 2. One of our 10 added Clearwater injector wells is anticipated to be rig released in early 2027 3. In addition, Obsidian Energy expects to participate in 9 (4.0 net) non-operated wells and drill one operated water source well 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) 6 (5.7) - - 6 (5.7) H2 Peace River (Clearwater)2 6 (6.0) - 10 (10.0) 16 (16.0) Light Oil Assets H1 Willesden Green (Belly River) 7 (7.0) - - 7 (7.0) H1 Willesden Green (Cardium) - - - - H2 Willesden Green (Belly River) 14 (14.0) - - 14 (14.0) H2 Willesden Green (Cardium) 3 (3.0) - - 3 (3.0) New Ventures H2 Activity 2 (2.0) 2 (2.0) Total Operated Wells3 47 (46.7) 1 (1.0) 17 (17.0) 65 (64.7) P E A C E R I V E R V I K I N G W I L L E S D E N G R E E N & P C U # 1 1
Page 13
Willesden Green (Belly River/Cardium/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 • Capital efficiencies increased by sharing pads and infrastructure with Belly River and Cardium development Pembina Cardium Unit #11 (Cardium, Non-operated) • Strong rates and production additions from development programs • Provides strong returns and robust FCF generation 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 12,384 778 3,010 2,500 Pro Forma Light Oil Assets Production ( Q 2 2 0 2 6 , b o e / d ) Willesden Green Viking PCU#11 (non-operated) Highwood Acquired Production V i k i n g 155 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 R3 W5 T31 R1 W4 See endnotes for additional information OBE WI Land Acquired WI Land
Page 14
Belly River • Large inventory of wells with proven strong results from drills in Open Creek and from our delineation well in Crimson • Drilled and rig-released 5 (5.0 net) wells in Open Creek in the first quarter • Spud 1 (1.0 net) well in Crimson in the second quarter • Continuing to focus on the Belly River in 2026, with 14 (14.0 net) wells planned in H2 2026 • Plan to drill delineation well in Faraway Cardium • 4 (4.0 net) Cardium wells onstream in the first quarter at the Open Creek 11-15 pad. Strong rates with IP30 average of 523 boe/d per well (79% liquids) • Open Creek had limited horizontal Cardium development prior to consolidating our working interest position in 2025 Infrastructure • Wilson Creek acquisition expands our operational footprint and aligns with existing OBE infrastructure for a competitive advantage and new opportunities for development WILLESDEN GREEN ASSET 14 Expanding Belly River program and drilling underexploited Cardium at Open Creek See endnotes for additional information; see ‘Well Economics’ for area economics Wilson Creek Crimson <0.9 years Payout (2P) 155 2P locations (2025, net) 17.1 RLI (2P 2025, years) T45 R3 W5 96% WI (operated) 14,884 boe/d (Q2 2026 pro forma production) 17% decline rate (PDP, 3-year average) OBE WI Land Acquired WI Land
Page 15
BELLY RIVER ACTIVITY 15 Increasing production rates, higher IP120 than IP30 Area Highlights • Large Belly River land base of ~145 sections • Robust inventory and readiness supports area growth • Eastern infrastructure expansion completed in late 2025 • Belly River development now accounts for 16% of area production (~2,000 boe/d) and is expanding Recent Operations • Production rates continue to strengthen over time as wells stabilize with higher IP120’s than IP30’s • 11-28 and 06-04 pads latest onstream, showing encouraging results and recent flow tests indicates strong pressure and flowing capability H2 2026 Plans • Accelerated growth with 14 (14.0 net) wells planned Crimson 12-21 Pad IP30: 510 boe/d (76% Liq) IP60: 559 boe/d (82% Liq) T41 Area wells OBE wells OBE WI Land Acquired WI Land Open Creek 15-06 Pad IP30: 100 boe/d (77% Liq) IP120: 195 boe/d (72% Liq) Open Creek 06-33 Pad IP30: 199 boe/d (86% Liq) IP120: 288 boe/d (69% Liq) Open Creek 11-28 Pad IP30: 303 boe/d (78% Liq) IP60: 366 boe/d (72% Liq) - 2,000 4,000 6,000 8,000 10,000 12,000 14,000 Jan-25 Apr-25 Jul-25 Oct-25 Jan-26 Apr-26 Net Total (boe/d) New Belly River Development Willesden Green Other T42 T44 R6W5R7W5 Open Creek 06-04 Pad IP30: 177 boe/d (71% Liq) IP60: 256 boe/d (69% Liq) Crimson 01-05 Pad First well RR in June R5W5 R4W5 T43
Page 16
Nampa Cadotte Walrus Seal Main Gift Lake Dawson Peavine West Dawson Peace River HVS • Large, contiguous, long-term land base of >830 sections with Bluesky and Clearwater heavy oil rights • New development fields at Dawson, West Dawson, Nampa and Walrus • 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 Clearwater and Bluesky heavy oil resource provides upside for future growth PEACE RIVER ASSET 16 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) 11,734 boe/d (Q2 2026 production) 25% decline rate (PDP, 3-year average) Slave Nipisi
Page 17
PEACE RIVER REGIONAL AREA Over 830 sections of land holdings with multi-zone potential 17 Nampa Cadotte Walrus Seal Main Gift Lake Dawson Peavine West Dawson HVS Golden Utikima Nipisi Nampa Clearwater focus with recently initiated waterflood pilot Recent infrastructure build-out West Dawson Clearwater development with highest quality oil discovered to date HVS/Walrus Bluesky development with recent recognition of top heavy oil wells 12-month cumulative production T88 T85 T76 T79 T82 R15W5 R5W5R10W5R20W5R25W5 Exploration Lands Recently accumulated exploration lands Dawson/Peavine Clearwater development success followed by integrated waterflood Baytex Clear North CNRL Gran Tierra Headwater Rubellite Spur Tamarack Paramount Obsidian Islander Grizzly See endnotes for additional information
Page 18
Dawson 04-24 Waterflood Pilot Fully operational February 2026 Q2 2026 Integrated WF Drilling & Scheme Expansion Baytex Peavine Waterflood Pilot Injector rig released March 2026 Area wells Directly supported production wells Injection wells EOR scheme area EOR planned scheme area OBE pipelines Baytex Peavine Waterflood Pilot Conversion approved May 2026 DAWSON/PEAVINE 18 Initiated waterflood pilot, continued integrated full-field development Robust Clearwater deliverability slated for full field waterflood development Area Highlights • Large, contiguous land block at 130+ sections • Clearwater focused multilateral open hole development • Production ~5,000 boe/d, 100% working interest in area • Strong primary deliverability with enhanced oil recovery upside Operational Update • Waterflood pilot fully operational in February 2026, results encouraging thus far • Drilling through breakup on 05-13 integrated waterflood pad • Recently acquired strategic natural gas pipeline infrastructure to support future operations H2 2026 Plans • Continued integrated waterflood development, with additional injector drills and centralized facility plans • 6 (6.0 net) production and 10 (10.0 net) injection wells R15W5 T78 T77 R16W5R17W5 See endnotes for additional information
Page 19
NAMPA 19 Initiated waterflood pilot, infrastructure build and continued delineation Clearwater production suitable for waterflood development with multi-zone development Area Highlights • Significant land position at 90+sections, with multi-zone potential • Clearwater focused multilateral open hole development • Multi-zone potential with upside in the Bluesky • High oil quality with enhanced oil recovery upside Operational Update • Encountered high oil quality (16.2 API gravity and 497cP viscosity) at our 06-28 pad waterflood pilot, onstream as of May 2026 • Finalizing new all-weather access road infrastructure to support future growth H2 2026 Plans • Continued evaluation of Clearwater waterflood pilot • Bluesky drilling to offset recent peer success • 2 (2.0 net) production wells Nampa 06-28 Waterflood Pilot Injection online early May Planned 2026 Bluesky Drills Area wells Directly supported production wells Injection wells EOR scheme area OBE Nampa Road 02/12-29 IP30 141 bopd 16.2° API, 497cP T85 T84 R16W5R17W5R18W5 R15W5 See endnotes for additional information
Page 20
W. Dawson 09-21 Waterflood Pilot Injection expected Early-June Delineation Well 00/13-21 IP30 309 bopd 17.2° API, 553cP 02/08-22 IP30 285 bopd 04/08-22 IP30 289 bopd Area wells Directly supported production wells Injection wells EOR scheme area OBE pipelines WEST DAWSON 20 Initiated waterflood pilot, delineation success Highest oil quality Clearwater production suitable for full field waterflood development Area Highlights • 20+ sections all-weather access • Clearwater focused multilateral open hole development • Production increasing with activity, recently over ~700 boe/d • Enhanced oil recovery upside Operational Update • Highest oil quality discovered with Q1/26 drills (17.2 API gravity and 553cP viscosity) • Rig released waterflood pilot and appraisal well from the 09-21 pad. Average IP30 294 bopd (100% oil) from three Q1 production wells • Recently acquired strategic natural gas pipeline infrastructure to support future operations H2 2026 Plans • Continued evaluation of Clearwater waterflood pilot; scouting and acquiring for further delineation T80 T79 R19W5R20W5 See endnotes for additional information
Page 21
NEW VENTURES 21 Strategic multi-zone exploration opportunity Established substantial land position in multi-zone exploration area Area Highlights • Successfully participated in recent area Crown Land Sales to establish a dominant position • Mineral land acreage acquired at an average cost of ~$380/ha • Accumulated over 150 sections of which 99 are in the oil sands window with long land tenure • Large, contiguous blocks well situated for multi-zone exploration potential and stacked development opportunity H2 2026 Plans • Exploration/appraisal planned in second half program SHUNDA ● PEACE RIVER SPIRIT RIVER/ CLEARWATER ● BLUESKY ● GETHING ● LOWER CRETACEOUS NOTIKEWAN FALHER ● WILRICH ● MISSISSIPPIAN Stratigraphic Table DEBOLT ○ PEKISKO ● PEKISKO ● New Ventures Land Acquisition Islander Pekisko Recent industry top producing drills with average IP30 ~490bopd T83 T81 T82 R10W5R12W5R14W5 Baytex Islander Obsidian Grizzly See endnotes for additional information
Page 22
RESERVES UNDERPIN OUR CURRENT AND FUTURE VALUE 22 Trading at substantial discount on booked reserves basis Focus on growing per share metrics to increase shareholder value $13.85 $8.24 $11.21 $13.94 $14.51 $20.09 $25.32 $23.59 $31.52 $38.83 $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 (C$ 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$85 WTIUS$65 WTI US$75 WTI See endnotes for additional information 209 108 53 48 318 108 160 50 357 155 180 47 - 50 100 150 200 250 300 350 400 450 Total Willesden Green/PCU #11 Peace River Viking P R O F O R M A 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
Page 23
WHY INVEST IN OBSIDIAN ENERGY 23 Focused oil development, EOR upside, share buybacks drive per share growth Unlocking asset potential while maintaining operational excellence and returning capital to shareholders Focused Strategy Substantial Reserves Valuation Upside Shareholder Returns Tax Advantage Responsible Operator Unlock asset value to drive production and FFO per share growth Continue to return capital to shareholders Low decline, oil weighted asset base with significant underlying reserves Significant land base with years of drilling inventory Trades at a significant discount on both reserve values/ cash multiples to peers EOR progress and New Ventures focus furthers upside Active share buybacks, ~23% shares retired since program inception in 2023 Prepaid equity program on ~8% of shares at $9.65/share, mitigates FFO volatility ~$2.3 billion of tax pools available Non-cash taxpayer for ~10 years at WTI US$70/bbl Safety driven culture, strong policies and practices in place Dedicated to make a positive impact in our communities See endnotes for additional information
Page 24
Appendix 24
Page 25
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 25 Non-Operated unit with years of low-risk inventory See endnotes for additional information; see ‘Well Economics’ for area economics - 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 Jan-22 Jul-22 Jan-23 Jul-23 Jan-24 Jul-24 Jan-25 Jul-25 Jan-26 Gross Production (boe/d) GROSS PCU#11 PRODUCTION 45% WI (non-operated) 3,010 boe/d (Q2 2026 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)
Page 26
VIKING ASSET 26 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 Light oil asset with significant inventory and highly economic returns 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 100% WI (operated) 778 boe/d (Q2 2026 production 16% decline rate (PDP, 3-year average) T31 R6 W4 <0.9 years Payout (2P) 47 2P locations (2025, net) 24.0 RLI (2P 2025, years)
Page 27
$1.0 billion $0.1 billion $0.6 billion $0.6 billion TAX POOL COMPOSITION Non-Capital Losses CEE & SR&ED CDE Other Pools (Q2 2026) CONSIDERABLE FUTURE VALUE FROM TAX POOLS 27 $2.3 billion of tax pools in unrecognized value to be leveraged with future growth The Company doesn’t expect to pay cash taxes for ~10 years at US$70/bbl WTI $1.1 billion of tax pools immediately deductible $2.3 billion of tax pools Amount of Pools Utilized by Year1 Illustrative Value of Tax Pools @ 8% Discount Rate2 $200 million $339 million $4.89/share $300 million $386 million $5.57/share $400 million $413 million $5.96/share $500 million $431 million $6.22/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 June 30, 2026). Value presented per Obsidian Energy share, using fully diluted shares outstanding as of June 30, 2026 Maximum Theoretical Value1 Total $469 million $6.77/share Immediately deductible $252 million $3.64/share 1. Maximum theoretical value is calculated based on average 2026 tax rate of 23%, applied to our total and immediately deductible tax pools, and using fully diluted shares outstanding as of June 30, 2026
Page 28
2025 RESERVES HIGHLIGHTS 28 Reserves replacement ratios reflect development program success YEAR -END 2025 RESERVES SUMMARY (OBE ONLY) 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$65 WTI) $865 million $1,246 million $1,802 million NPV10% (US$75 WTI) $1,060 million $1,604 million $2,309 million NPV10% (US$85 WTI) $1,241 million $1,940 million $2,779 million 1. Reserve figures exclude amounts associated with Wilson Creek asset acquisition
Page 29
WELL ECONOMICS 29 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%
Page 30
EXPERIENCED TEAM WITH STRONG TECHNICAL SKILLS 30 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 Jay McGilvary Vice President, Development Cliff Swadling Vice President, Operations 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
Page 31
ADVISORY 31 This presentation should be read in conjunction with the Company’s unaudited interim consolidated financial statements and MD&A for the three and six months ended June 30, 2026. 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.
Page 32
Endnotes
Page 33
ENDNOTES 33 Slide 2: Overview Market capitalization determined with share price on the close of business on July 29, 2026, on the TSX ($13.85 per share) and common shares outstanding at July 29, 2026. Enterprise value calculated by adding net debt as at June 30, 2026, 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”. 2P NPV10% uses WTI US$75/bbl, AECO $2.25/GJ, WCS differential US$13.75/bbl, MSW differential US$2.50 and FX rate of 1.40 CAD/USD. Map volumes do not include additional legacy wells outside these core areas (295 boe/d) as well as acquired production from the Highwood acquisition (~2,500 boe/d – May Production) 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 5: Delivering Results Production per share data based on average boe/d and basic shares for the year, as applicable. The Company includes prepaid equity forward contracts in our working capital deficiency given we have paid for these contracts upon entering them and the corresponding share-based compensation liabilities are included in Accounts Payable and Accrued Liabilities. Slide 6: Strategic Wilson Creek Asset Acquisition The total cash consideration payable at close was approximately $98 million, reflecting an initial unadjusted purchase price of $105 million less closing adjustments of approximately $7 million. CVP are subject to a range of average WTI prices in the applicable quarter. If the applicable WTI threshold is achieved, the quarterly CVP is calculated at $116,667 for each US$1/bbl increase based on average WTI above the threshold price, up to a maximum payment of $1.75 million. The applicable WTI thresholds and maximums are as follow: Q3/26 – US$85 - $100/bbl, Q4/26 – US$80 - $95/bbl, Q1/27 - US$75 - $90/bbl, Q2/27 - US$72.50 - $87.50/bbl. Acquisition multiples are based on internal forecasts for H2/26 using WTI US$75.00 and 2027 using WTI US$70.00. Slide 7: Wilson Creek Transaction Highlights Willesden Green 2P Reserves, 2P locations, 2P Belly River locations, and 2P RLI as defined by our Independent Qualified Reserve Evaluator in the Reserves Report. Wilson Creek acquisition 2P Reserves, 2P locations, 2P Belly River locations and 2P RLI were prepared internally by a Qualified Reserves Evaluator (QRE). 2027 NOI and FCF estimates are based on internal forecasts and are subject to change. Slide 8: Belly River Landscape Source: Enverus Pro forma Belly River production chart based on gross wellhead production Pro forma Belly River landscape chart, peers include the 10 largest belly river producers, in alphabetical order, IPO, LTC, PRQ, Sifton Petroleum, Sinopec, TAQA, TOU, YGR. Pro-forma Highwood only includes Brazeau production. Slide 9 2026 Guidance/Sensitivities Further details of production guidance ranges, by product type, are as follows: Asset level capital does not include $1 million in corporate capital. Guidance pricing assumptions include risk management (hedging) adjustments as of June 30, 2026. Pricing assumptions for Guidance are from July to December 2026. Per share calculations for our Updated and Previous Guidance are based on an estimated 66.8 million weighted average share outstanding for the year ended December 31, 2026. Net Debt figures are estimated at December 31, 2026. Net debt to FFO at June 30, 2027 is based on trailing 12-month FFO ended June 30, 2027, assuming an average H1/27 WTI price of US$70/bbl and approximately $120 million of H1/27 capital and decommissioning expenditures. The Company’s estimated AER spending closure obligation for 2026 remains subject to change in accordance with the terms and conditions of the agreement of purchase and sale governing the Company’s disposition of its Pembina assets to InPlay in 2025. Slide 10: 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. % hedged net is based on either production net of royalties or revenue net of royalties as applicable. Slide 11: H2 Development Program Highlights New Venture capital expenditures of $10 million is also included in the Light Oil and Heavy Oil capital expenditure figures. Light oil (bbls/d) Heavy Oil (bbls/d) NGL (bbl/d) Natural Gas (mmcf/d) Total (boe/d) Guidance 2026 7,600 11,700 2,300 50.4 30,000
Page 34
ENDNOTES 34 Slide 13: Light Oil Assets Booked locations reflects locations as defined by our Independent, Qualified Reserves Evaluator in their Reserves Report. For the 2P WG/PCU#11 locations, 130 net locations evaluated by GLJ at year-end 2025 and 25 net locations acquired through Belly River acquisition through Highwood based on internal reserve analysis prepared internally by a QRE. 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. Reserve figures are shown pro forma the Belly River acquisition from Highwood based on internal reserve analysis prepared internally by a QRE. Slide 16: 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. Slide 17: Peace River Regional Map Source: Derived from public sources. Includes majority working interest lands from top Mannville to base Gething. Oil sands and P&NG rights respective of Peace River OSA boundary Slide 18: Dawson/Peavine Production based on Q1 average. Baytex Energy Corp. pilot information obtained from public sources. Slide 20: West Dawson Production based on May actuals based on field information. Slide 21: New Ventures Production data from Islander Oil & Gas Inc. obtained from public data. Slide 22: 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 and for Willesden Green are disclosed on a proforma basis including the Wilson Creek acquisition which were prepared internally by a QRE. See ‘2025 Reserves Disclosure and Definitions’ for further details. NAV/share based on YE 2025 reserves run at flat pricing and include the Wilson Creek acquisition which are based on internal reserve analysis completed by a QRE and uses Net Debt as at June 30, 2026 of $354 million. Shares outstanding calculated using common shares outstanding as of July 29, 2026, and includes RSUs and exercisable options as at June 30, 2026. Share price depicted is at the close of business on July 29, 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 23: 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 25: 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 26: 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. Slide 28: 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. Reserve figures presented exclude amounts associated with the Wilson Creek asset acquisition which closed on June 30, 2026.
Page 35
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 PDP means proved developed producing reserves as per Oil and Gas Disclosures Advisory 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 QRE references Qualified Reserves Evaluator in accordance with COGE Handbook 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 35 2026E means the guidance for 2026 for the full year, based on internal assumptions and estimates 2027E means internal forecast for 2027 full year based on internal assumptions and estimates 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 cP means Centipoise and is metric to calculate viscosity COGE Handbook stands for the Canadian Oil and Gas Evaluation Handbook Company, Obsidian Energy or OBE means Obsidian Energy Ltd.; as applicable CVP mean Contingent Value Payment as part of potential consideration for the Wilson Creek asset acquisition with Highwood 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 oil 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 Highwood means Highwood Asset Management 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
Page 36
NON-GAAP MEASURES ADVISORY 36 Adjusted Funds Flow from Operations (AFFO) 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, certain other expenses and the impact on share based compensation of liability based incentive plans (includes the DSUs, PSUs and equity forward contracts gains and losses) and is representative of cash related to continuing operations. AFFO is used to assess the combined entity’s ability to fund planned capital programs. 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 AFFO 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. 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 unaudited interim consolidated financial statements and notes and management’s discussion and analysis (“MD&A”) as at and for the three and six months ended June 30, 2026, 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: AFFO, 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: AFFO per share which uses AFFO as a component; 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. 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. 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 which includes our equity forward contracts. Net Debt is a measure of leverage and liquidity. Net Debt to Adjusted Funds Flow from Operations is Net Debt divided by adjusted funds flow from operations Net Debt to Funds Flow from Operations is Net Debt divided by funds flow from operations. Net operating costs are calculated by deducting processing fees and road use recoveries 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. 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.
Page 37
OIL AND GAS INFORMATION ADVISORY 37 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.
Page 38
2025 RESERVES DISCLOSURE AND DEFINITIONS 38 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. Finding, Development and Acquisition (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 first year (or 2026) 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”.
Page 39
FORWARD-LOOKING INFORMATION ADVISORY 39 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; our expectations for the CVP, associated production, locations, netback and development program in connection with the Wilson Creek asset acquisition for 2026 and 2027; our corporate guidance for production, capital and decommissioning expenditures, net operating costs, G&A costs, FFO, FFO/share (basic), FCF, FCF/share (basic), net debt and net debt to FFO (at June 30/27); our guidance for asset level production, capital expenditures, net operating costs, netback, net operating income and Asset level FCF, and pricing sensitivities and assumptions; our hedges and strategies for risk management; our expected drilling and exploration programs in both the light and heavy programs and our new ventures program; our expectations for delineation and development in both our heavy and light oil assets and our operational programs, including waterflood initiatives; our expected future growth; our facility and pilot plans for the future; our expectations for incremental capital and growth while maintaining balance sheet strength; how our infrastructure creates optionality in our portfolio; our expectations in connection with our road infrastructure; our drilling opportunities; our expected decline rates, undeveloped reserves locations, RLI, payout timelines and FDC; the reasons to invest in Obsidian Energy; 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 (basic), FCF, FCF per share (basic), asset level FCF, net debt and net debt to FFO ratio (at June 30/27), 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; in connection with the Wilson Creek asset acquisition, the assumptions that the Company can fully integrate the asset and achieve the stated results; 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 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 senior 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 NCIB and the level thereof is uncertain. Any decision to acquire common shares of the Company pursuant to the NCIB 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 NCIB in the future.
Page 40
FORWARD-LOOKING INFORMATION ADVISORY (CONT.) 40 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 the Company may not achieve all of the anticipated benefits of the Wilson Creek asset acquisition; the risk that the Company’s financial and operating results post-transaction (Wilson Creek asset acquisition) may not be consistent with its expectations; 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; risks associated with the refusal of the U.S. to renew the Canada-United States-Mexico Agreement ("CUSMA") by the July 1, 2026 deadline, including the risk that the U.S. ultimately withdrawing from CUSMA, which could result in a significant increase in trade barriers, which could in turn have a material adverse effect on the Canadian and U.S. economies, and by extension the Canadian oil and natural gas industry and the Company; 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 senior 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 senior notes or to fund other activities; the possibility that we are unable to complete one or more repurchase offers pursuant to our senior 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, particularly between Iran, the United States and Isreal; 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. This document contains future-oriented financial information and financial outlook information (collectively, "FOFI") including all information disclosed under "Sensitivity Analysis" which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. The actual results of operations of the Company and the resulting financial results will likely vary from the amounts set forth herein and such variation may be material. The Company and its management believe that the FOFI has been prepared on a reasonable basis, reflecting management's best estimates and judgments. However, because this information is subjective and subject to numerous risks, it should not be relied on as necessarily indicative of future results. Except as required by applicable securities laws, the Company undertakes no obligation to update such FOFI. FOFI contained in this document was made as of the date of this document and was provided for the purpose of providing further information about the Company's anticipated future business operations. Readers are cautioned that the FOFI contained in this document should not be used for purposes other than for which it is disclosed herein. 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 July 29, 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.