Obsidian Energy. Corporate Presentation. April 2018

Transcription

1 Obsidian Energy Corporate Presentation April 2018

2 Important Notices to the Readers This presentation should be read in conjunction with the Company's audited consolidated financial statements, management's discussion and analysis ("MD&A") for the year ended December 31, 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-generally accepted accounting practice ("non-gaap") 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 Appendix at the end of this presentation for further details regarding these matters. 2

3 Obsidian Energy Corporate Profile Cardium Meaningful Free Cash Flow Generation, Waterflood Approach with Primary Optionality 18,190 boe/d Q Net Sections: 450 Peace River Manufactured Cold Flow, High Rate, Low Cost with Multiple Egress Options 4,963 boe/d Q Net Sections: 235 Deep Basin Multi Horizon Potential, Highly Economic Deep Basin Development 1,356 boe/d Q Net Sections: 700 Share Price April 1 st, 2018 OBE-TSX Daily Volume % of shares outstanding Corporate Metrics OBE-NYSE Daily Volume % of shares outstanding $/share $1.29 MM % MM % Market Capitalization $MM $651 Net Debt $MM $383 Enterprise Value $MM $1,034 FY 2018 Guidance Production boe/d 29,000-30,000 Growth % 5% Index Map Alberta Viking Short Cycle Investment to Toggle Growth, Industry Leading IP Rates Total Expenditures Capital Expenditures Decommissioning Expenses Operating Expense G&A Expense $MM $MM $/boe $/boe $125 $10 $ $13.50 $2.00-$2.50 2,508 boe/d Q Net Sections: 170 Legacy Asset Production of 4,429 boe/d in Q4 2017, Portion of OBE s legacy production sold in early See press release titled Obsidian Energy Announces Legacy Asset Disposition dated January 31 st for details 3

4 2017 Reserves Highlight Revitalized Operational Delivery Reserve book reflects a conservative future development profile centered around a growing quantum of low F&D waterflood additions Adding reserves at just over $13 per boe through 2017 demonstrates a powerful engine to reward investors NAV Valuation ($/Share) PDP 2P 2P NPV10 ($BN) $1.18 $1.71 Net Debt ($BN) $0.38 $0.38 Shares O/S (MM) Total NAV / Share $1.58 $ Corporate Reserves Replaced 131% Replaced 121% Light & M edium Crude Oil (mmbbl) Natural Gas Liquids (mm bbl) Replaced 126% PDP 1P 2P Heavy Crude Oil & Bitumen (mmbbl) Conventional Natural Gas (mmboe) Replaced Over 100% of Produced Reserves for the first time in five years Cardium operated development costs down 24% from year-end 2016 Commercial Trades Increased Liquids Weighting by Six Percent Independent reserve engineers recognizes the Deep Basin potential for the first time 4

5 Low Decline Rate Underpins Growth 16% Corporate Base Production Decline Rate Cardium Asset Under Historical Waterflood Capital Efficiencies of $6,500/boe/d on 2017 Optimization Projects Optimization of existing base wellbores Corporate Base Production boe/d 35,000 30,000 25,000 20,000 15,000 22% Base Development Decline Rate 16% Base Decline Rate 2017 Base Production & 2017 Development Declines 16% in ,000 Q Q Q Q Base Production 2017 Development 2018 Development 5

6 Focused 2018 Plan Predictable & Liquids Weighted Growth Profile Development Capital is 64% of Total Expenditures Flexibility to expand capital program in H2 and extend growth rate 2018 Production (boe/d) 29,000 30,000 boe per day 2018 Total Expenditures ($MM) $135 million 32,000 30,000 28,000 5% A&D Adjusted Production Growth Regulatory $14 Enviro 10% $10 8% Base & Infrastructure Capital $25 18% 26,000 24,000 22, Development $86 64% 20, E A&D Adjusted FY 2018E 6

7 Portfolio Optionality on Display Employing a quicker payout program that balances primary drilling with targeted low capital integrated waterflood opportunities Increased Cardium Horizontal Drilling Focus by $9MM (three wells) 2018 Development Allocations ($MM) Budget 2018 Operated Spuds 21 Operated spuds planned in 2018 (excludes non-operated activity) 40% Av. IRR 45% Av. IRR AB Viking $6 7% PROP $8 9% Deep Basin $8 9% 80% Av. IRR Optimization $14 16% 100% Av. IRR AB Viking 4 PROP 4 10 Deep Basin 2 Cardium $50 58% 50% Av. IRR 5 0 Cardium Wells Spud 7

8 Obsidian Energy s Dominant Cardium Position The largest Cardium land holder with significant running room 700 location inventory with >100MMboe of 2P Reserves Large size of the prize with the right geology for meaningful light oil recovery High OOIP recovery factor potential with integrated waterflood approach Contiguous position is advantageous in a highly variable stratigraphic play Multi-cycle bioturbated drilling approach Best in class Willesden Green results command more capital Outperformed the industry average oil production per well for the past four years Adding incremental wells to our 2018 program, focus on short cycle returns Attractive Pembina acreage driven by large EUR & waterflood upside Integrated waterflood has stabilized decline rate Industry leading drilling practices Focus on fit for purpose well design Continuous improvement through partner collaboration and offset well monitoring 8

9 The Largest Land Holder in The Cardium Play Fairway R10W5 INDEX MAP Significant Inventory Upside Reserve book includes 129 highly confident locations Pembina Booked Locations 87 Additional Inventory 363 Total Inventory 450 T50 PEMBINA Willesden Green Booked Locations 42 Additional Inventory 208 Total Inventory 250 Total Inventory kms 10 miles T45 Reserves Summary Large light oil weighted reserves OBE Cardium WI Land Arc Baccalieu Bonterra Inplay Prairie Storm Ridgeback Tamarack Valley Whitecap Yangarra WILLESDEN GREEN T40 Units Pembina Willesden Green PDP MMboe Proved MMboe Proved + Probable MMboe P BTCF NPV10 $MM $877 $525 9

10 Watercut (%) Attractive Geology with Recovery Factor Upside 120% R10W5 INDEX MAP 100% 80% A Lease NPCU #1 Bear Lake Lobstick Carrot Creek PEMBINA T50 60% G Lease J Lease D Lease F Lease NWPCU #1 Easyford OBE WI Land Industry Peer Land PCU #11 PCU #9 J Lease NPCU #1 40% 20% Lodgepole PCU #11 Open Creek PCU #9 Faraway Rose Creek Paddy Creek Crimson Lake Large expected gain in recovery factors on OOIP with application of integrated waterflood approach 0% 0% 10% 20% 30% 40% Recovery Factor (%) T45 Geology 50+ years of drilling history 15 kms 10 miles WILLESDEN GREEN Units Pembina Willesden Green OOIP / Section MMbbl Zone depth m 1,500-1,800 2,200 OBE Cardium WI land OBE producing well Injectors Por >8%, Perm >0.2mD Best quality reservoir Industry Hz well Cardium trend Crimson Lake Type Rock Sandstone Sandstone Net Pay m Porosity % 11% 9% Permeability md

11 Variable Stratigraphy Across the Play Multi-Cycle Optionality for Bioturbated Drilling SW Lodgepole PCU #9 G Lease F Lease E-NE Pembina Conglomerate Clean sandstone Muddy bioturbated sand Sandy bioturbated mud Shale (stratigraphic seal) Erosional contact (unconformity) Transitional contact W West Crimson Primary Crimson Unit East Crimson Primary Faraway Open Creek E Willesden Green 11

12 Blending Integrated Waterflood with Primary Optionality Willesden Green Cardium Acreage Position R8W5 OBE unit land OBE Cardium WI land OBE producing well Injectors Waterflood cutoff WF quality reservoir Halo Cardium acreage Industry Hz well Cardium trend Crimson Lake Waterflood 100% Working Interest Portions of unit with un swept oil, suited to horizontal development resulting in top tier wells Crimson Lake WF Majority of Booked Inventory Crimson Lake Halo 10 kms 5 miles Open Creek T42 Crimson Lake Halo 100% Working Interest Large inventory of high IP primary development locations Faraway 100% Working Interest High quality reservoir with historical pressure support Wellbore placement in the bioturbated window targeting clean sands above Ferrier Faraway INDEX MAP Open Creek 79% Working Interest 3 Obsidian controlled units with high quality reservoir 12

13 Average Cumulative Oil Production / Well (MBBL) Exceeding Industry Average in Willesden Green Outperformed the industry average oil production per well for the past four years Consistently improving results year over year R7W5 Willesden Green Average Cumulative Oil by Year 60 T Waterflood Response 10 kms 5 miles OBE INDUSTRY OBE land 2017 OBE well 2017 industry well 2016 OBE well 2016 industry well 2015 OBE well 2015 industry well 2014 OBE well 2014 industry well T OBE INDUSTRY OBE INDUSTRY OBE INDUSTRY Months 13

14 Production (bbl/d) Willesden Green Results Command More Capital 4 well pad in Willesden Green Cardium onstream as of Jan. 3, Average IP boe/day per well (87% liquids) R8W5 WILLESDEN GREEN W5 Pad 2018 drilled or completed 2018 optionality 2018 non-op participated Industry wells Injectors OBE unit land OBE Cardium WI land WILLESDEN GREEN W5 Pad 2 well pad on stream Feb 20, Averaging 450 boe/day per well through March 4, 2018 Adding 3 incremental Willesden Green Cardium wells to our 2018 development and potentially more with asset disposition proceeds Recent Drills Above Type Curve Months on Production 2018 Primary Type Curve 5 kms 3 miles 2018 Type Curve Economics Inputs DCET Cost ($MM) $3.4 Production EUR (Mboe) 290 IP30 (boe/d) 250 IP365 (boe/d) 140 Liquids (%) 90% Economic Outputs NPV (10%) ($MM) $3.2 PIR (10%) 1.0 IRR (%) 66% Payout (years) 2.2 Capital Efficiency ($/boe/d) $24,500 F&D ($/boe) $11.30 T42 14

15 Reservoir Complexity in Pembina W5 Pad Pi 9,249 kpa Pi 17,471 kpa Pembina Cardium Unit # drilled or completed Future development Industry wells Injectors OBE unit land OBE Cardium WI land Pi 5,996 kpa 11,500 kpa pressure differential within a single section Highlights the key difference in reservoirs: Halo versus Infill Waterflood Each investment opportunity will come with a different production forecast and reservoir development plan to maximize recovery and optimize IRR and NVP 15

16 Average Cumulative Oil Production/well (BBL) Pembina Waterflood: Improving Decline and Well Performance Drilling with active injection support is improving well performance and economics Strong focus on waterflood management work from 2016/2017 arrested oil decline from 22% to 3% in PCU #9 2016/2017 PCU #9 WF Optimization Waterflood Improves Well Performance 10, ,000 Injection support on both flanks 500,000 Gas/Oil Ratio Stable 400,000 1,000 Oil Rate Stabilizes 300,000 No injection support 200, ,000 OBE - 100/ W5/0 100 Jan-16 Apr-16 Jul-16 Oct-16 Jan-17 Apr-17 Jul-17 Oct-17 Jan-18 Number of Wells (#) Oil Rate (bbl/d) Gas Rate (Mcf/d) Produced Water (bbl/d) Injected Water (bbl/d) GOR (scf/bbl) OBE - 102/ W5/ Months 16

17 Pro duction (bbl/d) Pembina Development Economics Driven by Large EUR Integrated waterflood approach improves recovery factor 5 kms 3 miles PEMBINA W5 Pad R10W5 PEMBINA W5 Pad 2018 drilled or completed Future Development Industry Wells Injectors OBE unit land OBE Cardium WI land T48 After 50+ years, resource and geology is delineated and well understood High-netback light oil production with low decline rate Intergrated Waterflood Type Curve Mo nths on Production 2018 Type Curve Economics Inputs DCET Cost ($MM) $4.0 Production EUR (Mboe) 300 IP30 (boe/d) 250 IP365 (boe/d) 210 Liquids (%) 87% Economic Outputs NPV (10%) ($MM) $5.0 PIR (10%) 1.6 IRR (%) 99% Payout (years) 1.9 Capital Efficiency ($/boe/d) $19,000 F&D ($/boe) $

18 $/Meter (Drilling) Evolving Our Development Strategy and Sharing with Industry Monobore Well Design in Willesden Green Well specific approach to manage costs Intermediate/Liner Well Design in Willesden Green Well specific approach to manage costs Cost savings in areas with lower pressure Without managed pressure drilling equipment can save up to $200k per well Minimal uphole mud losses and solid wellbore stability Intermediate casing required in higher pressure areas to minimize up hole losses Provide well bore stability Extensive pressure database review to minimize the use of MPD Avg Willesden Green Monobore Well Design Completion system Open Hole / Cemented Lateral length meters 1,850 Spacing meters 60 No. of stages # 30 Tonnage per stage t/s 25 Avg Willesden Green Intermediate/Liner Well Design Completion system Open Hole Lateral length meters 2,200 Spacing meters 85 No. of stages # 26 Tonnage per stage t/s 25 Data driven unique well designs Do not use a factory drilling approach Drilling Cost per meter performance in Willesden Green OBE 2015 OBE 2016 OBE 2017 OBE 2017 (Monobore) 18 $600 $500 $400 $300 $200 $100 $0

19 Production (boe/d) C R E T A C E O U S M A N N V I L L E SPIRIT RIVER Deep Basin Results are Liquids Rich First Deep Basin program executed on schedule and on budget Condensate volumes in the 2017 program exceeded expectations making gas pricing less relevant 100/ W5 On Production: 10/26/2017 Initial Rate: 3.9 MMCFD 100/ W5 On Production: 10/12/2017 Initial Rate: 3.4 MMCFD 10 kms 5 miles INDEX MAP R8W5 Falher B Trend OBE land OBE operated Cardium unit 100/ W5 On Production: 8/30/2017 Initial Rate: 3.2 MMCFD WILLESDEN GREEN T42 Two-mile Falher well expected to be on stream at the end of March, initial pressure metrics and production tests look encouraging Deep Basin Type Curve F O R M A T I O N BELLY RIVER COLORADO SHALE CARDIUM COLORADO SHALE NOTIKEWIN FALHER WILRICH GLAUCONTIC SANDSTONE OSTRACOD BEDS ELLERSLIE FERNIE SHALE ROCK CREEK Average Liquids Ratio 55 bbl/mmcf (135 bbl/d per well) >40 high confidence near term liquids rich locations Spirit River Type Curve Economics Inputs DCET Cost ($MM) $3.8 Production EUR (Mboe) 610 IP30 (boe/d) 660 IP365 (boe/d) 400 Liquids (%) 28% Economic Outputs NPV (10%) ($MM) $4.40 PIR (10%) 1.2 IRR (%) 65% Months on Production Payout (years) 1.6 Capital Efficiency ($/boe/d) $9,500 F&D ($/boe) $

20 Production R10 AB Viking Program Continues to Exceed Expectations R10 Monitor West GP Misty GP Compeer GP R1W4 Light-oil, high netback shorter cycle wells Esther GP T30 Infrastructure advantage with key owned and operated gas plants and minimal incremental facility spend Targeting structural lows offsetting top performing 2017 wells to maximize light oil productivity Jay signoff Months on Production Type Curve (boe/d) 15 kms 10 miles OBE gas plant OBE land 2018 Type Curve Economics Inputs DCET Cost ($MM) $1.6 Production EUR (Mboe) 74 IP30 (boe/d) 190 IP365 (boe/d) 100 Liquids (%) 57% Update Economics Economic Outputs NPV (10%) ($MM) $0.7 PIR (10%) 0.4 IRR (%) 45% Payout (years) 1.9 Capital Efficiency ($/boe/d) $15,500 F&D ($/boe) $21.15 INDEX MAP 20

21 Production PROP Program in the Heart of Harmon Valley South INDEX MAP OBE land Acquired land in 2017 PROP Harmon Valley R15W5 Large contiguous position in a crude oil resource highly amenable to conventional cold-flow production Strong initial results confirm optimism for 2018 plans in heart of Harmon Valley South Harmon Valley South Seal 15 kms T80 Cash flow torque to increasing oil price with significant long term inventory Successful in mitigating differential spreads by utilizing multiple sales points Gas Gathering Impact Months on Production Total Production (boe/d) Oil (bbl/d) 2018 Type Curve Economics Inputs DCET Cost ($MM) $2.7 Production EUR (Mboe) 363 IP30 (boe/d) 205 IP365 (boe/d) 200 Liquids (%) 85% Economic Outputs NPV (10%) ($MM) $2.5 PIR (10%) 0.9 IRR (%) 40% 0 Payout (years) 2.4 Capital Efficiency ($/boe/d) $13,500 F&D ($/boe) $ miles 21

22 Capital Efficiencies ($/boe/d) 2018 Capital Efficiency Buildup Program leverages the short cycle opportunity set in our portfolio Development Capital efficiencies of <$15,000/boe/d Total Capital efficiencies of <$25,000/boe/d Total 2018 Corporate Capital Efficiencies $/boe/d $30,000 $25,000 $86MM Development Capital <$25,000 $20,000 $20,000 $15,000 $14,000 $16,000 <$15,000 $10,000 $7,000 $8,000 $5,000 $0 Deep Basin Optimization PROP AB Viking Cardium Total 2018 Total 2018 Development Capital 22

23 Reducing Liability Through Legacy Asset Disposition January 2018 sale of a significant portion our non-core legacy assets in exchange for the assumption of abandonment and reclamation liabilities Legacy Asset Disposition Lands R1W5 INDEX MAP R20 R10 R1W4 SUGDEN Cash flow accretive based on opex savings and liquids weight Reduces discounted decommissioning liabilities, improves corporate netback Legacy Package OBE land T55 Midpoint of Production Guidance (boe/d) 40, ,500 2, ,500 30,000 $20.00 $15.00 Midpoint of Opex Guidance ($/boe) $13.75 $ 0.50 $13.25 T45 20,000 $ ,000 $5.00 BASHAW 0 100% 75% 2018E Previous Guidance Liquids Weight (%) 6 2 % Legacy Adjustment 2018E Prof orma Production 3% 6 5 % $250 $200 $150 $ E Previous Guidance Decommissioning Liabilities ($MM) $ Legacy Adjustment $ E Prof orma Opex $ WIMBORNE MIKWAN ALSASK T35 50% 25% $100 $50 45 kms 30 miles ACADIA T25 0% 2018E Liquids Weight Legacy Adjustment 2018E Prof orma Liquids Weight $0 Q Decommissioning Liabilities Legacy Adjustment Q Prof orma Decommissioning Liabilities 23

24 Reducing Liability Through Efficient Asset Retirement Program based abandonment Working with AER as part of the Portfolio Management Pilot on full field abandonment to realize efficiencies and further reduce decommissioning expense Conducting science based methodology Streamlines reclamation phase and trajectory towards reclamation Asset Retirement Operations Average Well Abandonment Cost ($/Well) Average Pipeline Abandonment Cost ($/km) Average Reclamation Cost ($/Hectare) $120,000 $100,000 $80,000 $60,000 $40,000 $20,000 $92,000 $20,000 $25,000 28% Decrease 20% Decrease 58% Decrease $15,000 $19,000 $20,000 $83,000 $15,000 $13,500 $12,000 $66,000 $14,000 $15,000 $10,000 $10,000 $8,000 $5,000 $5,000 $0 2015Corporate $ $

25 Why Obsidian Energy, Why Now? Balanced and disciplined operator Cost reduction track record; reduced Opex and G&A by $130 million and lowered net debt by $120 million in 2017 Cardium waterflooding, complemented with primary development, delivers sustainable liquids growth in the near and long term Deep inventory across key development areas 16% corporate base decline generates meaningful cash for reinvestment at leading finding and development costs Over 1,000 drilling prospects across key development areas Setting up for growth Kick-started a disciplined growth story that is well positioned for self funded 2019 cash flow expansion Robust drill-ready portfolio allowing quick capitalization on incremental free cash flow 25

26 Appendix

27 End Notes All slides should be read in conjunction with Definitions and Industry Terms, Non-GAAP Measure Advisory, Oil and Gas Disclosures Advisory and Forward-Looking Advisory Slide 3. Obsidian Energy Corporate Profile Daily Volume (shares) is the 30 day average share volume traded on Canadian and US Exchanges per Bloomberg. Production is based on Q results.. The net sections are approximate numbers and are internal estimates. Slide Reserves Highlight Revitalized Operations Delivery NAV Valuation is based on 2P NPV10 as prepared by our independent reserves evaluation (Sproule Associates Limited) as at year-end Net Debt and share count is as at year-end All numbers are rounded Slide 5. Low Decline Rate Underpins Growth Corporate base production and decline is based on actual data generated internally. Lines have been smoothed for illustrative effect to adjust for volatility inherent in day to day oil and gas operations. Capital efficiencies on optimization projects are internal estimates and rounded. Slide 6. Focused 2018 Plan Production, capital expenditures are based on internal estimates for Slide 7. Portfolio Optionality on Display Internal Rates of Returns are rounded and based on a blended Sep 30, 2017 strip price and independent reserves evaluator (Sproule Associates Limited) price deck Slide 8. Obsidian s Dominate Cardium Position 2P reserves was prepared by our independent reserves evaluation (Sproule Associates Limited) as at year-end Locations are internal estimates. Best in Class refers to industry average oil production per well for the past four consecutive years being above industry average Original Oil In Place (OOIP) means Discovered Petroleum Initially In Place (DPIIP) as at December 31, OOIP/DPIIP estimates and recovery rates are as at December 31, 2017, and are based on current accepted technology and have been prepared by internal geologists and reservoir engineers. DPIIP, as defined in the Canadian Oil and Gas Evaluations Handbook (COGEH), is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior to production. The recoverable portion of DPIIP includes production, reserves and contingent resources; the remainder is unrecoverable. There is significant uncertainty regarding the ultimate recoverability and the commercial viability to produce any portion of this OOIP/DPIIP. The Company s average working interest in the Cardium is 81%. Notwithstanding the uncertainty regarding recoverability of OOIP/DPIIP, the Company believes that it is the most appropriate measure to properly consider the effects of the integrated waterflood program, particularly the effect of changes to recovery factor on potential ultimate resource recovery. Slide 15. Reservoir Complexity in Pembina Pressure readings are actual pressure measurements Slide 16. Pembina Waterflood: Improving Decline and Well Performance Both charts are pulled from public data Slide 17. Pembina Development Economics Driven by Large EUR Economics are based on Ed Par - Cad$66.93/bbl in 2018, Cad$64.72/bbl in 2019, escalating through 2022 and AECO - C$1.67/Mcf in 2018, C$1.88/Mcf in 2019, escalating through 2021, Future development locations are locations are currently being evaluated for development Slide 18 Evolving Our Development Strategy and Sharing with Industry All Figures are internal estimates and rounded Slides 19, 20, 21 (Asset Slides) Economics are based on Ed Par - Cad$66.93/bbl in 2018, Cad$64.72/bbl in 2019, escalating through 2022 and AECO - C$1.67/Mcf in 2018, C$1.88/Mcf in 2019, escalating through 2021 Slide Capital Efficiency Buildup Capital efficiencies for each core area are based on capital spent in that area on new production adds, 12 month forward production average, on an capital weighted average basis and rounded. Corporate Capital efficiencies includes all capital spent, 12 month forward production average, on an capital weighted average basis and rounded. Slide 23. Reducing Liability Through Legacy Asset Disposition All figures are internal estimates. Slide 24. Reducing Liability Through Decommissioning Expense All figures are internal estimates and are rounded Slide 25. Why Obsidian Energy, Why Now? All Figures are internal estimates and rounded Slide 9. The Largest Land Holder in The Cardium Play Fairway Additional inventory is an internal estimate, reserves summary was prepared by our independent reserves evaluation (Sproule Associates Limited) as at year-end Slide 10. Attractive Geology with Recovery Factor Upside Geology statistics table contains internal estimates and number are rounded, See slide 8 ends notes on OOIP Slide 11. Variable Stratigraphy Across the Play Is for illustration only, represents the stratigraphy across the Cardium fairway play and is an internal estimate Slide 13. Exceeding Industry Average in Willesden Green Average Cumulative Oil by is public data pulled from IHS database. Industry average oil production per well data pulled from IHS database Slide 14. Willesden Green Results Command More Capital Economics are based on Ed Par - Cad$66.93/bbl in 2018, Cad$64.72/bbl in 2019, escalating through 2022 and AECO - C$1.67/Mcf in 2018, C$1.88/Mcf in 2019, escalating through 2021, Potential locations are locations are currently being evaluated for development in the back half of 2018 assuming more capital is spent in this area 27

28 Definitions and Industry Terms 1P means proved reserves as per Oil and Gas Disclosures Advisory 2P means proved plus probable reserves as per Oil and Gas Disclosures Advisory Av., Ave., Avg. means avearge A&D means oil and natural gas property acquisitions and divestitures A&D Adj. means oil and natural gas property acquisitions and divestitures BTCF means before tax cash flow Base means production with no additional production from new drilling bbl means barrel or barrels $BN means billions of dollars Bopd means barrel of oil per day boe and boe/d mean barrels of oil equivalent and barrels of oil equivalent per day, respectively Capital Expenditures & Capex includes all direct costs related to our operated and non-operated development programs including drilling, completions, tie-in, development of and expansions to existing facilities and major infrastructure, optimization and EOR activities Company or OBE means Obsidian Energy Ltd; as applicable DCET means drilling, completions, equip and tie-in costs Enviro means decommissioning expenditures E means estimate G&A means general and administrative expenses H2 mean second half of the year Hz means horizontal well Hz means horizontal well kpa means kilopascals IP means initial production, which is the average production over a specified time period IRR means Internal Rate of Return which is the interest rate at which the NPV equals zero IP means initial production, which is the average production over a specified time period IRR means Internal Rate of Return which is the interest rate at which the NPV equals zero km means kilometers Liquids % means the percentage of crude oil and NGLs from the total barrels of oil equivalent of production Liquids means crude oil and NGLs M or k means thousands m means meters md means millidarcy Mmcf means million cubic feet Mmcf/d means million cubic feet per day MM means millions NPV means net present value OOIP means original oil in place Opex means operating costs PCU Means Pembina Cardium Unit Pi means osmotic pressure POR means porosity Perm means permeability PIR means profit investment ratio PROP means Peace River Oil Partnership scf/d means standard cubic feet per day Spud mean the process of beginning to drill a well TD means total depth where drilling has stopped t/s means tonnage per stage WI means working interest WF means waterflood EUR means estimated ultimate recovery F&D means finding and development costs FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates Free Cash Flow, which is Funds Flow from Operations less Total Capital Expenditures FY means fiscal year N, S, E, W means the North, South, East, West or in any combination NAV means net asset value Net Debt means Senior Debt plus bank debt plus non-cash working capital deficit, detailed in the Non-GAAP measure advisory NGL means natural gas liquids which includes hydrocarbon not marketed as natural gas (methane) or various classes of oil 28

29 Non-GAAP Measures Advisory Non-GAAP measures advisory In this presentation, we refer to certain financial measures that are not determined in accordance with IFRS. These measures as presented do not have any standardized meaning prescribed by IFRS and therefore they may not be comparable with calculations of similar measures for other companies. We believe that, in conjunction with results presented in accordance with IFRS, these measures assist in providing a more complete understanding of certain aspects of our results of operations and financial performance. You are cautioned, however, that these measures should not be construed as an alternative to measures determined in accordance with IFRS as an indication of our performance. These measures include the following: Netback is a measure of cash operating margin on an absolute or per-unit-of-production basis and is calculated as the absolute or per-unit-of-production amount of revenue less royalties, operating costs and transportation. The measure is used to assess the operational profitability of the company as well as relative profitability of individual assets. For additional information relating to netbacks, including a detailed calculation of our netbacks, see our latest management's discussion and analysis which is available in Canada at and in the United States at and Net debt is the amount of long-term debt, comprised of long-term notes and bank debt, plus net working capital (surplus)/deficit. Net debt is a measure of leverage and liquidity 29

30 Reserves Disclosure and Definitions Any reference to reserves in this presentation are based on the report ("Sproule Report") prepared by Sproule Associates Limited dated January 29, 2018 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, For further information regarding the Sproule Report, see Appendix A to our Annual Information Form dated March 6, 2018 ("AIF"). 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. For additional reserve definitions, see "Notes to Reserves Data Tables" in our AIF. 30

31 Forward-Looking Information Advisory Certain statements contained in this presentation constitute forward-looking statements or information (collectively "forward-looking statements. 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 presentation contains, without limitation, forward-looking statements pertaining to the following: the expected recovery factors at various location with integrated waterflood approach; the addition of potential incremental wells to our 2018 program and focus on short cycle returns; potential assets sales to further high-grade the portfolio and re-deploy proceeds to different initiatives; the significant inventory upside of the Company and large light oil weighted reserves; the Original Oil in Place; the potential for high IP primary development locations; that certain locations are well suited to horizontal development resulting in top tier wells; that we will have high0netback light oil production with low decline rate; that the Company is using well specific approaches to manage certain costs; that Cardium waterflooding, complemented with primary development, delivers sustainable liquids growth in the near and long term; that the Company base decline generates meaningful cash for reinvestment at leading finding and development costs; and that the disciplined growth story is well positioned for self funded 2019 cash flow expansion. that adding reserves at just over $13 per boe through 2017 demonstrates a powerful engine to reward investors; our expected base decline rates for production in 2018 and 2019; that we are working with the AER as part of the portfolio management pilot on full field abandonment to realize efficiencies and further reduce decommissioning expenses; that conducting science based methodology in connection with abandonment streamlines reclamation phases and trajectory towards reclamation; our expected 2018 guidance for production, growth, total expenditures (including capital and decommissioning), operating expenses, when we expect wells to come on production, and projected liquids weightings; the payout time at certain locations; that we have a predictable & liquids weighted growth profile, the expected development capital percentage of Total Expenditures and that there is flexibility to expand the capital program in the second half of the year and extend the growth rate; the expected average internal rates of return and costs at the various locations; that the Willesden Green and Pembina 2018 programs are less capital intensive with higher rates of return; that drilling in the bioturbated rock and fracking into clean intervals above reduces drill complexity and costs; that there is drill optionality between several cycles based on reservoir quality; that in the Alberta Viking we are targeting structural lows in 2018 to maximize light oil productivity; that in Peace River the recent results confirm optimism for 2018 plans in heart of Harmon Valley South, and that there is cash flow torque to increasing oil price with significant long term inventory; our expected approach to development including the area-specific asset development plans; the timing and our expectations of such development activities; that the 2018 program leverages the short cycle opportunity set in our portfolio; the expected development capital efficiencies and total capital efficiencies on a location and Company wide basis; that the Cardium waterflooding, complemented with primary development, yields sustainable liquids growth in the near and long term; that we have the leading position in the Cardium, with one of the most attractive assets in the basin; that the analogous Cardium fields prove the upside secondary recovery; that corporate base decline generates meaningful cash for reinvestment at leading finding and development costs; the amount of drilling prospect across key development areas; that we have kick-started a disciplined growth story that is well position for self funded 2019 cash flow expansion; that there is a robust pipeline of drill ready prospects to quickly capitalize on incremental free cash flow; that one time legacy and regulatory costs roll off in the second half of 2018, freeing up cash for larger 2019 development capital allocation; that the integrated waterflood improves the recovery factor with our large reserve base; and that we will add more horizontal drilling. The key metrics for the Company set forth in this presentation may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial outlook and future-oriented financial information contained in this presentation are based on assumptions about future events based on management's assessment of the relevant information currently available. In particular, this presentation contains projected operational and financial information for 2018, 2019 and beyond for the Company. The future-oriented financial information and financial outlooks contained in this presentation have been approved by management as of the date of this presentation. Readers are cautioned that any such financial outlook and future-oriented financial information contained herein should not be used for purposes other than those for which it is disclosed herein. With respect to forward-looking statements contained in this document, we have made assumptions regarding, among other things: our ability to complete asset sales and the terms and timing of any such sales; the economic returns that we anticipate realizing from expenditures made on our assets; future crude 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 capital expenditure levels; future crude oil, natural gas liquids and natural gas production levels; drilling results; future exchange rates and interest rates; future taxes and royalties; the continued suspension of our dividend; our ability to execute our capital programs as planned without significant adverse impacts from various factors beyond our control, including weather, infrastructure access and delays in obtaining regulatory approvals and third party consents; 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; our ability to obtain financing on acceptable terms, including our ability to renew or replace our reserve based loan; our ability to finance the repayment of our senior secured notes on maturity; and our ability to add production and reserves through our development and exploitation activities. In addition, many of the forward-looking statements contained in this document are located proximate to assumptions that are specific to those forward-looking statements, and such assumptions should be taken into account when reading such forward-looking statements. Please note that illustrative examples are not to be construed as guidance for the Company and further details on assumptions can be found in the Endnotes section of the presentation. Although Obsidian Energy believes that the expectations and assumptions on which such forward-looking information is based are reasonable, undue reliance should not be placed on the forward-looking information because Obsidian Energy can give no assurances that they will prove to be correct. Since forward-looking information addresses future events and conditions, by its very nature it involves inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to a number of factors and risks. These include, but are not limited to: the risks associated with the oil and gas industry in general such as operational risks in development, exploration and production; the possibility that the semiannual borrowing base re-determination under our of our reserve-based loan is not acceptable to the Company or that we breach one or more of the financial covenants pursuant to our amending agreements with holders of our senior, secured notes; delays or changes in plans with respect to exploration or development projects or capital expenditures; the uncertainty of estimates and projections relating to reserves, production, costs and expenses; health, safety and environmental risks; commodity price and exchange rate fluctuations; interest rate fluctuations; marketing and transportation; loss of markets; environmental risks; competition; incorrect assessment of the value of acquisitions; failure to complete or realize the anticipated benefits of acquisitions or dispositions; ability to access sufficient capital from internal and external sources; failure to obtain required regulatory and other approvals; reliance on third parties; and changes in legislation, including but not limited to tax laws, royalties and environmental regulations. Readers are cautioned that the foregoing list of factors is not exhaustive. Additional information on these and other factors that could affect Obsidian Energy, or its operations or financial results, are included in the Company's most recently filed Management's Discussion and Analysis (See "Forward-Looking Statements" therein)), Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) and other reports on file with applicable securities regulatory authorities and may be accessed through the SEDAR website ( EDGAR website ( or Obsidian Energy's website. Unless otherwise specified, the forward-looking statements contained in this document speak only as of April 9, Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement. 31