Obsidian Energy Corporate Presentation March 2018
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, 2017. 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
Obsidian Energy Corporate Profile Cardium Meaningful Free Cash Flow Generation, Waterflood Approach with Primary Optionality 18,190 boe/d Q4 2017 Net Sections: 450 Peace River Manufactured Cold Flow, High Rate, Low Cost with Multiple Egress Options 4,963 boe/d Q4 2017 Net Sections: 235 Deep Basin Multi Horizon Potential Highly Economic Mannville Development 1,356 boe/d Q4 2017 Net Sections: 700 Share Price Feb. 28, 2018 OBE-TSX Daily Volume % of shares outstanding Corporate Metrics OBE -NYSE Daily Volume % of shares outstanding $/share $1.18 MM 1.5 0.3% MM 1.9 0.4% Market Capitalization $MM $595 Net Debt $MM $383 Enterprise Value $MM $978 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 $13.00 - $13.50 $2.00-$2.50 2,508 boe/d Q4 2017 Net Sections: 170 Legacy Asset Production of 4,429 boe/d in Q4 2017, Portion of OBE s legacy production sold in early 2018. See press release titled Obsidian Energy Announces Legacy Asset Disposition dated January 31 st for details See end notes 3
Developing a Track Record of Delivering Results Q4 2017 A&D Adj. Production boe/d FY 2017 Production boe/d 2017 Total Expenditures $MM 2017 Operating Expenses $/boe 34,000 30,500 Double Digit Growth 31,447 boe/d 32,000 31,500 Guidance Beat 31,723 boe/d $180 $160 $140 Total Capital Within Guidance $157MM $14.00 Operating Costs Within Guidance $13.40/boe $120 $13.50 27,000 31,000 $100 $80 23,500 30,500 Production Guidance 30,500-31,500 $60 $40 $20 Total Expenditures Guidance $160 $13.00 Operating Cost Guidance $13.00 - $13.50 20,000 Q4 2016 Q4 2017 30,000 $0 Total Expenditures Guidance $12.50 *Net of Peace River Guidance Carry 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) 504 504 Total NAV / Share $1.58 $2.63 140 120 100 80 60 40 20 0 Corporate Reserves Replaced 131% Replaced 121% 96 75 32 27 8 8 6 6 47 35 Light & M edium Crude Oil (mmbbl) Natural Gas Liquids (mm bbl) Replaced 126% 131 43 10 12 66 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 See end notes 5
Low Decline Rate Underpins Growth 16% Corporate Base Production Decline Rate Cardium Asset Under Historical Waterflood Capital Efficiencies of $6,500/boe/d on 2017 Optimization Projects Optimization of existing base wellbores Corporate Base Production boe/d 35,000 30,000 25,000 20,000 15,000 22% Base + 2017 Development Decline Rate 16% Base Decline Rate 2017 Base Production & 2017 Development Declines 16% in 2019 10,000 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Base Production 2017 Development 2018 Development See end notes 6
Focused 2018 Plan Predictable & Liquids Weighted Growth Profile Development Capital is 64% of Total Expenditures Flexibility to expand capital program in H2 and extend growth rate 2018 Production (boe/d) 29,000 30,000 boe per day 2018 Total Expenditures ($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 22,000 2018 Development $86 64% 20,000 2017E A&D Adjusted FY 2018E See end notes 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 25 20 15 21 AB Viking 4 PROP 4 10 Deep Basin 2 Cardium $50 58% 50% Av. IRR 5 0 Cardium 11 2018 Wells Spud See end notes 8
Production (bbl/d) Willesden Green Results Command More Capital WILLESDEN GREEN WILLESDEN GREEN 11-03-43-8W5 Pad R8W5 WILLESDEN GREEN 14-01-043-08W5 Pad 4 well pad in Willesden Green Cardium on-stream as of Jan. 3, 2018. Average IP30 650 boe/day per well (87% liquids) 10 kms 5 miles T42 2 well pad on stream Feb 20, 2018. Averaging 450 boe/day per well INDEX MAP OBE Operated Cardium land OBE producing well Industry HZ well Adding 3 incremental Willesden Green Cardium wells to our 2018 development 450 400 350 300 250 200 150 100 50 Recent Drills Above Type Curve 0 0 6 12 18 24 30 36 42 48 Months on Production Select 2018 Metrics DCET Cost ($MM) $3.3 IRR (%) >50% Capital Efficiency ($/boe/d) $21,000 2017 Analyst Day Type Curve Economics Waterflood Inputs Type I DCET Cost ($MM) $6.5 Incremental Water Cost ($/bbl water) $0.20 Production EUR (Mboe) 545 IP30 (boe/d) 340 IP365 (boe/d) 265 Liquids (%) 80% Economic Outputs NPV (10%) ($MM) $5.0 PIR (10%) 0.8 IRR (%) 35% Payout (years) 2.5 Capital Efficiency ($/boe/d) $24,500 F&D ($/boe) $11.95 See end notes 9
Multi-Cycle Bioturbated Drilling Drilling in the bioturbated rock and fracking into clean intervals above reduces drill complexity and costs Bioturbated Drilling Activity 50 wells since 2014 in Willesden Green R9 R7W5 2 Operated primary wells for 2018 T43 Drill optionality between several cycles based on reservoir quality 5 kms 3 miles T42 Ability to target multiple cycles throughout a single drill path OBE Operated Cardium unit OBE Cardium land OBE Bioturbated Drilling Activity T41 Multi-Cycle Bioturbated Gamma Ray Grain Size Conglomerate Fracs Cardium D Bioturbated Window Bioturbated Window Cardium C Bioturbated Window Cardium B Bioturbated See end notes 10
Production Dominating Pembina Acreage R11W5 PEMBINA OBE Cardium land OBE land OBE producing well Industry HZ well 15 kms 10 miles Integrated waterflood approach improves recovery factor After 50+ years, resource and geology is delineated and well understood PEMBINA 8-25-47-9W5 Pad T50 INDEX MAP High-netback light oil production with low decline rate 200 180 160 140 120 100 80 Select 2018 Metrics DCET Cost ($MM) $3.5 IRR (%) >50% Capital Efficiency ($/boe/d) $19,000 2017 Analyst Day Type Curve Economics Waterflood Inputs Type I DCET Cost ($MM) $6.3 Incremental Water Cost ($/bbl water) $0.20 Production EUR (Mboe) 530 IP30 (boe/d) 185 IP365 (boe/d) 150 Liquids (%) 89% 60 40 20 Economic Outputs NPV (10%) ($MM) $6.1 PIR (10%) 1.0 IRR (%) 35% 0 0 6 12 18 24 30 36 42 48 Months on Production Payout (years) 3.1 Capital Efficiency ($/boe/d) $42,000 F&D ($/boe) $11.80 See end notes 11
Production R10 AB Viking Program Continues to Exceed Expectations R10 Monitor West GP Misty GP Compeer GP R1W4 Light-oil, high netback shorter cycle wells Esther GP T30 Infrastructure advantage with key owned and operated gas plants and minimal incremental facility spend Targeting structural lows offsetting top performing 2017 wells to maximize light oil productivity 200 180 160 140 120 100 80 60 40 20 0 0 6 12 18 24 30 36 42 48 Months on Production Total Production (boe/d) Liquids Production (bbl/d) 15 kms 10 miles OBE gas plant OBE land 2017 Analyst Day Type Curve Economics Inputs DCET Cost ($MM) $1.5 Production EUR (Mboe) 75 IP30 (boe/d) 175 IP365 (boe/d) 95 Liquids (%) 51% Economic Outputs NPV (10%) ($MM) $0.7 PIR (10%) 0.4 IRR (%) 50% INDEX MAP Payout (years) 1.7 Capital Efficiency ($/boe/d) $15,500 F&D ($/boe) $20.00 See end notes 12
Production (boe/d) PROP Program in the Heart of Harmon Valley South Large contiguous position in a crude oil resource highly amenable to conventional cold-flow production Strong initial results confirm optimism for 2018 plans in heart of Harmon Valley South Cash flow torque to increasing oil price with significant long term inventory Successful in mitigating differential spreads by utilizing multiple sales points 250 200 150 100 50 INDEX MAP OBE land Acquired land in 2017 PROP Harmon Valley Harmon Valley South R15W5 2017 Analyst Day Type Curve Economics Inputs DCET Cost ($MM) $2.8 Production EUR (Mboe) 400 IP30 (boe/d) 215 IP365 (boe/d) 210 Liquids (%) 93% Economic Outputs NPV (10%) ($MM) $2.6 PIR (10%) 0.9 IRR (%) 50% Seal 15 kms 10 miles T80 0 0 6 12 18 24 30 36 42 48 Months on Production Payout (years) 2.6 Capital Efficiency ($/boe/d) $13,500 F&D ($/boe) $7.00 See end notes 13
Gas Production (Mcf/d) Deep Basin Results are Liquids Rich First Deep Basin program executed on schedule and on budget Condensate volumes in the 2017 program exceeded expectations making gas pricing less relevant 100/02-03-044-09W5 On Production: 10/26/2017 Initial Rate: 3.9 MMCFD 100/02-07-043-07W5 On Production: 10/12/2017 Initial Rate: 3.4 MMCFD 10 kms 5 miles INDEX MAP R8W5 Falher B Trend OBE land OBE operated Cardium unit 100/14-30-043-07W5 On Production: 8/30/2017 Initial Rate: 3.2 MMCFD WILLESDEN GREEN T42 Two-mile Falher well expected to be on stream at the end of March, initial pressure metrics and production tests look encouraging 7,000 Average Liquids Ratio 55 bbl/mmcf (135 bbl/d per well) 2017 Analyst Day Type Curve Economics Inputs DCET Cost ($MM) $4.0 6,000 5,000 4,000 3,000 2,000 1,000 Select 2018 Metrics DCET Cost ($MM) $4.0 IRR (%) 80% Liquids (%) 22% Capital Efficiency ($/boe/d) $7,000 Production EUR (Mboe) 720 IP30 (boe/d) 1,030 IP365 (boe/d) 620 Liquids (%) 19% Economic Outputs NPV (10%) ($MM) $3.4 PIR (10%) 0.9 IRR (%) 60% 0 0 6 12 18 24 30 36 42 48 Months on Production Payout (years) 1.5 Capital Efficiency ($/boe/d) $6,500 F&D ($/boe) $5.50 See end notes 14
Capital Efficiencies ($/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 See end notes 15
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) 40,000 3 1,500 2,000 2 9,500 30,000 $20.00 $15.00 Midpoint of Opex Guidance ($/boe) $13.75 $ 0.50 $13.25 T45 20,000 $10.00 10,000 $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 $0.00 2018E Previous Guidance Decommissioning Liabilities ($MM) $ 1 7 0 Legacy Adjustment $ 2 3 2018E Prof orma Opex $ 1 4 7 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 $0 Q4 2017 Decommissioning Liabilities Legacy Adjustment Q4 2017 Prof orma Decommissioning Liabilities See end notes 16
Reducing Liability Through Efficient Asset Retirement Program based abandonment Working with AER as part of the Portfolio Management Pilot on full field abandonment to realize efficiencies and further reduce decommissioning expense Conducting science based methodology Streamlines reclamation phase and trajectory towards reclamation Asset Retirement Operations Average Well Abandonment Cost ($/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 2016 2017 $0 2015 2016 2017 $0 2015 2016 2017 See end notes 17
Why Obsidian Energy, Why Now? Balanced and disciplined operator Track record of lowering costs; stripped out $130 million of Opex and G&A in 2017 alone and lowered net debt by $120 million Prudent infrastructure investment and liability management Cardium waterflooding, complemented with primary development, yields sustainable liquids growth in the near and long term Deep inventory across key development areas Leading position in the Cardium, one of the most attractive assets in the basin. Larger land footprint than # 2 & 3 combined Analogous Cardium fields prove the upside of secondary recovery 16% corporate base decline generates meaningful cash for reinvestment at leading finding and development costs Over 1,000 drilling prospects across key development areas Unique entry point in our story Kick-started a disciplined growth story that is well positioned for self funded 2019 cash flow expansion Robust pipeline of drill ready prospects to quickly capitalize on incremental free cash flow One time legacy and regulatory costs roll off in second half 2018, freeing up cash for larger 2019 development capital allocation 18
Appendix
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 Q4 2017 results.. The net sections are approximate numbers and are internal estimates. Slide 5. 2017 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 2017. Net Debt and share count is as at year-end 2017. All numbers are rounded Slide 6. 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 7. Focused 2018 Plan Production, capital expenditures are based on internal estimates for 2018. Slide 8. 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 9. Willesden Green Results Command More Capital Economics are based on Investor day presentation and are internal estimates WTI - US$52/bbl in 2017, US$53/bbl in 2018, escalating through 2021 & AECO - C$2.90/Mcf in 2017, C$2.65/Mcf in 2018, escalating through 20. Select 2018 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 10. Bioturbated Drilling Bioturbated chart is for illustration only. Wells labeled Bioturbated are wells that had a strategy to target the bioturbated interval before drilling. Slides 11, 12, 13 & 14 (Asset Slides) Economics are based on Investor day presentation and are internal estimates WTI - US$52/bbl in 2017, US$53/bbl in 2018, escalating through 2021 & AECO - C$2.90/Mcf in 2017, C$2.65/Mcf in 2018, escalating through 20 Select 2018 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 15. 2018 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 16. Reducing Liability Through Legacy Asset Disposition All figures are internal estimates. Slide 17. Reducing Liability Through Decommissioning Expense All figures are internal estimates and are rounded 20
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 Base means production with no additional production from new drilling bbl means barrel or barrels $BN means billions of dollars Bopd means barrel of oil per day boe and boe/d mean barrels of oil equivalent and barrels of oil equivalent per day, respectively Capital Expenditures & Capex includes all direct costs related to our operated and non-operated development programs including drilling, completions, tie-in, development of and expansions to existing facilities and major infrastructure, optimization and EOR activities Company or OBE means Obsidian Energy Ltd; as applicable DCET means drilling, completions, equip and tie-in costs Enviro means decommissioning expenditures E means estimate EUR means estimated ultimate recovery F&D means finding and development costs FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates Free Cash Flow, which is Funds Flow from Operations less Total Capital Expenditures FY means fiscal year G&A means general and administrative expenses H2 mean second half of the year Hz means horizontal well 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 Mmcf means million cubic feet Mmcf/d means million cubic feet per day M means meters MM means millions 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 NPV means net present value Opex means operating costs PCU #9 Means Pembina Cardium Unit number 9 PIR means profit investment ratio PROP means Peace River Oil Partnership TD means total depth where drilling has stopped Spud mean the process of beginning to drill a well WI means working interest 21
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 www.sedar.com and in the United States at www.sec.gov; 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 22
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, 2017. 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. 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. 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. 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 nonproducing. 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. 23
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: 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 futureoriented 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 semi-annual 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 (www.sedar.com), EDGAR website (www.sec.gov) or Obsidian Energy's website. Unless otherwise specified, the forward-looking statements contained in this document speak only as of March 12, 2018. 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. 24