Obsidian Energy Corporate Presentation
February 2019 Important Notice to the Readers
This presentation should be read in conjunction with the Company’s unaudited consolidated financial statements, Management's Discussion and Analysis ("MD&A") for the three and nine months ended September 30, 2018. 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 & Endnotes at the end of this presentation for further details regarding these matters. All slides in this presentation should be read in conjunction with “Definitions and Industry Terms”, “Non-GAAP Measure Advisory”, “Oil and Gas Information Advisory”, “Reserves Disclosure and Definitions Advisory” and “Forward-Looking Advisory”. Unless noted otherwise, the pricing assumption for slide 3 are applicable for all the of the slides. All locations are considered to be Unbooked locations unless otherwise noted.
2 Corporate Overview
Market Summary Peace River Ticker Symbol OBE Cold flow heavy oil Manage base production and Shares Outstanding MM 507 commercialize
Market Value MM $269
Net Debt MM $446 Enterprise Value MM $715 Deep Basin Liquids rich deeper development underlying Cardium Corporate Summary Infrastructure capacity management and opportunistic partnering Q3 2018 Production boe/d 27,777
Reserves (2P YE 2018) mmboe` 125
RLI (2P YE 2018) years 13
PDP Decline (YE 2018) % 16
NPV10 (2P YE 2018) MM $1,702 2019 Guidance Cardium Production boe/d 26,750 – 27,750 Light oil conventional development Manufacturing model for exhaustive, Capital Expenditures repeatable inventory MM $120 Inc. Decommissioning Leverage shallow decline base Alberta Viking Production Growth % Flat Higher GOR oil play Operating Costs $/boe $14.00 - $14.50 Strategy is base production management and General & commercialization $/boe $2.00 - $2.50 Administrative
3 Our Strategic Priorities
1. Generate meaningful YoY Cash Flow Growth • Target annual cash flow per share growth 10-15% • Driven by high-graded investment metrics Disciplined (IRR’s >50%, Capital Efficiency $20,000 /boe/d)
2. Improve balance sheet strength • Maintain capital discipline to improve debt picture through spending within Funds Flow from Operations Relentless • Target Debt/EBITDA to 1.5X over coming 2-3 years
3. Simplify and grow the light oil business • Through targeted investment, grow Cardium light oil platform >20% over 3 years • Continue to rationalize the portfolio to Accountable reduce drag on cash flow • Maintain 33 operated secondary recovery projects to support top tier corporate decline (25-35%)
4 The Cardium Advantage Willesden Green H2 2018 Program Summary Actuals exceeding forecast Crimson Lake
R8W5 INDEX MAP Rig One 1 8-9 Pad (3 Wells): IP60 477 boepd (71% oil) 2 14-1 Pad (2 Wells): IP60 338 boepd (84% oil) 3 1-36 Pad (2 Wells): IP30 672 boepd (90% oil) 3 kms 4 9-2 Pad (2 Wells): IP10 502 boepd (90% oil) 2 miles
Rig Two
1 4-6 Pad (3 Wells): IP60 563 boepd (84% oil) T43 2 5-18 Pad (2 Wells): Fracturing complete 2 4500 H2 2018 Program Forecast 1 4000 H2 2018 Program Actuals 4 3500 2 3000 1
2500 3
BOE/d 2000 OBE 2020 well OBE 2019 well 1500 OBE 2019 optionality well OBE 2018 well 1000 OBE future well Unit land OBE Cardium WI land 500 On Production OBE East Crimson land 0 Sep-18 Dec-18 Mar-19 Jun-19 Sep-19 6 8-9 Cardium Pad (3 wells) Oct 18, 2018 Simultaneous Operations
Flowback Tanks Flare stack Frac Pumps Testers
Water Supply Crane for Coiled Tubing Lubricator
Data Van Coiled Tubing Unit Sand Haulers
Chem Van
Nitrogen Units Communication
Shale cheaper than mats
Wellsite Trailer Wet conditions
7 Revitalization of the Cardium Play
Historical Cardium Pool Historical Cardium Pool Historical Willesden Green Oil Production (bbl/d) Total Well Count (#) Cumulative Oil Production (Mbbl/d) 180,000 7,000 Horizontals 80 Horizontals Deviated 160,000 Deviated 70 6,000 Verticals 140,000 Verticals 60 5,000 120,000 Introduction of horizontal 50 100,000 technology has 4,000 awoken the giant 40 80,000 3,000 30 60,000 2,000 20 40,000
2014 - OBE 26 Wells 2014 - Industry 56 Wells 1,000 2015 - OBE 29 Wells 2015 - Industry 17 Wells 20,000 10 2016 - OBE 3 Wells 2016 - Industry 5 Wells 2017 - OBE 5 Wells 2017 - Industry 22 Wells 2018 - OBE 13 Wells 2018 - Industry 36 Wells 0 0 0 0 20 40 60 Months
The Cardium remains one of the premier plays in the Western Canadian Sedimentary Basin with six decades of production history and significant remaining untapped potential
8 The Broader Cardium Opportunity Value proposition is unique to each area
12 Month Cumulative Oil (Mbbl) per well Pembina Cardium Hz well Willesden Green Cardium Hz well OBE ‘17/ H1 ’18 R5W5 Ferrier Cardium Hz well Willesden Green OBE Crimson Lake well 50 OBE Cardium WI land Peer lands 40 Pembina Recent Oil rates Willesden Pembina 2,337 Wells 30 Green that far exceed Ferrier 20 horizontal wells drilled to date 10
0 12 Month Cumulative Gas (MMcf) per well 400 Ferrier
300 Development focused on T45 Willesden Willesden Green 200 Green oil-prone or 428 Wells OBE ‘17/ H1 ’18 flood- 100 Willesden Green Pembina supported Ferrier 286 Wells 0 reservoirs 12 Month Cumulative Production (boe/d) per well 80 Ferrier OBE ‘17/ H1 ’18
11 Willesden Green
- 12 - 60 Willesden Green Balanced
Ferrier 6 Ferrier Pembina WG 14 WG 40 production with top quartile 15 kms 20 10 miles recent results 0 9 Breaking Down the Cardium Play Fairways - A Large High-graded Inventory West Pembina Central Pembina
R10W5 INDEX MAP • Well established • Individual fairways and productive trend unit boundaries in significantly de-risked by historically pressure major Cardium players supported properties • Halo underdeveloped • Ability to waterflood for acreage minimal capital through West • Easy access to existing existing infrastructure Pembina OBE facilities with egress • Technical de-risking Central through geo-modelling Pembina 132 171 Type Curve Locations Type Curve Locations
Crimson Lake East Crimson T45 • Banked oil from historical • Continued Eastward
pressure maintenance 15 kms extension of Crimson • Top quality reservoir Lake development 10 miles previously ignored by East program vertical development Crimson Crimson • De-risked by new • Recent top quartile Lake competitor drilling in results 2018 • Existing flexible and • Existing flexible and OBE Cardium WI land scalable infrastructure Peer lands scalable infrastructure 59 448 type curve assigned locations 86 Type Curve Locations 600+ total identified inventory Type Curve Locations 126 YE 2018 Booked Cardium Locations 10 Crimson Lake
The Obsidian Energy flag pole for revitalized primary development on our Cardium acreage
• Banked oil from historical pressure maintenance in WGCU#9 • Top quality reservoir previously ignored by historical development due to topographic and infrastructure challenges for vertical drilling Crimson Lake
• Recent top quartile results from 2018 program R8W5 INDEX MAP • Existing flexible and scalable infrastructure at the Crimson 13-27 Facility with optionality to East Crimson
Crimson Lake Statistics 517 bopd, 09/17 OBE 40% Total Acreage (gross sections) 89.25
T43 Current Production (boe/d) 7,200
AveragePotential Working inventory Interest (%) build up89% 5 kms
with tiers? 3 miles WGCU#9 2018 YE 2P Booked Locations (#) 36 OBE 2020 well OBE 2019 well OBE 2019 optionality well OBE 2018 well Inventory shown on map (#) 59 OBE future well Peer well Unit land OBE Cardium WI land OBE East Crimson land
11 Crimson Lake Economics
Type Curve Rate vs Time Cost Inputs Cumulative Oil vs. Time 2,200m 2,600m 900 180 Drill & Complete $MM $3.2 $3.5 Equip & Tie $MM $0.5 $0.5 800 160 Total $MM $3.7 $4.0 H2 2018 Program IP30: (10 of 14 wells) 700 - 105% of average type-curve oil-rate 140 Economics - 100% of boe rate EUR Mboe 180 210 600 120 Oil IP30 bbl/d 410 484 Total IP30 boe/d 532 627 500 100 Oil IP365 bbl/d 157 186 Total IP365 boe/d 243 286 400 80 2,600m Type Curve
300 2,200m Type Curve 60 Production Production Rate (boe/d)
H2 2018 Program Average IP30 Cumulative Prod (mboe) NPV BTAX 10% $MM $2.0 $2.7 200 40 PIR 10% x 0.5 x 0.7 x
IRR % 90% 120% 100 20 Payout years 0.9 0.8
12M Efficiency $/boe/d $15,500 $14,000 0 0 F&D $/boe $20.75 $19.10 0 12 24 Months H2 2018 Program Average Well Cost (DCET) $3.6 MM (6% under average type-well cost)
12 Drilling Longer Wells, Efficiently
OBE Intermediate Wells Well Length 0 • Drilling two mile wells reduces fixed 2015 Wells drilling costs Surface Casing 2016 Wells • Mobilization 2017 Wells • Construction 1,000 2018 Wells • Infrastructure • Longer wells have proportionally higher rates and EUR
Intermediate Casing 2,000 Faster Drilling Drilling Speed Technical improvements and • High speed motors and optimized drill quicker parameters improve rate of penetration connections • Modelled and standardized well planning 3,000 for reservoir quality and lateral placement for fast drilling • Single bit laterals
MEASURED DEPTH (M) MEASURED Longer Laterals 4,000 Lower cost Drilling Time per section & higher resulting production rates • Monobore drilling in suitable areas to Total Depth reduce total drill time 5,000 • Reduced “flat time” and increased operational efficiency • Area development focus reduces Less Days Drilling: mobilization time Sticky savings if rates increase
6,000 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 DAYS 13 Optimized Well Design to Maximize the Economics of our Acreage Inter-well Spacing Inter-frac Spacing Lateral Length IRR & NPV Decisions IRR & NPV Decisions IRR & NPV Decisions
IRR
NPV
IRR
NPV
NPV Optimal frac Optimal economics spacing implies implies 4-5 wells CutoffPractical 30-35 stages for a IRR per section 2,600m well Lateral lengths beyond 3,000 m limited by mineral land configurations and weight on bit
0 250 500 750 1,000 1,250 1,500 0 50 100 150 200 250 1,000 1,500 2,000 2,500 3,000 Inter-well Spacing (meters) Inter-frac Spacing (meters) Well length (meters) • Tight interwell spacing • Ideal well economics require • Fixed costs of construction, erodes per well EUR modelled frac spacing drilling, and infrastructure economics assuming impact economics • Higher quality reservoir reasonable primary displays less production • Well length is limited by recovery factors variation with frac spacing rate of penetration and than lower quality reservoirs land continuity
14 Crimson Lake Cost Reduction Trajectory
Drill, Complete, Equip & Tie-In Costs $ thousands Surveying $3,700 ($10) ($20) ($150) Large program brings cost efficiency and flexibility
($150) Construction Reuse of existing pads, multi- well padsites constructed ($60) during dry periods ($10) $3,300 Drilling Monobore, drill parameters, single bit runs, multi-well pads mitigate rig move costs Capital Efficiency is a key element to our economic success Completions Mitigating coil use, pads Team is targeting a 10% reduction in mitigate mobilization costs, type well costs for our 2019 activity surface water lines, frac price negotiations H2 2018 wells coming in under type Site Facilities curve cost estimates thus far Leverage existing infrastructure & inventory
Crimson Survey Construct Drill Complete Wellsite Artificial 2019 Lake Facilities Lift Crimson 2,200m Lake Type Target Curve 15 East Crimson
Moving the Crimson success eastward and onward • Continued Eastward extension of the Crimson Lake development program • Area has been de-risked by recent drilling results supporting the revitalized development • Shared and scalable infrastructure with the Crimson Lake program East Crimson • Combination of pressure supported edge drilling R8W5 INDEX MAP and underdeveloped unit fairways
East Crimson Statistics
Total Acreage (gross sections) 54.71 T43
Current Production (boe/d) 1,750 WGCU#1
Average Working Interest (%) 82% WGCU#2 5 kms
WGCU#6 3 miles 2018 YE 2P Booked Locations (#) 19
OBE 2019 well Inventory shown on map (#) 86 OBE future well WGCU#3 Unit land OBE Cardium WI land OBE Crimson Lake land
16 Targeting Oil Banks in Historic Waterflood Targeting Oil Banks Horizontal development in pressure maintained fields like East Crimson has R6W5 two key target types: WGCU#1
• Banked oil on area edges where legacy drilling has failed to capture reserves
• Underdeveloped fairways within the 164 bopd WGCU#2 secondary recovery area where 02/18 T42 existing vertical well spacing has
181 bopd insufficient recovery 06/17 252 bopd 04/18 Keys To Success 226 bopd 04/18 474 bopd Recent production by peers has verified 07/18 the modelling in the area and further 482 bopd supports inventory 03/18
WGCU#9 380 bopd 12/17 WGCU#3 • Understanding reservoir fluid and movement over time through reservoir 405 bopd WGCU#6 473 bopd 09/17 08/18 modelling to find underdeveloped fairways
High cum OBE 2019 well oil recovery Future OBE well 5 kms • Horizontal well placement closer to Peer well Unit land 3 miles production (away from injection) to OBE Cardium WI land prevent water production
Low cum oil recovery • Utilize infield infrastructure to reduce capital costs 17 West Pembina
Proven oil rich Cardium trend with undeveloped primary development acreage • Significant offsetting production from established Cardium players throughout the West side of Pembina • Underdeveloped halo and core acreage West Pembina • Existing flexible and scalable infrastructure with
significant available capacity in multiple facilities R10W5 INDEX MAP • Additional uncaptured inventory in non-operated CCU#5 units in Northern area CCU#4
PCU#11
West Pembina Statistics CCU#1
Total Acreage (gross sections) 85.14
Current Production (boe/d) 2,850 T48
Average Working Interest (%) 59%
2018 YE 2P Booked Locations (#) 38
OBE 2019 optionality well Inventory shown on map (#) 132 OBE future well 5 kms Unit land OBE Cardium WI land 3 miles OBE Central Pembina land
18 Central Pembina
The epicenter of low decline and pressure maintained development
• Strong technical model is the foundation for additional development from unswept fairways • Ability to de-risk through geological and reservoir modelling Central Pembina • Proven and booked waterflood response as the PBLCU#1 foundation for growth INDEX MAP R10W5 • Ability to grow waterflood scale through existing wells and infrastructure for minimal capital cost allows for corporate decline maintenance PECU1
Central Pembina Statistics CCU#3 PCU#14
Total Acreage (gross sections) 200.82 PCU#4 NWPCU#1
Current Production (boe/d) 6,700 T48 PCU#31
Average Working Interest (%) 91% PCU#9
2018 YE 2P Booked Locations (#) 56 5 kms
3 miles PCU#3
Inventory shown on map (#) 171 OBE future well Unit land OBE Cardium WI land OBE West Pembina land
19 Cardium 3 Year Forecast • Cardium on its own is self funded and generates >$60MM of Free Cash Flow per year • Growing the Cardium by >20% with depth of inventory to back fill higher price scenario • Cardium feeds the rest of the business with high netbacks at strip
R10W5 3 Year Production Range boe/d ~50% Self Funded Cardium 35,000 growth with improved pricing 30,000
T50 25,000
Pembina 20,000 ~20% Self Funded Cardium Growth on Strip 15,000 2018 2019 2020 2021 Improved Pricing Optionality Cardium Production 3 Year NOI and Free Cash Flow T45 $MM 15 kms $400 Generates >$60MM of Free Cash 10 miles Flow per year & ~$200MM in 3 year $300 outlook Willesden Green $200
$100 OBE Cardium well OBE Cardium WI land Peer lands $0 2019 2020 2021 Cardium NOI Improved Pricing Optionality Cumulative FCF Cumulative FCF Optionality 20 Other Assets Deep Basin & Peace River
21 Deep Basin: Company Under a Company
Unit land • Ownership in key plant and R8W5 OBE below Base Cardium land OBE Cardium WI land pipeline infrastructure allows for development and operational Bigoray synergies with Cardium program 15 kms
Carrot 10 miles Creek • Competitive economics with liquids-rich gas and oil production development
T48 potential
Alder Flats • Large, high working interest 2019 - 2 well land base with significant multi- Upper Mannville program horizon inventory optionality
Willesden Green
2019 2 Well Upper Mannville Program Immediate cost savings by utilizing existing pad sites, surface infrastructure & operational proximity
22 Mannville Falher Type Curve
Type Curve Rate vs Time Cost Inputs Cumulative Oil vs. Time Drill & Complete $MM $3.0 500 300 Equip & Tie $MM $0.8 450 Total $MM $3.8 250 400 Production 350 200 EUR Mboe 400 300 Oil IP30 bbl/d 106 250 150 Total IP30 boe/d 410 200 Oil IP365 bbl/d 101 100 Total IP365 boe/d 414 150
100 Cumulative Prod (mboe) 50 Economics Production Rate (boe/d) 50 NPV BTAX 10% $MM $1.8 0 0 PIR 10% x 0.5 x 0 12 24 36 IRR % 40% Months Payout years 1.7 12M Efficiency $/boe/d $9,500 Mannville 2019 Falher Parameters F&D $/boe $9.60 Net Pay (m) 15-20
Porosity (%) 8 High Rate, Liquids Rich Play Water saturation (%) 30 CGR (Bbl/MMcf) 10-60
Spirit River Inventory Locations (#) 40
2018 YE 2P Booked Locations (#) 2
23 Large Peace River Presence
• Stable, heavy cold-flow oil base production R19W5 Cold Flow Inventory Total Locations 251 • Contiguous and extensive acreage with ample inventory Rainbow pipeline • Simultaneous operations and multi-leg, open- (WCS price Nampa hole drilling have resulted in 25% savings in exposure) well drilling costs since 2017 • Recent wells are exceeding historical results T85
Cadotte Marketing History (%) WCS/Seal PSO Rail Rainbow 100% R a il pipeline R a il R a il (WCS 75% Walrus price exposure) 50% PSO PSO PSO 25% HV W CS/Seal W C S/Seal W CS/Seal Main Seal 0% HV Q1 Q2 Q3 Nampa rail South 2018 2018 2018 terminal All-in Realized Pricing (C$/bbl) $50
$40
10 kms $30 5 miles Trucked to numerous WCS/Seal $20 locations on Peace pipeline Tiered inventory PSO Rail (PSO price exposure) Contingency inventory OBE Peace River WI land $10 OBE Blended Q1 Q2 Q3 2018 2018 2018
See end notes 24 Why invest in Obsidian Energy?
Significant rate of change in cash flow 10-15% Largest CAGR Cardium Flexibility to Development Ample acreage manage drilling infrastructure holder with a commodity catalysts head room low decline volatility base Simple, streamlined conventional light oil champion
25 Appendix & Endnotes
26 Asset Retirement Obligation Improvement
Legacy Abandonment 2019-2031
• OBE elected to participate in the AER’s ABC program to demonstrate a disciplined effort to reduce exposure to the costs of its Legacy portfolio
• OBE Legacy properties are scattered across Focusing our 2019 Alberta ABC efforts in the Wainwright area. • Expect to involve 2-3 fields per year ABC • Expected to reduce the average cost of abandoning these wells by approximately 30% on a program basis
Avg Well Abandonment Cost Avg Pipeline Abandonment Cost Avg Reclamation Cost $ / well $/km $/Hectare
$120,000 $20,000 $25,000 57% Decrease 33% Decrease $100,000 $20,000 58% Decrease $15,000 $80,000 $15,000 $60,000 $10,000 $10,000 $40,000 $5,000 $20,000 $5,000
$- $- $- 2015 2016 2017 2018 ABC 2015 2016 2017 2018 ABC 2015 2016 2017 2018 ABC 2019E 2019E 2019E 27 Management Team
Mr. French, joined Obsidian Energy on October 2016. Prior to joining the Company, Mr. French served as President and CEO of Bankers Petroleum Ltd. Prior to joining Bankers in 2013, Mr. French held several David L. French executive roles at Apache Corporation including Regional Production Manager for the western Canadian President and Chief business, and Global Vice President of Business Development. Earlier in his career Mr. French worked for Executive Officer McKinsey & Co. in energy consulting and built his career in the Permian Basin for Amoco Production Company (now BP). Mr. French holds a Bachelor’s degree in mechanical engineering from Rice University and an MBA from Harvard Business School.
Mr. Hendry is a Chartered Accountant with over 25 years of finance experience. Joining Obsidian Energy in April 2015 as Vice President of Finance, he moved into the CFO position in January 2017. Prior to David Hendry joining the Company, he served as a finance Vice President at Talisman Energy Inc. where he also worked Chief Financial Officer overseas for nine years in the Norway and U.K. North Sea offices. Mr. Hendry started his career working nine years in public accounting, largely at PricewaterhouseCoopers.
Mr. Smith joined the Company in July 2018 and brings over 20 years of engineering expertise across a broad range of technical and leadership roles. Most recently, he held the position of Vice President, Aaron Smith Production at Sinopec Canada. Prior to that appointment he led the Development and Marketing Vice President, divisions and served in asset leadership roles in the Cardium area. His early career is distinguished with Development increasing responsibility in Corporate Planning, Completions, and Reservoir Engineering. Aaron holds a Bachelor of Science in Geologic Engineering from the University of Saskatchewan.
Mr. Sweerts has over 25 years’ experience in the oil and gas industry and is currently the Vice President, Business Development & Commercial for Obsidian Energy. In his tenure at Obsidian Energy, Mr. Sweerts has also held the position of Vice President, Production and Technical Services. Prior to joining the Andrew Sweerts Company in June of 2014, Mr. Sweerts held a number of senior roles within Marathon Oil Canada Corp. Vice President, Business including Vice President, Operations and Engineering and Vice President, JV Operations and Marketing. Development & Commercial Earlier in his career, he held a variety of technical and commercial positions with successive levels of responsibility at Western Oil Sands LP and Suncor Energy. Mr. Sweerts has a Bachelor of Science degree in Chemical Engineering from the University of Waterloo, and a Master in Business Administration from Wilfred Laurier University. Mr. Hodgson brings over 16 years’ experience in the industry most recently leading Bankers Petroleum technical and commercial expansion efforts in Eastern Europe. Prior to New Ventures, Mr. Hodgson held Mark Hodgson positions managing service functions of Legal, Crude Marketing, Stakeholder Engagement, Supply Chain, Vice President, Operations Investor Relations, and Corporate Planning. Prior to Bankers Petroleum, he worked five years each in and E&P Services investment banking with Tristone Capital in London, and on Wall Street in New York with Group One, a trading house. Mr. Hodgson holds a degree in Finance from the Wharton school at the University of Pennsylvania.
28 End Notes
Slide 3: Corporate Overview Slide 17: Targeting Oil Banks in Historic Waterfloods Market Value and Enterprise Value was determined at the close of business on January 31, 2019. Net Debt is based on Peer posted rates from offsetting wells are peak calendar day rate from public data sourced from IHS Accumap with corresponding Q3 2018 financials. Reserves (2P), RLI, NPV10, is based on 2P, PDP Decline and our 2019 Guidance are as disclosed date labelled. Cumulative oil recovery is illustrative of total cumulative oil produced to date based on reservoir modelling and are in our press release dated February 11, 2019 (the “Release”). not reflective of variations in geology, waterflood effectiveness, or fluid composition.
Slide 6: Willesden Green H2 2018 Program Summary Slide 20: Cardium 3 Year Forecast Production amounts are averaged per well and timing is based on internal estimates. Is based on internal estimates
Slide 8 and 9: Revitalization of the Cardium Play & The Broader Cardium Opportunity Slide 23: Mannville Falher Type Curve Historical production and well count is public data sourced from IHS Accumap, all producing wells from Cardium All reserve locations are gross locations and are defined by Sproule at YE 2018 and do not include 2019 development activity. Net formation. Historic cumulative well production is public data sourced from IHS Accumap for horizontal producing wells Pay, Porosity, Water saturation, CGR, and Spirit River Inventory Locations are based on internal Reservoir Modeling and internal within the Willesden Green field rig released 2014 to current. assumptions
Slide 10: Breaking Down the Cardium Play Fairways Slide 25: Why invest in Obsidian Energy? Individual play fairways are Obsidian Energy defined trends displaying similar reservoir and geological characteristics. 10-15% CAGR is based on the price deck and assumptions that were run for the November 15, 2018 Investor Day Presentation The “448 type curve assigned locations” estimates that full field development based on the inventory locations outlined would achieve an estimated average production consistent with the defined type curve for that fairway. Type curves are Slide 27 : Asset Retirement Obligation Improvement defined by existing productive wells within the defined trend displaying similar reservoir and geological characteristics Cost estimates are based on internal estimates. and normalized for horizontal length and completion. Inventory not included within the assigned 448 has not been assigned a production profile and has not been included in development plan models or forward-looking production estimates.
Slide 12 and 22: Economics Slides Economic metrics are defined from provided type curves and on the Plan Pricing Scenario. Type curve production is defined by existing productive wells within the defined trend displaying similar reservoir and geological characteristics and normalized for horizontal length and completion. Development plan well counts are indicative and based on internal estimates under our Plan Pricing Scenario.
Slide 13: Drilling Longer Wells, Efficiently Drill days are calculated from spud to rig release date.
Slide 14: Optimized Well Design to Maximize the Economics of our Acreage Economic models are based modelled well productivity where Inter-well spacing, Inter-frac spacing, and Lateral Length are variable against fixed standard well performance and design based on Obsidian Energy internal calculations. Economic modelling is illustrative and will vary with individual well geology, reservoir composition, capital costs, and price assumptions.
Slide 15: Crimson Lake Cost Reduction Trajectory Capital costs and savings are estimates and based on average well design and costs. Individual well costs will vary based on depth, well design, surface constraints, road access, and external factors such as market demand and weather.
Slide 11, 16, 18 and 19: Asset Slides All reserve locations are gross location and are defined by Sproule at YE2018 and do not include 2019 development activity. Booked locations include both waterflood locations, waterflood development, and primary drilling locations. Total acreage and WI are based on highlighted land in the corresponding map. WI is calculated across the entire highlighted region of the map and includes land where Obsidian Energy is not the operator. No inventory locations have been assigned to land where Obsidian Energy is not the operator.
29 Definitions and Industry Terms
PDP means proved developed producing reserves as per Oil Fracturing is a short name for Hydraulic fracturing, a method for NGTL means a TransCanada operated transmission line and Gas Disclosures Advisory extracting oil and natural gas NOI means net operating income 1P means proved reserves as per Oil and Gas Disclosures Frac means fraccing, short name for Hydraulic fracturing, a Advisory method for extracting oil and natural gas NPV means net present value, before tax discounted at 10 percent 2P means proved plus probable reserves as per Oil and Gas FX means foreign exchange rate, in our case typically refers to Disclosures Advisory C$ to US$ exchange rates NYSE means New York Stock Exchange
12M Efficiency means 12 month capital efficiency in $/boe/d Free Cash Flow, which is Funds Flow from Operations less Opex means operating costs Total Capital Expenditures ABC means area based closure program initiative from the Payout means the time it takes to cover the return of your initial AERCF FFO means funds flow from operations, detailed in the Non- cash outlay GAAP measure advisory A&D means oil and natural gas property acquisitions and PCU means Pembina Cardium Unit divestitures FY means fiscal year PIR means profit investment ratio, defined as NPV divided by AER means Alberta Energy Regulor G&A means general and administrative expenses capital outlay
ARO means Asset Retirement Obligation GOR means gas oil ratio Plan Pricing Scenario means the flat price deck at US$60/bbl WTI, US$10/bbl Ed Par Differential, $2/mcf AECO and CAD/USD bbl and bbl/d means barrels of oil and barrels of oil per day, H1 means first half of the year 1.31x FX Rate respectively H2 means second half of the year POR means porosity bopd means barrel of oil per day Hz means horizontal well Perm means permeability boe, boe/d means barrels of oil equivalent and barrels of oil equivalent per day, respectively IP means initial production, which is the average production over PROP means Peace River Oil Partnership a specified time period CAGR means compound annual growth rate PSO means peace sour IRR means Internal Rate of Return which is the interest rate at Capital Expenditures & Capex includes all direct costs related which the NPV equals zero SEC means U.S. Securities and Exchange Commission to our operated and non-operated development programs including drilling, completions, tie-in, development of and Liquids means crude oil and NGLs Spud means the process of beginning to drill a well expansions to existing facilities and major infrastructure, optimization and EOR activities M or k means thousands Unbooked means locations that are internal estimates based on Obsidian Energy’s prospective acreage and an assumption as to CFPS means cash flow per share MMcf means million cubic feet and MMcf/d means million cubic the number of wells that can be drilled per section based on feet per day industry practice and internal review. Unbooked locations do not CGR means condensate gas ratio have attributed reserves or resources (including contingent and Mboe means thousand barrels oil equivalent prospective). Unbooked locations have been identified by Company or OBE means Obsidian Energy Ltd; as applicable management as an estimation of Obsidian Energy’s multi-year drilling activities based on evaluation of applicable geologic, MMboe means million barrels oil equivalent Decommissioning means decommissioning expenditures seismic, engineering, production and reserves information.
Mbbl & MMbbl means thousands barrels of oil and million WCS means Western Canadian Select Ed Par means Edmonton Par Crude barrels of oil, respectively WI means working interest Enviro means decommissioning expenditures N, S, E, W means the North, South, East, West or in any combination EUR means estimated ultimate recovery WF means waterflood NAV means net asset value F&D means finding and development costs WTI means West Texas Intermediate NGL means natural gas liquids which includes hydrocarbon not marketed as natural gas (methane) or various classes of oil YE means year end
YOY means year over year 30 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:
EBITDA is cash flow from operations excluding the impact of changes in non-cash working capital, decommissioning expenditures, financing expenses, realized gains and losses on foreign exchange hedges on prepayments, realized foreign exchange gains and losses on debt prepayments and restructuring expenses. In addition, under the syndicated credit facility, realized foreign exchange gains or losses related to debt maturities are excluded from the calculation. EBITDA as defined by Obsidian Energy’s debt agreements excludes the EBITDA contribution from assets sold in the prior 12 months and is used within Obsidian Energy’s covenant calculations related to its syndicated bank facility and senior notes.
Enterprise Value is the measure of a company’s total value and includes all ownership interests and asset claims from both debt and equity. It is calculated as share price multiplied by total shares outstanding plus Net Debt
Funds flow is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and office lease settlements
Funds flow from operations or FFO is cash flow from operating activities before changes in non-cash working capital, decommissioning expenditures and office lease settlements which also excludes the effects of financing related transactions from foreign exchange contracts and debt repayments and certain other expenses and is representative of cash related to continuing operations.
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
31 Oil and Gas Information Advisory
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.
This presentation contains a number of oil and gas metrics prepared by management, including reserve life index or "RLI", which does not have a standardized meaning or standard method of calculation and therefore such measure may not be comparable to similar measures used by other companies. Such metrics have been included herein to provide readers with additional measures to evaluate our performance on a comparable basis with prior periods; however, such measures are not reliable indicators of our future performance and our future performance may not compare to the performance in previous periods. RLI has been calculated in this presentation as the volume of our 2P reserves as of December 31, 2018 divided by our average daily production for 2019 production for the associated reserve category.
Inventory
This presentation discloses drilling locations in three categories: (i) proved locations; (ii) probable locations; and (iii) unbooked locations. Proved locations and probable locations are derived from the Sproule Report and account for drilling locations that have associated proved and/or probable reserves, as applicable. Unbooked 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.
Of the 891 gross drilling locations identified herein, 189 are proved locations, 208 are probable locations and 683 are unbooked locations.
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 drilling 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 derisked 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.
32 Reserves Disclosure and Definitions
Unless otherwise noted, any reference to reserves in this presentation are based on the report ("Sproule Report") prepared by Sproule Associates Limited dated January 24, 2019 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, 2018. For further information regarding the Sproule Report, see our Release. 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 the Release.
33 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: our 2019 guidance including production, production growth, operating and G&A cost ranges; the expected decline rates and reserve life index on reserves; how we intend our assets, including but not limited to, base production and commercialization, infrastructure capacity management and opportunistic partnering and development capital; our strategic priorities including meaningful year over year cash flow growth (including the target and how that will be driven), improved balance sheet strength (including maintaining capital discipline and target DEBT/EBITDA for next couple of years), and simplify and grow the light oil business (through targeted investment, portfolio rationalization and maintain operated secondary recovery projects to support declining the expected decline rates and reserve life index on reserves) our internal expectations for type curves; our expectations on how we will deliver returns in the future; that the Cardium has significant remaining untapped potential; our ability to waterflood certain locations and for minimal capital through existing infrastructure; our potential locations; that certain locations have been de-risked due to various reasons; that the Cardium play has remaining untapped potential; that drilling two mile wells reduces fixed drilling costs and longer wells have proportionally higher rates and EUR; that higher drilling speed motors and drill parameters improve rate of penetration and how we plan to drill and the impact that will have to efficiency and mobilization time; how we plan to drill, complete equip and tie-in in order to reduce certain costs; our inventory; our target for reduction in type well costs for our 2019 activity; how we plan to target certain oil banks and the keys to its success; our expectations for the 3 year production range and 3 year NOI and free cash flow in the Cardium and how strip pricing and greater than strip pricing will impact self-funded growth in the area; that the Cardium will feed the rest of the business with high netbacks at strip; that we own and operate an infrastructure kit which can handle our development plans in the Cardium and allows for development and operational synergies for the Deep Basin; our expectations for legacy abandonment and how participating in the AER ABC program will impact various costs and the amount of fields that will be involved each year moving forward.
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 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. There is also a Pricing Assumption slide which should be taken into account when reviewing the presentation. 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 End Notes 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 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 Annual Information Form (See "Risk Factors" and "Forward-Looking Statements" therein) which 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 February 10, 2019. 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.
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