Obsidian Energy Corporate Presentation · Deep Basin $8 9% Optimization $14 16% Cardium ... Horizontal Drilling Focus by $9MM (three wells) ... suited to horizontal development

Obsidian EnergyCorporate Presentation

April 2018

ObsidianEnergy.com | TSX/NYSE: OBE

Important Notices to the ReadersThis 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


Peace RiverManufactured Cold Flow, High Rate, Low

Cost with Multiple Egress Options

4,963 boe/d Q4 2017Net Sections: 235

Obsidian Energy Corporate Profile

3

Share PriceApril 1st, 2018

$/share $1.29

OBE-TSX Daily Volume% of shares outstanding

MM 1.30.3%

OBE-NYSE Daily Volume% of shares outstanding

MM 1.50.3%

Market Capitalization $MM $651

Net Debt $MM $383

Enterprise Value $MM $1,034

Corporate Metrics

Index Map

See end notes

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 31st for details

FY 2018 Guidance

Deep BasinMulti Horizon Potential,

Highly Economic Deep Basin Development


CardiumMeaningful Free Cash Flow Generation,

Waterflood Approach with Primary Optionality


Alberta VikingShort Cycle Investment to Toggle Growth,

Industry Leading IP Rates


Production boe/d 29,000-30,000

Growth % 5%

Total ExpendituresCapital ExpendituresDecommissioning

$MM$MM

$125$10

ExpensesOperating ExpenseG&A Expense

$/boe$/boe

$13.00 - $13.50$2.00-$2.50


3547

666

8

12

6

8

10

27

32

43

75

96

131

0

20

40

60

80

100

120

140

PDP 1P 2PLight & Medium Crude Oil (mmbbl) Heavy Crude Oil & Bitumen (mmbbl)Natural Gas Liquids (mm bbl) Conventional Natural Gas (mmboe)

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

Corporate Reserves

NAV Valuation ($/Share)

Replaced 126%

Replaced 131%

Replaced 121%

✓ 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

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

See end notes


10,000

15,000

20,000

25,000

30,000

35,000

Q1 2018 Q2 2018 Q3 2018 Q4 2018

Base Production 2017 Development 2018 Development

16% Base Decline Rate

22% Base + 2017 Development Decline Rate

5

Low Decline Rate Underpins Growth

16% Corporate Base Production Decline RateCardium Asset Under Historical Waterflood

Capital Efficiencies of $6,500/boe/d on 2017 Optimization ProjectsOptimization of existing base wellbores

2017 Base Production & 2017 Development Declines 16% in 2019

Corporate Base Productionboe/d

See end notes


20,000

22,000

24,000

26,000

28,000

30,000

32,000

2017E A&D Adjusted FY 2018E

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

5% A&D Adjusted Production Growth

Base & Infrastructure

Capital$25 18%

2018 Development

$86 64%

Enviro$10 8%

Regulatory$14 10%

See end notes


AB Viking$6 7%

PROP$8 9%

Deep Basin$8 9%

Optimization$14 16%

Cardium$50 58%

Cardium 11

Deep Basin2

PROP4

AB Viking4

21

0

5

10

15

20

25

2018 Wells Spud

7

Portfolio Optionality on DisplayEmploying a quicker payout program that balances primary drilling with targeted low capital integrated waterflood opportunities

2018 Development Allocations ($MM) Budget 2018 Operated Spuds21 Operated spuds planned in 2018(excludes non-operated activity)

80% Av. IRR45% Av. IRR

40% Av. IRR100% Av. IRR

50% Av. IRR

Increased Cardium Horizontal Drilling Focus by $9MM

(three wells)

See end notes


Obsidian Energy’s Dominant Cardium Position

8

✓ 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

See end notes


Pembina

Booked Locations 87

Additional Inventory 363

Total Inventory 450

Willesden Green

Booked Locations 42

Additional Inventory 208

Total Inventory 250

Total Inventory 700

Units Pembina

Willesden

Green

PDP MMboe 35 23

Proved MMboe 45 28

Proved + Probable MMboe 64 37

2P BTCF NPV10 $MM $877 $525

9

The Largest Land Holder in The Cardium Play Fairway

See end notes

Significant Inventory UpsideReserve book includes 129 highly confident locations

Reserves SummaryLarge light oil weighted reserves

R10W5

T50

PEMBINA

10 miles

15 kms

INDEX MAP

WILLESDENGREEN

OBE Cardium WI Land

Arc

Baccalieu

Bonterra

Inplay

Prairie Storm

Ridgeback

Tamarack Valley

Whitecap

Yangarra

T45

T40


A Lease

Bear Lake

Carrot Creek

Crimson Lake

D Lease EasyfordF Lease

Faraway

G Lease

J Lease

Lobstick

Lodgepole

NPCU #1

NWPCU #1

Open Creek

Paddy Creek

PCU #11

PCU #9

Rose Creek

0%

20%

40%

60%

80%

100%

120%

0% 10% 20% 30% 40%

Wa

terc

ut (%

)

Recovery Factor (%)

R10W5

PEMBINA

INDEX MAP

WILLESDENGREEN

T50

T45

10 miles

15 kms

OBE Cardium WI land

OBE producing well

Injectors

Por >8%, Perm >0.2mD

Best quality reservoir

Industry Hz well

Cardium trend

PCU #11

Crimson Lake

PCU #9

J Lease

NPCU #1

10

Attractive Geology with Recovery Factor Upside

See end notes

Units Pembina Willesden Green

OOIP / Section MMbbl 8-12 5-7

Zone depth m 1,500-1,800 2,200

Type Rock Sandstone Sandstone

Net Pay m 8-10 4-8

Porosity % 11% 9%

Permeability mD 0.50-2.0 0.25

Geology50+ years of drilling history

Large expected gain in recovery factors on OOIP

with application of integrated waterflood

approach

OBE WI Land

Industry Peer Land


Pembina

SW E-NELodgepole PCU #9 F Lease

11

Variable Stratigraphy Across the Play

11

Multi-Cycle Optionality for Bioturbated Drilling

See end notes

ConglomerateClean sandstoneMuddy bioturbated sandSandy bioturbated mudShale (stratigraphic seal)Erosional contact (unconformity)Transitional contact

WillesdenGreen

W EWest

CrimsonPrimary

CrimsonUnit

EastCrimsonPrimary Faraway

OpenCreek

G Lease

ObsidianEnergy.com | TSX/NYSE: OBE 12

Blending Integrated Waterflood with Primary Optionality

Willesden Green Cardium Acreage Position

Crimson Lake Waterflood 100% Working InterestPortions of unit with un swept oil, suited to horizontal development resulting in top tier wells

Faraway100% Working InterestHigh quality reservoir with historical pressure support

Open Creek79% Working Interest3 Obsidian controlled units with high quality reservoir

Crimson Lake Halo100% Working InterestLarge inventory of high IP primary development locations

Willesden Green Cardium Acreage Position

R8W5

INDEX MAP

Crimson Lake “Halo”

Open Creek

5 miles

10 kms

T42

Faraway

OBE unit land

OBE Cardium WI land

OBE producing well

Injectors

Waterflood cutoff

WF quality reservoir

Halo Cardium acreage

Industry Hz well

Cardium trend

Ferrier

Wellbore placement in the

bioturbated window

targeting clean sands above

Crimson Lake WF

Majority of Booked Inventory


Exceeding Industry Average in Willesden Green

See end notes

• Outperformed the industry average oil production per well for the past four years

• Consistently improving results year over year

Willesden Green Average Cumulative Oil by Year

5 miles

10 kms

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

R7W5

T40

T43

0

10

20

30

40

50

60

0 10 20 30 40 50 60

Av

era

ge

Cu

mu

lati

ve

Oil

Pro

du

cti

on

/ W

ell

(M

BB

L)

Months

2014 - OBE 2014 - INDUSTRY




Waterflood Response


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

0

50

100

150

200

250

300

350

400

0 6 12 18 24 30 36 42 48

Pro

ducti

on (

bb

l/d

)

Months on Production

2018 Primary Type Curve

14

Willesden Green Results Command More Capital

• 4 well pad in Willesden Green Cardium on-stream as of Jan. 3, 2018. Average IP30 650 boe/day per well (87% liquids)

• 2 well pad on stream Feb 20, 2018. 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

See end notes

WILLESDEN GREEN14-01-43-8W5 Pad

T42

3 miles

5 kms

R8W5WILLESDEN GREEN11-03-43-8W5 Pad

2018 drilled or completed

2018 optionality

2018 non-op participated

Industry wells

Injectors

OBE unit land

OBE Cardium WI land

2018 Type Curve Economics


Reservoir Complexity in Pembina

See end notes

Pi 9,249 kPa

Pi 17,471 kPa

Pi 5,996 kPa

Pembina Cardium Unit # 9

6-35-47-10W5 Pad

• 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

2018 drilled or completed

Future development

Industry wells

Injectors

OBE unit land

OBE Cardium WI land


0

100,000

200,000

300,000

400,000

500,000

600,000

0 50 100 150 200 250 300 350

Av

era

ge

Cu

mu

lati

ve

Oil

Pro

du

cti

on

/w

ell

(B

BL

)

Months

OBE - 100/05-23-048-09W5/0

OBE - 102/12-14-048-09W5/4

100

1,000

10,000

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)

16

Pembina Waterflood: Improving Decline and Well Performance

See end notes

2016/2017 PCU #9 WF Optimization Waterflood Improves 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

Oil Rate Stabilizes

Gas/Oil Ratio Stable

No injection support

Injection support on both flanks


Inputs


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


F&D ($/boe) $12.90

17

Pembina Development Economics Driven by Large EUR

• Integrated waterflood approach improves recovery factor

• After 50+ years, resource and geology is delineated and well understood

• High-netback light oil production with low decline rate

See end notes


PEMBINA8-25-47-9W5 Pad

3 miles

5 kms

R10W5

T48

PEMBINA7-22-049-11W5 Pad 2018 drilled or completed

Future Development

Industry Wells

Injectors

OBE unit land

OBE Cardium WI land

0

50

100

150

200

250

0 6 12 18 24 30 36 42 48

Pro

ducti

on (

bb

l/d

)


2018 Intergrated Waterflood Type Curve


Evolving Our Development Strategy and Sharing with Industry

Data driven unique well designsDo not use a factory drilling approach

Drilling Cost per meter performance in Willesden Green

Monobore Well Design inWillesden 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

Intermediate/Liner Well Design in Willesden GreenWell specific approach to manage costs

$0

$100

$200

$300

$400

$500

$600

OBE 2015 OBE 2016 OBE 2017 OBE 2017(Monobore)

$/M

eter

(D

rill

ing)

See end notes

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


0

100

200

300

400

500

600

700

0 6 12 18 24 30 36 42 48

Pro

ducti

on (

bo

e/d

)


Deep Basin Type Curve

Spirit River Type Curve Economics

INDEX MAP

5 miles

10 kms

OBE land

OBE operated Cardium unit

WILLESDENGREEN

R8W5

T42

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

• Two-mile Falher well expected to be on stream at the end of March, initial pressure metrics and production tests look encouraging

Falher BTrend

100/02-03-044-09W5 On Production:

10/26/2017Initial Rate: 3.9 MMCFD

100/14-30-043-07W5On Production:


100/02-07-043-07W5On Production:


Average Liquids Ratio 55 bbl/mmcf (135 bbl/d per well)

See end notes 19

>40 high confidence near term

liquids rich locations

F O R M A T I O N

CR

ET

AC

EO

US

BELLY RIVER

COLORADO SHALE

CARDIUM

COLORADO SHALE

MA

NN

VI

LL

E

SP

IRIT

R

IVE

R

NOTIKEWIN

FALHER

WILRICH

GLAUCONTIC SANDSTONE

OSTRACOD BEDS

ELLERSLIE

FERNIE SHALE

ROCK CREEK

Inputs


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%

Payout (years) 1.6


F&D ($/boe) $6.25


R10

20

AB Viking Program Continues to Exceed Expectations

• Light-oil, high netback shorter cycle wells

• 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

10 miles

15 kms OBE gas plant

OBE land

INDEX MAP

Compeer GP

Esther GP

Misty GP

Monitor West GP

R1W4

T30

R10


See end notes

Update Economics

Inputs


Production

EUR (Mboe) 74

IP30 (boe/d) 190

IP365 (boe/d) 100

Liquids (%) 57%

Economic Outputs

NPV (10%) ($MM) $0.7

PIR (10%) 0.4

IRR (%) 45%

Payout (years) 1.9


F&D ($/boe) $21.15

Jay signoff

0

20

40

60

80

100

120

140

160

180

200

0 6 12 18 24 30 36 42 48

Pro

ducti

on


Type Curve (boe/d)


0

50

100

150

200

250

0 6 12 18 24 30 36 42 48

Pro

ducti

on


Total Production (boe/d) Oil (bbl/d)

Inputs


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


F&D ($/boe) $7.50

21

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

10 miles

15 kms

OBE land

Acquired land in 2017

PROP

INDEX MAPR15W5

T80

HarmonValley

HarmonValleySouth

Seal


See end notes

Gas Gathering

Impact


Total 2018 Corporate 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

$7,000 $8,000

$14,000

$16,000

$20,000

<$15,000

<$25,000

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

DeepBasin

Optimization PROP AB Viking Cardium Total 2018Development

Total 2018Capital

Ca

pit

al

Eff

icie

nc

ies (

$/b

oe

/d

)

$86MM Development Capital

See end notes


6 2 % 3 % 6 5 %

0%

25%

50%

75%

100%

2018ELiquids Weight

LegacyAdjustment

2018EProforma Liquids

Weight

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

• Cash flow accretive based on opex savings and liquids weight

• Reduces discounted decommissioning liabilities, improves corporate netback

Liquids Weight (%)

Midpoint of Production Guidance (boe/d)

Decommissioning Liabilities ($MM)

Midpoint of Opex Guidance ($/boe)

R1W4

INDEX MAPSUGDEN

T25

R10R20R1W5

T35

T45

T55

MIKWAN

ACADIA

WIMBORNE

ALSASK

BASHAW

30 miles

45 kms

Legacy PackageOBE land

Legacy Asset Disposition Lands

$ 17 0

$ 14 7

$ 2 3

$0

$50

$100

$150

$200

$250

Q4 2017Decommissioning

Liabilities

LegacyAdjustment

Q4 2017Proforma

DecommissioningLiabilities

3 1 ,5002 9 ,500

2 ,000

0

10,000

20,000

30,000

40,000

2018EPreviousGuidance

LegacyAdjustment

2018EProforma

Production

$13.75 $13.25 $ 0.50

$0.00

$5.00

$10.00

$15.00

$20.00

2018EPreviousGuidance

LegacyAdjustment

2018EProforma Opex

See end notes


$19,000

$14,000

$8,000

$0

$5,000

$10,000

$15,000

$20,000

$25,000

2015 2016 2017

$15,000

$13,500

$12,000

$0

$5,000

$10,000

$15,000

$20,000

2015 2016 2017

$92,000

$83,000

$66,000

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

Corporate2015 2016 2017

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 ($/Well) Average Reclamation Cost ($/Hectare)Average Pipeline Abandonment Cost ($/km)

28% Decrease 20% Decrease 58% Decrease

See end notes


Why Obsidian Energy, Why Now?

• 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

Balanced and disciplined operator

• 16% corporate base decline generates meaningful cash for reinvestment at leading finding and development costs

• Over 1,000 drilling prospects across key development areas

Deep inventory across key

development areas

• 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

Setting up for growth

See end notes


Appendix


End Notes

27

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 4. 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 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 2018.

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 2017.

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, 2017.

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 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 2017.

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

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


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)


C$1.67/Mcf in 2018, C$1.88/Mcf in 2019, escalating through 2021

Slide 22. 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 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

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”


Definitions and Industry Terms

28

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

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

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

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

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


Non-GAAP Measures Advisory

29

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

http://www.sedar.com/

http://www.sec.gov/


Reserves Disclosure and DefinitionsAny 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.

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.


Forward-Looking Information Advisory

31

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 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 April 9, 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.

Obsidian Energy Corporate Presentation · Deep Basin $8 9% Optimization $14 16% Cardium ... Horizontal Drilling Focus by $9MM (three wells) ... suited to horizontal development

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