obsidian energy corporate presentation · this presentation should be read in conjunction with the...

Obsidian Energy Corporate Presentation

March 2018

ObsidianEnergy.com | TSX/NYSE: OBE

Important Notices to the Readers This presentation should be read in conjunction with the Company's audited consolidated financial statements, management's discussion and analysis ("MD&A") for the year ended December 31, 2017. All dollar amounts contained in this presentation are expressed in millions of Canadian dollars unless otherwise indicated.

Certain financial measures included in this presentation do not have a standardized meaning prescribed by International Financial Reporting Standards (“IFRS”) and therefore are considered non-generally accepted accounting practice ("non-GAAP") measures; accordingly, they may not be comparable to similar measures provided by other issuers. This presentation also contains oil and gas disclosures, various industry terms, and forward-looking statements, including various assumptions on which such forward-looking statements are based and related risk factors. Please see the Company's disclosures located in the Appendix at the end of this presentation for further details regarding these matters.

2


Peace River

Manufactured Cold Flow, High Rate, Low Cost with Multiple Egress Options

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

Obsidian Energy Corporate Profile

3

Share Price Feb. 28, 2018

$/share $1.18

OBE-TSX Daily Volume % of shares outstanding

MM 1.5 0.3%

OBE -NYSE Daily Volume % of shares outstanding

MM 1.9 0.4%

Market Capitalization $MM $595

Net Debt $MM $383

Enterprise Value $MM $978

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 Basin

Multi Horizon Potential Highly Economic Mannville Development


Cardium

Meaningful Free Cash Flow Generation, Waterflood Approach with Primary Optionality


Alberta Viking

Short Cycle Investment to Toggle Growth Industry Leading IP Rates


Production boe/d 29,000-30,000

Growth % 5%

Total Expenditures Capital Expenditures Decommissioning

$MM $MM

$125 $10

Expenses Operating Expense G&A Expense

$/boe $/boe

$13.00 - $13.50 $2.00-$2.50


Total Expenditures

Guidance $160

$0

$20

$40

$60

$80

$100

$120

$140

$160

$180

Total Expenditures Guidance

Operating Cost Guidance

$13.00 - $13.50

$12.50

$13.00

$13.50

$14.00

Guidance

20,000

23,500

27,000

30,500

34,000

Q4 2016 Q4 2017

Production Guidance

30,500 - 31,500

30,000

30,500

31,000

31,500

32,000

Guidance Beat

31,723 boe/d

4

Total Capital Within Guidance

$157MM

Developing a Track Record of Delivering Results

Q4 2017 A&D Adj. Production boe/d

FY 2017 Production boe/d

2017 Total Expenditures $MM

2017 Operating Expenses $/boe

Double Digit Growth

31,447 boe/d

Operating Costs Within Guidance

$13.40/boe

*Net of Peace River Carry


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)

5

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

6

Low Decline Rate Underpins Growth 16% Corporate Base Production Decline Rate Cardium Asset Under Historical Waterflood

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

2017 Base Production & 2017 Development Declines 16% in 2019

Corporate Base Production boe/d

See end notes


20,000

22,000

24,000

26,000

28,000

30,000

32,000

2017E A&D Adjusted FY 2018E

7

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

8

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

2018 Development Allocations ($MM) Budget 2018 Operated Spuds

21 Operated spuds planned in 2018 (excludes non-operated activity)

80% Av. IRR 45% Av. IRR

40% Av. IRR 100% Av. IRR

50% Av. IRR

Increased Cardium Horizontal Drilling Focus by $9MM

(three wells)

See end notes


0

50

100

150

200

250

300

350

400

450

0 6 12 18 24 30 36 42 48

Pro

ducti

on (

bb

l/d

)

Months on Production

9

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

• Adding 3 incremental Willesden Green Cardium wells to our 2018 development

5 miles

10 kms

OBE Operated Cardium land

OBE producing well

Industry HZ well

INDEX MAP

R8W5

T42

WILLESDEN GREEN

WILLESDEN GREEN 11-03-43-8W5 Pad

WILLESDEN GREEN 14-01-043-08W5 Pad

Recent Drills Above Type Curve

Inputs

Waterflood

Type I

DCET Cost ($MM) $6.5

Incremental Water Cost ($/bbl water) $0.20

Production

EUR (Mboe) 545

IP30 (boe/d) 340

IP365 (boe/d) 265

Liquids (%) 80%

Economic Outputs

NPV (10%) ($MM) $5.0

PIR (10%) 0.8

IRR (%) 35%

Payout (years) 2.5

Capital Efficiency ($/boe/d) $24,500

F&D ($/boe) $11.95

2017 Analyst Day Type Curve Economics

Select 2018 Metrics


IRR (%) >50%

Capital Efficiency ($/boe/d)

$21,000

See end notes

ObsidianEnergy.com | TSX/NYSE: OBE 10

Multi-Cycle Bioturbated Drilling • Drilling in the bioturbated rock and

fracking into clean intervals above reduces drill complexity and costs

• Drill optionality between several cycles based on reservoir quality

• Ability to target multiple cycles throughout a single drill path

10

Grain Size Gamma Ray

Fracs

Cardium C

Multi-Cycle Bioturbated

Cardium B

Cardium D

Conglomerate

Bioturbated

Bioturbated Window

Bioturbated Window

Bioturbated Window

OBE Operated Cardium unit

OBE Cardium land

OBE Bioturbated Drilling Activity

T42

T41

3 miles

5 kms

R9 R7W5

T43 2 Operated primary wells for 2018

Bioturbated Drilling Activity 50 wells since 2014 in Willesden Green

See end notes


PEMBINA

10 miles

15 kms

OBE Cardium land

OBE land

OBE producing well

Industry HZ well

INDEX MAP

R11W5

T50

11

Dominating Pembina Acreage

• 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

Inputs

Waterflood

Type I


Incremental Water Cost ($/bbl water) $0.20

Production

EUR (Mboe) 530

IP30 (boe/d) 185

IP365 (boe/d) 150

Liquids (%) 89%

Economic Outputs

NPV (10%) ($MM) $6.1

PIR (10%) 1.0

IRR (%) 35%

Payout (years) 3.1


F&D ($/boe) $11.80

0

20

40

60

80

100

120

140

160

180

200

0 6 12 18 24 30 36 42 48

Pro

ducti

on


PEMBINA 8-25-47-9W5 Pad

2017 Analyst Day Type Curve Economics Select 2018 Metrics


IRR (%) >50%


$19,000

See end notes


R10

12

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

Inputs


Production

EUR (Mboe) 75

IP30 (boe/d) 175

IP365 (boe/d) 95

Liquids (%) 51%

Economic Outputs

NPV (10%) ($MM) $0.7

PIR (10%) 0.4

IRR (%) 50%

Payout (years) 1.7


F&D ($/boe) $20.00

0

20

40

60

80

100

120

140

160

180

200

0 6 12 18 24 30 36 42 48

Pro

ducti

on


Total Production (boe/d)

Liquids Production (bbl/d)


See end notes


0

50

100

150

200

250

0 6 12 18 24 30 36 42 48

Pro

ducti

on (

bo

e/d

)


13

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 MAP R15W5

T80

Harmon Valley

Harmon Valley South

Seal

Inputs


Production

EUR (Mboe) 400

IP30 (boe/d) 215

IP365 (boe/d) 210

Liquids (%) 93%

Economic Outputs

NPV (10%) ($MM) $2.6

PIR (10%) 0.9

IRR (%) 50%

Payout (years) 2.6


F&D ($/boe) $7.00


See end notes


INDEX MAP

5 miles

10 kms

OBE land

OBE operated Cardium unit

WILLESDEN GREEN

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 B Trend

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

10/26/2017 Initial Rate: 3.9 MMCFD

100/14-30-043-07W5 On Production:


100/02-07-043-07W5 On Production:


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

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

0 6 12 18 24 30 36 42 48

Ga

s P

rod

ucti

on (

Mcf/

d)


Inputs


Production

EUR (Mboe) 720

IP30 (boe/d) 1,030

IP365 (boe/d) 620

Liquids (%) 19%

Economic Outputs

NPV (10%) ($MM) $3.4

PIR (10%) 0.9

IRR (%) 60%

Payout (years) 1.5


F&D ($/boe) $5.50


Select 2018 Metrics


IRR (%) 80%

Liquids (%) 22%


$7,000

See end notes 14


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

16

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 MAP SUGDEN

T25

R10 R20 R1W5

T35

T45

T55

MIKWAN

ACADIA

WIMBORNE

ALSASK

BASHAW

30 miles

45 kms

Legacy Package OBE 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

17

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?

• Track record of lowering costs; stripped out $130 million of Opex and G&A in 2017 alone and lowered net debt by $120 million

• Prudent infrastructure investment and liability management

• Cardium waterflooding, complemented with primary development, yields sustainable liquids growth in the near and long term

Balanced and disciplined operator

• Leading position in the Cardium, one of the most attractive assets in the basin. Larger land footprint than # 2 & 3 combined

• Analogous Cardium fields prove the upside of secondary recovery

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

• Over 1,000 drilling prospects across key development areas

Deep inventory across key

development areas

• Kick-started a disciplined growth story that is well positioned for self funded 2019 cash flow expansion

• Robust pipeline of drill ready prospects to quickly capitalize on incremental free cash flow

• One time legacy and regulatory costs roll off in second half 2018, freeing up cash for larger 2019 development capital allocation

Unique entry point in our story


Appendix


End Notes

20

All slides should be read in conjunction with “Definitions and Industry Terms”, “Non-GAAP Measure Advisory”, “Oil and Gas Disclosures Advisory” and “Forward-Looking Advisory” Slide 3. Obsidian Energy Corporate Profile

Daily Volume (shares) is the 30 day average share volume traded on Canadian and US Exchanges per Bloomberg. Production is based on Q4 2017 results.. The net sections are approximate numbers and are internal estimates.

Slide 5. 2017 Reserves Highlight Revitalized Operations Delivery

NAV Valuation is based on 2P NPV10 as prepared by our independent reserves evaluation (Sproule Associates Limited) as at year-end 2017. Net Debt and share count is as at year-end 2017. All numbers are rounded

Slide 6. Low Decline Rate Underpins Growth

Corporate base production and decline is based on actual data generated internally. Lines have been smoothed for illustrative effect to adjust for volatility inherent in day to day oil and gas operations. Capital efficiencies on optimization projects are internal estimates and rounded.

Slide 7. Focused 2018 Plan

Production, capital expenditures are based on internal estimates for 2018.

Slide 8. Portfolio Optionality on Display

Internal Rates of Returns are rounded and based on a blended Sep 30, 2017 strip price and independent reserves evaluator (Sproule Associates Limited) price deck

Slide 9. Willesden Green Results Command More Capital

Economics are based on Investor day presentation and are internal estimates WTI - US$52/bbl in 2017, US$53/bbl in 2018, escalating through 2021 & AECO - C$2.90/Mcf in 2017, C$2.65/Mcf in 2018, escalating through 20. Select 2018 economics are based on Ed Par - Cad$66.93/bbl in 2018, Cad$64.72/bbl in 2019, escalating through 2022 and AECO - C$1.67/Mcf in 2018, C$1.88/Mcf in 2019, escalating through 2021

Slide 10. Bioturbated Drilling

Bioturbated chart is for illustration only. Wells labeled Bioturbated are wells that had a strategy to target the bioturbated interval before drilling .

Slides 11, 12, 13 & 14 (Asset Slides)

Economics are based on Investor day presentation and are internal estimates WTI - US$52/bbl in 2017, US$53/bbl in 2018, escalating through 2021 & AECO - C$2.90/Mcf in 2017, C$2.65/Mcf in 2018, escalating through 20 Select 2018 economics are based on Ed Par - Cad$66.93/bbl in 2018, Cad$64.72/bbl in 2019, escalating through 2022 and AECO - C$1.67/Mcf in 2018, C$1.88/Mcf in 2019, escalating through 2021

Slide 15. 2018 Capital Efficiency Buildup

Capital efficiencies for each core area are based on capital spent in that area on new production adds, 12 month forward production average, on an capital weighted average basis and rounded. Corporate Capital efficiencies includes all capital spent, 12 month forward production average, on an capital weighted average basis and rounded.

Slide 16. Reducing Liability Through Legacy Asset Disposition

All figures are internal estimates.

Slide 17. Reducing Liability Through Decommissioning Expense

All figures are internal estimates and are rounded


Definitions and Industry Terms

21

IP means initial production, which is the average production over a specified time period

IRR means Internal Rate of Return which is the interest rate at which the NPV equals zero

IP means initial production, which is the average production over a specified time period

IRR means Internal Rate of Return which is the interest rate at which the NPV equals zero

km means kilometers

Liquids % means the percentage of crude oil and NGLs from the total barrels of oil equivalent of production

Liquids means crude oil and NGLs

Mmcf means million cubic feet

Mmcf/d means million cubic feet per day

M means meters

MM means millions

NAV means net asset value

Net Debt means Senior Debt plus bank debt plus non-cash working capital deficit, detailed in the Non-GAAP measure advisory

NGL means natural gas liquids which includes hydrocarbon not marketed as natural gas (methane) or various classes of oil

NPV means net present value

Opex means operating costs

PCU #9 Means Pembina Cardium Unit number 9

PIR means profit investment ratio

PROP means Peace River Oil Partnership

TD means total depth where drilling has stopped

Spud mean the process of beginning to drill a well

WI means working interest

1P means proved reserves as per Oil and Gas Disclosures Advisory

2P means proved plus probable reserves as per Oil and Gas Disclosures Advisory

Av., Ave., Avg. means avearge

A&D means oil and natural gas property acquisitions and divestitures

A&D Adj. means oil and natural gas property acquisitions and divestitures

Base means production with no additional production from new drilling

bbl means barrel or barrels

$BN means billions of dollars

Bopd means barrel of oil per day

boe and boe/d mean barrels of oil equivalent and barrels of oil equivalent per day, respectively

Capital Expenditures & Capex includes all direct costs related to our operated and non-operated development programs including drilling, completions, tie-in, development of and expansions to existing facilities and major infrastructure, optimization and EOR activities

Company or OBE means Obsidian Energy Ltd; as applicable

DCET means drilling, completions, equip and tie-in costs

Enviro means decommissioning expenditures

E means estimate

EUR means estimated ultimate recovery

F&D means finding and development costs

FX means foreign exchange rate, in our case typically refers to C$ to US$ exchange rates

Free Cash Flow, which is Funds Flow from Operations less Total Capital Expenditures

FY means fiscal year

G&A means general and administrative expenses

H2 mean second half of the year

Hz means horizontal well


Non-GAAP Measures Advisory

22

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.sec.gov/


Reserves Disclosure and Definitions Any reference to reserves in this presentation are based on the report ("Sproule Report") prepared by Sproule Associates Limited dated January 29, 2018 where they evaluated one hundred percent of the

crude oil, natural gas and natural gas liquids reserves of Obsidian Energy and the net present value of future net revenue attributable to those reserves effective as at December 31, 2017. For further

information regarding the Sproule Report, see Appendix A to our Annual Information Form dated March 6, 2018 ("AIF"). It should not be assumed that the estimates of future net revenues presented herein

represent the fair market value of the reserves. There is no assurance that the forecast price and cost assumptions will be attained and variances could be material. The recovery and reserves estimates of

crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual crude oil, natural gas and natural gas

liquid reserves may be greater than or less than the estimates provided herein. The estimates of reserves for individual properties may not reflect the same confidence level as estimates of reserves for all

properties, due to the effects of aggregation.

Production and Reserves

The use of the word "gross" in this presentation (i) in relation to our interest in production and reserves, means our working interest (operating or non-operating) share before deduction of royalties and without

including our royalty interests, (ii) in relation to wells, means the total number of wells in which we have an interest, and (iii) in relation to properties, means the total area of properties in which we have an

interest. The use of the word "net" in this presentation (i) in relation to our interest in production and reserves, means our working interest (operating or non-operating) share after deduction of royalty

obligations, plus our royalty interests, (ii) in relation to our interest in wells, means the number of wells obtained by aggregating our working interest in each of our gross wells, and (iii) in relation to our interest in

a property, means the total area in which we have an interest multiplied by the working interest owned by us. Unless otherwise stated, production volumes and reserves estimates in this presentation are stated

on a gross basis. All references to well counts are net to the Company, unless otherwise indicated.

Reserve Definitions

reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on the analysis of drilling,

geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally accepted as being reasonable. Reserves are classified according to the

degree of certainty associated with the estimates.

probable reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less

than the sum of the estimated proved plus probable reserves.

proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated

proved reserves.

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:

Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example,

when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and nonproducing.

Developed producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if

shut-in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is

unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render

them capable of production. They must fully meet the requirements of the reserves category (proved, probable) to which they are assigned.

For additional reserve definitions, see "Notes to Reserves Data Tables" in our AIF.


Forward-Looking Information Advisory

24

Certain statements contained in this presentation constitute forward-looking statements or information (collectively "forward-looking statements. Forward-looking statements are typically identified by words such as "anticipate",

"continue", "estimate", "expect", "forecast", "budget", "may", "will", "project", "could", "plan", "intend", "should", "believe", "outlook", "objective", "aim", "potential", "target" and similar words suggesting future events or future

performance. In addition, statements relating to "reserves" or "resources" are deemed to be forward-looking statements as they involve the implied assessment, based on certain estimates and assumptions, that the reserves and

resources described exist in the quantities predicted or estimated and can be profitably produced in the future. In particular, this presentation contains, without limitation, forward-looking statements pertaining to the following: that

adding reserves at just over $13 per boe through 2017 demonstrates a powerful engine to reward investors; our expected base decline rates for production in 2018 and 2019; that we are working with the AER as part of the portfolio

management pilot on full field abandonment to realize efficiencies and further reduce decommissioning expenses; that conducting science based methodology in connection with abandonment streamlines reclamation phases and

trajectory towards reclamation; our expected 2018 guidance for production, growth, total expenditures (including capital and decommissioning), operating expenses, when we expect wells to come on production, and projected liquids

weightings; the payout time at certain locations; that we have a predictable & liquids weighted growth profile, the expected development capital percentage of Total Expenditures and that there is flexibility to expand the capital

program in the second half of the year and extend the growth rate; the expected average internal rates of return and costs at the various locations; that the Willesden Green and Pembina 2018 programs are less capital intensive with

higher rates of return; that drilling in the bioturbated rock and fracking into clean intervals above reduces drill complexity and costs; that there is drill optionality between several cycles based on reservoir quality; that in the Alberta

Viking we are targeting structural lows in 2018 to maximize light oil productivity; that in Peace River the recent results confirm optimism for 2018 plans in heart of Harmon Valley South, and that there is cash flow torque to increasing

oil price with significant long term inventory; our expected approach to development including the area-specific asset development plans; the timing and our expectations of such development activities; that the 2018 program

leverages the short cycle opportunity set in our portfolio; the expected development capital efficiencies and total capital efficiencies on a location and Company wide basis; that the Cardium waterflooding, complemented with primary

development, yields sustainable liquids growth in the near and long term; that we have the leading position in the Cardium, with one of the most attractive assets in the basin; that the analogous Cardium fields prove the upside

secondary recovery; that corporate base decline generates meaningful cash for reinvestment at leading finding and development costs; the amount of drilling prospect across key development areas; that we have kick-started a

disciplined growth story that is well position for self funded 2019 cash flow expansion; that there is a robust pipeline of drill ready prospects to quickly capitalize on incremental free cash flow; that one time legacy and regulatory costs

roll off in the second half of 2018, freeing up cash for larger 2019 development capital allocation; that the integrated waterflood improves the recovery factor with our large reserve base; and that we will add more horizontal drilling.

The key metrics for the Company set forth in this presentation may be considered to be future-oriented financial information or a financial outlook for the purposes of applicable Canadian securities laws. Financial outlook and 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 March 12, 2018. Except as expressly required by applicable securities laws, we do not undertake any obligation to publicly

update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The forward-looking statements contained in this document are expressly qualified by this cautionary statement.

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