InPlay Oil Corp

Corporate Presentation

March 2021

TSX : IPO

OTCQX : IPOOF

Investment Highlights

• Technically focused management team operating a sustainable light oil growth Company in a

challenging environment while providing top-tier production growth within Adjusted Funds Flow

(“AFF”) (1)

• Positioned in two of the most exciting light oil plays in the Western Canada Sedimentary Basin

– Highly economic and low CAPEX bioturbated Cardium light oil play

– High impact large resource shallow East Basin Duvernay light oil play (longer term asset)

• Consistently deliver top-tier organic light oil growth within AFF (excluding COVID impacted 2020)

– 2019 production growth of 7% over 2018

– 2018 production growth of 17% over 2017

• 2021 Forecast: return to top-tier light oil growth, strong AFF, significant FAFF(1)

– Guidance of 5,100 – 5,400 boe/d(2) (69% liquids) exceeds 2019 production of 5,000 boe/d (66% liquids)

– 28% - 35% organic annual production growth over 2020, 2% - 8% over 2019

– Forecasting record year of AFF (420% - 460% growth over 2020, 20% - 29% over 2019)

– Generation of Free Adjusted Funds Flow (“FAFF”) of $15 - $18 million, to be used to repay debt

• Operational & technical expertise and high quality asset base drives top quartile capital efficiencies

“Key to thriving in fundamentally changed oil and gas industry”

– PDP Finding, Development and Acquisition cost of $9.85 per boe in 2020

– Capital efficiency of $19,949 per boe/d in 2020

2 Refer to Slide Notes and Reader Advisories

(1) Adjusted funds flow and Free adjusted funds flow are non-GAAP measures. See “Non-GAAP Measures” in the Reader Advisories

(2) See “Production Breakdown by Product Type” in the Reader Advisories

3

• Weathered the COVID Storm

– Halted 2020 capital program and eliminated all workovers

– Operations review to identify uneconomic production resulting in shut-ins and curtailments

– Implemented operating and corporate cost reduction initiatives resulting in savings of ~25% in 2020

• Back to Business

– Increased liquidity and sustainability with a $25 million second lien, four year term credit facility from the

Business Development Bank of Canada

– Initiated well workovers and returned curtailed and shut-in production beginning in Q3 2020

– Resumed capital program in Q4 2020, currently achieving pre-COVID (2019) production levels

– Completed highly accretive low cost tuck-in acquisition in our core area – in a strong position to do more

• Production acquired at a fraction of the cost to drill

• Added Tier-1 inventory (significant portion of drilling activity over the next 3 - 4 years)

• Better than Ever

– Record reserves at December 31, 2020 and significant growth in an extremely challenging environment

– Strong NAV(1) BT10 per share of $1.02 (PDP), $1.94 (TP) and $3.50 (TPP)

– Q1 2021 drilling activity and other optimization projects estimated to add an additional 10% to the PDP

reserves as assigned in the December 31, 2020 Reserve Report.

– Actively executing on our recovery plans for continued measured growth, FAFF(1) and debt repayment

– Liquidity and reserves provide long term growth opportunities and value to shareholders

Refer to Slide Notes and Reader Advisories

Investment Highlights

(1) Net asset value and Free adjusted funds flow are non-GAAP measure. See “Non-GAAP Measures” in the Readers Advisories

Corporate Overview

4

OPERATING SUMMARY

2021 Average Production (light oil & liquids %) 5,100 – 5,400 boe/d (69%)(1)

2021 Hz Drilling Plans 8.0

Proved Reserves 21,624 mboe

Proved and Probable Reserves 32,816 mboe

Proved and Probable NPV BT10% ($mm) $263.7 mm

68% oil & NGLin TPP reserve booking

MARKET SUMMARY

Basic Shares Outstanding (basic / FD) (mm) 68.3 / 74.6

Market Capitalization(2) (@ $0.58 per share) (mm) $40

Enterprise Value(2) (@ $0.58 per share) (mm) $114

Liquidity (shares/day average over last 6 months) ~ 155,000

Employee & Director Ownership (diluted) 8.3%

Large Insider Shareholders (diluted) 28.1%

DEBT SUMMARY ($mm)

Bank Debt / Net Debt $63.8 / $73.7

Credit Facilities $90.0(3)



(2) Market capitalization and Enterprise value are non-GAAP measures. See “Non-GAAP Measures” in the Reader Advisories

(3) Inclusive of $25 million, second lien, four year BDC Term Facility.

Management and Directors

5

Management

Strong Technically and Value Creators

Doug Bartole, P. Eng., ICD.D

President and CEO, Director

Kevin Yakiwchuk, MSc., P. Geol.

Vice President Exploration

Gordon Reese, BSc. Geol.

Vice President Business Development

Thane Jensen, P. Eng.

Vice President Operations

Darren Dittmer, CPA, CMA

CFO

Directors

Experienced Industry Board

Doug Bartole, P. Eng., ICD.D

Jackie Bentley CPA, CA

Craig Golinowski CFA, MBA

Dennis Nerland, LLB, ICD.D

Steve Nikiforuk, CPA, CA, ICD.D

Dale Shwed

Please see appendix or InPlay’s website for additional details on Management and Directors

6

Consistent Top-Tier Organic Light Oil Growth

20

30

40

50

60

70

80

90

2016 2017 2018 2019 2020 2021e500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

Pro

du

ctio

n/s

h(b

oe

/d/m

m s

har

es)

Pro

du

ctio

n (

bo

e/d

)

Total Liquids (bbl) Gas (boe) Prod / mm shares

Production(1)

730

4

791

1

834

8

871

8

96

77

16

57

9

17

47

3

18

85

9

18

57

3

21

62

4

24486

2608427063 27295

32816

2016 2017 2018 2019 20200

5,000

10,000

15,000

20,000

25,000

30,000

35,000

Re

serv

es

(MB

OE)

PDP TP TPP

Reserves

• Significant reserves growth in 2020 compared to 2019

(PDP +11%, TP +16%, TPP +20%), an exceptional

accomplishment in comparison to our peers

• Consistently increasing reserves year over year in all

categories with top-tier FD&A costs

• Resumption of capital program in 2021 yields estimated production

growth of 28% to 35% over 2020 (2% to 8% over 2019)

Sold 250 boe/d (70% liquids) of non core assets at premium market

valuations in October 2018



2020 Year End Reserves & EfficiencyHighlights

7

Reserve Highlights

BOE

(Mboe)

NPV BT10%

($000s)

Reserves

Replacement

(%)

RLI

(Years)

Proved Developed Producing 9,677 94,599 166 6.6

Total Proved 21,624 157,201 309 14.8

Total Proved + Probable 32,816 263,691 479 22.5

Finding, Development & Acquisition Costs and Recycle Ratios

FD&A

($/boe)

Recycle

Ratio *

Avg. Peer

FD&A

($/boe)(1)

Recycle Ratio

($/boe)(1)

Proved Developed Producing 9.85 1.2 25.01 0.8

Total Proved 5.86 2.0 16.25 1.1

Total Proved + Probable 8.21 1.4 12.25 1.4


(1) “Average peer FD&A” and “Average peer Recycle Ratio” for 2020 derived from publically disclosed values for peers defined

as light oil weighted small to mid cap exploration and development companies having greater than 60% oil and liquids

weighting (BNE, GXE, TVE, WCP). Of the 9 peers evaluated in 2019, two have been sold and three did not report these

measures for 2020 given the difficult circumstances during the year.

* Strong Recycle Ratio: $1 capital invested returns $2+

IPO Providing Top-Tier Efficiencies in Finding Reserves and Adding Producing Barrels

8

IPO 3 Year Finding Costs & Recycle Ratios - Consistent & Top-Tier

IPO 3 year average PDP FD&A of $11.08/boe, recycle ratio of 1.8

IPO 3 year average TP FD&A of $9.95/boe, recycle ratio of 2.0

IPO 3 year average TPP FD&A of $9.92/boe, recycle ratio of 2.0

IPO Capital Efficiencies Adding Producing Boed - Consistent & Top-Tier

2020 capital efficiency of $19,949 per boe/d

3 year average capital efficiency of $17,702 per boe/d0

1

2

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

IPO A B Avg C D E F G

PDP FD&A ($/boe) Recycle Ratio (x)

2020 PDP FDA & Recycle Ratios Versus Peers2

2020 TPP FDA & Recycle Ratios Versus Peers

0

1

2

$0.00

$5.00

$10.00

$15.00

$20.00

A IPO Avg B C F D E G

TPP FD&A ($/boe) Recycle Ratio (x)

2

2020 TP FDA & Recycle Ratios Versus Peers

0

1

2

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

IPO A B Avg F C D E G

TP FD&A ($/boe) Recycle Ratio (x)

2

• The peers above are defined as light oil weighted small to large cap exploration and development companies having

greater than 60% oil and liquids weighting (BNE, CJ, GXE, OBE, SGY, TVE, WCP). Data sourced from publicly

available data sources, including the Annual Information Form for the year ended December 31, 2020 for each issuer

Of the 9 peers evaluated in 2019, two have been sold and three did not report these

measures for 2020 given the difficult circumstances during the year

Environmental Leadership


• Reduction in CO2 emissions by 12% in 2018 and 25% in 2019

compared to prior year. 2% reduction in 2020 compared to 2019,

despite COVID-19 production shut-ins and curtailments

• Environmental investment in a Vapor Recovery Unit providing a

492,000 m3 reduction in vented gas since Q2 2019

• Increasing gas conservation through operations including the 100%

utilization of pneumatic controls at field sites

• Rigorous pipeline integrity program to mitigate risk of environmental

impact, with regular visual inspections being performed

• Obtained $1.8 million from the Alberta government’s Site

Rehabilitation Program (“SRP”) in 2020 with additional grants

expected in subsequent phases of the program

• Approved for the AER’s Area Based Closure (“ABC”) program

spending approximately 3 - 4 % of AFF on decommissioning in 2021

• Program design allows for spending in a focused area

• Industry has seen decommissioning costs reduced up to 40%

due to the ABC efficiencies

• No reportable spills or lost time incidents in 2019 or 2020

0%

5%

10%

15%

20%

0

500

1,000

1,500

2,000

2017 2018 2019 2020 2021e

AR

O S

pe

nd

/In

acti

ve L

iab

ility

(%

)A

RO

Sp

en

d/A

dj.

Fu

nd

s Fl

ow

(%

)

$’0

00

s

Environmental Liability

ARO Spend ARO Spend/Adj. Funds Flow

ARO Spend/Inactive Liability

0.00

0.01

0.02

0.03

0.04

2017 2018 2019 2020

GHG Emissions

Tonnes of CO2 Equivalent per boe

12%

25%2%

* Spending includes grants from Alberta’s Site Rehabilitation Program * Grants from subsequent phases of the program have not been incorporated

10

2021e Production

boe/d (% liquids) (1)

Net Drilling

InventoryFormations

Willesden Green 2,715 (61%) 102 Cardium

Pembina 2,205 (81%) 153Cardium

Belly River

Other 330 (64%) 300Mannville,

Nisku, Duvernay

Total 5,250 (69%) 555

0

1,000

2,000

3,000

4,000

5,000

6,000

Jan/21 Apr/21 Jul/21 Oct/21 Jan/22 Apr/22 Jul/22 Oct/22

Bas

e P

rod

uct

ion

(b

oe

/d)

PDP (boed)

2021Decline: 26% 2022

Decline: 16%

Top Quartile declines in oil weighted growth universe

90% Cardiumproduction Calgary

Edmonton

A L B E R T A

PEMBINA

WILLESDEN GREEN

E. BASINDUVERNAY

30

40

50

60

70

80

2016 2017 2018 2019 2020 2021e30%

35%

40%

45%

50%

55%

60%

65%

WTI

($

US)

Op

era

tin

g In

com

e P

rofi

t M

argi

n (2

)Operating Income Profit Margin Average $WTI

• Consistently increased corporate margins

• Implemented cost reduction initiatives during 2020 price collapse with

savings of ~25% and ~10% to be retained going forward

Focused Light Oil Producer with Low Decline High Margin Operations

Low decline light oil weighted production + high netbacks + economic, quick payout inventory

= TOP-TIER LIGHT OIL GROWTH


(1) Yearly average production at mid-point of guidance

(2) Operating income profit margin is a non-GAAP measure. See “Non-GAAP Measures” in the Readers Advisories.

Achieved pre-COVID (2019) production levels in Q1 2021

Consistently drilling industry pacesetter 1.5 mile horizontal wells and exceeding forecasted volumes

Willesden Green Cardium

11

2019 Hz Drilling Activity : 8 (4.8 net)


2021 Hz Drilling Plans : 3 - 5 (3.0 – 5.0 net)

Upside Potential

– 102 net Hz Cardium drilling locations

– Continued efficiency improvements driving down well costs

• Drill, complete and equip cost on latest ERH program reduced by 25% (~$800k/well)

from previous program

Land : 39,043 (22,857 net) acres

Facilities : 6 operated oil facilities

InPlay Cardium Land

InPlay Cardium Hz Wells

Industry Cardium Hz Wells

Cardium Vertical Wells


1.0 Mile Hz Type Curve Economics 1.5 Mile Hz Type Curve Economics

WTIFx

(USD/CAD)

Payout

(yrs)

IRR

(%)

NPV

BT10%

($mm)

Yr 1

Netback

(Cdn/boe)

F&D

(/boe)

Recycle

Ratio

(times)

Payout

(yrs)

IRR

(%)

NPV

BT10%

($mm)

Yr 1

Netback

(Cdn/boe)

F&D

(/boe)

Recycle

Ratio

(times)

$40 $0.72 1.3 71 1.3 $33.90 $10.93 3.1 0.9 136 2.6 $34.94 $9.03 3.9

$50 $0.74 0.8 153 2.1 $41.67 $10.60 3.9 0.6 325 3.6 $42.88 $8.82 4.9

$60 $0.76 0.6 301 2.8 $49.04 $10.38 4.7 0.4 772 4.5 $50.39 $8.68 5.8

Break-even (10% IRR) $21 WTIBreak-even (10% IRR) $25 WTI

1.0 Mile 1.5 Mile

Capex (mm) $2.0 $2.7

Potential Recovery (mboe) 210 320

IP90 (boe/d) 290 460

IP365 (boe/d) 145 220

Yr1 Cap. Eff. (/ boe/d) $13,910 $12,0400

100

200

300

400

500

0 3 6 9 12

Cal

end

ar D

aily

Oil

(bb

l/d)

Month

1.0 Mile 1.5 Mile

12

Pembina




2021 Hz Drilling Plans : 3 - 5 (3.0 – 5.0 net)

Upside Potential

– 153 net Hz drilling locations (80% operated)

Land

– 57,975 (36,803 net) acres

Facilities

– 5 major oil facilities with custom treating & water disposal

– 2 (100% WI) batteries tied into Pembina Pipelines Sales

InPlay Wells

InPlay Rights

Acquisition Wells

Acquisition Rights

Cardium Vertical

Cardium Horizontal

0

50

100

150

200

250

300

0 3 6 9 12 15

Cal

end

ar D

aily

Oil

(bb

l/d)

Month

Boe/d (% oil)

IP30 IP60 IP90 IP365

183 (96) 191 (95) 186 (94) 143 (88)

Recent 1-mile wells exceeded expectations by over 43% despite production curtailments

* Production restrictions

due to low commodity pricing

1.0 Mile Hz Type Curve Economics 1.5 Mile Hz Type Curve Economics

WTIFx

(USD/CAD)

Payout

(yrs)

IRR

(%)

NPV

BT10%

($mm)

Yr 1

Netback

(Cdn/boe)

F&D

(/boe)

Recycle

Ratio

(times)

Payout

(yrs)

IRR

(%)

NPV

BT10%

($mm)

Yr 1

Netback

(Cdn/boe)

F&D

(/boe)

Recycle

Ratio

(times)

$40 $0.72 1.7 52 1.1 $36.21 $10.79 3.4 1.6 59 1.6 $41.59 $10.21 4.1

$50 $0.74 1.0 113 1.9 $46.69 $10.44 4.5 1.0 118 2.6 $52.90 $9.82 5.4

$60 $0.76 0.8 184 2.5 $54.23 $10.24 5.3 0.7 185 3.2 $61.03 $9.64 6.3

1.0 Mile 1.5 Mile

Capex (mm) $1.7 $2.3

Potential Recovery (mboe) 160 230

IP90 (boe/d) 175 190

IP365 (boe/d) 100 120

Yr1 Cap. Eff. (/ boe/d) $17,190 $18,9500

100

200

300

0 3 6 9 12

Cal

end

ar D

aily

Oil

(bb

l/d)

Month

1.0 Mile 1.5 Mile

Drilling industry pacesetter 1.0 mile horizontal wells and exceeding forecasted volumes

Break-even (10% IRR) $24 WTIBreak-even (10% IRR) $26 WTI

*

*

Pembina Acquisition Highlights

13

Total of 30 ERH Locations

Light Oil production and reserves cannot be added through the drill bit at these metrics

Strategic Cardium asset acquisition (100% WI)– Purchase Price - $1.9mm (net of adjustments)

• ~ 1.0 times 2019 net operating income

– Third party 2019 PDP/TP year end reserves of ~ 1,000 Mboe

• Acquired for ~ $1.90 per boe

• Third party 2019 PDP/TP NPV10 of $13.7mm

– Production of 240 boe/d (63% liquids), base decline of ~10%

• Acquired for ~ $7,900 per boe/d

• Increased production through optimization to 320 boe/d, levels not

seen since 2017

– Contiguous lands allow for Extended Reach Horizontal (ERH) drilling

– 30 well drilling inventory

• 23 classified as Tier-1 that compete with IPO inventory

• Drilled 3, 1.5 mile wells in Q1, 2021

• 100% WI Crown lands allow for full scale development at a pace

entirely within our control

14

7.9 – 10.8 days

(Recent 3 well pad 7.9 – 8.8 days)

Willesden Green Pembina

2,500

2,750

3,000

3,250

3,500

3,750

4,000

4.0 4.5 5.0 5.5 6.0

Mea

sure

d D

epth

(m

)

Days from Spud to RR

• All 13 of InPlay’s 1.5 mile Hz wells drilled in Willesden Green fall within the

top 25 fastest drilled to date

• Recent 3 wells in Q4 2020 were fastest and lowest cost to date

3,900

4,000

4,100

4,200

4,300

4,400

4,500

7.5 8.0 8.5 9.0 9.5 10.0 10.5 11.0

Mea

sure

d D

epth

(m

)

Days from Spud to RR

4.1 – 4.8 days

* Long build well

• All 6 of InPlay’s Pembina wells drilled in the last year fall within the 33

fastest drilled by industry, 5 are in the top 9 with 3 being the fastest

• Reduced well costs (DCE) by 25% to ~$1.8mm• Reduced well costs (DCE) by 25% to ~ $2.4mm

InPlay Drill Times vs PeersInPlay results are “Best in Class”

*

*

* Long build well

*

15

48.4 Crown Sections in the Huxley Area (30,480 net acres)

– Crown lands provide 5% royalties for 4-6 years @ $60-$70 WTI

– Extensive activity directly offsetting InPlay’s land

• Long land tenure allows InPlay a measured pace of development as

others prove up the play around us

Significant Light Oil Resource (high quality oil - premium price to Edmonton Light)

Upside Potential

– Potential recovery of 250 mbbl to >500 mbbl per well

– 290 net drilling locations (at 6 wells / section) targeting Upper Duvernay

• Hz wells been drilled into Lower Duvernay show similar production

results as Upper Duvernay

– Well costs reflect pad development scenario; single delineation wells

currently estimated to cost 30%-40% more

Joffre

HuxleyInPlay Duvernay Rights

Leduc Reef

Duvernay Depth (m)

Duvernay Wells


East Basin Duvernay Shale Emerging Light Oil Play

0

20

40

60

80

100

01,0002,0003,0004,0005,0006,0007,0008,0009,000

Pro

d H

z W

ell

Co

un

t

Pro

du

ctio

n (

bo

e/d

)

Huxley Area Industry Production

* Production restrictions due to low commodity pricing

*

US$50 WTI Oil Price (NPV 10% / IRR)

EUR vs. CAPEX$4.5mm

(1 mile)

$5.5mm

(1.5 mile)

$6.5mm

(2 mile)

250 mbbl $3.1mm / 38% $2.1mm / 24% $1.2mm / 16%

315 mbbl $4.9mm / 64% $4.1mm / 40% $3.1mm / 27%

400 mbbl $7.2mm / 124% $6.6mm / 75% $5.9mm / 50%

500 mbbl $10.1mm / 261% $9.5mm / 144% $8.9mm / 92%

US$60 WTI Oil Price (NPV 10% / IRR)

250 mbbl $4.1mm / 51% $3.2mm / 32% $2.2mm / 22%

315 mbbl $5.9mm / 86% $5.3mm / 54% $4.4mm / 37%

400 mbbl $8.5mm / 173% $8.0mm / 101% $7.3mm / 67%

500 mbbl $11.6mm / 396% $11.1mm / 205% $10.6mm / 127%

2021 ForecastCommodity Price Assumptions

WTI oil price (US$/bbl) $60.50

Edmonton par (C$/bbl) $71.50

AECO gas price ($/GJ) $2.60

Operational Forecast

Average production (boe/d) (% liquids) 5,100 – 5,400 (69%)

Adjusted funds flow ($mm) (1)(2) $39.0 - $42.0

Free adjusted funds flow ($mm) (1)(2) $15.0 - $18.0

Funds flow ($mm) (1) $37.5 - $40.5

Capital program ($mm) $23

Net horizontal wells 8.0

Net Debt/EBITDA (1)(2) 1.3x – 1.5x

Sensitivities - Adjusted funds flow

+/- $5/bbl WTI (mm) – assumes price change from April 1 – December 31, 2021 $2.1 / ($3.3)

+/- $0.25/mcf AECO (mm) – assumes price change from April 1 – December 31, 2021 $0.4 / ($0.4)


(1) Refer to the “Forward Looking Information” section in the “Readers Advisories” for the assumptions used in the calculation of forecasted 2020

“Funds flow”, “Adjusted funds flow”, “Free adjusted funds flow” and “Net Debt/EBITDA”

(2) Adjusted funds flow, Free adjusted funds flow and Net Debt/EBITDA are a non-GAAP measures. See “Non-GAAP Measures” in the Reader Advisories

2020 Year End Net Asset Value

17

PDP

($000s)

TP

($000s)

TPP

($000s)

NPV BT10% 94,599 157,201 263,691

Undeveloped Land 49,029

Net Debt (73,681)

Net Asset Value (1) 69,947 132,549 239,039

Basic Common Shares 68,257

2020 NAV / Share $1.02 $1.94 $3.50

2019 NAV / Share $1.70 $2.87 $4.56

Future Development Capital ($000s) 169,800 258,500

Years of 2020 CAPEX 7.3 11.2


(1) Net asset value is a non-GAAP measure. See “Non-GAAP Measures” in the Readers Advisories.

The reduction in 2020 NAV from 2019 NAV is primarily due to the following decrease in the reserve evaluator’s price decks:

– WTI prices dropping 28%, 24% and 20% in years 1, 2 and 3 respectively and 19% for the remaining years.

– Propane prices dropping 43% and 28% in years 1 and 2 respectively and 21-23% for the remaining years.

– Butane prices dropping 41% and 30% in years 1 and 2 respectively and 16% for the remaining years.

– AECO spot gas prices increasing 21% in year 1, decreasing 4% in year 2 and decreasing 10-13% for the remaining years.

Current WTI strip pricing for 2021 and 2022 is approximately 34% and 13% higher than the pricing used in the 2020 Reserve Report.

Summary

• Strong team managing a sustainable Company through a challenging environment

• Aggressive and effective response to COVID; now positioned for continued growth

• Top decile organic per share light oil production growth while also generating FAFF(1)

of $15mm - $18mm

• Financially strong with 2021 expected Net Debt/EBITDA(1) of 1.3 to 1.5 times

• Positioned for more tuck-in acquisitions in current environment

• Significant torque to upside with oil pricing

• ‘Best in Class’ operational and technical acumen

– Driving costs lower and exceeding production forecasts equate to continued

stronger capital efficiencies and reserve additions

“Key to thriving in fundamentally changed O&G industry”

18

(1) Free adjusted funds flow and Net Debt/EBITDA are non-GAAP measures. See “Non-GAAP Measures” in the Reader Advisories

19

Appendix

InPlay TeamStrong Technically and Value Creators

Doug Bartole, President and CEO and Director, P. Eng., ICD.D (over 27 years)

• Founder of InPlay; Founder, President and CEO of Vero Energy; VP Operations of True Energy; Management and Engineering roles at Husky Energy, Renaissance Energy and PanCanadian Petroleum

• Director of Invicta Energy (founder of Royal Acquisition Corp. which was the public RTO vehicle for Invicta)

• Member of APEGA, Institute of Corporate Directors, and a Governor of CAPP (Canadian Association of Petroleum Producers)

Kevin Yakiwchuk, Vice President Exploration, MSc, P. Geol. (over 26 years)

• Founder of InPlay; Founder and VP Exploration at Vero Energy; VP Exploration at True Energy; Geologist at Crestar Energy,Renaissance Energy and Shell Canada

Gordon Reese, BSc. Geol., Vice President Business Development (over 40 years)

• Founder, President and CEO of Invicta Energy; President and CEO at Cipher Energy, VP Exploration at True Energy andvarious prospect generation and management roles at CS Resources and Gulf Canada

Thane Jensen, Vice President Operations, P. Eng. (over 27 years)

• Sr. V.P. Operations, Exploration and Development, and prior VP Engineering at Penn West Exploration

• Reservoir Engineer, Exploitation Engineer, and Drilling and Completions Engineer at PanCanadian Petroleum Ltd.

Darren Dittmer, CFO, CPA, CMA (over 25 years)

• CFO of Barrick Energy Inc. from September 2008 until sale of all assets in July 2013

• Controller and CFO of Cadence Energy and prior Controller of Kereco Energy, Ketch Resources and Upton Resources

20

21

Risk Management


Hedges (Commodity derivative contracts)

2021 2022

Q1 Q2 Q3 Q4 Q1

Natural Gas AECO Swap (GJ/d) 4,000 4,750 4,750 2,925 -

Hedged price ($AECO/GJ) $2.64 $2.46 $2.46 $2.40 -

Natural Gas AECO Costless Collar (GJ/d) - - - 1,325 2,000

Hedged price – ($AECO/GJ)Floor

Ceiling- - -

$2.70

$3.36

$2.70

$3.36

Crude Oil WTI Swap (bbl/d) 1,915 1,750 250 250 -

Hedged price – ($USD WTI/bbl)(1) $45.48 $46.18 $51.35 $51.35 -

Crude Oil WTI Costless Collar 250 250 250 250 -

Hedged price – ($USD WTI/bbl)Floor

Ceiling

$34.50

$50.15

$34.50

$50.15

$52.00

$69.00

$52.00

$69.00-

Crude Oil WTI Three-way Collar - 250 1,000 1,000 -

Hedged price – ($CAD WTI/bbl)(2)(3)

Low put

Mid put

High call

-

$57.53

$63.29

$77.99

$57.47

$63.98

$79.38

$57.47

$63.98

$79.38

-

(1) Assumes $0.79 CAD/USD FX rate.

(2) Assumes $0.79 CAD/USD FX rate and incorporates the impact of three CAD/USD FX hedges with an average exchange rate

of $0.782 – Q2/21, $0.786 – Q3/21 and $0.786 – Q4/21.

(3) The WTI three-way collars are a combination of a high priced call, low priced put and a mid priced put. The high call price is

the maximum price the Company will receive for the contract volumes. The mid put price is the minimum price InPlay will

receive, unless the market price falls below the low put strike price, in which case InPlay receives market price less the

difference between the mid put price minus the low put price.

Slide Notes

22

Slide 21. Production and adjusted funds flow growth rates and free adjusted funds flow are based on forecasted assumptions outlined in the “Forward Looking Information and Statements” in the Reader Advisories.

2. Refer to press release dated March 17, 2021 for details of 2020 Capital efficiency and PDP Finding, Development and Acquisition (“FD&A”) cost.

Slide 31. See “Drilling Locations” within “Oil and Gas Advisories” in the Reader Advisories.

2. See “Reserves” within “Oil and Gas Advisories” in the Reader Advisories.

Slide 41. Production rates and 2021 drilling plans are based on forecasted assumptions as outlined in the “Forward Looking Information and Statements” section in the Reader Advisories.

2. Reserves and NPV are derived from InPlay’s independent reserve evaluation effective December 31, 2020, see “Reserves” and “Net Present Value Estimates” within “Oil and Gas Advisories” in the Reader

Advisories.

3. Shares (basic and fully dilutive) outstanding at the date of this presentation

4. Market capitalization and Enterprise value based on current share price. Bank debt and Net debt as of December 31, 2020

Slide 61. Annual average production and growth rates are based on forecasted assumptions as outlined in the “Forward Looking Information and Statements” section in the Reader Advisories.

2. See “Reserves” within “Oil and Gas Advisories” in the Reader Advisories.

Slide 71. Reserves and NPV are derived from InPlay’s independent reserve evaluation effective December 31, 2020, see “Reserves” and “Net Present Value Estimates” within “Oil and Gas Advisories” in the Reader

Advisories.

2. Refer to notes in InPlay’s press release dated March 17, 2021 for details of 2020 Reserves replacement, Reserve life index (“RLI”), FD&A and Recycle ratio calculations.

3. “Average peer FD&A” and “Average peer Recycle Ratio” for 2020 derived from publically disclosed values for peers defined as light oil weighted small to large cap exploration and development companies

having greater than 60% oil and liquids weighting (BNE, GXE, TVE, WCP)

Slide 81. Refer to notes in InPlay’s press release dated March 17, 2021 for details of 2020 Capital efficiencies, FD&A and Recycle ratio calculations.

2. The peers in the referenced slide are defined as light oil weighted small to large cap exploration and development companies having greater than 60% oil and liquids weighting (BNE, CJ, GXE, OBE, SGY, TVE,

WCP).

Slide 91. 2021 Decommissioning expenditures as a % of AFF is based on forecasted assumptions as outlined in the “Forward Looking Information and Statements” section in the Reader Advisor ies.

Slide 101. Reflects annual average production and liquids weighting based on forecasted assumptions as outlined in the “Forward Looking Information and Statements” section in the Reader Advisories.

2. See “Drilling Locations” under “Oil and Gas Advisories” in the Reader Advisories.

3. Decline based on PDP from InPlay’s independent reserve evaluation effective December 31, 2020; assumes no additional drilling. See “Reserves” under “Oil and Gas Advisories” in the Reader Advisories.

4. See “Forward Looking Information and Statements” in the Reader Advisories for material assumptions used to forecast Operating income profit margin for 2021.

Slide 111. See “Type Curves and Potential Recovery Estimates” under “Oil and Gas Advisories” in the Reader Advisories.

2. See “Drilling Locations” within “Oil and Gas Advisories” in the Reader Advisories.

3. Upside potential Cardium locations identified as 1 mile equivalents at maximum of 6 wells per section.

4. New well economics are based on: WTI/Edmonton Par light oil differential of negative $3.20 / $4.00 / $4.80 respectively over indicated WTI pricing range, AECO $2.75/GJ

5. Based on half cycle costs, “Recycle Ratio” based on first year netbacks

Slide Notes (continued)

23

Slide 121. See “Type Curves and Potential Recovery Estimates” under “Oil and Gas Advisories” in the Reader Advisories.


3. New well economics are based on: WTI/Edmonton Par light oil differential of negative $3.20 / $4.00 / $4.80 respectively over indicated WTI pricing range, AECO $2.75/GJ

4. Based on half cycle costs, “Recycle Ratio” based on first year netbacks

Slide 131. See “Drilling Locations” within “Oil and Gas Advisories” in the Reader Advisories.

2. Reserves assigned by the seller’s independent external reserve evaluator effective January 1, 2020

Slide 141. Peer drilling data sourced from geoLOGIC Systems Ltd database.

Slide 151. Internal valuation of Duvernay land is based on area land sales.


3. Potential recovery estimates for the area are internal estimates made by comparing industry historical well results surrounding InPlay’s land base in the area to the type curve library noted in the “Type

Curves and Potential Recovery Estimates” section in “Oil and Gas Advisories” to identify the most applicable type curve and associated recovery. The referenced estimates are meant to closely

approximate Proved Plus Probable Undeveloped reserves as defined by COGE. Given the process described above however, these estimates are considered internally generated recovery estimates

prepared by InPlay’s technical team and are not reserve of resource estimates prepared in accordance with the requirements of COGE.

4. Economics are based on: WTI/Edmonton Par light oil differential of negative $2.50 / $4.00 / $5.50 respectively over indicated WTI pricing range, AECO $2.00/GJ

5. Economics assume Crown land for royalties payable on produced volumes (InPlay’s Duvernay lands are 100% Crown)

6. See “Estimated Ultimate Recovery” within “Oil and Gas Advisories” in the Reader Advisories.

Slide 161. Funds flow is a GAAP measure which includes impacts of decommissioning obligation expenditures and is presented as it is the closest GAAP measure to Adjusted funds flow.

2. Sensitivities indicated are applicable for the period from April 1, 2021 – December 31, 2021

Slide 171. Reserves and associated reserve values are derived from InPlay’s independent reserve evaluation effective December 31, 2020.

2. See “Reserves” and “Net Present Value Estimates” under under “Oil and Gas Advisories”. Changes in 2020 NAV from 2019 NAV include, but are not limited to: impact of Reserve Report WTI price deck

dropping 28%, 24% and 20% in years 1, 2 and 3 respectively and 1% for the remaining years thereafter with respect to December 31, 2019 Reserve report price deck.

3. Duvernay land holdings attributed a value of $36.6 mm ($1,200/acre) for 30,480 net acre based on internal valuations. The remaining undeveloped acreage is based on an internal valuation totaling

$12.5 mm ($351/acre) for 35,452 net acres. These internal valuations are based on land sale results in the area.

4. Net debt and basic shares outstanding as at December 31, 2020.

Slide 181. Free adjusted funds flow and Net Debt/EBITDA are based on forecasted assumptions outlined in the “Forward Looking Information and Statements” in the Reader Advisories.

24

All amounts in this presentation are stated in Canadian dollars unless otherwise specified. Throughout this presentation, the terms Boe (barrels of oil equivalent) and Mmboe (millions of barrels of oil equivalent) are used. Such termswhen used in isolation, may be misleading. In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties and without including anyroyalty interest, unless otherwise stated. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on "company gross reserves" using forecast prices and costs. Completedisclosure of our oil and gas reserves and other oil and gas information in accordance with NI 51-101 is available on our SEDAR profile at www.sedar.com. The recovery and reserve estimates contained herein are estimates onlyand there is no guarantee that the estimated reserves will be recovered. In relation to the disclosure of estimates for individual properties, such estimates may not reflect the same confidence level as estimates of reserves and futurenet revenue for all properties, due to the effects of aggregation. The Company's belief that it will establish additional reserves over time with conversion of probable undeveloped reserves into proved reserves is a forward-lookingstatement and is based on certain assumptions and is subject to certain risks, as discussed previously under the heading "Forward-Looking Information and Statements".

The information contained in this corporate presentation does not purport to be all-inclusive or to contain all information that a prospective investor may require. Prospective investors are encouraged to conduct their own analysisand reviews of InPlay and of the information contained in this corporate presentation. Without limitation, prospective investors should consider the advice of their financial, legal, accounting, tax and other advisors and such otherfactors they consider appropriate in investigating and analyzing InPlay.

Oil and Gas Advisories

The recovery and reserve estimates of InPlay's reserves provided herein are estimates only and there is no guarantee that the estimated reserves with be recovered. Throughout this presentation various references are made to"potential" and "targeted" resource and recoveries which have been prepared by management of InPlay and are not estimates of reserves or resources. Accordingly, undue reliance should not be placed on same. Such informationhas been prepared by management for the purposes of making capital investment decisions and for internal budget preparation only. In addition, forward-looking statements or information are based on a number of material factors,expectations or assumptions of InPlay which have been used to develop such statements and information but which may prove to be incorrect. Although InPlay believes that the expectations reflected in such forward-lookingstatements or information are reasonable, undue reliance should not be placed on forward-looking statements because InPlay can give no assurance that such expectations will prove to be correct. In addition to other factors andassumptions which may be identified herein, assumptions have been made regarding, among other things: the impact of increasing competition; the general stability of the economic and political environment in which InPlayoperates; the timely receipt of any required regulatory approvals; the ability of InPlay to obtain qualified staff, equipment and services in a timely and cost efficient manner; the ability of InPlay to add production and reserves throughacquisition, development and exploration activities; drilling results; the ability of the operator of the projects in which InPlay has an interest in to operate the field in a safe, efficient and effective manner; field production rates anddecline rates; the ability to replace and expand oil and natural gas reserves through acquisition, development and exploration; risks associated with the degree of certainty in resource assessments; the timing and cost of pipeline,storage and facility construction and expansion and the ability of InPlay to secure adequate product transportation; future commodity prices; currency, exchange and interest rates; regulatory framework regarding royalties, taxes andenvironmental matters in the jurisdictions in which InPlay operates; and the ability of InPlay to successfully market its oil and natural gas products.

Certain information in this document may constitute "analogous information" as defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities ("NI-51-101"), including but not limited to, information relatingto the areas in geographical proximity to lands that are or may be held by InPlay. Such information has been obtained from government sources, regulatory agencies or other industry participants. InPlay believes the information isrelevant as it helps to define the reservoir characteristics in which InPlay may hold an interest. InPlay is unable to confirm that the analogous information was prepared by a qualified reserves evaluator or auditor. Such information isnot an estimate of the reserves or resources attributable to lands held or potentially to be held by InPlay and there is no certainty that the reservoir data and economics information for the lands held or potentially to be held by InPlaywill be similar to the information presented herein. The reader is cautioned that the data relied upon by InPlay may be in error and/or may not be analogous to such lands to be held by InPlay.

Any references in this presentation to initial, early and/or test or production/performance rates are useful in confirming the presence of hydrocarbons, however, such rates are not determinate of the rates at which such wells willproduce or continue production and to decline thereafter. Additionally, such rates may also include recovered "load oil" fluid used in well completion stimulation. Readers are cautioned not to place reliance on such rates incalculating the aggregate production for InPlay. The initial production rate may be estimated based on other third-party estimates or limited data available at this time. In all cases in this presentation, initial production or tests are notnecessarily indicative of long-term performance of the relevant well or fields or of ultimate recovery of hydrocarbons.

References to light oil, NGLs or natural gas production in this press release refer to the light and medium crude oil, natural gas liquids and conventional natural gas product types, respectively, as defined in NI-51-101.

Reserves – All reserves disclosed in this presentation are derived from InPlay’s independent reserve evaluation effective December 31, 2020, complete details of which can be found within our Annual Information form filed onSEDAR. 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 associatedwith the estimates as follows:

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.

Proved Developed Producing Reserves are those proved 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.

Proved Developed Producing Reserves are those proved 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 isunknown.

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 theestimated proved plus probable reserves.

Test Results and Initial Production Rates - A pressure transient analysis or well-test interpretation has not been carried out and thus certain of the test results provided herein should be considered to be preliminary until suchanalysis or interpretation has been completed. Test results and initial production rates disclosed herein may not necessarily be indicative of long term performance or of ultimate recovery. Initial Production “IP”) rates indicate theaverage daily production over the indicated daily period.

BOE equivalent - Barrel of oil equivalents or BOEs may be misleading, particularly if used in isolation. A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burnertip 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 than the energy equivalency of 6:1, utilizing a 6:1conversion basis may be misleading as an indication of value.

Estimated Ultimate Recovery – Estimated Ultimate Recovery (“EUR”) is an approximation of the quantity of oil or gas that is potentially recoverable or has already been recovered from a reserve or well. EUR is not a defined termwithin the COGE Handbook and therefore any reference to EUR in this presentation is not deemed to be reported under the requirements of NI 51-101. Readers are cautioned that there is no certainty that the Company willultimately recover the estimated quantity of oil or gas from such reserves or wells.

Net Present Value Estimates - It should not be assumed that the net present value of the estimated future net revenues of the reserves of InPlay included in this presentation represent the fair market value of the reserves. There isno assurance that the forecast prices and cost assumptions will be attained and variances could be material.

Reader Advisories

25

Oil and Gas Advisories (cont’d)

Type Curves and Potential Recovery Estimates - The type curves presented herein reflect a selection from a type curves library provided by InPlay’s independent reserve evaluator. In each case the type curve presented is thatwhich in management’s assessment feels best represents the expected average drilling results based upon InPlay producing wells in the area as well as non-InPlay wells determined by management to be analogous for purposes ofthe type curve assignments. Type curves presented incorporate the most recent data from actual well results and would only be representative of the specific drilled locations. There is no guarantee that InPlay will achieve theestimated or similar results derived therefrom. The referenced potential recovery estimates are meant to approximate Proved Plus Probable Undeveloped reserves as defined by COGE. The potential recovery estimates have beengenerated using the relevant oil type curve noted above and incorporating management assumptions relating to gas and NGL amounts which are based on historical results. These estimates are considered internally generatedrecovery targets developed by InPlay’s technical team and are not reserve or resource estimates prepared in accordance with the requirements of COGE. Accordingly, undue reliance should not be placed on the same. Suchinformation has been prepared by management for the purposes of making capital investment decisions and for internal budget preparation only.

Drilling Locations - This presentation discloses drilling locations in two categories: (i) booked locations; and (ii) unbooked locations. Booked locations are proved locations and probable locations derived from the InPlay’sindependent reserves evaluation effective December 31, 2020 and account for drilling locations that have associated proved and/or probable reserves, as applicable. Of the 555 drilling locations identified herein, 92 are booked asproved plus probable locations, 31 are booked as probable locations and 432 are unbooked locations. Unbooked locations are management estimates based on prospective acreage and an assumption as to the number of wells thatcan be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by management as an estimation of theCompany's potential multi-year drilling activities based on evaluation of applicable geologic, seismic, engineering, production and reserves information. There is no certainty that the InPlay will drill all unbooked drilling locations and ifdrilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drilling locations on which InPlay actually drills wells will depend upon the availability of capital, regulatoryapprovals, seasonal 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 either InPlay restrictions,oil and other industry participants drilling existing wells in relative close proximity to such unbooked drilling locations, certain unbooked drilling locations are farther away from existing wells where management has less informationabout the characteristics of the reservoir. Therefore, there is uncertainty whether wells will be drilled in such unbooked locations and if drilled there is more uncertainty that such wells will result in additional oil and gas reserves,resources or production.

Oil & Gas Metrics - This presentation may contain metrics commonly used in the oil and natural gas industry, such as "finding and development costs", "finding and development recycle ratio", "finding, development and acquisitioncosts", "finding, development and acquisition recycle ratio", “payout”, "RLI" and "IRR". These terms do not have standardized meanings or standardized methods of calculation and therefore may not be comparable to similarmeasures presented by other companies, and therefore should not be used to make such comparisons. Management uses oil and gas metrics for its own performance measurements and to provide shareholders with measures tocompare InPlay's operations over time. Readers are cautioned that the information provided by these metrics, or that can be derived from the metrics presented in this presentation, should not be unduly relied upon.

Finding and development costs ("F&D costs") are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the prior year for the particular reserve category and the costsincurred on exploration and development activities in the year by the change in reserves from the prior year for the reserve category.

F&D recycle ratio is calculated by dividing the operating netback per boe for the period by the F&D costs per boe for the particular reserve category.

Finding, development and acquisition costs ("FD&A costs") are calculated on a per boe basis by dividing the aggregate of the change in future development costs from the prior year for the particular reserve categoryand the costs incurred on exploration and development activities and property acquisitions (net of dispositions) in the year by the change in reserves from the year for the reserve category.

FD&A recycle ratio is calculated by dividing the operating netback per boe for the period by the FD&A costs per boe for the particular reserve category.

Payout refers to the time required to pay back the capital expenditures (on a before tax basis) of a project.

Reserve Life Index (“RLI”) is calculated by dividing the quantity of a particular reserve category of reserves by the forecast of the first year's production for the corresponding reserve category.

Reserve Replacement: The reserves replacement ratio is calculated by dividing the yearly change in reserves before production by the actual annual production for that year.

Internal Rate of Return (“IRR”) refers to the discount rate that makes the net present value of all cash flows of a project equal zero.

Forward Looking Information and Statements

This presentation contains forward-looking statements and forward-looking information within the meaning of applicable securities laws. The use of any of the words "expect", "anticipate", "continue", "estimate", "objective", "ongoing","may", "will", "project", "should", "believe", "plans", "intends" and similar expressions are intended to identify forward-looking information or statements. More particularly and without limitation, this presentation includes forward-looking information and statements about our strategy, plans and focus, forecast annual growth rates, planned capital expenditures and the source of funding of our capital program, expected future production and product mix, thequantity and estimated value of reserves, forecast operating and financial results including funds flow, adjusted funds flow, operating income profit margin, drilling inventories and drilling plans, anticipated debt levels, forecastedcommodity prices and differentials, forecasted exchange rates, anticipated production costs and capital efficiencies.

This corporate presentation contains future-oriented financial information and financial outlook information (collectively, "FOFI") about InPlay's prospective results of operations, funds flow, adjusted funds flow, and componentsthereof, all of which are subject to the same assumptions, risk factors, limitations, and qualifications as set forth in the above paragraphs. FOFI contained in this corporate presentation was made as of the date of this corporatepresentation and was provided for the purpose of providing further information about InPlay's future business operations, InPlay disclaims any intention or obligation to update or revise any FOFI contained in this corporatepresentation, whether as a result of new information, future events or otherwise, unless required pursuant to applicable cautioned that the FOFI contained in this corporate presentation should not be used for purposes other than forwhich it is disclosed herein.

Total Locations Proved Locations Probable Locations Unbooked Locations

Willesden Green Cardium 102 27% 9% 17%

Pembina Cardium 94 43% 53% 92%

Pembina Belly River 59 26% 35% 6%

Duvernay 290 1% 3% 67%

Other 10 2% 0% 2%

Total 555 100% 100% 100%

Reader Advisories (continued)

26

Reader Advisories (continued)Forward Looking Information and Statements (cont’d)

Additionally, readers are advised that historical results, growth and transactions described in this presentation may not be reflective of future results, growth and transactions with respect to InPlay.

The forward-looking statements and information are based on certain key expectations and assumptions made by InPlay and its management, including expectations and assumptions concerning general economic conditions inCanada, the United States and elsewhere, and oil and gas industry conditions, including applicable royalty rates and environmental and tax laws and regulations. Although InPlay believes that the expectations and assumptions onwhich such forward-looking statements and information are based are reasonable as of the date hereof, undue reliance should not be placed on the forward-looking statements and information because InPlay can give no assurancethat they will prove to be correct.

Since forward-looking statements and information address future events and conditions, by their very nature they involve inherent risks and uncertainties. Actual results could differ materially from those currently anticipated due to anumber of factors and risks including, but not limited to the risks associated with the oil and gas industry in general. Readers are cautioned that the foregoing list of factors is not exhaustive. The forward-looking statements andinformation contained in this presentation are made as of the date hereof and InPlay undertakes no obligation to update publicly or revise any forward-looking statements or information, whether as a result of new information, futureevents or otherwise, unless so required by applicable securities laws.

In addition, this presentation contains certain forward-looking information relating to economics for drilling opportunities in the areas that InPlay has an interest. Such information includes, but is not limited to, anticipated payoutrates, rates of return, profit to investment ratios and recycle ratios which are based on additional various forward looking information such as production rates, anticipated well performance and type curves, the estimated net presentvalue of the anticipated future net revenue associated with the wells, anticipated reserves, anticipated capital costs, anticipated finding and development costs, estimated ultimate recoverable volumes, anticipated future royalties,operating expenses, and transportation expenses.

Forward Looking Information Assumptions

The key budget and underlying material assumptions used by the Company in the development of its planned 2021 capital program and associated guidance including forecasted 2021 production, funds flow, adjusted funds flow,free adjusted funds flow, Net Debt, Net Debt/EBITDA ratio and operating income profit margin are as follows:

Prior Guidance

FY 2021(1)

Updated Guidance

FY 2021

WTI US$/bbl $49.50 $60.50

NGL Price $/boe $24.50 $27.30

AECO $/GJ $2.45 $2.60

Foreign Exchange rate (US$/CDN$) 0.78 0.79

MSW Differential US$/bbl $4.95 $4.00

Production Boe/d 5,100 – 5,400 5,100 – 5,400

Royalties $/boe 2.90 – 3.40 3.90 – 4.50

Operating expenses $/boe 11.50 – 13.50 11.50 – 13.50

Transportation $/boe 0.80 – 0.90 0.80 – 0.90

Interest $/boe 2.25 – 2.75 2.25 – 2.75

General and administrative $/boe 2.60 – 3.10 2.60 – 3.10

Hedging (gain)/loss $/boe 0.80 – 1.20 3.75 – 4.25

Capital Expenditures $ millions $23 $23

Decommissioning Expenditures $ millions $1.3 – $1.5 $1.3 – $1.5

Net Debt $ millions $65.0 - $68.0 $58.0 - $61.0

Forecasted Adjusted Funds Flow $ millions $30.5 - $33.5 $39.0 - $42.0

Forecasted Funds Flow $ millions $29.0 - $32.0 $37.5 - $40.51. As per press release dated January 7, 2021

• Forecasted production breakdown is as follows: light oil - 56%, natural gas liquids - 13%, natural gas – 31%. See “Production Breakdown by Product Type” below

• Quality and pipeline transmission adjustments may impact realized oil prices in addition to the MSW Differential provided above

• Changes in working capital are not assumed to have a material impact between Dec 31, 2020 and Dec 31, 2021

Prior Guidance

FY 2021(1)

Updated Guidance

FY 2021


Capital Expenditures $ millions $23 $23

Forecasted Free Adjusted Funds Flow $ millions $7.5 - $10.5 $15.0 - $18.0

Prior Guidance

FY 2021(1)

Updated Guidance

FY 2021


Interest $/boe 2.25 – 2.75 2.25 – 2.75

EBTDA $ millions $35.5 - $38.5 $43.0 - $46.0

Net Debt $ millions $65.0 - $68.0 $58.0 - $61.0

Net Debt/EBITDA 1.7 – 1.9 1.3 – 1.5

27

Reader Advisories (continued)

Non-GAAP Measures

Included in this document are references to the terms “adjusted funds flow”, “free adjusted funds flow”, “operating income profit margin”, “Net Debt/EBITDA”, “net asset value”, “market capitalization” and “enterprise value”.Management believes these measures are helpful supplementary measures of financial and operating performance and provide users with similar, but potentially not comparable, information that is commonly used by other oil andnatural gas companies. These terms do not have any standardized meaning prescribed by GAAP and should not be considered an alternative to, or more meaningful than, “funds flow”, “profit (loss) before taxes”, “profit (loss) andcomprehensive income (loss)” or assets and liabilities as determined in accordance with GAAP as a measure of the Company’s performance and financial position. InPlay’s determination of these Non-GAAP measures may not becomparable to those reported by other companies. For a reconciliation to the nearest GAAP figure, where applicable, for adjusted funds flow, free adjusted funds flow and operating income profit margin, refer to section titled“Forward Looking Information Assumptions”.

Adjusted Funds Flow - InPlay uses “adjusted funds flow” as a key performance indicator. Adjusted funds flow should not be considered as an alternative to or more meaningful than funds flow as determined in accordance withGAAP as an indicator of the Company’s performance. InPlay’s determination of adjusted funds flow may not be comparable to that reported by other companies. Adjusted funds flow is calculated by adjusting for decommissioningexpenditures from funds flow. This item is adjusted from funds flow as decommissioning expenditures are incurred on a discretionary and irregular basis and are primarily incurred on previous operating assets, making the exclusionof this item relevant in Management’s view to the reader in the evaluation of InPlay’s performance. For a detailed description of InPlay’s method of calculating adjusted funds flow and its reconciliation to the nearest GAAP term,refer to the section “Non-GAAP Measures” in the Company’s most recent MD&A filed on SEDAR.

Free Adjusted Funds Flow - InPlay uses “free adjusted funds flow” as a key performance indicator. Free adjusted funds flow should not be considered as an alternative to or more meaningful than funds flow as determined inaccordance with GAAP as an indicator of the Company’s performance. Free adjusted funds flow is calculated by the Company as adjusted funds flow less capital expenditures and is a measure of the cashflow remaining aftercapital expenditures that can be used for additional capital activity, repayment of debt or decommissioning expenditures. Management considers free adjusted funds flow an important measure to identify the Company’s ability toimprove the financial condition of the Company through debt repayment, which has become more important recently with the introduction of second lien lenders. Refer to “Forward Looking Information Assumptions” section for acalculation of forecast free adjusted funds flow.

Operating Income Profit Margin - InPlay uses “operating income profit margin” as key performance indicators. Operating income should not be considered as an alternative to or more meaningful than net income as determined inaccordance with GAAP as an indicator of the Company’s performance. Operating income is calculated by the Company as oil and natural gas sales less royalties, operating expenses and transportation expenses and is a measureof the profitability of operations before administrative, share-based compensation, financing and other non-cash items Operating income profit margin is calculated by the Company as operating income as a percentage of oil andnatural gas sales. Management considers operating income profit margin an important measure to evaluate its operational performance as it demonstrates how efficiently the Company generates field level profits from its salesrevenue. For a detailed description of InPlay’s method of the calculation of operating income profit margin and its reconciliation to the nearest GAAP term, refer to the section “Non-GAAP Measures” in the Company’s most recentMD&A filed on SEDAR.

Net Debt/EBITDA - InPlay uses “Net Debt/EBITDA” as a key performance indicator. EBITDA should not be considered as an alternative to or more meaningful than funds flow as determined in accordance with GAAP as anindicator of the Company’s performance. EBITDA is calculated by the Company as adjusted funds flow before interest expense. This measure is consistent with the EBITDA formula prescribed under the Company's Credit Facility.Net Debt/EBITDA is calculated as Net Debt divided by EBITDA. Management considers Net Debt/EBITDA a key performance indicator as it is a key metric under our first lien and second lien credit facilities and is an importantmeasure to identify the Company’s annual ability to fund financing expenses, net debt reductions and other obligations. Refer to the “Forward Looking Information Assumptions” section for a calculation of forecast Net Debt/EBITDA.

Net Asset Value - Management considers net asset value an important measure to evaluate changes to asset value of the Company. Net asset value is calculated by the Company as the net present value of future operatingincome (BT 10%) for proved plus probable reserves derived from InPlay’s independent reserve evaluation effective December 31, 20120 plus Undeveloped Land value less net debt and working capital deficiency. Refer to the slidetitled “2020 Year End Net Asset Value” for a calculation of this measure.

Market Capitalization - Management considers market capitalization an important measure of the market value of InPlay’s equity. Market capitalization is calculated by the Company as the Company’s current share pricemultiplied by the current number of shares outstanding.

Enterprise Value - Management considers enterprise value an important measure to evaluate changes to the market value of the Company. Enterprise value should not be considered as an alternative to or more meaningful thantotal capitalization as determined in accordance with GAAP as an indicator of the Company’s performance. Enterprise value is calculated by the Company as the Company’s market capitalization plus net debt less cash and cashequivalents. Refer below for a calculation of this measure.

Basic Shares Outstanding 68.3Market Capitalization (@ assumed $0.58 per share) (mm) $40Net debt (mm) $74Enterprise Value (@ assumed $0.58 per share) (mm) $114

Production Breakdown by Product Type

Disclosure of production on a per boe basis in this press release consists of the constituent product types as defined in NI 51-101 and their respective quantities disclosed in the table below:

Light and Medium

Crude oil

(bbls/d)

NGLS

(boe/d)

Conventional

Natural gas

(Mcf/d)

Total

(boe/d)

2016 Average Production 1,318 143 2,871 1,940





2021 Annual Guidance 2,960 733 9,344 5,250

1. With respect to forward-looking production guidance, product type breakdown is based upon management's expectations based on reasonable assumptions but are subject to variability based on actual well results.

Contact Us

Doug Bartole

President and CEO

587.955.0632

[email protected]

28

#920, 640 – 5th Avenue SW

Calgary, AB T2P 3G4

www.inplayoil.com

Documents

InPlay Oil Corp