athabasca oil corporation

ATHABASCA OIL CORPORATIONFOCUSED | EXECUTING | DELIVERINGNOVEMBER 2021

ATHABASCA OIL (TSX:ATH)

WHY OWN ATHABASCA

1

Athabasca is committed to returning free cash flow to

stakeholders to drive significant equity value

PREDICTABLE, LOW DECLINE THERMAL OIL BUSINESSLow sustaining capital requirements (~$5/bbl)

>1 billion 2P reserves at top quartile assets

DE‐RISKED LIGHT OIL BUSINESS WITH FLEXIBLE CAPITALPeer leading operating netback; $37/boe in Q3/21

Large inventory in the Montney & Duvernay; ~850 gross locations

STRONG FINANCIAL CAPACITY~$265MM liquidity including ~$195MM cash (year‐end 2021)

No term debt maturities until Q4 2026

MANAGING FOR STRONG FREE CASH FLOW~$90MM FCF in 2021; >$600MM over 2022‐24 at US$70 WTI

Targeting net cash position in 2023 by directing at least 75% of FCF to further debt reduction

INTEGRATED SUSTAINABILITY Strong governance; Board oversight of ESG

Committed to reducing emissions; MOU with Entropy for CCUS

2021e financial forecasts based on Oct. 4 strip pricing (US$67.50 WTI, US $12.25 WCS differentials, 0.79 US$/C$ FX) & includes ~$110MM hedging losses.~$5/bbl sustaining capital management estimate. Gross inventory based on management estimates. Please see Reader Advisory “Non‐GAAP Financial Information” for more information.


PORTFOLIO – 34,000 BOE/D | 90% LIQUIDS

22021 guidance product breakdown: 78% Bitumen, 10% natural gas (comprised of 99%+ of shale gas), 4% Condensate NGLs, 2% Other NGLs, 6% Oil (comprised of 99%+ of tight oil).Consolidated reserves as of December 31, 2020. Reserves referred to throughout presentation were evaluated by McDaniel & Associates Consultants Ltd. Additional information included in the back as reader advisories.

PLACIDMONTNEY

LIGHT OIL ASSETS (~8,000 BOE/D) THERMAL OIL ASSETS (~26,000 BBL/D)

LEISMERTop tier project that has been in operation for 11 years with a

productive capacity of 20,000 bbl/d

CORNERCompelling long‐term

development opportunity

HANGINGSTONE9,000 bbl/d with low near‐term sustaining

capital

HANGINGSTONE

CORNER

LEISMER

PLACID MONTNEY70% WI Placid with stable declines, high margins and flexible future development

KAYBOB DUVERNAY30% WI in de‐risked

resource with spending governed by a strong JV agreement and high

margins

KAYBOB DUVERNAY


Q3 2021 HIGHLIGHTS

$274MM Unrestricted CashRefinancing completed Oct. 2021

$72MM Adj FFO ($0.12/sh)2021e ~$195MM

Operating Netback~$37/boe Light Oil

~$36/bbl Thermal Oil

34,255 boe/d (90% liquids)2021e 34,250 boe/d

$16MM Capex 2021e ~$100MM

31Q3 production volumes by product: 26,729 bbl/d Bitumen. 20,304 mcf/d natural gas (>99% share gas), 3,296 bbl/d condensate NGLs, 846 bbl/d other NGLs, 1,984 bbl/d Oil (>99% tight oil) 3Includes ~$110MM hedging losses

$57MM Free Cash Flow2021e ~$90MM


STRONG CASH FLOWo Maintain production base of ~34,000 boe/d

o Low annual sustaining capital of ~$125MM

o Robust hedging reduces cash flow volatility and provides certainty on achieving deleveraging target

o 10+ year tax free horizon ($3.3B of tax pools)

o +/‐ US$5 oil = +/‐ ~$65MM cash flow (unhedged)

UNIQUE LOW LEVERAGE COMPANYo Direct at least 75% of free cash flow to debt repayment

o Term debt target of US$175MM (50% reduction)

o Net cash position achieved in 2023

MANAGING FOR STRONG FREE CASH FLOW

4Illustrative 2022‐2024 cumulative free cash flow, EBITDA, Term Debt & Net Debt; 2022‐H1/23 assumes 75% hedged at strip pricing on Oct. 4 strip pricing US$67.50 WTI, US $12.25 WCS differentials, 0.79 US$/C$ FX) and unhedged H2/23‐2024.Reader Advisory “Non‐GAAP Financial Information” for more information.

EBITDA & FCF AT US$70 WTI (C$MM)>$600MM 3‐year cum FCF

DEBT OUTLOOK AT US$70 WTI (C$MM)

Net cash position

US$175MM target

US$350MM New Notes

+ EBITDA

ATHABASCA OIL (TSX:ATH) 5

2022E IMPLIED EV AT US$70 WTI

STRATEGIC PLANo Reduce cash costs through a lower interest burden

o Transition Enterprise Value to 100% Equity

o Evaluate the distribution of free cash flow across the capital structure once debt target is achieved

LONG TERM VALUE COMPONENTS o Leismer – regulatory approval to 40,000 bbl/d,

established regional infrastructure, 695 MMbbl 2P

o Corner – top tier greenfield SAGD opportunity with regulatory approval to 40,000 bbl/d, 323 MMbbl 2P

o Light Oil – ~850 gross locations, established owned and operated infrastructure position, no near‐term expiries

o $3.3B tax pools ($2.5B NCL/CEE 100% deductible)

CREATING SIGNFICANT SHAREHOLDER VALUE NET DEBT / EBITDA AT US$70 WTI (X)

Illustrative ND/EBITDA assumes 75% hedged at strip pricing on Oct. 4 strip pricing (US$67.50 WTI, US‐$12.25 WCS differentials, 0.79 US$/C$ FX) and unhedged H2/23‐2024.2022E Implied EV assumes 75% hedged at strip pricing on Oct. 4 strip pricing (US$67.50 WTI, US‐$12.25 WCS differentials, 0.79 US$/C$ FX) Reader Advisory “Non‐GAAP Financial Information” for more information

Net cash position

$555MM current market cap


CAPITAL STRUCTURE OVERVIEW o US$350MM Second Lien Notes

• 9.75% coupon

• 5‐year term to Q4 2026

o $150MM Credit Facilities • $110MM Reserve Based Facility for hedging & LC requirements

• $40MM Unsecured EDC LC facility

2021 GUIDANCEo ~34,250 boe/d (90% liquids)

o ~$190MM Adj. Funds Flow ($0.35/sh)

o ~$100MM Capital Expenditures

o ~$90MM Free Cash Flow ($0.17/sh)

2022 BUDGET – TO BE RELEASED IN DECEMBER

Basic Shares Outstanding 531 MM

Market Capitalization ($1.05/sh) ~$555 MM

2021e Year‐end Net Debt ~$205 MM

Total Enterprise Value ~$760 MM

Warrants ($0.94 exercise price) 79.4 MM

Tax Pools (Total / NCLs & CEE) $3,300 / $2,400 MM

CAPITAL STRUCTURE AND 2021 GUIDANCE

6

CAPITALIZATION OVERVIEW (ATH‐TSX)

CAPITAL STRUCTURE (2021E YEAR‐END)

~$195MM Unrestricted

Cash

US$350MMNew Notes(~C$440MM)

EQUITY DEBT CASH & LIQUIDITY

~$555MM Market

Capitalization ($1.05/share)

~$70MM liquidity on

RBL

2021e financial forecasts based on Oct. 4 strip pricing (US$67.50 WTI, US $12.25 WCS differentials, 0.79 US$/C$ FX) & includes ~$110MM hedging losses.Please see Reader Advisory “Non‐GAAP Financial Information” for more information.


RISK MANAGEMENT

OBJECTIVES

o Ensure funding to protect sustaining capital

o Reduce cash flow and earnings volatility

o Provide certainty for achieving deleveraging target

2022 HEDGING PROGRAM

o Hedge ~50% of blended sales• Net of internal Light Oil natural production hedge

o 13,500 bbl/d ~US$54 WCS swaps protect capital program down to US$50 WTI

o Additional collars and puts maintain upside exposure to the current price environment

FUTURE HEDGING PROGRAM

o Reduce to 25 – 50% of production upon achieving US$175MM term debt reduction target

NEAR‐TERM HEDGE TARGET(~50% SALES VOLUMES )

2022 HEDGED FUNDS FLOW SENSITIVITY

7Implied WTI assumes US$12.50 WCS differential. Illustrative annual funds flow sensitivity assuming 75% hedged at strip pricing on Oct. 4 strip pricing.Please see Reader Advisory “Non‐GAAP Financial Information” for more information.


WESTERN CANADIAN MARKET ACCESS

8

CANADIAN EGRESS OUTLOOK (MMBBL/D)CANADIAN MARKET ACCESS IMPROVINGo Excess pipeline capacity for foreseeable future

Enbridge L3R: +270,000 bbl/d in‐service

TMX: +590,000 bbl/d in 2023

Keystone Base: +50,000 bbl/d

o Lower WCSB supply growth expectations

Producers focused on return of capital vs. growth model

POSITIVE OUTLOOK FOR CANADIAN HEAVY DIFFERENTIALS

o Low sustained WCS heavy differentials and reduced volatility going forward

Source: ENB, BMO

HEAVY OIL PRICING OUTLOOK (US$WCS)Historical Prices Strip Pricing (Nov. 1, 2021)

US$ WCS


INTEGRATED SUSTAINABILITY

9

CARBON CAPTURE – AOC’S LOW‐CARBON BARRELo Entropy Inc. (Entropy) modular carbon capture technology (CCUS)

• Athabasca signed an MOU with Entropy in April 2021

• Goal is to produce a “net‐zero” barrel at Leismer

o Technology evaluation underway with a focus on application

o Exploring sequestration options for captured carbon into either regional disposal zones or participation in industry carbon trunk line projects

ALBERTA BASED INDUSTRY & GOVERNMENT INITIATIVES o Open access pipeline systems and developments:

1. Carbon Grid – multi‐sector solution targeting >20MM T CO2 annually

2. Oil Sands “Pathways” – energy industry alliance

3. Alberta Carbon Trunk Line – ~15MM T CO2 annually into Clive oil reservoir

Athabasca Stated ESG Goal (May 2021)“Prepare a technology roadmap for a lower carbon future evaluating carbon capture use and storage, cogeneration,

solvent injection, and renewable energy”

TECHNOLOGY OVERVIEW

PROJECT MAP

TC / PEMBINA FT. SASK. SEQUEST.

OIL SANDS “PATHWAYS” COLD LAKE

LEISMERHANGINGSTONE

Redwater

Clive

Fort McMurray

Sequestration

Trunk Line

or

ACTL

PPL / TC

2

13

1

2

3

NET GHG EMISSIONS INTENSITYo New technologies integral to

reducing emissions

— $45MM+ investment in technology since 2015

— Mitigated GHG emissions by 250,000 tCO since 2015

Sources: corporate disclosure and press releases. Additional information included in the back as reader advisories.

ASSET OVERVIEW


THE THERMAL BUSINESS

11

THERMAL PROPERTIES

~26,600 bbl/d 2021E Production

2010 First Production

LEISMER

US$43/bbl & US$52/bbl

WTI Breakeven*(Operating & FCF)

~$85MM 2021ECapital Expenditures

HANGINGSTONE

2015 First Production

HIGHLIGHTS

61 MMbbl & 365 MMbbl

Gross Reserves (PDP & Proved)

~6 years & ~38 years RLI(PDP & Proved)

100% Working Interest

Consolidated reserves as of December 31, 2020. Calculation for RLI is 2020 year end reported net reserves plus subsequent changes where applicable, divided by 2021e production. Management 2021e production estimate.Please see reader advisory “Additional Oil and Gas Information”, “Drilling Locations” and “Non‐GAAP Financial Information” for more information.

~$285MM &$29/bbl

2021E Operating Income & Netback

AOCHangingstone

AOCLeismer

AOCCorner

Hangingstone

Surmont

EnbridgeCheecham

Fort McMurray

Jackfish

Christina LakeEnbridgeWaupisoo

*Break‐even economics based on 2021e production, US$12.50 WCS diffs, 0.8 US$/C$ FX, 0% C5 diff & C$2.90 AECO.


PAD 8NPAD 8N

PAD 8SPAD 8S

PAD 1PAD 1 PAD 2PAD 2

PAD 7PAD 7

PAD 4PAD 4PAD 3PAD 3

PAD 6PAD 6

PAD 5PAD 5

Existing Surface PadsExisting Drainage AreasPad L7

High : 40

Low : 10Pad L8NPad L8S

CPFCPF

THERMAL OIL – LEISMER FUTURE OPPORTUNITIES

12

LEISMER DEVELOPMENT (BBL/D) AND SOR (X)ILLUSTRATIVE PROJECT ECONOMICS (US$65 WTI)*

STRATEGYo Maximize free cashflow and deliver strong netbacks

o Focus on projects that improve the SOR

2021 BASE CAPITAL o L7P6 and L6 Infills on production July 2021

o Pad L8 first steam October 2021; on production early 2022

FUTURE CAPITAL FLEXIBILITYo Additional wells on Pad L8 will leverage off existing infrastructure

o Low sustaining capital requirements (~$5/bbl)

DEVELOPMENT MAP

Pads 1‐7

Pad 8

Illustrative Sustaining

*Flat long‐term commodity price assumptions: US$65 WTI, US$12.50 WCS diff, US$0 C5+ diff, C$3.50 AECO, 0.8 US$/C$ FXAdditional information included in the back as reader advisories.

L8 NorthCapital (lease edge) $MM $49

Plateau Rate per project bbl/d 5,400EUR per project mbbl 13,400

IRR % 119%NPV10 $MM $347

F&D $/bbl $3.65Recycle Ratio x 7.2xCapital Efficiency $/bbl/d $9,000P/I x 7.1x

Low risk development with compelling economics


THERMAL OIL – HANGINGSTONE 2021 INITIATIVES STRONG RESERVOIR RESPONSEo Excellent facility run‐time following Summer 2020 turnaround

o NCG aiding in pressure build‐up and energy usage

o Start‐up of standing well pair underway (AA03)

COST OPTIMIZATIONo Low non‐energy operating expenses (~$6.50/bbl Q3/21)

o Competitive netback (~$33/bbl Q3/21)

o 5,000 bbl/d third‐party truck‐in terminal and amended dilbit transportation contract completed in 2021

CAPITAL OUTLOOKo Minimal sustaining capital required in the medium term

DEVELOPMENT MAP

PRODUCTION (BBL/D) & SOR (X)

Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com. SORs are annual averages.Additional information included in the back as reader advisories.

Current


90 %98 % 93 %

98 % 100 %93 % 96 % 96 % 94 %

60 %

2016 2017 2018 2019 2020

LeismerHangingstone

$0

$25

$50

$75

$100

2016 2017 2018 2019 2020

Leismer

Hangingstone

0

200

400

600

800

1,000

1,200

1 13 25 37 49 61 73Months

Pad 1‐6

Pad 7

$0

$5

$10

$15

$20

$25

L5 L6 L7 6xWPs L8 Full Pad 14 WP

Avg. Facilities CostAvg. Completion CostAvg. Drilling Cost

14

LEISMER TECHNOLOGY DRIVING RATES (BBL/D)

LEISMER LOWER WELL PAIR COSTS ($MM)HISTORY OF HIGH UTILIZATION RATES

NON‐ENERGY OPEX ($MM)

Achieved through longer laterals and implementation of

flow control devices

THERMAL OIL – OPERATIONS IMPROVEMENTS

Hangingstone partial shut‐in in 2020

Hangingstone partial shut‐in in 2020

Leismer

Hangingstone

Additional information included in the back as reader advisories.


~8,000 boe/d 2021E Production

PLACID MONTNEY

~$5MM 2021E Net Capital Expenditures

KAYBOB DUVERNAY

70% W. I. and Operated 30% W. I. and non‐

Operated

~850 Gross Locations

~450,000 Gross Acres

14 MMboe & 37 MMboe

Gross Reserves (PDP & Proved)

~5 years & ~13 years RLI(PDP & Proved)

LIGHT OIL PROPERTIESHIGHLIGHTS

THE LIGHT OIL BUSINESS

Consolidated reserves as of December 31, 2020. Calculation for RLI is 2020 year end reported net reserves plus subsequent changes where applicable, divided by 2021E production. Management 2021E production estimate.Please see reader advisory “Additional Oil and Gas Information”, “Drilling Locations” and “Non‐GAAP Financial Information” for more information.

Placid

Kaybob

~$100MM &$36/bbl

2021E Operating Income & Netback

o Joint Venture with Murphy

o Duvernay activity has de‐risked the asset with $1B+ JV investment to date

o No near‐term land maturities

o Athabasca has discretion over capital spend


LIGHT OIL – FUTURE OPPORTUNITIES

16

STRATEGIC OBJECTIVESo Maintain future optionality

o Maximize netback and cash flow generation

MONTNEY FUTURE ACTIVITY o 2022: 3‐well development pad to maintain production

o ~150 gross future locations

DUVERNAY FUTURE ACTIVITYo 2022: Complete 3 DUCs; readiness for development

o ~700 gross de‐risked future locations

o Spending governed by a strong Joint Development Agreement

ILLUSTRATIVE MULTI WELL PAD ECONOMICS (US$65 WTI)

MONTNEY DUVERNAYSINGLE WELL SINGLE WELL

12‐24 Pad 3‐well pad

PLACID MONTNEY

KAYBOB DUVERNAY

KAYBOB EAST

SIMONETTE

KAYBOB NORTH

KAYBOB WEST

TWO CREEKSSAXON

Volatile Oil WindowGas Condensate WindowIndustry Duvernay Hz WellsATH Duvernay Hz Wells

Capital $MM $7 $8

IP365 boe/d 480 420EUR mboe 515 680Liquids yield % 52% 72%

IRR % 82% 65%

F&D $/boe $13.50 $11.80Recycle Ratio x 3.2x 4.2xCapital Efficiency $/boe/d $14,500 $19,100P/I x 1.1x 1.1x


$0

$5

$10

$15

$20

$25

$30

$35

$40

$45

CPG

ATH LO TVE

WCP SGY

BNE

ARX

PIPE

POU

NVA KEL

SDE CR BIR

SRX

TOU

CVE De

epBa

sin

$/bo

eLiquids Weighted Netback (>40% liquids)

Gas Weighted Netback (>60% gas)

Costs (Operating, Transportation, Royalties)

$0

$5

$10

$15

2016 2017 2018 2019 2020$0

$2

$4

$6

$8

$10

$12

$14

$16

2014 2015 2016 2017 2018 2019 2020 2021Target

MontneyDuvernay

0

300

600

900

1,200

1,500

0 60 120 180 240 300 360Days

2016 Wells2017 Wells2018 Wells2019 Wells2020 Wells

LIGHT OIL – NETBACKS & OPERATIONS IMPROVEMENTS

17

REDUCING OPEX AT PLACID ($/BOE) DUVERNAY OIL WELL RESULTS (BOE/D) HISTORICAL D&C COSTS ($MM)*

>100% increase in IP30 rates to ~1,000 boe/d

~$6.50/boe reduction

High Liquids %High Quality ProductLow Lifting Costs

* 2021 does not have any approved operations for the Duvernay; 2021 target D&C costs reflect Q1/20 pace setter well results

Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com. Additional information included in the back as reader advisories

INDUSTRY LEADING NETBACK (Q2/21)

~$37/boe in Q3

ESG OVERVIEW


ESG – INAUGURAL 2021 REPORT

19

Our commitment to ESG responsibility and sustainability is part of our long-term strategy and is an ongoing process. Each year we

plan to measure, improve, and progress as an organization.

We believe that the responsible energy we produce here in Alberta makes people’s lives better.

Our inaugural ESG report is an opportunity for us to showcase the positive impacts we have made and explain how sustainability and responsibility are being embedded into every decision we make.

“Our commitment to ESG responsibility and sustainability is part of our long‐term strategy and an ongoing process.”

Inaugural ESG Report available on our website & SEDAR


0.04

0.05

0.06

0.07

0.08

2015 2016 2017 2018 2019 2020

tonn

es Co2

e/bo

e

70%

75%

80%

85%

90%

95%

Oil Sands Mining In Situ Enhanced oilrecovery

AthabascaThermal Oil

ESG – 2020 HIGHLIGHTS

20

NET GHG EMISSIONS INTENSITY WATER RECYCLE RATIO

20% Reduction

Athabasca has a longstanding history of consistently measuring, tracking and reporting on ESG metrics


ESG - ENVIRONMENTAL

21

CARBON CAPTURE – AOC’S LOW‐CARBON BARRELo Entropy Inc. (Entropy) modular carbon capture technology (CCUS)

• Athabasca signed an MOU with Entropy in April 2021

• Goal is to produce a “net‐zero” barrel at Leismer

o Technology evaluation underway with a focus on application

o Exploring sequestration options for captured carbon into either regional disposal zones or participation in industry carbon trunk line projects

ALBERTA BASED INDUSTRY & GOVERNMENT INITIATIVES o Open access pipeline systems and developments:

1. Carbon Grid – multi‐sector solution targeting >20MM T CO2 annually

2. Oil Sands “Pathways” – energy industry alliance

3. Alberta Carbon Trunk Line – ~15MM T CO2 annually into Clive oil reservoir

Athabasca Stated ESG Goal (May 2021)“Prepare a technology roadmap for a lower carbon future evaluating carbon capture use and storage, cogeneration,

solvent injection, and renewable energy”

TECHNOLOGY OVERVIEW

PROJECT MAP

TC / PEMBINA FT. SASK. SEQUEST.

OIL SANDS “PATHWAYS” COLD LAKE

LEISMERHANGINGSTONE

Redwater

Clive

Fort McMurray

Sequestration

Trunk Line

or

ACTL

PPL / TC

2

13

1

2

3

NET GHG EMISSIONS INTENSITYo New technologies integral to

reducing emissions

— $45MM+ investment in technology since 2015

— Mitigated GHG emissions by 250,000 tCO since 2015


ESG – GOVERNANCE & SOCIAL

22

SOCIAL

o Contributed 66% of the Provincial Park Lands

• Expanded the ecologically and culturally significant Kitaskino Nuwenene Wildland Provincial Park by relinquishing 235,000 acres of mineral rights

o Exceeded voluntary closure spend by 50% in 2020

o Best in class safety performance and environmental stewardship

• No lost time to injuries and no reportable spills in 2020

Strong governance, social responsibility and safety are core to AOC’s business

GOVERNANCEo Technically‐focused, experienced management team

• Four most senior executives have managed current portfolio for an aggregate of 35 years

o Compensation aligned with financial, operational and environmental goals

o Independent and energy‐rich experienced Board provides oversight for long‐term strategy


ESG – COMMITMENT TO RESPONSIBILITY

23

GOALSo Reduce emission intensity by 30% (2015 2025)

o Top tier safety results (<0.5 TRIF in 2021); aspiration of no harm to people and no hydrocarbon spills

o ESG to be a formal consideration in all capital allocation decisions

o Prepare a roadmap for lower carbon future including carbon capture use & storage, cogeneration, solvent injection and renewables

o Maintain and continually improve disclosure with best‐in‐class standards (GRI, SASB, TCFD)

ACCOUNTABILITY & GOVERANCE o ESG goals have been incorporated in AOC’s annual compensation scorecard

o Independent Board provides oversight to the Company’s ESG performance

“As we progress, Athabasca will focus on transparency and continuous advancement as we deliver on our commitments to our stakeholders,

communities, and employees. We invite you to join us on our ESG journey as we continue to grow and responsibly produce energy in Alberta”

APPENDIX


Rob Broen, P.Eng.President & Chief Executive

Officer

o Joined Athabasca in 2012 as Senior Vice President Light Oil. Promoted to Chief Operating Officer in 2013 and President and Chief Executive Officer in 2015

o 30 years of exploration and production experience including 18 years with Talisman Energy in various technical and management capacities (President, Talisman Energy USA Inc. and Senior Vice President, North American Shale). At Talisman, managed capital budgets over $1 billion and a 120,000 boe/d North American shale portfolio (Montney, Duvernay, Marcellus and Eagle Ford)

o Bachelor of Science in chemical engineering from the University of Alberta and a graduate of the Ivey Executive Program at the Richard Ivey School of Business

Matt Taylor, CFAChief Financial Officer

o Joined Athabasca 2014 as Vice President Capital Markets & Communications. Promoted to Chief Financial Officer in 2019

o Over 15 years of financial, corporate and capital markets experience including equity research and investment banking at National Bank Financial, GMP Securities and CIBC World Markets. Most recently Director of Energy Equity Research at National Bank

o Bachelor of Commerce with a specialization in finance from UBC Sauder School of Business and holds a Chartered Financial Analyst designation

Karla Ingoldsby, P.Eng.Vice President, Thermal Oil

o Joined Athabasca in 2010 as a Senior Reservoir Engineer and has been progressively appointed into more senior roles including Development Manager in the Joint Venture with PetroChina Canada and Director positions for Geoscience Reservoir and Development, Ventures & Land, and Thermal Oil Production

o 20 years of Oil and Gas experience, including reservoir engineering roles at Royal Dutch Shell overseeing thermal oil assets and conventional oil and gas assets

o Bachelor of Science in Mechanical Engineering from the University of Alberta

Mike Wojcichowsky, P.Eng.Vice President, Light Oil

o Joined Athabasca in 2013 as the Thermal Drilling Manager. Progressively appointed to more senior roles including Director of Drilling & Completions Services and Director of Light Oil

o 20 years of Oil and Gas experience in both Canada and the North Sea. Former Drilling & Engineering Manager at Talisman Energy for their Montney and Duvernay assets

o Bachelor of Science and Master of Science degrees in Mechanical Engineering from the University of Alberta

MANAGEMENT TEAM

25


2016 2017 2018 2019 2020

HISTORICAL TRANSFORMATION OF ATH

20212021

ResourceAppraisal

Fundingnot Secured

Managing for strong FCF

Certainty for deleveraging

Integrated Sustainability

26

$486MM Light Oil JV

with Murphy Oil

$560MM Leismer

Acquisition from Equinor

$470MM Contingent Bitumen Royalties

Inaugural ESG

Report

PRODUCTION (BOE/D) EXPENSED G&A ($/BOE)

Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com. 2021e financial forecasts based on Oct. 4 strip pricing (US$67.50 WTI, US $12.25 WCS differentials, 0.79 US$/C$ FX) & includes ~$110MM hedging losses.Additional information included in the back as reader advisories.

US$350MM New Notes &

$150MM Credit Facilities

$265MM Infrastructure

Sale

Onset of COVID Pandemic

Resumption of Pre‐COVIDBusiness Plan

EBITDA ($MM)

* 2021e includes ~$110MM in hedging losses

COVIDWCSBEgress

Constraints

US$450MM Term Notes


READER ADVISORY

27

Forward Looking Statements

This Presentation contains forward‐looking information that involves various risks, uncertainties and other factors. All information other than statements of historical fact is forward‐looking information. The use of any of the words“anticipate”, “plan”, “forecast”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “target”, “should”, “believe”, “predict”, “pursue”, “potential”, “view” and ”contemplate” and similar expressions are intended to identifyforward‐looking information. The forward‐looking information is not historical fact, but rather is based on the Company’s current plans, objectives, goals, strategies, estimates, assumptions and projections about the Company’sindustry, business and future operating and financial results. This information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those anticipated in suchforward‐looking information. No assurance can be given that these expectations will prove to be correct and such forward‐looking information included in this Presentation should not be unduly relied upon. This information speaksonly as of the date of this Presentation and, except as required by applicable securities laws, the Company undertakes no obligation to update any forward‐looking statement to reflect events or circumstances after the date on whichsuch statement is made or to reflect the occurrence of unanticipated events. In particular, this Presentation contains forward‐looking information pertaining to, but not limited to, the following: our strategic plans and free cash flowpotential; the Company’s 2021 Outlook and illustrative multi‐year outlook; including liquidity, EBITDA, funds flow, net debt, production outlook, capital budget, operating income for Thermal Oil and Light Oil; EBITDA and funds flowsensitivity; hedging targets; future debt levels and composition; Trans Mountain and Keystone in‐service dates; timing of Leismer well on stream dates and expected benefits therefrom; our drilling plans in Leismer and L8 projecteconomics; expected operating cost savings at Hangingstone and timing for first oil from new well pair; expected costs savings resulting from the Hangingstone truck‐in terminal; type well economic metrics; expectations for WCS heavyoil to be amongst the most valuable global crude benchmarks; emissions reductions target; target Term Debt levels; and other matters.

In addition, information and statements in this Presentation relating to "Reserves" are deemed to be forward‐looking information, as they involve the implied assessment, based on certain estimates and assumptions, that the reservesdescribed exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future.

With respect to forward‐looking information contained in this Presentation, assumptions have been made regarding, among other things: commodity prices; the regulatory framework governing royalties, taxes and environmentalmatters in the jurisdictions in which the Company conducts and will conduct business and the effects that such regulatory framework will have on the Company, including on the Company’s financial condition and results of operations;the Company’s financial and operational flexibility; the Company’s financial sustainability; Athabasca's cash flow break‐even commodity price; the Company’s ability to obtain qualified staff and equipment in a timely and cost‐efficientmanner; the applicability of technologies for the recovery and production of the Company’s reserves and resources; future capital expenditures to be made by the Company; future sources of funding for the Company’s capitalprograms; the Company’s future debt levels; future production levels; the Company’s ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms; operating costs; compliance of counterparties withthe terms of contractual arrangements; impact of increasing competition globally; collection risk of outstanding accounts receivable from third parties; geological and engineering estimates in respect of the Company’s reserves andresources; recoverability of reserves and resources; the geography of the areas in which the Company is conducting exploration and development activities and the quality of its assets. Certain other assumptions related to theCompany’s Reserves are contained in the report of McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluating Athabasca’s Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 2020 (which isrespectively referred to herein as the "McDaniel Report”).

Actual results could differ materially from those anticipated in this forward‐looking information as a result of the risk factors set forth in the Company’s Annual Information Form (“AIF”) dated March 3, 2021 and Management’sDiscussion and Analysis dated November 3, 2021 available on SEDAR at www.sedar.com, including, but not limited to: weakness in the oil and gas industry; exploration, development and production risks; prices, markets and marketing;market conditions; continued impact of the COVID‐19 pandemic; ability to finance capital requirements; climate change and carbon pricing risk; regulatory environment and changes in applicable law; gathering and processing facilities,pipeline systems and rail; statutes and regulations regarding the environment; political uncertainty; state of capital markets; anticipated benefits of acquisitions and dispositions; abandonment and reclamation costs; changing demandfor oil and natural gas products; royalty regimes; foreign exchange rates and interest rates; reserves; hedging; operational dependence; operating costs; project risks; financial assurances; diluent supply; third party credit risk;indigenous claims; reliance on key personnel and operators; income tax; cybersecurity; advanced technologies; hydraulic fracturing; liability management; seasonality and weather conditions; unexpected events; internal controls;insurance; litigation; natural gas overlying bitumen resources; competition; chain of title and expiration of licenses and leases; breaches of confidentiality; new industry related activities or new geographical areas; and risks related toour debt and securities.

Also included in this Presentation are estimates of Athabasca's 2021 Outlook which are based on the various assumptions as to production levels, commodity prices, currency exchange rates and other assumptions disclosed in thisPresentation. To the extent any such estimate constitutes a financial outlook, it was approved by management and the Board of Directors of Athabasca, and is included to provide readers with an understanding of the Company’soutlook. Management does not have firm commitments for all of the costs, expenditures, prices or other financial assumptions used to prepare the financial outlook or assurance that such operating results will be achieved and,accordingly, the complete financial effects of all of those costs, expenditures, prices and operating results are not objectively determinable. The actual results of operations of the Company and the resulting financial results may varyfrom the amounts set forth herein, and such variations may be material. The financial outlook contained in this Presentation was made as of the date of this Presentation and the Company disclaims any intention or obligations toupdate or revise such financial outlook, whether as a result of new information, future events or otherwise, unless required pursuant to applicable law.

Drilling Locations

“BOEs" may be misleading, particularly if used in isolation. A BOE conversion ratio of six thousand cubic feet of natural gas to one barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy equivalency conversion method primarilyapplicable at the burner tip and does not represent a value equivalency at the wellhead. As the value ratio between natural gas and crude oil based on the current prices of natural gas and crude oil is significantly different from theenergy equivalency of 6:1, utilizing a conversion on a 6:1 basis may be misleading as an indication of value.

Initial Production Rates

Test Results and Initial Production Rates: The well test results and initial production rates provided in this presentation should be considered to be preliminary, except as otherwise indicated. Test results and initial production ratesdisclosed herein may not necessarily be indicative of long‐term performance or of ultimate recovery.


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Additional Oil and Gas Information:

Other Oil and Gas terms: This presentation contains certain other oil and gas metrics, including D&C (drilling and completion costs), F&D, steam oil ratio (or SOR), reserves life index, recycle ratio, capital efficiency and P/I, which do nothave standardized meanings or standard methods of calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. Such metrics havebeen included herein to provide readers with additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance and future performance may not compare tothe performance in previous periods and therefore such metrics should not be unduly relied upon. D&C includes all capital spent to drill, complete, equip and tie‐in a well. The calculation of F&D costs includes all exploration anddevelopment capital for the year plus the change in future development capital for the year. Steam oil ratio, or SOR, measures the average volume of steam required to produce a barrel of oil. The Company’s reserves life index for agiven period is determined by taking the Company’s total proved plus probable reserves at the end of that period divided by the Company’s gross production for the same period. Recycle ratio is calculated by dividing operating netbackby F&D per boe. Capital efficiency is a measure of how effective projects are at adding production. Lower capital efficiencies indicate a more productive investment for adding production. For Light Oil capital efficiency is calculated bydividing Capital and IP365 rates and for Thermal Oil is calculated by dividing Capital and plateau rates. P/I is a measure of a projects net value relative to its capital investment and is calculated by dividing a project's NVP10 value by itsCapital. All Thermal Oil production and volumes are bitumen. Light Oil % liquids include oil, condensate and NGLs as liquids. Consolidated % liquids include bitumen, oil, condensate and NGLs as liquids. Natural Gas volumes include bothConventional and Shale Gas, however most gas volumes are Shale Gas. Sustaining capital is a management estimate of annual capital projects required to maintain production levels.

Reserves Information

The McDaniel Report was prepared using the assumptions and methodology guidelines outlined in the COGE Handbook and in accordance with National Instrument 51‐101 Standards of Disclosure for Oil and Gas Activities, effectiveDecember 31, 2020. There are numerous uncertainties inherent in estimating quantities of bitumen, light crude oil and medium crude oil, tight oil, conventional natural gas, shale gas and natural gas liquids reserves and the future cashflows attributed to such reserves. The reserve and associated cash flow information set forth above are estimates only. In general, estimates of economically recoverable reserves and the future net cash flows therefrom are basedupon a number of variable factors and assumptions, such as historical production from the properties, production rates, ultimate reserve recovery, timing and amount of capital expenditures, marketability of oil and natural gas, royaltyrates, the assumed effects of regulation by governmental agencies and future operating costs, all of which may vary materially. For those reasons, estimates of the economically recoverable reserves attributable to any particular groupof properties, classification of such reserves based on risk of recovery and estimates of future net revenues associated with reserves prepared by different engineers, or by the same engineers at different times, may vary. TheCompany's actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from estimates thereof and such variations could be material. Reserves figures described herein havebeen rounded to the nearest MMbbl or MMboe. For additional information regarding the consolidated reserves and information concerning the resources of the Company as evaluated by McDaniel in the McDaniel Report, please referto the Company’s AIF.

Reserve Values (i.e. Net Asset Value) is calculated using the estimated net present value of all future net revenue from our reserves, before income taxes discounted at 10%, as estimated by McDaniel effective December 31, 2020 andbased on average pricing of McDaniel, Sproule and GLJ as of January 1, 2021.

The 700 Duvernay drilling locations referenced include: 7 proved undeveloped locations and 78 probable undeveloped locations for a total of 85 booked locations with the balance being unbooked locations. The 150 Montney drillinglocations referenced include: 63 proved undeveloped locations and 35 probable undeveloped locations for a total of 98 booked locations with the balance being unbooked locations. Proved undeveloped locations and probableundeveloped locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2020 and account for drilling locations that have associated proved and/orprobable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent or prospective). Unbooked locations have beenidentified by management as an estimation of Athabasca’s multi‐year drilling activities expected to occur over the next two decades based on evaluation of applicable geologic, seismic, engineering, production and reservesinformation. There is no certainty that the Company will drill all unbooked drilling locations and if drilled there is no certainty that such locations will result in additional oil and gas reserves, resources or production. The drillinglocations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, commodity prices, provincial fiscal and royalty policies, costs, actual drillingresults, additional reservoir information that is obtained and other factors.

Non‐GAAP Financial Measures and Production Disclosure

The "Adjusted Funds Flow”, "Light Oil Operating Income", “Light Oil Operating Netback”, “Light Oil Capital Expenditures Net of Capital‐Carry”, "Thermal Oil Operating Income (Loss)", "Thermal Oil Operating Netback", “ConsolidatedOperating Income”, “Consolidated Operating Netback”, “Consolidated Capital Expenditures Net of Capital‐Carry”, “Adjusted EBITDA”, “Free Cash Flow”, “Liquidity”, and “Term Debt” are financial measures contained in this Presentationdo not have standardized meanings which are prescribed by IFRS and they are considered to be non‐GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not beconsidered in isolation with measures that are prepared in accordance with IFRS. The “Advisories and Other Guidance” section within the Company’s Q3 2021 MD&A includes reconciliations of these measures, where applicable, to thenearest IFRS measures.

Adjusted Funds Flow is not intended to represent cash flow from operating activities, net earnings or other measures of financial performance calculated in accordance with IFRS. Adjusted Funds Flow is calculated by adjusting forchanges in non‐cash working capital, restructuring expenses and settlement of provisions from cash flow from operating activities. The Adjusted Funds Flow measure allows management and others to evaluate the Company’s ability tofund its capital programs and meet its ongoing financial obligations using cash flow internally generated from ongoing operating related activities. Adjusted Funds Flow per share is calculated as Adjusted Funds Flow divided by theapplicable number of weighted average shares outstanding.

The Operating Income (Loss) measures in this News Release are calculated by subtracting the cost of diluent, royalties, operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstreamsales. The Operating Netback measures are calculated by dividing the respective projects Operating Income (Loss) by its respective sales volumes and is presented on a per boe basis. The Operating Income (Loss) and the OperatingNetback measures allow management and others to evaluate the production results from the Company’s assets.

The Consolidated Operating Income (Loss) Net of Realized Hedging measure in this News Release is calculated by adding or subtracting realized gains (losses) on commodity risk management contracts, royalties, cost of diluent,operating expenses and cash transportation & marketing expenses from petroleum, natural gas and midstream sales. The Consolidated Operating Netback Net of Realized Hedging measure is calculated by dividing ConsolidatedOperating Income (Loss) Net of Realized Hedging by the total sales volumes and is presented on a per boe basis. The Consolidated Operating Income (Loss) Net of Realized Hedging and the Consolidated Operating Netback Net ofRealized Hedging measures allow management and others to evaluate the production results from the Company’s Light Oil and Thermal Oil assets combined together, including the impact of realized commodity risk management gainsor losses.


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Non‐GAAP Financial Measures and Production Disclosure Cont’d

The Consolidated Capital Expenditures Net of Capital‐Carry and Light Oil Capital Expenditures Net of Capital‐Carry measures in this News Release are outlined in the Company’s Q3 2021 MD&A. These measures allow management andothers to evaluate the true net cash outflow related to Athabasca's capital expenditures.

Net Debt is defined as face value of term debt plus accounts payable and accrued liabilities plus current portion of provisions and other liabilities less current assets.

Adjusted EBITDA is defined as Net income (loss) and comprehensive income (loss) before financing and interest expense, depreciation, depletion, impairment and taxation (recovery) expense adjusted for unrealized foreign exchangegain (loss), unrealized gain (loss) on risk management contracts, gain (loss) on revaluation of provisions and other, gain (loss) on sale of assets and non‐cash stock‐based compensation.

The Free Cash Flow measure in this News Release is calculated by subtracting Capital Expenditures Net of Capital‐Carry from Adjusted Funds Flow. This measure allows management and others to evaluate Athabasca's ability togenerate funds to finance operations and capital expenditures.

Liquidity is defined as cash and cash equivalents plus available credit capacity.

Term Debt is defined as the face value of the New Notes.

Break‐even reflects the estimated WCS oil price per barrel required to generate an asset level operating income of Cdn $0. Break‐even is used to assess the impact of changes in WCS oil prices on operating income of an asset and couldimpact future investment decisions. Break‐even does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.

Historical annual and 2021e Corporate volumes by product are provided below:

Product 2016 2017 2018 2019 2020Bitumen bbl/d 7,384 27,900 27,900 26,058 22,745Natural Gas mcf/d 13,858 20,890 33,104 28,281 23,229Condensate NGLs bbl/d 788 2,687 2,793 2,009 1,964Other NGLs bbl/d 383 505 1,049 918 785Light & Medium Crude Oil bbl/d 331 104 98 27 2Tight Oil bbl/d 784 758 1,823 2,471 3,116Total boe/d 11,980 35,435 39,180 36,196 32,483

Product 2021 Production SplitBitumen 78%Natural Gas* 10%Condensate NGLs 4%Other NGLs 2%Oil** 6%* comprised of 99% or greater of shale gas, with the remaining being conventional natural gas

** comprised of 99% or greater of tight oil, with the remaining being light and medium crude oil

athabasca oil corporation

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