athabasca oil corporation...leismer –top tier oil sands project o ~20,000 bbl/d productive...

ATHABASCA OIL CORPORATIONFOCUSED | EXECUTING | DELIVERINGCORPORATE OVERVIEW – MARCH 2021

ATHABASCA OIL (TSX:ATH)

PREMIER RESOURCE EXPOSURE

~34,000 boe/d~90% liquids

~90 year 2P RLI1,150 MMboe 2P

400 MMboe Proved

MONTNEY

DUVERNAY

LIGHT OIL

LIGHT OIL CORNER

LEISMER

HANGINGSTONE

THERMAL OIL

~$650MM EV$165MM Cash

1Footnotes and additional information included in the back as endnotes and reader advisories


Q4 2020 HIGHLIGHTS

$165MM CashUnrestricted

$11MM Adjusted Funds Flow

Netbacks$23/boe Light Oil$13/bbl Leismer

34,233 boe/d89% liquids

$17MM Capex98% Thermal Oil


1,150 MMboe 2P Reserves

0.9x PDP & 2.7x 1P Asset Coverage


$‐

$2

$4

$6

2016 2017 2018 2019 2020

($102)

$102 $6 $155

($19)($25)

$0

$25

$50

$75

$100

$125

$150

$175

2016 2017 2018 2019 2020 2021e* ‐

10,000

20,000

30,000

40,000

50,000

2016 2017 2018 2019 2020 2021e

THE TRANSFORMATION

2016 2017 2018 2019 2020 20212021

ResourceAppraisal

Fundingnot Secured

FCF Generation

Disciplined Operations

Strong Balance Sheet

3

$486MM Light Oil JV

with Murphy Oil

$560MM Leismer

Acquisition from Equinor

$400MM Contingent Bitumen Royalty

$265MM Infrastructure

Sale

$70MM Contingent Bitumen Royalty

PRODUCTION (BOE/D) ADJUSTED FUNDS FLOW ($MM)EXPENSED G&A ($/BOE)$15MM FCF

Q4 WCS Diff Blow

Out

Footnotes and additional information included in the back as endnotes and reader advisories

COVID19Managed Business

Momentum

Refinance 2L Notes

(to be completed)

* US$55 WTI, US$12.50 WCS diff, 0.79FX; shaded +US$5 WTI

COVID‐19 extreme oil prices


$‐

$5

$10

$15

$20

$25

2016 2017 2018 2019 2020

$‐

$5

$10

$15

$20

$25

2016 2017 2018 2019 2020

‐

10,000

20,000

30,000

40,000

50,000

2016 2017 2018 2019 2020

0

300

600

900

1,200

1,500

2016 2017 2018 2019 2020

OPERATIONAL IMPROVEMENTS

4

PRODUCTION (BOE/D) OPERATING EXPENSES ($/BOE)

CAPITAL EXPENDITURES ($/BOE) 2P RESERVES (MMBOE)

~$10/boe reduction(‐15% CAGR)

>100% Production Per Share Growth(28% CAGR)

~900 mmboe added(235% 2P Reserves per Share Growth)


~$20/boe reduction(‐28% CAGR)


80

85

90

95

100

105

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2019 2020 2021 2022

mmbb

l/d

Global SupplyGlobal Demand

3,000

3,500

4,000

4,500

5,000

5,500

2018 2019 2020e 2021e 2022e 2023e

Total Alberta + Sask Adjusted Exports

Future Export Pipeline Capacity

BUSINESS ENVIRONMENT & COVID-19 IMPACT

COVID‐19 IMPACTo WHO declared COVID‐19 a pandemic in March 2020

o Resulted in a material disruption to global economy

o Economies starting to reopen and positive developments on the vaccine front

INVENTORIES CONTINUE TO DRAWDOWNo Global supply‐demand deficit of ~1.4 mmbbl/d mid 2021;

incorporates 4.4 mmbbl/d supply increase from OPEC+*

o Alberta ~30.5 mmbbl storage; ‐25% from peaks in January 2020

CANADIAN PIPELINE EGRESS o Enbridge Line 3 Replacement: +270mbbl/d in late 2021

o TMX: +590mbbl/d in late 2022

STRONG DEMAND FOR CANADIAN HEAVY BARRELSo Venezuelan and Mexican exports continue to decline

o PADD 2 refiners increasingly relying on Canadian heavy barrels

o International refiners seeking direct purchases

CDN EXPORTS/EGRESS BALANCE (MBBL/D)

SUPPLY/DEMAND OUTLOOK

5Source: RBC Capital Markets

Source: Goldman Sachs

* Goldman Sachs


$40/$45/$57 $40/$45/$57

$39.90/$45.63$55.00

$55.90 $55.90

‐

5,000

10,000

15,000

20,000

Q1 2021 Q2 2021 Q3 2021 Q4 2021

Sold CallsCollars3‐Ways

OUTLOOK, CAPITALIZATION & HEDGING

Basic Shares Outstanding 531 MM

Market Capitalization ($0.45/sh) $239 MM

Q4/20 Net Debt $412 MM

Total Enterprise Value ~$650 MM

Term Debt (9.875% due Feb 2022) US$450 MM

Q4/20 Cash (Unrestricted / Restricted) $165 / $136 MM

Tax Pools (total / NCL & CEE) $3.3 / $2.4 billion

Q4/20 Net debt = FV term debt + Working Capital Deficit (adj. for risk management contracts)

CAPITALIZATION OVERVIEW (ATH‐TSX)

WTI HEDGES (BBL/D; US$/BBL)

WCS DIFF HEDGES (BBL/D; US$/BBL)

6

2021 OUTLOOK

o Production 31,000 – 33,000 boe/d (90% liquids)

o Capital program $100MM

~$95MM Thermal Oil & ~$5MM Light Oil


$14.44

$11.98

$12.09

$12.95

‐

5,000

10,000

15,000

20,000

Q1 2021 Q2 2021 Q3 2021 Q4 2021


0

0.01

0.02

0.03

0.04

0.05

0.06

0.07

2015 2016 2017 2018 2019 2020

Intensity

(ton

nes C

O2e

/bbl)

Corporate CO2e Emissions Intensity

GOVERNANCE

SOCIALENVIRONMENT

ESG COMMITMENT

7

Air Qualityo 42% reduction in corporate per boe emissions

o Optimized facilities to reduce emissions

o Deployed technologies reducing energy

o AOC’s Board is responsible for the stewardship of the Company provides independent and effective leadership

o Some key areas of oversight include:

• Health, safety and environmental performance; Strategic direction and risk management; Succession and compensation; Ethics and compliance

o AOC’s policies are available on our website

Water & Land Useo 95% water recycle rate at Thermal Ops

o Target reductions in water use

o Minimized surface footprint

o Collaborate with industry partners on wildlife & footprint programs

o Planted ~12,000 trees in 2019

Kitaskino Nuwenëné Wildland Expansiono Collaboration between Government,

Indigenous community and industry

o AOC contributed 95,000 ha (66%) of mineral rights to help create world’s largest contiguous protected boreal forest

o AOC works with Indigenous Communities to help preserve their rights and cultures

o AOC supports many local causes

70%

75%

80%

85%

90%

95%

100%

Oil SandsMining

In Situ Enhanced oilrecovery

AthabascaThermal Oil

Recycle Ra

tes (%)

Thermal Water Recycling (2020)

2020 AOC water recycling data; 2019 industry averages


2021 2022

ATHABASCA VALUE PROPOSITION

20202020

COVID19

Managing Business

Momentum

Significant Liquidity$70MM

Contingent Bitumen Royalty

US$450MM Notes due Feb/22

Canadian Pipelines in Service

Top Tier Assets with Long Term Reserves

Liquids weighted portfolio

Flexible development plan

~1 billion bbl reserves at Leismer/Corner

~850 locations in Light Oil

Certainty on Long Term Egress to High Value

Markets

7,200 bbl/d on Keystone

20,000 bbl/d on TMX

Financial Capacity to Navigate Volatile Markets

Through the Cycle

$165MM cash (Q4/20)

Term on debt until 2022

Low corporate decline

Unparalleled Torque to Oil Prices longer term

+US$5 WTI generates ~$70MM EBITDA (unhedged)

~US$45 WTI operating break‐even*

FCF Generation



AOC is a compelling oil weighted investment

FCF Generation



Future Growth Projects

* Break‐even based on US$12.50 WCS heavy differential 8Footnotes and additional information included in the back as endnotes and reader advisories

Refinance 2L Notes

(to be completed)

THERMAL OIL LEISMER, HANGINGSTONE & OTHER ASSETS


THERMAL OIL PORTFOLIO

LEISMER – TOP TIER OIL SANDS PROJECTo ~20,000 bbl/d productive capacity (~3x SOR)

o 694 mmbbl 2P reserves; ~90 year 2P RLI

o US$27 WCS operating break‐even (US$12.50 WCS diff)

HANGINGSTONEo ~9,500 bbl/d productive capacity (~4.5x SOR)

o 36 mmbbl 2P reserves


CORNER – LONG TERM DEVELOPMENTo Top tier lease with superior reservoir to Leismer

o Fully delineated; 40,000 bbl/d regulatory approval


DOVER WEST – LONG TERM RESOURCEo Multi target reservoir

o 5 billion bbl recoverable resource

AOC THERMAL PROPERTIES

10

AOCHangingstone

AOCLeismer

AOCCorner

Hangingstone

Surmont

EnbridgeCheecham

Fort McMurray

Jackfish

Christina LakeEnbridgeWaupisoo



3.0x

3.2x

3.4x

3.6x

3.8x

4.0x

4.2x

4.4x

0

5,000

10,000

15,000

20,000

25,000

Q1 20

18

Q2 20

18

Q3 20

18

Q4 20

18

Q1 20

19

Q2 20

19

Q3 20

19

Q4 20

19

Q1 20

20

Q2 20

20

Q3 20

20

Q4 20

20

Pads 1‐6Pad 7SOR

LEISMER OVERVIEW

DEVELOPMENT MAP

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

PRODUCTION HISTORY (BBL/D; X)

11

ASSET OVERVIEWo Located ~100 km south of Fort McMurray

o Central Processing Facility (CPF); approved capacity of 40,000 bbl/d

o On site lodge with ~500 person capacity; owned Aerodrome

SUBSURFACE DATA & WELLSo 500+ delineation wells; 100% seismic coverage

o First steam September 2010

o 7 producing pads (40 well pairs & 13 infill wells)

TOP TIER OIL SANDS PROJECTo ~20,000 bbl/d productive capacity (~3x SOR)

o 694 mmbbl 2P reserves; ~90 year 2P RLI


INFRASTRUCTUREo Dilbit pipe connected to Enbridge Cheecham Terminal

o Diluent pipe connected from Enbridge Cheecham Terminal

o Fuel gas from TransCanada Pipeline



02,5005,0007,500

10,00012,500

2010 2012 2014 2016 2018 2020 2022 2024 2026

05,000

10,00015,00020,00025,000

2010 2012 2014 2016 2018 2020 2022 2024 2026

0

2,500

5,000

7,500

2010 2012 2014 2016 2018 2020 2022 2024 2026

ForecastActuals

‐

5,000

10,000

15,000

20,000

2010 2012 2014 2016 2018 2020 2022 2024 2026

ForecastActuals

LEISMER PAD OVERVIEW

PADS 1‐4 (BBL/D)

PADS 5‐6 (BBL/D)

PAD 7 (BBL/D)

Pads 1‐4

LEISMER (BBL/D)

LEISMER PAD SUMMARY

Pads 5‐6 L7

PDP Forecast

HIGHLIGHTS

o Pads L1 – 4 have well developed chambers

~27% annual decline since 2018

Seismic shows connected pairs and pads

o Pads L5 – 6 are late in plateau

Decline expected to start in 2021 after 6 years of plateau

o Pad L7 start up in 2019

~30% of 2021 forecasted production


Pad 1 Pad 2 Pad 3 Pad 4 Pad 5 Pad 6 Pad 7

Years on Production years 11 11 11 11 7 6 2

Current Production* bbl/d 2,200 1,400 1,200 700 3,200 3,500 4,800

Recovery Factor % 87% 61% 67% 69% 44% 32% 4%

2021 Decline Rate % 31% 23% 32% 28% 6% 2% 0%

* as of October 2020


2.5x

3.0x

3.5x

4.0x

4.5x

0

3,000

6,000

9,000

12,000

Jan‐19

Apr‐19

Jul‐1

9

Oct‐19

Jan‐20

Apr‐20

Jul‐2

0

Oct‐20

Jan‐21

Pad 1‐4 Production

Pad 1‐4 SOR

0

200

400

600

800

1,000

1,200

1 13 25 37 49 61 73Months

Pad 1‐6

Pad 7

$‐

$25

$50

$75

$100

2016 2017 2018 2019 2020

$0

$5

$10

$15

$20

$25

L5 L6 L7 6xWPs L8 Full Pad 14 WP

Avg. Facilities CostAvg. Completion CostAvg. Drilling Cost

13

TECHNOLOGY DRIVING RATES (BBL/D) LOWER WELL PAIR COSTS ($MM)

TECHNOLOGY IMPROVING SORS (BBL/D; X) NON‐ENERGY OPEX ($MM)

Achieved through longer laterals and implementation

of flow control devices

Non‐Condensable Gas Co‐Injection (NCG)

implemented June 2019

2020 SOR 3.3x2019 SOR 3.7x

LEISMER IMPROVEMENTS

Blending costs also reduced by ~$30MM annually through

optimization projects



$42

$38 $37

$40

$35 $34

$38

$33 $32

Budget 2021 25 kbbl/d 40 kbbl/d

US$14/bbl WTI‐WCS diff



‐

5,000

10,000

15,000

20,000

25,000

Jan‐20 Jan‐21 Jan‐22 Jan‐23 Jan‐24 Jan‐25 Jan‐

LEISMER FUTURE OPPORTUNITIES

14

ILLUSTRATIVE PROJECT ECONOMICS (US$55 WTI)WTI BREAKEVEN (US$/BBL)

>US$5/bbl reduction with additional scale

STRATEGYo Maximize free cashflow and deliver strong netbacks

o Focus on projects that improve the SOR

o Maintain agility and execution readiness

2021 BASE CAPITAL o L7P6 and L6 Infills on production H2 2021

o Pad L8 pipeline

o Pad L8 D&C and facility construction; on production H1 2022

FUTURE CAPITAL FLEXIBILITYo 9 additional well pair locations on Pad L8

LEISMER DEVELOPMENT (BBL/D)

Pads 1‐7

L6 infills + L7P6

Pad 8

Illustrative Sustaining

Long term assumptions: 0.75 FX, $2.90 AECO, $0 C5+ diff, US$12.50 WCS diff


L8 North L6 infills L7P6Capital (lease edge) $MM $54 $8 $7

Plateau Rate per project bbl/d 5,400 360 630EUR per project mbbl 13,400 1,000 2,000

IRR % 90% 85% 245%NPV10 $MM $270 $15 $40

F&D $/bbl $4.00 $8.00 $3.50 Recycle Ratio x 4.6x 2.0x 4.6xCapital Efficiency $/bbl/d $10,000 $22,000 $11,000 P/I x 4.4x 1.8x 5.6x


3.0x

3.5x

4.0x

4.5x

5.0x

5.5x

0

2,500

5,000

7,500

10,000

Q1 20

18

Q2 20

18

Q3 20

18

Q4 20

18

Q1 20

19

Q2 20

19

Q3 20

19

Q4 20

19

Q1 20

20

Q2 20

20

Q3 20

20

Q4 20

20

ProductionSOR

HANGINGSTONE OVERVIEW

DEVELOPMENT MAP

15

PRODUCTION HISTORY (BBL/D; X)

ASSET HIGHLIGHTSo Located ~20 km south of Fort McMurray

o Central Processing Facility (CPF); approved capacity of 12,000 bbl/d

o No camp; proximal to Fort McMurray

SUBSURFACE DATA & WELLSo >250 delineation wells with good seismic coverage

o First steam March 2015

o 5 producing pads (25 well pairs)

HANGINGSTONE PROJECT o ~9,500 bbl/d productive capacity (~4.5x SOR)



INFRASTRUCTUREo Dilbit export to Enbridge Cheecham Terminal

o Diluent from Inter Pipeline

o Fuel gas from TransCanada Pipeline

Curtailment &

Turnaround



0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

ActualsForecast

$0

$15

$30

$45

$60

2016 2017 2018 2019 2020

REDUCING NON‐ENERGY OPEX ($MM)~$27MM reduction through staffing, camp and disposal (~$9.25/bbl reduction)

HANGINGSTONE FUTURE OPPORTUNITIES

16

STRATEGYo Focused on base production

o Continued cost management

o Minimize capital spend

2021 EXPECTATIONSo Current production 8,800 bbl/d (Feb 2021)

o Expected to ramp‐up to 9,000 – 9,500 bbl/d in H2 2021

o Maintenance capital only

o Implement NCG to reduce SORs

MAXIMIZING PROFITABILITYo US$36 WCS operating break‐even (US$12.50 WCS diff)

o US$25 WCS shut‐in economics (US$12.50 WCS diff)

PRODUCTION OUTLOOK

2020 shut‐in opex


LIGHT OIL PLACID & KAYBOB


LIGHT OIL PORTFOLIO

18

PLACID MONTNEY – 70% WORKING INTERESTo ~80,000 gross prospective acres

o ~150 gross future locations

o $19/boe operating netback (Q4/20)

KAYBOB DUVERNAY – 30% WORKING INTERESTo ~220,000 gross prospective acres



OWNED AND OPERATED INFRASTRUCTURE o Located in a major development corridor

o Four batteries servicing the Montney and Duvernay

o Gas dually connected to Keyera Simonette & SEMCAMs KA

o Liquids pipeline connected to Pembina

AOC LIGHT OIL PROPERTIES


New recent entrants in Q1 2021: Crescent Point, KRC and Distinction


0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2019 2020

boe/d

PLACID MONTNEY OVERVIEWPLACID ACTIVITY

NET PRODUCTION HISTORY (BOE/D)

Wells

ATH MontneySpud in Past YearSpud +1 Year

19

PLACID MONTNEY ASSET – OPERATED o Located ~140 km southeast of Grande Prairie

o ~80 mmcf/d & 10,000 bbl/d infrastructure capacity

o Field operations located in Fox Creek

SUBSURFACE DATA & WELLSo Targeting multiple Montney intervals

o ~55 horizontal producers

PLACID HIGHLIGHTS – 70% WORKING INTERESTo Q4 production ~5,350 boe/d (44% liquids)

o ~80,000 gross prospective acres; no near‐term expiries

o ~150 gross future locations; 200 – 300 bbl/mmcf initial free liquids


OWNED AND OPERATED INFRASTRUCTUREo Two batteries located at Placid and Saxon



Distinction

KRC

New Montney wells on‐line



0

1,000

2,000

3,000

4,000

5,000

6,000

Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

2019 2020

boe/d

KAYBOB DUVERNAY

KAYBOB DUVERNAY OVERVIEW

20

NET PRODUCTION HISTORY (BOE/D)

KAYBOB EAST

SIMONETTE

KAYBOB NORTH

KAYBOB WEST

TWO CREEKSSAXON

Volatile Oil WindowGas Condensate WindowIndustry Duvernay Hz WellsATH Duvernay Hz Wells

KAYBOB DUVERNAY ASSET – NON OPo Located ~160 km southeast of Grande Prairie

o Two batteries; ~100 mmcf/d & 25,000 bbl/d

o $1 billion invested over past 4 years ($75MM net to AOC)

SUBSURFACE DATA & WELLSo Over‐pressured reservoir through all areas

o ~70 current horizontal producers

KAYBOB HIGHLIGHTS o Q4 production ~4,050 boe/d (77% liquids)

o ~220,000 gross prospective acres; ~90% of land held


o 200 – 1,000 bbl/mmcf condensate yields


OWNED AND OPERATED INFRASTRUCTUREo Two batteries located at Kaybob West & Kaybob East





$0

$5

$10

$15

2016 2017 2018 2019 2020

Median

$0

$5

$10

$15

$20

$25

ATH LO

CPG

WCP

TOG

OBE SGY

BNE

TVE

OVV BIR

TOU

ARX VII

KEL

AAV

NVA

POU CR SRX

CVE De

epBa

sin

Liquids Weighted Netback (>40% liquids)

Gas Weighted Netback (>60% gas)

Costs (Operating, Transportation, Royalties)

$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 IMPROVEMENTS

21

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

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

~$6.50/boe reduction

Liquids Weighted Netback (>40% liquids)

Gas Weighted Netback (>60% gas)

Costs (Operating, Transportation, Royalties)

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 resultsFootnotes and additional information included in the back as endnotes and reader advisories

INDUSTRY LEADING NETBACK (Q3/20)


PLACID FUTURE OPPORTUNITIES

22

STRATEGIC OBJECTIVESo Continued development flexibility and readiness

o Focus on free cash flow generation

FUTURE ACTIVITY o Minimal 2021 budget focused on maintenance capital to

support base production

o Operational readiness to drill and complete 4 well padConditional: 12‐24 PadDrill & Complete 4 Wells

2021 CONDITIONAL DEVELOPMENT

ILLUSTRATIVE FIVE YEAR PRODUCTION* (BOE/D) ILLUSTRATIVE MULTI WELL PAD ECONOMICS (US$55 WTI)

0.75 FX, $2.90/mcf AECO, $0/bbl C5+ diff, US$6/bbl Ed Par diff

Capital (6 wells) $MM $37.9

IP365 per well boe/d 475EUR per well mboe 500

IRR % 45%NPV10 $MM $22.3

F&D $/boe $12.50Recycle Ratio x 2.5xCapital Efficiency $/boe/d $14,000P/I x 0.6x

* Athabasca internal illustrative development scenarioFootnotes and additional information included in the back as endnotes and reader advisories

0

3,000

6,000

9,000

12,000

2020 2021e 2022e 2023e 2024e 2025e

Single Rig Program (~$75MM/yr)

PDP


0

1,250

2,500

3,750

5,000

6,250

7,500

2020 2021e 2022e 2023e 2024e 2025e

$150MM/yr Gross Program

$75MM/yr Gross Program

PDP

DUVERNAY FUTURE OPPORTUNITIES

23

STRATEGIC OBJECTIVESo Continued development flexibility and readiness

o Focus on free cash flow generation

FUTURE DEVELOPMENTo Minimal 2021 budget focused on maintenance capital to

support base production

o Several future development scenarios dependent on commodity prices

o Spending governed by a strong Joint Development Agreement (JDA)

ILLUSTRATIVE FIVE YEAR PRODUCTION* (BOE/D) ILLUSTRATIVE SINGLE WELL KAYBOB EAST ECONOMICS (US$55 WTI)

KAYBOB DUVERNAYKAYBOB EAST

SIMONETTE

KAYBOB NORTH

KAYBOB WEST

TWO CREEKSSAXON

Volatile Oil WindowGas Condensate WindowIndustry Duvernay Hz WellsATH Duvernay Hz Wells

0.75 FX, $2.90/mcf AECO, $0/bbl C5+ diff

Capital $MM $8.0

IP365 boe/d 470EUR mboe 675

IRR % 50%NPV10 $MM $6.7

F&D $/boe $11.75Recycle Ratio x 3.1xCapital Efficiency $/boe/d $17,000P/I x 0.8x

* Athabasca internal illustrative growth scenariosFootnotes and additional information included in the back as endnotes and reader advisories

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


Ensured the Safety of Staff and Contractors

RESPONSE TO COVID-19

• Enacted Business Continuity Plan

• Developed site specific plans with Alberta Health guidelines

• Transitioned Calgary staff to working remotely with site specific pre‐cautionary measures in place

• Hangingstone shut‐in/restart

• Voluntary curtailments at Leismer and Placid

• Reduced 2020 opex ($15MM)

• G&A optimization ($6MM)

• Reduced capital program (~$40MM reduction)

• Upsized Contingent Bitumen Royalty ($70MM cash)

• Reduced future KXL service

• Proactive hedge program

MANAGED BUSINESS MOMENTUM

Defer PDP for stronger prices

SOLIDIFIED BALANCE SHEET

$165MM unrestricted cash

Maximized Funds Flow

Maintained Strong Corporate Liquidity

AOC continues to advance liquidity enhancing opportunities and cost savings initiatives

SAFETY AND SECURITY OF SITES

RESULTS TO DATE

26


MARKET EGRESS

THERMAL OIL EGRESSLONG TERM EGRESS SECURED o 7,200 bbl/d on Keystone

o 20,000 bbl/d on TMX Expansion

o 10,000 bbl/d on Keystone XL

CANADIAN PIPELINES UNDER CONSTRUCTION

o Trans Mountain Expansion – Government of Canada owned

Enbridge Waupisoo

Enbridge South Cheecham Terminal

Edmonton

Hardisty

Storage130,000 bbl for apportionment management

Trans Mountain Expansion20,000 bbl/d 2022+

International markets

TC Energy KeystoneUSGC (PADD III)7,200 bbl/d

TC Energy Keystone XL10,000 bbl/d 2022+

Enbridge Mainline Mid‐west (PADD II)(common carrier line)

Current EgressLT Egress AOC Thermal Leases

27


THE WORLD NEEDS CANADA’S ENERGY

o Energy Demand to grow by 27% by 2040

o ALL forms of energy are needed

CANADA IS A GLOBAL LEADER IN INNOVATION & ENVIRONMENTAL STEWARDSHIP

o If Canadian Energy standards were applied across the world GHG emissions would decrease 23% (~100MM car equivalent)

o Oil Sands 0.15% of world emissions

CANADA NEEDS A ROBUST ENERGY SECTOR

o >$40B in annual capital investment

o Employment far reaching (533,000 jobs), largest employer of Indigenous people

CANADIAN ENERGY MAKES A GLOBAL DIFFERENCE

Sources: CAPP, IEA, “Global carbon intensity of crude oil production” published Aug 2018 in Science Mag

The World Needs More Canadian Energy

WORLD ENERGY MIX (2016 – 2040)

EMISSIONS IN THE GLOBAL CONTEXTChina 24%

US 13%

EU 7%

India 7%

Russia 4%

Japan 3%

Canada <1.5%

Australia 1%

Other 40%

28


ENDNOTES

29

Slide Endnotes1 (1) Production is the mid‐point of 2021 guidance, product breakdown provided below:

(2) Cash = unrestricted cash & equivalents as of December 31, 2020(3) Consolidated reserves as of December 31, 2020. Reserves referred to throughout presentation were evaluated by McDaniel & Associates Consultants Ltd.(4) Reserve life index (RLI) calculated on corporate 2P reserves of 1,156 mmboe and ~34,000 boe/d production. Please see reader advisory “Additional Oil and Gas

Information” for more information (5) For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2020

Annual Information Form which is available on Company’s website or on SEDAR www.sedar.com

2 (1) Q4 production volumes by product:

(2) Consolidated reserves as of December 31, 2020. Reserves referred to throughout presentation were evaluated by McDaniel & Associates Consultants Ltd(3) Asset Coverage ratios = McDaniel NPV10 before tax for PDP and 1P divided by the face value of the outstanding second lien notes (US$450MM)(4) Adjusted Funds Flow is a non‐GAPP measures that equals cash flow from operating activities + restructuring fees + changes in non‐cash working capital + settlement of

provisions + plus long‐term deposits. Please see reader advisory “Non‐GAAP Financial Information” for more information.(5) Cash = unrestricted cash & equivalents as of December 31, 2020(6) Netbacks is a non‐GAPP measure that equals operating netbacks prior to realized hedging gains (losses) and other income. Please see reader advisory “Non‐GAAP

Financial Information” for more information.(7) Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com

Product 2021 Production SplitBitumen 77%Natural Gas 10%Condensate NGLs 4%Other NGLs 2%Light & Medium Crude Oil 0%Tight Oil 7%

Product Q4/2020Bitumen bbl/d 24,839Natural Gas mcf/d 23,529Condensate NGLs bbl/d 1,841Other NGLs bbl/d 787Light & Medium Crude Oil bbl/d 2Tight Oil bbl/d 2,843Total boe/d 34,233


ENDNOTES

30

Slide Endnotes3‐4 (1) Historical annual and 2021e Corporate volumes by product are provided below:

(2) Adjusted funds flow is a non‐GAPP measures that equals cash flow from operating activities + restructuring fees + changes in non‐cash working capital + settlement of provisions + plus long‐term deposits. Please see reader advisory “Non‐GAAP Financial Information” for more information.

(3) 2021e adjusted funds flow is based on US$55 WTI, US$12.50 WCS differentials and 0.79FX; shaded portions shows upside for +US$5 WTI increase(4) FCF is a non‐GAAP measure that equals adjusted funds flow – capital expenditures. Please see reader advisory “Non‐GAAP Financial Information” for more information. (5) Operating Expenses = energy opex + non‐energy opex + light oil opex + emission taxes (6) For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2020

Annual Information Form which is available on Company’s website or on SEDAR www.sedar.com(7) Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com

6 (1) 2021 production guidance product breakdown:

(2) Net debt is a non‐GAPP measure that equals FV term debt + Current Liabilities (adj. for risk management) ‐ Current Assets (adj. for risk management) as of December 31, 2020. Please see reader advisory “Non‐GAAP Financial Information” for more information

(3) Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com

8 (1) Cash = unrestricted cash & equivalents as of December 31, 2020(2) Consolidated reserves as of December 31, 2020. Reserves referred to throughout presentation were evaluated by McDaniel & Associates Consultants Ltd.(3) Gross Montney inventory based on management estimate of 4 wells per section. Gross Duvernay acres and inventories based on management estimate of 4‐6 wells per

section and ~2,750m laterals. See reader advisory “Drilling Locations” for more detail(4) EBITDA is a non‐GAPP measure that is defined as Net income (loss) and comprehensive income (loss) before foreign exchange gain (loss), gain (loss) on foreign

exchange risk management contracts, gain (loss) on revaluation of provisions and other, gain (loss) on sale of assets, financing and interest expense, depreciation, depletion, impairment and taxation (recovery) expense. Please see reader advisory “Non‐GAAP Financial Information” for more information

(5) Corporate operating break‐even based on 2021 forecasted production and 0.75FX, US$0 C5 diff and C$2.90 AECO pricing assumptions. Operating break‐even reflects the estimated WTI oil price per barrel required to generate adjusted funds flow of Cdn $0. Break‐even is used to assess the impact of changes in WTI oil prices on adjusted funds flow and could impact 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

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




ENDNOTES

31

Slide Endnotes10‐16 (1) Leismer reserve life index calculated on 694mmbbl 2P reserves and 20,000 bbl/d production; Hangingstone reserve life index calculated on 36mmbbl 2P reserves and

9,500 bbl/d production. Please see reader advisory “Additional Oil and Gas Information” for more information (2) For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2020

Annual Information Form which is available on Company’s website or on SEDAR www.sedar.com(3) Break‐evens and shut‐in economics based on 2021 forecasted production and 0.75FX, US$0 C5 diff and C$2.90 AECO pricing assumptions. 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 could impact 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

(4) Dover West recoverable resource is based on McDaniel’s 2C unrisked best estimate 2.2 billion barrels + managements estimate of recoverable volumes associated with the Leduc Carbonates of ~3 billion barrel which are not book as reserves or contingent resource by McDaniel

(5) Recovery Factors are calculated by dividing the Estimated Ultimate Recovery by the Gross Bitumen in Place (6) All bbl/d, bbl, mbbl and mmbbl references are bitumen

18‐21 (1) Gross Duvernay acres and inventories. Well inventory based on management estimate of 4‐6 wells per section and ~2,750m laterals See reader advisory “Drilling Locations” for more detail

(2) Gross Montney inventory based on management estimate of 4 wells per section. See reader advisory “Drilling Locations” for more detail(3) Operating netback is a non‐GAAP measure calculated that is prior to realized hedging gains (losses) and other income. Please see reader advisory “Non‐GAAP Financial

Information” for more information(4) Free liquids yield refers to Condensate NGLs divided by raw gas(5) Condensate yield refers to Tight Oil volumes divided by raw gas(6) Historical quarterly Placid production by product:

(7) Historical quarterly Kaybob production by product:

Product 2019 2020Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Natural Gas mcf/d 22,426 20,442 17,538 15,723 12,939 14,221 19,668 17,901Condensate NGLs bbl/d 2,710 2,150 1,734 1,457 1,480 1,916 2,612 1,841Other NGLs bbl/d 556 524 439 494 351 389 631 524Light & Medium Crude Oil bbl/d 0 0 0 0 0 0 0 0Tight Oil bbl/d 0 0 0 0 0 0 0 0Total boe/d 7,004 6,081 5,096 4,571 3,987 4,675 6,521 5,347

Product 2019 2020Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4

Natural Gas mcf/d 10,150 9,564 9,421 7,971 7,123 7,642 7,746 5,628Condensate NGLs bbl/d 0 0 0 0 0 0 0 0Other NGLs bbl/d 536 349 371 406 359 291 332 263Light & Medium Crude Oil bbl/d 52 29 16 10 3 0 0 2Tight Oil bbl/d 2,428 2,157 2,969 2,326 2,705 3,225 3,685 2,843Total boe/d 4,708 4,129 4,926 4,071 4,254 4,791 5,308 4,047


ENDNOTES

32

Slide Endnotes22 ‐ 23 (1) Placid Montney future production forecasts are ~50‐55% shale gas, ~35‐40% condensate NGLs and ~10% other NGLs

(2) Placid Montney IP365 rates are ~40% shale gas, ~50% condensate NGLs and ~10% other NGLs; EURs are ~50% shale gas, ~40% condensate NGLs and ~10% other NGLs (3) Kaybob Duvernay future production forecasts are ~75% tight oil, ~25% shale gas and ~10% NGLs(4) Kaybob East IP365 rates are ~25% shale gas, ~70% tight oil and ~5% NGLs; EURs are ~30% shale gas, ~65% tight oil and ~5% NGLs


READER ADVISORY

33

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”, “continue”, “estimate”, “expect”, “may”, “will”, “project”, “target”, “should”, “believe”, “predict”, “pursue”, “potential”, “view” and ”contemplate” and similar expressions are intended to identify forward‐lookinginformation. 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’s industry, business andfuture 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 such forward‐lookinginformation. 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 speaks only as of the dateof this Presentation. In particular, this Presentation contains forward‐looking information pertaining to, but not limited to, the following: our strategic plans; the Company’s 2021 Outlook; refinancing of its US$450 million Second LienNotes; 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; Hangingstone ramp‐up to previousbitumen rates; type well economic metrics; and other matters.

In addition, information and statements in this Presentation relating to "Reserves" and “Resources” are deemed to be forward‐looking information, as they involve the implied assessment, based on certain estimates and assumptions,that the reserves and resources described exist in the quantities predicted or estimated, and that the reserves and resources described can be profitably produced in the future. With respect to forward‐looking information contained inthis Presentation, assumptions have been made regarding, among other things: commodity prices; the regulatory framework governing royalties, taxes and environmental matters in the jurisdictions in which the Company conducts andwill 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; theCompany’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‐efficient manner; the applicability of technologies for therecovery 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 capital programs; the Company’s future debt levels; futureproduction levels; the Company’s ability to obtain financing and/or enter into joint venture arrangements, on acceptable terms; operating costs; compliance of counterparties with the terms of contractual arrangements; impact ofincreasing competition globally; collection risk of outstanding accounts receivable from third parties; geological and engineering estimates in respect of the Company’s reserves and resources; 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 the Company’s Reserves and Resources are contained in thereport of McDaniel & Associates Consultants Ltd. (“McDaniel”) evaluating Athabasca’s Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 2020 (which is respectively referred to herein as the "McDanielReport”).

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 available on SEDAR atwww.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; abilityto 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 theenvironment; political uncertainty; state of capital markets; anticipated benefits of acquisitions and dispositions; abandonment and reclamation costs; changing demand for oil and natural gas products; royalty regimes; foreignexchange 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 to our 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.

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.


READER ADVISORY CONT’D

34

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

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 Light Oil Operating Income (Loss) measure in this Presentation is calculated by subtracting royalties, operating expenses and transportation & marketing expenses from petroleum and natural gas sales. The Light Oil OperatingNetback measure is calculated by dividing the Light Oil Operating Income (Loss) by the Light Oil production and is presented on a per boe basis. The Light Oil Operating Income (Loss) and the Light Oil Operating Netback measures allowmanagement and others to evaluate the production results from the Company’s Light Oil assets.

The Operating Income (Loss) measure in this Presentation with respect to the Leismer Project and Hangingstone Project is calculated by subtracting the cost of diluent blending, royalties, operating expenses and transportation &marketing expenses from heavy oil (i.e. blended bitumen) sales. The Thermal Oil Operating Netback measure is calculated by dividing the respective projects Operating Income (Loss) by its respective bitumen sales volumes and ispresented on a per barrel basis. The Thermal Oil Operating Income (Loss) and the Thermal Oil Operating Netback measures allow management and others to evaluate the production results from the Company’s Thermal Oil assets.

The Consolidated Operating Income (Loss) measure in this Presentation is calculated by adding or subtracting realized gains (losses) on commodity risk management contracts, royalties, the cost of diluent blending, operating expensesand transportation & marketing expenses from petroleum and natural gas sales. The Consolidated Operating Netback measure is calculated by dividing Consolidated Operating Income (Loss) by the total sales volumes and is presentedon a per boe basis. The Consolidated Operating Income (Loss) and the Consolidated Operating Netback measures allow management and others to evaluate the production results from the Company’s Light Oil and Thermal Oil assetscombined together including the impact of realized commodity risk management gains or losses.

The Consolidated Capital Expenditures Net of Capital‐Carry and Light Oil Capital Expenditures Net of Capital‐Carry measures in this Presentation are outlined in the Company’s Q4 2020 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 current liabilities (adjusted for risk management contracts) less current assets (adjusted for risk management contracts and capital‐carry receivable).

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 stock‐based compensation.

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

Liquids is defined as bitumen, light crude oil, medium crude oil and natural gas liquids.

athabasca oil corporation...leismer –top tier oil sands project o ~20,000 bbl/d productive...

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