athabasca oil corporation€¦ · 05/01/2021 · o global supply‐demand deficit of...

ATHABASCA OIL CORPORATIONFOCUSED | EXECUTING | DELIVERINGCORPORATE OVERVIEW - JANUARY 2021

ATHABASCA OIL (TSX:ATH)

PREMIER RESOURCE EXPOSURE

~32,000 boe/d~90% liquids

95 year 2P RLI1,300 MMboe 2P

455 MMboe Proved

MONTNEY

DUVERNAY

LIGHT OIL

LIGHT OIL CORNER

LEISMER

HANGINGSTONE

THERMAL OIL

~$500MM EV$152MM Cash

1Footnotes and additional information included in the back as endnotes


Q3 2020 HIGHLIGHTS

$152MM CashUnrestricted

$2.2MM Free Cash Flow

Netbacks$21/boe Light Oil$16/bbl Leismer

32,061 boe/d86% liquids

Footnotes and additional information included in the back as endnotes

$12MM Capex85% Thermal / 15% Light Oil

2


$‐

$2

$4

$6

2016 2017 2018 2019 2020F

($102)

$102 $6 $155 TBD

($25)

$25

$75

$125

$175

2016 2017 2018 2019 2020 ‐

10,000

20,000

30,000

40,000

50,000

2016 2017 2018 2019 2020F

THE TRANSFORMATION

2016 2017 2018 2019 20202020

COVID19

Manage Business

Momentum

Maintain Strong Liquidity

ResourceAppraisal

Fundingnot Secured

FCF Generation

Disciplined Operations

Strong Balance Sheet

Future Growth Projects

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



$‐

$5

$10

$15

$20

$25

2016 2017 2018 2019 2020F 2021F

‐

10,000

20,000

30,000

40,000

50,000

2016 2017 2018 2019 2020F 2021F

0

300

600

900

1,200

1,500

2016 2017 2018 2019 2020F

$‐

$5

$10

$15

$20

$25

2016 2017 2018 2019 2020F

OPERATIONAL IMPROVEMENTS

4

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

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

~$10/boe reduction(‐14% CAGR)

~$20/boe reduction(‐26% CAGR)

>100% Production Per Share Growth(22% CAGR)

>1 billion boe added(282% 2P Reserves per Share Growth)



Ensured the Safety of Staff and Contractors

RESPONSE TO COVID-19

• Enacted Business Continuity Plan• Developed site specific plans with

Alberta Health guidelines

• Successful transitioned back to the office 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

$152MM 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



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

$0

$5

$10

$15

2018 2019 2020e 2021e 2022e 2023e

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

INVENTORIES CONTINUE TO DRAWDOWNo Global supply‐demand deficit of 1.5‐2mmbbl/d in H2 2020*

o Alberta ~24mmbbl storage; ‐40% from peaks in January

o OPEC+ extending cuts in 2021

CANADIAN PIPELINE EGRESS o Keystone & Express: +75mbbl/d in H2 2021

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

o TMX: +590mbbl/d in H1 2023

o KXL: AB government financial support; US gov’t uncertainty

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)

WTI‐WCS DIFFERENTIAL (US$/BBL)

6Source: RBC Capital Markets

Source: Streamline, RBC Capital Markets

$26

Pipe Economics

* Goldman Sachs


$14.44

$11.98 $11.98

‐

5,000

10,000

15,000

20,000

Q1 2021 Q2 2021 Q3 2021 Q4 2021

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

$39.90/$45.63

‐

5,000

10,000

15,000

20,000

Q1 2021 Q2 2021 Q3 2021 Q4 2021

Collars

3‐Ways

OUTLOOK, CAPITALIZATION & HEDGING

Basic Shares Outstanding 531 MM

Market Capitalization ($0.17/sh) $90 MM

Q3/20 Net Debt $411 MM

Total Enterprise Value $501 MM

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

Q3/20 Cash (Unrestricted / Restricted) $152 / $151 MM

Q4e/20 Liquidity ~$170 MM

Tax Pools (total / NCL & CEE) $3.2 / $2.2 billion

Q3/20 Net debt = FV term debt + Working Capital Deficit (adj. for risk management contracts and restricted cash)

CAPITALIZATION OVERVIEW (ATH‐TSX)

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

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

7

2020 OUTLOOK

o Production ~32,250 boe/d

o Capital program ~$85MM

2021 OUTLOOK

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

o Capital program $75MM

o ~$70MM Thermal Oil & ~$5MM Light Oil


GOVERNANCE

SOCIALENVIRONMENT

0.02

0.03

0.04

0.05

0.06

0.07

2015 2016 2017 2018 2019

Intensity

(ton

nes C

O2e

/boe

)

ESG COMMITMENT

8

CORPORATE EMISSIONS INTENSITY

Air Qualityo 34% reduction in corporate 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

THERMAL WATER RECYCLING (2019) Water Use & Recycling

o 95% water recycle rate at Thermal Ops

o Target reductions in water use

Land & Wildlife

o Minimized surface footprint

o Collaborate with industry partners on wildlife & footprint programs

o Planted ~12,000 trees in 2019

o Community & stakeholder engagement

o AOC supports many local causes

70%

75%

80%

85%

90%

95%

Oil sands mining In Situ Enhanced oilrecovery

AthabascaThermal Oil

Recycle Ra

tes


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

10,000 bbl/d on Keystone XL

20,000 bbl/d on TMX

Financial Capacity to Navigate Volatile Markets

Through the Cycle

$152MM liquidity (Q3/20)

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




* Break‐even based on US$12.50 WCS heavy differential. 9

THERMAL OIL LEISMER, HANGINGSTONE & OTHER ASSETS


THERMAL OIL PORTFOLIO

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

o 695 mmbbl 2P reserves; 95 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)



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

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

o 353 mmbbl 2P reserves

DOVER WEST – LONG TERM RESOURCEo Multi target reservoir

o 5 billion bbl recoverable resource

AOC THERMAL PROPERTIES

11

AOCHangingstone

AOCLeismer

AOCCorner

Hangingstone

Surmont

EnbridgeCheecham

Fort McMurray

Jackfish

Christina LakeEnbridgeWaupisoo



3.0

3.2

3.4

3.6

3.8

4.0

4.2

4.4

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)

12

NCG and Pad L7 have improved SORs by ~20%

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)



INFRASTRUCTUREo Dilbit pipe connected to Enbridge Cheecham Terminal

o Diluent pipe connected from Enbridge Cheecham Terminal

o Fuel gas from TransCanada Pipeline



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

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 1 – 4 have well developed chambers

~27% annual decline since 2018

Seismic shows connected pairs and pads

o Pads 5 – 6 are late in plateau

Decline expected to start in 2021 after 6 years of plateau

o Pad 7 start up in 2019

Accounts for ~30% of 2021 production



2.5

3.0

3.5

4.0

4.5

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

Pad 1‐4 Production

Pad 1‐4 SOR

$‐

$25

$50

$75

$100

2016 2017 2018 2019 2020F

$0

$5

$10

$15

$20

$25

L5 L6 L7 6xWPs L8 Full Pad 14 WP

Avg. Facilities CostAvg. Completion CostAvg. Drilling Cost

0

300

600

900

1,200

1 13 25 37 49 61 73Months

Pad 1‐6

Pad 7

14

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

~20% reduction in SOR to 3.2x

LEISMER IMPROVEMENTS

Blending costs also reduced by ~$30MM annually



$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

15

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 & L6 Infills first steam Mar/Apr 2021

o Pad 8 pipeline (seasonal), facility fab, drill/complete long leads

2021 CONDITIONAL CAPITAL o Pad 8 drilling, completions, and facility construction

LEISMER DEVELOPMENT (BBL/D)

Pads 1‐7

L6 infills + L7P6

Pad 8

Illustrative Sustaining

0.75 FX, $2.90/mcf AECO, $0/bbl C5+ diffUS$ WCS Diff – 2022: $14/bbl, 2023: $12/bbl & 2024+: $10/bbl

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 % 65% 80% 215%NPV10 $MM $265 $15 $41

F&D $/bbl $4.00 $8.00 $3.25Recycle Ratio x 4.6x 2.0x 4.9xCapital Efficiency $/bbl/d $15,500 $22,000 $11,000P/I x 4.9x 1.9x 5.9x



3.0

3.5

4.0

4.5

5.0

5.5

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

16

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 2020F

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

HANGINGSTONE FUTURE OPPORTUNITIES

17

STRATEGYo Focused on base production

o Continued cost management

o Minimize capital spend

2021 EXPECTATIONSo Production ramping up from 7,500 to 9,000 bbl/d

o Maintenance capital only

o Implement NCG to reduce SORs

MAXIMIZING PROFITABILITYo Long term egress commitments of ~$45MM annually


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

19

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

o ~150 gross future locations

o $19/boe operating netback (Q3/20)

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

Fox Creek

Pembina

AllianceSEMCAMsKA

KeyeraSimonette


0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

2018 2019 2020

PLACID MONTNEY OVERVIEWPLACID ACTIVITY


NET PRODUCTION HISTORY (BOE/D)

Wells

ATH MontneySpud in Past YearSpud +1 Year

20

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 Q3 production ~6,500 boe/d (50% 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


o Liquids pipeline connected to Pembina

Delphi

Ovintiv

New Montney wells on‐line


KAYBOB DUVERNAY

KAYBOB DUVERNAY OVERVIEW

21

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 Q3 production ~5,300 boe/d (76% 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


o Liquids pipeline connected to Pembina 0

1,000

2,000

3,000

4,000

5,000

6,000

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3

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

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

$5

$10

$15

2016 2017 2018 2019 2020F

LIGHT OIL IMPROVEMENTS

22

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

INDUSTRY LEADING NETBACK (Q3/20)Liquids Weighted Netback (>40% liquids)

Gas Weighted Netback (>60% gas)

Costs (Operating, Transportation, Royalties)

High Liquids %High Quality ProductLow Lifting Costs

Footnotes and additional information included in the back as endnotes* 2021 does not have any approved operations for the Duvernay; 2021 target D&C costs reflect Q1/20 pace setter well results


0

3,000

6,000

9,000

12,000

2020e 2021e 2022e 2023e 2024e 2025e

Single Rig Program (~$75MM/yr)

PDP

PLACID FUTURE OPPORTUNITIES

23

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 pad in H2/21Conditional: 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


DUVERNAY FUTURE OPPORTUNITIES

24

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 constructive 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

0

1,250

2,500

3,750

5,000

6,250

7,500

2020e 2021e 2022e 2023e 2024e 2025e

$150MM/yr Gross Program

$75MM/yr Gross Program

PDP

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

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

26


MARKET EGRESS

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

o 10,000 bbl/d on Keystone XL

o 20,000 bbl/d on TMX Expansion

CANADIAN PIPELINES UNDER CONSTRUCTION

o Trans Mountain Expansion – Government of Canada owned

o Keystone XL – Government of Alberta backed

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


TRACK RECORD OF TRANSACTION EXECUTION

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C$486MM Light Oil Joint Venture

• $1B asset investment through capital carry• De‐risked emerging Duvernay play• Protective development agreement with

experienced shale player

C$560MM Leismer Acquisition

• Equinor (Statoil) world‐class assets• Opportunistic and countercyclical acquisition• Drives cash flow growth and scale

~C$400MM Contingent Royalty

• Burgess Energy private investors• Monetize long dated out‐of‐money resource• Royalty not triggered until >$60 USD WCS

C$265MM Leismer Infra. Disposition

• Enbridge services existing Thermal operations • Competitive metrics >10x EBITDA• Leismer acquisition fully paid out

C$70MM Upsized Contingent Royalty

• Assets unencumbered until >$60 USD WCS• Extremely attractive cost of capital

US$450MM Senior Note Issuance

• Proceeds directed to retiring existing Notes• 5 year term provides strategic flexibility• Instrument sized for $55 WTI & $12.50 diffs

HIGHLIGHTS

o ~$2.25 billion of strategic and creative transactions completed through the down cycle

o Transactions focused on managing risk and building scale while minimizing dilution to shareholders

H1 2016

H2 2016

H1 2017

H1 2017

H1 2019

H1 2020


STRATEGIC RATIONALE

o Corporate

• Reduce development risk profile while maintaining upside potential• Strengthen balance sheet and facilitate debt refinancing

o Montney

• Material operated land position with flexibility to control pace of developmento Duvernay

• Partner/operator is an experienced player in the Eagle Ford (800+ oil wells drilled to date)• Accelerate delineation of the volatile oil window • Limit near‐term capital exposure through carry provision

$800MM LIGHT OIL JOINT VENTURE

o Greater Placid Assets – AOC 70% WI & operator; 60,000 gross Montney acres

o Greater Kaybob Assets – MUR 70% WI & operator; 200,000 gross Duvernay acres

o $486MM net consideration to AOC

LIGHT OIL JOINT VENTURE WITH MURPHY OIL

30

As of May 13, 2016


0%

3%

6%

9%

12%

15%

$50 $75 $100 $125 $150 $175

WCS (US$/bbl)

Leismer, Hangingstone, Corner

Dover West, Birch, Grosmont

CONTINGENT BITUMEN ROYALTY

SLIDING SCALE STRUCTURE

$70MM UPSIZED ROYALTY

o Upsized Royalty only applies to the Hangingstone, Leismer and Corner

o Total cash proceeds of $467MM

ROYALTY OVERVIEW

o US$ Western Canadian Select benchmark trigger

o Royalty scale between 0 – 15%

• US$60 WCS initial 2.5% trigger (equivalent to US$72.50 WTI with a US$12.50 WCS diff)

o Applied to the realized bitumen price net of transportation and storage

FUTURE EXPANSION PHASES & PROJECTS

o Limited impact on future project returns

o No commitments to future development phases

o Higher pricing threshold on greenfield assets

SLIDING SCALE ROYALTY

US$ WCSLeismer, Corner & Hangingstone

$100 15.0%

31


STATOIL PURCHASE: TRANSFORMATIONAL ACQUISITION

32

2Assets

510km2Total Acreage

~24,000 bbl/dCurrent Production

838Delineation Wells

2P Reserves 856 mmbblResource 628 mmbbl

$165MMCash Flow at

US$60/bbl WTI

~70 yearLeismer 2P RLI80,000 bbl/d

Regulatory ApprovalInfrastructureDilbit/Diluent Pipes

Storage Tanks

As of January 31, 2017


LEISMER INFRASTRUCTURE TRANSACTION

33

STRATEGIC TRANSACTION WITH ENBRIDGE

o $265MM cash consideration

o 30 year term with an annual toll of ~$26MM

o Priority service on pipelines & dilbit/diluent tanks (2x 150mbbl)

o Excess volumes above firm commitments receive a discounted toll

o Enhanced credit terms with Enbridge across our Thermal Oil business Competitive Break‐evens

Unlocking Value

Proceeds ~50% of market cap

Bolstered Liquidity

~$550MM funding capacity

Recouped Leismer acquisition cash consideration ($435MM) within two years through free cash flow, contingent bitumen royalty and infrastructure proceeds (combined ~$500MM)Recouped Leismer acquisition cash consideration ($435MM) within two years through free cash flow, contingent bitumen royalty and infrastructure proceeds (combined ~$500MM)

Q4/18e funding capacity pro forma infrastructure sale. Includes: cash, available credit facilities & Duvernay capital carry

As of January 15, 2019


Slide Endnotes1 (1) Liquidity = cash & equivalents + available credit facilities as of September 30, 2020

(2) Consolidated reserves as at December 31, 2019 evaluated by McDaniel & Associates Consultants Ltd.(3) Reserve life index calculated on corporate 2P reserves of 1,300 mmboe and ~37,500 boe/d production (4) For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2019

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

2‐5 / 7 (1) Historical financial and operating results found on Company’s website or on SEDAR www.sedar.com(2) Adjusted Funds Flow = cash flow from operating activities + restructuring fees + changes in non‐cash working capital + settlement of provisions + plus long‐term

deposits (3) Liquidity = cash & equivalents + available credit facilities as of September 30, 2020 (4) Operating Expenses = enegy opex + non‐energy opex + light oil opex + emission taxes (5) Netbacks = operating netbacks prior to realized hedging gains (losses) and other income(6) FCF = adjusted funds flow – capital expenditures(7) Net debt = FV term debt + Current Liabilities (adj. for risk management) ‐ Current Assets (adj. for risk management) as of September 30, 2020

9 (1) Liquidity = cash & equivalents + available credit facilities as of September 30, 2020(2) Consolidated reserves as at December 31, 2019 evaluated by McDaniel & Associates Consultants Ltd.(3) Gross Montney inventory based on management estimate of 4 wells per section. 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(4) EBITDA 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

(5) Corporate operating break‐even based on 2021 forecasted production and 0.75FX, US$0 C5 diff and C$2.90 AECO pricing assumptions11‐17 (1) Leismer reserve life index calculated on 695mmbbl 2P reserves and 20,000 bbl/d production; Hangingstone reserve life index calculated on 177mmbbl 2P reserves and

9,000 bbl/d production(2) 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(3) For additional information regarding Athabasca’s reserves and resources estimates, please see “Independent Reserve and Resource Evaluations” in the Company’s 2019

Annual Information Form which is available on Company’s website or on SEDAR www.sedar.com(4) Dover West recoverable resource is based on McDaniel’s 2C unrisked best estimate + managements estimate of recoverable volumes associated with the Leduc

Carbonates 19‐24 (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 prior to realized hedging gains (losses) and other income

ENDNOTES

34


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”, “believe”, “view”, ”contemplate”, “target”, “potential” and similar expressions are intended to identify forward‐looking information. The forward‐lookinginformation 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 and future operating and financialresults. 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‐looking information. No assurance can begiven 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 date of this Presentation. In particular,this Presentation contains forward‐looking information pertaining to the following: the Company’s 2020 expected average production, 2021 production guidance, including % of liquids production, 2021 budget guidance, break‐evenpricing, 2021 drilling plans and expected payout periods, the Hangingstone project ramp‐up, key priorities in 2021 and other matters.

Information relating to "reserves" is also deemed to be forward‐looking information, as it involves the implied assessment, based on certain estimates and assumptions, that the reserves described exist in the quantities predicted orestimated and that the reserves 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 outlook;the regulatory framework in the jurisdictions in which the Company conducts business; the Company’s financial and operational flexibility; the Company’s, capital expenditure outlook, financial sustainability and ability to access sourcesof funding; geological and engineering estimates in respect of Athabasca’s reserves and resources; and other matters. Certain other assumptions related to the Company’s Reserves are contained in the report of McDaniel evaluatingAthabasca’s Proved Reserves, Probable Reserves and Contingent Resources as at December 31, 2019 (which is respectively 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 4, 2020 and ManagementDiscussion & Analysis for the three and nine months ended September 30, 2020 dated November 4, 2020 (“MD&A”), each available on SEDAR at www.sedar.com, including, but not limited to: fluctuations in commodity prices, foreignexchange and interest rates; political and general economic, market and business conditions in Alberta, Canada, the United States and globally; changes to royalty regimes, environmental risks and hazards; the potential formanagement estimates and assumptions to be inaccurate; the dependence on Murphy as the operator of the Company’s Duvernay assets; the capital requirements of Athabasca’s projects and the ability to obtain financing; operationaland business interruption risks, including those that may be related to the COVID‐19 pandemic; failure by counterparties to make payments or perform their operational or other obligations to Athabasca in compliance with the termsof contractual arrangements; aboriginal claims; failure to obtain regulatory approvals or maintain compliance with regulatory requirements; uncertainties inherent in estimating quantities of reserves and resources; litigation risk;environmental risks and hazards; reliance on third party infrastructure; hedging risks; insurance risks; claims made in respect of Athabasca’s operations, properties or assets; risks related to Athabasca’s credit facilities and seniorsecured notes; and risks related to Athabasca’s common shares.

Drilling Locations: The ~700 Duvernay drilling locations referenced include: 45 proved undeveloped or non‐producing locations and 35 probable undeveloped locations for a total of 40 booked locations with the balance being unbookedlocations. The ~150 Montney drilling locations referenced include: 77 proved undeveloped locations and 24 probable undeveloped locations for a total of 101 booked locations with the balance being unbooked locations. Provedundeveloped locations and probable undeveloped locations are booked and derived from the Company's most recent independent reserves evaluation as prepared by McDaniel as of December 31, 2019 and account for drillinglocations that have associated proved and/or probable reserves, as applicable. Unbooked locations are internal management estimates. Unbooked locations do not have attributed reserves or resources (including contingent orprospective). Unbooked locations have been identified 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 reserves information. 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 drilling locations on which the Company will actually drill wells, including the number and timing thereof is ultimately dependent upon the availability of funding, oil and natural gas prices, provincial fiscaland royalty policies, costs, actual drilling results, additional reservoir information that is obtained and other factors.

Additional Oil and Gas Information:

“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.

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.

Non‐GAAP Financial Measures:

The "Adjusted Funds Flow”, "Light Oil Operating Income", “Light Oil Operating Netback”, “Light Oil Capital Expenditures Net of Capital‐Carry”, "Thermal Oil Operating Income", "Thermal Oil Operating Netback", “Consolidated OperatingIncome”, “Consolidated Operating Netback”, “Consolidated Capital Expenditures Net of Capital‐Carry”, and “Net Debt” financial measures contained in this Presentation do not have standardized meanings which are prescribed by IFRSand they are considered to be non‐GAAP measures. These measures may not be comparable to similar measures presented by other issuers and should not be considered in isolation with measures that are prepared in accordance withIFRS. Definitions are outlined this presentations end notes and the Company’s Q3 2020MD&A and financials available on SEDAR (www.sedar.com) or the Company’s website (www.atha.com) .

READER ADVISORY

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