energy Creating - ARC Resources...assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital

energy Creating

for the world

Investor PresentationFebruary 2021

Advisory Statements

Forward-looking Information and Statements and Advisory StatementsThis presentation contains forward-looking information as to ARC’s internal projections, expectations, or beliefs relating to future events or future performance and includes information as to ARC’s future well inventory in its core areas, itsexploration and development drilling and other exploitation plans for 2021, and related production expectations, expenditures and cash flows, the Company’s plans for constructing and expanding facilities, the volume of ARC's crude oil andnatural gas reserves and the volume of ARC's crude oil and natural gas resources in the Montney, the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's crude oiland natural gas production, future results from operations, and operating metrics. These statements represent Management’s expectations or beliefs concerning, among other things, future operating results and various components thereof orthe economic performance of ARC. The projections, estimates, and beliefs contained in such forward-looking statements are based on Management's assumptions relating to the production performance of ARC’s crude oil and natural gasassets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital expenditure budgets, future commodity prices, continuing access to capital, and the continuationof the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties, such as changes in crude oil and natural gas prices, infrastructure constraints in relation to the development of theMontney, risks associated with the degree of certainty in resource assessments, and including the business risks discussed in ARC’s annual and quarterly Management’s Discussion and Analysis and other continuous disclosure documents,and related to Management’s assumptions, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-lookingstatements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differ materially from those predicted. Other than the 2021 Guidance, which is discussed quarterly, ARC does not undertake to updateany forward-looking information in this document whether as to new information, future events, or otherwise except as required by securities laws and regulations.

ARC has adopted the standard of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used in isolation. A boeconversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price ofcrude oil as compared to natural gas is significantly different than the energy equivalency of the 6 Mcf:1 bbl conversion ratio, utilizing the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.

Throughout this presentation, crude oil refers to tight, light, medium, and heavy crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Natural gas refers to shale gasand conventional natural gas product types as defined by NI 51-101. ARC’s production of conventional natural gas is considered to be immaterial. ARC’s core producing properties that are considered to be shale gas include Attachie, Dawson,Parkland (including parts of Tower), and Sunrise, and as such, natural gas, condensate, and natural gas liquids (“NGLs”) are disclosed. ARC’s core producing properties that are considered to be tight oil include Ante Creek and parts of Tower,and as such, crude oil, natural gas, and NGLs are disclosed. ARC’s core producing property that is considered to be light crude oil is Pembina, and as such, crude oil, natural gas, and NGLs are disclosed.

Throughout this presentation, when condensate is disclosed, it is done so as it is the product type that is measured at the first point of sale. As per the Canadian Oil and Gas Evaluation (“COGE”) Handbook, condensate is a by-product of theNGLs product type. NGLs by-products include ethane, butane, propane, and pentanes-plus (condensate).

Non-GAAP MeasuresThroughout this presentation, ARC uses the terms free funds flow, netback, and return on average capital employed (“ROACE”) to analyze the Company’s financial and operational performance. These non-GAAP measures do not have anystandardized meaning prescribed under International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures presented by other issuers.

Free Funds Flow

ARC uses free funds flow as a measure of the efficiency and liquidity of ARC’s business, measuring its funds available for capital investment to manage debt levels, pay dividends, and return capital to shareholders. ARC computes free fundsflow as funds from operations generated during the period less capital expenditures before undeveloped land purchases and property acquisitions and dispositions. By removing the impact of current period capital expenditures from funds fromoperations, Management believes this measure provides an indication to investors and shareholders of the funds ARC has available for future capital allocation decisions.

Netback

ARC calculates netback on a total and per boe basis as commodity sales from production less royalties, operating, and transportation expense. ARC discloses netback both before and after the effect of realized gain or loss on risk managementcontracts. Realized gain or loss represent the portion of risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent measures that reflect how ARC’srisk management program can impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that is commonly used by other oil and gasproducers. The measurement on a per boe basis assists Management with evaluating operational performance on a comparable basis.

Return on Average Capital Employed

ARC calculates ROACE, expressed as a percentage, as net income (loss) plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months preceding period end.Capital employed is the total of net debt plus shareholders’ equity. ROACE since inception is the annual average net income (loss) plus interest and total income tax expense (recovery) for the years 1996 to 2020 divided by the average of theopening and closing capital employed over the same period. Refer to the "Capital Management" note in ARC’s financial statements for additional discussion on net debt. ARC uses ROACE as a measure of long-term operational performance, tomeasure how effectively Management utilizes the capital it has been provided and to demonstrate to shareholders the sustainability of its business model and that capital has been invested profitably over the long term.

8% 9% 6%

77%

10% 8% 6%

76%

Corporate Profile

ARC Is a Leading Canadian Energy Producer in Its 24th Year of Delivering on Its Disciplined, Returns-focused Value Proposition

Asset SnapshotCorporate Summary

(1) Average daily trading volume for the six months ended December 31, 2020.(2) Market capitalization and net debt as at December 31, 2020.(3) Refer to the “Capital Management” note in ARC’s financial statements.(4) Based on net debt as at December 31, 2020 and funds from operations for the year ended December 31, 2020.

2020 Production 2020 Proved + Probable Reserves

Crude oilCondensate and pentanes plusNGLsNatural gas

161,564 boe/day 929 MMboe

ABBC

Crude oilCondensateNGLsNatural gas

Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 2.8 millionShares outstanding 353 millionEnterprise value (2) $2.9 billionNet debt as at December 31, 2020 (3) $742.7 millionNet debt to funds from operations (3)(4) 1.1 timesQuarterly dividend $0.06/shareDividends paid since inception $6.7 billion

ARC holds ~970 net Montney sections (~632,000 acres)

Attachie

GreaterSunrise Area

Ante Creek

GreaterDawson Area

Pembina

02/10/2021 1

A Differentiated Company

ARC Is a Unique Long-term Investment Opportunity

Guiding Principles

Sustainable Business Model

Risk Management around All Aspects of the Business

Superior Capital Discipline and Allocation

Operational Excellence and Top-tier ESG Performance

Owned-and-operated Infrastructure

Sustainable Business Model

Resources

ESG

Profitability

ARC Integrates Its Best-in-class Resources with Its Profitable Business Model and Leading ESG Performance

Sustainability

Best-in-class Resources• Talented people• Montney commodity mix

Profitable Business Model Focused on the Long Term• Profitable growth• Risk management• Balance sheet strength• Managed pace of development• Operational excellence• Low-cost producer with owned-and-operated infrastructure

ESG• Industry-leading performance in environmental and

safety metrics• Strong governance with award-winning transparency

02/10/2021 2

2020 Accomplishments

ARC Strengthened Its Business in 2020 through Prudent Capital Allocation Decisions and Excellent Operational Execution

Excellent Safety Performance Major Facility Brought On-stream Record Annual Production

Strong Reserves Replacement Record Operating Expense Significant Debt Reduction

7 yearswithout a lost-time incident

Excellent safety performance with ARC employees surpassing

Delivered recordannual production of

161,564boe/day

Reduced net debt by

$197.5MM

or 21%$3.94/boethe lowest in ARC’s24-year history

Delivered an operating expense of203%

of 2020 production replaced through development activities

Dawson Phase IVahead of schedule, under budget, and with a perfect safety record

Brought on-stream

2020 Guidance and Results

(1) Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(2) Comprises expense recognized under the Restricted Share Unit and Performance Share Unit Plans, Share Option Plan, and Long-term Restricted Share Award Plan, and excludes compensation expense under the Deferred Share Unit Plan.

In periods where substantial share price fluctuation occurs, G&A expense is subject to greater volatility.(3) Excludes accretion of the asset retirement obligation.

2020 OriginalGuidance

2020 Revised Guidance

(March 2020)

2020 Revised Guidance

(November 2020)2020

Actual

Production

Crude oil (bbl/day) 15,000 - 17,000 14,000 - 16,000 15,000 - 16,000 15,726

Condensate (bbl/day) 12,000 - 14,000 11,000 - 13,000 12,000 - 13,000 13,519

Crude oil and condensate (bbl/day) 27,000 - 31,000 25,000 - 29,000 27,000 - 29,000 29,245

Natural gas (MMcf/day) (1) 715 - 725 705 - 710 725 - 730 739.2

NGLs (bbl/day) 8,500 - 9,000 8,000 - 8,500 9,000 - 9,500 9,112

Total production (boe/day) (1) 155,000 - 161,000 150,000 - 155,000 157,000 - 160,000 161,564

Expenses ($/boe)

Operating 4.55 - 4.95 4.55 - 4.95 4.00 - 4.20 3.94

Transportation 3.10 - 3.30 3.10 - 3.30 3.00 - 3.20 2.98

G&A expense before share-based compensation expense 1.00 - 1.20 1.00 - 1.20 1.05 - 1.15 1.12

G&A - share-based compensation expense (2) 0.30 - 0.45 0.30 - 0.45 0.30 - 0.45 0.43

Interest and financing (3) 0.65 - 0.80 0.65 - 0.80 0.65 - 0.75 0.66

Current income tax expense (recovery) as a per cent of funds from operations (2) - 3 (2) - 3 (5) - 0 (4)

Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 500 300 350 343.2

02/10/2021 3

2021 Business Priorities

Protect the Balance Sheet, Support the Dividend, Prioritize Capital Investments That Drive Long-term Value and Profitability

Protect Strong Financial Position and Maintain Flexibility

Demonstrate Capital Disciplineand Profitability of Investments

Deliver Meaningful Returns to Shareholders

Strengthen balance sheet with freefunds flow (1)

Execute capital program of $375 million to $425 million to sustain production at core Montney areas• 80% of program for profitable half-cycle

investments• Two small-scale infrastructure

optimization projects at Sunriseand Parkland/Tower

Generate strong funds from operations to pay dividend, sustain production, and substantially reduce net debt

Reduce net debt to annualized funds from operations to low end of, or possibly below, target range of 1.0 to 1.5x

Declare dividends of $0.24/share

(1) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. Refer to “Non-GAAP Measures” in the Advisory Statements to this presentation.

Capital Allocation Principles and Priorities

ARC’s Portfolio Approach to Capital Allocation Is Focused on Delivering Strong Returns to Shareholders

Dividend$85MM/year

Maintenance Capital

Sources of Cash Dividend Sustaining Capital DiscretionaryOutflows

Funds fromOperations

Inflows

•Debt Reduction•Long-termDevelopmentInvestments

•Share Buybacks•Dividend Increases•M&A

Outflows

Pay sustainable dividend

Focused on:• Protecting strong financial position and

maintaining flexibility• Prioritizing profitability and value over

volumes• Returning capital to shareholders

Manage net debt to funds from operationsratio within 1.0 and 1.5 times

Profitably sustain production through efficient execution and controlled decline rate

Principles Priorities

Com

mitt

edC

apita

lD

iscr

etio

nary

Cap

ital

02/10/2021 4

Historical Capital Allocation and Outlook

ARC Plans to Maximize the Generation of Free Funds Flow(1) in 2021 to Further Strengthen Its Balance Sheetand Evaluate Other Capital Allocation Opportunities

Inflows Outflows

Funds from Operations Net A&D Proceeds Dividend Capital Expenditures

2016 to 2019 Capital Allocation 2020 Capital Allocation 2021 Forecasted Capital Allocation

Inflows OutflowsInflows Outflows


Financial Strength

ARC Has One of the Strongest Balance Sheets in the Sectorand Targets Its Net Debt to Funds from Operations to Be in the Range of 1.0 and 1.5 Times over the Long Term

ARC

ARC

(1) Source: RBC Capital Markets. Consensus estimates as per FactSet on January 28, 2021.

US Benchmarking: 2021E Year-end Net Debt / 2021E Cash Flow (1)

Canadian Benchmarking: 2021E Year-end Net Debt / 2021E Cash Flow (1)

0.6 0.7 1.2 1.2 1.3 1.3 1.4

1.7 1.8 1.9 2.1 2.3 2.5 2.5 2.7 3.0 3.2 3.3

3.7 3.7

4.4 4.8 4.8 Group Average

0.2 0.5 0.7 0.7

1.1 1.3 1.7

2.1 2.1 2.2 2.4 2.5 2.6 2.7 2.7 3.2 3.3 3.5

3.8

4.7 4.8 Group Average

02/10/2021 5

Significant Liquidity

ARC Has Ample Liquidity to Sustain and Grow Its Business

(1) As at December 31, 2020.(2) Assumes Cdn$/US$ exchange rate of 1.2755.(3) Credit Facility includes $40 million working capital facility.(4) Non-cash working capital not included.

Bank Credit Facility• $950 million committed credit facility plus

$40 million• $72.6 million drawn at December 31, 2020•• Credit facility

Long-term Notes & Master Shelf•• Private Placement market• Notes are rated NAIC 2-• Repayments structured to mature over several years to

reduce financing risk

Cash & Existing Credit Capacity

Undrawn Master Shelf

$287.2MM

Cash & Cash Equivalents

$0.4MM

Undrawn Credit Facility

$917.4MM

Drawn Master Shelf

$191.1MM

Long-term Notes$438.2MM

Drawn Credit Facility$72.6MM

$1.9 Billion Total Cash & Existing Credit Capacity($1.2 Billion Available) (1)(2)(3)(4)

Production and Capital Expenditures

ARC Has Moved Towards an Expanded Production Base with Lower Capital Expenditures

Production (Mboe/day)

Capital Expenditures ($ millions)

123133

139

162 158 to 165

2017 2018 2019 2020 2021F Production Base

830

679 692

343375 to 425

2017 2018 2019 2020 2021F Capital Expenditures

02/10/2021 6

Long-term Corporate Profitability

ARC Has Delivered a ~9% ROACE since Inception


Return on Average Capital Employed (%) (1) Delivering Full-cycle Asset Level Returns

Single-well Economics(Half-cycle)

Proportional Facility and Appropriate

Timing Included:Project

Economics(Full-cycle)

Corporate Costs

TargetDouble-digit

Return on AverageCapital Employed

Afte

r-ta

x R

ate

of R

etur

n

(30)

(15)

0

15

30

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

ROACE Trailing Three-year ROACE

2021 Guidance

$375 millionto $425 million

Invest

Allowing ARC to:

with low operating expense of $4.00/boe – $4.50/boe

Generate Meaningful Funds from Operations to Fully FundDividend and Capital Program and Strengthen Balance Sheet

to profitably sustain production in core areas and complete small-scale facility optimization projects at Sunrise and Parkland/Tower

While ensuring the safe and responsibleexecution of the capital program

750 – 775 MMcf/dayof natural gas production (1)

to produce158,000 – 165,000boe/day (1)

and drill

69 gross operated wells

32,500 – 36,500 bbl/dayof crude oil and liquids production

(1) Does not incorporate the potential impact that third-party transportation restrictions may have on ARC’s natural gas production.(2) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. Refer to “Non-GAAP Measures” in the Advisory Statements to this presentation

2021 Budget Is Focused on Maximizing Generation of Free Funds Flow(2), Capital Discipline, Profitability, and Financial Strength

Advance Strong ESG Performance

02/10/2021 7

2021 Guidance

(1) Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(2) Comprises expense recognized under the Restricted Share Unit and Performance Share Unit Plans, Share Option Plan, and Long-term Restricted Share Award Plan, and excludes compensation expense under the Deferred Share Unit Plan.

In periods where substantial share price fluctuation occurs, G&A expense is subject to greater volatility.(3) Excludes accretion of the asset retirement obligation.(4) Ongoing weakness in commodity prices resulting from COVID-19 impacts on demand and market volatility may impact ARC’s future financial and operational results. ARC will continuously monitor its guidance and provide updates as deemed

appropriate.

2021Guidance (4)

Production

Crude oil (bbl/day) 12,000 - 13,500

Condensate (bbl/day) 11,000 - 12,500

Crude oil and condensate (bbl/day) 23,000 - 26,000

Natural gas (MMcf/day) (1) 750 - 775

NGLs (bbl/day) 9,500 - 10,500

Total production (boe/day) (1) 158,000 - 165,000

Expenses ($/boe)

Operating 4.00 - 4.50

Transportation 3.00 - 3.50

G&A expense before share-based compensation expense 1.00 - 1.25

G&A - share-based compensation expense (2) 0.30 - 0.45

Interest and financing (3) 0.45 - 0.55

Current income tax expense (recovery) as a per cent of funds from operations 3 - 7

Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 375 - 425

2021 Budget of $375 Million to $425 Million

80% of 2021 Budget Will Be Directed towards Profitable Half-cycle Investments in ARC’s Core Montney Areas

BC

Ante Creek$58MM • 16 wells~17,000 boe/day

Deliver profitable light oil production by leveraging2020 facility expansion

Pembina$6MM

~6,500 boe/dayPreserve light oil production

as liquids prices recover

Parkland/Tower$70MM • 12 wells~30,000 boe/day

Complete facility optimization and sour conversion to

enhance deliverability and profitability of the asset

Dawson$168MM • 32 wells~62,500 boe/day

Maximize throughput to capitalize on anticipated

strength in natural gas pricing

Note: Well counts denote wells drilled in calendar year; number of wells with completion activities in calendar year may vary.

Sunrise$77MM • 9 wells~40,000 boe/day

Expand existing facility by 40 MMcf/day and maximize throughput to capitalize on

anticipated strength in natural gas pricing

Attachie

SeptimusTower

Parkland

Sunrise

Sundown

Dawson

Pouce Coupe

Ante Creek

Pembina

Attachie$6MM

~3,500 boe/dayComplete detailed

engineering work for development

AB

02/10/2021 8

Approach to ESG

ARC’s Guiding Principles for ESG Help Inform Comprehensive Strategies and Leading Performance

+ Ensure appropriate focus and oversight on ESG strategies and practices

+ Continually improve governance structure and processes

+ Ensure strong link between executive compensation and performance, including incorporating ESG metrics into determination of compensation levels

+ Be an industry leader in health, safety, and environmental practices and performance

+ Form strong relationships with Indigenous communities

+ Create shared value for society

+ Develop a diverse and inclusive workforce

Environmental Social GovernanceEnviro GoverSocial+ Provide low-carbon energy for

the future

+ Protect ARC’s water resources –“Secure, Reduce, Recycle”

+ Restore land

0

125

250

375

500

0

25

50

75

100

Res

erve

s (B

boe)

Aver

age

ESG

Sco

re

Average ESG Score (LHS) Reserves (RHS)

ESG Excellence

Canadian Energy Sector Is Regulated by Some of the Highest Standards and Is a Clean, Ethical Energy SourceARC Ranks among the Best in the World on ESG Performance

(1) Source: BMO Capital Markets; Yale Environmental Performance Index (EPI); Social Progress Imperative; Worldbank Worldwide Governance Indicators, BMO Capital Markets; Bloomberg; CSRHub. For presentation, an equal weight (1/3) of each index is represented.

(2) Source: BP “Statistical Review of World Energy” (2020). Reserves as at December 31, 2019.

ESG Ratings by Major Oil-producing Country (1)(2) Oil and Gas Companies’ Relative ESG Rankings (1)

ARC

40

46

52

58

64

70

40 46 52 58 64 70

Soci

al a

nd G

over

nanc

e Sc

ore

Environmental Score

Africa

Asia

Canada

Europe

Middle East

Latin America

Russia

United States

02/10/2021 9

0.00

0.01

0.02

0.03

0.04

0

300

600

900

1,200

2015 2016 2017 2018 2019 2025Target

GH

G E

mis

sion

s In

tens

ity (t

CO

2e/b

oe)

GH

G E

mis

sion

s (tC

O2e

)Direct Emissions (LHS) Indirect Emissions (LHS) GHG Emissions Intensity (RHS)

Emissions Management Strategy and Performance

ARC Delivered a 47 Per Cent Reduction in Its GHG Emissions Intensity in 2019 Compared to Its 2017 BaselineA New Target Has Been Set to Reduce GHG Emissions Intensity by an Additional 20 Per Cent by 2025

GHG Emissions Performance (Scope 1 and 2)

2019 GHG Emissions Intensity Benchmarking (1)

(1) Performance data for 2019 GHG emissions intensities comes from 2019 CDP submissions and other publicly available data sources. Peer group includes: BNP, BTE, CNQ, CPG, CVE, ERF, MEG, NVA, OVV, PEY, SU, TOU, VET, VII, WCP.

Emissions Management Strategy

Proactively focus on reducing GHG intensity

Set GHG emissions intensity reduction target

Incorporate emissions management solutions into project planning

0.00

0.03

0.06

0.09

0.12

ARC

201

9

ARC

201

8

tCO

2e/b

oe

20% reduction target relative to

2019 baseline

Water Management Strategy and Performance

ARC’s Water Management Strategy Is Centred around Responsibility, Sustainability, and Profitability

Water Storage Reservoirs

Dawson

ParklandSunrise

Ante Creek

Water Management Strategy

Responsibly manage water use in operations

Evaluate technologies and procedures to implement best practices

Water strategy is key in long-term planning

• $55 million of water infrastructure investments in ARC’sMontney operations since 2017 to add 700,000 m3 of water storage capacity

• Nearly 90 per cent of water used in ARC’s operations is recycled

Water Management Strategy in Action

02/10/2021 10

Social and Governance Performance

The Energy That ARC Creates Provides People with the Opportunity to Live Better Lives

Safety People & Diversity Indigenous Relations

7 yearswithout an employeelost-time injury incident

66%decrease in contractor recordable injuriessince 2014

26%of leadership roles areheld by women

Target to achieve

30%female representation on Board of Directors within three years

Financial support tocommunity pow wows,culture camps, treatydays, and other initiatives

Proactive engagement with neighbouring Indigenous communities, ensuring Indigenous partners have access to employment and share in the benefits

World-class Montney Resource

ARC Has Identified 4,500 Future Drilling Locations across Its Montney Assets

Montney Optionality

• Geographic Optionality• Egress Optionality• Commodity Optionality• Multi-layer Optionality

ABBC

Oil & Liquids

Dry Gas

Condensate-rich Gas

(1) Subject to change based on technology and economic environment.(2) Dry Gas defined as wells expected to produce less than 20 barrels of NGLs for every MMcf of natural gas.

Significant Montney Inventory (1)(2)

Dry Gas Inventory

Liquids-rich Inventory

0

1,600

3,200

4,800

6,400

Well Drilled to YE 2020 2P Booked Locations Internal Inventory Estimate

Num

ber o

f Loc

atio

ns

02/10/2021 11

Multiple Layers to Develop

Up to 1,000 Feet Thick, ARC’s Montney Assets Have Significant Future Delineation Opportunities

Attachie Septimus Sunrise Tower Parkland Dawson Pouce Coupe

MontneyA

Montney B

Montney C

Montney D

Montney E

Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells

Upp

er M

ontn

eyLo

wer

Mon

tney

Owned-and-operated InfrastructureARC’s strong planning and execution capabilities have delivered three major facilities since 2017, all completed ahead of schedule, under budget, and with excellent safety records2017 to 2020: Dawson Phase III – Sunrise Phase II – Dawson Phase IV – Ante Creek 10-36 Expansion2021: Infrastructure optimization projects at Sunrise Phase I & II and Parkland/Tower Phase I

Owned-and-operated Infrastructure Affords ARC Greater Control over Its Cost Structure and Liquids Recoveries

Dawson Phase III & IV

Dawson Phase I & II

Parkland/Tower Phase I

Sunrise Phase I & II

NE BC

ABAnte Creek 10-36

Ante Creek 10-7

Ante Creek 2-26

Corporate Sales Capacity:• >800 MMcf/day of Natural Gas Capacity

Over 90% Owned and Operated

• >50 Mbbl/day of Liquids Capacity

02/10/2021 12

Attachie 2-27 Pad Phase I Attachie 2-27 Pad Phase II

$/m

etre

Best-in-class Operational Performance

Drilling and Completions Efficiency Improvements Are an Example of ARC’s Commitment to Continuous Improvement

20%improvement in total capital cost per lateral length relative to 2019

18%improvement in completions execution efficiency relative to 2019

7%year-over-year improvement indrilling days per well

Estimated total of

$35MMsavings through continuous improvement and procurement initiatives in 2020

Capital Cost per Lateral Length Drilling Execution Efficiency Drilling Days per Well

Completions Execution Efficiency Normalized Well Cost Total Savings

2019 2020

Met

ers

Dril

led

per D

ay

~5%Improvement

31%Reduction

0.00

10.00

20.00

30.00

40.00

Ante CreekUpper Montney

TowerUpper Montney

Attachie WestUpper Montney

Top-tier Montney Economics

Low Cost Structure Supports Strong Economics in Stable Pricing Environment

Montney Natural Gas Break-evens (Cdn$/Mcf) (1) Montney Liquids Break-evens (US$/bbl) (1)(2)

(1) Break-even prices are Cdn$ per Mcf or US$ per barrel as indicated. Break-even analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero. Montney natural gas break-evens run with WTI oil held constant at US$45 per barrel and Montney liquids break-evens run with AECO natural gas held constant at Cdn$2.20 per GJ.

(2) Tower Upper Montney break-even denotes the midpoint of a range of outcomes depending on the liquids ratio.

2020 Average Realized Natural Gas Priceincluding Gain on Risk Management Contracts: $2.30/Mcf

2020 Average Realized Condensate Price: $36/bbl

2020 Average Realized Crude Oil Price: $32/bbl

0.00

0.60

1.20

1.80

2.40

Parkland-DawsonLower Montney

DawsonUpper Montney

SunriseUpper Montney

SunriseUpper Montney

DawsonUpper Montney

Parkland-DawsonLower Montney

Ante CreekMiddle Montney

TowerUpper Montney

Attachie WestUpper Montney

2020 Average Realized Natural Gas Price: $2.26/Mcf

02/10/2021 13

0

4

8

12

16

0

8

16

24

32

(1) Source: Peters & Co. 2019 E&P Reserves Comparative (April 7, 2020).(2) Refer to ARC’s Annual Information Form for information pertaining to ARC’s finding and development costs.(3) Three-year PDP FD&A Costs peer group includes: BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(4) Source: Company reports. 2020 YTD Operating Expense represents data for the nine months ended September 30, 2020. Peer group includes: BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(5) Source: Peters & Co. Limited E&P Overview Tables (January 25, 2021). Peer group includes APA, AR, COG, DVN, EOG, FANG, OVV, PEY, PXD, TOU, VII.

Cost Management and Decline Rate

Low-cost Producers with a Low Decline Rate Deliver Superior Returns over Time

Group Average

ARC

Group Average

Three-year PDP FD&A Costs ($/boe) (1)(2)(3) 2020 YTD Operating Expense ($/boe) (4) 2021E Corporate Decline Rates (%) (5)

ARC

Canadian ProducersUS Producers

ARC

Daw

son

ARC

ARC

Sun

rise

Gas

ARC

NE

BC

Oil

& G

as

Group Average

0

10

20

30

40

2.45 2.94

1.72 2.36

(0.09) (0.06)

0.40

(0.10)

0.18

(0.06)

0.44 0.04

2.54 2.82

2.56 2.30

(0.50)

0.50

1.50

2.50

3.50

Q4 2019 Q4 2020 2019 2020

Cdn

$/M

cf

Natural Gas Financial and Physical Price Management

ARC Is Increasing Its Exposure to Local Pricing Given Structural Improvements to WCSB

ARC’s Natural Gas Price and Diversification (2)(3)(4)WCSB Demand & Export Capacity Growth (1)WCSB Demand & Export Capacity Growth (1)

NGTL East Gate Capacity+1.3 Bcf/day by 2022

Intra-Alberta Demand+1.5 Bcf/day by 2025

LNG Canada Phase 1+2.1 Bcf/day by 2025

Enbridge T-South Capacity+0.2 Bcf/day by 2021

NGTL West Gate Capacity+0.3 Bcf/day by 2023

5.4 Bcf/day Demand & Export CapacityGrowth Expected by 2025

(1) Source: ARC Risk Research, TC Energy, Enbridge, company reports.(2) Realized gain (loss) on risk management contracts is not included in ARC’s realized natural gas price.(3) Based on internal production assumptions and adjusted for ARC’s heat content.(4) “Hedged” includes all physical and financial fixed price swaps and collars.

Diversification Activities

Realized Gain (Loss) onRisk Management Contracts

Average Price before Diversification Activities

Dawn Floating

Malin Floating

Henry Hub Floating

Midwest US Floating

AECO Floating

Station 2 Floating

Hedged36%23%

11% 12%

17%25%

34% 37%

13%13% 15% 15%

17% 19% 14% 14%

6% 9% 15% 7%6% 6% 6% 10%5% 5% 5% 5%

2021 2022 2023 20240%

25%

50%

75%

100%

% o

f Tot

al P

rodu

ctio

n

02/10/2021 14

Financial Price Management

Hedging Program Mitigates Volatility in Funds from Operations and Provides Certainty of Cash Flows

Crude Oil & Condensate Production Hedged (bbl/day) Natural Gas Production Hedged (MMBtu/day)

~50% of Crude Oil & CondensateHedged for 2021

~40% of Natural GasHedged for 2021

0

4,000

8,000

12,000

16,000

H1 2021 H2 20210

90,000

180,000

270,000

360,000

H1 2021 H2 2021

Resource Potential and Scalability

ARC has:

• ~970 net Montney sections (~632,000 acres)

• 4,500 future drilling locations identified across the Montney

• Commodity, geographic, and multi-layer optionality

Scalability Allows for Profitable Growth to Generate Sustainable Funds from Operations and Maintain Financial Strength

2017

Base Production (Montney & Cardium)

• Dawson Phase III• Sunrise Phase II

Future Development Projects

~123 Mboe/day

• Dawson Phase IV• Ante Creek Expansion

Attachie

GreaterSunrise Area

Ante Creek

GreaterDawson Area

~162 Mboe/day

02/10/2021 15

2010 2011 2013 2015 2017 2019 Q2 2020 Q4 2021

Greater Dawson Area Overview

Large Integrated Network of Owned-and-operated Infrastructure

Snapshot Development Plan

2021 Development Focus

Infrastructure Build-out

DawsonPhase I

DawsonPhase II

Parkland/Tower

Phase I

Parkland/Tower Battery

Upgrade

Dawson Phase I & II

UpgradeDawsonPhase III

Dawson Phase IV

Montney Crude Oil & Liquids Processing Capacity

Montney Natural Gas Processing Capacity

• Maximize throughput to capitalize on strength in natural gas pricing• Improve Parkland/Tower’s deliverability and profitability with facility optimization

and sour conversion project

Tower

Parkland

Dawson

Pembina & EnbridgeTCPLParkland-Dawson Interconnect Pipeline

Phase I & IIGas Plants

Phase III & IVGas Plants


(1) Denotes corporate total for capital budget, planned wells, and expected production for 2021.

Capital Budget Expected ProductionPlanned Wells

$375 million to $425 million (1) 69 wells (1) 158 to 165 Mboe/day (1)

$238 million(58%)

44 wells(64%)

~92.5 Mboe/day(57%)

Parkland/Tower

Optimization

Dawson Lower Montney Development

Cumulative Natural Gas Production (MMcf) (1) Estimated Ultimate Recovery (Mboe) Capital Efficiency ($/boe/day)

Cumulative Condensate Production (Mbbl) (1) Well Costs ($ millions) Finding and Development Costs ($/boe)

Optimized Pad and Well Designs Have Resulted in Improved Capital Efficiency and F&D Costs

(1) Average production per pad.

0

500

1,000

1,500

2,000

2017 2018 2019 20200

3,000

6,000

9,000

12,000

2017 2018 2019 2020

0.0

1.5

3.0

4.5

6.0

2017 2018 2019 20200

2

4

6

8

2017 2018 2019 2020

0

600

1,200

1,800

2,400

0 6 12 18 24Months on Production

2017201820192020

0

15

30

45

60

0 6 12 18 24Months on Production

2017201820192020

02/10/2021 16

Dawson Upper Montney Development (1)

Cumulative Natural Gas Production(Bcf) (2) Estimated Ultimate Recovery (Mboe) Capital Efficiency ($/boe/day)

Cumulative Condensate Production (Mbbl) (2) Well Costs ($ millions) Finding and Development Costs ($/boe)

Optimized Pad and Well Designs Have Resulted in Improved Capital Efficiency and F&D Costs

0

375

750

1,125

1,500

2017 2018 2019

0.0

1.5

3.0

4.5

6.0

2017 2018 2019

0

2,500

5,000

7,500

10,000

2017 2018 2019

0

2

4

6

8

2017 2018 2019

0

750

1,500

2,250

3,000

0 6 12 18 24 30 36Months on Production

201720182019

0

10

20

30

40

0 6 12 18 24 30 36Months on Production

201720182019

(1) 2020 wells brought on production in December 2020; charts will be updated once sufficient production data is available.(2) Average production per well.

2015 2018 2019 Q4 2021

Sunrise Overview

Low-cost Natural Gas Development with Excellent Deliverability

Snapshot

SunrisePhase I


SunrisePhase II

SunrisePhase II

Development Plan



• Complete infrastructure optimization project to add 40 MMcf/day of processing and sales capacity

• Maximize throughput to capitalize on strength in natural gas pricing




$77 million(19%)

9 wells(13%)

~40 Mboe/day(25%)

SunrisePhase I & IIExpansion


02/10/2021 17

Existing Infrastructure 2012 Q2 2020

Ante Creek Overview

Low-risk Montney Light Oil Development

Snapshot

Ante CreekPhase I

Ante CreekExpansion

Development Plan



• Deliver profitable light oil production by leveraging 2020 facility expansion






$58 million(14%)

16 wells(23%)

~17 Mboe/day(11%)

2-26Gas Plant

10-7Gas Plant

10-36Gas Plant

Existing Infrastructure

Attachie Overview

Most Recent Development Activities Have Improved Area’s Capital Efficiencies

Snapshot

Attachie West Phase I

Development Plan



• Complete detailed engineering work for development• Will recommence drilling activities once development is undertaken to ensure the

most efficient and profitable execution possible

Phase IGas Plant



4-20Battery

(3.5 Mbbl/day)

Phase IGas Plant

COP Acreage Acquired from KEL (1)

(1) ConocoPhillips acquired Kelt’s acreage in Q3 2020.

PembinaNorth Montney Mainline

ARC AcreageCOP Acreage

(1) .(2) Denotes corporate total for capital budget, planned wells, and expected production for 2021.



$6 million(1%)

0 wells(0%)

~3.5 Mboe/day(2%)

02/10/2021 18

Continuous Improvement in Pad and Well Design

Well Results from 2-27 Pad Phase I Have Validated Pad and Well Design Changes

Pad and Well Design Evolution Cumulative Oil & Condensate Production (Mbbl)

(1) Facility constraints relieved in Q2 2020; three of four wells on 2-27 Pad Phase I produced consistently prior to this. Over 322 days of production, the four wells have produced approximately 525,000 barrels of condensate and approximately 1,800 MMcf of natural gas.

20192-27 Pad Phase II

200 metre Spacing45 m

400 m 400 m

400 m 400 m

45 m

300 m 300 m 300 m

300 m 300 m2018

13-14 Pad150 metre Spacing

20192-27 Pad Phase I

300 metre Spacing45 m

600 m

600 m

2017B13-26 Well

Unconstrained

201613-26 Well

Unconstrained

16-16 Well13-26 WellB13-26 Well13-14 Pad Average2-27 Pad Phase I Average (1)

2-27 Pad Phase II AverageAttachie Type Curve

0

75

150

225

300

0 300 600 900 1,200 1,500Days on Production

Advancing Attachie towards Commercialization

ARC Is Progressing the Technical, Commercial, and Funding Aspects of Attachie West Phase I

Technical Commercial Funding

Strong liquids deliverability

Improved capital efficiencies

Competitor activity

Commodity egress

Regulatory

Support infrastructure

Balance sheet

Maximize profitability

Project readiness

02/10/2021 19

73%

2%4%21%

Pembina Overview

High Working Interest Light Oil Production

Snapshot Development Plan


• Preserve light oil production as liquids prices recover

2020 Production Split

8.9 Mboe/day

Berrymoor

LindaleNPCU

MIPABuckCreek

SPCU

Blue boundaries denote units.

Crude oilCondensateNGLsNatural gas




$6 million(1%)

0 wells(0%)

~6.5 Mboe/day(4%)

Additional Information

02/10/2021 20

Asset Details

Diversified Commodity Mix across Asset Portfolio Provides Optionality

(1) Denote Montney or Cardium sections only.(2) Reserve life index based on 2021 guided production.

Dawson Sunrise Parkland/Tower Ante Creek Attachie Pembina

Net production – Q4 2020Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)

8,121322.3

61,834

36234.4

39,098

11,359142.9

35,181

9,78950.9

18,274

3,13213.5

5,386

6,24310.4

7,976

LandNet sections (1)

Working interest137

~100%36

~93%94

~90% / ~94%197

~100%308

~99%206

~88%

PDP Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)

9413.3485

4

66-

3944

4513.2194

4

2211.1

674

73.3205

3126.0

2912

2P Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)

32252.2

1,61814

2350.1

1,40716

15851.164114

7939.124213

3619.210227

5545.7

5822

Business Overview

ARC Manages a Profitable Business through All Commodity Price Cycleswith Its Efficient Montney Production Base and Strong Balance Sheet

Production Net Debt to Funds from Operations Dividends (1)

(1) Dividends as a per cent of funds from operations calculated as dividends before Dividend Reinvestment Plan and Stock Dividend Program.

0%

30%

60%

90%

120%

0

2

4

6

8

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Div

iden

ds a

s a

% o

f Fun

ds fr

om O

pera

tions

Cum

ulat

ive

Div

iden

ds ($

bill

ions

)

Cumulative Dividend (LHS)

Dividends as a % of Funds from Operations (RHS)

0.0

0.5

1.0

1.5

2.0

2.5

0

400

800

1,200

1,600

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

Rat

io

$ m

illio

ns

Net Debt (LHS)

Funds From Operations (LHS)

Net Debt to Funds from Operations (RHS)

0

45,000

90,000

135,000

180,000

199

6 1

997

199

8 1

999

200

0 2

001

200

2 2

003

200

4 2

005

200

6 2

007

200

8 2

009

201

0 2

011

201

2 2

013

201

4 2

015

201

6 2

017

201

8 2

019

202

0

boe/

day

Montney Natural Gas (boe/day)

Non-Montney Natural Gas (boe/day)

Montney Crude Oil & Liquids (bbl/day)

Non-Montney Crude Oil & Liquids (bbl/day)

02/10/2021 21

Note Repayment Schedule

Long-term Note Repayments Structured to Mature over Several Years to Reduce Financing Risk

Long-term Notes Principal Repayment Schedule (Cdn$ millions) (1)

(1) Assumes Cdn$/US$ exchange rate of 1.2755 at December 31, 2020.

0

50

100

150

200

2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

3.72% US$ Note8.21% US$ Note5.36% US$ Note3.31% US$ Note3.81% US$ Note4.49% Cdn$ Note

Risk Management Program

Program Executed with a Long-term View

(1) 2021 to 2025 Forecast values reflect the forward strip pricing curve as at December 31, 2020 (net of credit adjustment).(2) Refer to the “Financial Instruments and Market Risk Management” note in ARC’s financial statements and the section entitled “Risk Management” contained within ARC’s MD&A.

Realized Gain (Loss) on Risk Management Contracts ($ millions) (1)(2)

(100)

0

100

200

300

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021F 2022F 2023F 2024F 2025F

Crude Oil

Natural Gas

Foreign Exchange & Power

Total

02/10/2021 22

Risk Management Contracts PositionsRisk Management Contracts Positions (1)

December 31, 2020 2021 2022 2023 2024 2025Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling 55.46 9,992 51.96 2,000 - - - - - -Floor 48.33 9,992 45.00 2,000 - - - - - -Sold Floor 39.65 8,992 35.00 2,000 - - - - - -Swap 41.22 1,992 - - - - - - - -Sold Swaption (2) 43.00 1,008 - - - - - - - -Total Crude Oil Volumes (bbl/day) 11,984 2,000 - - -Crude Oil – MSW (Differential to WTI) (3) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/daySwap (6.11) 5,000 - - - - - - - -Natural Gas – NYMEX Henry Hub (4) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 3.10 125,466 3.15 65,000 2.74 10,000 2.74 10,000 - -Floor 2.58 125,466 2.59 65,000 2.50 10,000 2.50 10,000 - -Sold Floor 2.08 107,877 2.19 65,000 2.10 10,000 2.10 10,000 - -Sold Calls 4.00 7,397 - - - - - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 2.41 120,000 2.50 120,000 2.40 90,000 2.40 90,000 2.73 20,000Floor 1.95 120,000 1.93 120,000 1.87 90,000 1.87 90,000 2.00 20,000Sold Floor - - 1.75 10,000 - - - - - -Swap 2.28 67,397 2.23 20,000 2.06 10,000 2.06 10,000 - -Sold Swaption (2) - - 2.00 20,000 - - - - - -Natural Gas – Chicago US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 4.10 4,932 - - - - - - - -Floor 2.75 4,932 - - - - - - - -Total Natural Gas Volumes (MMBtu/day) 308,016 197,694 104,782 104,782 18,956Natural Gas – AECO Basis (Differential to NYMEX Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/daySold Swap (0.93) 66,260 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000 (0.66) 5,000Total AECO Basis Volumes (MMBtu/day) 66,260 35,000 70,000 70,000 5,000Natural Gas – Other Basis (Differential to NYMEX Henry Hub) (5) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 110,000 110,000 80,000 4,973 -Foreign Exchange Contract Settlement Date Notional Amount ($ millions) Ceiling (Cdn$/US$) Floor (Cdn$/US$)Variable Rate Collar (6) August 23, 2021 8 1.2586 1.3050

(1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of optionsis purely for indicative purposes. All positions are financially settled against the benchmark prices.

(2) The sold swaption allows the counterparty, at a specific future date, to enter into a swap with ARC at the above-detailed terms. These volumes are not included in the total commodity volumes until such time that the option is exercised.(3) MSW differential refers to the discount between WTI and the mixed sweet crude oil grade at Edmonton, calculated on a monthly weighted average basis in US dollars.(4) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.(5) ARC has entered into basis swaps at locations other than AECO.(6) Variable rate collar whereby if the Cdn$/US$ spot rate is below 1.2586 at expiry, the ceiling will re-adjust to 1.2863.

Produced Reserves Replacement

• Finding and development costs of $2.34/boe for 2P reserves and $2.60/boe for TP reserves (2)

203 Per Cent of Produced Reserves Replaced150 Per Cent Reserves Replacement or Greater for 13th Consecutive Year

Growth through Acquisition Organic Growth

(1) 1997 to 2002 reserves data is based on company interest established reserves (proved plus 50 per cent of probable reserves). 2003 to 2020 reserves data is based on gross interest proved plus probable reserves.(2) Includes future development capital.

Annual Produced Reserves Replacement (MMboe) (1)

(50)

0

50

100

150

1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Reserves Replacement - Development Reserves Replacement - Net Acquisitions & Dispositions Reserves Replacement - Total Production

02/10/2021 23

8% 9% 6%

77%

929 MMboe

Key Reserves Information (1)

Year-end 2020 Reserves Added 120 MMboe of 2P Reserves through Development Activities

Key Reserve Data 2020 Proved + Probable Reserves

Crude oilCondensate and pentanes plusNGLsNatural gas

Probable35%

PDP29%

PNP2%

PUD34%

0

250

500

750

1,000

2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

2P R

eser

ves

(MM

boe)

Crude oil and liquids Natural gas

Proved ProducingCrude and Tight OilNGLsNatural Gas

268 MMboe35 MMbbl32 MMbbl

1.2 Tcf

Total ProvedCrude and Tight OilNGLsNatural Gas

603 MMboe52 MMbbl84 MMbbl

2.8 Tcf

Proved plus ProbableCrude and Tight OilNGLsNatural Gas

929 MMboe75 MMbbl

138 MMbbl4.3 Tcf

PDP Reserve Life Index (2)

1P Reserve Life Index (2)

2P Reserve Life Index (2)

4.5 years10.2 years15.8 years

(1) Reserves data effective December 31, 2020. TPIIP resources dataeffective December 31, 2018.

(2) Based on 2021 production guidance midpoint of 161,500 boe per day.(3) Independent Resources Evaluation conducted by GLJ effective December

31, 2018. For resources disclosure, refer to the February 7, 2019 newsrelease entitled “ARC Resources Ltd. Announced 118 MMboe of TotalProved Plus Probable Reserve Additions in 2018, Replacing 245 Per Centof Production, and Delivers Record Proved Producing Reserve Additions of82 MMboe”.

TPIIP (1)(3)

Tight OilShale Gas

14.3 Billion Barrels101.8 Tcf

Montney Development Economics

Half-cycle Economics (1)(2)(3)

US$45/bbl WTICdn$2.20/GJ AECO

Sunrise

Upper Montney

Dawson

Upper Montney

Parkland

Upper Montney

Dawson-Parkland

Lower Montney

Tower

Upper Montney

Ante Creek

Middle Montney

IRR 110% 155% 105%100% to 125% (dependent on liquids ratio)

65% to 95%(dependent on area)

100%

Recycle Ratio 7.2x 7.4x 4.8x 4.2 to 5.7x 5.0 to 6.2x 3.9x

Break-even Cdn$0.95/Mcf Cdn$0.36/Mcf Cdn$0.39/Mcf Cdn$0.26/Mcf US$13 to $19/bbl US$20/bbl

Production Split6 Mcf : 1 bbl (4)

20 Mcf : 1 bbl (5)

Liquids / Natural Gas1% / 99%1% / 99%



Liquids / Natural Gas17-36% / 64-83%

40-65% / 35-60%(dependent onliquids ratio)

Liquids / Natural Gas34-43% / 66-57%63-72% / 37-28%


(1) IRR (half-cycle after-tax rate of return) run at US$45/bbl WTI and Cdn$2.20/GJ AECO flat pricing.(2) Break-even prices are US$ per barrel WTI or Cdn$ per Mcf AECO as indicated. Breakeven analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero.(3) Recycle ratio is calculated using first 12 months of undiscounted netback divided by F&D.(4) Utilizes the standard 6 Mcf:1 bbl ratio when converting natural gas to boe.(5) Utilizes a 20 Mcf:1 bbl ratio when converting natural gas to boe.

02/10/2021 24

Sunrise – Type Curve

Key Metrics 2021 Type Curve(Average of 3 Layers)

DCET Capex/Well ($ millions) $3.4

Internal 2P Reserves (Bcfe) 11.5

IP (1 month) (MMcf/day) 7.0

IP (12 months) (MMcf/day) 6.8

Half-cycle Economics US$45/bbl WTI &Cdn$2.20/GJ AECO

IRR (%, after-tax) 110%

0

2,000

4,000

6,000

8,000

0 6 12 18 24 30 36

Nat

ural

Gas

Pro

duct

ion

Rat

e (M

cf/d

ay)

Months On Production

Type Curve (1)(2)(3)(4) Development Economics

Natural Gas (Mcf/day)

(1) Type curves are internal estimates based on analog wells and reservoir modeling.(2) Assumed cycle time (from spud to on-production): six months.(3) Average lateral length of 2021 Type Curve: 2,000m.(4) Chart data based on raw production and table based on sales.

0

150

300

450

600

Wells Drilled toYE 2020

2P BookedLocations

Internal InventoryEstimate

Wel

ls

Sunrise – Development Potential

Reserves Maps Drilling Inventory

Upper Montney ABooked Reserves

Upper Montney A+Booked Reserves

Upper Montney B Booked Reserves

Lower MontneyBooked Reserves

Upp

er M

ontn

eyLo

wer

Mon

tney

ARC Montney Lands

ARC Montney Lands with 2P Reserves Booked as of YE 2020

Existing Horizontal Wells, Development

Existing Horizontal Wells, Pilot

02/10/2021 25

Dawson Upper Montney – Type Curve

Key Metrics 2021 Type Curve


Internal 2P Reserves (Mboe) 1,820

IP (1 month) (boe/day) 1,415

IP (12 months) (boe/day) 1,315




0

50

100

150

200

0

2,000

4,000

6,000

8,000

0 6 12 18 24 30 36C

onde

nsat

e Pr

oduc

tion

Rat

e (b

bl/d

ay)

Nat

ural

Gas

Pro

duct

ion

(Mcf

/day

)

Months on Production

Natural Gas (Mcf/day)Condensate (bbl/day)

(1) Type curves are internal estimates based on analog wells and reservoir modeling.(2) Assumed cycle time (from spud to on-production): five months.(3) Average lateral length of 2021 Type Curve: 2,900m.(4) Chart data based on raw production and table based on sales.

Dawson-Parkland Lower Montney – Type Curve

Key Metrics

Medium Liquids Ratio

2021Type Curve

HighLiquids Ratio

2021Type Curve

DCET Capex/Well ($ millions) $4.1 $4.9

Internal 2P Reserves (Mboe) 1,380 880

IP (1 month) (boe/day) 1,460 1,165

IP (12 months) (boe/day) 1,075 720


IRR (%, after-tax) 125% 100%


0

400

800

1,200

1,600

0 6 12 18 24 30 36

Prod

uctio

n R

ate

(boe

/day

)


Natural Gas (boe/day)Condensate (bbl/day)

(1) Type curves are internal estimates based on analog wells and reservoir modeling.(2) Assumed cycle time (from spud to on-production): four months for Medium Liquids Ratio and three months for High Liquids Ratio.(3) Average lateral length of 2021 Type Curve: 2,600m for High Liquids Ratio and 2,400m for Medium Liquids Ratio.(4) Chart and table data based on sales production.

02/10/2021 26

0

250

500

750

1,000


2P BookedLocations


Wel

ls

Dawson – Development Potential


Upper Montney ABooked Reserves


Upp

er

Mon

tney

Low

er M

ontn

ey



Potential Horizontal Wells

ARC Montney Lands


pper Montney Aooked Reserves

Parkland Upper Montney – Type Curve



Internal 2P Reserves (Mboe) 925


IP (12 months) (boe/day) 720




0

150

300

450

600

0

1,250

2,500

3,750

5,000

0 6 12 18 24 30 36

Con

dens

ate

& N

GLs

Pro

duct

ion

Rat

e (b

bl/d

ay)

Nat

ural

Gas

Pro

duct

ion

Rat

e (M

cf/d

ay)


Natural Gas (Mcf/day)Condensate (bbl/day)NGLs [C2, C3, C4] (bbl/day)

(1) Type curves are internal estimates based on analog wells and reservoir modeling.(2) Assumed cycle time (from spud to on-production): five months.(3) Average lateral length of 2021 Type Curve: 2,350m.(4) Chart and table data based on sales production.

02/10/2021 27

0

400

800

1,200

1,600

0 6 12 18 24 30 36

Prod

uctio

n R

ate

(boe

/day

)


Tower – Type Curve

Key MetricsCore2021

Type Curve

Transition2021

Type CurveDCET Capex/Well ($ millions) $3.9 $4.5

Internal 2P Reserves (Mboe) 635 1,120

IP (1 month) (boe/day) 1,095 1,415

IP (12 months) (boe/day) 485 540

Half-cycle Economics US$45/bbl WTI &AECO Cdn$2.20/GJ

IRR (%, after-tax) 95% 65%


(1) Type curves are internal estimates based on analog well performance(2) Assumed cycle time (from spud to on-production): five months.(3) Average lateral length of 2021 Type Curve: 2,000m for Core and 2,600m for Transition.(4) Chart and table data based on sales production.

Natural Gas – Core (boe/day)Natural Gas – Transition (boe/day)

Condensate – Core (bbl/day)Condensate – Transition (bbl/day)NGLs [C2, C3, C4] – Core (bbl/day)NGLs [C2, C3, C4] – Transition (bbl/day)

0

250

500

750

1,000


2P BookedLocations


Wel

ls

Parkland/Tower – Development Potential

Upper Montney A+ Booked Reserves


Upper Montney A Booked Reserves


Upp

er M

ontn

eyLo

wer

Mon

tney




ARC Montney Lands


Tower Parkland

s

02/10/2021 28

0

100

200

300

400

500

0

400

800

1,200

1,600

0 6 12 18 24 30 36O

il, C

onde

nsat

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NG

Ls P

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ate

(bbl

/day

)

Nat

ural

Gas

Pro

duct

ion

Rat

e (M

cf/d

ay)


Ante Creek – Type Curve




IP (1 month) (boe/day) 590





(1) Type curves are internal estimates based on analog wells and reservoir modeling.(2) Assumed cycle time (from spud to on-production): four months.(3) Average lateral length of 2021 Type Curve: 2,200m.(4) 2020 Type Curve reflects constraints due to operational execution.

Natural Gas (Mcf/day)Oil (bbl/day)Condensate (bbl/day)NGLs [C2, C3, C4] (bbl/day)

0

200

400

600

800


2P BookedLocations


Wel

ls

Ante Creek – Development Potential


ARC Montney Lands


02/10/2021 29

Attachie West – Type Curve








0

300

600

900

1,200

0

750

1,500

2,250

3,000

0 6 12 18 24 30 36C

onde

nsat

e &

NG

Ls P

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ate

(bbl

/day

)

Nat

ural

Gas

Pro

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ion

Rat

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Type Curve (1)(2)(3)(4)(5) Development Economics

Natural Gas (Mcf/day)Condensate (bbl/day)NGLs [C2, C3, C4] (bbl/day)

(1) Type curves are internal estimates based on analog wells and reservoir modeling.(2) Assumed cycle time (from spud to on-production): six months.(3) Average lateral length of 2021 Type Curve: 2,250m.(4) Designated as Gas Tier 1 (<1900m TVD).(5) Chart data based on raw production and table based on sales.

0

500

1,000

1,500

2,000


2P BookedLocations


Wel

ls

Attachie – Development Potential


Upper Montney A Booked Reserves


Upp

er M

ontn

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wer

Mon

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ARC Montney Lands


r Montneyd Reserves

Montney A d Reserves

02/10/2021 30

ESG Recognitions and Rankings

Member of MSCI Global Sustainability IndexMSCI ESG Rating: AAA

Voluntary participant since 20072020 Climate Change Score: A-2020 Water Security Score: B

Member of Sustainalytics’ Jantzi Social Index

Member of FTSE Russell’s FTSE4Good Index Series since 2018

Member of the 30% Club since 2018

View ARC’s 2020 ESG Report at www.arcresources.com/responsibility

Member of Bloomberg’s Gender-Equality Index since 2021

Reserves and Resources Disclosure

All reserves in this presentation are, unless indicated otherwise, as at December 31, 2020 as evaluated by GLJ Ltd. (“GLJ”) in accordance with the definitions, standards, andprocedures contained in the COGE Handbook and NI 51-101. Resources volumes for the Montney are as at December 31, 2018 as evaluated by GLJ in accordance withthe definitions, standards, and procedures contained in the COGE Handbook and NI 51-101 .

TPIIP, DPIIP, and UPIIP have been estimated using a one per cent porosity cut-off for shale gas and tight oil.Reserves volumes for ARC’s Montney assets and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for the

Montney in this presentation are “Best Estimates”.All reserves and resources volumes for the Montney and elsewhere in this presentation are company gross.Gas volumes are “sales” for reserves and resource and raw gas for DPIIP and TPIIP.The tight oil DPIIP is a stock tank barrel.All DPIIP and TPIIP other than cumulative production, reserves, Contingent Resources, and Prospective Resources have been categorized as unrecoverable.The amount of natural gas and liquids ultimately recovered from ARC’s the Montney resource will be primarily a function of the future price of both commodities.

02/10/2021 31

Definitions of Reserves and Resources

Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a givendate, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which aregenerally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:

Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantitiesrecovered will be greater or less than the sum of the estimated proved plus probable reserves.

Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered andUndiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-in-Place". Resources areclassified in the following categories:

Total Petroleum Initially-in-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantityof petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to bediscovered.Discovered Petroleum Initially-in-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior toproduction. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable.Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using establishedtechnology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable.Project Maturity Subclass Development Not Viable is defined as a Contingent Resource that is not viable in the conditions prevailing at the effective date of theevaluation, and where no further data acquisition or evaluation is planned and therefore has not been assigned a low chance of development.Project Maturity Subclass Development Pending is defined as a Contingent Resource that has been assigned a high chance of development and the resolution of finalconditions for development are being actively pursued.Project Maturity Subclass Development Unclarified is defined as a Contingent Resource that requires further appraisal to clarify the potential for development and hasbeen assigned a lower chance of development until contingencies can be clearly defined.

Definitions of Reserves and Resources

Undiscovered Petroleum Initially-in-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to bediscovered. The recoverable portion of UPIIP is referred to as "prospective resources" and the remainder as "unrecoverable".Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application offuture development projects.Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion ofthese quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never berecovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the bestestimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Ifprobabilistic methods are used, there should be at least a 50 per cent probability that the quantities actually recovered will equal or exceed the best estimate.

02/10/2021 32

Contact Information

Visit ARC’s Website at www.arcresources.com

Kris BibbySenior Vice President and Chief Financial Officer

403.503.8675

[email protected]

Martha WilmotInvestor Relations Analyst

403.509.7280

[email protected]

General Investor Relations Enquiries403.503.8600

1.888.272.4900

[email protected]

02/10/2021 33

Notes

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02/10/2021 34

(1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled "Funds from Operations" and “Capitalization,Financial Resources and Liquidity” contained within ARC’s MD&A.

(2) Dividends per share are based on the number of shares outstanding at each dividend record date.(3) Trading statistics denote trading activity on the Toronto Stock Exchange only.

FINANCIAL ANDOPERATIONAL HIGHLIGHTS

2020 2019($ millions, except per share amounts) Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1FINANCIAL RESULTSCommodity sales from production 363.1 285.0 217.9 269.5 325.1 253.7 282.9 327.8

Per share, basic 1.03 0.81 0.62 0.76 0.92 0.72 0.80 0.93Per share, diluted 1.02 0.81 0.62 0.76 0.92 0.72 0.80 0.93

Net income (loss) 120.8 (66.1) (43.5) (558.4) (10.2) (57.2) 94.4 (54.6)Per share, basic 0.34 (0.19) (0.12) (1.58) (0.03) (0.16) 0.27 (0.15)Per share, diluted 0.34 (0.19) (0.12) (1.58) (0.03) (0.16) 0.27 (0.15)

Funds from operations (1) 212.0 144.6 150.2 160.8 172.8 145.4 193.0 186.2Per share, basic 0.60 0.41 0.42 0.46 0.49 0.41 0.54 0.53Per share, diluted 0.60 0.41 0.42 0.46 0.49 0.41 0.54 0.53

Dividends declared 21.3 21.2 21.3 42.5 53.1 53.1 53.1 53.1Per share (2) 0.06 0.06 0.06 0.12 0.15 0.15 0.15 0.15

Total assets 4,954.2 4,982.9 5,136.8 5,172.6 5,778.3 5,819.2 5,878.9 5,952.4Total liabilities 2,163.6 2,292.7 2,360.3 2,332.4 2,338.4 2,317.1 2,267.7 2,383.6Net debt outstanding (1) 742.7 867.8 961.1 1,079.7 940.2 945.5 829.2 796.3Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4Weighted average shares, diluted 354.3 353.4 353.4 353.4 353.4 353.4 353.9 353.4Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4CAPITAL EXPENDITURESGeological and geophysical 2.5 2.4 3.4 6.5 0.9 1.1 0.3 9.3Drilling and completions 68.1 40.8 31.8 131.3 86.7 101.0 110.1 144.9Plant and facilities 3.1 5.9 8.3 25.8 47.5 51.1 56.2 53.3Maintenance and optimization 1.5 2.1 1.4 4.4 3.0 6.2 5.8 3.4Corporate assets 1.5 1.4 (0.8) 1.8 3.6 2.5 1.8 2.8Total capital expenditures 76.7 52.6 44.1 169.8 141.7 161.9 174.2 213.7Undeveloped land purchases — — — — — 0.7 — —Total capital expenditures, including undeveloped

land purchases 76.7 52.6 44.1 169.8 141.7 162.6 174.2 213.7Acquisitions 61.6 — 0.5 2.5 — — — 0.2Dispositions (63.2) — (0.6) (2.4) (1.1) (2.8) (0.9) (0.2)Total capital expenditures, undeveloped land

purchases, and net acquisitions and dispositions 75.1 52.6 44.0 169.9 140.6 159.8 173.3 213.7OPERATIONAL RESULTSProduction

Crude oil (bbl/day) 15,554 15,373 14,987 16,997 17,083 16,782 18,272 18,251Condensate (bbl/day) 14,715 14,831 13,239 11,262 10,937 10,846 10,230 8,210Crude oil and condensate (bbl/day) 30,269 30,204 28,226 28,259 28,020 27,628 28,502 26,461Natural gas (MMcf/day) 783.1 708.2 773.3 692.2 669.0 595.4 596.4 632.5NGLs (bbl/day) 8,678 10,208 9,405 8,152 8,123 7,952 7,041 7,183Total (boe/day) 169,468 158,444 166,510 151,783 147,650 134,813 134,938 139,054

Average realized prices, prior to risk management contractsCrude oil ($/bbl) 48.14 45.45 25.88 49.69 65.11 64.79 70.26 63.72Condensate ($/bbl) 53.55 48.49 31.54 57.52 68.08 65.70 71.38 64.81Natural gas ($/Mcf) 2.88 2.16 1.92 2.05 2.36 1.54 1.74 2.79NGLs ($/bbl) 18.03 14.85 10.84 6.36 11.69 5.25 7.71 25.43Oil equivalent ($/boe) 23.29 19.55 14.38 19.52 23.93 20.46 23.04 26.20

TRADING STATISTICS (3)

($, based on intra-day trading)High 7.20 6.94 6.12 8.39 8.26 7.85 9.61 10.49Low 5.66 4.54 3.64 2.42 5.40 5.37 6.37 7.82Close 6.00 5.95 4.56 4.05 8.18 6.31 6.41 9.12Average daily volume (thousands) 1,582 1,363 2,177 3,207 2,583 1,838 2,255 2,291

CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. KvisleBoard Chair

Farhad Ahrabi (1)(2)

David R. Collyer (2)(3)(4)

John P. Dielwart (1)(2)

Michael G. McAllister (1)(2)

Kathleen O’Neill (4)(5)

Herbert C. Pinder Jr. (3)(4)

William G. Sembo (3)(5)

Nancy L. Smith (1)(5)

Terry M. Anderson(1) Member of Risk Committee(2) Member of Safety, Reserves and Operational Excellence Committee(3) Member of Human Resources and Compensation Committee(4) Member of Policy and Board Governance Committee(5) Member of Audit Committee

OFFICERSTerry M. AndersonPresident and Chief Executive Officer

Kris J. BibbySenior Vice President and Chief Financial Officer

Chris D. BaldwinVice President, Geosciences

Ryan V. BerrettVice President, Marketing

Sean R. A. CalderVice President, Production

Lara M. ConradVice President, Development and Planning

Armin JahangiriVice President, Operations

Lisa A. OlsenVice President, Human Resources

Grant A. ZawalskyCorporate Secretary

EXECUTIVE OFFICEARC Resources Ltd.1200, 308 – 4th Avenue SWCalgary, Alberta T2P 0H7T 403.503.8600TOLL FREE 1.888.272.4900F 403.509.6427W www.arcresources.com

TRANSFER AGENTComputershare Trust Company of Canada600, 530 – 8th Avenue SWCalgary, Alberta T2P 3S8T 403.267.6800

AUDITORSPricewaterhouseCoopers LLPCalgary, Alberta

ENGINEERING CONSULTANTSGLJ Ltd.Calgary, Alberta

LEGAL COUNSELBurnet Duckworth & Palmer LLPCalgary, Alberta

CORPORATE CALENDARMay 5, 2021Q1 2021 Results

May 6, 2021Annual Meeting of Shareholders

STOCK EXCHANGE LISTINGThe Toronto Stock ExchangeTrading Symbol: ARX

INVESTOR INFORMATIONVisit ARC’s website:W www.arcresources.comor contact Investor Relations:T 403.503.8600TOLL FREE 1.888.272.4900E [email protected]

mailto:[email protected]

energy Creating - ARC Resources...assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital

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