ARC Resources - ARC Resources - energy Creating...ARC’s production of conventional natural gas is considered to be immaterial. ARC’s core producing properties that are considered

energy Creating

for the world

Investor PresentationJanuary 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 coreareas, its exploration and development drilling and other exploitation plans for 2020 and 2021, and related production expectations, expenditures and cash flows, the Company’s plans for constructing and expanding facilities, thevolume of ARC's crude oil and natural 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, thevolume and product mix of ARC's crude oil and 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 or the economic performance of ARC. The projections, estimates, and beliefs contained in such forward-looking statements are based on Management's assumptions relatingto the production performance of ARC’s crude oil and natural gas assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital expenditurebudgets, future commodity prices, continuing access to capital, and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties, such as changes in crudeoil and natural gas prices, infrastructure constraints in relation to the development of the Montney, risks associated with the degree of certainty in resource assessments, and including the business risks discussed in ARC’s annualand 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 differmaterially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differmaterially from those predicted. Other than the 2020 and 2021 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in this document whether as to new information, futureevents, 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 inisolation. A boe conversion 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 ratiobased on the current price of crude 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 indicationof 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”). ARC’s production ofheavy crude oil is considered to be immaterial. Natural gas refers to shale gas and 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”) aredisclosed. 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 tobe 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 the NGLs product type. NGLs by-products include ethane, butane, propane, and pentanes-plus (condensate).

Non-GAAP MeasuresThroughout this presentation, ARC uses the terms 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.

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 riskmanagement contracts. 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 measuresthat reflect how ARC’s risk 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 iscommonly used by other oil and gas producers. 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 precedingperiod 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 YTDdivided by the average of the opening 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 ameasure of long-term operational performance, to measure 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 beeninvested profitably over the long term.

10% 8% 6%

76%

9% 9% 6%

76%

Corporate Profile

ARC Is a Canadian Oil and Gas 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 September 30, 2020.(2) Market capitalization and net debt as at September 30, 2020.(3) Refer to the “Capital Management” note in ARC’s financial statements.(4) Based on net debt as at September 30, 2020 and annualized funds from operations for the nine months ended September 30, 2020.

2020 YTD Production 2019 Proved + Probable Reserves

Crude oilCondensate and pentanes plusNGLsNatural gas

159 Mboe/day 910 MMboe

Attachie

GreaterSunrise Area

Ante Creek

GreaterDawson Area

Pembina

ABBC ARC holds ~1,000 net Montney sections (~636,000 acres)

Crude oilCondensateNGLsNatural gas

Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 4.4 millionShares outstanding 353 millionEnterprise value (2) $3.0 billionNet debt as at September 30, 2020 (3) $867.8 millionNet debt to funds from operations (3)(4) 1.4 timesQuarterly dividend $0.06/shareDividends paid since inception $6.7 billion

12/31/2020 1

A Differentiated Investment

ARC Is a Unique Long-term Investment

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

Business Priorities in 2021

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 surplus funds from operations 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 minor infrastructure optimization

projects at Sunrise and 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

12/31/2020 2

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 to 1.5x

Profitably sustain production through efficient execution and controlled decline rate

Capital Allocation Principles Capital Allocation Priorities

Com

mitt

edC

apita

lD

iscr

etio

nary

Cap

ital

Historical Capital Allocation and Outlook

ARC Anticipates to Generate Sufficient Funds from Operations in 2020 and 2021to Fund Its Dividend and Capital Requirements and to Substantially Reduce Net Debt

Inflows Outflows

Funds from Operations Net A&D Proceeds Dividend Capital Expenditures

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

Inflows Outflows Inflows Outflows

12/31/2020 3

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 October 21, 2020.

US Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)

Canadian Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)

1.3 1.4 1.6 1.6 2.3 2.5 2.6 2.7 2.8 2.9 4.4 4.4 4.4 4.5 4.5 4.6

5.4 5.7 5.8 6.4 8.2

9.2

Group Average

0.7 0.8 1.3 1.3 1.9 2.0 2.2 2.7 3.0 3.1 3.4 3.4 3.5 3.8 4.1 5.0 5.3 5.7 5.8 6.3 6.7 7.1

Group Average

Significant Liquidity

ARC Has Ample Liquidity to Sustain Its Business

(1) As at September 30, 2020.(2) Assumes Cdn$/US$ exchange rate of 1.3324.(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••• 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

$300.1MM

Cash & Cash Equivalents

$2.4MM

Undrawn Credit Facility

$818.9MMDrawn Master

Shelf$199.6MM

Long-term Notes$456.1MM

Drawn Credit Facility$171.1MM

$1.9 Billion Total Cash & Existing Credit Capacity($1.1 Billion Available) (1)(2)(3)(4)

12/31/2020 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

157 to 160 158 to 165

2017 2018 2019 2020F 2021F Production Base

830

679 692

350375 to 425

2017 2018 2019 2020F 2021F Capital Expenditures

Long-term Corporate Profitability

ARC Has Delivered a ~8% ROACE since Inception

(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.

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

YTD

ROACE Trailing Three-year ROACE

12/31/2020 5

2021 Guidance

$375 millionto $425 million

Invest

Allowing ARC to:

with low operating expense of $4.00 – $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 minor 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 liquids production

(1) Does not incorporate the potential impact that third-party transportation restrictions may have on ARC’s natural gas production.

2021 Budget Is Focused on Maximizing Generation of Surplus Funds from Operations, Capital Discipline, Profitability, and Financial Strength

Advance Strong ESG Performance

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) The current income tax estimate varies depending on the level of commodity prices.(5) 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 (5)

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 (4) 3 - 7

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

12/31/2020 6

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

ABBC

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

Septimus

Tower

ParklandSunsetSunrise

Sundown

Dawson

Pouce Coupe

Ante Creek

Pembina

Attachie$6MM

~3,500 boe/dayComplete detailed

engineering work for development

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

12/31/2020 7

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 Sustainability 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

Emissions Management Strategy and Performance

ARC Delivered a 47 Per Cent Reduction in Its GHG Emissions Intensity 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) 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

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 Indirect Emissions GHG Emissions Intensity

20% reduction target relative to

2019 baseline

12/31/2020 8

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

Social and Governance Performance

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

Safety People & Diversity Indigenous Relations

6 yearswithout an employeelost-time injury incident

37%decrease in contractor recordable injuriessince 2017

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

12/31/2020 9

World-class Montney Resource

ARC Has Identified over 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.

Significant Montney Inventory (1)

0

1,600

3,200

4,800

6,400

Wells Drilled to YE 2019 2P Booked Locations Internal Inventory Estimate

Num

ber o

f Loc

atio

ns

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

12/31/2020 10

Owned-and-operated Infrastructure

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

AB

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

Over 90% Owned and Operated

• >50 Mbbl/day of Liquids Capacity

Ante Creek 10-36

Ante Creek 10-7

Ante Creek 2-26

Best-in-class Operational Performance

Drilling and Completions Cost Reductions in Dawson Are an Example of ARC’s Commitment to Continuous Improvement

1,400

1,700

2,000

2,300

2,600

2014 2020

Dawson Drilling and Completions Costs ($/lateral metre) Operational Performance

60%Reduction

60% reduction in drilling and completions costs since 2014

Drilling times reduced from25 days to <10 days

Continuous improvement and optimization of completions design

and pumping efficiency

Drilling longer wells

12/31/2020 11

0.00

10.00

20.00

30.00

40.00

Ante CreekUpper Montney

TowerUpper Montney

Attachie WestUpper Montney

0.00

0.60

1.20

1.80

2.40

Parkland-DawsonLower Montney

DawsonUpper Montney

SunriseUpper Montney

Top-tier Montney Economics

Low Cost Structure Supports Strong Economics in Stable Pricing Environment

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

2020 YTD Average Realized Natural Gas Price: $2.04/Mcf

(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$40 per barrel and Montney liquids break-evens run with AECO natural gas held constant at Cdn$2.00 per GJ.

(2) Parkland-Dawson Lower Montney and Dawson Upper Montney break-evens denote the midpoint of a range of outcomes depending on the liquids ratio.

2020 YTD Average Realized Natural Gas Priceincluding Gain on Risk Management Contracts: $2.12/Mcf

2020 YTD Average Realized Condensate Price: $34/bbl

2020 YTD Average Realized Crude Oil Price: $30/bbl

SunriseUpper Montney

DawsonUpper Montney

Parkland-DawsonLower Montney

Ante CreekMiddle Montney

TowerUpper Montney

Attachie WestUpper Montney

0

4

8

12

16

0

10

20

30

40

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) H1 2020 Operating Expense from company reports and represent data for the six months ended June 30, 2020.(5) H1 2020 Operating Expense peer group includes: BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(6) Source: Peters & Co. Limited E&P Overview Tables (November 3, 2020). Peer group includes APA, AR, COG, CXO, 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 ($/boe) (1)(2)(3) H1 2020 Operating Expense ($/boe) (4)(5) 2021E Corporate Decline Rates (%) (6)

ARC

Canadian ProducersUS Producers

ARC

Daw

son

ARC

ARC

Sun

rise

Gas

ARC

NE

BC

Oil

& G

as

Group Average

12/31/2020 12

36% 34%20%

12% 12%

10% 17%25% 33% 37%

16% 13%13% 15% 15%

15% 16%19% 14% 14%

9% 9% 12% 15% 7%9% 6% 6% 6% 10%5% 5% 5% 5% 5%

Bal 2020 2021 2022 2023 20240%

25%

50%

75%

100%

% o

f Tot

al P

rodu

ctio

n

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 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 on Risk Management Contracts

Average Price before Diversification Activities

Dawn Floating

Malin Floating

Henry Hub Floating

Midwest US Floating

AECO Floating

Station 2 Floating

Hedged

1.65 1.72 2.13 2.07 2.26

0.72 0.40

(0.08) (0.15) (0.10)

0.81 0.44

0.09 0.11 0.02

3.18

2.56 2.14 2.03 2.18

(0.50)

0.50

1.50

2.50

3.50

2018 2019 Q1 2020 Q2 2020 Q3 2020

Cdn

$/M

cf

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)

0

5,000

10,000

15,000

20,000

Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 20210

90,000

180,000

270,000

360,000

Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021

~70% of Crude Oil & Condensate Hedged for the Balance of 2020 and~40% Hedged for 2021

~40% of Natural Gas Hedged for the Balance

of 2020 and 2021

12/31/2020 13

Resource Potential and Scalability

ARC has:

• ~1,000 net Montney sections (~636,000 acres)

• Over 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

2019

Base Production (Montney & Cardium)

Dawson Phase IV & Ante Creek Expansion

Future Development Projects

Attachie

GreaterSunrise Area

GreaterDawson Area

Ante Creek

~139 Mboe/day

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 anticipated 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

12/31/2020 14

Lower Montney Development and Liquids Growth

Integrated Approach to Development in Greater Dawson Area Allows ARCto Optimize Infrastructure Capacities to Maximize Profitability

(1) Total Petroleum Initially-in-Place as at December 31, 2018.(2) NGLs volumes are Unrisked Best Estimate Economic Contingent Resource as at December 31, 2018.

Parkland

Dawson

2020 Lower Montney Wells2019 Lower Montney Wells

Phase II & IVGas Plants


100.

Greater Dawson Area Lower Montney Development

• 23 Tcf (1) of resources in lower Montney

• 105 MMbbl of contingent resource NGLs, of which 71 MMbbl is condensate (1)(2)

Large Resourcein Place

Tiered Inventory

Strong Return on Investment

• North Dawson & ParklandCGR: ~150 bbl/MMcf

• Core Dawson CGR: ~40 bbl/MMcf• 300+ drilling locations at Dawson

250+ drilling locations at Parkland/Tower

• Prioritize wells based on return on investment

• Lower Montney wells have strong IRR and one-year payout

• Improved capital efficiency through increased lateral length Free Condensate-to-gas Ratio (bbl/MMcf)

2021 Lower Montney Wells

0

50,000

100,000

150,000

200,000

0 12 24 36 48 60

Cum

ulat

ive

Con

dens

ate

Prod

uctio

n (b

bl)

Months on Production

Greater Dawson Area Strong Condensate Results

Strong Range of Condensate Outcomes from Both Upper and Lower Montney Development

Greater Dawson Area Condensate Performance

Type Curve

NGLs[C2,C3,C4]EUR (Mbbl)

Condensate EUR (Mbbl)

Natural Gas

EUR (Bcf)

Upper Montney Low End 10 30 7.3

Upper Montney High End 105 85 5.9

Lower Montney Low End 110 100 6.0

Lower Montney High End 80 240 2.4

Lower Montney Range

Upper Montney Range

12/31/2020 15

Optimizing Dawson Lower Montney Development

Technology Has Enhanced Profitability through Improved EURs, Better Capital Efficiency, and Lower F&D Costs

Estimated Ultimate Recovery (Mboe) Capital Efficiency ($/boe/day)

Well Costs ($ millions) Finding and Development Costs ($/boe)

0

375

750

1,125

1,500

2017 2018 20190

2,500

5,000

7,500

10,000

2017 2018 2019

3,500

4,000

4,500

5,000

5,500

2017 2018 20190

2

4

6

8

2017 2018 2019

Dawson Phase IV On-stream

Commissioning Activities Completed in Q1 2020 and Facility Brought On-stream in Q2 2020Wells to Initially Fill Facility Are Meeting Type Curve Expectations

Dawson Phase IV Project Checklist

Commercial and Development Execution

Regulatory Approval Secured

Takeaway Secured

Economics Robust

Facility Execution

Project Cost On budget

Safety 0 LTIs

On-stream April 2020

12/31/2020 16

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 anticipated strength in natural gas pricing


Sunset

Sunrise




$77 million(19%)

9 wells(13%)

~40 Mboe/day(25%)

SunrisePhase I & IIExpansion

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

2-26Gas Plant

10-7Gas Plant

10-36Gas Plant

2-26Gas Plant

10-7Gas Plant

10-36Gas Plant






$58 million(14%)

16 wells(23%)

~17 Mboe/day(11%)

12/31/2020 17

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%)

0

75

150

225

300

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

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 235 days of production, the four wells have produced approximately 445,000 barrels of condensate and approximately 1,375 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

12/31/2020 18

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

73%

2%4%21%

Pembina Overview

High Working Interest Light Oil Production

Snapshot Development Plan


• Preserve light oil production as liquids prices recover

YTD 2020 Production Split

9.2 Mboe/day

Berrymoor

LindaleNPCU

MIPABuckCreek

SPCUPCU7

Blue boundaries denote units.

Crude oilCondensateNGLsNatural gas




$6 million(1%)

0 wells(0%)

~6.5 Mboe/day(4%)

12/31/2020 19

Additional Information

2020 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) The current income tax estimate varies depending on the level of commodity prices.

2020 OriginalGuidance

2020 Revised Guidance

(March 2020)

2020 Revised Guidance

(November 2020)2020 YTD

Actuals

Production

Crude oil (bbl/day) 15,000 - 17,000 14,000 - 16,000 15,000 - 16,000 15,784

Condensate (bbl/day) 12,000 - 14,000 11,000 - 13,000 12,000 - 13,000 13,117

Crude oil and condensate (bbl/day) 27,000 - 31,000 25,000 - 29,000 27,000 - 29,000 28,901

Natural gas (MMcf/day) (1) 715 - 725 705 - 710 725 - 730 724.5

NGLs (bbl/day) 8,500 - 9,000 8,000 - 8,500 9,000 - 9,500 9,258

Total production (boe/day) (1) 155,000 - 161,000 150,000 - 155,000 157,000 - 160,000 158,911

Expenses ($/boe)

Operating 4.55 - 4.95 4.55 - 4.95 4.00 - 4.20 3.93

Transportation 3.10 - 3.30 3.10 - 3.30 3.00 - 3.20 2.99

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

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 0.71

Current income tax expense (recovery) as a per cent of funds from operations (4) (2) - 3 (2) - 3 (5) - 0 (8)

Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 500 300 350 266.5

12/31/2020 20

2020 Budget of $350 MillionABBC

Ante Creek$65MM • 13 wells~16,000 boe/day

Expansion at Ante Creek facility brought on-stream in

Q2 2020

Pembina$3MM

~9,000 boe/dayPreserve light oil production

as liquids prices recover

Parkland/Tower$53MM • 8 wells~32,000 boe/day

Drilling activities deferredas liquids prices recover Dawson

$134MM • 19 wells~58,000 boe/day

Phase IV facility brought on-stream in Q2 2020; ensure maximum

throughput during winter months 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$48MM • 16 wells~38,500 boe/day

Ensure maximum throughput during winter months

to capitalize on anticipated strength in natural gas pricing

Attachie

Septimus

Tower

ParklandSunsetSunrise

Sundown

Dawson

Pouce Coupe

Ante Creek

Pembina

Attachie$31MM

~4,000 boe/dayOptimize pad profitability with

implementation of next generation of well design

Capital Budget Increased to $350 Million to Accelerate Development Activities at Dawson and Sunriseto Maximize Throughput during Winter Months to Capitalize on Anticipated Strength in Natural Gas Pricing

Asset Details

Diversified Commodity Mix across Asset Portfolio Provides Optionality

(1) Denote Montney or Cardium sections only.(2) Reserve life index based on 2020 guided production.

Dawson Sunrise Parkland/Tower Ante Creek Attachie Pembina

Net production – Q3 2020Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)

8,731309.1

60,251

21200.6

33,450

12,241123.8

32,876

9,72345.4

17,271

3,46012.0

5,458

6,31510.9

8,130

LandNet sections (1)

Working interest137

~100%32

~89%94

~90% / ~94%206

~100%308

~99%217

~89%

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

7910.4410

4

660.3396

5

4614.6186

4

209.6623

62.8173

3832.7

3511

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

30051.2

1,49414

2342.5

1,39018

15348.962714

7838.623912

3920.511222

6049.9

6117

12/31/2020 21

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

YTD

Rat

io

$ m

illio

ns

Net Debt (LHS)

Annualized Funds From Operations (LHS)

Net Debt to Annualized Funds from Operations (RHS)

Business Overview

ARC Manages a Profitable Business through 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

YTD

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

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 YT

D

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)

0

50

100

150

200

Bal 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

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

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 1.3324 at September 30, 2020.

12/31/2020 22

Risk Management Program

Program Executed with a Long-term View

(1) 2020 Forecast values reflect actuals for the nine months ended September 30, 2020 and forecast for October through December 2020 reflect the forward strip pricing curve as at September 30, 2020 (net of credit adjustment). 2021 to 2025 Forecastvalues reflect the forward strip pricing curve as at September 30, 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.(3) Realized pricing is based on annual average settlements.

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 2020F 2021F 2022F 2023F 2024F 2025F

Crude Oil

Natural Gas

Foreign Exchange & Power

Total

Risk Management Contracts PositionsRisk Management Contracts PositionsSeptember 30, 2020 Q4 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$/bbl bbl/day US$/bbl bbl/dayCeiling 55.70 8,500 55.80 9,492 51.42 1,000 - - - - - -Floor 47.35 8,500 48.64 9,492 45.00 1,000 - - - - - -Sold Floor 41.92 6,500 39.92 8,492 35.00 1,000 - - - - - -Swap 45.16 4,000 35.05 1,000 - - - - - - - -Sold Swaption (2) - - 43.00 1,008 - - - - - - - -Crude Oil – Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 86.38 6,500 - - - - - - - - - -Floor 75.38 6,500 - - - - - - - - - -Sold Floor 60.38 6,500 - - - - - - - - - -Total Crude Oil Volumes (bbl/day) 19,000 10,492 1,000 - - -Crude Oil – MSW (Differential to WTI) (4) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling (7.00) 1,000 - - - - - - - - - -Floor (10.20) 1,000 - - - - - - - - - -Swap (8.01) 7,000 (6.11) 5,000 - - - - - - - -Natural Gas – Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 2.99 115,109 3.02 110,000 3.11 45,000 2.74 10,000 2.74 10,000 - -Floor 2.59 115,109 2.55 110,000 2.55 45,000 2.50 10,000 2.50 10,000 - -Sold Floor 2.19 115,109 2.10 110,000 2.18 45,000 2.10 10,000 2.10 10,000 - -Swap 1.86 6,739 - - - - - - - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.05 83,152 2.41 120,000 2.47 110,000 2.40 90,000 2.40 90,000 2.73 20,000Floor 2.45 83,152 1.95 120,000 1.90 110,000 1.87 90,000 1.87 90,000 2.00 20,000Sold Floor 1.75 33,152 - - - - - - - - - -Swap 2.44 80,000 2.25 62,466 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$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 4.10 13,261 4.10 4,932 - - - - - - - -Floor 2.75 13,261 2.75 4,932 - - - - - - - -Total Natural Gas Volumes (MMBtu/day) 289,747 287,876 168,216 104,782 104,782 18,956Natural Gas – AECO Basis (Differential to Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/daySold Swap (0.81) 86,630 (0.93) 66,260 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000 - -Total AECO Basis Volumes (MMBtu/day) 86,630 66,260 35,000 70,000 70,000 -Natural Gas – Other Basis (Differential to Henry Hub) (6)

MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 100,000 120,000 110,000 80,000 4,973 -

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

(2) The sold swaption allows the counterparty, at a specified 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) Crude oil prices referenced to WTI, multiplied by the WM/Reuters Intra-day Cdn$/US$ Foreign Exchange Spot Rate as of Noon Eastern Standard Time.

(4) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton calculated on a monthly weighted average basis in US$.(5) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.(6) ARC has entered into basis swaps at locations other than AECO.

12/31/2020 23

(40)

0

40

80

120

160

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

MM

boe

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

Produced Reserves Replacement

• Strong 2019 development 2P reserve adds, with 164 per cent of produced reserves replaced• Finding and development costs of $4.82/boe for proved plus probable reserves and $9.74/boe for total proved reserves (2)

150 Per Cent Reserves Replacement or Greater for 12th 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 2019 reserves data is based on gross interest proved plus probable reserves.(2) Includes future development capital.

Annual Produced Reserves Replacement (1)

PDP28%

PNP 2%

PUD35%

Probable35%

Key Reserve Information (1)

Year-end 2019 Reserves Added 83 MMboe of 2P Reserves through Development Activities

(1) Reserves data effective December 31, 2019; TPIIP resources data effective December 31, 2018.(2) Based on 2020 original production guidance midpoint of 158,000 boe per day.(3) Independent Resources Evaluation conducted by GLJ effective December 31, 2018. For resources disclosure, refer to the February 7, 2019 news release entitled, “ARC Resources Ltd. Announced 118 MMboe of Total Proved Plus Probable Reserve

Additions in 2018, Replacing 245 Per Cent of Production, and Delivers Record Proved Producing Reserve Additions of 82 MMboe”.

YE 2019 2P Reserves

0

250

500

750

1,000

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019

2P R

eser

ves

(MM

boe)

Natural GasCrude Oil & Liquids Oil

9%Condensate & Pentanes Plus

9%

NGLs6%

Natural Gas76%

Proved Producing 258 MMboe

Total Proved 595 MMboe

Proved plus ProbableCrude and Tight OilNGLsNatural Gas

910 MMboe83 MMbbl

134 MMbbl4.2 Tcf

2P Reserve Life Index (2) 15.8 years

TPIIP (1)(3)

Tight OilShale Gas

14.3 billion barrels101.8 Tcf

12/31/2020 24

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

Reserves and Resources Disclosure

All reserves in this presentation are, unless indicated otherwise, as at December 31, 2019 as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in accordance with thedefinitions, standards, and procedures contained in the COGE Handbook and NI 51-101. Resources volumes for the Montney are as at December 31, 2018 as evaluatedby GLJ in accordance with the 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.

12/31/2020 25

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.

12/31/2020 26

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]

12/31/2020 27

Notes

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

____________________________________________________________________________

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12/31/2020 28

(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 2018($ millions, except per share amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4FINANCIAL RESULTSCommodity sales from production 285.0 217.9 269.5 325.1 253.7 282.9 327.8 302.5

Per share, basic 0.81 0.62 0.76 0.92 0.72 0.80 0.93 0.86Per share, diluted 0.81 0.62 0.76 0.92 0.72 0.80 0.93 0.86

Net income (loss) (66.1) (43.5) (558.4) (10.2) (57.2) 94.4 (54.6) 159.7Per share, basic (0.19) (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45Per share, diluted (0.19) (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45

Funds from operations (1) 144.6 150.2 160.8 172.8 145.4 193.0 186.2 208.6Per share, basic 0.41 0.42 0.46 0.49 0.41 0.54 0.53 0.59Per share, diluted 0.41 0.42 0.46 0.49 0.41 0.54 0.53 0.59

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

Total assets 4,982.9 5,136.8 5,172.6 5,778.3 5,819.2 5,878.9 5,952.4 6,016.2Total liabilities 2,292.7 2,360.3 2,332.4 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4Net debt outstanding (2) 867.8 961.1 1,079.7 940.2 945.5 829.2 796.3 702.7Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4Weighted average shares, diluted 353.4 353.4 353.4 353.4 353.4 353.9 353.4 353.9Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4CAPITAL EXPENDITURESGeological and geophysical 2.4 3.4 6.5 0.9 1.1 0.3 9.3 0.3Drilling and completions 40.8 31.8 131.3 86.7 101.0 110.1 144.9 77.0Plant and facilities 5.9 8.3 25.8 47.5 51.1 56.2 53.3 41.4Maintenance and optimization 2.1 1.4 4.4 3.0 6.2 5.8 3.4 11.7Corporate assets 1.4 (0.8) 1.8 3.6 2.5 1.8 2.8 1.2Total capital expenditures 52.6 44.1 169.8 141.7 161.9 174.2 213.7 131.6Undeveloped land — — — — 0.7 — — 0.2Total capital expenditures, including undeveloped

land purchases 52.6 44.1 169.8 141.7 162.6 174.2 213.7 131.8Acquisitions — 0.5 2.5 — — — 0.2 —Dispositions — (0.6) (2.4) (1.1) (2.8) (0.9) (0.2) (0.9)Total capital expenditures, land purchases, and net

acquisitions and dispositions 52.6 44.0 169.9 140.6 159.8 173.3 213.7 130.9OPERATIONAL RESULTSProduction

Crude oil (bbl/day) 15,373 14,987 16,997 17,083 16,782 18,272 18,251 20,092Condensate (bbl/day) 14,831 13,239 11,262 10,937 10,846 10,230 8,210 8,458Crude oil and condensate (bbl/day) 30,204 28,226 28,259 28,020 27,628 28,502 26,461 28,550Natural gas (MMcf/day) 708.2 773.3 692.2 669.0 595.4 596.4 632.5 603.3NGLs (bbl/day) 10,208 9,405 8,152 8,123 7,952 7,041 7,183 7,402Total (boe/day) 158,444 166,510 151,783 147,650 134,813 134,938 139,054 136,502

Average realized prices, prior to risk management contractsCrude oil ($/bbl) 45.45 25.88 49.69 65.11 64.79 70.26 63.72 43.30Condensate ($/bbl) 48.49 31.54 57.52 68.08 65.70 71.38 64.81 57.25Natural gas ($/Mcf) 2.16 1.92 2.05 2.36 1.54 1.74 2.79 2.85NGLs ($/bbl) 14.85 10.84 6.36 11.69 5.25 7.71 25.43 29.12Oil equivalent ($/boe) 19.55 14.38 19.52 23.93 20.46 23.04 26.20 24.09

TRADING STATISTICS (3)

($, based on intra-day trading)High 6.94 6.12 8.39 8.26 7.85 9.61 10.49 14.84Low 4.54 3.64 2.42 5.40 5.37 6.37 7.82 7.38Close 5.95 4.56 4.05 8.18 6.31 6.41 9.12 8.10Average daily volume (thousands) 1,363 2,177 3,207 2,583 1,838 2,255 2,291 2,117

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 Petroleum Consultants Ltd.Calgary, Alberta

LEGAL COUNSELBurnet Duckworth & Palmer LLPCalgary, Alberta

CORPORATE CALENDARFebruary 11, 2021Year-end 2020 Results

May 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]

ARC is listed on the Jantzi Social Index; a common stock index of 60 Canadian companies that pass a set of broadly based environmental, social and governance rating criteria.

mailto:[email protected]

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ARC Resources - ARC Resources - energy Creating...ARC’s production of conventional natural gas is considered to be immaterial. ARC’s core producing properties that are considered