energy creating · arc is a canadian oil and gas producer in its 24th year of delivering on its...

energy Creating

for the world

Investor PresentationAugust 2020

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 beyond, 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 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in this document whether as to new information, future events, orotherwise 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 financial and operational performance. These non-GAAP measures do not have any standardized meaningprescribed 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% 5%

77%

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

H1 2020 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) 5.0 millionShares outstanding 353 millionEnterprise value (2) $2.6 billionNet debt as at June 30, 2020 (3) $961.1 millionNet debt to funds from operations (3)(4) 1.5 timesQuarterly dividend $0.06/shareDividends paid since inception $6.6 billion

07/30/2020 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

Build Owned-and-operated Infrastructure

Current Commodity Price Environment

ARC Will Continue to Optimize Its Production Based on Prevailing Commodity Prices

Majority of shut-in production broughtback online due to commodity

price improvement

Continue to monitor operational output from areas with higher operating expense

~70% of anticipatedcrude oil and condensate production

hedged for the remainder of 2020

Brought Dawson Phase IVon-stream in early Q2 2020

Focus H2 2020 capitalprogram on natural gas development activities at Dawson and Sunrise to

maximize throughput during winter months

~40% of anticipatednatural gas production hedged for the

remainder of 2020

Light Crude Oil & Liquids Production StrategyNatural Gas Production Strategy

07/30/2020 2

Capital Budget and Dividend

ARC Is Positioned to Endure This Period of Economic Uncertainty and Remain in a Position of Financial Strength

2020 Capital Budget Reduced by 40% Dividend Reduced by 60% Business Sustainability

Original Budget Reduced Budget Original Dividend Reduced Dividend

$300 million

$500 million$0.05 per Share

(Monthly)

$0.06 per Share(Quarterly)

Low cost structure and operational flexibility

Commodity optionality and robust market

diversification activities

Invest in profitable growth when it makes

sense to do so

Strong balance sheet with ample liquidity

Maintaining Financial Strength

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

ARC

ARC

(1) Source: RBC Capital Markets. Consensus estimates as per FactSet on July 15, 2020.

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

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

1.7 1.8 1.8 2.0 2.3 2.4 3.3 3.4 3.7 4.0 4.1

5.0 5.0 5.2 5.4 5.4 5.8 6.4 7.2 7.4

9.6

11.6 12.0

Group Average

0.6 0.8 1.3 1.4 1.8 1.9 2.0 2.2 2.4 2.7 2.8 2.9 3.3 3.6 3.6 4.1 4.3 4.4 4.6 5.0 5.3 5.9 5.9 6.7 7.7 8.9 9.0

Group Average

07/30/2020 3

Significant Liquidity

ARC Has Ample Liquidity to Sustain Its Business

(1) As at June 30, 2020.(2) Assumes Cdn$/US$ exchange rate of 1.36155.(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•• Repayments structured to mature over a number of years

to reduce financing risk

Cash & Existing Credit Capacity

Undrawn Master Shelf

$306.7MM

Undrawn Credit Facility

$820.3MMDrawn Master

Shelf$203.9MM

Long-term Notes$571.4MM

Drawn Credit Facility$169.7MM

$2.1 Billion Total Cash & Existing Credit Capacity($1.1 Billion Available) (1)(2)(3)(4)

Long-term Corporate Profitability

ARC Has Delivered a ~9% 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

07/30/2020 4

Dividend$85MM/year

Capital Expenditures

Sources of Cash Dividend Sustaining Capital DiscretionaryOutflows

Capital Allocation Priorities and Principles

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

Funds fromOperations

Pay sustainable dividend and grow funds from operations per share

Develop profitable projects

Manage net debt to funds from operations ratio within 1.0 to 1.5x

Maintain a low cost structure andcorporate decline rate

Capital Allocation Priorities Capital Allocation Principles

Continue to implement physicaland financial diversification strategyInflows Outflows

•Debt Reduction•Long-termDevelopmentInvestments

•Share Buybacks•DividendIncreases

Historical Capital Allocation and Outlook

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

2016 to 2019 Capital Allocation 2020 Forecasted Capital Allocation

Inflows Outflows

Funds from Operations Net A&D Proceeds Dividend Capital Expenditures

Inflows Outflows

07/30/2020 5

ARC’s Vision for the Future

ARC Has Moved Towards a Larger Production Base with Lower Capital Expenditures

Production (Mboe/day)

Capital Expenditures ($ millions)830

679 692

300

2017 2018 2019 2020F Capital Expenditures

123133

139

150 to 155

2017 2018 2019 2020F Production Base

2020 Guidance (1)

Reducing Capital Expenditures by 57% and Delivering 10% Increase in Production Relative to 2019

$300 millionInvest

Allowing ARC to:

with low operating expense of $4.55 – $4.95/boe

Maintain Balance Sheet StrengthCreate Shareholder ValueAdvance Strong ESG Performance including Publication of ESG Report in Q3 2020

to bring Dawson Phase IV andAnte Creek expansion on-stream in Q2 and to focus on natural gas development

While ensuring the safe and responsibleexecution of the capital program

705 – 710 MMcf/dayof natural gas production (2)

to produce150,000 – 155,000boe/day (2)

and drill

31 gross operated wells

33,000 – 37,500 bbl/dayof liquids production

(1) Given ongoing uncertainty, continued market volatility, and the potential for both voluntary and involuntary production curtailments over the coming months, there is considerable uncertainty embedded into ARC’s 2020 guidance items.(2) Does not incorporate the potential impact that third-party transportation restrictions may have on ARC’s natural gas production.

07/30/2020 6

2020 Budget of $300 Million

Dawson Phase IV and Ante Creek Facility Expansion Brought On-stream in Q2 2020Majority of Remaining Capital Being Directed at Dawson and Sunrise

ABBC

Ante Creek$65MM • 7 wells~17,000 boe/day

Expansion at Ante Creek facility brought on-stream in

Q2 2020

Pembina$8MM

~10,000 boe/dayPreserve light oil production

as liquids prices recover

Parkland/Tower$63MM • 8 wells~27,500 boe/day

Drilling activities deferredas liquids prices recover

Dawson$87MM • 9 wells~56,000 boe/day

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

maximum throughput during winter months to capitalize on

strong natural gas prices

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

Sunrise$35MM • 7 wells~36,000 boe/day

Ensure maximum throughput during winter monthsto capitalize on strong

natural gas prices

Attachie

Septimus

Tower

ParklandSunsetSunrise

Sundown

Dawson

Pouce Coupe

Ante Creek

Pembina

Attachie$30MM

~5,000 boe/dayOptimize pad profitability

with implementation of next generation of well design

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

07/30/2020 7

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

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)

H1 2020 Average Realized Natural Gas Price: $1.98/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 atUS$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.

H1 2020 Average Realized Natural Gas Priceincluding Gain on Risk Management Contracts: $2.08/Mcf

H1 2020 Average Realized Condensate Price: $31/bbl

H1 2020 Average Realized Crude Oil Price: $28/bbl

SunriseUpper Montney

DawsonUpper Montney

Parkland-DawsonLower Montney

Ante CreekMiddle Montney

TowerUpper Montney

Attachie WestUpper Montney

07/30/2020 8

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) Q1 2020 Operating Expense from company reports and represent data for the three months ended March 31, 2020.(5) Q1 2020 Operating Expense peer group includes: BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(6) Source: Peters & Co. Limited E&P Overview Tables (July 27, 2020). 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 ($/boe) (1)(2)(3) Q1 2020 Operating Expense ($/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

Best-in-class Operational Performance

Drilling and Completions Cost Reductions in Dawson Is 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

07/30/2020 9

Risk Management Program

Program Executed with a Long-term View

(1) 2020 Forecast values based on actuals for the six months ended June 30, 2020 and forecast for July through December 2020 based on the forward strip pricing curve as at June 30, 2020 (net of credit adjustment). 2021 to 2024 Forecast values basedon the forward strip pricing curve as at June 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.

WTI (3)

US$/bbl$62 $80 $95 $94 $98 $93 $49 $43 $51 $65 $57

AECO (3)

Cdn$/GJ$3.91 $3.79 $3.44 $2.27 $3.00 $4.19 $2.63 $1.98 $2.30 $1.45 $1.54

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

(100)

0

100

200

300

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

$ m

illio

ns

Crude Oil

Natural Gas

Foreign Exchange & Power

Total

Financial Price Management

Hedging Program Continues to Mitigate Volatility in Funds from Operations

~70% of Crude Oil & Condensate Hedged for the Balance of 2020 ~40% of Natural Gas Hedged for the Balance of 2020

0

5,000

10,000

15,000

20,000

Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021

Cru

de O

il &

Con

dens

ate

Prod

uctio

n H

edge

d (b

bl/d

ay)

0

80,000

160,000

240,000

320,000

Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021

Nat

ural

Gas

Pro

duct

ion

Hed

ged

(MM

Btu/

day)

07/30/2020 10

2.17 1.65 1.72 2.13 2.07

0.39 0.72 0.40

(0.08) (0.15)

0.78 0.81 0.44

0.09 0.11

3.34 3.18

2.56 2.14 2.03

(1.00)

0.00

1.00

2.00

3.00

4.00

2017 2018 2019 Q1 2020 Q2 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+0.5 Bcf/day by 2023

5.6 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 at AECO, Station 2, and Henry Hub.

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

Empress Floating

34% 34%18% 13% 13%

16% 14%

22% 28% 33%

11% 14%14% 15%

15%

17% 15%18% 13%

13%

8% 10% 13% 17% 8%

10% 7% 7% 7% 11%4% 6% 6% 5% 5%2% 2% 2%

Bal 2020 Cal 2021 Cal 2022 Cal 2023 Cal 20240%

25%

50%

75%

100%

% o

f Tot

al P

rodu

ctio

n

ARC’s ESG Excellence

Canadian Energy Sector Is Regulated by Some of the Highest Standards and Is a Clean, Ethical Energy SourceARC Ranks among the Highest 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” (2019). Reserves as at December 31, 2018.

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

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)

07/30/2020 11

>95% reduction expected due to plant

electrification

25% reduction target relative to

2017 baseline

Emissions Management Strategy

ARC Expects to Significantly Exceed Its 25 Per Cent GHG Emissions Intensity Reduction Target

GHG Emissions Intensity Performance (Scope 1 and 2)

2018 GHG Emissions Intensity Benchmarking (1)

0.00

0.01

0.02

0.03

0.04

2014 2015 2016 2017 2018 2019F 2021Target

Tonn

es o

f CO

2Eq

uiva

lent

per

boe

ARC Total ARC Sunrise

0.00

0.03

0.06

0.09

0.12

ARC

Sun

rise

ARC

BC

ARC

Tot

al

Tonn

es o

f CO

2Eq

uiva

lent

pe

r boe

(1) Peer group includes: BNP, BTE, CNQ, CPG, CVE, ERF, MEG, NVA, OVV, PEY, SU, 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

Water Management Strategy

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 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

• Freshwater usage reduced by 25 per cent from 2017 to 2018

Water Management Strategy in Action

07/30/2020 12

0.0

0.5

1.0

1.5

2.0

2014 2015 2016 2017 2018 2019 2020 YTD

Tota

l Rec

orda

ble

Inci

dent

Fre

quen

cy

Strong Safety Performance

• Strong safety performance is the result of well-planned and executed operations and alignment with strong service providers

ARC Employees Have Gone over Six Years Without a Lost-time Incident

60%Reduction

Contractor Total Recordable Incident Frequency

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

07/30/2020 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

2015 2018 2019

Sunrise Overview

H2 2020 Capital Program Focused on Natural Gas Development Activities at Sunrise

Snapshot

SunrisePhase I

Montney Natural Gas Processing Capacity

SunrisePhase II

SunrisePhase II

$35 million(12%)

7 wells(23%)

~36 Mboe/day(24%)

Development Plan

2020 Development Focus

Infrastructure Build-out

• Ensure maximum throughput during winter months at Sunrise Phase I and II facilities, which have combined processing capacity of 240 MMcf per day

• Area’s operating expense is less than $0.30 per Mcf

Capital Budget Expected ProductionPlanned Wells

(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.

Phase I & IIGas Plants

Sunset

Sunrise

$300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)

07/30/2020 14

Greater Dawson Area Overview

Large Integrated Network of Owned-and-operated Infrastructure

Snapshot Development Plan



2010 2011 2013 2015 2017 Q4 2019 Q2 2020

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



$150 million(50%)

17 wells(55%)

~83.5 Mboe/day(55%)

• Brought Dawson Phase IV on-stream in Q2 2020• Recommenced drilling activities in Q3 2020 to capture strong natural gas prices


Tower

Parkland

Dawson

Pembina & EnbridgeTCPLParkland-Dawson Interconnect Pipeline


Phase III & IVGas Plants



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

2019 Lower Montney Wells2020 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

Free Condensate-to-gas Ratio (bbl/MMcf)

Lower Montney Wells to Be Drilled into 2021

07/30/2020 15

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

Optimizing Dawson Lower Montney Development

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

Estimated Ultimate Recovery Capital Efficiency

Well Costs Finding and Development Costs

0

375

750

1,125

1,500

2017 2018 2019

Estim

ated

Ulti

mat

e R

ecov

ery

(Mbo

e)

0

2,500

5,000

7,500

10,000

2017 2018 2019

Cap

ital E

ffici

ency

($

/boe

/day

)

3,500

4,000

4,500

5,000

5,500

2017 2018 2019

Wel

l Cos

ts($

mill

ions

)

0

2

4

6

8

2017 2018 2019

Find

ing

& D

evel

opm

ent

Cos

ts ($

/boe

)

07/30/2020 16

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

Existing Infrastructure 2012 Q2 2020

Ante Creek Overview

Low-risk Montney Light Oil Development

Snapshot

Ante CreekPhase I

Ante CreekExpansion

Development Plan



• Brought Ante Creek facility expansion on-stream in Q2 2020

$65 million(22%)

7 wells(23%)

~17 Mboe/day(11%)

2-26Gas Plant

10-7Gas Plant

10-36Gas Plant



2-26Gas Plant

10-7Gas Plant

10-36Gas Plant




07/30/2020 17

Attachie Overview

Newest Wells on Production Have Verified Type Curve Expectations

Snapshot

Attachie West Phase I

$30 million(10%)

0 wells(0%)

~5 Mboe/day(3%)

Development Plan



• Optimize pad profitability with implementation of next generation of well design• Prepare Attachie West Phase I for execution as next major facility

(1)(2) Denotes corporate total for capital budget, planned wells, and expected production for 2020.

Existing Infrastructure


PembinaNorth Montney Mainline

8.9 Bbbl liquids and 32 Tcf gas in place (1)

(1) Total Petroleum Initially-in-Place at Attachie as at December 31, 2018.

4-20Battery

(3.5 Mbbl/day)

Phase IGas Plant




0

75

150

225

300

0 350 700 1,050 1,400

Cum

ulat

ive

Oil

& C

onde

nsat

e Pr

oduc

tion

(Mbb

l)

Days on Production

Continuous Improvement in Pad and Well Design

Well Results from Newest Pad Have Validated Pad and Well Design Changes

Pad and Well Design Evolution Cumulative Condensate Production

(1) Facility constraints relieved in Q2 2020; three of four wells on 2-27 Pad Phase I produced consistently prior to this. Over 190 days of production, the four wells have produced approximately 360,000 barrels of condensate and approximately 1,150 MMcf of natural gas.

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

Attachie Type Curve

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

02-27

A2-27

J2-27

B2-27

07/30/2020 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

74%

2%4%20%

Pembina Overview

High Interest Light Oil Production

Snapshot

$8 million(3%)

0 wells(0%)

~10 Mboe/day(7%)

Development Plan


• Preserve light oil production as liquids prices recover further

H1 2020 Production Split(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.

9.8 Mboe/day



Berrymoor

LindaleNPCU

MIPABuckCreek

SPCUPCU7

Blue boundaries denote units.

Crude oilCondensateNGLsNatural gas

07/30/2020 19

Additional Information

2020 Guidance (1)

2020 Capital Program Was Reduced to Protect ARC’s Strong Balance Sheet

2020Guidance

2020 YTDActuals

Production

Crude oil (bbl/day) 14,000 - 16,000 15,992

Condensate (bbl/day) 11,000 - 13,000 12,251

Crude oil and condensate (bbl/day) 25,000 - 29,000 28,243

Natural gas (MMcf/day) (2) 705 - 710 732.7

NGLs (bbl/day) 8,000 - 8,500 8,779

Total production (boe/day) (2) 150,000 - 155,000 159,146

Expenses ($/boe)

Operating 4.55 - 4.95 3.83

Transportation 3.10 - 3.30 2.87

G&A expense before share-based compensation expense 1.00 - 1.20 1.13

G&A - share-based compensation expense (3) 0.30 - 0.45 0.17

Interest and financing (4) 0.65 - 0.80 0.74

Current income tax expense (recovery) as a per cent of funds from operations (5) (2) - 3 (11)

Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 300 213.9(1) Given ongoing uncertainty, continued market volatility, and the potential for both voluntary and involuntary production curtailments over the coming months, there is considerable uncertainty embedded into ARC’s 2020 guidance items.(2) Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(3) 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.(4) Excludes accretion of asset retirement obligation.(5) The current income tax estimate varies depending on the level of commodity prices.

07/30/2020 20

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.

Sunrise Dawson Parkland/Tower Ante Creek Attachie Pembina

Net production – Q2 2020Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)

12243.9

40,662

10,454342.3

67,510

10,592121.0

30,757

7,59840.4

14,329

1,8177.3

3,034

7,06611.4

8,973

LandNet sections (1)

Working interest32

~89%137

~100%94

~90% / ~94%206

~100%308

~99%217

~89%

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

660.3396

5

7910.4410

4

4614.6186

4

209.6623

62.8173

3832.7

3511

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

2342.5

1,39018

30051.2

1,49414

15348.962714

7838.623912

3920.511222

6049.9

6117

0.00

0.50

1.00

1.50

2.00

2.50

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)

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 FFO (RHS)

ARC’s Business

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

45,000

90,000

135,000

180,000

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

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)

07/30/2020 21

Note Repayment Schedule

Long-term Note Repayments Structured to Mature over a Number of Years to Reduce Financing Risk

Long-term Notes Principal Repayment Schedule (1)

(1) Assumes Cdn$/US$ exchange rate of 1.36155 at June 30, 2020.

0

50

100

150

200

Bal 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029

Cdn

$ m

illio

ns

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

Risk Management Contract PositionsRisk Management Contracts Positions at June 30, 2020 (1) Q3 2020 to Q4 2020 2021 2022 2023 2024

Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling 55.70 8,500 57.29 7,992 - - - - - -Floor 47.35 8,500 50.35 7,992 - - - - - -Sold Floor 41.92 6,500 40.23 7,992 - - - - - -Swap 45.16 4,000 35.05 1,000 - - - - - -Sold Swaption (2) - - 54.32 3,008 - - - - - -Crude Oil – Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 86.38 6,500 - - - - - - - -Floor 75.38 6,500 - - - - - - - -Sold Floor 60.38 6,500 - - - - - - - -Total Crude Oil Volumes (bbl/day) 19,000 8,992 - - -Crude Oil - MSW (Differential to WTI) (4) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling (7.00) 1,000 - - - - - - - -Floor (10.20) 1,000 - - - - - - - -Swap (8.01) 6,989 - - - - - - - -Natural Gas - Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 2.94 125,108 3.02 110,000 3.11 45,000 2.74 10,000 2.74 10,000Floor 2.56 125,108 2.55 110,000 2.55 45,000 2.50 10,000 2.50 10,000Sold Floor 2.17 125,108 2.10 110,000 2.18 45,000 2.10 10,000 2.10 10,000Swap 1.86 13,405 - - - - - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.06 50,162 2.41 120,000 2.40 90,000 2.40 90,000 2.40 90,000Floor 2.56 50,162 1.95 120,000 1.87 90,000 1.87 90,000 1.87 90,000Swap 2.23 90,324 1.99 40,000 2.06 10,000 2.06 10,000 2.06 10,000Sold Swaption (2) - - - - 2.00 20,000 - - - -Total Natural Gas Volumes (MMBtu/day) 271,669 261,651 139,782 104,782 104,782Natural 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/daySold Swap (0.85) 83,297 (0.93) 69,192 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000Total AECO Basis Volumes (MMBtu/day) 83,297 69,192 35,000 70,000 70,000Natural Gas – Other Basis (MMBtu/day)

(Differential to Henry Hub) (6) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 100,000 120,000 110,000 80,000 4,973

Foreign Exchange Contract Settlement Date Notional Amount (US$ millions)Ceiling

(Cdn$/US$)Floor

(Cdn$/US$)Variable Rate Collar (7) August 24, 2020 24 1.2771 1.3231

(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 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$.(5) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.(6) ARC has entered into basis swaps at locations other than AECO.(7) Variable rate collar whereby if the Cdn$/US$ spot rate is below $1.2771 at expiry, the ceiling will readjust to $1.3058.

07/30/2020 22

(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

07/30/2020 23

ESG Recognitions and Rankings

Member of MSCI Global Sustainability IndexMSCI ESG Rating: AAA

Voluntary participant since 20072019 Climate Change Score: B2019 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

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.

07/30/2020 24

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.

07/30/2020 25

Contact Information

Please Visit Our 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]

07/30/2020 26

Notes

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07/30/2020 27

(1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled "Funds from Operations" and “Capitalization, Financial Resources andLiquidity” 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($ millions, except per share amounts) 2020 2019 2018FINANCIAL Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3Commodity sales from production 217.9 269.5 325.1 253.7 282.9 327.8 302.5 375.1

Per share, basic 0.62 0.76 0.92 0.72 0.80 0.93 0.86 1.06Per share, diluted 0.62 0.76 0.92 0.72 0.80 0.93 0.86 1.06

Net income (loss) (43.5) (558.4) (10.2) (57.2) 94.4 (54.6) 159.7 45.1Per share, basic (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45 0.13Per share, diluted (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45 0.13

Funds from operations (1) 150.2 160.8 172.8 145.4 193.0 186.2 208.6 205.0Per share, basic 0.42 0.46 0.49 0.41 0.54 0.53 0.59 0.58Per share, diluted 0.42 0.46 0.49 0.41 0.54 0.53 0.59 0.58

Dividends declared 21.3 42.5 53.1 53.1 53.1 53.1 53.1 53.0Per share (2) 0.06 0.12 0.15 0.15 0.15 0.15 0.15 0.15

Total assets 5,136.8 5,172.6 5,778.3 5,819.2 5,878.9 5,952.4 6,016.2 5,846.3Total liabilities 2,360.3 2,332.4 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4 2,278.3Net debt outstanding (1) 961.1 1,079.7 940.2 945.5 829.2 796.3 702.7 667.8Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.5Weighted average shares, diluted 353.4 353.4 353.4 353.4 353.9 353.4 353.9 354.0Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4CAPITAL EXPENDITURESGeological and geophysical 3.4 6.5 0.9 1.1 0.3 9.3 0.3 1.2Drilling and completions 31.8 131.3 86.7 101.0 110.1 144.9 77.0 126.5Plant and facilities 8.3 25.8 47.5 51.1 56.2 53.3 41.4 31.8Maintenance and optimization 1.4 4.4 3.0 6.2 5.8 3.4 11.7 7.1Corporate assets (0.8) 1.8 3.6 2.5 1.8 2.8 1.2 2.7Total capital expenditures 44.1 169.8 141.7 161.9 174.2 213.7 131.6 169.3Undeveloped land — — — 0.7 — — 0.2 —Total capital expenditures, including undeveloped

land purchases 44.1 169.8 141.7 162.6 174.2 213.7 131.8 169.3

Acquisitions 0.5 2.5 — — — 0.2 — —Dispositions (0.6) (2.4) (1.1) (2.8) (0.9) (0.2) (0.9) (96.2)Total capital expenditures, land purchases, and net

acquisitions and dispositions 44.0 169.9 140.6 159.8 173.3 213.7 130.9 73.1

OPERATING

ProductionCrude oil (bbl/day) 14,987 16,997 17,083 16,782 18,272 18,251 20,092 23,867Condensate (bbl/day) 13,239 11,262 10,937 10,846 10,230 8,210 8,458 8,158Crude oil and condensate (bbl/day) 28,226 28,259 28,020 27,628 28,502 26,461 28,550 32,025Natural gas (MMcf/day) 773.3 692.2 669.0 595.4 596.4 632.5 603.3 574.2NGLs (bbl/day) 9,405 8,152 8,123 7,952 7,041 7,183 7,402 7,687Total (boe/day) 166,510 151,783 147,650 134,813 134,938 139,054 136,502 135,410

Average realized prices, prior to risk management contractsCrude oil ($/bbl) 25.88 49.69 65.11 64.79 70.26 63.72 43.30 78.62Condensate ($/bbl) 31.54 57.52 68.08 65.70 71.38 64.81 57.25 85.28Natural gas ($/Mcf) 1.92 2.05 2.36 1.54 1.74 2.79 2.85 2.15NGLs ($/bbl) 10.84 6.36 11.69 5.25 7.71 25.43 29.12 35.26Oil equivalent ($/boe) 14.38 19.52 23.93 20.46 23.04 26.20 24.09 30.12

TRADING STATISTICS (3)

($, based on intra-day trading)High 6.12 8.39 8.26 7.85 9.61 10.49 14.84 15.90Low 3.64 2.42 5.40 5.37 6.37 7.82 7.38 12.70Close 4.56 4.05 8.18 6.31 6.41 9.12 8.10 14.40Average daily volume (thousands) 2,177 3,207 2,583 1,838 2,255 2,291 2,117 1,246

CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. Kvisle (1)

Board Chair

Farhad Ahrabi (1)(2)

David R. Collyer (1)(3)(4)

John P. Dielwart (1)(2)

Kathleen O’Neill (4)(5)

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

William G. Sembo (3)(5)

Nancy L. Smith (2)(5)

Terry M. Anderson(1) Member of Safety, Reserves and Operational Excellence Committee(2) Member of Risk 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 403.503.8609W 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 CALENDARNovember 5, 2020Q3 2020 Results

STOCK EXCHANGE LISTINGThe Toronto Stock ExchangeTrading Symbol: ARX

INVESTOR INFORMATIONVisit our websiteW www.arcresources.comor contactInvestor RelationsT 403.503.8600 orTOLL 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]

energy creating · arc is a canadian oil and gas producer in its 24th year of delivering on its...

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