our february 2020 investor presentation future - arc resources · advisory statements...

OUR FOCUS OUR FUTURE

February 2020 Investor Presentation

Advisory Statements

Forward-looking Information and Statements and Advisory StatementsThis presentation contains forward-looking information as to ARC’s internal projections, expectations, or beliefs relating to future events or future performance and includes information as to ARC’s future well inventory in its core areas, its exploration anddevelopment drilling and other exploitation plans for 2020 and beyond, and related production expectations, costs and cash flow, expenses, the Company’s plans for constructing and expanding facilities, the volume of ARC's crude oil and natural gas reservesand the volume of ARC's crude oil and natural gas resources in the Montney, the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's crude oil and natural gas production, futureresults 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. Theprojections, estimates, and beliefs contained in such forward-looking statements are based on Management's assumptions relating to the production performance of ARC’s crude oil and natural gas assets, the cost and competition for services, thecontinuation of ARC’s historical experience with expenses and production, changes in the capital expenditure budgets, future commodity prices, continuing access to capital, and the continuation of the current regulatory and tax regime in Canada, andnecessarily involve known and unknown risks and uncertainties, such as changes in crude oil and natural gas prices, infrastructure constraints in relation to the development of the Montney, risks associated with the degree of certainty in resourceassessments, and including the business risks discussed in ARC’s annual and quarterly Management’s Discussion & Analysis and other continuous disclosure documents, and related to Management’s assumptions, which may cause actual performance andfinancial results in future periods to differ materially 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 todiffer materially 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, or otherwise except asrequired by securities laws and regulations.

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

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

Throughout this presentation, when condensate is disclosed, it is done so as it is the product type that is measured at the first point of sale. As per the Canadian Oil and Gas Evaluation (“COGE”) Handbook, condensate is a by-product of the NGLs producttype. 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 meaning prescribed underInternational 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 risk management 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 measures that reflect how ARC’s risk management programcan impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that is commonly used by other oil and gas producers. The measurement on a per boebasis assists Management with evaluating operational performance on a comparable basis.

Return on Average Capital Employed

ARC calculates ROACE, expressed as a percentage, as net income (loss) plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months preceding period end. Capital employed isthe 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 2019 divided by the average of the opening and closing capitalemployed over the same period. Refer to the "Capital Management" note in ARC’s financial statements for additional discussion on net debt. ARC uses ROACE as a measure of long-term operational performance, to measure how effectively Managementutilizes the capital it has been provided and to demonstrate to shareholders the sustainability of its business model and that capital has been invested profitably over the long term.

Other DefinitionsThroughout this presentation, ARC uses the term sustaining capital. This measure does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.

Sustaining Capital

Sustaining capital refers to estimated capital expenditures to maintain production from existing facilities at approximately current production levels.

13% 7%5%

75%

9% 9% 6%

76%

Corporate Profile

ARC Is a Canadian Oil and Gas Producer in Its 23rd Year of Delivering on Its Disciplined,Returns-focused Value Proposition, Including over $6.5 Billion in Dividends Paid since Inception

Asset SnapshotCorporate Summary

(1) Average daily trading volume for the six months ended February 11, 2020.(2) Market capitalization as at February 11, 2020 and net debt as at December 31, 2019.(3) Refer to the “Capital Management” note in ARC’s financial statements.(4) Based on funds from operations for the year ended December 31, 2019 and net debt as at December 31, 2019

Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 4.0 millionShares outstanding 353 millionEnterprise value (2)(3) $3.3 billionNet debt at December 31, 2019 (3) $940.2 millionNet debt to funds from operations (3)(4) 1.3 timesMonthly dividend $0.05/share

2019 Production 2019 Proved + Probable Reserves

Crude oilCondensate and pentanes plusNGLsNatural gas

139 Mboe/day 910 MMboe

Attachie

GreaterSunrise Area

Ante Creek

GreaterDawson Area

ARC holds ~1,000 net Montney sections (~638,000 acres)

Pembina

ABBC

Greater Dawson Area 88 Mboe/day

Greater Sunrise Area 36 Mboe/day

Ante Creek 18 Mboe/day

Pembina 10 Mboe/dayAttachie Pilot 5 Mboe/day

0

40

80

120

160

2020 Expected Production (Mboe/day)

Crude oilCondensateNGLsNatural gas

02/20/2020 1

Corporate Strategy

ARC’s Strategy Is Focused on Long-term Profitability

RISK-MANAGED

VALUECREATION

HIGH-QUALITYASSETS &

OPERATIONAL EXCELLENCE

FINANCIALSUSTAINABILITY &

RETURN ONINVESTMENT

HIGHPERFORMANCE

PEOPLE &CULTURE

COMMERCIALACTIVITIES &

RISKMANAGEMENT

Long-term Corporate Profitability

ARC Has Delivered a 10% 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

(10%)

0%

10%

20%

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

ROACE Trailing Three-year ROACE

02/20/2020 2

Longer-term Capital Allocation Priorities & Principles

Dividend and Sustaining Capital Requirements Are Fully Funded at US$45/bbl WTI and US$2.00/MMBtu NYMEX Henry Hub

Dividend$212 million

per year

Three-year Average

Sustaining Capital (1)

~$400 millionper year

Sources of Cash Dividend Sustaining Capital Growth Capital

Funds fromOperations

Pay meaningful 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

(1) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. Refer to “Other Definitions” in the Advisory Statements to this presentation.

Capital Allocation Principles

Inflows Outflows

Fully funded at US$45/bbl WTI and US$2.00/MMBtu NYMEX Henry Hub

Continue to implement physicaland financial diversification strategy

• Debt Reduction• Long-term Development

Investments• Share Buybacks• Dividend Increases

Historical Capital Allocation and Outlook

ARC Expects to Generate Funds from Operations That Will Fully Fund Its Dividend and All Capital Requirements in 2020

(1) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. Refer to “Other Definitions” in the Advisory Statements to this presentation.

Inflows Outflows

2016 to 2019 Capital Allocation 2020 Forecasted Capital Allocation

Inflows Outflows

Funds from Operations Net A&D Proceeds Dividend Sustaining Capital (1) Long-term Development Investments

02/20/2020 3

ARC’s Vision for the Future

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

830

679 692

500

2017 2018 2019 2020F Three-year Average Sustaining Capital

(1) Total production for 2020F denotes the midpoint of the production guidance range of 155,000 to 161,000 boe per day for 2020.(2) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. Refer to “Other Definitions” in the Advisory Statements to this presentation.

123133

139

158

2017 2018 2019 2020F Production Base

Production (Mboe/day) (1)

Capital Expenditures ($ millions) (2)

2020 Guidance

Reducing Capital Expenditures by 28% and Delivering 14% Increase in Production

$500 millionInvest to keep facilities at or

near gas capacity while maximizing liquids production and cashflow generation

Allowing ARC to:

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

Maintain Balance Sheet StrengthFocus on Organic Liquids GrowthCreate Shareholder Value

w

and to completeDawson Phase IV andAnte Creek oil expansion, andcommence Parkland sour conversion

While ensuring the safe and responsibleexecution of the capital program

715 – 725 MMcf/dayof gas production

to produce155,000 – 161,000boe/day

and drilling

65 grossoperated wells

35,500 – 40,000 bbl/dayof liquids production

02/20/2020 4

Attachie$30MM

5,000 boe/dayOptimize pad profitability

with implementation of next generation of well design

2020 Budget of $500 Million

Completion of Dawson Phase IV Will Grow Profitable Production and Deliver Annual Production of 155 to 161 Mboe Per Day

ABBC

Ante Creek$79MM • 12 wells18,000 boe/day

Expansion at Ante Creek facility to add 15 MMcf/day of gas and 2,500 bbl/day of oil in Q2 2020

Pembina$11MM

10,000 boe/dayManage production declines

and maximize cash flow generation from light

oil production

Parkland/Tower$96MM • 6 wells29,000 boe/day

Convert existing sweet facility to a sour facility to support development of liquids-rich

lower Montney wells

Dawson$231MM • 39 wells

59,000 boe/dayPhase IV facility to comeon-stream in Q2 2020;

development focused on liquids-rich lower Montney

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

Sunrise$40MM • 8 wells36,000 boe/day

Generate cash flow through owned and operated facilities with capacity of 240 MMcf/day

Red Creek

AttachieSeptimus

Tower

ParklandSunset

Sunrise

Sundown

Dawson

Pouce Coupe

Ante Creek

Pembina

Maintaining Financial Strength

ARC Has One of the Strongest Balance Sheets in the Sectorwith a Targeted Net Debt to Annualized Funds from Operations Ratio of 1.0 to 1.5x

ARC

ARC

(1) Source: RBC Research. Consensus estimates as per FactSet on January 21, 2020.

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

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

0.7 0.7 0.8 1.0 1.2 1.2 1.2 1.3 1.4 1.5 1.6 1.6 1.6 1.8 1.8 1.9 1.9 1.9 2.2 2.3 2.3 2.4 2.4 2.6 3.3

4.2 4.3 4.8 5.1

Group Average

0.3 0.4 1.0 1.1 1.2 1.2 1.2 1.3 1.4 1.4 1.5 1.6 1.6

2.1 2.3 2.4 2.4 2.5 2.7 3.1 3.1 3.3 3.4 3.5 3.8 3.9 4.2

5.3

7.0 Group Average

02/20/2020 5

World-class Montney Resource

ARC Has Identified over 4,500 Future Drilling Locations across ARC’s 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

02/20/2020 6

0

4

8

12

16

0

6

12

18

24

(1) Source: Peters & Co. 2018 Reserves Comparison – E&P Producers (March 29, 2019). Three-year 2P FD&A Costs represent data for the years 2016 to 2018 and include future development capital.(2) Refer to ARC’s February 7, 2019 news release entitled, “ARC Resources Ltd. Announces 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” for information pertaining to ARC’s finding and development costs.(3) Three-year 2P FD&A Costs peer group includes: BNP, BTE, CPG, PEY, POU, TOU, VET, VII, WCP.(4) Includes future development capital for build-out of Dawson Phase I & II liquids-handling upgrade and new Dawson Phase IV infrastructure.(5) 2019 YTD Operating Expense from company reports and represent data for the nine months ended September 30, 2019.(6) 2019 YTD Operating Expense peer group includes: BNP, BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(7) Source: Peters & Co. Limited E&P Overview Tables (January 28, 2020). Peer group includes APA, AR, COG, DVN, EOG, FANG, OVV, PEY, PXD, TOU, VII.

Cost Management & Decline Rate

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

Group Average

ARC

Group Average

ARC

Daw

son

(4)

ARC

NE

BC

Oil

& G

as

ARC

Sun

rise

Gas

Three-year 2P FD&A Costs ($/boe) (1)(2)(3) 2019 YTD Operating Expense ($/boe) (5)(6) 2020E Corporate Decline Rates (7)

ARC

Canadian ProducersUS Producers

0%

12%

24%

36%

48%

ARC

Daw

son

ARC

ARC

Sun

rise

Gas

ARC

NE

BC

Oil

& G

as

Oil & Liquids Financial and Physical Price Management

~60% of ARC’s 2019 Commodity Sales from Production Was Derived from Crude Oil and Liquids

76% of ARC’s liquids production is made up of light oil and condensate

Crude Oil & Liquids Sales Mix Crude Oil & Liquids Benchmark Pricing Crude Oil Risk Management

OilCondensateNGLs

(1) Per cent of production hedged based on full-year 2020 production guidance.

39% 37%

24%30

40

50

60

70

Jan

2019

Feb

2019

Mar

201

9

Apr 2

019

May

201

9

Jun

2019

Jul 2

019

Aug

2019

Sep

2019

Oct

201

9

Nov

201

9

Dec

201

9

US$

/bar

rel

Benchmark Pricing

Mixed Sweet BlendWTICondensateWestern Canadian Select

0%

15%

30%

45%

60%

Q12020

Q22020

Q32020

Q42020

Q12021

Q22021

Q32021

Q42021

Per C

ent o

f Cru

de O

il Pr

oduc

tion

Hed

ged

Crude Oil Hedges (1)

02/20/2020 7

1.70

2.45

1.65 1.72

1.15

(0.09)

0.72 0.40

0.62

0.18 0.81

0.44

3.47

2.54

3.18

2.56

(1.00)

0.00

1.00

2.00

3.00

4.00

Q4 2018 Q4 2019 2018 2019

Cdn

$/M

cf

Natural Gas Financial and Physical Price Management

Integrated Physical Marketing and Financial Risk Management StrategiesEnable ARC to Effectively Execute on Its Long-term Plans

2019 Natural Gas Flows and Sales Points (US$/MMBtu) ARC’s Natural Gas Price (4)

Initial Tie-in of ARC’s Production:• 80% through the TC Energy NGTL system• 20% through the Enbridge Westcoast system

Westcoast/NWP Alliance

TCPLMainline

GTN

Northern Border

GLGT

Station 2

$0.77

$0.17

$0.60

Malin

$2.67

$0.21

$0.48

$1.98

Chicago

$2.56

$0.21

$0.66

$1.69

Ventura

$2.53

$0.21

$0.54

$1.78

Dawn

$2.40

$0.21

$0.76

$1.43

AECO

$1.22

$0.21

$1.01

Henry Hub

Via Northern Border

Pricing Hub

Hub Market Price (1)

Field-to-Hub Transportation Cost (2)

Hub-to-Hub Transportation Cost (3)

Market Netback

(1) 2019 monthly index pricing, or daily index in the absence of a monthly index.(2) Uses a three-year average published toll including abandonment costs.(3) As per published pipeline data.(4) Realized gain on risk management contracts is not included in ARC’s realized natural gas price.

Realized Gain on Risk Management ContractsDiversification ActivitiesAverage Price before Diversification Activities

WCSB Demand & Export Capacity Growth (1) Natural Gas Diversification (2)(3)

Natural Gas Financial and Physical Price Management

Integrated Physical Marketing and Financial Risk Management StrategiesEnable ARC to Effectively Execute on Its Long-term Plans

24%

9% 3%

28%

37%37%

8%8%

12%

18%

16% 19%

10%17% 14%

8% 7% 7%

4% 6% 6%2%

Bal 2020 Cal 2021 Cal 20220%

25%

50%

75%

100%

Perc

enta

ge o

f Tot

al N

atur

al G

as P

rodu

ctio

n (%

)

(1) Source: ARC Risk Research, TC Energy, Enbridge, company reports.(2) Based on production assumptions for sanctioned projects.(3) “Hedged” includes all physical and financial fixed price swaps and collars at AECO, Station 2, and Henry Hub.

p p y

(1) Source: ARC Risk Research, TC Energy, Enbridge, company reports.(2) B d d i i f i d j

NGTL East Gate Capacity+1.3 Bcf/day by 2021

Intra-Alberta Demand+1.5 Bcf/day by 2024

LNG Canada Phase 1+2.1 Bcf/day by 2024

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/Egress Growth Expected by 2024

AECO FloatingStation 2 FloatingMidwest US Floating

HedgedMalin FloatingDawn FloatingEmpress Floating

Henry Hub Floating

02/20/2020 8

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

(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)

Emissions Management Strategy

ARC’s GHG Emissions Intensity Performance Is Industry-leading

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

esof

CO

2Eq

uiva

lent

per

boe

ARC Total ARC Sunrise

25% reduction target relative to

2017 baseline

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.

>95% reductionexpected due to plant

electrification

Emissions Management Strategy

Proactively focus on reducing GHG intensity

Set GHG emissions intensity reduction target

Incorporate emissions management solutions into project planning

02/20/2020 9

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 waterstorage capacity

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

Water Management Strategy in Action

0.0

0.5

1.0

1.5

2.0

2014 2015 2016 2017 2018 2019

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 Six Years Without a Lost-time Incident

75%Reduction

Contractor Total Recordable Incident Frequency

02/20/2020 10

Owned-and-operated Infrastructure

ARC Is Building Sustainable Businesses in the Montney and Is Increasing Its Liquids Processing Capacity

Dawson Phase III & IV

Dawson Phase I & II

Parkland/Tower Phase I

Sunrise Phase I & II

Ante Creek Phase I

NE BC

AB

Facility Investment of ~$815 million645 MMcf/day of Natural Gas Capacity33.5 Mbbl/day of Liquids Capacity

-35,000

-25,000

-15,000

-5,000

5,000

15,000

25,000

35,000

150,000,000)

100,000,000)

$50,000,000)

$0

$50,000,000

100,000,000

150,000,000

200,000,000

2018

2019

2020

F

2021

F

2022

F

2023

F

2024

F

2025

F

2026

F

2027

F

2028

F

2029

F

2030

F

Dawson Phase IV Business Model

Infrastructure Investment in Greater Dawson Area Is Supporting ARC’s Broad Shift to the Liquids-rich Lower Montney

(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 entities. Refer to “Non-GAAP Measures” in the Advisory Statements to this presentation.(2) Economics run at US$55/bbl WTI and Cdn$1.90/GJ AECO flat pricing.

Netback (1)(2)

Capital ExpendituresFacility Expenditures

ProductionNetback less Capital Expenditures -35,000

-25,000

-15,000

-5,000

5,000

15,000

25,000

35,000

150,000,000)

100,000,000)

$50,000,000)

$0

$50,000,000

100,000,000

150,000,000

200,000,000 Dawson Phase IVNatural Gas Processing Capacity: 90 MMcf/day

Condensate-handling Capacity: 7,500 bbl/day (production expected to stabilize at ~3,000 bbl/day)NGLs-handling Capacity: 3,000 bbl/day (production expected to stabilize at ~1,500 bbl/day)

~$300 MillionInitial Investment

Facility, Infrastructure, andWells to Fill Plant

Drill 8 to 10 Wells per Year45% of Netback Required to Sustain Business (2)

02/20/2020 11

Resource Potential and ScalabilityARC has:

• ~1,000 net Montney sections (~638,000 acres)

• Over 4,000 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)

In Progress

Future Development Projects

Attachie

GreaterSunrise Area

GreaterDawson Area

Ante Creek

~139 Mboe/day

Greater Dawson Area Overview

Lower Montney Focus with Dawson Phase IV Infrastructure Build-out

Snapshot Development Plan

2020 Development Focus

Infrastructure Build-out

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

Montney Natural Gas Processing Capacity

Capital Budget Expected ProductionPlanned Wells

$327 million(65%)

$500 million (1)

45 wells(69%)

65 wells (1)

88 Mboe/day• 19 Mbbl/day• 410 MMcf/day(56%)

155 to 161 Mboe/day (1)

• Complete the Dawson Phase IV project, expected to be on-stream in Q2 2020• Commence sour conversion of existing Parkland sweet facility, expected to be

completed in H1 2021• Commissioned Phase I & II liquids-handling upgrade in early Q4 2019

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

Tower

Parkland

Dawson

Pembina & EnbridgeTCPLParkland-Dawson Interconnect Pipeline

Phase I & IIGas Plants

Phase III & IVGas Plants


02/20/2020 12

Lower Montney Development and Liquids Growth

Integrated Approach to Development in the Greater Dawson Area Allows ARC to 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.(3) Internal rate of return (half-cycle after-tax rate of return) run at US$55/bbl WTI and Cdn$1.90/GJ AECO flat pricing.

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

Parkland

Dawson

2019 Lower Montney Wells2020 Lower Montney Wells

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

Phase III & IVGas Plants


100

Greater Dawson Area Lower Montney Development

• 23 Tcf (1) of resources in lowerMontney

• 105 MMbbl of contingent resourceNGLs, of which 71 MMbbl iscondensate (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 atParkland/Tower

• Prioritize wells based on return oninvestment

• Lower Montney wells have >100%IRR and one-year payout (3)

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

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

02/20/2020 13

Optimizing Dawson Lower Montney Development

Use of Technology Has Enhanced Lower Montney 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 2019Fi

ndin

g &

Dev

elop

men

t C

osts

($/b

oe)

Dawson Phase IV Update

Commissioning Activities Have Commenced with the Dawson Phase IV Facility Expected to Be On-stream in Q2 2020

Commercial and Development Execution

Regulatory Approval Secured

Takeaway Secured

Economics Robust

Facility Execution

Project Cost On budget

Safety 0 LTIs

Mechanical Work 75% complete

Electrical Work 67% complete

Commissioning Work 15% complete

Expected On-stream Q2 2020

Dawson Phase IV Project Checklist

02/20/2020 14

Existing Infrastructure 2012 Q2 2020

Ante Creek Overview

Strong Cash Flow Generating Asset with Facility’s Oil Expansion Project Planned for Q2 2020

Snapshot

Ante CreekPhase I



Ante CreekExpansion

Development Plan



• Low-risk, high netback Montney light oil development• Ante Creek facility’s oil expansion will add up to 2,500 bbl/day of light oil

production, expected to be brought on-stream in Q2 2020

$79 million(16%)

12 wells(19%)


2-26Gas Plant

10-7Gas Plant

10-36Gas Plant


$500 million (1) 65 wells (1) 155 to 161 Mboe/day (1)


2-26Gas Plant

10-7Gas Plant

10-36Gas Plant

Attachie Overview

Strong CGR of 300 Barrels per MMcf for Three Newest Wells on Production

Snapshot

Attachie West Phase I

$30 million(6%)

0 wells(0%)


Development Plan



• Four wells brought on production in Q4 2019; due to facility constraints, three of the fourwells are producing consistently• Over 90 days of production, cumulative production from the three wells is 160,000

barrels of condensate and 530 MMcf of natural gas for a CGR of 300 bbl/MMcf



(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

02/20/2020 15

0

75

150

225

300

0 350 700 1,050 1,400

Cum

ulat

ive

Con

dens

ate

Prod

uctio

n (M

bbl)

Days on Production

Continuous Improvement in Pad and Well Design

Initial Well Results from Newest Pad Are Encouraging with Average Condensate-to-gas Ratio of 300 Barrels per MMcf

Pad and Well Design Evolution Cumulative Condensate Production

(1) Due to facility constraints, only three of the four wells on 2-27 Pad Phase I have been producing consistently. Over 90 days of production, the three wells have produced approximately 160,000 barrels of condensate and approximately 530 MMcf of natural gas.

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

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

Attachie Is Being Advanced Towards Commercialization

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

Technical Commercial Funding

Strong liquids deliverability

Improved capital efficiencies

Competitor activity

Commodity egress

Regulatory

Support infrastructure

Balance sheet

Maximize profitability

Project readiness

02/20/2020 16

2015 2018 2019

Sunrise Overview

Sunrise Phase I & II Operating at Full 240 MMcf Per Day of Sales CapacityExpect Operating Area’s Operating Expense to Be Less Than $0.30 per Mcf

Snapshot

SunrisePhase I


SunrisePhase II

SunrisePhase II

$40 million(8%)

8 wells(12%)

36 Mboe/day• 217 MMcf/day(23%)

Development Plan



• Final transportation arrangements in effect at Sunrise Phase II early in Q4 2019• ARC plans to operate Sunrise Phase I & II facility at or near processing capacity

of 240 MMcf per day through 2020 depending on prevailing commodity prices





Sunset

Sunrise

76%

2%4%18%

Pembina Overview

High Working Interest Light Oil Production, Competitive Operating Netback and Strong Cash Flow Generation

Snapshot

$11 million(2%)

0 wells(0%)


Development Plan


• Manage production declines and maximize cash flow generation from light oil production

2019 Production Split(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.

10.3 Mboe/day



Berrymoor

LindaleNPCU

MIPABuckCreek

SPCUPCU7

Blue boundaries denote units.

Crude oilCondensateNGLsNatural gas

02/20/2020 17

Additional Information

2019 & 2020 Guidance

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

2019Guidance

2019Actuals

2020Guidance

Production

Crude oil (bbl/day) 17,000 - 19,000 17,591 15,000 - 17,000

Condensate (bbl/day) 9,000 - 11,000 10,066 12,000 - 14,000

Crude oil and condensate (bbl/day) 26,000 - 30,000 27,657 27,000 - 31,000

Natural gas (MMcf/day) (1) 620 - 630 623.3 715 - 725

NGLs (bbl/day) 6,500 - 7,000 7,578 8,500 - 9,000

Total production (boe/day) (1) 136,000 - 142,000 139,126 155,000 - 161,000

Expenses ($/boe)

Operating 5.00 - 5.35 4.97 4.55 - 4.95

Transportation 2.90 - 3.10 2.94 3.10 - 3.30

G&A expense before share-based compensation expense 1.10 - 1.30 1.20 1.00 - 1.20

G&A - share-based compensation expense (2) 0.20 - 0.35 0.46 0.30 - 0.45

Interest and financing (3) 0.75 - 0.90 0.81 0.65 - 0.80

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

Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 700 691.5 500(1) 2020 Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(2) Comprises expenses 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 asset retirement obligation.(4) The current income tax estimate varies depending on the level of commodity prices.

02/20/2020 18

Asset Details

Diversified Commodity Mix across Portfolio of Assets

Dawson Parkland/Tower Ante Creek Attachie Sunrise Pembina

Net production – Q4 2019Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)

4,971228.3

43,014

12,022128.7

33,464

7,47746.3

15,199

2,4109.7

4,022

76235.5

39,324

8,86611.4

10,773

LandNet sections (1)

Working interest137

~100%94

~90% / ~94%208

~100%308

~99%32

~89%217

~89%

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

7910.4410

4

4614.6186

4

209.6623

62.8173

660.3396

5

3832.7

3511

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

30051.2

1,49414

15348.962714

7838.623912

3920.511222

2342.5

1,39018

6049.9

6117

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

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

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)

Transformation of ARC’s Business

Montney Transformation Has Allowed ARC to Manage a Profitable Business through Commodity Price Cycles

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.

201930%

0

40,000

80,000

120,000

160,000

1996

1997

1998

1999

2000

2001

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

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)

0.00

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

F

Rat

io

$ m

illio

ns

Net Debt (LHS)

Funds From Operations (LHS)

Net Debt to Funds from Operations (RHS)

02/20/2020 19

(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)

Growth through Acquisition Organic Growth

150 Per Cent Reserves Replacement or Greater for 12th Consecutive Year

(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

02/20/2020 20

(100)

(50)

0

50

100

150

200

250

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

Risk Management Program

Program Executed with a Long-term View

(1) 2020 to 2024 Forecast values based on the forward price curve as at December 31, 2019, 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)

Risk Management Contract Positions

1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoffprofile 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.

Risk Management Contracts Positions at December 31, 2019 (1) 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$/bbl bbl/dayCeiling 61.59 6,500 61.92 5,500 - - - - - -Floor 54.23 6,500 54.64 5,500 - - - - - -Sold Floor 41.92 6,500 44.09 5,500 - - - - - -Swap 59.09 2,000 - - - - - - - -Sold Swaption (2) - - 60.03 2,000 - - - - - -Crude Oil – Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 86.38 6,500 - - - - - - - -Floor 75.38 6,500 - - - - - - - -Sold Floor 60.38 6,500 - - - - - - - -Total Crude Oil Volumes (bbl/day) 15,000 5,500 - - -Crude Oil - MSW (Differential to WTI) (4) US$/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 (8.31) 7,000 - - - - - - - -Natural Gas - Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 3.05 105,000 3.32 50,000 3.43 25,000 - - - -Floor 2.62 105,000 2.75 50,000 2.66 25,000 - - - -Sold Floor 2.21 105,000 2.25 50,000 2.25 25,000 - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.60 30,000 - - - - - - - -Floor 3.08 30,000 - - - - - - - -Swap 3.35 22,541 2.00 10,000 - - - - - -Sold Swaption (2) - - - - 2.00 10,000 - - - -Total Natural Gas Volumes (MMBtu/day) 154,799 59,478 25,000 - -Natural 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 (0.81) 74,262 (0.95) 54,192 (0.90) 20,000 (0.93) 50,000 (0.93) 50,000Total AECO Basis Volumes (MMBtu/day) 74,262 54,192 20,000 50,000 50,000Natural 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$/US$)

FloorCdn$/US$

Variable Rate Collar (7) August 24, 2020 24 1.2771 1.3231Interest Rate Contract Term Received Notional Amount (US$ millions) Fixed Rate Pay Notional Amount (US$ millions) Fixed RateCross Currency Swap December 2019 – January 2020 40 3.48% 52 3.14%

4) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton.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 Cdn$/US$ spot rate is below $1.2771 at expiry, the ceiling will readjust to $1.3058.

02/20/2020 21

ESG Recognitions and Rankings

Member of MSCI Global Sustainability IndexMSCI ESG Rating: AAA

Voluntary participant since 20072018 Climate Change Score: B2018 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

Best Disclosure of Corporate Governanceand Executive Compensation Practices in 2016

Reserves and Resources DisclosureAll reserves in this presentation are, unless indicated otherwise, as at December 31, 2019 as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in accordance with the

definitions, standards, and procedures contained in the COGE Handbook and NI 51-101. Resources volumes for the Montney are as at December 31, 2018 as evaluated byGLJ 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.

02/20/2020 22

Definitions of Reserves and ResourcesReserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date,based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generallyaccepted 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 are classifiedin 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 quantity ofpetroleum 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.

Forecast

Definitions of Reserves and ResourcesUndiscovered Petroleum Initially-in-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered.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 of thesequantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovereddue to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.

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

02/20/2020 23

Contact Information

For further information about ARC Resources Ltd. please visit our website www.arcresources.com.

Or contact:Investor RelationsE-mail: [email protected] 403.503.8600 F 403.509.6427Toll Free 1.888.272.4900ARC Resources Ltd.1200, 308 – 4 Avenue SWCalgary, AB T2P 0H7

Kris Bibby Martha WilmotSenior Vice President and Chief Financial Officer Investor Relations Analyst

403.503.8675 403.509.7280

[email protected] [email protected]

02/20/2020 24

Notes

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02/20/2020 25

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02/20/2020 26

FINANCIAL ANDOPERATIONAL HIGHLIGHTS

(1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled, "Funds from Operations" and “Capitalization, Financial Resourcesand 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.

($ millions, except per share amounts) 2019 2018FINANCIAL Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1Commodity sales from production 325.1 253.7 282.9 327.8 302.5 375.1 344.4 340.2

Per share, basic 0.92 0.72 0.80 0.93 0.86 1.06 0.97 0.96Per share, diluted 0.92 0.72 0.80 0.93 0.86 1.06 0.97 0.96

Net income (loss) (10.2) (57.2) 94.4 (54.6) 159.7 45.1 (45.9) 54.9Per share, basic (0.03) (0.16) 0.27 (0.15) 0.45 0.13 (0.13) 0.16Per share, diluted (0.03) (0.16) 0.27 (0.15) 0.45 0.13 (0.13) 0.16

Funds from operations (1) 172.8 145.4 193.0 186.2 208.6 205.0 204.4 201.0Per share, basic 0.49 0.41 0.54 0.53 0.59 0.58 0.58 0.57Per share, diluted 0.49 0.41 0.54 0.53 0.59 0.58 0.58 0.57

Dividends declared 53.1 53.1 53.1 53.1 53.1 53.0 53.1 53.1Per share (2) 0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15

Total assets 5,778.3 5,819.2 5,878.9 5,952.4 6,016.2 5,846.3 6,059.8 6,235.7Total liabilities 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4 2,278.3 2,485.8 2,563.8Net debt outstanding (1) 940.2 945.5 829.2 796.3 702.7 667.8 757.0 728.0Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.5 353.5 353.5Weighted average shares, diluted 353.4 353.4 353.9 353.4 353.9 354.0 353.5 353.8Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.5 353.5CAPITAL EXPENDITURESGeological and geophysical 3.7 2.7 1.3 11.9 1.3 3.4 2.1 4.0Drilling and completions 80.7 98.6 107.0 129.2 60.5 114.2 102.6 139.1Plant and facilities 56.6 60.0 65.5 72.3 69.6 51.2 58.8 70.0Corporate assets 0.7 0.6 0.4 0.3 0.2 0.5 1.3 0.6Total capital expenditures 141.7 161.9 174.2 213.7 131.6 169.3 164.8 213.7Undeveloped land — 0.7 — — 0.2 — — 0.7Total capital expenditures, including

undeveloped land purchases 141.7 162.6 174.2 213.7 131.8 169.3 164.8 214.4Acquisitions — — — 0.2 — — — 0.2Dispositions (1.1) (2.8) (0.9) (0.2) (0.9) (96.2) (0.7) (98.3)Total capital expenditures, land purchases, and

net acquisitions and dispositions 140.6 159.8 173.3 213.7 130.9 73.1 164.1 116.3OPERATINGProduction

Crude oil (bbl/d) 17,083 16,782 18,272 18,251 20,092 23,867 24,893 25,037Condensate (bbl/d) 10,937 10,846 10,230 8,210 8,458 8,158 6,960 5,505Crude oil and condensate (bbl/d) 28,020 27,628 28,502 26,461 28,550 32,025 31,853 30,542Natural gas (MMcf/d) 669.0 595.4 596.4 632.5 603.3 574.2 537.9 564.9NGLs (bbl/d) 8,123 7,952 7,041 7,183 7,402 7,687 6,380 6,332Total (boe/d) 147,650 134,813 134,938 139,054 136,502 135,410 127,879 131,016

Average realized prices, prior to risk management contractsCrude oil ($/bbl) 65.11 64.79 70.26 63.72 43.30 78.62 78.57 69.50Condensate ($/bbl) 68.08 65.70 71.38 64.81 57.25 85.28 85.10 77.42Natural gas ($/Mcf) 2.36 1.54 1.74 2.79 2.85 2.15 1.91 2.50NGLs ($/bbl) 11.69 5.25 7.71 25.43 29.12 35.26 32.98 31.39Oil equivalent ($/boe) 23.93 20.46 23.04 26.20 24.09 30.12 29.59 28.85

TRADING STATISTICS (3)

($, based on intra-day trading)High 8.26 7.85 9.61 10.49 14.84 15.90 15.25 15.90Low 5.40 5.37 6.37 7.82 7.38 12.70 12.71 11.88Close 8.18 6.31 6.41 9.12 8.10 14.40 13.58 14.04Average daily volume (thousands) 2,583 1,838 2,255 2,291 2,117 1,246 1,150 1,406

CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. Kvisle (1)

Chairman

Farhad Ahrabi (1)(2)

David R. Collyer (1)(3)

John P. Dielwart (1)(2)

Fred J. Dyment (2)(4)

Kathleen O’Neill (4)(5)

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

William G. Sembo (3)(5)

Nancy L. Smith (2)(5)

Myron M. Stadnyk(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. AndersonChief Executive OfficerMyron M. StadnykPresident

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 CALENDARMay 6, 2020Q1 2020 Results

May 7, 2020Annual Meeting

July 30, 2020Q2 2020 Results

November 5, 2020Q3 2020 Results

STOCK EXCHANGE LISTINGThe Toronto Stock ExchangeTrading Symbol: ARX

INVESTOR INFORMATIONVisit our website atwww.arcresources.comor contact:Investor 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.

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