energy for the world Investor Presentation September 2020 - - PDF document

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Creating energy for the world Investor Presentation September 2020 Advisory Statements Forward-looking Information and Statements and Advisory Statements This presentation contains forward-looking information as to ARCs internal

SLIDE 1

energy

Creating

for the world

Investor Presentation

September 2020

SLIDE 2

Advisory Statements

Forward-looking Information and Statements and Advisory Statements This 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 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, the volume 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, the volume 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 relating to 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 expenditure budgets, 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 crude

il 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 annual

and quarterly Management’s Discussion and Analysis and other continuous disclosure documents, and related to Management’s assumptions, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differ 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

therwise except as required by securities laws and regulations.

ARC has adopted the standard of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used in

isolation. A 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 ratio

based 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 indication

f 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 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”) are

disclosed. ARC’s core producing properties that are considered to be tight oil include Ante Creek and parts of Tower, and as such, crude oil, natural gas, and NGLs are disclosed. ARC’s core producing property that is considered to

be light crude oil is Pembina, and as such, crude oil, natural gas, and NGLs are disclosed. Throughout this presentation, when condensate is disclosed, it is done so as it is the product type that is measured at the first point of sale. As per the Canadian Oil and Gas Evaluation (“COGE”) Handbook, condensate is a by- product of the NGLs product type. NGLs by-products include ethane, butane, propane, and pentanes-plus (condensate). Non-GAAP Measures Throughout 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 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 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 program can impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that is commonly used by other oil and 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 preceding period end. Capital employed is the total of net debt plus shareholders’ equity. ROACE since inception is the annual average net income (loss) plus interest and total income tax expense (recovery) for the years 1996 to 2020 YTD divided 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 a measure 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 been invested 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 Snapshot Corporate Summary (1) Average daily trading volume for the six months ended August 31, 2020. (2) Market capitalization as at August 31, 2020 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 oil Condensate and pentanes plus NGLs Natural gas 159 Mboe/day 910 MMboe Attachie Greater Sunrise Area Ante Creek Greater Dawson Area Pembina AB BC ARC holds ~1,000 net Montney sections (~636,000 acres) Crude oil Condensate NGLs Natural gas Founded July 11, 1996 Ticker symbol TSX : ARX Average daily trading volume (1) 4.3 million Shares outstanding 353 million Enterprise value (2) $3.3 billion Net debt as at June 30, 2020 (3) $961.1 million Net debt to funds from operations (3)(4) 1.5 times Quarterly dividend $0.06/share Dividends paid since inception $6.6 billion

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SLIDE 3

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 brought back online due to commodity price improvement Continue to monitor operational output from areas with higher operating expense ~70% of anticipated crude oil and condensate production hedged for the remainder of 2020 Brought Dawson Phase IV

n-stream in early Q2 2020

Focus H2 2020 capital program on natural gas development activities at Dawson and Sunrise to maximize throughput during winter months ~40% of anticipated natural gas production hedged for the remainder of 2020

Light Crude Oil & Liquids Production Strategy Natural Gas Production Strategy

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SLIDE 4

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

perational 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 Sector and 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

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SLIDE 5

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
Notes are rated NAIC 2-
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 $820.3MM Drawn 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 Target Double-digit Return on Average Capital Employed After-tax Rate of Return (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

08/31/2020 4

SLIDE 6 Dividend $85MM/year Capital Expenditures Sources of Cash Dividend Sustaining Capital Discretionary Outflows

Capital Allocation Priorities and Principles

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

Funds from Operations Pay sustainable dividend and grow funds from operations per share Develop profitable projects Manage net debt to funds from

perations ratio within 1.0 to 1.5x

Maintain a low cost structure and corporate decline rate Capital Allocation Priorities Capital Allocation Principles Continue to implement physical and financial diversification strategy Inflows Outflows

Debt Reduction
Long-term

Development Investments

Share Buybacks
Dividend

Increases

Historical Capital Allocation and Outlook

ARC Anticipates to Generate Sufficient Funds from Operations in 2020 to 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

08/31/2020 5

SLIDE 7

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 123 133 139 150 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 million

Invest

Allowing ARC to:

with low operating expense

f $4.55 – $4.95/boe

Maintain Balance Sheet Strength Create Shareholder Value Advance Strong ESG Performance including Recent Publication of ESG Report

to bring Dawson Phase IV and Ante Creek expansion on-stream in Q2 and to focus on natural gas development While ensuring the safe and responsible execution of the capital program 705 – 710 MMcf/day

f natural gas production (2)

to produce

150,000 – 155,000

boe/day (2) and drill

31 gross

perated wells

33,000 – 37,500 bbl/day

f 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.

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SLIDE 8

2020 Budget of $300 Million

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

AB BC 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/day Preserve light oil production as liquids prices recover Parkland/Tower $63MM • 8 wells ~27,500 boe/day Drilling activities deferred as 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 months to capitalize on strong natural gas prices Attachie Septimus Tower Parkland Sunset Sunrise Sundown Dawson Pouce Coupe Ante Creek Pembina Attachie $30MM ~5,000 boe/day Optimize 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

AB BC Oil & Liquids Dry Gas Condensate-rich Gas (1) Subject to change based on technology and economic environment. Significant Montney Inventory (1) 1,600 3,200 4,800 6,400 Wells Drilled to YE 2019 2P Booked Locations Internal Inventory Estimate Number of Locations

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SLIDE 9

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 Montney A Montney B Montney C Montney D Montney E Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells Upper Montney Lower Montney 0.00 10.00 20.00 30.00 40.00 Ante Creek Upper Montney Tower Upper Montney Attachie West Upper Montney 0.00 0.60 1.20 1.80 2.40 Parkland-Dawson Lower Montney Dawson Upper Montney Sunrise Upper 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 at US$40 per barrel and Montney liquids break-evens run with AECO natural gas held constant at Cdn$2.00 per GJ. (2) Parkland-Dawson Lower Montney and Dawson Upper Montney break-evens denote the midpoint of a range of outcomes depending on the liquids ratio. H1 2020 Average Realized Natural Gas Price including 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 Sunrise Upper Montney Dawson Upper Montney Parkland-Dawson Lower Montney Ante Creek Middle Montney Tower Upper Montney Attachie West Upper Montney

08/31/2020 8

SLIDE 10 4 8 12 16 0% 10% 20% 30% 40% 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 Producers US Producers ARC Dawson ARC ARC Sunrise Gas ARC NE BC Oil & Gas 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 from 25 days to <10 days Continuous improvement and

ptimization of completions design

and pumping efficiency Drilling longer wells 08/31/2020 9

SLIDE 11

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 based

n 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) 100 200 300 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020F 2021F 2022F 2023F 2024F $ millions 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 5,000 10,000 15,000 20,000 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Crude Oil & Condensate Production Hedged (bbl/day) 80,000 160,000 240,000 320,000 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Natural Gas Production Hedged (MMBtu/day)

08/31/2020 10

SLIDE 12 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$/Mcf

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 Capacity Growth 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 2024 0% 25% 50% 75% 100% % of Total Production 125 250 375 500 25 50 75 100 Reserves (Bboe) Average ESG Score Average ESG Score (LHS) Reserves (RHS)

ARC’s ESG Excellence

Canadian Energy Sector Is Regulated by Some of the Highest Standards and Is a Clean, Ethical Energy Source ARC 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” (2020). Reserves as at December 31, 2019. ESG Ratings by Major Oil Producing Country (1)(2) Oil and Gas Companies’ Relative ESG Rankings (1) ARC 40 46 52 58 64 70 40 46 52 58 64 70 Social and Governance Score Environmental Score Africa Asia Canada Europe Middle East Latin America Russia United States

08/31/2020 11

SLIDE 13

Emissions Management Strategy

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

GHG Emissions Performance (Scope 1 and 2) 2019 GHG Emissions Intensity Benchmarking (1) (1) Peer group includes: BNP, BTE, CNQ, CPG, CVE, ERF, MEG, NVA, OVV, PEY, SU, TOU, VET, VII, WCP. Emissions Management Strategy

Proactively focus on reducing GHG intensity Set GHG emissions intensity reduction target Incorporate emissions management solutions into project planning

0.00 0.03 0.06 0.09 0.12 ARC 2019 ARC 2018 tCO2e/boe 0.00 0.01 0.02 0.03 0.04 300 600 900 1,200 2015 2016 2017 2018 2019 2025 Target GHG Emissions Intensity (tCO2e/boe) GHG Emissions (tCO2e) Direct Emissions Indirect Emissions GHG Emissions Intensity 20% reduction target relative to 2019 baseline

Water Management Strategy

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

Water Storage Reservoirs Dawson Parkland Sunrise 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’s

Montney operations since 2017 to add 700,000 m3 of water storage capacity

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

recycled Water Management Strategy in Action

08/31/2020 12

SLIDE 14 0.0 0.5 1.0 1.5 2.0 2014 2015 2016 2017 2018 2019 2020 YTD Total Recordable Incident Frequency

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

08/31/2020 13

SLIDE 15

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 Greater Sunrise Area Greater Dawson Area Ante Creek ~139 Mboe/day 2015 2018 2019

Sunrise Overview

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

Snapshot Sunrise Phase I Montney Natural Gas Processing Capacity Sunrise Phase II Sunrise Phase 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 Production Planned Wells (1) Denotes corporate total for capital budget, planned wells, and expected production for 2020. Phase I & II Gas Plants Sunset Sunrise $300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)

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SLIDE 16

Greater Dawson Area Overview

Large Integrated Network of Owned-and-operated Infrastructure

Snapshot Development Plan 2020 Development Focus Infrastructure Build-out 2010 2011 2013 2015 2017 Q4 2019 Q2 2020 Dawson Phase I Dawson Phase II Parkland Tower Phase I Parkland Tower Battery Upgrade Dawson Phase I & II Upgrade Dawson Phase III Dawson Phase IV Montney Crude Oil & Liquids Processing Capacity Montney Natural Gas Processing Capacity Capital Budget Expected Production Planned Wells $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

(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020. Tower Parkland Dawson Pembina & Enbridge TCPL Parkland-Dawson Interconnect Pipeline Phase I & II Gas Plants Phase III & IV Gas Plants Phase I & II Gas Plants $300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)

Lower Montney Development and Liquids Growth

Integrated Approach to Development in 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.

Parkland Dawson

2019 Lower Montney Wells 2020 Lower Montney Wells Phase II & IV Gas Plants Phase I & II Gas 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 Resource in Place Tiered Inventory Strong Return on Investment

North Dawson & Parkland

CGR: ~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

08/31/2020 15

SLIDE 17 50,000 100,000 150,000 200,000 12 24 36 48 60 Cumulative Condensate Production (bbl) 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 375 750 1,125 1,500 2017 2018 2019 Estimated Ultimate Recovery (Mboe) 2,500 5,000 7,500 10,000 2017 2018 2019 Capital Efficiency ($/boe/day) 3,500 4,000 4,500 5,000 5,500 2017 2018 2019 Well Costs ($ millions) 2 4 6 8 2017 2018 2019 Finding & Development Costs ($/boe)

08/31/2020 16

SLIDE 18

Dawson Phase IV On-stream

Commissioning Activities Completed in Q1 2020 and Facility Brought On-stream in Q2 2020 Wells 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 Creek Phase I Ante Creek Expansion Development Plan 2020 Development Focus Infrastructure Build-out

Brought Ante Creek facility expansion on-stream in Q2 2020

$65 million (22%) 7 wells (23%) ~17 Mboe/day (11%) 2-26 Gas Plant 10-7 Gas Plant 10-36 Gas Plant Capital Budget Expected Production Planned Wells (1) Denotes corporate total for capital budget, planned wells, and expected production for 2020. 2-26 Gas Plant 10-7 Gas Plant 10-36 Gas Plant $300 million (1) 31 wells (1) 150 to 155 Mboe/day (1) Montney Crude Oil & Liquids Processing Capacity Montney Natural Gas Processing Capacity

08/31/2020 17

SLIDE 19

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 2020 Development Focus Infrastructure Build-out

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

(1) (2) Denotes corporate total for capital budget, planned wells, and expected production for 2020. Existing Infrastructure Capital Budget Expected Production Planned Wells Phase I Gas Plant $300 million (2) 31 wells (2) 150 to 155 Mboe/day (2) Montney Crude Oil & Liquids Processing Capacity Montney Natural Gas Processing Capacity 4-20 Battery (3.5 Mbbl/day) Phase I Gas Plant COP Acreage Acquired from KEL (1) (1) ConocoPhillips acquired Kelt’s acreage in Q3 2020. Pembina North Montney Mainline ARC Acreage COP Acreage 75 150 225 300 350 700 1,050 1,400 Cumulative Oil & Condensate Production (Mbbl) 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) Facilityconstraints 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 Well 13-26 Well B13-26 Well 13-14 Pad Average 2-27 Pad Phase I (1) Attachie Type Curve 2019 2-27 Pad Phase II 200 metre Spacing 45 m 400 m 400 m 400 m 400 m 45 m 300 m 300 m 300 m 300 m 300 m 2018 13-14 Pad 150 metre Spacing 2019 2-27 Pad Phase I 300 metre Spacing 45 m 600 m 600 m 2017 B13-26 Well Unconstrained 2016 13-26 Well Unconstrained 02-27 A2-27 J2-27 B2-27

08/31/2020 18

SLIDE 20

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 2020 Development Focus

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 Capital Budget Expected Production Planned Wells $300 million (1) 31 wells (1) 150 to 155 Mboe/day (1) Berrymoor Lindale NPCU MIPA Buck Creek SPCU PCU7 Blue boundaries denote units. Crude oil Condensate NGLs Natural gas

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SLIDE 21

Additional Information

2020 Guidance (1)

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

2020 Guidance 2020 YTD Actuals 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.

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SLIDE 22

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 2020 Crude oil & liquids (bbl/day) Natural gas (MMcf/day) Total (boe/day) 12 243.9 40,662 10,454 342.3 67,510 10,592 121.0 30,757 7,598 40.4 14,329 1,817 7.3 3,034 7,066 11.4 8,973 Land Net sections (1) Working interest 32 ~89% 137 ~100% 94 ~90% / ~94% 206 ~100% 308 ~99% 217 ~89% PDP Reserves (MMboe) Liquids (MMbbl) Gas (Bcf) Reserves life index (Years) (2) 66 0.3 396 5 79 10.4 410 4 46 14.6 186 4 20 9.6 62 3 6 2.8 17 3 38 32.7 35 11 2P Reserves (MMboe) Liquids (MMbbl) Gas (Bcf) Reserves life index (Years) (2) 234 2.5 1,390 18 300 51.2 1,494 14 153 48.9 627 14 78 38.6 239 12 39 20.5 112 22 60 49.9 61 17 0.00 0.50 1.00 1.50 2.00 2.50 400 800 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 Ratio $ millions Net Debt (LHS) Annualized Funds From Operations (LHS) Net Debt to Annualized Funds from Operations (RHS) 0% 30% 60% 90% 120% 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 Dividends as a % of Funds from Operations Cumulative Dividends ($ billions) Cumulative Dividend (LHS) Dividends as a % of FFO (RHS)

ARC’s Business

ARC Manages a Profitable Business through Commodity Price Cycles with 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. 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)

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SLIDE 23

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. 50 100 150 200 Bal 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Cdn$ millions 3.72% US$ Note 8.21% US$ Note 5.36% US$ Note 3.31% US$ Note 3.81% US$ Note 4.49% Cdn$ Note

Risk Management Contract Positions

Risk 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/day Ceiling 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/day Ceiling 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/day Ceiling (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/day Ceiling 2.94 125,108 3.02 110,000 3.11 45,000 2.74 10,000 2.74 10,000 Floor 2.56 125,108 2.55 110,000 2.55 45,000 2.50 10,000 2.50 10,000 Sold Floor 2.17 125,108 2.10 110,000 2.18 45,000 2.10 10,000 2.10 10,000 Swap 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/day Ceiling 3.06 50,162 2.41 120,000 2.40 90,000 2.40 90,000 2.40 90,000 Floor 2.56 50,162 1.95 120,000 1.87 90,000 1.87 90,000 1.87 90,000 Swap 2.23 90,324 1.99 40,000 2.06 10,000 2.06 10,000 2.06 10,000 Sold Swaption (2)

2.00

20,000

Total Natural Gas Volumes (MMBtu/day)

271,669 261,651 139,782 104,782 104,782 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$/MMBtu MMBtu/day Sold Swap (0.85) 83,297 (0.93) 69,192 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000 Total AECO Basis Volumes (MMBtu/day) 83,297 69,192 35,000 70,000 70,000 Natural Gas – Other Basis (MMBtu/day) (Differential to Henry Hub) (6) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day Sold Swap 100,000 120,000 110,000 80,000 4,973 Foreign Exchange Contract Settlement Date Notional Amount (US$ 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 listed above 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.

08/31/2020 22

SLIDE 24 (40) 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 MMboe 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) PDP 28% PNP 2% PUD 35% Probable 35%

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 250 500 750 1,000 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2P Reserves (MMboe) Natural Gas Crude Oil & Liquids Oil 9% Condensate & Pentanes Plus 9% NGLs 6% Natural Gas 76% Proved Producing 258 MMboe Total Proved 595 MMboe Proved plus Probable Crude and Tight Oil NGLs Natural Gas 910 MMboe 83 MMbbl 134 MMbbl 4.2 Tcf 2P Reserve Life Index (2) 15.8 years TPIIP (1)(3) Tight Oil Shale Gas 14.3 billion barrels 101.8 Tcf

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SLIDE 25

ESG Recognitions and Rankings

Member of MSCI Global Sustainability Index MSCI ESG Rating: AAA Voluntary participant since 2007 2019 Climate Change Score: B 2019 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

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

Reserves and Resources Disclosure

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

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SLIDE 26

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 given date, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generally 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 will exceed 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 quantities recovered 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 and Undiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-in-Place". Resources are classified 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 quantity

f 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 be

discovered. 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 to

production. 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 established technology 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 the evaluation, 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 final conditions 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 has been 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 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 of future 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 these quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovered 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 best estimate 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. If probabilistic 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.

08/31/2020 25

SLIDE 27

Contact Information

Please Visit Our Website at www.arcresources.com

Kris Bibby Senior Vice President and Chief Financial Officer 403.503.8675 KBibby@arcresources.com Martha Wilmot Investor Relations Analyst 403.509.7280 MWilmot@arcresources.com General Investor Relations Enquiries 403.503.8600 1.888.272.4900 IR@arcresources.com

08/31/2020 26

SLIDE 28

Notes

____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________ ____________________________________________________________________________

08/31/2020 27

SLIDE 29

08/31/2020 28

SLIDE 30 (1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled "Funds from Operations" and “Capitalization, Financial Resources and Liquidity” contained within ARC’s MD&A. (2) Dividends per share are based on the number of shares outstanding at each dividend record date. (3) Trading statistics denote trading activity on the Toronto Stock Exchange only.

FINANCIAL AND OPERATIONAL HIGHLIGHTS

($ millions, except per share amounts) 2020 2019 2018 FINANCIAL Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3 Commodity 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 1.06 Per 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 45.1 Per share, basic (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45 0.13 Per share, diluted (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45 0.13 Funds from operations (1) 150.2 160.8 172.8 145.4 193.0 186.2 208.6 205.0 Per share, basic 0.42 0.46 0.49 0.41 0.54 0.53 0.59 0.58 Per 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 53.0 Per 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 5,846.3 Total liabilities 2,360.3 2,332.4 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4 2,278.3 Net debt outstanding (1) 961.1 1,079.7 940.2 945.5 829.2 796.3 702.7 667.8 Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.5 Weighted average shares, diluted 353.4 353.4 353.4 353.4 353.9 353.4 353.9 354.0 Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4 CAPITAL EXPENDITURES Geological and geophysical 3.4 6.5 0.9 1.1 0.3 9.3 0.3 1.2 Drilling and completions 31.8 131.3 86.7 101.0 110.1 144.9 77.0 126.5 Plant and facilities 8.3 25.8 47.5 51.1 56.2 53.3 41.4 31.8 Maintenance and optimization 1.4 4.4 3.0 6.2 5.8 3.4 11.7 7.1 Corporate assets (0.8) 1.8 3.6 2.5 1.8 2.8 1.2 2.7 Total capital expenditures 44.1 169.8 141.7 161.9 174.2 213.7 131.6 169.3 Undeveloped 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 Production Crude oil (bbl/day) 14,987 16,997 17,083 16,782 18,272 18,251 20,092 23,867 Condensate (bbl/day) 13,239 11,262 10,937 10,846 10,230 8,210 8,458 8,158 Crude oil and condensate (bbl/day) 28,226 28,259 28,020 27,628 28,502 26,461 28,550 32,025 Natural gas (MMcf/day) 773.3 692.2 669.0 595.4 596.4 632.5 603.3 574.2 NGLs (bbl/day) 9,405 8,152 8,123 7,952 7,041 7,183 7,402 7,687 Total (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 contracts Crude oil ($/bbl) 25.88 49.69 65.11 64.79 70.26 63.72 43.30 78.62 Condensate ($/bbl) 31.54 57.52 68.08 65.70 71.38 64.81 57.25 85.28 Natural gas ($/Mcf) 1.92 2.05 2.36 1.54 1.74 2.79 2.85 2.15 NGLs ($/bbl) 10.84 6.36 11.69 5.25 7.71 25.43 29.12 35.26 Oil 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 15.90 Low 3.64 2.42 5.40 5.37 6.37 7.82 7.38 12.70 Close 4.56 4.05 8.18 6.31 6.41 9.12 8.10 14.40 Average daily volume (thousands) 2,177 3,207 2,583 1,838 2,255 2,291 2,117 1,246

SLIDE 31

CORPORATE AND SHAREHOLDER INFORMATION

DIRECTORS Harold 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 OFFICERS Terry M. Anderson President and Chief Executive Officer Kris J. Bibby Senior Vice President and Chief Financial Officer Chris D. Baldwin Vice President, Geosciences Ryan V. Berrett Vice President, Marketing Sean R. A. Calder Vice President, Production Lara M. Conrad Vice President, Development and Planning Armin Jahangiri Vice President, Operations Lisa A. Olsen Vice President, Human Resources Grant A. Zawalsky Corporate Secretary EXECUTIVE OFFICE ARC Resources Ltd. 1200, 308 – 4th Avenue SW Calgary, Alberta T2P 0H7 T 403.503.8600 TOLL FREE 1.888.272.4900 F 403.503.8609 W www.arcresources.com TRANSFER AGENT Computershare Trust Company of Canada 600, 530 – 8th Avenue SW Calgary, Alberta T2P 3S8 T 403.267.6800 AUDITORS PricewaterhouseCoopers LLP Calgary, Alberta ENGINEERING CONSULTANTS GLJ Petroleum Consultants Ltd. Calgary, Alberta LEGAL COUNSEL Burnet Duckworth & Palmer LLP Calgary, Alberta CORPORATE CALENDAR November 5, 2020 Q3 2020 Results STOCK EXCHANGE LISTING The Toronto Stock Exchange Trading Symbol: ARX INVESTOR INFORMATION Visit our website W www.arcresources.com

r contact

Investor Relations T 403.503.8600 or TOLL FREE 1.888.272.4900 E IR@arcresources.com ARC is listed on the Jantzi Social Index; a common stock index of 60 Canadian companies that pass a set

f broadly based environmental,

social and governance rating criteria.