energy Creating
for the world
Investor PresentationMay 2020
Advisory Statements
Forward-looking Information and Statements and Advisory StatementsThis presentation contains forward-looking information as to ARC’s internal projections, expectations, or beliefs relating to future events or future performance and includes information as to ARC’s future well inventory in its coreareas, its exploration and development drilling and other exploitation plans for 2020 and beyond, and related production expectations, expenditures and cash flows, the Company’s plans for constructing and expanding facilities, thevolume of ARC's crude oil and natural gas reserves and the volume of ARC's crude oil and natural gas resources in the Montney, the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, thevolume and product mix of ARC's crude oil and natural gas production, future results from operations, and operating metrics. These statements represent Management’s expectations or beliefs concerning, among other things,future operating results and various components thereof or the economic performance of ARC. The projections, estimates, and beliefs contained in such forward-looking statements are based on Management's assumptions relatingto the production performance of ARC’s crude oil and natural gas assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital expenditurebudgets, future commodity prices, continuing access to capital, and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties, such as changes in crudeoil and natural gas prices, infrastructure constraints in relation to the development of the Montney, risks associated with the degree of certainty in resource assessments, and including the business risks discussed in ARC’s annualand quarterly Management’s Discussion and Analysis and other continuous disclosure documents, and related to Management’s assumptions, which may cause actual performance and financial results in future periods to differmaterially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differmaterially from those predicted. Other than the 2020 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in this document whether as to new information, future events, orotherwise except as required by securities laws and regulations.
ARC has adopted the standard of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used inisolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratiobased on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6 Mcf:1 bbl conversion ratio, utilizing the 6 Mcf:1 bbl conversion ratio may be misleading as an indicationof value.
Throughout this presentation, crude oil refers to tight, light, medium, and heavy crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). ARC’s production ofheavy crude oil is considered to be immaterial. Natural gas refers to shale gas and conventional natural gas product types as defined by NI 51-101. ARC’s production of conventional natural gas is considered to be immaterial.ARC’s core producing properties that are considered to be shale gas include Attachie, Dawson, Parkland (including parts of Tower), and Sunrise, and as such, natural gas, condensate, and natural gas liquids (“NGLs”) aredisclosed. ARC’s core producing properties that are considered to be tight oil include Ante Creek and parts of Tower, and as such, crude oil, natural gas, and NGLs are disclosed. ARC’s core producing property that is considered tobe light crude oil is Pembina, and as such, crude oil, natural gas, and NGLs are disclosed.
Throughout this presentation, when condensate is disclosed, it is done so as it is the product type that is measured at the first point of sale. As per the Canadian Oil and Gas Evaluation (“COGE”) Handbook, condensate is a by-product of the NGLs product type. NGLs by-products include ethane, butane, propane, and pentanes-plus (condensate).
Non-GAAP MeasuresThroughout this presentation, ARC uses the terms netback and return on average capital employed (“ROACE”) to analyze financial and operational performance. These non-GAAP measures do not have any standardized meaningprescribed under International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures presented by other issuers.
Netback
ARC calculates netback on a total and per boe basis as commodity sales from production less royalties, operating, and transportation expense. ARC discloses netback both before and after the effect of realized gain or loss on riskmanagement contracts. Realized gain or loss represent the portion of risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent measuresthat reflect how ARC’s risk management program can impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that iscommonly used by other oil and gas producers. The measurement on a per boe basis assists Management with evaluating operational performance on a comparable basis.
Return on Average Capital Employed
ARC calculates ROACE, expressed as a percentage, as net income (loss) plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months precedingperiod end. Capital employed is the total of net debt plus shareholders’ equity. ROACE since inception is the annual average net income (loss) plus interest and total income tax expense (recovery) for the years 1996 to 2020 YTDdivided by the average of the opening and closing capital employed over the same period. Refer to the "Capital Management" note in ARC’s financial statements for additional discussion on net debt. ARC uses ROACE as ameasure of long-term operational performance, to measure how effectively Management utilizes the capital it has been provided and to demonstrate to shareholders the sustainability of its business model and that capital has beeninvested profitably over the long term.
11% 8%5%
76%
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
Asset SnapshotCorporate Summary
(1) Average daily trading volume for the six months ended May 6, 2020.(2) Market capitalization as at May 6, 2020 and net debt as at March 31, 2020.(3) Refer to the “Capital Management” note in ARC’s financial statements.(4) Based on net debt as at March 31, 2020 and annualized funds from operations for the three months ended March 31, 2020.
Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 5.6 millionShares outstanding 353 millionEnterprise value (2) $3.1 billionNet debt at March 31, 2020 (3) $1,079.7 millionNet debt to funds from operations (3)(4) 1.7 timesQuarterly dividend $0.06/share
Q1 2020 Production 2019 Proved + Probable Reserves
Crude oilCondensate and pentanes plusNGLsNatural gas
152 Mboe/day 910 MMboe
Attachie
GreaterSunrise Area
Ante Creek
GreaterDawson Area
Pembina
ABBC ARC holds ~1,000 net Montney sections (~636,000 acres)
Crude oilCondensateNGLsNatural gas
05/06/2020 1
Corporate Strategy
ARC’s Consistent Strategy Is Steadfast amid Uncertain Economic Environmentand Remains Focused on Long-term Corporate Profitability
RISK-MANAGED
VALUECREATION
HIGH-QUALITYASSETS &
OPERATIONAL EXCELLENCE
FINANCIALSUSTAINABILITY &
RETURN ONINVESTMENT
HIGHPERFORMANCE
PEOPLE &CULTURE
COMMERCIALACTIVITIES &
RISKMANAGEMENT
Current Commodity Price Environment
ARC Is Actively Managing Its Production Based on Prevailing Commodity Prices
Natural Gas Production Strategy Crude Oil & Liquids Production Strategy Corporate Production
0
40
80
120
160
Q1 2020Production
Shut-inProduction
DawsonPhase IV
Aver
age
Dai
ly P
rodu
ctio
n (M
boe/
day)
Reduce operational outputfrom areas with higher
operating expense
Preserve liquids production and netback until commodity
prices recover
~70% of anticipatedcrude oil and condensate production hedged for the
remainder of 2020
Bring Dawson Phase IVon-stream
Maximize low-cost Montney natural gas production
~40% of anticipatednatural gas production hedged
for the remainder of 2020
05/06/2020 2
Capital Budget and Dividend
ARC Is Positioned to Endure This Period of Economic Uncertainty and Remain in a Position of Financial Strength
2020 Capital Budget Reduced by 40% Dividend Reduced by 60% Business Sustainability
Original Budget Reduced Budget Original Dividend Reduced Dividend
< $300 million
$500 million$0.05 per Share
(Monthly)
$0.06 per Share(Quarterly)
Low cost structure and operational flexibility
Commodity optionality and robust market
diversification activities
Invest in profitable growth when it makes
sense to do so
Strong balance sheet with ample liquidity
Maintaining Financial Strength
ARC Has One of the Strongest Balance Sheets in the Sectorand Targets Its Net Debt to Funds from Operations to Be between 1.0 and 1.5 Times over the Long Term
ARC
ARC
(1) Source: RBC Capital Markets. Consensus estimates as per FactSet on April 23, 2020
US Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)
Canadian Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)
1.3 1.3 1.5 1.5 1.8 2.2 2.2 2.3 2.7 2.9 2.9 3.2 3.5 3.5 3.6 3.7 3.9 4.1 4.5 4.6 4.6 5.7 5.8 6.6 7.3
10.0
Group Average
0.7 0.9 1.3 1.4 1.5 1.8 2.0 2.0 2.1 2.4 2.8 3.3 3.4 3.7 3.7 4.0 4.0 4.2 4.7 4.8 5.0 5.5 5.5 5.8 7.2 7.7
9.7
Group Average
05/06/2020 3
Significant Liquidity
ARC Has Ample Liquidity to Sustain Its Business
(1) As at March 31, 2020.(2) Assumes Cdn$/US$ of $1.4120.(3) Credit Facility includes $40 million working capital facility.(4) Non-cash working capital not included.
Undrawn Master Shelf
$292MM
Cash$9MM
Undrawn Credit Facility
$901MM
Master Shelf$194MM
Long-term Notes$595MM
Credit Facility$89MM
$2.2 Billion Total Cash & Existing Credit Capacity($1.2 Billion Available) (1)(2)(3)(4)
Bank Credit Facility• $950 million committed credit facility plus $40
million••• Credit facility
Long-term Notes & Master Shelf•• Private Placement market•• Repayments structured to mature over a number of years
to reduce financing risk
Undrawn Master Shelf
$318MM
Cash & Cash Equivalents
$6MM
Undrawn Credit Facility
$868MMDrawn Master Shelf
$212MM
Long-term Notes$644MM
Drawn Credit Facility$122MM
$2.2 Billion Total Cash & Existing Credit Capacity($1.2 Billion Available) (1)(2)(3)(4)
Cash & Existing Credit Capacity
Long-term Corporate Profitability
ARC Has Delivered a ~9% ROACE since Inception
(1) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. Refer to “Non-GAAP Measures” in the Advisory Statements to this presentation.
Return on Average Capital Employed (1) Delivering Full-cycle Asset Level Returns
Single-well Economics(Half-cycle)
Proportional Facility and Appropriate
Timing Included:Project
Economics(Full-cycle)
Corporate Costs
TargetDouble-digit
Return on AverageCapital Employed
Afte
r-ta
x R
ate
of R
etur
n
(20%)
(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
2020
YTD
ROACE Trailing Three-year ROACE
05/06/2020 4
Dividend$85MM/year
Capital Expenditures
Sources of Cash Dividend Sustaining Capital DiscretionaryOutflows
Capital Allocation Priorities and Principles
Protect the Balance Sheet, Support the Dividend, Prioritize Capital Investments That Drive Long-term Value and Profitability
Funds fromOperations
Pay meaningful dividend and grow funds from operations per share
Develop profitable projects
Manage net debt to funds from operations ratio within 1.0 to 1.5x
Maintain a low cost structure andcorporate decline rate
Capital Allocation Priorities Capital Allocation Principles
Continue to implement physicaland financial diversification strategyInflows Outflows
•Debt Reduction•Long-termDevelopmentInvestments
•Share Buybacks•DividendIncreases
Historical Capital Allocation and Outlook
ARC Anticipates to Generate Surplus Funds from Operations That Will Fund Its Dividend and Capital Requirements in 2020
2016 to 2019 Capital Allocation 2020 Forecasted Capital Allocation
Inflows Outflows
Funds from Operations Net A&D Proceeds Dividend Capital Expenditures
Inflows Outflows
05/06/2020 5
ARC’s Vision for the Future
ARC Has Moved Towards a Larger Production Base with Lower Capital Expenditures
Production (Mboe/day)
Capital Expenditures ($ millions)830
679 692
<300
2017 2018 2019 2020F Capital Expenditures
123133
139
150 to 155
2017 2018 2019 2020F Production Base
2020 Guidance (1)
Reducing Capital Expenditures by 57% and Delivering 10% Increase in Production Relative to 2019
Invest up to$300 million
Allowing ARC to:
with low operating expense of $4.55 – $4.95/boe
Maintain Balance Sheet StrengthCreate Shareholder ValueAdvance Strong ESG Performance including Publication of ESG Report in Q3 2020
to bring Dawson Phase IV andAnte Creek expansion on-stream in Q2 and to focus on dry gas development
While ensuring the safe and responsibleexecution of the capital program
705 – 710 MMcf/dayof natural gas production (2)
to produce150,000 – 155,000boe/day (2)
and drill
31 grossoperated wells
33,000 – 37,500 bbl/dayof liquids production
(1) Given ongoing uncertainty, continued market volatility, and the potential for both voluntary and involuntary production curtailments over the coming months, there is considerable uncertainty embedded into ARC’s 2020 guidance items.(2) Does not incorporate the potential impact that third-party transportation restrictions may have on ARC’s natural gas production.
05/06/2020 6
2020 Budget of up to $300 Million
Dawson Phase IV and Ante Creek Facility Expansion Completed in Q1 2020Most Significant Amount of Remaining Capital Being Directed at Low-cost Sunrise Natural Gas Property
ABBC
Ante Creek$65MM • 7 wells~17,000 boe/day
Expansion at Ante Creek facility brought on-stream in
Q2 2020
Pembina$8MM
~10,000 boe/dayPreserve light oil production
until commodity prices recover
Parkland/Tower$63MM • 8 wells~27,500 boe/day
Drilling and completions activities deferred until
commodity prices recover
Dawson$87MM • 9 wells~56,000 boe/day
Phase IV facility broughton-stream in Q2 2020;
maximize natural gas production
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
Maximize natural gas production through
owned-and-operated facilities
Attachie
Septimus
Tower
ParklandSunsetSunrise
Sundown
Dawson
Pouce Coupe
Ante Creek
Pembina
Attachie$30MM
~5,000 boe/dayOptimize pad profitability
with implementation of next generation of well design
World-class Montney Resource
ARC Has Identified over 4,500 Future Drilling Locations across Its Montney Assets
Montney Optionality
• Geographic Optionality• Egress Optionality• Commodity Optionality• Multi-layer Optionality
ABBC
Oil & Liquids
Dry Gas
Condensate-rich Gas
(1) Subject to change based on technology and economic environment.
Significant Montney Inventory (1)
0
1,600
3,200
4,800
6,400
Wells Drilled to YE 2019 2P Booked Locations Internal Inventory Estimate
Num
ber o
f Loc
atio
ns
05/06/2020 7
Multiple Layers to Develop
Up to 1,000 Feet Thick, ARC’s Montney Assets Have Significant Future Delineation Opportunities
Attachie Septimus Sunrise Tower Parkland Dawson Pouce Coupe
MontneyA
Montney B
Montney C
Montney D
Montney E
Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells
Upp
er M
ontn
eyLo
wer
Mon
tney
0.00
12.50
25.00
37.50
50.00
Ante CreekUpper Montney
TowerUpper Montney
Attachie WestUpper Montney
0.00
0.60
1.20
1.80
2.40
Parkland-DawsonLower Montney
DawsonUpper Montney
SunriseUpper Montney
Top-tier Montney Economics
Low Cost Structure Supports Strong Economics in Stable Pricing Environment
Montney Natural Gas Break-evens (Cdn$/Mcf) (1)(2) Montney Liquids Break-evens (US$/bbl) (1)(2)
Q1 2020 Average Realized Natural Gas Price: $2.05/Mcf
(1) Break-even prices are Cdn$ 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.
Q1 2020 Average Realized Natural Gas Priceincluding Gain on Risk Management Contracts: $2.14/Mcf Q1 2020 Average Realized Condensate Price: $43.35/bbl
Q1 2020 Average Realized Crude Oil Price: $36.94/bbl
SunriseUpper Montney
DawsonUpper Montney
Parkland-DawsonLower Montney
Ante CreekMiddle Montney
TowerUpper Montney
Attachie WestUpper Montney
05/06/2020 8
0
8
16
24
32
0
4
8
12
16
(1) Source: Peters & Co. 2019 E&P Reserves Comparative (April 7, 2020).(2) Refer to ARC’s Annual Information Form for information pertaining to ARC’s finding and development costs.(3) Three-year PDP FD&A Costs peer group includes: BNP, BTE, CPG, PEY, POU, TOU, VET, VII, WCP.(4) 2019 Operating Expense from company reports and represent data for the year ended December 31, 2019.(5) 2019 Operating Expense peer group includes: BNP, BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(6) Source: Peters & Co. Limited E&P Overview Tables (April 27, 2020). Peer group includes APA, AR, COG, DVN, EOG, FANG, OVV, PEY, PXD, TOU, VII.
Cost Management & Decline Rate
Low-cost Producers with a Low Decline Rate Deliver Superior Returns over Time
Group Average
ARC
Group Average
Three-year PDP FD&A Costs ($/boe) (1)(2)(3) 2019 Operating Expense ($/boe) (4)(5) 2020E Corporate Decline Rates (6)
ARC
Canadian ProducersUS Producers
ARC
Daw
son
ARC
ARC
Sun
rise
Gas
ARC
NE
BC
Oil
& G
as
0%
12%
24%
36%
48%
Group Average
Risk Management Program
Program Executed with a Long-term View
(1) 2020 Forecast values based on actuals for the three months ended March 31, 2020 and forecast for April through December 2020 based on the forward strip pricing curve as at March 31, 2020 (net of credit adjustment). 2021 to 2024 Forecast valuesbased on the forward strip pricing curve as at March 31, 2020 (net of credit adjustment).
(2) Refer to the “Financial Instruments and Market Risk Management” note in ARC’s financial statements and the section entitled, “Risk Management” contained within ARC’s MD&A.(3) Realized pricing is based on annual average settlements.
WTI (3)
US$/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)
(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
05/06/2020 9
Financial Price Management
Hedging Program Continues to Mitigate Volatility in Funds from Operations
~70% of Crude Oil & Condensate Hedged for the Balance of 2020 ~40% of Natural Gas Hedged for the Balance of 2020
0
5,000
10,000
15,000
20,000
Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021
Cru
de O
il &
Con
dens
ate
Prod
uctio
n H
edge
d (b
bl/d
ay)
0
80,000
160,000
240,000
320,000
Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021N
atur
al G
as P
rodu
ctio
n H
edge
d (M
MBt
u/da
y)
2.04 2.17 1.65 1.72 2.13
0.19 0.39
0.72 0.40
(0.08)
0.92 0.78 0.81
0.44 0.09
3.15 3.34 3.18
2.56 2.14
(1.00)
0.00
1.00
2.00
3.00
4.00
2016 2017 2018 2019 Q1 2020
Cdn
$/M
cf
Natural Gas Financial and Physical Price Management
ARC Is Increasing Its Exposure to Local Pricing Given Structural Improvements to WCSB
ARC’s Natural Gas Price and Diversification (2)(3)(4)WCSB Demand & Export Capacity Growth (1)WCSB Demand & Export Capacity Growth (1)
NGTL East Gate Capacity+1.3 Bcf/day by 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 & Export CapacityGrowth Expected by 2024
(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
35% 34%17% 12% 12%
19% 14%
23% 29% 34%
12%14%
14% 15%15%
16%15%
18% 13%13%
7% 10% 13% 17% 8%
7% 7% 7% 7% 11%
4% 6% 6% 5% 5%2% 2% 2%
Bal 2020 Cal 2021 Cal 2022 Cal 2023 Cal 20240%
25%
50%
75%
100%
% o
f Tot
al P
rodu
ctio
n Dawn Floating
Malin Floating
Henry Hub Floating
Midwest US Floating
AECO Floating
Station 2 Floating
Hedged
Empress Floating
05/06/2020 10
ARC’s ESG Excellence
Canadian Energy Sector Is Regulated by Some of the Highest Standards and Is a Clean, Ethical Energy SourceARC Ranks among the Highest in the World on Sustainability Performance
(1) Source: BMO Capital Markets; Yale Environmental Performance Index (EPI); Social Progress Imperative; Worldbank Worldwide Governance Indicators, BMO Capital Markets; Bloomberg; CSRHub. For presentation, an equal weight (1/3) of each index is represented.
(2) Source: BP “Statistical Review of World Energy” (2019). Reserves as at December 31, 2018.
ESG Ratings by Major Oil Producing Country (1)(2) Oil and Gas Companies’ Relative ESG Rankings (1)
ARC
40
46
52
58
64
70
40 46 52 58 64 70
Soci
al a
nd G
over
nanc
e Sc
ore
Environmental Score
Africa
Asia
Canada
Europe
Middle East
Latin America
Russia
United States
0
125
250
375
500
0
25
50
75
100
Res
erve
s (B
boe)
Aver
age
ESG
Sco
re
Average ESG Score (LHS) Reserves (RHS)
>95% reduction expected due to plant
electrification
25% reduction target relative to
2017 baseline
Emissions Management Strategy
ARC Expects to Significantly Exceed Its 25 Per Cent GHG Emissions Intensity Reduction Target
GHG Emissions Intensity Performance (Scope 1 and 2)
2018 GHG Emissions Intensity Benchmarking (1)
0.00
0.01
0.02
0.03
0.04
2014 2015 2016 2017 2018 2019F 2021Target
Tonn
es o
f CO
2Eq
uiva
lent
per
boe
ARC Total ARC Sunrise
0.00
0.03
0.06
0.09
0.12
ARC
Sun
rise
ARC
BC
ARC
Tot
al
Tonn
es o
f CO
2Eq
uiva
lent
pe
r boe
(1) Peer group includes: BNP, BTE, CNQ, CPG, CVE, ERF, MEG, NVA, OVV, PEY, SU, VET, VII, WCP.
Emissions Management Strategy
Proactively focus on reducing GHG intensity
Set GHG emissions intensity reduction target
Incorporate emissions management solutions into project planning
05/06/2020 11
Water Management Strategy
ARC’s Water Management Strategy Is Centred around Responsibility, Sustainability, and Profitability
Water Storage Reservoirs
Dawson
ParklandSunrise
Ante Creek
Water Management Strategy
Responsibly manage water use in operations
Evaluate technologies and procedures to implement best practices
Water strategy key in long-term planning
• $55 million of water infrastructure investments in ARC’sMontney operations since 2017 to add 700,000 m3 of water storage capacity
• Freshwater usage reduced by 25 per cent from 2017 to 2018
Water Management Strategy in Action
0.0
0.5
1.0
1.5
2.0
2014 2015 2016 2017 2018 2019 2020 YTD
Tota
l Rec
orda
ble
Inci
dent
Fre
quen
cy
Strong Safety Performance
• Strong safety performance is the result of well-planned and executed operations and alignment with strong service providers
ARC Employees Have Gone Six Years Without a Lost-time Incident
50%Reduction
Contractor Total Recordable Incident Frequency
05/06/2020 12
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
Ante Creek Phase I
NE BC
AB
Core Montney:• Facility Investment of ~$815 million• 645 MMcf/day of Natural Gas Capacity
33.5 Mbbl/day of Liquids Capacity
Resource Potential and Scalability
ARC has:
• ~1,000 net Montney sections (~636,000 acres)
• Over 4,500 future drilling locations identified across the Montney
• Commodity, geographic, and multi-layer optionality
Scalability Allows for Profitable Growth to Generate Sustainable Funds from Operations and Maintain Financial Strength
2019
Base Production (Montney & Cardium)
Dawson Phase IV & Ante Creek Expansion
Future Development Projects
Attachie
GreaterSunrise Area
GreaterDawson Area
Ante Creek
~139 Mboe/day
05/06/2020 13
2015 2018 2019
Sunrise Overview
Maximizing Low-cost Dry Gas Production to Capitalize on Strong Natural Gas Pricing
Snapshot
SunrisePhase I
Montney Natural Gas Processing Capacity
SunrisePhase II
SunrisePhase II
$35 million(12%)
7 wells(23%)
~36 Mboe/day(24%)
Development Plan
2020 Development Focus
Infrastructure Build-out
• Operate Sunrise Phase I & II facility at or near processing capacity of 240 MMcf per day through 2020 to capitalize on strong natural gas pricing
• Expect area’s operating expense to be less than $0.30 per Mcf
Capital Budget Expected ProductionPlanned Wells
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
Phase I & IIGas Plants
Sunset
Sunrise
<$300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)
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
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
$150 million(50%)
17 wells(55%)
~83.5 Mboe/day(55%)
• Completed the Dawson Phase IV project which was brought on-stream inQ2 2020
• Maximize natural gas production to capitalize on strong natural gas prices
(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
Phase I & IIGas Plants
<$300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)
05/06/2020 14
Lower Montney Development and Liquids Growth
Integrated Approach to Development in Greater Dawson Area Allows ARCto Optimize Infrastructure Capacities to Maximize Profitability
(1) Total Petroleum Initially-in-Place as at December 31, 2018.(2) NGLs volumes are Unrisked Best Estimate Economic Contingent Resource as at December 31, 2018.
Parkland
Dawson
2019 Lower Montney Wells2020 Lower Montney Wells
Phase III & IVGas Plants
Phase I & IIGas Plants
100
Greater Dawson Area Lower Montney Development
• 23 Tcf (1) of resources in lower Montney
• 105 MMbbl of contingent resource NGLs, of which 71 MMbbl is condensate (1)(2)
Large Resourcein Place
Tiered Inventory
Strong Return on Investment
• North Dawson & ParklandCGR: ~150 bbl/MMcf
• Core Dawson CGR: ~40 bbl/MMcf• 300+ drilling locations at Dawson
250+ drilling locations at Parkland/Tower
• Prioritize wells based on return on investment
• Lower Montney wells have strong IRR and one-year payout
Free Condensate-to-gas Ratio (bbl/MMcf)
0
50,000
100,000
150,000
200,000
0 12 24 36 48 60
Cum
ulat
ive
Con
dens
ate
Prod
uctio
n (b
bl)
Months on Production
Greater Dawson Area Strong Condensate Results
Strong Range of Condensate Outcomes from Both Upper and Lower Montney Development
Greater Dawson Area Condensate Performance
Type Curve
NGLs[C2,C3,C4]EUR (Mbbl)
Condensate EUR (Mbbl)
Natural Gas
EUR (Bcf)
Upper Montney Low End 10 30 7.3
Upper Montney High End 105 85 5.9
Lower Montney Low End 110 100 6.0
Lower Montney High End 80 240 2.4
Lower Montney Range
Upper Montney Range
05/06/2020 15
Optimizing Dawson Lower Montney Development
Technology Has Enhanced Profitability through Improved EURs, Better Capital Efficiency, and Lower F&D Costs
Estimated Ultimate Recovery Capital Efficiency
Well Costs Finding and Development Costs
0
375
750
1,125
1,500
2017 2018 2019
Estim
ated
Ulti
mat
e R
ecov
ery
(Mbo
e)
0
2,500
5,000
7,500
10,000
2017 2018 2019
Cap
ital E
ffici
ency
($
/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 On-stream
Commissioning Activities Completed in Q1 2020 and Facility Brought On-stream in Q2 2020
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
05/06/2020 16
Existing Infrastructure 2012 Q2 2020
Ante Creek Overview
Low-risk Montney Light Oil Development
Snapshot
Ante CreekPhase I
Ante CreekExpansion
Development Plan
2020 Development Focus
Infrastructure Build-out
• Completed Ante Creek facility expansion which was brought on-stream inQ2 2020
• Preserve light oil production until prices recover
$65 million(22%)
7 wells(23%)
~17 Mboe/day(11%)
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
Capital Budget Expected ProductionPlanned Wells
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
<$300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
Attachie Overview
Strong CGR of 300 Barrels per MMcf for Three Newest Wells on Production
Snapshot
Attachie West Phase I
$30 million(10%)
0 wells(0%)
~5 Mboe/day(3%)
Development Plan
2020 Development Focus
Infrastructure Build-out
• Three wells from Attachie 2-27 Phase I pad have cumulatively produced 250,000 barrels of condensate and 815 MMcf of natural gas over 140 days of production
• Solution has been put in place to address the minimal amounts of sour gas that was being observed
(1)(2) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
Existing Infrastructure
Capital Budget Expected ProductionPlanned Wells
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
<$300 million (2) 31 wells (2) 150 to 155 Mboe/day (2)
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
05/06/2020 17
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 Have Validated Pad and Well Design Changes
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 140 days of production, the three wells have produced approximately 250,000 barrels of condensate and approximately 815 MMcf of natural gas.
16-16 Well13-26 WellB13-26 Well13-14 Pad Average2-27 Pad Phase I Average (1)
Attachie Type Curve
20192-27 Pad Phase II
200 metre Spacing45 m
400 m 400 m
400 m 400 m
45 m
300 m 300 m 300 m
300 m 300 m2018
13-14 Pad150 metre Spacing
20192-27 Pad Phase I
300 metre Spacing45 m
600 m
600 m
2017B13-26 Well
Unconstrained
201613-26 Well
Unconstrained
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
05/06/2020 18
75%
2%4%19%
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 until prices recover
Q1 2020 Production Split(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
10.5 Mboe/day
Capital Budget Expected ProductionPlanned Wells
<$300 million (1) 31 wells (1) 150 to 155 Mboe/day (1)
Berrymoor
LindaleNPCU
MIPABuckCreek
SPCUPCU7
Blue boundaries denote units.
Crude oilCondensateNGLsNatural gas
Additional Information
05/06/2020 19
2020 Guidance (1)
2020 Capital Program Was Reduced to Protect ARC’s Strong Balance Sheet
2020 OriginalGuidance
2020 Revised Guidance
2020 YTDActuals
Production
Crude oil (bbl/day) 15,000 - 17,000 14,000 - 16,000 16,997
Condensate (bbl/day) 12,000 - 14,000 11,000 - 13,000 11,262
Crude oil and condensate (bbl/day) 27,000 - 31,000 25,000 - 29,000 28,259
Natural gas (MMcf/day) (2) 715 - 725 705 - 710 692.2
NGLs (bbl/day) 8,500 - 9,000 8,000 - 8,500 8,152
Total production (boe/day) (2) 155,000 - 161,000 150,000 - 155,000 151,783
Expenses ($/boe)
Operating 4.55 - 4.95 4.55 - 4.95 4.40
Transportation 3.10 - 3.30 3.10 - 3.30 2.85
G&A expense before share-based compensation expense 1.00 - 1.20 1.00 - 1.20 1.22
G&A - share-based compensation expense (3) 0.30 - 0.45 0.30 - 0.45 (0.11)
Interest and financing (4) 0.65 - 0.80 0.65 - 0.80 0.77
Current income tax expense (recovery) as a per cent of funds from operations (5) (2) - 3 (2) - 3 (2)
Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 500 300 169.8(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) 2020 Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(3) 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.(4) Excludes accretion of asset retirement obligation.(5) The current income tax estimate varies depending on the level of commodity prices.
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 – Q1 2020Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)
28255.3
42,571
7,290237.8
46,926
10,397126.1
31,410
7,80443.4
15,038
2,1738.1
3,523
8,53112.0
10,538
LandNet sections (1)
Working interest32
~89%137
~100%94
~90% / ~94%205
~100%308
~99%217
~89%
PDP Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)
660.3396
5
7910.4410
4
4614.6186
4
209.6623
62.8173
3832.7
3511
2P Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)
2342.5
1,39018
30051.2
1,49414
15348.962714
7838.623912
3920.511222
6049.9
6117
05/06/2020 20
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
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)
0.00
0.50
1.00
1.50
2.00
2.50
0
400
800
1,200
1,600
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
YTD
Rat
io
$ m
illio
ns
Net Debt (LHS)
Annualized Funds From Operations (LHS)
Net Debt to Annualized Funds from Operations (RHS)
0%
30%
60%
90%
120%
0
2
4
6
8
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
YTD
Div
iden
ds a
s a
% o
f Fun
ds fr
om O
pera
tions
Cum
ulat
ive
Div
iden
ds ($
bill
ions
)
Cumulative Dividend (LHS)
Dividends as a % of FFO (RHS)
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 US$/Cdn$ exchange rate of 1.412 at March 31, 2020.
0
50
100
150
200
2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
$ m
illio
ns
05/06/2020 21
Risk Management Contract PositionsRisk Management Contracts Positions at May 6, 2020 (1) Q2 to Q4 2020 2021 2022 2023 2024
Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling 56.21 8,282 57.29 7,992 - - - - - -Floor 47.94 8,282 50.35 7,992 - - - - - -Sold Floor 41.92 6,500 40.23 7,992 - - - - - -Swap 45.96 3,782 35.05 1,000 - - - - - -Sold Swaption (2) - - 54.32 3,008 - - - - - -Crude Oil – Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 86.38 6,500 - - - - - - - -Floor 75.38 6,500 - - - - - - - -Sold Floor 60.38 6,500 - - - - - - - -Total Crude Oil Volumes (bbl/day) 18,564 8,992 - - -Crude Oil - MSW (Differential to WTI) (4) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling (7.00) 1,000 - - - - - - - -Floor (10.20) 1,000 - - - - - - - -Swap (8.21) 7,000 - - - - - - - -Natural Gas - Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 2.93 128,345 3.02 110,000 3.11 45,000 2.74 10,000 2.74 10,000Floor 2.55 128,345 2.55 110,000 2.55 45,000 2.50 10,000 2.50 10,000Sold Floor 2.17 128,345 2.10 110,000 2.18 45,000 2.10 10,000 2.10 10,000Swap 1.86 13,382 - - - - - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.08 50,109 2.41 120,000 2.39 85,000 2.39 85,000 2.39 85,000Floor 2.56 50,109 1.95 120,000 1.86 85,000 1.86 85,000 1.86 85,000Swap 2.20 95,673 1.99 40,000 2.06 10,000 2.06 10,000 2.06 10,000Sold Swaption (2) - - - - 2.00 20,000 - - - -Total Natural Gas Volumes (MMBtu/day) 279,902 261,651 135,043 100,043 100,043Natural Gas - AECO Basis (Differential to Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/daySold Swap (0.84) 77,782 (0.93) 69,192 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000Total AECO Basis Volumes (MMBtu/day) 77,782 69,192 35,000 70,000 70,000Natural Gas – Other Basis (MMBtu/day)
(Differential to Henry Hub) (6) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 100,000 120,000 110,000 80,000 4,973
Foreign Exchange Contract Settlement Date Notional Amount (US$ millions) Ceiling(Cdn$/US$)
FloorCdn$/US$
Variable Rate Collar (7) August 24, 2020 24 1.2771 1.3231
1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listedabove does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. Allpositions 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.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.
(40)
0
40
80
120
160
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MM
boe
Reserves Replacement - Development Reserves Replacement - Net Acquisitions & Dispositions Reserves Replacement - Total Production
Produced Reserves Replacement
• Strong 2019 development 2P reserve adds, with 164 per cent of produced reserves replaced• Finding and development costs of $4.82/boe for proved plus probable reserves and $9.74/boe for total proved reserves (2)
150 Per Cent Reserves Replacement or Greater for 12th Consecutive Year
Growth through Acquisition Organic Growth
(1) 1997 to 2002 reserves data is based on company interest established reserves (proved plus 50 per cent of probable reserves). 2003 to 2019 reserves data is based on gross interest proved plus probable reserves.(2) Includes future development capital.
Annual Produced Reserves Replacement (1)
05/06/2020 22
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
ESG Recognitions and Rankings
Member of MSCI Global Sustainability IndexMSCI ESG Rating: AAA
Voluntary participant since 20072019 Climate Change Score: B2019 Water Security Score: B
Member of Sustainalytics’ Jantzi Social Index
Member of FTSE Russell’s FTSE4Good Index Series since 2018
Member of the 30% Club since 2018
Best Disclosure of Corporate Governanceand Executive Compensation Practices in 2016
05/06/2020 23
Reserves and Resources Disclosure
All reserves in this presentation are, unless indicated otherwise, as at December 31, 2019 as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in accordance with thedefinitions, standards, and procedures contained in the COGE Handbook and NI 51-101. Resources volumes for the Montney are as at December 31, 2018 as evaluatedby GLJ in accordance with the definitions, standards, and procedures contained in the COGE Handbook and NI 51-101 .
TPIIP, DPIIP, and UPIIP have been estimated using a one per cent porosity cut-off for shale gas and tight oil.Reserves volumes for ARC’s Montney assets and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for the
Montney in this presentation are “Best Estimates”.All reserves and resources volumes for the Montney and elsewhere in this presentation are company gross.Gas volumes are “sales” for reserves and resource and raw gas for DPIIP and TPIIP.The tight oil DPIIP is a stock tank barrel.All DPIIP and TPIIP other than cumulative production, reserves, Contingent Resources, and Prospective Resources have been categorized as unrecoverable.The amount of natural gas and liquids ultimately recovered from ARC’s the Montney resource will be primarily a function of the future price of both commodities.
Definitions of Reserves and Resources
Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a givendate, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which aregenerally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantitiesrecovered will be greater or less than the sum of the estimated proved plus probable reserves.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered andUndiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-in-Place". Resources areclassified in the following categories:
Total Petroleum Initially-in-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantityof petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to bediscovered.Discovered Petroleum Initially-in-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior toproduction. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable.Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using establishedtechnology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable.Project Maturity Subclass Development Not Viable is defined as a Contingent Resource that is not viable in the conditions prevailing at the effective date of theevaluation, and where no further data acquisition or evaluation is planned and therefore has not been assigned a low chance of development.Project Maturity Subclass Development Pending is defined as a Contingent Resource that has been assigned a high chance of development and the resolution of finalconditions for development are being actively pursued.Project Maturity Subclass Development Unclarified is defined as a Contingent Resource that requires further appraisal to clarify the potential for development and hasbeen assigned a lower chance of development until contingencies can be clearly defined.
05/06/2020 24
Definitions of Reserves and Resources
Undiscovered Petroleum Initially-in-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to bediscovered. The recoverable portion of UPIIP is referred to as "prospective resources" and the remainder as "unrecoverable".Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application offuture development projects.Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion ofthese quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never berecovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the bestestimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Ifprobabilistic methods are used, there should be at least a 50 per cent probability that the quantities actually recovered will equal or exceed the best estimate.
Contact Information
Please Visit Our Website at www.arcresources.com
Kris BibbySenior Vice President and Chief Financial Officer
403.503.8675
Martha WilmotInvestor Relations Analyst
403.509.7280
General Investor Relations Enquiries403.503.8600
1.888.272.4900
05/06/2020 25
Notes
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05/06/2020 26
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05/06/2020 27
(1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled, "Funds from Operations" and “Capitalization, Financial Resources andLiquidity” contained within ARC’s MD&A.
(2) Dividends per share are based on the number of shares outstanding at each dividend record date.(3) Trading statistics denote trading activity on the Toronto Stock Exchange only.
FINANCIAL ANDOPERATIONAL HIGHLIGHTS($ millions, except per share amounts) 2020 2019 2018FINANCIAL RESULTS Q1 Q4 Q3 Q2 Q1 Q4 Q3 Q2Commodity sales from production 269.5 325.1 253.7 282.9 327.8 302.5 375.1 344.4
Per share, basic 0.76 0.92 0.72 0.80 0.93 0.86 1.06 0.97Per share, diluted 0.76 0.92 0.72 0.80 0.93 0.86 1.06 0.97
Net income (loss) (558.4) (10.2) (57.2) 94.4 (54.6) 159.7 45.1 (45.9)Per share, basic (1.58) (0.03) (0.16) 0.27 (0.15) 0.45 0.13 (0.13)Per share, diluted (1.58) (0.03) (0.16) 0.27 (0.15) 0.45 0.13 (0.13)
Funds from operations (1) 160.8 172.8 145.4 193.0 186.2 208.6 205.0 204.4Per share, basic 0.46 0.49 0.41 0.54 0.53 0.59 0.58 0.58Per share, diluted 0.46 0.49 0.41 0.54 0.53 0.59 0.58 0.58
Dividends declared 42.5 53.1 53.1 53.1 53.1 53.1 53.0 53.1Per share (2) 0.12 0.15 0.15 0.15 0.15 0.15 0.15 0.15
Total assets 5,172.6 5,778.3 5,819.2 5,878.9 5,952.4 6,016.2 5,846.3 6,059.8Total liabilities 2,332.4 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4 2,278.3 2,485.8Net debt outstanding (1) 1,079.7 940.2 945.5 829.2 796.3 702.7 667.8 757.0Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.4 353.5 353.5Weighted average shares, diluted 353.4 353.4 353.4 353.9 353.4 353.9 354.0 353.5Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.5CAPITAL EXPENDITURESGeological and geophysical 6.5 0.9 1.1 0.3 9.3 0.3 1.2 0.8Drilling and completions 131.3 86.7 101.0 110.1 144.9 77.0 126.5 118.7Plant and facilities 25.8 47.5 51.1 56.2 53.3 41.4 31.8 33.5Maintenance and optimization 4.4 3.0 6.2 5.8 3.4 11.7 7.1 9.0Corporate assets 1.8 3.6 2.5 1.8 2.8 1.2 2.7 2.8Total capital expenditures 169.8 141.7 161.9 174.2 213.7 131.6 169.3 164.8Undeveloped land — — 0.7 — — 0.2 — —
Total capital expenditures, including undeveloped land purchases 169.8 141.7 162.6 174.2 213.7 131.8 169.3 164.8
Acquisitions 2.5 — — — 0.2 — — —Dispositions (2.4) (1.1) (2.8) (0.9) (0.2) (0.9) (96.2) (0.7)
Total capital expenditures, land purchases, and net acquisitions and dispositions 169.9 140.6 159.8 173.3 213.7 130.9 73.1 164.1
OPERATIONAL RESULTSProduction
Crude oil (bbl/d) 16,997 17,083 16,782 18,272 18,251 20,092 23,867 24,893Condensate (bbl/d) 11,262 10,937 10,846 10,230 8,210 8,458 8,158 6,960Crude oil and condensate (bbl/d) 28,259 28,020 27,628 28,502 26,461 28,550 32,025 31,853Natural gas (MMcf/d) 692.2 669.0 595.4 596.4 632.5 603.3 574.2 537.9NGLs (bbl/d) 8,152 8,123 7,952 7,041 7,183 7,402 7,687 6,380Total (boe/d) 151,783 147,650 134,813 134,938 139,054 136,502 135,410 127,879
Average realized prices, prior to risk management contractsCrude oil ($/bbl) 49.69 65.11 64.79 70.26 63.72 43.30 78.62 78.57Condensate ($/bbl) 57.52 68.08 65.70 71.38 64.81 57.25 85.28 85.10Natural gas ($/Mcf) 2.05 2.36 1.54 1.74 2.79 2.85 2.15 1.91NGLs ($/bbl) 6.36 11.69 5.25 7.71 25.43 29.12 35.26 32.98Oil equivalent ($/boe) 19.52 23.93 20.46 23.04 26.20 24.09 30.12 29.59
TRADING STATISTICS (3)
($, based on intra-day trading)High 8.39 8.26 7.85 9.61 10.49 14.84 15.90 15.25Low 2.42 5.40 5.37 6.37 7.82 7.38 12.70 12.71Close 4.05 8.18 6.31 6.41 9.12 8.10 14.40 13.58Average daily volume (thousands) 3,207 2,583 1,838 2,255 2,291 2,117 1,246 1,150
CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. Kvisle (1)
Board Chair
Farhad Ahrabi (1)(2)
David R. Collyer (1)(3)(4)
John P. Dielwart (1)(2)
Kathleen O’Neill (4)(5)
Herbert C. Pinder Jr. (3)(4)
William G. Sembo (3)(5)
Nancy L. Smith (2)(5)
Terry M. Anderson(1) Member of Safety, Reserves and Operational Excellence Committee(2) Member of Risk Committee(3) Member of Human Resources and Compensation Committee(4) Member of Policy and Board Governance Committee(5) Member of Audit Committee
OFFICERSTerry M. AndersonChief Executive Officer
Kris J. BibbySenior Vice President and Chief Financial Officer
Chris D. BaldwinVice President, Geosciences
Ryan V. BerrettVice President, Marketing
Sean R. A. CalderVice President, Production
Lara M. ConradVice President, Development and Planning
Armin JahangiriVice President, Operations
Lisa A. OlsenVice President, Human Resources
Grant A. ZawalskyCorporate Secretary
EXECUTIVE OFFICEARC Resources Ltd.1200, 308 – 4th Avenue SWCalgary, Alberta T2P 0H7T 403.503.8600TOLL FREE 1.888.272.4900F 403.503.8609W www.arcresources.com
TRANSFER AGENTComputershare Trust Company of Canada600, 530 – 8th Avenue SWCalgary, Alberta T2P 3S8T 403.267.6800
AUDITORSPricewaterhouseCoopers LLPCalgary, Alberta
ENGINEERING CONSULTANTSGLJ Petroleum Consultants Ltd.Calgary, Alberta
LEGAL COUNSELBurnet Duckworth & Palmer LLPCalgary, Alberta
CORPORATE CALENDARJuly 30, 2020Q2 2020 Results
November 5, 2020Q3 2020 Results
STOCK EXCHANGE LISTINGThe Toronto Stock ExchangeTrading Symbol: ARX
INVESTOR INFORMATIONVisit our websiteW www.arcresources.comor contactInvestor RelationsT 403.503.8600 orTOLL FREE 1.888.272.4900E [email protected]
ARC is listed on the Jantzi Social Index; a common stock index of 60 Canadian companies that pass a set of broadly based environmental, social and governance rating criteria.