OUR February 2020 Investor Presentation FUTURE - ARC Resources · Advisory Statements...
Transcript of OUR February 2020 Investor Presentation FUTURE - ARC Resources · Advisory Statements...
OUR FOCUS OUR FUTURE
February 2020 Investor Presentation
Advisory Statements
Forward-looking Information and Statements and Advisory StatementsThis presentation contains forward-looking information as to ARC’s internal projections, expectations, or beliefs relating to future events or future performance and includes information as to ARC’s future well inventory in its core areas, its exploration anddevelopment drilling and other exploitation plans for 2020 and beyond, and related production expectations, costs and cash flow, expenses, the Company’s plans for constructing and expanding facilities, the volume of ARC's crude oil and natural gas reservesand the volume of ARC's crude oil and natural gas resources in the Montney, the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's crude oil and natural gas production, futureresults from operations, and operating metrics. These statements represent Management’s expectations or beliefs concerning, among other things, future operating results and various components thereof or the economic performance of ARC. Theprojections, estimates, and beliefs contained in such forward-looking statements are based on Management's assumptions relating to the production performance of ARC’s crude oil and natural gas assets, the cost and competition for services, thecontinuation of ARC’s historical experience with expenses and production, changes in the capital expenditure budgets, future commodity prices, continuing access to capital, and the continuation of the current regulatory and tax regime in Canada, andnecessarily involve known and unknown risks and uncertainties, such as changes in crude oil and natural gas prices, infrastructure constraints in relation to the development of the Montney, risks associated with the degree of certainty in resourceassessments, and including the business risks discussed in ARC’s annual and quarterly Management’s Discussion & Analysis and other continuous disclosure documents, and related to Management’s assumptions, which may cause actual performance andfinancial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results todiffer materially from those predicted. Other than the 2020 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in this document whether as to new information, future events, or otherwise except asrequired by securities laws and regulations.
ARC has adopted the standard of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used in isolation. A boe conversion ratioof 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to naturalgas is significantly different than the energy equivalency of the 6 Mcf:1 bbl conversion ratio, utilizing the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value.
Throughout this presentation, crude oil refers to tight, light, medium, and heavy crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). ARC’s production of heavy crude oil isconsidered to be immaterial. Natural gas refers to shale gas and conventional natural gas product types as defined by NI 51-101. ARC’s production of conventional natural gas is considered to be immaterial. ARC’s core producing properties that areconsidered to be shale gas include Attachie, Dawson, Parkland (including parts of Tower), and Sunrise, and as such, natural gas, condensate, and natural gas liquids (“NGLs”) are disclosed. ARC’s core producing properties that are considered to be tight oilinclude Ante Creek and parts of Tower, and as such, crude oil, natural gas, and NGLs are disclosed. ARC’s core producing property that is considered to be light crude oil is Pembina, and as such, crude oil, natural gas, and NGLs are disclosed.
Throughout this presentation, when condensate is disclosed, it is done so as it is the product type that is measured at the first point of sale. As per the Canadian Oil and Gas Evaluation (“COGE”) Handbook, condensate is a by-product of the NGLs producttype. NGLs by-products include ethane, butane, propane, and pentanes-plus (condensate).
Non-GAAP MeasuresThroughout this presentation, ARC uses the terms netback and return on average capital employed (“ROACE”) to analyze financial and operational performance. These non-GAAP measures do not have any standardized meaning prescribed underInternational Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures presented by other issuers.
Netback
ARC calculates netback on a total and per boe basis as commodity sales from production less royalties, operating, and transportation expense. ARC discloses netback both before and after the effect of realized gain or loss on risk management contracts.Realized gain or loss represent the portion of risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent measures that reflect how ARC’s risk management programcan impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that is commonly used by other oil and gas producers. The measurement on a per boebasis assists Management with evaluating operational performance on a comparable basis.
Return on Average Capital Employed
ARC calculates ROACE, expressed as a percentage, as net income (loss) plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months preceding period end. Capital employed isthe total of net debt plus shareholders’ equity. ROACE since inception is the annual average net income (loss) plus interest and total income tax expense (recovery) for the years 1996 to 2019 divided by the average of the opening and closing capitalemployed over the same period. Refer to the "Capital Management" note in ARC’s financial statements for additional discussion on net debt. ARC uses ROACE as a measure of long-term operational performance, to measure how effectively Managementutilizes the capital it has been provided and to demonstrate to shareholders the sustainability of its business model and that capital has been invested profitably over the long term.
Other DefinitionsThroughout this presentation, ARC uses the term sustaining capital. This measure does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers.
Sustaining Capital
Sustaining capital refers to estimated capital expenditures to maintain production from existing facilities at approximately current production levels.
13% 7%5%
75%
9% 9% 6%
76%
Corporate Profile
ARC Is a Canadian Oil and Gas Producer in Its 23rd Year of Delivering on Its Disciplined,Returns-focused Value Proposition, Including over $6.5 Billion in Dividends Paid since Inception
Asset SnapshotCorporate Summary
(1) Average daily trading volume for the six months ended February 11, 2020.(2) Market capitalization as at February 11, 2020 and net debt as at December 31, 2019.(3) Refer to the “Capital Management” note in ARC’s financial statements.(4) Based on funds from operations for the year ended December 31, 2019 and net debt as at December 31, 2019
Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 4.0 millionShares outstanding 353 millionEnterprise value (2)(3) $3.3 billionNet debt at December 31, 2019 (3) $940.2 millionNet debt to funds from operations (3)(4) 1.3 timesMonthly dividend $0.05/share
2019 Production 2019 Proved + Probable Reserves
Crude oilCondensate and pentanes plusNGLsNatural gas
139 Mboe/day 910 MMboe
Attachie
GreaterSunrise Area
Ante Creek
GreaterDawson Area
ARC holds ~1,000 net Montney sections (~638,000 acres)
Pembina
ABBC
Greater Dawson Area 88 Mboe/day
Greater Sunrise Area 36 Mboe/day
Ante Creek 18 Mboe/day
Pembina 10 Mboe/dayAttachie Pilot 5 Mboe/day
0
40
80
120
160
2020 Expected Production (Mboe/day)
Crude oilCondensateNGLsNatural gas
02/20/2020 1
Corporate Strategy
ARC’s Strategy Is Focused on Long-term Profitability
RISK-MANAGED
VALUECREATION
HIGH-QUALITYASSETS &
OPERATIONAL EXCELLENCE
FINANCIALSUSTAINABILITY &
RETURN ONINVESTMENT
HIGHPERFORMANCE
PEOPLE &CULTURE
COMMERCIALACTIVITIES &
RISKMANAGEMENT
Long-term Corporate Profitability
ARC Has Delivered a 10% ROACE since Inception
(1) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other issuers. Refer to “Non-GAAP Measures” in the Advisory Statements to this presentation.
Return on Average Capital Employed (1) Delivering Full-cycle Asset Level Returns
Single-well Economics(Half-cycle)
Proportional Facility and Appropriate
Timing Included:Project
Economics(Full-cycle)
Corporate Costs
TargetDouble-digit
Return on AverageCapital Employed
Afte
r-ta
x R
ate
of R
etur
n
(10%)
0%
10%
20%
30%
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
ROACE Trailing Three-year ROACE
02/20/2020 2
Longer-term Capital Allocation Priorities & Principles
Dividend and Sustaining Capital Requirements Are Fully Funded at US$45/bbl WTI and US$2.00/MMBtu NYMEX Henry Hub
Dividend$212 million
per year
Three-year Average
Sustaining Capital (1)
~$400 millionper year
Sources of Cash Dividend Sustaining Capital Growth Capital
Funds fromOperations
Pay meaningful dividend and grow funds from operations per share
Develop profitable projects
Manage net debt to funds from operations ratio within 1.0 to 1.5x
Maintain a low cost structure andcorporate decline rate
Capital Allocation Priorities
(1) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. Refer to “Other Definitions” in the Advisory Statements to this presentation.
Capital Allocation Principles
Inflows Outflows
Fully funded at US$45/bbl WTI and US$2.00/MMBtu NYMEX Henry Hub
Continue to implement physicaland financial diversification strategy
• Debt Reduction• Long-term Development
Investments• Share Buybacks• Dividend Increases
Historical Capital Allocation and Outlook
ARC Expects to Generate Funds from Operations That Will Fully Fund Its Dividend and All Capital Requirements in 2020
(1) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. Refer to “Other Definitions” in the Advisory Statements to this presentation.
Inflows Outflows
2016 to 2019 Capital Allocation 2020 Forecasted Capital Allocation
Inflows Outflows
Funds from Operations Net A&D Proceeds Dividend Sustaining Capital (1) Long-term Development Investments
02/20/2020 3
ARC’s Vision for the Future
ARC Has Moved Towards a Larger Production Base with Lower Capital Requirements
830
679 692
500
2017 2018 2019 2020F Three-year Average Sustaining Capital
(1) Total production for 2020F denotes the midpoint of the production guidance range of 155,000 to 161,000 boe per day for 2020.(2) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other issuers. Refer to “Other Definitions” in the Advisory Statements to this presentation.
123133
139
158
2017 2018 2019 2020F Production Base
Production (Mboe/day) (1)
Capital Expenditures ($ millions) (2)
2020 Guidance
Reducing Capital Expenditures by 28% and Delivering 14% Increase in Production
$500 millionInvest to keep facilities at or
near gas capacity while maximizing liquids production and cashflow generation
Allowing ARC to:
with improved operating expense of $4.55 – $4.95/boe
Maintain Balance Sheet StrengthFocus on Organic Liquids GrowthCreate Shareholder Value
w
and to completeDawson Phase IV andAnte Creek oil expansion, andcommence Parkland sour conversion
While ensuring the safe and responsibleexecution of the capital program
715 – 725 MMcf/dayof gas production
to produce155,000 – 161,000boe/day
and drilling
65 grossoperated wells
35,500 – 40,000 bbl/dayof liquids production
02/20/2020 4
Attachie$30MM
5,000 boe/dayOptimize pad profitability
with implementation of next generation of well design
2020 Budget of $500 Million
Completion of Dawson Phase IV Will Grow Profitable Production and Deliver Annual Production of 155 to 161 Mboe Per Day
ABBC
Ante Creek$79MM • 12 wells18,000 boe/day
Expansion at Ante Creek facility to add 15 MMcf/day of gas and 2,500 bbl/day of oil in Q2 2020
Pembina$11MM
10,000 boe/dayManage production declines
and maximize cash flow generation from light
oil production
Parkland/Tower$96MM • 6 wells29,000 boe/day
Convert existing sweet facility to a sour facility to support development of liquids-rich
lower Montney wells
Dawson$231MM • 39 wells
59,000 boe/dayPhase IV facility to comeon-stream in Q2 2020;
development focused on liquids-rich lower Montney
Note: Well counts denote wells drilled in calendar year; number of wells with completion activities in calendar year may vary.
Sunrise$40MM • 8 wells36,000 boe/day
Generate cash flow through owned and operated facilities with capacity of 240 MMcf/day
Red Creek
AttachieSeptimus
Tower
ParklandSunset
Sunrise
Sundown
Dawson
Pouce Coupe
Ante Creek
Pembina
Maintaining Financial Strength
ARC Has One of the Strongest Balance Sheets in the Sectorwith a Targeted Net Debt to Annualized Funds from Operations Ratio of 1.0 to 1.5x
ARC
ARC
(1) Source: RBC Research. Consensus estimates as per FactSet on January 21, 2020.
US Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)
Canadian Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)
0.7 0.7 0.8 1.0 1.2 1.2 1.2 1.3 1.4 1.5 1.6 1.6 1.6 1.8 1.8 1.9 1.9 1.9 2.2 2.3 2.3 2.4 2.4 2.6 3.3
4.2 4.3 4.8 5.1
Group Average
0.3 0.4 1.0 1.1 1.2 1.2 1.2 1.3 1.4 1.4 1.5 1.6 1.6
2.1 2.3 2.4 2.4 2.5 2.7 3.1 3.1 3.3 3.4 3.5 3.8 3.9 4.2
5.3
7.0 Group Average
02/20/2020 5
World-class Montney Resource
ARC Has Identified over 4,500 Future Drilling Locations across ARC’s Montney Assets
Montney Optionality
• Geographic Optionality• Egress Optionality• Commodity Optionality• Multi-layer Optionality
ABBC
Oil & Liquids
Dry Gas
Condensate-rich Gas
(1) Subject to change based on technology and economic environment.
Significant Montney Inventory (1)
0
1,600
3,200
4,800
6,400
Wells Drilled to YE 2019 2P Booked Locations Internal Inventory Estimate
Num
ber o
f Loc
atio
ns
Multiple Layers to Develop
Up to 1,000 Feet Thick, ARC’s Montney Assets Have Significant Future Delineation Opportunities
Attachie Septimus Sunrise Tower Parkland Dawson Pouce Coupe
MontneyA
Montney B
Montney C
Montney D
Montney E
Existing Horizontal Wells, Development Existing Horizontal Wells, Pilots Potential Horizontal Wells
Upp
er M
ontn
eyLo
wer
Mon
tney
02/20/2020 6
0
4
8
12
16
0
6
12
18
24
(1) Source: Peters & Co. 2018 Reserves Comparison – E&P Producers (March 29, 2019). Three-year 2P FD&A Costs represent data for the years 2016 to 2018 and include future development capital.(2) Refer to ARC’s February 7, 2019 news release entitled, “ARC Resources Ltd. Announces 118 MMBoe of Total Proved Plus Probable Reserve Additions in 2018, Replacing 245 Per Cent of Production, and Delivers Record Proved Producing Reserve
Additions of 82 MMBoe” for information pertaining to ARC’s finding and development costs.(3) Three-year 2P FD&A Costs peer group includes: BNP, BTE, CPG, PEY, POU, TOU, VET, VII, WCP.(4) Includes future development capital for build-out of Dawson Phase I & II liquids-handling upgrade and new Dawson Phase IV infrastructure.(5) 2019 YTD Operating Expense from company reports and represent data for the nine months ended September 30, 2019.(6) 2019 YTD Operating Expense peer group includes: BNP, BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(7) Source: Peters & Co. Limited E&P Overview Tables (January 28, 2020). Peer group includes APA, AR, COG, DVN, EOG, FANG, OVV, PEY, PXD, TOU, VII.
Cost Management & Decline Rate
Low-cost Producers with a Low Decline Rate Deliver Superior Returns over Time
Group Average
ARC
Group Average
ARC
Daw
son
(4)
ARC
NE
BC
Oil
& G
as
ARC
Sun
rise
Gas
Three-year 2P FD&A Costs ($/boe) (1)(2)(3) 2019 YTD Operating Expense ($/boe) (5)(6) 2020E Corporate Decline Rates (7)
ARC
Canadian ProducersUS Producers
0%
12%
24%
36%
48%
ARC
Daw
son
ARC
ARC
Sun
rise
Gas
ARC
NE
BC
Oil
& G
as
Oil & Liquids Financial and Physical Price Management
~60% of ARC’s 2019 Commodity Sales from Production Was Derived from Crude Oil and Liquids
76% of ARC’s liquids production is made up of light oil and condensate
Crude Oil & Liquids Sales Mix Crude Oil & Liquids Benchmark Pricing Crude Oil Risk Management
OilCondensateNGLs
(1) Per cent of production hedged based on full-year 2020 production guidance.
39% 37%
24%30
40
50
60
70
Jan
2019
Feb
2019
Mar
201
9
Apr 2
019
May
201
9
Jun
2019
Jul 2
019
Aug
2019
Sep
2019
Oct
201
9
Nov
201
9
Dec
201
9
US$
/bar
rel
Benchmark Pricing
Mixed Sweet BlendWTICondensateWestern Canadian Select
0%
15%
30%
45%
60%
Q12020
Q22020
Q32020
Q42020
Q12021
Q22021
Q32021
Q42021
Per C
ent o
f Cru
de O
il Pr
oduc
tion
Hed
ged
Crude Oil Hedges (1)
02/20/2020 7
1.70
2.45
1.65 1.72
1.15
(0.09)
0.72 0.40
0.62
0.18 0.81
0.44
3.47
2.54
3.18
2.56
(1.00)
0.00
1.00
2.00
3.00
4.00
Q4 2018 Q4 2019 2018 2019
Cdn
$/M
cf
Natural Gas Financial and Physical Price Management
Integrated Physical Marketing and Financial Risk Management StrategiesEnable ARC to Effectively Execute on Its Long-term Plans
2019 Natural Gas Flows and Sales Points (US$/MMBtu) ARC’s Natural Gas Price (4)
Initial Tie-in of ARC’s Production:• 80% through the TC Energy NGTL system• 20% through the Enbridge Westcoast system
Westcoast/NWP Alliance
TCPLMainline
GTN
Northern Border
GLGT
Station 2
$0.77
$0.17
$0.60
Malin
$2.67
$0.21
$0.48
$1.98
Chicago
$2.56
$0.21
$0.66
$1.69
Ventura
$2.53
$0.21
$0.54
$1.78
Dawn
$2.40
$0.21
$0.76
$1.43
AECO
$1.22
$0.21
$1.01
Henry Hub
Via Northern Border
Pricing Hub
Hub Market Price (1)
Field-to-Hub Transportation Cost (2)
Hub-to-Hub Transportation Cost (3)
Market Netback
(1) 2019 monthly index pricing, or daily index in the absence of a monthly index.(2) Uses a three-year average published toll including abandonment costs.(3) As per published pipeline data.(4) Realized gain on risk management contracts is not included in ARC’s realized natural gas price.
Realized Gain on Risk Management ContractsDiversification ActivitiesAverage Price before Diversification Activities
WCSB Demand & Export Capacity Growth (1) Natural Gas Diversification (2)(3)
Natural Gas Financial and Physical Price Management
Integrated Physical Marketing and Financial Risk Management StrategiesEnable ARC to Effectively Execute on Its Long-term Plans
24%
9% 3%
28%
37%37%
8%8%
12%
18%
16% 19%
10%17% 14%
8% 7% 7%
4% 6% 6%2%
Bal 2020 Cal 2021 Cal 20220%
25%
50%
75%
100%
Perc
enta
ge o
f Tot
al N
atur
al G
as P
rodu
ctio
n (%
)
(1) Source: ARC Risk Research, TC Energy, Enbridge, company reports.(2) Based on production assumptions for sanctioned projects.(3) “Hedged” includes all physical and financial fixed price swaps and collars at AECO, Station 2, and Henry Hub.
p p y
(1) Source: ARC Risk Research, TC Energy, Enbridge, company reports.(2) B d d i i f i d j
NGTL East Gate Capacity+1.3 Bcf/day by 2021
Intra-Alberta Demand+1.5 Bcf/day by 2024
LNG Canada Phase 1+2.1 Bcf/day by 2024
Enbridge T-South Capacity+0.2 Bcf/day by 2021
NGTL West Gate Capacity+0.5 Bcf/day by 2023
5.6 Bcf/day Demand/Egress Growth Expected by 2024
AECO FloatingStation 2 FloatingMidwest US Floating
HedgedMalin FloatingDawn FloatingEmpress Floating
Henry Hub Floating
02/20/2020 8
ARC’s ESG Excellence
Canadian Energy Sector Is Regulated by Some of the Highest Standards and Is a Clean, Ethical Energy SourceARC Ranks among the Highest in the World on Sustainability
(1) Source: BMO Capital Markets; Yale Environmental Performance Index (EPI); Social Progress Imperative; Worldbank Worldwide Governance Indicators, BMO Capital Markets; Bloomberg; CSRHub. For presentation, an equal weight (1/3) of each index is represented.
(2) Source: BP “Statistical Review of World Energy” (2019). Reserves as at December 31, 2018.
ESG Ratings by Major Oil Producing Country (1)(2) Oil and Gas Companies’ Relative ESG Rankings (1)
ARC
40
46
52
58
64
70
40 46 52 58 64 70
Soci
al a
nd G
over
nanc
e Sc
ore
Environmental Score
Africa
Asia
Canada
Europe
Middle East
Latin America
Russia
United States
0
125
250
375
500
0
25
50
75
100
Res
erve
s (B
boe)
Aver
age
ESG
Sco
re
Average ESG Score (LHS) Reserves (RHS)
Emissions Management Strategy
ARC’s GHG Emissions Intensity Performance Is Industry-leading
GHG Emissions Intensity Performance (Scope 1 and 2)
2018 GHG Emissions Intensity Benchmarking (1)
0.00
0.01
0.02
0.03
0.04
2014 2015 2016 2017 2018 2019F 2021Target
Tonn
esof
CO
2Eq
uiva
lent
per
boe
ARC Total ARC Sunrise
25% reduction target relative to
2017 baseline
0.00
0.03
0.06
0.09
0.12
ARC
Sun
rise
ARC
BC
ARC
Tot
al
Tonn
es o
f CO
2Eq
uiva
lent
pe
r boe
(1) Peer group includes: BNP, BTE, CNQ, CPG, CVE, ERF, MEG, NVA, OVV, PEY, SU, VET, VII, WCP.
>95% reductionexpected due to plant
electrification
Emissions Management Strategy
Proactively focus on reducing GHG intensity
Set GHG emissions intensity reduction target
Incorporate emissions management solutions into project planning
02/20/2020 9
Water Management Strategy
ARC’s Water Management Strategy Is Centred around Responsibility, Sustainability, and Profitability
Water Storage Reservoirs
Dawson
ParklandSunrise
Ante Creek
Water Management Strategy
Responsibly manage water use in operations
Evaluate technologies and procedures to implement best practices
Water strategy key in long-term planning
• $55 million of water infrastructure investments in ARC’sMontney operations since 2017 to add 700,000 m3 of waterstorage capacity
• Freshwater usage reduced by 25 per cent from 2017 to 2018
Water Management Strategy in Action
0.0
0.5
1.0
1.5
2.0
2014 2015 2016 2017 2018 2019
Tota
l Rec
orda
ble
Inci
dent
Fre
quen
cy
Strong Safety Performance
• Strong safety performance is the result of well-planned and executed operations and alignment with strong service providers
ARC Employees Have Gone Six Years Without a Lost-time Incident
75%Reduction
Contractor Total Recordable Incident Frequency
02/20/2020 10
Owned-and-operated Infrastructure
ARC Is Building Sustainable Businesses in the Montney and Is Increasing Its Liquids Processing Capacity
Dawson Phase III & IV
Dawson Phase I & II
Parkland/Tower Phase I
Sunrise Phase I & II
Ante Creek Phase I
NE BC
AB
Facility Investment of ~$815 million645 MMcf/day of Natural Gas Capacity33.5 Mbbl/day of Liquids Capacity
-35,000
-25,000
-15,000
-5,000
5,000
15,000
25,000
35,000
150,000,000)
100,000,000)
$50,000,000)
$0
$50,000,000
100,000,000
150,000,000
200,000,000
2018
2019
2020
F
2021
F
2022
F
2023
F
2024
F
2025
F
2026
F
2027
F
2028
F
2029
F
2030
F
Dawson Phase IV Business Model
Infrastructure Investment in Greater Dawson Area Is Supporting ARC’s Broad Shift to the Liquids-rich Lower Montney
(1) Non-GAAP measure that does not have any standardized meaning under IFRS and therefore may not be comparable to similar measures presented by other entities. Refer to “Non-GAAP Measures” in the Advisory Statements to this presentation.(2) Economics run at US$55/bbl WTI and Cdn$1.90/GJ AECO flat pricing.
Netback (1)(2)
Capital ExpendituresFacility Expenditures
ProductionNetback less Capital Expenditures -35,000
-25,000
-15,000
-5,000
5,000
15,000
25,000
35,000
150,000,000)
100,000,000)
$50,000,000)
$0
$50,000,000
100,000,000
150,000,000
200,000,000 Dawson Phase IVNatural Gas Processing Capacity: 90 MMcf/day
Condensate-handling Capacity: 7,500 bbl/day (production expected to stabilize at ~3,000 bbl/day)NGLs-handling Capacity: 3,000 bbl/day (production expected to stabilize at ~1,500 bbl/day)
~$300 MillionInitial Investment
Facility, Infrastructure, andWells to Fill Plant
Drill 8 to 10 Wells per Year45% of Netback Required to Sustain Business (2)
02/20/2020 11
Resource Potential and ScalabilityARC has:
• ~1,000 net Montney sections (~638,000 acres)
• Over 4,000 future drilling locations identified across the Montney
• Commodity, geographic, and multi-layer optionality
Scalability Allows for Profitable Growth to Generate Sustainable Funds from Operations and Maintain Financial Strength
2019
Base Production (Montney & Cardium)
In Progress
Future Development Projects
Attachie
GreaterSunrise Area
GreaterDawson Area
Ante Creek
~139 Mboe/day
Greater Dawson Area Overview
Lower Montney Focus with Dawson Phase IV Infrastructure Build-out
Snapshot Development Plan
2020 Development Focus
Infrastructure Build-out
2010 2011 2013 2015 2017 Q4 2019 Q2 2020
DawsonPhase I
DawsonPhase II
Parkland Tower
Phase I
Parkland Tower Battery
Upgrade
Dawson Phase I & II
UpgradeDawsonPhase III
Dawson Phase IV
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
Capital Budget Expected ProductionPlanned Wells
$327 million(65%)
$500 million (1)
45 wells(69%)
65 wells (1)
88 Mboe/day• 19 Mbbl/day• 410 MMcf/day(56%)
155 to 161 Mboe/day (1)
• Complete the Dawson Phase IV project, expected to be on-stream in Q2 2020• Commence sour conversion of existing Parkland sweet facility, expected to be
completed in H1 2021• Commissioned Phase I & II liquids-handling upgrade in early Q4 2019
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
Tower
Parkland
Dawson
Pembina & EnbridgeTCPLParkland-Dawson Interconnect Pipeline
Phase I & IIGas Plants
Phase III & IVGas Plants
Phase I & IIGas Plants
02/20/2020 12
Lower Montney Development and Liquids Growth
Integrated Approach to Development in the Greater Dawson Area Allows ARC to Optimize Infrastructure Capacities to Maximize Profitability
(1) Total Petroleum Initially-in-Place as at December 31, 2018.(2) NGLs volumes are Unrisked Best Estimate Economic Contingent Resource as at December 31, 2018.(3) Internal rate of return (half-cycle after-tax rate of return) run at US$55/bbl WTI and Cdn$1.90/GJ AECO flat pricing.
Free Condensate-to-gas Ratio (bbl/MMcf)
Parkland
Dawson
2019 Lower Montney Wells2020 Lower Montney Wells
Free Condensate-to-gas Ratio (bbl/MMcf)
Phase III & IVGas Plants
Phase I & IIGas Plants
100
Greater Dawson Area Lower Montney Development
• 23 Tcf (1) of resources in lowerMontney
• 105 MMbbl of contingent resourceNGLs, of which 71 MMbbl iscondensate (1)(2)
Large Resourcein Place
Tiered Inventory
Strong Return on Investment
• North Dawson & ParklandCGR: ~150 bbl/MMcf
• Core Dawson CGR: ~40 bbl/MMcf• 300+ drilling locations at Dawson
250+ drilling locations atParkland/Tower
• Prioritize wells based on return oninvestment
• Lower Montney wells have >100%IRR and one-year payout (3)
Greater Dawson Area Strong Condensate Results
Strong Range of Condensate Outcomes from Both Upper and Lower Montney Development
Greater Dawson Area Condensate Performance
Type Curve
NGLs[C2,C3,C4]EUR (Mbbl)
Condensate EUR (Mbbl)
Natural Gas
EUR (Bcf)
Upper Montney Low End 10 30 7.3
Upper Montney High End 105 85 5.9
Lower Montney Low End 110 100 6.0
Lower Montney High End 80 240 2.4
Lower Montney Range
Upper Montney Range
0
50,000
100,000
150,000
200,000
0 12 24 36 48 60
Cum
ulat
ive
Con
dens
ate
Prod
uctio
n (b
bl)
Months on Production
02/20/2020 13
Optimizing Dawson Lower Montney Development
Use of Technology Has Enhanced Lower Montney Profitability through Improved EURs, Better Capital Efficiency, and Lower F&D Costs
Estimated Ultimate Recovery Capital Efficiency
Well Costs Finding and Development Costs
0
375
750
1,125
1,500
2017 2018 2019
Estim
ated
Ulti
mat
e R
ecov
ery
(Mbo
e)
0
2,500
5,000
7,500
10,000
2017 2018 2019
Cap
ital E
ffici
ency
($
/boe
/day
)3,500
4,000
4,500
5,000
5,500
2017 2018 2019
Wel
l Cos
ts($
mill
ions
)
0
2
4
6
8
2017 2018 2019Fi
ndin
g &
Dev
elop
men
t C
osts
($/b
oe)
Dawson Phase IV Update
Commissioning Activities Have Commenced with the Dawson Phase IV Facility Expected to Be On-stream in Q2 2020
Commercial and Development Execution
Regulatory Approval Secured
Takeaway Secured
Economics Robust
Facility Execution
Project Cost On budget
Safety 0 LTIs
Mechanical Work 75% complete
Electrical Work 67% complete
Commissioning Work 15% complete
Expected On-stream Q2 2020
Dawson Phase IV Project Checklist
02/20/2020 14
Existing Infrastructure 2012 Q2 2020
Ante Creek Overview
Strong Cash Flow Generating Asset with Facility’s Oil Expansion Project Planned for Q2 2020
Snapshot
Ante CreekPhase I
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
Ante CreekExpansion
Development Plan
2020 Development Focus
Infrastructure Build-out
• Low-risk, high netback Montney light oil development• Ante Creek facility’s oil expansion will add up to 2,500 bbl/day of light oil
production, expected to be brought on-stream in Q2 2020
$79 million(16%)
12 wells(19%)
18 Mboe/day• 9 Mbbl/day• 55 MMcf/day(11%)
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
Capital Budget Expected ProductionPlanned Wells
$500 million (1) 65 wells (1) 155 to 161 Mboe/day (1)
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
Attachie Overview
Strong CGR of 300 Barrels per MMcf for Three Newest Wells on Production
Snapshot
Attachie West Phase I
$30 million(6%)
0 wells(0%)
5 Mboe/day• 3 Mbbl/day• 11 MMcf/day(3%)
Development Plan
2020 Development Focus
Infrastructure Build-out
• Four wells brought on production in Q4 2019; due to facility constraints, three of the fourwells are producing consistently• Over 90 days of production, cumulative production from the three wells is 160,000
barrels of condensate and 530 MMcf of natural gas for a CGR of 300 bbl/MMcf
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
(1)(2) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
Existing Infrastructure
Capital Budget Expected ProductionPlanned Wells
$500 million (2) 65 wells (2) 155 to 161 Mboe/day (2)
PembinaNorth Montney Mainline
8.9 Bbbl liquids and 32 Tcf gas in place (1)
(1) Total Petroleum Initially-in-Place at Attachie as at December 31, 2018.
4-20Battery
(3.5 Mbbl/day)
Phase IGas Plant
02/20/2020 15
0
75
150
225
300
0 350 700 1,050 1,400
Cum
ulat
ive
Con
dens
ate
Prod
uctio
n (M
bbl)
Days on Production
Continuous Improvement in Pad and Well Design
Initial Well Results from Newest Pad Are Encouraging with Average Condensate-to-gas Ratio of 300 Barrels per MMcf
Pad and Well Design Evolution Cumulative Condensate Production
(1) Due to facility constraints, only three of the four wells on 2-27 Pad Phase I have been producing consistently. Over 90 days of production, the three wells have produced approximately 160,000 barrels of condensate and approximately 530 MMcf of natural gas.
16-16 Well13-26 WellB13-26 Well13-14 Pad Average2-27 Pad Phase I Average (1)
20192-27 Pad Phase II
200 metre Spacing45 m
400 m 400 m
400 m 400 m
45 m
300 m 300 m 300 m
300 m 300 m2018
13-14 Pad150 metre Spacing
20192-27 Pad Phase I
300 metre Spacing45 m
600 m
600 m
2017B13-26 Well
Unconstrained
201613-26 Well
Unconstrained
Attachie Is Being Advanced Towards Commercialization
ARC Is Progressing the Technical, Commercial, and Funding Aspects of Attachie West Phase I
Technical Commercial Funding
Strong liquids deliverability
Improved capital efficiencies
Competitor activity
Commodity egress
Regulatory
Support infrastructure
Balance sheet
Maximize profitability
Project readiness
02/20/2020 16
2015 2018 2019
Sunrise Overview
Sunrise Phase I & II Operating at Full 240 MMcf Per Day of Sales CapacityExpect Operating Area’s Operating Expense to Be Less Than $0.30 per Mcf
Snapshot
SunrisePhase I
Montney Natural Gas Processing Capacity
SunrisePhase II
SunrisePhase II
$40 million(8%)
8 wells(12%)
36 Mboe/day• 217 MMcf/day(23%)
Development Plan
2020 Development Focus
Infrastructure Build-out
• Final transportation arrangements in effect at Sunrise Phase II early in Q4 2019• ARC plans to operate Sunrise Phase I & II facility at or near processing capacity
of 240 MMcf per day through 2020 depending on prevailing commodity prices
Capital Budget Expected ProductionPlanned Wells
$500 million (1) 65 wells (1) 155 to 161 Mboe/day (1)
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
Phase I & IIGas Plants
Sunset
Sunrise
76%
2%4%18%
Pembina Overview
High Working Interest Light Oil Production, Competitive Operating Netback and Strong Cash Flow Generation
Snapshot
$11 million(2%)
0 wells(0%)
10 Mboe/day• 8 Mbbl/day• 10 MMcf/day(6%)
Development Plan
2020 Development Focus
• Manage production declines and maximize cash flow generation from light oil production
2019 Production Split(1) Denotes corporate total for capital budget, planned wells, and expected production for 2020.
10.3 Mboe/day
Capital Budget Expected ProductionPlanned Wells
$500 million (1) 65 wells (1) 155 to 161 Mboe/day (1)
Berrymoor
LindaleNPCU
MIPABuckCreek
SPCUPCU7
Blue boundaries denote units.
Crude oilCondensateNGLsNatural gas
02/20/2020 17
Additional Information
2019 & 2020 Guidance
ARC Has Moved Towards a Larger Production Base with Lower Capital Requirements
2019Guidance
2019Actuals
2020Guidance
Production
Crude oil (bbl/day) 17,000 - 19,000 17,591 15,000 - 17,000
Condensate (bbl/day) 9,000 - 11,000 10,066 12,000 - 14,000
Crude oil and condensate (bbl/day) 26,000 - 30,000 27,657 27,000 - 31,000
Natural gas (MMcf/day) (1) 620 - 630 623.3 715 - 725
NGLs (bbl/day) 6,500 - 7,000 7,578 8,500 - 9,000
Total production (boe/day) (1) 136,000 - 142,000 139,126 155,000 - 161,000
Expenses ($/boe)
Operating 5.00 - 5.35 4.97 4.55 - 4.95
Transportation 2.90 - 3.10 2.94 3.10 - 3.30
G&A expense before share-based compensation expense 1.10 - 1.30 1.20 1.00 - 1.20
G&A - share-based compensation expense (2) 0.20 - 0.35 0.46 0.30 - 0.45
Interest and financing (3) 0.75 - 0.90 0.81 0.65 - 0.80
Current income tax expense (recovery) as a per cent of funds from operations (4) (3) - 2 (2) (2) - 3
Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 700 691.5 500(1) 2020 Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(2) Comprises expenses recognized under the Restricted Share Unit and Performance Share Unit Plans, Share Option Plan, and Long-term Restricted Share Award Plan, and excludes compensation expense under the Deferred Share Unit Plan.
In periods where substantial share price fluctuation occurs, G&A expense is subject to greater volatility.(3) Excludes accretion of asset retirement obligation.(4) The current income tax estimate varies depending on the level of commodity prices.
02/20/2020 18
Asset Details
Diversified Commodity Mix across Portfolio of Assets
Dawson Parkland/Tower Ante Creek Attachie Sunrise Pembina
Net production – Q4 2019Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)
4,971228.3
43,014
12,022128.7
33,464
7,47746.3
15,199
2,4109.7
4,022
76235.5
39,324
8,86611.4
10,773
LandNet sections (1)
Working interest137
~100%94
~90% / ~94%208
~100%308
~99%32
~89%217
~89%
PDP Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)
7910.4410
4
4614.6186
4
209.6623
62.8173
660.3396
5
3832.7
3511
2P Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)
30051.2
1,49414
15348.962714
7838.623912
3920.511222
2342.5
1,39018
6049.9
6117
(1) Denote Montney or Cardium sections only.(2) Reserve life index based on 2020 guided production.
0%
30%
60%
90%
120%
0
2
4
6
8
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
Div
iden
ds a
s a
% o
f Fun
ds fr
om O
pera
tions
Cum
ulat
ive
Div
iden
ds ($
bill
ions
)
Cumulative Dividend (LHS)
Dividends as a % of FFO (RHS)
Transformation of ARC’s Business
Montney Transformation Has Allowed ARC to Manage a Profitable Business through Commodity Price Cycles
Production Net Debt to Funds from Operations Dividends (1)
(1) Dividends as a per cent of funds from operations calculated as dividends before Dividend Reinvestment Plan and Stock Dividend Program.
201930%
0
40,000
80,000
120,000
160,000
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
boe/
day
Montney Natural Gas (boe/day)
Non-Montney Natural Gas (boe/day)
Montney Crude Oil & Liquids (bbl/day)
Non-Montney Crude Oil & Liquids (bbl/day)
0.00
0.50
1.00
1.50
2.00
2.50
0
400
800
1,200
1,600
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
F
Rat
io
$ m
illio
ns
Net Debt (LHS)
Funds From Operations (LHS)
Net Debt to Funds from Operations (RHS)
02/20/2020 19
(40)
0
40
80
120
160
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MM
boe
Reserves Replacement - Development Reserves Replacement - Net Acquisitions & Dispositions Reserves Replacement - Total Production
Produced Reserves Replacement
• Strong 2019 development 2P reserve adds, with 164 per cent of produced reserves replaced• Finding and development costs of $4.82/boe for proved plus probable reserves and $9.74/boe for total proved reserves (2)
Growth through Acquisition Organic Growth
150 Per Cent Reserves Replacement or Greater for 12th Consecutive Year
(1) 1997 to 2002 reserves data is based on company interest established reserves (proved plus 50 per cent of probable reserves). 2003 to 2019 reserves data is based on gross interest proved plus probable reserves.(2) Includes future development capital.
Annual Produced Reserves Replacement (1)
PDP28%
PNP 2%
PUD35%
Probable35%
Key Reserve Information (1)
Year-end 2019 Reserves Added 83 MMboe of 2P Reserves through Development Activities
(1) Reserves data effective December 31, 2019; TPIIP resources data effective December 31, 2018.(2) Based on 2020 original production guidance midpoint of 158,000 boe per day.(3) Independent Resources Evaluation conducted by GLJ effective December 31, 2018. For resources disclosure, refer to the February 7, 2019 news release entitled, “ARC Resources Ltd. Announced 118 MMboe of Total Proved Plus Probable Reserve
Additions in 2018, Replacing 245 Per Cent of Production, and Delivers Record Proved Producing Reserve Additions of 82 MMboe”.
YE 2019 2P Reserves
0
250
500
750
1,000
2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
2P R
eser
ves
(MM
boe)
Natural GasCrude Oil & Liquids Oil
9%Condensate & Pentanes Plus
9%
NGLs6%
Natural Gas76%
Proved Producing 258 MMboe
Total Proved 595 MMboe
Proved plus ProbableCrude and Tight OilNGLsNatural Gas
910 MMboe83 MMbbl
134 MMbbl4.2 Tcf
2P Reserve Life Index (2) 15.8 years
TPIIP (1)(3)
Tight OilShale Gas
14.3 billion barrels101.8 Tcf
02/20/2020 20
(100)
(50)
0
50
100
150
200
250
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020F 2021F 2022F 2023F 2024F
$ m
illio
ns
Crude Oil
Natural Gas
Foreign Exchange & Power
Total
Risk Management Program
Program Executed with a Long-term View
(1) 2020 to 2024 Forecast values based on the forward price curve as at December 31, 2019, net of credit adjustment.(2) Refer to the “Financial Instruments and Market Risk Management” note in ARC’s financial statements and the section entitled, “Risk Management” contained within ARC’s MD&A.(3) Realized pricing is based on annual average settlements.
WTI (3)
US$/bbl$62 $80 $95 $94 $98 $93 $49 $43 $51 $65 $57
AECO (3)
Cdn$/GJ$3.91 $3.79 $3.44 $2.27 $3.00 $4.19 $2.63 $1.98 $2.30 $1.45 $1.54
Realized Gain (Loss) on Risk Management Contracts (1)(2)
Risk Management Contract Positions
1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoffprofile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. All positions are financially settled against the benchmark prices.
2) The swaption allows the counterparty, at a specified future date, to enter into a swap with ARC at the above-detailed terms. These volumes are not included in the total commodity volumes until such time that the option is exercised.
3) Crude oil prices referenced to WTI, multiplied by the WM/Reuters Intra-day Cdn$/US$ Foreign Exchange Spot Rate as of Noon Eastern Standard Time.
Risk Management Contracts Positions at December 31, 2019 (1) 2020 2021 2022 2023 2024
Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling 61.59 6,500 61.92 5,500 - - - - - -Floor 54.23 6,500 54.64 5,500 - - - - - -Sold Floor 41.92 6,500 44.09 5,500 - - - - - -Swap 59.09 2,000 - - - - - - - -Sold Swaption (2) - - 60.03 2,000 - - - - - -Crude Oil – Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 86.38 6,500 - - - - - - - -Floor 75.38 6,500 - - - - - - - -Sold Floor 60.38 6,500 - - - - - - - -Total Crude Oil Volumes (bbl/day) 15,000 5,500 - - -Crude Oil - MSW (Differential to WTI) (4) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling (7.00) 1,000 - - - - - - - -Floor (10.20) 1,000 - - - - - - - -Swap (8.31) 7,000 - - - - - - - -Natural Gas - Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 3.05 105,000 3.32 50,000 3.43 25,000 - - - -Floor 2.62 105,000 2.75 50,000 2.66 25,000 - - - -Sold Floor 2.21 105,000 2.25 50,000 2.25 25,000 - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.60 30,000 - - - - - - - -Floor 3.08 30,000 - - - - - - - -Swap 3.35 22,541 2.00 10,000 - - - - - -Sold Swaption (2) - - - - 2.00 10,000 - - - -Total Natural Gas Volumes (MMBtu/day) 154,799 59,478 25,000 - -Natural Gas - AECO Basis (Differential to Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/daySold Swap (0.81) 74,262 (0.95) 54,192 (0.90) 20,000 (0.93) 50,000 (0.93) 50,000Total AECO Basis Volumes (MMBtu/day) 74,262 54,192 20,000 50,000 50,000Natural Gas – Other Basis (MMBtu/day)
(Differential to Henry Hub) (6) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 100,000 120,000 110,000 80,000 4,973
Foreign Exchange Contract Settlement Date Notional Amount (US$ millions) Ceiling(Cdn$/US$)
FloorCdn$/US$
Variable Rate Collar (7) August 24, 2020 24 1.2771 1.3231Interest Rate Contract Term Received Notional Amount (US$ millions) Fixed Rate Pay Notional Amount (US$ millions) Fixed RateCross Currency Swap December 2019 – January 2020 40 3.48% 52 3.14%
4) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton.5) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.6) ARC has entered into basis swaps at locations other than AECO.7) Variable rate collar whereby if Cdn$/US$ spot rate is below $1.2771 at expiry, the ceiling will readjust to $1.3058.
02/20/2020 21
ESG Recognitions and Rankings
Member of MSCI Global Sustainability IndexMSCI ESG Rating: AAA
Voluntary participant since 20072018 Climate Change Score: B2018 Water Security Score: B
Member of Sustainalytics’ Jantzi Social Index
Member of FTSE Russell’s FTSE4Good Index Series since 2018
Member of the 30% Club since 2018
Best Disclosure of Corporate Governanceand Executive Compensation Practices in 2016
Reserves and Resources DisclosureAll reserves in this presentation are, unless indicated otherwise, as at December 31, 2019 as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in accordance with the
definitions, standards, and procedures contained in the COGE Handbook and NI 51-101. Resources volumes for the Montney are as at December 31, 2018 as evaluated byGLJ in accordance with the definitions, standards, and procedures contained in the COGE Handbook and NI 51-101 .
TPIIP, DPIIP, and UPIIP have been estimated using a one per cent porosity cut-off for shale gas and tight oil.Reserves volumes for ARC’s Montney assets and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for the
Montney in this presentation are “Best Estimates”.All reserves and resources volumes for the Montney and elsewhere in this presentation are company gross.Gas volumes are “sales” for reserves and resource and raw gas for DPIIP and TPIIP.The tight oil DPIIP is a stock tank barrel.All DPIIP and TPIIP other than cumulative production, reserves, Contingent Resources, and Prospective Resources have been categorized as unrecoverable.The amount of natural gas and liquids ultimately recovered from ARC’s the Montney resource will be primarily a function of the future price of both commodities.
02/20/2020 22
Definitions of Reserves and ResourcesReserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date,based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which are generallyaccepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantitiesrecovered will be greater or less than the sum of the estimated proved plus probable reserves.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered andUndiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-in-Place". Resources are classifiedin the following categories:
Total Petroleum Initially-in-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantity ofpetroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to bediscovered.Discovered Petroleum Initially-in-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior toproduction. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable.Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using establishedtechnology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable.Project Maturity Subclass Development Not Viable is defined as a Contingent Resource that is not viable in the conditions prevailing at the effective date of theevaluation, and where no further data acquisition or evaluation is planned and therefore has not been assigned a low chance of development.Project Maturity Subclass Development Pending is defined as a Contingent Resource that has been assigned a high chance of development and the resolution of finalconditions for development are being actively pursued.Project Maturity Subclass Development Unclarified is defined as a Contingent Resource that requires further appraisal to clarify the potential for development and hasbeen assigned a lower chance of development until contingencies can be clearly defined.
Forecast
Definitions of Reserves and ResourcesUndiscovered Petroleum Initially-in-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to be discovered.The recoverable portion of UPIIP is referred to as "prospective resources" and the remainder as "unrecoverable".Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application offuture development projects.Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion of thesequantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never be recovereddue to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the bestestimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Ifprobabilistic methods are used, there should be at least a 50 per cent probability that the quantities actually recovered will equal or exceed the best estimate.
02/20/2020 23
Contact Information
For further information about ARC Resources Ltd. please visit our website www.arcresources.com.
Or contact:Investor RelationsE-mail: [email protected] 403.503.8600 F 403.509.6427Toll Free 1.888.272.4900ARC Resources Ltd.1200, 308 – 4 Avenue SWCalgary, AB T2P 0H7
Kris Bibby Martha WilmotSenior Vice President and Chief Financial Officer Investor Relations Analyst
403.503.8675 403.509.7280
[email protected] [email protected]
02/20/2020 24
Notes
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02/20/2020 26
FINANCIAL ANDOPERATIONAL HIGHLIGHTS
(1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled, "Funds from Operations" and “Capitalization, Financial Resourcesand Liquidity” contained within ARC’s MD&A.
(2) Dividends per share are based on the number of shares outstanding at each dividend record date.(3) Trading statistics denote trading activity on the Toronto Stock Exchange only.
($ millions, except per share amounts) 2019 2018FINANCIAL Q4 Q3 Q2 Q1 Q4 Q3 Q2 Q1Commodity sales from production 325.1 253.7 282.9 327.8 302.5 375.1 344.4 340.2
Per share, basic 0.92 0.72 0.80 0.93 0.86 1.06 0.97 0.96Per share, diluted 0.92 0.72 0.80 0.93 0.86 1.06 0.97 0.96
Net income (loss) (10.2) (57.2) 94.4 (54.6) 159.7 45.1 (45.9) 54.9Per share, basic (0.03) (0.16) 0.27 (0.15) 0.45 0.13 (0.13) 0.16Per share, diluted (0.03) (0.16) 0.27 (0.15) 0.45 0.13 (0.13) 0.16
Funds from operations (1) 172.8 145.4 193.0 186.2 208.6 205.0 204.4 201.0Per share, basic 0.49 0.41 0.54 0.53 0.59 0.58 0.58 0.57Per share, diluted 0.49 0.41 0.54 0.53 0.59 0.58 0.58 0.57
Dividends declared 53.1 53.1 53.1 53.1 53.1 53.0 53.1 53.1Per share (2) 0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15
Total assets 5,778.3 5,819.2 5,878.9 5,952.4 6,016.2 5,846.3 6,059.8 6,235.7Total liabilities 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4 2,278.3 2,485.8 2,563.8Net debt outstanding (1) 940.2 945.5 829.2 796.3 702.7 667.8 757.0 728.0Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.5 353.5 353.5Weighted average shares, diluted 353.4 353.4 353.9 353.4 353.9 354.0 353.5 353.8Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.5 353.5CAPITAL EXPENDITURESGeological and geophysical 3.7 2.7 1.3 11.9 1.3 3.4 2.1 4.0Drilling and completions 80.7 98.6 107.0 129.2 60.5 114.2 102.6 139.1Plant and facilities 56.6 60.0 65.5 72.3 69.6 51.2 58.8 70.0Corporate assets 0.7 0.6 0.4 0.3 0.2 0.5 1.3 0.6Total capital expenditures 141.7 161.9 174.2 213.7 131.6 169.3 164.8 213.7Undeveloped land — 0.7 — — 0.2 — — 0.7Total capital expenditures, including
undeveloped land purchases 141.7 162.6 174.2 213.7 131.8 169.3 164.8 214.4Acquisitions — — — 0.2 — — — 0.2Dispositions (1.1) (2.8) (0.9) (0.2) (0.9) (96.2) (0.7) (98.3)Total capital expenditures, land purchases, and
net acquisitions and dispositions 140.6 159.8 173.3 213.7 130.9 73.1 164.1 116.3OPERATINGProduction
Crude oil (bbl/d) 17,083 16,782 18,272 18,251 20,092 23,867 24,893 25,037Condensate (bbl/d) 10,937 10,846 10,230 8,210 8,458 8,158 6,960 5,505Crude oil and condensate (bbl/d) 28,020 27,628 28,502 26,461 28,550 32,025 31,853 30,542Natural gas (MMcf/d) 669.0 595.4 596.4 632.5 603.3 574.2 537.9 564.9NGLs (bbl/d) 8,123 7,952 7,041 7,183 7,402 7,687 6,380 6,332Total (boe/d) 147,650 134,813 134,938 139,054 136,502 135,410 127,879 131,016
Average realized prices, prior to risk management contractsCrude oil ($/bbl) 65.11 64.79 70.26 63.72 43.30 78.62 78.57 69.50Condensate ($/bbl) 68.08 65.70 71.38 64.81 57.25 85.28 85.10 77.42Natural gas ($/Mcf) 2.36 1.54 1.74 2.79 2.85 2.15 1.91 2.50NGLs ($/bbl) 11.69 5.25 7.71 25.43 29.12 35.26 32.98 31.39Oil equivalent ($/boe) 23.93 20.46 23.04 26.20 24.09 30.12 29.59 28.85
TRADING STATISTICS (3)
($, based on intra-day trading)High 8.26 7.85 9.61 10.49 14.84 15.90 15.25 15.90Low 5.40 5.37 6.37 7.82 7.38 12.70 12.71 11.88Close 8.18 6.31 6.41 9.12 8.10 14.40 13.58 14.04Average daily volume (thousands) 2,583 1,838 2,255 2,291 2,117 1,246 1,150 1,406
CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. Kvisle (1)
Chairman
Farhad Ahrabi (1)(2)
David R. Collyer (1)(3)
John P. Dielwart (1)(2)
Fred J. Dyment (2)(4)
Kathleen O’Neill (4)(5)
Herbert C. Pinder Jr. (3)(4)
William G. Sembo (3)(5)
Nancy L. Smith (2)(5)
Myron M. Stadnyk(1) Member of Safety, Reserves and Operational Excellence Committee(2) Member of Risk Committee(3) Member of Human Resources and Compensation Committee(4) Member of Policy and Board Governance Committee(5) Member of Audit Committee
OFFICERSTerry M. AndersonChief Executive OfficerMyron M. StadnykPresident
Kris J. BibbySenior Vice President and Chief Financial Officer
Chris D. BaldwinVice President, Geosciences
Ryan V. BerrettVice President, Marketing
Sean R. A. CalderVice President, Production
Lara M. ConradVice President, Development and Planning
Armin JahangiriVice President, Operations
Lisa A. OlsenVice President, Human Resources
Grant A. ZawalskyCorporate Secretary
EXECUTIVE OFFICEARC Resources Ltd.1200, 308 – 4th Avenue SWCalgary, Alberta T2P 0H7T 403.503.8600TOLL FREE 1.888.272.4900F 403.503.8609W www.arcresources.com
TRANSFER AGENTComputershare Trust Company of Canada600, 530 – 8th Avenue SWCalgary, Alberta T2P 3S8T 403.267.6800
AUDITORSPricewaterhouseCoopers LLPCalgary, Alberta
ENGINEERING CONSULTANTSGLJ Petroleum Consultants Ltd.Calgary, Alberta
LEGAL COUNSELBurnet Duckworth & Palmer LLPCalgary, Alberta
CORPORATE CALENDARMay 6, 2020Q1 2020 Results
May 7, 2020Annual Meeting
July 30, 2020Q2 2020 Results
November 5, 2020Q3 2020 Results
STOCK EXCHANGE LISTINGThe Toronto Stock ExchangeTrading Symbol: ARX
INVESTOR INFORMATIONVisit our website atwww.arcresources.comor contact:Investor RelationsT 403.503.8600 orTOLL FREE 1.888.272.4900E [email protected]
ARC is listed on the Jantzi Social Index; a common stock index of 60 Canadian companies that pass a set of broadly based environmental, social and governance rating criteria.