26
OUR FOCUS OUR FUTURE September 2019 Investor Presentation
OUR FOCUS OUR FUTURE
September 2019 Investor Presentation
Contact Information & Advisory Statements
Kris Bibby Martha Wilmot General Investor Enquiries
Vice President, Finance and Capital Markets Investor Relations Analyst www.arcresources.com
403.503.8675 403.509.7280 1.888.272.4900
[email protected] [email protected] [email protected]
Capital Markets & Investor Relations Contact Information
Forward-looking Information and 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 our future well inventory in our core areas, our exploration and development drilling and other exploitationplans for 2019 and beyond, and related production expectations, costs and cash flow, expenses, our plans for constructing and expanding facilities, the volume of ARC's oil and gas reserves and the volume of ARC's oil and gas resources in the Montney, the recognition of additional reserves andthe capital required to do so, the life of ARC's reserves, the volume and product mix of ARC's oil, liquids and natural gas production, future results from operations and operating metrics. These statements represent Management’s expectations or beliefs concerning, among other things, futureoperating results and various components thereof or the economic performance of ARC. The projections, estimates and beliefs contained in such forward-looking statements are based on Management's assumptions relating to the production performance of ARC’s oil and gas assets, the cost andcompetition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital expenditure budgets, future commodity prices, continuing access to capital and the continuation of the current regulatory and tax regime in Canada and necessarilyinvolve known and unknown risks and uncertainties, such as changes in oil and 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 MD&A and other continuous disclosure documents, and related to Management’s assumptions, which may cause actual performance and financial results in future periods to differ materially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differ materially from those predicted. Other than the 2019 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in thisdocument whether as to new information, future events or otherwise except as required by securities laws and regulations.
We have adopted the standard of six thousand cubic feet of natural gas to one barrel of oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used in isolation. A boe conversion ratio of 6 Mcf:1 barrel is based on an energy equivalencyconversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6:1 conversion ratio,utilizing the 6:1 conversion ratio may be misleading as an indication of value.
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 under IFRS and therefore may not be comparable tosimilar 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 portionof risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent measures that reflect how ARC’s risk management program can impact its netback. Management believes that netback is a key industrybenchmark and a measure of performance for ARC that provides investors with information that is commonly used by other oil and gas producers. The measurement on a per boe basis assists Management with evaluating operating performance on a comparable basis.
Return on Average Capital Employed
ARC calculates ROACE, expressed as a percentage, as net income plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months preceding period end. Capital employed is the total of net debt plus shareholders’equity. ROACE since inception is the annual average net income plus interest and total income tax expense (recovery) for the years 1996 to 2018 divided by the average of the opening and closing capital employed over the same period. Refer to the "Capital Management" note in ARC’s financialstatements for additional discussion on net debt. ARC uses ROACE as a measure of long-term operating 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 hasbeen invested profitably over the long term.
Other DefinitionsThroughout this presentation, ARC uses the terms sustaining capital and growth capital. These measures do not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities.
Sustaining Capital
Sustaining capital refers to estimated capital expenditures to maintain production from existing facilities at approximately current production levels.
Growth Capital
Growth capital refers to capital expenditures that result in increased production levels at existing facilities or increased production from new facilities and infrastructure required to support higher production levels.
Corporate Profile
ARC Is a Canadian Oil and Gas Producer in Its 23rd Year of Delivering on Its Disciplined,Returns-focused Value Proposition Including ~$6.5 Billion in Dividends Paid since Inception
Attachie
GreaterSunrise Area
Ante Creek
GreaterDawson Area
Asset SnapshotCorporate Summary
ARC holds ~1,100 net Montney sections (~707,000 acres)
Pembina
ABBC
20% 5%
75%
137 Mboe/day
(1) Average daily trading volume for the trailing six month period ended August 29, 2019.(2) Refer to the “Capital Management” note in ARC’s financial statements.(3) Market capitalization as at August 29, 2019 and net debt as at June 30, 2019.(4) Based on annualized funds from operations for the six months ended June 30, 2019 and net debt as at June 30, 2019.
Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 3.2 millionShares outstanding 353 millionEnterprise value (2)(3) $2.9 billionNet debt at June 30, 2019 (2) $829.2 millionNet debt to annualized funds from operations (2)(4) 1.1 timesMonthly dividend $0.05/share
2019 YTD Production 2018 Proved + Probable Reserves
Crude oil and condensateNGLsNatural gas
11% 7%5%
77%Crude oilCondensate and pentanes plusNGLsNatural gas
879 MMboe
08/30/2019 1
Corporate Strategy
ARC’s Strategy Is Focused on Profitability, Sustainability, and Creating Optionality for the Long Term
RISK-MANAGED
VALUECREATION
HIGH-QUALITY,LONG-LIFE ASSETS, MARKET ACCESS &
PORTFOLIO MANAGEMENT
FINANCIALFLEXIBILITY &
CAPITALALLOCATION
HEALTH, SAFETY, ENVIRONMENT &
OPERATIONAL EXCELLENCE
TOP TALENT &STRONG
LEADERSHIPCULTURE
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.
(10%)
0%
10%
20%
30%
ROACE Trailing Three-year ROACE
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
08/30/2019 2
Funds from Operations
Dividend~$210 million
Sustaining Capital (1)
~$400 million
2020F Inflows 2020F Outflows
Capital Allocation Priorities
ARC Expects to Be Self-funding Once Dawson Phase IV Is Brought On-stream in Q2 2020
2019 Forecasted Capital Allocation 2020 Forecasted Capital Allocation
1.0 to 1.5xNet Debt to Funds from Operations 1.0 to 1.5xNet Debt to Funds
from Operations
Funds fromOperations
Dividend~$210 million
SustainingCapital (1)
~$400 million
Long-term Development Investments~$300 million
2019F Inflows 2019F Outflows
(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.
2019Budget$700 million
2020Budget$550 million to $625 million
Long-termDevelopmentInvestments
~$150 to $225 million
2019 Budget of $700 Million
Delivers Annual Production of 136,000 to 142,000 boe per day in 2019While Investing in 25,500 boe per day Infrastructure at Dawson Phase IV, Planned to Come on Stream in Q2 2020
ABBC
Red Creek
Attachie
SeptimusTower
ParklandSunsetSunrise
Sundown
Dawson
Pouce Coupe
Ante Creek
Attachie~$80MM • 10 wells
3,000 boe/dayContinue to pilot well designs to optimize capital efficiencies
Ante Creek~$100MM • 14 wells
16,000 boe/dayExpansion at Ante Creek 10-36 facility to add 15
MMcf/day of gas and 2,500 bbl/day of oil in Q2 2020
Pembina~$40MM • 11 wells
10,000 boe/dayManage production declines
and maximize cash flow generation from light
oil production
Parkland/Tower~$135MM • 14 wells
32,000 boe/daySustain production and
develop lower Montney via interconnect to Dawson
Pembina
Dawson~$305MM • 39 wells
42,000 boe/dayPhase I & II upgrade to be
completed by YE 2019; progress Phase IV facility to come on stream in Q2 2020; development is focused on liquids-rich lower Montney
$400MM – Sustaining Capital (1)
$300MM – Long-term Development Investments
(1) Sustaining capital does not have any standardized meaning and therefore should not be used to make comparisons to similar measures presented by other entities. Refer to “Other Definitions” in the Advisory Statements to this presentation.Note: Well counts denote wells drilled in calendar year; number of wells with completion activities in calendar year may vary.
Sunrise~$25MM
34,000 boe/daySuccessfully repatriated 60
MMcf/day in Q2 2019;production will ramp up once final transportation arrangements come
into effect in H2 2019
08/30/2019 3
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
0.6x
0.6x 0.8x 1.0x
1.0x 1.1x 1.2x 1.3x 1.4x
1.4x 1.6x 1.7x
1.7x
1.7x
1.7x 1.8x
1.8x 1.9x 2.0x 2.1x 2.2x
2.2x 2.3x 2.4x 2.
9x 3.1x 3.2x 3.5x 3.
9x
7.0xGroup Average
0.3x 0.5x
0.5x 1.
2x 1.3x
1.3x
1.3x 1.4x
1.4x
1.4x 1.5x 1.7x 1.8x 1.9x
1.9x 2.2x 2.3x 2.6x
2.6x 2.7x
2.7x 2.9x
2.9x 3.0x 3.2x
3.2x 3.3x 3.6x
4.7x 4.9x 5.2x
Group Average
(1) Source: RBC Research. Consensus estimates as per FactSet on July 17, 2019.
US Benchmarking: 2019E Year-end Net Debt / 2019E Cash Flow (1)
Canadian Benchmarking: 2019E Year-end Net Debt / 2019E Cash Flow (1)
World-class Montney Resource
GLJ Has Recognized over 3,500 Future Drilling Locations across ARC’s Montney Assets
Montney Optionality Reserve & Resource Summary (1)(2) Significant Montney Inventory (3)
Geographic OptionalityEgress OptionalityCommodity OptionalityMulti-layer Optionality
ABBC
Oil & Liquids
Dry Gas
Condensate-rich Gas 0
1,250
2,500
3,750
5,000
1
Num
ber o
f Loc
atio
ns
Development Unclarified ECR Booked LocationsDevelopment Pending ECR Booked Locations2P Booked Undeveloped LocationsTotal Hz Wells Drilled to YE 2018
0
1,000
2,000
3,000
4,000
MM
boe
Liquids
(1) Contingent resource consists of best estimate risked Development Pending and Development Unclarified ECR.(2) Prospective resource is best estimate risked.(3) Subject to change based on technology and economic environment.
08/30/2019 4
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
0.75
1.50
2.25
3.00
Parkland-DawsonLower Montney
DawsonUpper Montney
SunriseUpper Montney
0
15
30
45
60
Ante CreekUpper Montney
TowerUpper Montney
Attachie WestUpper Montney
Top-tier Montney Economics
Strong Rates of Return across the Montney Portfolio
Montney Liquids Break-evens (US$/bbl) (1) Montney Natural Gas Break-evens (Cdn$/Mcf) (1)(4)
2019 YTD Average Realized Condensate Price: $51.34/bbl
2019 YTD Average Realized Crude Oil Price: $50.24/bbl
2019 YTD Average Realized Natural Gas Price: $2.28/Mcf
Ante CreekUpper Montney
TowerUpper Montney
Attachie WestUpper Montney
SunriseUpper Montney
DawsonUpper Montney
Parkland-DawsonLower Montney
130% 85% to 110% 50%
5.6x 3.2x to 3.4x 4.0x
80% to 110% 80% to 90% 70%
4.2x to 4.3x 3.3x to 4.9x 5.3x
IRR (2)
Recycle Ratio (3)
(1) Break-even prices are US$ per barrel or Cdn$ per Mcf as indicated. Break-even analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero.(2) Internal rate of return (half-cycle after-tax rate of return) run at US$60/bbl WTI and Cdn$2.00/GJ AECO flat pricing.(3) Recycle ratio is calculated using first 12 months of undiscounted netback divided by finding and development cost.(4) Parkland-Dawson Lower Montney and Dawson Upper Montney break-evens denote the midpoint of a range of outcomes depending on the liquids ratio.
IRR (2)
Recycle Ratio (3)
2019 YTD Average Realized Natural Gas Priceincluding Gain on Risk Management Contracts: $2.78/Mcf
08/30/2019 5
0
4
8
12
16
0
6
12
18
24
(1) Source: Peters & Co. 2018 Reserves Comparison – E&P Producers (March 29, 2019). Three-year 2P FD&A Costs represent data for the years 2016 to 2018 and include future development capital.(2) Refer to ARC’s February 7, 2019 news release entitled, “ARC Resources Ltd. Announces 118 MMBoe of Total Proved Plus Probable Reserve Additions in 2018, Replacing 245 Per Cent of Production, and Delivers Record Proved Producing Reserve
Additions of 82 MMBoe” for information pertaining to ARC’s finding and development costs.(3) Three-year 2P FD&A Costs peer group includes: BNP, BTE, CPG, PEY, POU, TOU, VET, VII, WCP.(4) Includes future development capital for build-out of Dawson Phase I & II liquids-handling upgrade and new Dawson Phase IV infrastructure.(5) Q1 2019 Operating Expense from company reports and represent data for the three months ended March 31, 2019.(6) Q1 2019 Operating Expense peer group includes: BNP, BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(7) Source: Peters & Co. Limited E&P Overview Tables (July 22, 2019). Peer group includes APA, AR, COG, DVN, ECA, EOG, FANG, PXD.
Cost Management & Decline Rate
Low-cost Producers with a Low Decline Rate Deliver Superior Returns over Time
Group Average
ARC
NE
BC
Oil
& G
asARCARC
Group Average
ARC
Sun
rise
Gas
ARC
Daw
son
(4)
ARC
NE
BC
Oil
& G
as
ARC
Sun
rise
Gas
ARC
Daw
son
Three-year 2P FD&A Costs ($/boe) (1)(2)(3) Q1 2019 Operating Expense ($/boe) (5)(6) Corporate Decline Rates (7)
0%
10%
20%
30%
40%
ARC
Oil & Liquids Financial and Physical Price Management
58% of ARC’s 2019 YTD Commodity Sales from Production Was Derived from Crude Oil and Liquids
79% of ARC’s liquids production is made up of oil and condensate
40% 39%
21%0
20
40
60
80
Jul-1
8
Aug-
18
Sep-
18
Oct
-18
Nov
-18
Dec
-18
Jan-
19
Feb-
19
Mar
-19
Apr-1
9
May
-19
Jun-
19
US$
/bar
rel
Benchmark Pricing
Mixed Sweet BlendWTICondensateWestern Canadian Select
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 2019 production guidance.
0%
15%
30%
45%
60%
Per C
ent o
f Cru
de O
il Pr
oduc
tion
Hed
ged
Crude Oil Hedges (1)
08/30/2019 6
Natural Gas Financial and Physical Price Management
Integrated Physical Marketing and Financial Risk Management StrategiesEnable ARC to Effectively Execute on Its Long-term Plans
Natural Gas Flows and Sales Points (2019 YTD in US$/MMBtu) ARC’s Natural Gas Price and Diversification (4)(5)(6)
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
$0.72
$0.18
$0.54
Malin
$3.03
$0.15
$0.48
$2.40
Chicago
$2.89
$0.15
$0.66
$2.08
Ventura
$2.85
$0.15
$0.54
$2.16
Dawn
$2.63
$0.15
$0.79
$1.69
AECO
$1.17
$0.15
$1.02
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 YTD 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.(5) Based on production assumptions for sanctioned projects.(6) “Hedged” includes all physical and financial fixed price swaps and collars at AECO, Station 2, and Henry Hub.
28%14% 6%
18%
24% 45%
6%11%
8%26%
18%15%
14%22% 13%
4% 7% 7%4% 4% 6%
Bal 2019 Cal 2020 Cal 20210%
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
$1.28 $1.43 $1.70$2.22
$1.07
$0.63$0.72
$1.15$0.57
$0.67
$1.05 $0.87
$0.62$0.36
$0.63
$2.96 $3.02
$3.47$3.15
$2.37
0.00
1.00
2.00
3.00
4.00
Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019
Cdn
$/M
cf
Diversification Activities
Realized Gain on Risk Management Contracts
Average Price before Diversification Activities
Responsible Environmental Practices
• Consistent reductions in GHG emissions intensity due to facilityand multi-well pad electrification projects
• GHG emissions intensity reduced by 17 per cent and absoluteGHG emissions reduced by 11 per cent from 2017 to 2018
Strong Environmental Performance Underpins ARC’s Sustainable Future Growth
0.00
0.01
0.02
0.03
0.04
2014 2015 2016 2017 2018 2021Target
tonn
es o
f CO
2eq
uiva
lent
per
boe
GHG Emissions Intensity (1)
(tonnes of CO2 equivalent per boe)
25% reduction target relative to
2017 baseline
• $55 million of water infrastructure investments in ARC’s Montneyoperations since 2017 to add 700,000 m3 of water storage capacity
• Freshwater usage reduced by 25 per cent from 2017 to 2018
Reducing GHG Emissions Intensity Reducing Freshwater Needs
(1) Includes Scope 1 and Scope 2 emissions.
7%12%
17%
Dawson Water Reservoir
Parkland Water Hub
08/30/2019 7
Strong Safety Performance
• Strong safety performance is the result of well-planned and executed operations and alignment with strong service providers
Zero Lost-time Incidents (“LTI”) for Employees and Contractors in 2018; Over Five Years LTI-free for Employees
0.0
0.5
1.0
1.5
2.0
2014 2015 2016 2017 2018 2019 YTD
Tota
l Rec
orda
ble
Inci
dent
Fre
quen
cy 75%Reduction
Contractor Total Recordable Incident Frequency
Environmental, Social, and Governance Excellence
Responsible Development Is Engrained in ARC’s Long-term Strategy and Has Shaped the Company We Are Today
(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.
ARC
ESG Ratings by Major Oil Producing Country (1) Oil and Gas Companies’ Relative ESG Rankings (1)
08/30/2019 8
100% Owned-and-operated Infrastructure
ARC Is Building Sustainable Businesses in the Montney and Is Increasing Its Liquids Processing Capacity
Multi-year Investment Plan
Existing Infrastructure 2018 to 2019 Q4 2019 Q2 2020 Q2 2020
SunrisePhase II
DawsonPhase I & II
Upgrade
DawsonPhase IV
Ante Creek Expansion
Attachie WestPhase I
~$575 Million Facility Investment ~$360 Million Facility InvestmentTotal
~$935 Million
17.5 Mbbl/day Liquids-handling Capacity540 MMcf/day Natural Gas Processing Capacity
30 Mbbl/day Liquids-handling Capacity165 MMcf/day Natural Gas Processing Capacity
47.5 Mbbl/day705 MMcf/day
Montney Natural Gas Processing CapacityMontney Crude Oil & Liquids Processing CapacityCardium Production
Multi-year Infrastructure Investment Plan
Projects
Processing Capacity2017 2018 2019 2020 2021 2022
Oil and Condensate
(bbl/day)NGLs
(bbl/day)
Natural Gas
(MMcf/day)Total
(boe/day)
SunrisePhase II
1
180 30,000
DawsonPhase IV (1) 7,500 3,000 90 25,500
Attachie West Phase I 10,000 4,000 60 24,000
Sanctioned Development Processing Capacity Available
Significant Incremental Production Capacity from Infrastructure Investments
ARC is also investing in the following facility upgrade projects:• Dawson Phase I & II Upgrade – 2,000 bbl/day of condensate and 1,000 bbl/day of NGLs – YE 2019• Ante Creek Expansion – 2,500 bbl/day of oil and 15 MMcf/day of natural gas – Q2 2020
Sanctioned Q4 2016
New
Pilot & Commercialize
(1) Condensate production expected to stabilize at ~3,000 bbl/day and NGLs production expected to stabilize at ~1,500 bbl/day.
08/30/2019 9
Dawson Phase IV Business Model
Infrastructure Investment in Greater Dawson Area Is Supporting ARC’s Broad Shift to the Liquids-rich Lower Montney
Dawson Phase IV
(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$60/bbl WTI and Cdn$2.00/GJ AECO flat pricing.
~$290 MillionInitial Investment
Facility, Infrastructure, andWells to Fill Plant
Drill 8 to 10 Wells per Year40% of Netback Required to Sustain Business (2)
-35,000
-30,000
-25,000
-20,000
-15,000
-10,000
-5,000
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
000,000)
000,000)
$0
,000,000
,000,000
,000,000
-35,000
-30,000
-25,000
-20,000
-15,000
-10,000
-5,000
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
,000,000)
,000,000)
$0
,000,000
,000,000
,000,000
2018
F
2019
F
2020
F
2021
F
2022
F
2023
F
2024
F
2025
F
2026
F
2027
F
2028
F
2029
F
2030
F
Natural Gas Processing Capacity: 90 MMcf/dayCondensate-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)
Netback (1)(2)
Capital ExpendituresFacility Expenditures
ProductionNetback less Capital Expenditures
2018
Strategic Optionality
Scalability Allows for Profitable Growth to Generate Sustainable Funds from Operations and Maintain Financial Strength
2018
Base Production (Montney & Cardium)
In Progress
Future Development Projects
~133 Mboe/day
Greater Dawson Area• Dawson I & II Liquids-handling Upgrade (YE 2019)• Dawson IV (Q2 2020)• Dawson V – Parkland/Tower IIIAnte Creek• Ante Creek 10-36 Expansion (Q2 2020)Attachie• Attachie West I – Attachie West II – Attachie Central I & II – Attachie East I & IIGreater Sunrise Area• Sunrise III – Septimus I & II – Sundown
Attachie
GreaterSunrise Area
GreaterDawson Area
Ante Creek
08/30/2019 10
Greater Dawson Area Overview
Lower Montney Focus with Dawson Phase IV and Infrastructure Enhancements at Dawson Phase I & II
Snapshot Development Plan
2019 Development Focus
Infrastructure Build-out
31Mbbl/day
360MMcf/day
2010 2011 2013 2015 2017 YE 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
$440 million(63%)
$700 million (1)
53 wells(60%)
88 wells (1)
74 Mboe/day(53%)
136 to 142 Mboe/day (1)
• Development focused on liquids-rich lower Montney• Phase I & II liquids-handling upgrade to be completed by YE 2019• Dawson Phase IV being progressed and expected to be on-stream in Q2 2020
Tower
Parkland
Dawson
Pembina & EnbridgeTCPLParkland-Dawson Interconnect Pipeline
Phase I & IIGas Plants
Phase III & IVGas Plants
Phase I & IIGas Plants
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2019.
Lower Montney Production Success
Strong Liquids Results to Produce into Integrated Infrastructure of Greater Dawson Area
Parkland
Dawson
Free Condensate-to-gas Ratio (bbl/MMcf)
• High free condensate-to-gas ratio (“CGR”) in Parkland and northwest Dawson is yielding development wells with strong profitability
• Strong gas deliverability within the core of Dawson is yielding development wells with strong condensate production and strong profitability despite lower CGRs
• Sufficient thickness exists in Parkland and Dawson for multi-layer lower Montney development
100
Phase III & IVGas Plants
Phase I & IIGas Plants
08/30/2019 11
15Mbbl/day
75MMcf/day
Existing Infrastructure 2012 Q2 2020
Ante Creek Overview
Strong Cash Flow Generating Asset with Facility Expansion Project Planned for Q2 2020
Snapshot
Ante CreekPhase I
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
Ante CreekExpansion
Capital Budget Expected ProductionPlanned Wells
$700 million (1) 88 wells (1) 136 to 142 Mboe/day (1)
Development Plan
2019 Development Focus
Infrastructure Build-out
• Low-risk, high netback Montney light oil development• Ante Creek 10-36 facility expansion will add up to 2,500 bbl/day of light oil
production by Q2 2020
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2019.
$100 million(14%)
14 wells(16%)
16 Mboe/day(12%)
Attachie Overview
Regulatory Approval for Construction of Phase I and Sales Line Obtained
Snapshot
Attachie West Phase I
Capital Budget Expected ProductionPlanned Wells
$80 million(11%)
$700 million (2)
10 wells(11%)
88 wells (2)
3 Mboe/day(2%)
136 to 142 Mboe/day (2)
Development Plan
2019 Development Focus
Infrastructure Build-out
• 10-well pad drilled in Q2 2019; four wells will be completed in Q3 2019 with initial production expected in Q4 2019
• Advancing planning and regulatory approvals for Attachie West Phase I
PembinaNorth Montney Mainline
Phase IGas Plant4-20
Battery(3.5 Mbbl/day)
8.9 Bbbl liquids and 32 Tcf gas in place (1)
(1) Total Petroleum Initially-in-Place at Attachie.
Septimus
Attachie
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 2019.
17.5Mbbl/day
60MMcf/day
Existing Infrastructure
08/30/2019 12
240MMcf/day
2015 2018 2019
Sunrise Overview
Successfully Repatriated 60 MMcf per Day in Q2 2019, Final 60 MMcf per Day Expected to Be in Service in H2 2019
Snapshot
SunrisePhase I
Montney Natural Gas Processing Capacity
SunrisePhase II
SunrisePhase II
Capital Budget Expected ProductionPlanned Wells
$25 million(4%)
$700 million (1)
0 wells(0%)
88 wells (1)
34 Mboe/day(24%)
136 to 142 Mboe/day (1)
Development Plan
2019 Development Focus
Infrastructure Build-out
• Final 60 MMcf/day processing and sales capacity at Sunrise Phase II will be available in H2 2019 once final transportation arrangements are in place
• Exact timing and pace at which production is brought on-stream will be commodity price-dependent
Phase I & IIGas Plants
Sunset
Sunrise
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2019.
Pembina Overview
High Working Interest Light Oil Production, Competitive Operating Netback and Strong Cash Flow Generation
Snapshot
Capital Budget Expected ProductionPlanned Wells
$40 million(6%)
$700 million (1)
11 wells(13%)
88 wells (1)
10 Mboe/day(7%)
136 to 142 Mboe/day (1)
Development Plan
2019 Development Focus
• Managing production declines through modest drilling program• Maximizing cash flow generation from light oil production
Berrymoor
LindaleNPCU
MIPA
BuckCreek
SPCUPCU7
Crude oil and condensateNGLsNatural gas
2019 YTD Production Split(1) Denotes corporate total for capital budget, planned wells, and expected production for 2019.
78%
4%18%
10.3 Mboe/day
Blue boundaries denote units.
08/30/2019 13
2019 Guidance
2019 Capital Program Focused on Investing in Multi-year Development Projects to Grow Liquids Production
2019 OriginalGuidance
2019 Revised Guidance
2019 YTDActuals
Production
Crude oil and condensate (bbl/day) 25,500 - 30,500 26,000 - 30,000 27,487
Natural gas (MMcf/day) 620 - 630 620 - 630 614.2
NGLs (bbl/day) 6,000 - 6,500 6,500 - 7,000 7,111
Total production (boe/day) 135,000 - 142,000 136,000 - 142,000 136,985
Expenses ($/boe)
Operating 5.30 - 5.70 5.00 - 5.35 5.15
Transportation 2.60 - 2.90 2.90 - 3.10 2.97
G&A expense before share-based compensation expense 1.10 - 1.30 1.10 - 1.30 1.17
G&A - share-based compensation expense (1) 0.35 - 0.50 0.20 - 0.35 0.21
Interest and financing (2) 0.70 - 0.90 0.75 - 0.90 0.84
Current income tax expense (recovery) as a per cent of funds from operations (3) 2 - 7 (3) - 2 (3)
Capital expenditures before land purchases and net property acquisitions (dispositions) ($ millions) 775 700 387.9
Weighted average shares (millions) 353 353 353
(1) 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.
(2) Excludes accretion of asset retirement obligations.(3) The current income tax estimate varies depending on the level of commodity prices.
Additional Information
08/30/2019 14
Asset Details
Dawson Parkland/Tower Ante Creek Attachie Sunrise Pembina
Net productionCrude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)
4,007237.1
43,257
12,773118.7
32,561 (2)
8,38247.9
16,359
1,5878.4
2,988
96164.5
27,513
8,26411.2
10,126
LandNet sectionsWorking interest
137~100%
94~90% / ~94%
314~100%
308~99%
32~89%
217~89%
PDP Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (1)
729.3378
5
4414.1178
4
2010.2
603
52.5
14.84
590.3355
5
3933.4
3411
2P Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (1)
27542.0
1,39718
15249.861213
7236.621512
3114.8
9727
2392.7
1,41619
6352.1
6317
Diversified Commodity Mix across Portfolio of Assets
(1) Reserve life index based on 2019 guided production.(2) Production includes 4,976 boe/day (~45% condensate and NGLs) that was directed to Dawson Phase III for processing and sales via the Parkland-Dawson interconnect pipeline.
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 (1) Dividends (2)
(1) 2019 YTD based on annualized funds from operations for the six months ended June 30, 2019 and net debt as at June 30, 2019. (2) Calculated as dividends before Dividend Reinvestment Plan and Stock Dividend Program as a per cent of funds from operations.
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 Crude Oil & Liquids (bbl/day)
Montney Crude Oil & Liquids (bbl/day)
Non-Montney Natural Gas (boe/day)
0.0
0.5
1.0
1.5
2.0
2.5
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
YTD
Rat
io
$ m
illio
ns
Net Debt (LHS)
Funds From Operations (LHS)
Net Debt to 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
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)
2019 YTD28%
08/30/2019 15
Record Produced Reserves Replacement in 2018
• Strong 2018 development 2P reserve adds, with 245 per cent of produced reserves replaced• Finding and development costs of $5.76/boe for proved plus probable reserves and $6.02/boe for total proved reserves (2)
200 Per Cent Reserves Replacement or Greater for 11th 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 2018 reserves data is based on gross interest proved plus probable reserves.(2) Excludes future development capital.
Annual Produced Reserves Replacement (1)
(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
MM
boe
Reserves Replacement - Development Reserves Replacement - Net Acquisitions & Dispositions Reserves Replacement - Total Production
Key Reserve Information• Proved Producing 244 MMboe
• Total Proved 551 MMboe
• Proved plus Probable 879 MMboe• Crude and Tight Oil 98 MMbbl• NGLs 107 MMbbl• Natural Gas 4.0 Tcf
• 2P Reserve Life Index (1) 17.4 years
Year-end 2018 Reserves Added 118 MMboe of 2P Reserves through Development Activities
0
200
400
600
800
1,000
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018
2P R
eser
ves
(MM
boe)
Natural GasLiquids
(1) Based on 2019 original production guidance midpoint of 138,500 boe per day.
10% CAGR
YE 2018 2P Reserves
Oil11%
Condensate & Pentanes Plus
7%NGLs
5%
Natural Gas77%
PDP28%
PNP 1%
PUD34%
Probable37%
08/30/2019 16
CUMULATIVE PRODUCTION
TOTAL PROVED + PROBABLE RESERVES
DEVELOPMENTUNCLARIFIED
RISKED
DEVELOPMENTPENDINGRISKED
Large-scale Montney Resource
Extensive Development Potential from Montney Assets with TPIIP of 14.3 Billion Barrels of Oil and 101.8 Tcf of Shale Gas (1)
Oil 17 MMbblCondensate & NGLs 157 MMbbl
2.8 Tcf
ECONOMIC CONTINGENT RESOURCE
8.1 Tcf
(1) Independent Resources Evaluation conducted by GLJ effective December 31, 2018. Contingent Resource quoted is Best Estimate case. For reserves and resources disclosure, refer to ARC’s February 7, 2019 news release entitled, “ARC ResourcesLtd. 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”.
5.3 Tcf
4.0 Tcf
1.3 Tcf
Oil 48 MMbblCondensate & NGLs 104 MMbbl
Oil 38 MMbblCondensate & NGLs 39 MMbbl
Oil 47 MMbblCondensate & NGLs 255 MMbbl
ECONOMIC CONTINGENT RESOURCEOil 64 MMbblCondensate
& NGLs412 MMbbl
Shale Gas Tight Oil, Condensate & NGLs
Risk Management Program
Program Executed with a Long-term View; Fair Value of Risk Management Contracts Is a Net Asset of $104.5 Million (4)
(1) 2019 Forecast values based on actuals for the six months ended June 30, 2019 and forecast for July through December 2019 based on the forward price curve as at June 30, 2019 and net of credit adjustment. 2020 to 2024 Forecast values based onthe forward price curve as at June 30, 2019 and net of credit adjustment.
(2) Realized pricing is based on annual average settlements.(3) Refer to the “Financial Instruments and Market Risk Management” note in ARC’s financial statements and the section entitled, “Risk Management” contained within ARC’s MD&A.(4) Represents the fair value of ARC’s risk management contracts as at June 30, 2019.
WTIUS$/bbl
$62 $80 $95 $94 $98 $93 $49 $43 $51 $65
AECOCdn$/GJ
$3.91 $3.79 $3.44 $2.27 $3.00 $4.19 $2.63 $1.98 $2.30 $1.46
(100)
(50)
0
50
100
150
200
250
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019F 2020F 2021F 2022F 2023F 2024F
$ m
illio
ns
Crude Oil
Natural Gas
Foreign Exchange & Power
Total
Realized Gain (Loss) on Risk Management Contracts (1)(2)(3)
08/30/2019 17
Risk Management Contract Positions June 30, 2019
(1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listed above does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes. All positions are financially settled against the benchmark prices.(2) 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.(3) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton.(4) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.(5) Natural gas prices referenced to AECO 7A Index(6) ARC has entered into basis swaps at locations other than AECO.(7) Cdn$/US$ referenced to WM/Reuters Intra-day Spot Rate as of Noon Eastern Standard Time.(8) Variable rate collar whereby the ceiling will be adjusted to $1.3050 if the Cdn$/US$ spot rate is below $1.2748 at expiry.
Risk Management Contracts Positions (1) 2019 2020 2021 2022 2023 2024
Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling 65.78 4,000 62.53 4,000 63.69 3,500 - - - - - -Floor 52.50 4,000 53.75 4,000 55.00 3,500 - - - - - -Sold Floor 42.50 4,000 40.00 4,000 43.57 3,500 - - - - - -Swap 56.73 2,000 59.09 2,000 - - - - - - - -Crude Oil – Cdn$ WTI (2) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 88.00 1,000 86.38 6,500 - - - - - - - -Floor 80.00 1,000 75.38 6,500 - - - - - - - -Sold Floor 65.00 1,000 60.38 6,500 - - - - - - - -Swap 71.17 8,000 - - - - - - - - - -Total Crude Oil Volumes (bbl/day) 15,000 12,500 3,500 - - -Crude Oil - MSW (Differential to WTI) (3) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/daySwap (9.40) 4,500 (9.97) 2,995 - - - - - - - -Natural Gas - NYMEX Henry Hub (4) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 3.38 120,000 3.32 50,000 3.32 50,000 3.43 25,000 - - - -Floor 2.78 120,000 2.75 50,000 2.75 50,000 2.66 25,000 - - - -Sold Floor 2.33 120,000 2.25 50,000 2.25 50,000 2.25 25,000 - - - -Swap 4.00 40,000 - - - - - - - - - -Natural Gas – AECO (5) Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.30 10,000 3.60 30,000 - - - - - - - -Floor 3.00 10,000 3.08 30,000 - - - - - - - -Swap 3.16 20,000 3.35 30,000 - - - - - - - -Total Natural Gas Volumes (MMBtu/day) 188,435 106,869 50,000 25,000 - -Natural Gas - AECO Basis
(Percentage of NYMEX Henry Hub) AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/day AECO/NYMEX MMBtu/daySold Swap 81 40,000 - - - - - - - - - -Natural Gas - AECO Basis
(Differential to NYMEX Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/daySold Swap (0.92) 133,424 (0.82) 98,361 (0.97) 34,192 - - - - - -Total AECO Basis Volumes (MMBtu/day) 173,424 98,361 34,192 - - -Natural Gas – Other Basis (MMBtu/day)
(Differential to NYMEX Henry Hub) (6) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 60,000 100,000 120,000 110,000 80,000 4,973Foreign Exchange (7) Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ Millions Cdn$/US$ US$ MillionsSold Average Rate Forward 1.2907 11 - - - - - - - - - -Ceiling (8) - - 1.2748 6 - - - - - - - -Floor (8) - - 1.3250 6 - - - - - - - -
Recognitions and Rankings• MSCI Global Sustainability Index
• Jantzi Social Index
• FTSE Russell’s FTSE4Good Index Series
• CDP Participant for nine consecutive years
• Joined the 30% Club in 2018
• Globe and Mail Board Games: Ranked 46 out of 236 companies with a score of 87/100
• Brendan Wood International: Ranked #1 in peer group for Confidence in Corporate Strategy in 2018
• 2016 Canadian Coalition for Good Governance: Best Disclosure of Corporate Governance and Executive Compensation Practices
• 2017 & 2018 IR Magazine Awards: Best IR in Energy Sector, Grand Prix for Mid-Cap, Best Financial Reporting, Best Use of Technology, Best Investor Relations Officer
• 2018 IR Magazine Global Awards: Best IR in Energy Sector
• 2019 IR Magazine Awards: Grand Prix for Mid-Cap, Best Investor Relations Officer
• 2018 Brendan Wood International: Global TopGun IRO and TopGun Company for Transparency and Reporting as Reported by Investors
08/30/2019 18
Appendix
Reserves and Resources DisclosureAll reserves and resources volumes for the Montney and elsewhere in this presentation are, unless indicated otherwise, as at
December 31, 2018 as evaluated by GLJ Petroleum Consultants Ltd. in accordance with the definitions, standards andprocedures contained in the Canadian Oil and Gas Evaluation Handbook and National Instrument 51-101 Standards forDisclosure for Oil and Gas Activities.
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.This presentation contains metrics commonly used in the oil and natural gas industry, such as “reserve replacement”, “reserve life
index” or “RLI”, “recycle ratio”, “finding and development costs” or “F&D costs”, “finding, development and acquisition costs” or“FD&A costs”, “netback”, “finding and development recycle ratio” or “F&D recycle ratio”, and “finding, development andacquisition recycle ratio” or “FD&A recycle ratio”. These terms do not have any standardized meaning and may not becomparable to similar measures presented by other issuers, and therefore should not be used to make such comparisons.
08/30/2019 19
Definitions of Oil and Gas Reserves and ResourcesReserves are estimated remaining quantities of 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 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.
Forecast
Definitions of Oil and Gas 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 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.
08/30/2019 20
This presentation contains forward-looking information and statements that may be identified by words like “outlook”, “estimates”and similar expressions. These forward-looking statements are based on certain assumptions that involve a number of risks anduncertainties and are not guarantees of future performance. Reference is made to the section titled “Forward-looking Statements”at the beginning of the presentation and also to the February 7, 2019 news release entitled, “ARC Resources Ltd. Announces 118MMboe of Total Proved Plus Probable Reserve Additions in 2018, Replacing 245 Per Cent of Production, and Delivers RecordProved Producing Reserve Additions of 82 MMboe” which may be found on ARC’s website at www.arcresources.com or onSEDAR at www.sedar.com and which are hereby incorporated by reference in this presentation and which outline a number ofassumptions, risks and uncertainties associated with forward-looking statements. Actual results could differ materially as a resultof changes to ARC’s plans, the impact of changes in commodity prices, general economic, market and business conditions aswell as production, development and operating performance and other risks associated with oil and gas operations.
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
08/30/2019 21
Notes
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08/30/2019 22
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 2018 2017FINANCIAL Q2 Q1 Q4 Q3 Q2 Q1 Q4 Q3Commodity sales from production 282.9 327.8 302.5 375.1 344.4 340.2 337.3 276.5
Per share, basic 0.80 0.93 0.86 1.06 0.97 0.96 0.95 0.78Per share, diluted 0.80 0.93 0.86 1.06 0.97 0.96 0.95 0.78
Net income (loss) 94.4 (54.6) 159.7 45.1 (45.9) 54.9 73.9 48.5Per share, basic 0.27 (0.15) 0.45 0.13 (0.13) 0.16 0.21 0.14Per share, diluted 0.27 (0.15) 0.45 0.13 (0.13) 0.16 0.21 0.14
Funds from operations (1) 193.0 186.2 208.6 205.0 204.4 201.0 221.1 163.8Per share, basic 0.54 0.53 0.59 0.58 0.58 0.57 0.63 0.46Per share, diluted 0.54 0.53 0.59 0.58 0.58 0.57 0.63 0.46
Dividends declared 53.1 53.1 53.1 53.0 53.1 53.1 53.1 53.0Per share (2) 0.15 0.15 0.15 0.15 0.15 0.15 0.15 0.15
Total assets 5,878.9 5,952.4 6,016.2 5,846.3 6,059.8 6,235.7 6,224.0 6,115.0Total liabilities 2,267.7 2,383.6 2,340.4 2,278.3 2,485.8 2,563.8 2,555.1 2,468.2Net debt outstanding (1) 829.2 796.3 702.7 667.8 757.0 728.0 728.0 645.1Weighted average shares, basic 353.4 353.4 353.4 353.5 353.5 353.5 353.5 353.5Weighted average shares, diluted 353.9 353.4 353.9 354.0 353.5 353.8 353.8 353.9Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.5 353.5 353.5 353.5CAPITAL EXPENDITURESGeological and geophysical 1.3 11.9 1.3 3.4 2.1 4.0 2.5 1.8Drilling and completions 107.0 129.2 60.5 114.2 102.6 139.1 154.8 119.3Plant and facilities 65.5 72.3 69.6 51.2 58.8 70.0 87.2 55.5Corporate assets 0.4 0.3 0.2 0.5 1.3 0.6 0.6 1.8Total capital expenditures 174.2 213.7 131.6 169.3 164.8 213.7 245.1 178.4Undeveloped land — — 0.2 — — 0.7 0.4 77.3Total capital expenditures, including
undeveloped land purchases 174.2 213.7 131.8 169.3 164.8 214.4 245.5 255.7Acquisitions — 0.2 — — — 0.2 2.2 —Dispositions (0.9) (0.2) (0.9) (96.2) (0.7) (98.3) — —Total capital expenditures, land purchases and
net acquisitions and dispositions 173.3 213.7 130.9 73.1 164.1 116.3 247.7 255.7OPERATIONALProduction
Crude oil (bbl/day) 18,272 18,251 20,092 23,867 24,893 25,037 24,641 25,020Condensate (bbl/day) 10,230 8,210 8,458 8,158 6,960 5,505 6,989 6,815Crude oil and condensate (bbl/day) 28,502 26,461 28,550 32,025 31,853 30,542 31,630 31,835Natural gas (MMcf/day) 596.4 632.5 603.3 574.2 537.9 564.9 572.4 549.6NGLs (bbl/day) 7,041 7,183 7,402 7,687 6,380 6,332 6,380 6,091Total (boe/day) 134,938 139,054 136,502 135,410 127,879 131,016 133,409 129,526
Average realized prices, prior to risk management contractsCrude oil ($/bbl) 70.26 63.72 43.30 78.62 78.57 69.50 67.29 54.50Condensate ($/bbl) 71.38 64.81 57.25 85.28 85.10 77.42 69.04 54.35Natural gas ($/Mcf) 1.74 2.79 2.85 2.15 1.91 2.50 2.27 2.00NGLs ($/bbl) 7.71 25.43 29.12 35.26 32.98 31.39 35.31 28.37Oil equivalent ($/boe) 23.04 26.20 24.09 30.12 29.59 28.85 27.48 23.20
TRADING STATISTICS (3)
($, based on intra-day trading)High 9.61 10.49 14.84 15.90 15.25 15.90 18.34 18.31Low 6.37 7.82 7.38 12.70 12.71 11.88 13.64 15.61Close 6.41 9.12 8.10 14.40 13.58 14.04 14.75 17.19Average daily volume (thousands) 2,255 2,291 2,117 1,246 1,150 1,406 1,114 1,008
CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. Kvisle (1)
Chairman
Myron M. StadnykPresident and Chief Executive Officer
David R. Collyer (1) (2)
John P. Dielwart (1) (3)
Fred J. Dyment (3) (4)
Kathleen O’Neill (4) (5)
Herbert C. Pinder Jr. (2) (4)
William G. Sembo (2) (5)
Nancy L. Smith (3) (5)
(1) Member of Safety, Reserves and Operational Excellence Committee(2) Member of Human Resources and Compensation Committee(3) Member of Risk Committee(4) Member of Policy and Board Governance Committee(5) Member of Audit Committee
OFFICERSMyron M. StadnykPresident and Chief Executive Officer
Terry M. AndersonSenior Vice President and Chief Operating Officer
P. Van R. DafoeSenior Vice President and Chief Financial Officer
Chris D. BaldwinVice President, Geosciences
Ryan V. BerrettVice President, Marketing
Kris J. BibbyVice President, Finance and Capital Markets
Sean R. A. CalderVice President, Production
Lara M. ConradVice President, Engineering and Planning
Armin JahangiriVice President, Operations
Lisa A. OlsenVice President, Human Resources
Grant A. ZawalskyCorporate Secretary
EXECUTIVE OFFICEARC Resources Ltd.1200, 308 – 4th Avenue SWCalgary, Alberta T2P 0H7T 403.503.8600TOLL FREE 1.888.272.4900F 403.503.8609W www.arcresources.com
TRANSFER AGENTComputershare Trust Company of Canada600, 530 – 8th Avenue SWCalgary, Alberta T2P 3S8T 403.267.6800
AUDITORSPricewaterhouseCoopers LLPCalgary, Alberta
ENGINEERING CONSULTANTSGLJ Petroleum Consultants Ltd.Calgary, Alberta
LEGAL COUNSELBurnet Duckworth & Palmer LLPCalgary, Alberta
CORPORATE CALENDARNovember 7, 2019Q3 2019 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.
