ARC Resources - ARC Resources - energy Creating...ARC’s production of conventional natural gas is...
Transcript of ARC Resources - ARC Resources - energy Creating...ARC’s production of conventional natural gas is...
energy Creating
for the world
Investor PresentationJanuary 2021
Advisory Statements
Forward-looking Information and Statements and Advisory StatementsThis presentation contains forward-looking information as to ARC’s internal projections, expectations, or beliefs relating to future events or future performance and includes information as to ARC’s future well inventory in its coreareas, its exploration and development drilling and other exploitation plans for 2020 and 2021, and related production expectations, expenditures and cash flows, the Company’s plans for constructing and expanding facilities, thevolume of ARC's crude oil and natural gas reserves and the volume of ARC's crude oil and natural gas resources in the Montney, the recognition of additional reserves and the capital required to do so, the life of ARC's reserves, thevolume and product mix of ARC's crude oil and natural gas production, future results from operations, and operating metrics. These statements represent Management’s expectations or beliefs concerning, among other things,future operating results and various components thereof or the economic performance of ARC. The projections, estimates, and beliefs contained in such forward-looking statements are based on Management's assumptions relatingto the production performance of ARC’s crude oil and natural gas assets, the cost and competition for services, the continuation of ARC’s historical experience with expenses and production, changes in the capital expenditurebudgets, future commodity prices, continuing access to capital, and the continuation of the current regulatory and tax regime in Canada, and necessarily involve known and unknown risks and uncertainties, such as changes in crudeoil and natural gas prices, infrastructure constraints in relation to the development of the Montney, risks associated with the degree of certainty in resource assessments, and including the business risks discussed in ARC’s annualand quarterly Management’s Discussion and Analysis and other continuous disclosure documents, and related to Management’s assumptions, which may cause actual performance and financial results in future periods to differmaterially from any projections of future performance or results expressed or implied by such forward-looking statements. Accordingly, readers are cautioned that events or circumstances could cause actual results to differmaterially from those predicted. Other than the 2020 and 2021 Guidance, which is discussed quarterly, ARC does not undertake to update any forward-looking information in this document whether as to new information, futureevents, or otherwise except as required by securities laws and regulations.
ARC has adopted the standard of six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil ratio when converting natural gas to barrels of oil equivalent ("boe"). Boe may be misleading, particularly if used inisolation. A boe conversion ratio of 6 Mcf:1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Given that the value ratiobased on the current price of crude oil as compared to natural gas is significantly different than the energy equivalency of the 6 Mcf:1 bbl conversion ratio, utilizing the 6 Mcf:1 bbl conversion ratio may be misleading as an indicationof value.
Throughout this presentation, crude oil refers to tight, light, medium, and heavy crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). ARC’s production ofheavy crude oil is considered to be immaterial. Natural gas refers to shale gas and conventional natural gas product types as defined by NI 51-101. ARC’s production of conventional natural gas is considered to be immaterial.ARC’s core producing properties that are considered to be shale gas include Attachie, Dawson, Parkland (including parts of Tower), and Sunrise, and as such, natural gas, condensate, and natural gas liquids (“NGLs”) aredisclosed. ARC’s core producing properties that are considered to be tight oil include Ante Creek and parts of Tower, and as such, crude oil, natural gas, and NGLs are disclosed. ARC’s core producing property that is considered tobe light crude oil is Pembina, and as such, crude oil, natural gas, and NGLs are disclosed.
Throughout this presentation, when condensate is disclosed, it is done so as it is the product type that is measured at the first point of sale. As per the Canadian Oil and Gas Evaluation (“COGE”) Handbook, condensate is a by-product of the NGLs product type. NGLs by-products include ethane, butane, propane, and pentanes-plus (condensate).
Non-GAAP MeasuresThroughout this presentation, ARC uses the terms netback and return on average capital employed (“ROACE”) to analyze the Company’s financial and operational performance. These non-GAAP measures do not have anystandardized meaning prescribed under International Financial Reporting Standards (“IFRS”) and therefore may not be comparable to similar measures presented by other issuers.
Netback
ARC calculates netback on a total and per boe basis as commodity sales from production less royalties, operating, and transportation expense. ARC discloses netback both before and after the effect of realized gain or loss on riskmanagement contracts. Realized gain or loss represent the portion of risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent measuresthat reflect how ARC’s risk management program can impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with information that iscommonly used by other oil and gas producers. The measurement on a per boe basis assists Management with evaluating operational performance on a comparable basis.
Return on Average Capital Employed
ARC calculates ROACE, expressed as a percentage, as net income (loss) plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months precedingperiod end. Capital employed is the total of net debt plus shareholders’ equity. ROACE since inception is the annual average net income (loss) plus interest and total income tax expense (recovery) for the years 1996 to 2020 YTDdivided by the average of the opening and closing capital employed over the same period. Refer to the "Capital Management" note in ARC’s financial statements for additional discussion on net debt. ARC uses ROACE as ameasure of long-term operational performance, to measure how effectively Management utilizes the capital it has been provided and to demonstrate to shareholders the sustainability of its business model and that capital has beeninvested profitably over the long term.
10% 8% 6%
76%
9% 9% 6%
76%
Corporate Profile
ARC Is a Canadian Oil and Gas Producer in Its 24th Year of Delivering on Its Disciplined, Returns-focused Value Proposition
Asset SnapshotCorporate Summary
(1) Average daily trading volume for the six months ended September 30, 2020.(2) Market capitalization and net debt as at September 30, 2020.(3) Refer to the “Capital Management” note in ARC’s financial statements.(4) Based on net debt as at September 30, 2020 and annualized funds from operations for the nine months ended September 30, 2020.
2020 YTD Production 2019 Proved + Probable Reserves
Crude oilCondensate and pentanes plusNGLsNatural gas
159 Mboe/day 910 MMboe
Attachie
GreaterSunrise Area
Ante Creek
GreaterDawson Area
Pembina
ABBC ARC holds ~1,000 net Montney sections (~636,000 acres)
Crude oilCondensateNGLsNatural gas
Founded July 11, 1996Ticker symbol TSX : ARXAverage daily trading volume (1) 4.4 millionShares outstanding 353 millionEnterprise value (2) $3.0 billionNet debt as at September 30, 2020 (3) $867.8 millionNet debt to funds from operations (3)(4) 1.4 timesQuarterly dividend $0.06/shareDividends paid since inception $6.7 billion
12/31/2020 1
A Differentiated Investment
ARC Is a Unique Long-term Investment
Guiding Principles
Sustainable Business Model
Risk Management around All Aspects of the Business
Superior Capital Discipline and Allocation
Operational Excellence and Top-tier ESG Performance
Owned-and-operated Infrastructure
Business Priorities in 2021
Protect the Balance Sheet, Support the Dividend, Prioritize Capital Investments That Drive Long-term Value and Profitability
Protect Strong Financial Position and Maintain Flexibility
Demonstrate Capital Disciplineand Profitability of Investments
Deliver Meaningful Returns to Shareholders
Strengthen balance sheet with surplus funds from operations Execute capital program of $375 million to
$425 million to sustain production at core Montney areas• 80% of program for profitable half-cycle
investments• Two minor infrastructure optimization
projects at Sunrise and Parkland/Tower
Generate strong funds from operations to pay dividend, sustain production, and substantially reduce net debt
Reduce net debt to annualized funds from operations to low end of, or possibly below, target range of 1.0 to 1.5x
Declare dividends of $0.24/share
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Capital Allocation Principles and Priorities
ARC’s Portfolio Approach to Capital Allocation Is Focused on Delivering Strong Returns to Shareholders
Dividend$85MM/year
Maintenance Capital
Sources of Cash Dividend Sustaining Capital DiscretionaryOutflows
Funds fromOperations
Inflows
•Debt Reduction•Long-termDevelopmentInvestments
•Share Buybacks•Dividend Increases•M&A
Outflows
Pay sustainable dividend
Focused on:• Protecting strong financial position and
maintaining flexibility• Prioritizing profitability and value over
volumes• Returning capital to shareholders
Manage net debt to funds from operationsratio within 1.0 to 1.5x
Profitably sustain production through efficient execution and controlled decline rate
Capital Allocation Principles Capital Allocation Priorities
Com
mitt
edC
apita
lD
iscr
etio
nary
Cap
ital
Historical Capital Allocation and Outlook
ARC Anticipates to Generate Sufficient Funds from Operations in 2020 and 2021to Fund Its Dividend and Capital Requirements and to Substantially Reduce Net Debt
Inflows Outflows
Funds from Operations Net A&D Proceeds Dividend Capital Expenditures
2016 to 2019 Capital Allocation 2020 Forecasted Capital Allocation 2021 Forecasted Capital Allocation
Inflows Outflows Inflows Outflows
12/31/2020 3
Financial Strength
ARC Has One of the Strongest Balance Sheets in the Sectorand Targets Its Net Debt to Funds from Operations to Be in the Range of 1.0 and 1.5 Times over the Long Term
ARC
ARC
(1) Source: RBC Capital Markets. Consensus estimates as per FactSet on October 21, 2020.
US Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)
Canadian Benchmarking: 2020E Year-end Net Debt / 2020E Cash Flow (1)
1.3 1.4 1.6 1.6 2.3 2.5 2.6 2.7 2.8 2.9 4.4 4.4 4.4 4.5 4.5 4.6
5.4 5.7 5.8 6.4 8.2
9.2
Group Average
0.7 0.8 1.3 1.3 1.9 2.0 2.2 2.7 3.0 3.1 3.4 3.4 3.5 3.8 4.1 5.0 5.3 5.7 5.8 6.3 6.7 7.1
Group Average
Significant Liquidity
ARC Has Ample Liquidity to Sustain Its Business
(1) As at September 30, 2020.(2) Assumes Cdn$/US$ exchange rate of 1.3324.(3) Credit Facility includes $40 million working capital facility.(4) Non-cash working capital not included.
Bank Credit Facility• $950 million committed credit facility plus $40
million••• Credit facility
Long-term Notes & Master Shelf•• Private Placement market• Notes are rated NAIC 2-• Repayments structured to mature over several years to
reduce financing risk
Cash & Existing Credit Capacity
Undrawn Master Shelf
$300.1MM
Cash & Cash Equivalents
$2.4MM
Undrawn Credit Facility
$818.9MMDrawn Master
Shelf$199.6MM
Long-term Notes$456.1MM
Drawn Credit Facility$171.1MM
$1.9 Billion Total Cash & Existing Credit Capacity($1.1 Billion Available) (1)(2)(3)(4)
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Production and Capital Expenditures
ARC Has Moved Towards an Expanded Production Base with Lower Capital Expenditures
Production (Mboe/day)
Capital Expenditures ($ millions)
123133
139
157 to 160 158 to 165
2017 2018 2019 2020F 2021F Production Base
830
679 692
350375 to 425
2017 2018 2019 2020F 2021F Capital Expenditures
Long-term Corporate Profitability
ARC Has Delivered a ~8% 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
(30)
(15)
0
15
30
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
YTD
ROACE Trailing Three-year ROACE
12/31/2020 5
2021 Guidance
$375 millionto $425 million
Invest
Allowing ARC to:
with low operating expense of $4.00 – $4.50/boe
Generate Meaningful Funds from Operations to Fully FundDividend and Capital Program and Strengthen Balance Sheet
to profitably sustain production in core areas and complete minor facility optimization projects at Sunrise and Parkland/Tower
While ensuring the safe and responsibleexecution of the capital program
750 – 775 MMcf/dayof natural gas production (1)
to produce158,000 – 165,000boe/day (1)
and drill
69 gross operated wells
32,500 – 36,500 bbl/dayof liquids production
(1) Does not incorporate the potential impact that third-party transportation restrictions may have on ARC’s natural gas production.
2021 Budget Is Focused on Maximizing Generation of Surplus Funds from Operations, Capital Discipline, Profitability, and Financial Strength
Advance Strong ESG Performance
2021 Guidance
(1) Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(2) Comprises expense recognized under the Restricted Share Unit and Performance Share Unit Plans, Share Option Plan, and Long-term Restricted Share Award Plan, and excludes compensation expense under the Deferred Share Unit Plan.
In periods where substantial share price fluctuation occurs, G&A expense is subject to greater volatility.(3) Excludes accretion of the asset retirement obligation.(4) The current income tax estimate varies depending on the level of commodity prices.(5) Ongoing weakness in commodity prices resulting from COVID-19 impacts on demand and market volatility may impact ARC’s future financial and operational results. ARC will continuously monitor its guidance and provide updates as deemed
appropriate.
2021Guidance (5)
Production
Crude oil (bbl/day) 12,000 - 13,500
Condensate (bbl/day) 11,000 - 12,500
Crude oil and condensate (bbl/day) 23,000 - 26,000
Natural gas (MMcf/day) (1) 750 - 775
NGLs (bbl/day) 9,500 - 10,500
Total production (boe/day) (1) 158,000 - 165,000
Expenses ($/boe)
Operating 4.00 - 4.50
Transportation 3.00 - 3.50
G&A expense before share-based compensation expense 1.00 - 1.25
G&A - share-based compensation expense (2) 0.30 - 0.45
Interest and financing (3) 0.45 - 0.55
Current income tax expense (recovery) as a per cent of funds from operations (4) 3 - 7
Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 375 - 425
12/31/2020 6
2021 Budget of $375 Million to $425 Million
80% of 2021 Budget Will Be Directed towards Profitable Half-cycle Investments in ARC’s Core Montney Areas
ABBC
Ante Creek$58MM • 16 wells~17,000 boe/day
Deliver profitable light oil production by leveraging2020 facility expansion
Pembina$6MM
~6,500 boe/dayPreserve light oil production
as liquids prices recover
Parkland/Tower$70MM • 12 wells~30,000 boe/day
Complete facility optimization and sour conversion to
enhance deliverability and profitability of the asset
Dawson$168MM • 32 wells~62,500 boe/day
Maximize throughput to capitalize on anticipated
strength in natural gas pricing
Note: Well counts denote wells drilled in calendar year; number of wells with completion activities in calendar year may vary.
Sunrise$77MM • 9 wells~40,000 boe/day
Expand existing facility by 40 MMcf/day and maximize throughput to capitalize on
anticipated strength in natural gas pricing
Attachie
Septimus
Tower
ParklandSunsetSunrise
Sundown
Dawson
Pouce Coupe
Ante Creek
Pembina
Attachie$6MM
~3,500 boe/dayComplete detailed
engineering work for development
Approach to ESG
ARC’s Guiding Principles for ESG Help Inform Comprehensive Strategies and Leading Performance
+ Ensure appropriate focus and oversight on ESG strategies and practices
+ Continually improve governance structure and processes
+ Ensure strong link between executive compensation and performance, including incorporating ESG metrics into determination of compensation levels
+ Be an industry leader in health, safety, and environmental practices and performance
+ Form strong relationships with Indigenous communities
+ Create shared value for society
+ Develop a diverse and inclusive workforce
Environmental Social GovernanceEnviro GoverSocial+ Provide low-carbon energy for
the future
+ Protect ARC’s water resources –“Secure, Reduce, Recycle”
+ Restore land
12/31/2020 7
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)
ESG Excellence
Canadian Energy Sector Is Regulated by Some of the Highest Standards and Is a Clean, Ethical Energy SourceARC Ranks among the Best in the World on Sustainability Performance
(1) Source: BMO Capital Markets; Yale Environmental Performance Index (EPI); Social Progress Imperative; Worldbank Worldwide Governance Indicators, BMO Capital Markets; Bloomberg; CSRHub. For presentation, an equal weight (1/3) of each index is represented.
(2) Source: BP “Statistical Review of World Energy” (2020). Reserves as at December 31, 2019.
ESG Ratings by Major Oil-producing Country (1)(2) Oil and Gas Companies’ Relative ESG Rankings (1)
ARC
40
46
52
58
64
70
40 46 52 58 64 70
Soci
al a
nd G
over
nanc
e Sc
ore
Environmental Score
Africa
Asia
Canada
Europe
Middle East
Latin America
Russia
United States
Emissions Management Strategy and Performance
ARC Delivered a 47 Per Cent Reduction in Its GHG Emissions Intensity Compared to Its 2017 BaselineA New Target Has Been Set to Reduce GHG Emissions Intensity by an Additional 20 Per Cent by 2025
GHG Emissions Performance (Scope 1 and 2)
2019 GHG Emissions Intensity Benchmarking (1)
(1) Peer group includes: BNP, BTE, CNQ, CPG, CVE, ERF, MEG, NVA, OVV, PEY, SU, TOU, VET, VII, WCP.
Emissions Management Strategy
Proactively focus on reducing GHG intensity
Set GHG emissions intensity reduction target
Incorporate emissions management solutions into project planning
0.00
0.03
0.06
0.09
0.12
ARC
201
9
ARC
201
8
tCO
2e/b
oe
0.00
0.01
0.02
0.03
0.04
0
300
600
900
1,200
2015 2016 2017 2018 2019 2025Target
GH
G E
mis
sion
s In
tens
ity (t
CO
2e/b
oe)
GH
G E
mis
sion
s (tC
O2e
)
Direct Emissions Indirect Emissions GHG Emissions Intensity
20% reduction target relative to
2019 baseline
12/31/2020 8
Water Management Strategy and Performance
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 is key in long-term planning
• $55 million of water infrastructure investments in ARC’sMontney operations since 2017 to add 700,000 m3 of water storage capacity
• Nearly 90 per cent of water used in ARC’s operations is recycled
Water Management Strategy in Action
Social and Governance Performance
The Energy That ARC Creates Provides People with the Opportunity to Live Better Lives
Safety People & Diversity Indigenous Relations
6 yearswithout an employeelost-time injury incident
37%decrease in contractor recordable injuriessince 2017
26%of leadership roles areheld by women
Target to achieve
30%female representation on Board of Directors within three years
Financial support tocommunity pow wows,culture camps, treatydays, and other initiatives
Proactive engagement with neighbouring Indigenous communities, ensuring Indigenous partners have access to employment and share in the benefits
12/31/2020 9
World-class Montney Resource
ARC Has Identified over 4,500 Future Drilling Locations across Its Montney Assets
Montney Optionality
• Geographic Optionality• Egress Optionality• Commodity Optionality• Multi-layer Optionality
ABBC
Oil & Liquids
Dry Gas
Condensate-rich Gas
(1) Subject to change based on technology and economic environment.
Significant Montney Inventory (1)
0
1,600
3,200
4,800
6,400
Wells Drilled to YE 2019 2P Booked Locations Internal Inventory Estimate
Num
ber o
f Loc
atio
ns
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
12/31/2020 10
Owned-and-operated Infrastructure
Owned-and-operated Infrastructure Affords ARC Greater Control over Its Cost Structure and Liquids Recoveries
Dawson Phase III & IV
Dawson Phase I & II
Parkland/Tower Phase I
Sunrise Phase I & II
NE BC
AB
Corporate Sales Capacity:• >800 MMcf/day of Natural Gas Capacity
Over 90% Owned and Operated
• >50 Mbbl/day of Liquids Capacity
Ante Creek 10-36
Ante Creek 10-7
Ante Creek 2-26
Best-in-class Operational Performance
Drilling and Completions Cost Reductions in Dawson Are an Example of ARC’s Commitment to Continuous Improvement
1,400
1,700
2,000
2,300
2,600
2014 2020
Dawson Drilling and Completions Costs ($/lateral metre) Operational Performance
60%Reduction
60% reduction in drilling and completions costs since 2014
Drilling times reduced from25 days to <10 days
Continuous improvement and optimization of completions design
and pumping efficiency
Drilling longer wells
12/31/2020 11
0.00
10.00
20.00
30.00
40.00
Ante CreekUpper Montney
TowerUpper Montney
Attachie WestUpper Montney
0.00
0.60
1.20
1.80
2.40
Parkland-DawsonLower Montney
DawsonUpper Montney
SunriseUpper Montney
Top-tier Montney Economics
Low Cost Structure Supports Strong Economics in Stable Pricing Environment
Montney Natural Gas Break-evens (Cdn$/Mcf) (1)(2) Montney Liquids Break-evens (US$/bbl) (1)
2020 YTD Average Realized Natural Gas Price: $2.04/Mcf
(1) Break-even prices are Cdn$ per Mcf or US$ per barrel as indicated. Break-even analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero. Montney natural gas break-evens run with WTI oil held constant at US$40 per barrel and Montney liquids break-evens run with AECO natural gas held constant at Cdn$2.00 per GJ.
(2) Parkland-Dawson Lower Montney and Dawson Upper Montney break-evens denote the midpoint of a range of outcomes depending on the liquids ratio.
2020 YTD Average Realized Natural Gas Priceincluding Gain on Risk Management Contracts: $2.12/Mcf
2020 YTD Average Realized Condensate Price: $34/bbl
2020 YTD Average Realized Crude Oil Price: $30/bbl
SunriseUpper Montney
DawsonUpper Montney
Parkland-DawsonLower Montney
Ante CreekMiddle Montney
TowerUpper Montney
Attachie WestUpper Montney
0
4
8
12
16
0
10
20
30
40
0
8
16
24
32
(1) Source: Peters & Co. 2019 E&P Reserves Comparative (April 7, 2020).(2) Refer to ARC’s Annual Information Form for information pertaining to ARC’s finding and development costs.(3) Three-year PDP FD&A Costs peer group includes: BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(4) H1 2020 Operating Expense from company reports and represent data for the six months ended June 30, 2020.(5) H1 2020 Operating Expense peer group includes: BTE, CPG, ERF, PEY, POU, TOU, VET, VII, WCP.(6) Source: Peters & Co. Limited E&P Overview Tables (November 3, 2020). Peer group includes APA, AR, COG, CXO, DVN, EOG, FANG, OVV, PEY, PXD, TOU, VII.
Cost Management and Decline Rate
Low-cost Producers with a Low Decline Rate Deliver Superior Returns over Time
Group Average
ARC
Group Average
Three-year PDP FD&A Costs ($/boe) (1)(2)(3) H1 2020 Operating Expense ($/boe) (4)(5) 2021E Corporate Decline Rates (%) (6)
ARC
Canadian ProducersUS Producers
ARC
Daw
son
ARC
ARC
Sun
rise
Gas
ARC
NE
BC
Oil
& G
as
Group Average
12/31/2020 12
36% 34%20%
12% 12%
10% 17%25% 33% 37%
16% 13%13% 15% 15%
15% 16%19% 14% 14%
9% 9% 12% 15% 7%9% 6% 6% 6% 10%5% 5% 5% 5% 5%
Bal 2020 2021 2022 2023 20240%
25%
50%
75%
100%
% o
f Tot
al P
rodu
ctio
n
Natural Gas Financial and Physical Price Management
ARC Is Increasing Its Exposure to Local Pricing Given Structural Improvements to WCSB
ARC’s Natural Gas Price and Diversification (2)(3)(4)WCSB Demand & Export Capacity Growth (1)WCSB Demand & Export Capacity Growth (1)
NGTL East Gate Capacity+1.3 Bcf/day by 2022
Intra-Alberta Demand+1.5 Bcf/day by 2025
LNG Canada Phase 1+2.1 Bcf/day by 2025
Enbridge T-South Capacity+0.2 Bcf/day by 2021
NGTL West Gate Capacity+0.3 Bcf/day by 2023
5.4 Bcf/day Demand & Export CapacityGrowth Expected by 2025
(1) Source: ARC Risk Research, TC Energy, Enbridge, company reports.(2) Realized gain on risk management contracts is not included in ARC’s realized natural gas price.(3) Based on internal production assumptions and adjusted for ARC’s heat content.(4) “Hedged” includes all physical and financial fixed price swaps and collars.
Diversification Activities
Realized Gain on Risk Management Contracts
Average Price before Diversification Activities
Dawn Floating
Malin Floating
Henry Hub Floating
Midwest US Floating
AECO Floating
Station 2 Floating
Hedged
1.65 1.72 2.13 2.07 2.26
0.72 0.40
(0.08) (0.15) (0.10)
0.81 0.44
0.09 0.11 0.02
3.18
2.56 2.14 2.03 2.18
(0.50)
0.50
1.50
2.50
3.50
2018 2019 Q1 2020 Q2 2020 Q3 2020
Cdn
$/M
cf
Financial Price Management
Hedging Program Mitigates Volatility in Funds from Operations and Provides Certainty of Cash Flows
Crude Oil & Condensate Production Hedged (bbl/day) Natural Gas Production Hedged (MMBtu/day)
0
5,000
10,000
15,000
20,000
Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 20210
90,000
180,000
270,000
360,000
Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021
~70% of Crude Oil & Condensate Hedged for the Balance of 2020 and~40% Hedged for 2021
~40% of Natural Gas Hedged for the Balance
of 2020 and 2021
12/31/2020 13
Resource Potential and Scalability
ARC has:
• ~1,000 net Montney sections (~636,000 acres)
• Over 4,500 future drilling locations identified across the Montney
• Commodity, geographic, and multi-layer optionality
Scalability Allows for Profitable Growth to Generate Sustainable Funds from Operations and Maintain Financial Strength
2019
Base Production (Montney & Cardium)
Dawson Phase IV & Ante Creek Expansion
Future Development Projects
Attachie
GreaterSunrise Area
GreaterDawson Area
Ante Creek
~139 Mboe/day
2010 2011 2013 2015 2017 2019 Q2 2020 Q4 2021
Greater Dawson Area Overview
Large Integrated Network of Owned-and-operated Infrastructure
Snapshot Development Plan
2021 Development Focus
Infrastructure Build-out
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
• Maximize throughput to capitalize on anticipated strength in natural gas pricing• Improve Parkland/Tower’s deliverability and profitability with facility optimization
and sour conversion project
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 2021.
Capital Budget Expected ProductionPlanned Wells
$375 million to $425 million (1) 69 wells (1) 158 to 165 Mboe/day (1)
$238 million(58%)
44 wells(64%)
~92.5 Mboe/day(57%)
Parkland/Tower
Optimization
12/31/2020 14
Lower Montney Development and Liquids Growth
Integrated Approach to Development in Greater Dawson Area Allows ARCto Optimize Infrastructure Capacities to Maximize Profitability
(1) Total Petroleum Initially-in-Place as at December 31, 2018.(2) NGLs volumes are Unrisked Best Estimate Economic Contingent Resource as at December 31, 2018.
Parkland
Dawson
2020 Lower Montney Wells2019 Lower Montney Wells
Phase II & IVGas Plants
Phase I & IIGas Plants
100.
Greater Dawson Area Lower Montney Development
• 23 Tcf (1) of resources in lower Montney
• 105 MMbbl of contingent resource NGLs, of which 71 MMbbl is condensate (1)(2)
Large Resourcein Place
Tiered Inventory
Strong Return on Investment
• North Dawson & ParklandCGR: ~150 bbl/MMcf
• Core Dawson CGR: ~40 bbl/MMcf• 300+ drilling locations at Dawson
250+ drilling locations at Parkland/Tower
• Prioritize wells based on return on investment
• Lower Montney wells have strong IRR and one-year payout
• Improved capital efficiency through increased lateral length Free Condensate-to-gas Ratio (bbl/MMcf)
2021 Lower Montney Wells
0
50,000
100,000
150,000
200,000
0 12 24 36 48 60
Cum
ulat
ive
Con
dens
ate
Prod
uctio
n (b
bl)
Months on Production
Greater Dawson Area Strong Condensate Results
Strong Range of Condensate Outcomes from Both Upper and Lower Montney Development
Greater Dawson Area Condensate Performance
Type Curve
NGLs[C2,C3,C4]EUR (Mbbl)
Condensate EUR (Mbbl)
Natural Gas
EUR (Bcf)
Upper Montney Low End 10 30 7.3
Upper Montney High End 105 85 5.9
Lower Montney Low End 110 100 6.0
Lower Montney High End 80 240 2.4
Lower Montney Range
Upper Montney Range
12/31/2020 15
Optimizing Dawson Lower Montney Development
Technology Has Enhanced Profitability through Improved EURs, Better Capital Efficiency, and Lower F&D Costs
Estimated Ultimate Recovery (Mboe) Capital Efficiency ($/boe/day)
Well Costs ($ millions) Finding and Development Costs ($/boe)
0
375
750
1,125
1,500
2017 2018 20190
2,500
5,000
7,500
10,000
2017 2018 2019
3,500
4,000
4,500
5,000
5,500
2017 2018 20190
2
4
6
8
2017 2018 2019
Dawson Phase IV On-stream
Commissioning Activities Completed in Q1 2020 and Facility Brought On-stream in Q2 2020Wells to Initially Fill Facility Are Meeting Type Curve Expectations
Dawson Phase IV Project Checklist
Commercial and Development Execution
Regulatory Approval Secured
Takeaway Secured
Economics Robust
Facility Execution
Project Cost On budget
Safety 0 LTIs
On-stream April 2020
12/31/2020 16
2015 2018 2019 Q4 2021
Sunrise Overview
Low-cost Natural Gas Development with Excellent Deliverability
Snapshot
SunrisePhase I
Montney Natural Gas Processing Capacity
SunrisePhase II
SunrisePhase II
Development Plan
2021 Development Focus
Infrastructure Build-out
• Complete infrastructure optimization project to add 40 MMcf/day of processing and sales capacity
• Maximize throughput to capitalize on anticipated strength in natural gas pricing
Phase I & IIGas Plants
Sunset
Sunrise
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2021.
Capital Budget Expected ProductionPlanned Wells
$375 million to $425 million (1) 69 wells (1) 158 to 165 Mboe/day (1)
$77 million(19%)
9 wells(13%)
~40 Mboe/day(25%)
SunrisePhase I & IIExpansion
Existing Infrastructure 2012 Q2 2020
Ante Creek Overview
Low-risk Montney Light Oil Development
Snapshot
Ante CreekPhase I
Ante CreekExpansion
Development Plan
2021 Development Focus
Infrastructure Build-out
• Deliver profitable light oil production by leveraging 2020 facility expansion
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
2-26Gas Plant
10-7Gas Plant
10-36Gas Plant
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2021.
Capital Budget Expected ProductionPlanned Wells
$375 million to $425 million (1) 69 wells (1) 158 to 165 Mboe/day (1)
$58 million(14%)
16 wells(23%)
~17 Mboe/day(11%)
12/31/2020 17
Existing Infrastructure
Attachie Overview
Most Recent Development Activities Have Improved Area’s Capital Efficiencies
Snapshot
Attachie West Phase I
Development Plan
2021 Development Focus
Infrastructure Build-out
• Complete detailed engineering work for development• Will recommence drilling activities once development is undertaken to ensure the
most efficient and profitable execution possible
Phase IGas Plant
Montney Crude Oil & Liquids Processing Capacity
Montney Natural Gas Processing Capacity
4-20Battery
(3.5 Mbbl/day)
Phase IGas Plant
COP Acreage Acquired from KEL (1)
(1) ConocoPhillips acquired Kelt’s acreage in Q3 2020.
PembinaNorth Montney Mainline
ARC AcreageCOP Acreage
(1) .(2) Denotes corporate total for capital budget, planned wells, and expected production for 2021.
Capital Budget Expected ProductionPlanned Wells
$375 million to $425 million (2) 69 wells (2) 158 to 165 Mboe/day (2)
$6 million(1%)
0 wells(0%)
~3.5 Mboe/day(2%)
0
75
150
225
300
0 300 600 900 1,200 1,500Days on Production
Continuous Improvement in Pad and Well Design
Well Results from 2-27 Pad Phase I Have Validated Pad and Well Design Changes
Pad and Well Design Evolution Cumulative Oil & Condensate Production (Mbbl)
(1) Facility constraints relieved in Q2 2020; three of four wells on 2-27 Pad Phase I produced consistently prior to this. Over 235 days of production, the four wells have produced approximately 445,000 barrels of condensate and approximately 1,375 MMcf of natural gas.
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
16-16 Well13-26 WellB13-26 Well13-14 Pad Average2-27 Pad Phase I Average (1)
2-27 Pad Phase II AverageAttachie Type Curve
12/31/2020 18
Advancing Attachie towards Commercialization
ARC Is Progressing the Technical, Commercial, and Funding Aspects of Attachie West Phase I
Technical Commercial Funding
Strong liquids deliverability
Improved capital efficiencies
Competitor activity
Commodity egress
Regulatory
Support infrastructure
Balance sheet
Maximize profitability
Project readiness
73%
2%4%21%
Pembina Overview
High Working Interest Light Oil Production
Snapshot Development Plan
2021 Development Focus
• Preserve light oil production as liquids prices recover
YTD 2020 Production Split
9.2 Mboe/day
Berrymoor
LindaleNPCU
MIPABuckCreek
SPCUPCU7
Blue boundaries denote units.
Crude oilCondensateNGLsNatural gas
(1) Denotes corporate total for capital budget, planned wells, and expected production for 2021.
Capital Budget Expected ProductionPlanned Wells
$375 million to $425 million (1) 69 wells (1) 158 to 165 Mboe/day (1)
$6 million(1%)
0 wells(0%)
~6.5 Mboe/day(4%)
12/31/2020 19
Additional Information
2020 Guidance
(1) Guidance does not incorporate the potential impact that third-party transportation restrictions may have on ARC's natural gas production.(2) Comprises expense recognized under the Restricted Share Unit and Performance Share Unit Plans, Share Option Plan, and Long-term Restricted Share Award Plan, and excludes compensation expense under the Deferred Share Unit Plan.
In periods where substantial share price fluctuation occurs, G&A expense is subject to greater volatility.(3) Excludes accretion of the asset retirement obligation.(4) The current income tax estimate varies depending on the level of commodity prices.
2020 OriginalGuidance
2020 Revised Guidance
(March 2020)
2020 Revised Guidance
(November 2020)2020 YTD
Actuals
Production
Crude oil (bbl/day) 15,000 - 17,000 14,000 - 16,000 15,000 - 16,000 15,784
Condensate (bbl/day) 12,000 - 14,000 11,000 - 13,000 12,000 - 13,000 13,117
Crude oil and condensate (bbl/day) 27,000 - 31,000 25,000 - 29,000 27,000 - 29,000 28,901
Natural gas (MMcf/day) (1) 715 - 725 705 - 710 725 - 730 724.5
NGLs (bbl/day) 8,500 - 9,000 8,000 - 8,500 9,000 - 9,500 9,258
Total production (boe/day) (1) 155,000 - 161,000 150,000 - 155,000 157,000 - 160,000 158,911
Expenses ($/boe)
Operating 4.55 - 4.95 4.55 - 4.95 4.00 - 4.20 3.93
Transportation 3.10 - 3.30 3.10 - 3.30 3.00 - 3.20 2.99
G&A expense before share-based compensation expense 1.00 - 1.20 1.00 - 1.20 1.05 - 1.15 1.15
G&A - share-based compensation expense (2) 0.30 - 0.45 0.30 - 0.45 0.30 - 0.45 0.43
Interest and financing (3) 0.65 - 0.80 0.65 - 0.80 0.65 - 0.75 0.71
Current income tax expense (recovery) as a per cent of funds from operations (4) (2) - 3 (2) - 3 (5) - 0 (8)
Capital expenditures before land and net property acquisitions (dispositions) ($ millions) 500 300 350 266.5
12/31/2020 20
2020 Budget of $350 MillionABBC
Ante Creek$65MM • 13 wells~16,000 boe/day
Expansion at Ante Creek facility brought on-stream in
Q2 2020
Pembina$3MM
~9,000 boe/dayPreserve light oil production
as liquids prices recover
Parkland/Tower$53MM • 8 wells~32,000 boe/day
Drilling activities deferredas liquids prices recover Dawson
$134MM • 19 wells~58,000 boe/day
Phase IV facility brought on-stream in Q2 2020; ensure maximum
throughput during winter months to capitalize on anticipated strength
in natural gas pricing
Note: Well counts denote wells drilled in calendar year; number of wells with completion activities in calendar year may vary.
Sunrise$48MM • 16 wells~38,500 boe/day
Ensure maximum throughput during winter months
to capitalize on anticipated strength in natural gas pricing
Attachie
Septimus
Tower
ParklandSunsetSunrise
Sundown
Dawson
Pouce Coupe
Ante Creek
Pembina
Attachie$31MM
~4,000 boe/dayOptimize pad profitability with
implementation of next generation of well design
Capital Budget Increased to $350 Million to Accelerate Development Activities at Dawson and Sunriseto Maximize Throughput during Winter Months to Capitalize on Anticipated Strength in Natural Gas Pricing
Asset Details
Diversified Commodity Mix across Asset Portfolio Provides Optionality
(1) Denote Montney or Cardium sections only.(2) Reserve life index based on 2020 guided production.
Dawson Sunrise Parkland/Tower Ante Creek Attachie Pembina
Net production – Q3 2020Crude oil & liquids (bbl/day)Natural gas (MMcf/day)Total (boe/day)
8,731309.1
60,251
21200.6
33,450
12,241123.8
32,876
9,72345.4
17,271
3,46012.0
5,458
6,31510.9
8,130
LandNet sections (1)
Working interest137
~100%32
~89%94
~90% / ~94%206
~100%308
~99%217
~89%
PDP Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)
7910.4410
4
660.3396
5
4614.6186
4
209.6623
62.8173
3832.7
3511
2P Reserves (MMboe)Liquids (MMbbl)Gas (Bcf)Reserves life index (Years) (2)
30051.2
1,49414
2342.5
1,39018
15348.962714
7838.623912
3920.511222
6049.9
6117
12/31/2020 21
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
2020
YTD
Rat
io
$ m
illio
ns
Net Debt (LHS)
Annualized Funds From Operations (LHS)
Net Debt to Annualized Funds from Operations (RHS)
Business Overview
ARC Manages a Profitable Business through Commodity Price Cycleswith Its Efficient Montney Production Base and Strong Balance Sheet
Production Net Debt to Funds from Operations Dividends (1)
(1) Dividends as a per cent of funds from operations calculated as dividends before Dividend Reinvestment Plan and Stock Dividend Program.
0%
30%
60%
90%
120%
0
2
4
6
8
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
YTD
Div
iden
ds a
s a
% o
f Fun
ds fr
om O
pera
tions
Cum
ulat
ive
Div
iden
ds ($
bill
ions
)
Cumulative Dividend (LHS)
Dividends as a % of Funds from Operations (RHS)
0
45,000
90,000
135,000
180,000
199
6 1
997
199
8 1
999
200
0 2
001
200
2 2
003
200
4 2
005
200
6 2
007
200
8 2
009
201
0 2
011
201
2 2
013
201
4 2
015
201
6 2
017
201
8 2
019
202
0 YT
D
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
50
100
150
200
Bal 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029
3.72% US$ Note8.21% US$ Note5.36% US$ Note3.31% US$ Note3.81% US$ Note4.49% Cdn$ Note
Note Repayment Schedule
Long-term Note Repayments Structured to Mature over Several Years to Reduce Financing Risk
Long-term Notes Principal Repayment Schedule (Cdn$ millions) (1)
(1) Assumes Cdn$/US$ exchange rate of 1.3324 at September 30, 2020.
12/31/2020 22
Risk Management Program
Program Executed with a Long-term View
(1) 2020 Forecast values reflect actuals for the nine months ended September 30, 2020 and forecast for October through December 2020 reflect the forward strip pricing curve as at September 30, 2020 (net of credit adjustment). 2021 to 2025 Forecastvalues reflect the forward strip pricing curve as at September 30, 2020 (net of credit adjustment).
(2) Refer to the “Financial Instruments and Market Risk Management” note in ARC’s financial statements and the section entitled, “Risk Management” contained within ARC’s MD&A.(3) Realized pricing is based on annual average settlements.
Realized Gain (Loss) on Risk Management Contracts ($ millions) (1)(2)
(100)
0
100
200
300
2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020F 2021F 2022F 2023F 2024F 2025F
Crude Oil
Natural Gas
Foreign Exchange & Power
Total
Risk Management Contracts PositionsRisk Management Contracts PositionsSeptember 30, 2020 Q4 2020 2021 2022 2023 2024 2025Crude 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 55.70 8,500 55.80 9,492 51.42 1,000 - - - - - -Floor 47.35 8,500 48.64 9,492 45.00 1,000 - - - - - -Sold Floor 41.92 6,500 39.92 8,492 35.00 1,000 - - - - - -Swap 45.16 4,000 35.05 1,000 - - - - - - - -Sold Swaption (2) - - 43.00 1,008 - - - - - - - -Crude Oil – Cdn$ WTI (3) Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/day Cdn$/bbl bbl/dayCeiling 86.38 6,500 - - - - - - - - - -Floor 75.38 6,500 - - - - - - - - - -Sold Floor 60.38 6,500 - - - - - - - - - -Total Crude Oil Volumes (bbl/day) 19,000 10,492 1,000 - - -Crude Oil – MSW (Differential to WTI) (4) US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/dayCeiling (7.00) 1,000 - - - - - - - - - -Floor (10.20) 1,000 - - - - - - - - - -Swap (8.01) 7,000 (6.11) 5,000 - - - - - - - -Natural Gas – Henry Hub (5) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 2.99 115,109 3.02 110,000 3.11 45,000 2.74 10,000 2.74 10,000 - -Floor 2.59 115,109 2.55 110,000 2.55 45,000 2.50 10,000 2.50 10,000 - -Sold Floor 2.19 115,109 2.10 110,000 2.18 45,000 2.10 10,000 2.10 10,000 - -Swap 1.86 6,739 - - - - - - - - - -Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/dayCeiling 3.05 83,152 2.41 120,000 2.47 110,000 2.40 90,000 2.40 90,000 2.73 20,000Floor 2.45 83,152 1.95 120,000 1.90 110,000 1.87 90,000 1.87 90,000 2.00 20,000Sold Floor 1.75 33,152 - - - - - - - - - -Swap 2.44 80,000 2.25 62,466 2.23 20,000 2.06 10,000 2.06 10,000 - -Sold Swaption (2) - - - - 2.00 20,000 - - - - - -Natural Gas – Chicago US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/dayCeiling 4.10 13,261 4.10 4,932 - - - - - - - -Floor 2.75 13,261 2.75 4,932 - - - - - - - -Total Natural Gas Volumes (MMBtu/day) 289,747 287,876 168,216 104,782 104,782 18,956Natural Gas – AECO Basis (Differential to Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/daySold Swap (0.81) 86,630 (0.93) 66,260 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000 - -Total AECO Basis Volumes (MMBtu/day) 86,630 66,260 35,000 70,000 70,000 -Natural Gas – Other Basis (Differential to Henry Hub) (6)
MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/daySold Swap 100,000 120,000 110,000 80,000 4,973 -
(1) The prices and volumes in this table represent averages for several contracts representing different periods. The average price for the portfolio of options listedabove does not have the same payoff profile as the individual option contracts. Viewing the average price of a group of options is purely for indicative purposes.All positions are financially settled against the benchmark prices.
(2) The sold swaption allows the counterparty, at a specified future date, to enter into a swap with ARC at the above-detailed terms. These volumes are not included in the total commodity volumes until such time that the option is exercised.
(3) Crude oil prices referenced to WTI, multiplied by the WM/Reuters Intra-day Cdn$/US$ Foreign Exchange Spot Rate as of Noon Eastern Standard Time.
(4) MSW differential refers to the discount between WTI and the mixed sweet crude grade at Edmonton calculated on a monthly weighted average basis in US$.(5) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.(6) ARC has entered into basis swaps at locations other than AECO.
12/31/2020 23
(40)
0
40
80
120
160
1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
MM
boe
Reserves Replacement - Development Reserves Replacement - Net Acquisitions & Dispositions Reserves Replacement - Total Production
Produced Reserves Replacement
• Strong 2019 development 2P reserve adds, with 164 per cent of produced reserves replaced• Finding and development costs of $4.82/boe for proved plus probable reserves and $9.74/boe for total proved reserves (2)
150 Per Cent Reserves Replacement or Greater for 12th Consecutive Year
Growth through Acquisition Organic Growth
(1) 1997 to 2002 reserves data is based on company interest established reserves (proved plus 50 per cent of probable reserves). 2003 to 2019 reserves data is based on gross interest proved plus probable reserves.(2) Includes future development capital.
Annual Produced Reserves Replacement (1)
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
12/31/2020 24
ESG Recognitions and Rankings
Member of MSCI Global Sustainability IndexMSCI ESG Rating: AAA
Voluntary participant since 20072020 Climate Change Score: A-2020 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
View ARC’s 2020 ESG Report at www.arcresources.com/responsibility
Reserves and Resources Disclosure
All reserves in this presentation are, unless indicated otherwise, as at December 31, 2019 as evaluated by GLJ Petroleum Consultants Ltd. (“GLJ”) in accordance with thedefinitions, standards, and procedures contained in the COGE Handbook and NI 51-101. Resources volumes for the Montney are as at December 31, 2018 as evaluatedby GLJ in accordance with the definitions, standards, and procedures contained in the COGE Handbook and NI 51-101 .
TPIIP, DPIIP, and UPIIP have been estimated using a one per cent porosity cut-off for shale gas and tight oil.Reserves volumes for ARC’s Montney assets and elsewhere in this presentation are, unless indicated otherwise, Proved plus Probable, while the resource categories for the
Montney in this presentation are “Best Estimates”.All reserves and resources volumes for the Montney and elsewhere in this presentation are company gross.Gas volumes are “sales” for reserves and resource and raw gas for DPIIP and TPIIP.The tight oil DPIIP is a stock tank barrel.All DPIIP and TPIIP other than cumulative production, reserves, Contingent Resources, and Prospective Resources have been categorized as unrecoverable.The amount of natural gas and liquids ultimately recovered from ARC’s the Montney resource will be primarily a function of the future price of both commodities.
12/31/2020 25
Definitions of Reserves and Resources
Reserves are estimated remaining quantities of crude oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a givendate, based on the analysis of drilling, geological, geophysical, and engineering data; the use of established technology; and specified economic conditions, which aregenerally accepted as being reasonable. Reserves are classified according to the degree of certainty associated with the estimates as follows:
Proved Reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered willexceed the estimated proved reserves.Probable Reserves are those additional reserves that are less certain to be recovered than proved reserves. It is equally likely that the actual remaining quantitiesrecovered will be greater or less than the sum of the estimated proved plus probable reserves.
Resources encompasses all petroleum quantities that originally existed on or within the earth’s crust in naturally occurring accumulations, including Discovered andUndiscovered (recoverable and unrecoverable) plus quantities already produced. "Total Resources" is equivalent to "Total Petroleum Initially-in-Place". Resources areclassified in the following categories:
Total Petroleum Initially-in-Place ("TPIIP") is that quantity of petroleum that is estimated to exist originally in naturally occurring accumulations. It includes that quantityof petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to bediscovered.Discovered Petroleum Initially-in-Place ("DPIIP") is that quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations prior toproduction. The recoverable portion of DPIIP includes production, reserves, and contingent resources; the remainder is unrecoverable.Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using establishedtechnology or technology under development but which are not currently considered to be commercially recoverable due to one or more contingencies.Economic Contingent Resources ("ECR") are those Contingent Resources which are currently economically recoverable.Project Maturity Subclass Development Not Viable is defined as a Contingent Resource that is not viable in the conditions prevailing at the effective date of theevaluation, and where no further data acquisition or evaluation is planned and therefore has not been assigned a low chance of development.Project Maturity Subclass Development Pending is defined as a Contingent Resource that has been assigned a high chance of development and the resolution of finalconditions for development are being actively pursued.Project Maturity Subclass Development Unclarified is defined as a Contingent Resource that requires further appraisal to clarify the potential for development and hasbeen assigned a lower chance of development until contingencies can be clearly defined.
Definitions of Reserves and Resources
Undiscovered Petroleum Initially-in-Place ("UPIIP") is that quantity of petroleum that is estimated, on a given date, to be contained in accumulations yet to bediscovered. The recoverable portion of UPIIP is referred to as "prospective resources" and the remainder as "unrecoverable".Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations by application offuture development projects.Unrecoverable is that portion of DPIIP and UPIIP quantities which is estimated, as of a given date, not to be recoverable by future development projects. A portion ofthese quantities may become recoverable in the future as commercial circumstances change or technological developments occur; the remaining portion may never berecovered due to the physical/chemical constraints represented by subsurface interaction of fluids and reservoir rocks.
Uncertainty Ranges are described by the COGE Handbook as low, best, and high estimates for reserves and resources. The Best Estimate is considered to be the bestestimate of the quantity that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. Ifprobabilistic methods are used, there should be at least a 50 per cent probability that the quantities actually recovered will equal or exceed the best estimate.
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Contact Information
Visit ARC’s Website at www.arcresources.com
Kris BibbySenior Vice President and Chief Financial Officer
403.503.8675
Martha WilmotInvestor Relations Analyst
403.509.7280
General Investor Relations Enquiries403.503.8600
1.888.272.4900
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Notes
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(1) Refer to the "Capital Management" note in ARC’s financial statements and to the sections entitled "Funds from Operations" and “Capitalization,Financial Resources and Liquidity” contained within ARC’s MD&A.
(2) Dividends per share are based on the number of shares outstanding at each dividend record date.(3) Trading statistics denote trading activity on the Toronto Stock Exchange only.
FINANCIAL ANDOPERATIONAL HIGHLIGHTS
2020 2019 2018($ millions, except per share amounts) Q3 Q2 Q1 Q4 Q3 Q2 Q1 Q4FINANCIAL RESULTSCommodity sales from production 285.0 217.9 269.5 325.1 253.7 282.9 327.8 302.5
Per share, basic 0.81 0.62 0.76 0.92 0.72 0.80 0.93 0.86Per share, diluted 0.81 0.62 0.76 0.92 0.72 0.80 0.93 0.86
Net income (loss) (66.1) (43.5) (558.4) (10.2) (57.2) 94.4 (54.6) 159.7Per share, basic (0.19) (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45Per share, diluted (0.19) (0.12) (1.58) (0.03) (0.16) 0.27 (0.15) 0.45
Funds from operations (1) 144.6 150.2 160.8 172.8 145.4 193.0 186.2 208.6Per share, basic 0.41 0.42 0.46 0.49 0.41 0.54 0.53 0.59Per share, diluted 0.41 0.42 0.46 0.49 0.41 0.54 0.53 0.59
Dividends declared 21.2 21.3 42.5 53.1 53.1 53.1 53.1 53.1Per share (2) 0.06 0.06 0.12 0.15 0.15 0.15 0.15 0.15
Total assets 4,982.9 5,136.8 5,172.6 5,778.3 5,819.2 5,878.9 5,952.4 6,016.2Total liabilities 2,292.7 2,360.3 2,332.4 2,338.4 2,317.1 2,267.7 2,383.6 2,340.4Net debt outstanding (2) 867.8 961.1 1,079.7 940.2 945.5 829.2 796.3 702.7Weighted average shares, basic 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4Weighted average shares, diluted 353.4 353.4 353.4 353.4 353.4 353.9 353.4 353.9Shares outstanding, end of period 353.4 353.4 353.4 353.4 353.4 353.4 353.4 353.4CAPITAL EXPENDITURESGeological and geophysical 2.4 3.4 6.5 0.9 1.1 0.3 9.3 0.3Drilling and completions 40.8 31.8 131.3 86.7 101.0 110.1 144.9 77.0Plant and facilities 5.9 8.3 25.8 47.5 51.1 56.2 53.3 41.4Maintenance and optimization 2.1 1.4 4.4 3.0 6.2 5.8 3.4 11.7Corporate assets 1.4 (0.8) 1.8 3.6 2.5 1.8 2.8 1.2Total capital expenditures 52.6 44.1 169.8 141.7 161.9 174.2 213.7 131.6Undeveloped land — — — — 0.7 — — 0.2Total capital expenditures, including undeveloped
land purchases 52.6 44.1 169.8 141.7 162.6 174.2 213.7 131.8Acquisitions — 0.5 2.5 — — — 0.2 —Dispositions — (0.6) (2.4) (1.1) (2.8) (0.9) (0.2) (0.9)Total capital expenditures, land purchases, and net
acquisitions and dispositions 52.6 44.0 169.9 140.6 159.8 173.3 213.7 130.9OPERATIONAL RESULTSProduction
Crude oil (bbl/day) 15,373 14,987 16,997 17,083 16,782 18,272 18,251 20,092Condensate (bbl/day) 14,831 13,239 11,262 10,937 10,846 10,230 8,210 8,458Crude oil and condensate (bbl/day) 30,204 28,226 28,259 28,020 27,628 28,502 26,461 28,550Natural gas (MMcf/day) 708.2 773.3 692.2 669.0 595.4 596.4 632.5 603.3NGLs (bbl/day) 10,208 9,405 8,152 8,123 7,952 7,041 7,183 7,402Total (boe/day) 158,444 166,510 151,783 147,650 134,813 134,938 139,054 136,502
Average realized prices, prior to risk management contractsCrude oil ($/bbl) 45.45 25.88 49.69 65.11 64.79 70.26 63.72 43.30Condensate ($/bbl) 48.49 31.54 57.52 68.08 65.70 71.38 64.81 57.25Natural gas ($/Mcf) 2.16 1.92 2.05 2.36 1.54 1.74 2.79 2.85NGLs ($/bbl) 14.85 10.84 6.36 11.69 5.25 7.71 25.43 29.12Oil equivalent ($/boe) 19.55 14.38 19.52 23.93 20.46 23.04 26.20 24.09
TRADING STATISTICS (3)
($, based on intra-day trading)High 6.94 6.12 8.39 8.26 7.85 9.61 10.49 14.84Low 4.54 3.64 2.42 5.40 5.37 6.37 7.82 7.38Close 5.95 4.56 4.05 8.18 6.31 6.41 9.12 8.10Average daily volume (thousands) 1,363 2,177 3,207 2,583 1,838 2,255 2,291 2,117
CORPORATE ANDSHAREHOLDER INFORMATIONDIRECTORSHarold N. KvisleBoard Chair
Farhad Ahrabi (1)(2)
David R. Collyer (2)(3)(4)
John P. Dielwart (1)(2)
Michael G. McAllister (1)(2)
Kathleen O’Neill (4)(5)
Herbert C. Pinder Jr. (3)(4)
William G. Sembo (3)(5)
Nancy L. Smith (1)(5)
Terry M. Anderson(1) Member of Risk Committee(2) Member of Safety, Reserves and Operational Excellence Committee(3) Member of Human Resources and Compensation Committee(4) Member of Policy and Board Governance Committee(5) Member of Audit Committee
OFFICERSTerry M. AndersonPresident and Chief Executive Officer
Kris J. BibbySenior Vice President and Chief Financial Officer
Chris D. BaldwinVice President, Geosciences
Ryan V. BerrettVice President, Marketing
Sean R. A. CalderVice President, Production
Lara M. ConradVice President, Development and Planning
Armin JahangiriVice President, Operations
Lisa A. OlsenVice President, Human Resources
Grant A. ZawalskyCorporate Secretary
EXECUTIVE OFFICEARC Resources Ltd.1200, 308 – 4th Avenue SWCalgary, Alberta T2P 0H7T 403.503.8600TOLL FREE 1.888.272.4900F 403.509.6427W 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 CALENDARFebruary 11, 2021Year-end 2020 Results
May 5, 2021Q1 2021 Results
May 6, 2021Annual Meeting of Shareholders
STOCK EXCHANGE LISTINGThe Toronto Stock ExchangeTrading Symbol: ARX
INVESTOR INFORMATIONVisit ARC’s website:W www.arcresources.comor contact Investor Relations:T 403.503.8600TOLL 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.