ARC Resources Ltd. Investor Presentation - August 2021
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ARC Resources Ltd. Investor Presentation August 2021
ARC Is the Largest Pure-play Montney Producer
Shares outstanding 725 million
Market capitalization1 $6.9 billion
Net debt2 $2.1 billion
Enterprise value1 2 $9.0 billion
Quarterly dividend3 $0.066/share
Dividend yield4 2.8%
Montney production5
Mboe/day
~340
2%
22%
~340
15%
61%
(1) Market Capitalization as at July 29, 2021. Crude oil Condensate
ARC
Peer
Peer
Peer
Peer
Peer
Peer
(2) Net Debt excluding Lease Obligations as at June 30, 2021. Refer to the Advisory Statements to this presentation.
1
2
3
4
5
6
(3) ARC’s board of directors has approved a 10% increase to ARC’s quarterly dividend, from $0.06/share to $0.066/share. The dividend increase is effective for ARC’s
third quarter 2021 dividend, payable on October 15, 2021 to shareholders of record on September 30, 2021. NGLs Natural gas
(4) Dividend yield as at July 29, 2021.
(5) Source: Company reports, estimated operated Montney volumes used in the absence of public disclosure.
ARC is the premium investment opportunity for exposure to the Montney 2
ARC’s Guiding Principles
Sustainable business Risk management
around all aspects of the Superior capital discipline
model with best-in-class business, including focused on maximizing free
people and assets, along with maintaining a strong funds flow1 to optimize
a relentless focus on financial position through shareholder returns
long-term profitability commodity price cycles
Owned-and-operated
Operational excellence
infrastructure to support and top-tier ESG performance
operational control, low cost through efficient and
structure, and optimized disciplined execution
revenue streams
(1) Free Funds Flow is a 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 the Advisory Statements to this presentation.
ARC’s guiding principles are enduring 3
ARC Is a Premier Business
Strong balance sheet
Investment-grade credit rating; net debt1 is forecasted to be less than 1.0 time annualized funds from operations by Q3 20212
Substantial free funds flow3
Free funds flow3 is forecasted to be ~$1.0 billion in 20212
Recently increased dividend by 10%
Dividend is sustainable at less than US$40/bbl WTI and Cdn$1.90/GJ AECO
Profitable development runway
Decades’ worth of high-quality inventory maps to a 5% growth rate over the long term
Global leader in ESG
Lowest GHG emissions intensity in the sector in Canada; member of the 30% Club
(1) Net Debt excluding Lease Obligations. Refer to the Advisory Statements to this presentation.
(2) Based on forward price curve as at July 29, 2021.
(3) Free Funds Flow is a 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 the Advisory Statements to this presentation.
3
ARC delivers financial strength, free funds flow , returns to shareholders, profitable growth, and ESG excellence 4
2021 Outlook
2021 Plan – Executing on ARC’s Disciplined Strategy
Fully integrate Seven Generations
Integrate people, assets, and processes while focusing on realizing immediate cost savings and synergies
De-risk the business through debt reduction
Maintain investment-grade credit rating and reduce net debt1 to ~1.0 annualized funds from operations
Increase return of capital
Sustainably increase dividend by 10% and evaluate instituting normal course issuer bid
Sanction and commence development of Attachie West Phase I
Subject to Board approval, execute leading development opportunity in the most efficient and profitable manner possible
(1) Net Debt excluding Lease Obligations. Refer to the Advisory Statements to this presentation.
(2) Free Funds Flow is a 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 the Advisory Statements to this presentation.
2
ARC’s 2021 plan increases total shareholder value and delivers on free funds flow priorities 6
1
Delivering on Free Funds Flow Priorities
US$55/bbl WTI
Free funds flow1:
Cdn$2.50/GJ AECO
• Current dividend
• Sustainable dividend
US$45/bbl WTI increases
Cdn$2.25/GJ AECO • Attachie West Phase I
• Share repurchases
• Strategic M&A
US$40/bbl WTI
Maintenance capital:
Cdn$1.90/GJ AECO
~$1.1 billion annually to
sustain production at
~340,000 boe/day
Funds from Maintenance Capital Current Dividend Attachie West Phase I Incremental Returns Excess Free Funds
1
Operations Capital to Shareholders Flow
Flow
(1) Free Funds Flow is a 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 the Advisory Statements to this presentation.
ARC’s maintenance capital and current dividend break-even is less than US$40/bbl WTI and Cdn$1.90/GJ AECO 7
Q2 2021 in Review
Dividend increase Free funds flow1 Net debt2
$249.7 million or $2.1 billion or
10% increase
$0.35/share 1.3 times FFO
Quarterly dividend
increased to $0.066/share Allocated to net debt2 Reduced by $270.8 million
effective for ARC’s Q3 reduction and dividend or 11%
2021 dividend
(1) Free Funds Flow is a 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 the Advisory Statements to this presentation.
(2) Net Debt excluding Lease Obligations. Refer to the Advisory Statements to this presentation.
Second quarter 2021 results demonstrated strong free funds flow1 generation 8
$160 Million in Annual Synergies from 7G Acquisition
Synergies expected for 2022
$160 million
180
Synergies
$25 million
150
$25 million
$15 million
120
1
$50 million
90
60
$45 million
Synergies Captured
30
0
Corporate Costs Finance Costs Operating Efficiencies Market Optimization Drilling & Completions Efficiencies Annual Synergies
(1) Finance costs are expected to be approximately $50 million lower for the combined entity than they would have been if the Seven Generations senior notes remained outstanding.
ARC estimates that over half of identified synergies have been captured to-date 9
De-risking the Business through Debt Reduction
Long-term notes repayment schedule1 2021 forecasted net debt2 sensitivities
Cdn$ millions $ billions, ratio
600 2,000 2.0
450 3.72% US$ Note
1,500 1.5
8.21% US$ Note
5.36% US$ Note
300 3.31% US$ Note
1,000 1.0
3.81% US$ Note
150 4.49% Cdn$ Note
2.354% Cdn$ Note 500 0.5
3.465% Cdn$ Note
0
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
0 0.0
US$40/bbl WTI & US$50/bbl WTI & US$60/bbl WTI & US$70/bbl WTI &
US$2.30/MMBtu US$2.60/MMBtu US$2.90/MMBtu US$3.20/MMBtu
ARC has ample liquidity NYMEX Henry NYMEX Henry NYMEX Henry NYMEX Henry
+ $2.0 billion unsecured extendible revolving credit facility Hub Hub Hub Hub
+ $1.9 billion of available liquidity Net Debt (LHS) Net Debt to Funds from Operations (RHS)
(1) Assumes Cdn$/US$ exchange rate of 1.2405 as at June 30, 2021.
(2) Net Debt excluding Lease Obligations. Refer to the Advisory Statements to this presentation.
Investment-grade credit rating allows for access to low-cost debt 10Evaluating Strategic M&A Opportunities
Assets must be as good or better than ARC’s existing assets
Infrastructure must be largely owned and operated
Assets must have similar ESG characteristics and performance
Assets must be able to increase free funds flow1 per share at various commodity scenarios
Opportunity can create scale and/or unique synergies
(1) Free Funds Flow is a 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 the Advisory Statements to this presentation.
ARC has no holes in its portfolio but will continue to evaluate strategic M&A opportunities with the Company’s screening criteria 11Industry-leading Financial Performance amongst Peers
Comparative cash returns1 2 2022E return on average capital employed3 4
24% Canadian E&Ps 20% Canadian E&Ps
US E&Ps US E&Ps
18% 15%
12% 10%
6% 5%
0% 0%
ARC ARC
Average Free Cash Flow Yield (2021E to 2022E)
Dividend Yield (Current)
(1) Source: Barclays Capital Markets; FactSet (April 2021). Peer group includes North American E&Ps: APA, AR, CLR, CNQ, CNX, COG, COP, CVE, DVN, EOG, EQT, FANG, MRO, OVV, PXD, RRC, SWN, TOU, XEC.
(2) Free Cash Flow Yield is calculated as funds from operations less capital expenditures and dividends.
(3) Source: Peters & Co. “E&P Overview Tables” (July 26, 2021). Peer group includes North American E&Ps: APA, AR, CNQ, COG, DVN, EOG, FANG, OVV, PXD, TOU.
(4) Return on Average Capital Employed is calculated as unhedged cash flow less Peters & Co.’s estimate of required capital spending to maintain flat production volumes year-over-year, expressed as a percentage of capital employed. Capital employed is defined as average shareholders’ equity excluding impairment plus net debt.
ARC is expected to deliver one of the highest cash return and return on average capital employed amongst its Canadian peers 12Guidance – Production
Q3 2021 to Q4 2021 2021 2021 Revised
Guidance1 2 Guidance1 2 Guidance1 2
Production
Crude oil (bbl/day) 8,000 - 9,000 12,000 - 13,500 9,000 - 10,500
Condensate (bbl/day) 72,000 - 78,000 55,000 - 60,000 55,000 - 60,000
Crude oil and condensate (bbl/day) 80,000 - 87,000 67,000 - 73,500 64,000 - 70,500
Natural gas (MMcf/day) 1,230 - 1,265 1,100 - 1,140 1,100 - 1,140
NGLs (bbl/day) 50,000 - 53,000 40,000 - 42,000 40,000 - 42,000
Total production (boe/day) 335,000 - 350,000 290,000 - 305,000 287,000 - 302,000
• ARC disposed of its Pembina assets in Q2 2021, and as such, adjusted its guidance for crude oil and total
production; guidance for condensate, natural gas, and NGLs production remains unchanged
• Q3 2021 to Q4 2021 production guidance is unchanged at ~340,000 boe/day
(1) ARC acquired Seven Generations Energy Ltd. on April 6, 2021, and as such, 2021 guidance includes ARC’s financial and operational results for the three months ended March 31, 2021, plus the Company’s expectations for the combined financial and operational results of ARC’s and Seven Generations Energy Ltd.’s operations for the
remainder of 2021.
(2) 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.
13Guidance – Expenses and Capital Expenditures
2021 2021 Revised
Guidance1 2 Guidance1 2
Expenses ($/boe)
Operating 4.10 - 4.60 3.90 - 4.40
Transportation 4.50 - 5.00 4.50 - 5.00
G&A expense before share-based compensation expense3 0.90 - 1.00 0.90 - 1.00
4
G&A - share-based compensation expense 0.30 - 0.45 0.30 - 0.45
Transaction costs 0.20 - 0.30 0.20 - 0.30
Interest and financing 0.70 - 0.80 0.70 - 0.80
Current income tax expense as a per cent of funds from operations 1-5 1-5
Capital expenditures before land and net property acquisitions
(dispositions) ($ millions) 950 - 1,000 950 - 1,000
• ARC disposed of its Pembina assets in Q2 2021, and as such, lowered its guidance for operating expenses
(1) ARC acquired Seven Generations Energy Ltd. on April 6, 2021, and as such, 2021 guidance includes ARC’s financial and operational results for the three months ended March 31, 2021, plus the Company’s expectations for the combined financial and operational results of ARC’s and Seven Generations Energy Ltd.’s operations for the
remainder of 2021.
(2) 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.
(3) Excludes transaction costs associated with the acquisition of Seven Generations Energy Ltd.
(4) Comprises expense recognized under all share-based compensation plans, with the exception of the Deferred Share Unit Plans.
14Guidance – Capital Program of $950 Million to $1.0 Billion
Attachie
~$5MM
~3,500 boe/day
Complete detailed engineering
work for Attachie West Phase I Ante Creek
~$60MM ● 16 wells
~17,000 boe/day
Deliver profitable light oil
Greater Dawson production by leveraging
2020 facility expansion
~$240MM ● 44 wells
~95,000 boe/day
Sustain production and complete
small-scale facility sour conversion and Kakwa1
optimization project at Parkland/Tower Kakwa
~$525MM ● 55 wells
~180,000 boe/day
Integrate asset and focus
Sunrise on maximizing free funds
flow2 generation
~$80MM ● 9 wells
~44,000 boe/day
Expand existing facility by 40 MMcf/day
and maximize throughput to capitalize on
anticipated strength in natural gas pricing
Note: Well counts denote wells drilled in calendar year; number of wells with completions activities in calendar year may vary.
(1) Assets acquired through the Business Combination with Seven Generations Energy Ltd., which closed on April 6, 2021.
(2) Free Funds Flow is a 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 the Advisory Statements to this presentation.
2
Focused on asset integration, sustaining production, and maximizing free funds flow generation 15Asset Overview
Greater Dawson Overview
Snapshot
Overview Low break-evens2
Production1 Dawson & Parkland
91 Mboe/day (22% liquids) $0.26/Mcf to $0.39/Mcf
Land position
Tower 149,800 net acres (97% W.I.)
Phase I & II
Gas Plants
Phase III & IV
Parkland Gas Plants
Large resource Significant optionality
Phase I & II
Dawson Gas Plants
Drilling inventory3 4 Integrated infrastructure allows
>1,200 locations ARC to prioritize wells based on
Pembina & Enbridge `` Years to sustain return on investment and
TCPL ~20 years prevailing commodity prices
Parkland-Dawson Interconnect Pipeline
(1) Represents results for the three months ended June 30, 2021.
(2) Break-even prices are at Cdn$/Mcf AECO. Break-even analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero.
(3) Comprises approximately 20 per cent of 2P booked undeveloped locations and approximately 80 per cent of internal inventory estimates.
(4) Subject to change based on technology and economic environment.
(5) Free Funds Flow is a 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 the Advisory Statements to this presentation.
5
Low reinvestment rates and strong lower Montney liquids performance driving significant free funds flow generation 17Sunrise Overview
Snapshot
Overview Low cost structure
Production1 Operating expense
~280 MMcf/day ~$0.20/Mcf
Optimally positioned for Finding and development cost
LNG supply ~$0.35/Mcf
Phase I & II
Gas Plants
Efficient resource Environmental
performance
Land position Electrified facility and field drive
23,100 net acres (93% W.I.) ultra-low emissions profile
Drilling inventory2 3 Up to five layers of development
400 locations significantly reduces footprint
Coastal GasLink
(1) Sunrise facilities expansion of 40 MMcf/day was brought on-stream in May 2021.
(2) Comprises approximately 25 per cent of 2P booked undeveloped locations and approximately 75 per cent of internal inventory estimates.
(3) Subject to change based on technology and economic environment.
Lowest-cost dry natural gas play in North America 18Kakwa Overview
Snapshot
Gold Creek
Gas Plant
Overview Near-term objective
Production1 Integrate asset into portfolio and
Cutbank
Gas Plant
173 Mboe/day (58% liquids) focus on realizing immediate
Land position operations, drilling, and
493,100 net acres (99% W.I.) completions synergies
Karr
Facility
Capital efficiency Right-size
Pembina
Kakwa River
Lator
Gas Plant
and decline rate transportation
contracts
Focus on improving capital Align transportation levels with
efficiencies and reducing decline physical transportation needs to
rate of 40% by ~2% per year increase free funds flow2
NGTL
Alliance
Pembina
(1) Represents results for the three months ended June 30, 2021.
(2) Free Funds Flow is a 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 the Advisory Statements to this presentation.
2
Premium condensate-rich and high-deliverability natural gas play that generates significant free funds flow 19Ante Creek Overview
Snapshot
Overview Stable cash flows
2-26 Production1 Balanced commodity mix and
Gas Plant 17 Mboe/day (50% liquids) moderate decline rates
Land position Break-even2
122,000 net acres (100% W.I.) US$20/bbl
10-7
Gas Plant
Efficiency Optimizing
10-36
Gas Plant
evolution infrastructure
Well and pad design Leveraging 2020 facility
improvements are delivering expansion to efficiently grow free
strong capital efficiencies and funds flow3 profile
enhanced profitability
(1) Represents results for the three months ended June 30, 2021.
(2) Break-even prices are at US$/bbl WTI. Break-even analysis is run on a single commodity and is defined as the price at which NPV10 is equal to zero.
(3) Free Funds Flow is a 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 the Advisory Statements to this presentation.
3
Highly profitable, stable light oil development generating significant free funds flow 20Attachie Overview
Snapshot
Overview Significant resource
Pilot production1 Resource in place2
4.4 Mboe/day (54% liquids) 8.9 Bbbl of liquids
32 Tcf of gas
Phase I
4-20
Gas Plant
Development Delineation
Battery potential complete
Land position Piloting activities have set the
202,000 net acres (99% W.I.) stage for efficient execution of
Drilling inventory3 4 large-scale development
Pembina >1,500 locations
North Montney Mainline
(1) Represents results for the three months ended June 30, 2021. ARC has been conducting piloting activities in Attachie West in advance of the planned sanctioning of Attachie West Phase I.
(2) Total Petroleum Initially-in-Place as of December 31, 2018.
(3) Comprises approximately two per cent of 2P booked undeveloped locations and approximately 98 per cent of internal inventory estimates.
(4) Subject to change based on technology and economic environment.
Attachie is the premier development opportunity within ARC’s portfolio 21Attachie West Phase I Design
Total Condensate and Natural Gas Forecasted Capital
Processing NGLs Processing Processing Investment
Capacity Capacity Capacity (2022 to 2023)
40 Mboe/day 25 Mbbl/day 90 MMcf/day ~$600 million
Targeted Sanction Date: Q4 2021
Targeted On-stream Date: Q3 2023
Subject to Board approval, ARC is ready to sanction Attachie West Phase I once its debt reduction targets are met 22Attachie West Phase I Forecasted Cash Flow Profile
$500,000,000 45, 000
40, 000
$400,000,000 35, 000
30, 000
$300,000,000 25, 000
20, 000
$200,000,000 15, 000
10, 000
$100,000,000 5,0 00
0
$0 -5,000
2021F
2022F
2023F
2024F
2025F
2026F
2027F
2028F
2029F
2030F
-10,000
($100,000,000) -15,000
Netback1 2
-20,000
($200,000,000)
Capital Expenditures -25,000
Free Funds Flow1 3 -30,000
($300,000,000) Production -35,000
(1) Economics run at US$55/bbl WTI and US$2.75/MMBtu NYMEX Henry Hub flat pricing.
(2) Netback is a 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 the Advisory Statements to this presentation.
(3) Free Funds Flow is a 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 the Advisory Statements to this presentation.
2
Once on-stream, Attachie West Phase I is expected to generate free funds flow of $250 million annually 23Network of Owned-and-operated Infrastructure
Combined network of owned-and-operated infrastructure
+ Natural gas processing and sales capacity of 1.5 Bcf/day
+ Ability to optimize larger portfolio, which has access to
downstream markets across North America
Benefits of owned-and-operated infrastructure
+ Lowers cost structure and increases funds from
operations
+ Provides ability to manage production based upon
prevailing commodity prices to optimize revenues
+ Retains economics of facility optimization projects
Owned-and-operated infrastructure affords greater optionality and control over cost structure 24ARC’s ESG Excellence
Global oil and gas companies’ relative ESG rankings1 2
64
ARC
Social and Governance Score
58
Africa
Asia
Canada
52 Europe
Latin America
Middle East
Russia
46
United States
40
38 46 54 62 70
Environmental Score
(1) Source: BMO Capital Markets; CSRHub; Bloomberg (January 2021).
(2) ARC scores represented are prior to the acquisition of Seven Generations Energy Ltd., which closed on April 6, 2021.
ARC scores amongst the best in the world for environmental, social, and governance performance 25Strong Performance across Key ESG Factors
Environmental Social Governance
1 1
Emissions performance Safety Executive compensation
+ Lowest GHG emissions intensity + #1 corporate priority + 95% shareholder approval of ARC’s
amongst Canadian upstream E&P + Absolute focus on workplace safety for 2021 “say on pay” advisory vote
companies employees and contractors + Majority of executive pay “at risk” and
+ “A-” score by CDP for Climate Change tied to medium- and long-term share
disclosure and performance price and ESG performance
1
Water usage Diversity and inclusion Board of Directors
+ Responsibly manage water usage in + 30% Club and Bloomberg Gender- + 9 of 11 directors are independent
operations Equality Index member + >98% average shareholder approval
+ 90% of water used on ARC’s legacy + 25% of executive team and 36% of rating in 2021
assets is recycled directors are female
+ “B” score by CDP for Water Security
Jantzi Social Index constituent
Minimizing the environmental Stakeholder benefits across all Governance principles aligned to
impact of resource development aspects of the business shareholder values
(1) Results represented are prior to the acquisition of Seven Generations Energy Ltd., which closed on April 6, 2021.
ARC’s ESG commitment leads to joint stakeholder and shareholder benefits 26ARC’s Resource and Scalability Potential
Drilling locations by area1 2 Resource potential
2,000
1,500
1,000
500
0
Attachie Greater Kakwa Sundown Ante Sunrise Septimus 2020
Dawson Creek Base Production Future Development Projects
(1) Comprises 2P booked undeveloped locations and internal inventory estimates.
(2) Subject to change based on technology and economic environment.
ARC has decades’ worth of premium drilling locations with commodity and geographic optionality 27Additional Information
Natural Gas Financial and Physical Price Management
WCSB demand and export capacity growth1 Natural gas realizations2 and diversification3 4
5.00 $4.39
4.00
$1.41 $3.16
5.4 Bcf/day Demand & Export Capacity $2.82
Cdn$/Mcf
3.00 Realized Gain (Loss) on
Growth Expected by 2025 $2.03 $2.18 Risk Management Contracts
2.00 $0.02 Diversification Activities
$0.11 $3.37
$2.94 $3.19 Average Price before
1.00 $2.07 $2.26 Diversification Activities
LNG Canada Phase 1 ($0.06) ($0.03)
0.00 ($0.15) ($0.10)
+2.1 Bcf/day by 2025 ($0.06) ($0.21) ($0.18)
(1.00)
Intra-Alberta Demand Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021
+1.5 Bcf/day by 2025
100%
Enbridge T-South Capacity 8% 9% 9% 9%
+0.2 Bcf/day by 2021 7%
NGTL East Gate Capacity 9% 9% 12%
6% Dawn Floating
+1.3 Bcf/day by 2022 75% 14%
15%
% of Total Production
30% Malin Floating
24%
NGTL West Gate Capacity 15%
16%
Henry Hub Floating
+0.3 Bcf/day by 2023 50% 14% Midwest US Floating
21% WCSB Floating
38%
41% Hedged
25%
41%
31%
15%
7%
0%
Bal 2021 2022 2023 2024
(1) Source: ARC Risk Research, TC Energy, Enbridge Inc., company reports.
(2) Realized gain (loss) on risk management contracts is not included in ARC’s realized natural gas price.
(3) Diversification based on internal volume and marketing assumptions, adjusted for ARC’s heat content.
(4) “Hedged” includes all physical and financial fixed price swaps, collars, and 3-ways.
Well-diversified North American natural gas exposure increases optionality 29Canadian Condensate Market
Crude oil and condensate pricing1 WCSB condensate supply and demand2 3
US$/bbl Mbbl/day
80 800
60 600
40 400
20 200
0 0
2017 2018 2019 2020 2021 2017 2018 2019 2020 2021F 2022F 2023F 2024F
WTI Condensate WCS WCSB Condensate Supply Imports Required WCSB Condensate Demand
• Heavy reliance on imported volumes from the US results in • WCSB condensate demand is expected to stay well in excess of
Canadian condensate trading within a very tight range to WTI local supply for the foreseeable future
(1) Source: Bloomberg.
(2) Source: ARC Risk Research, Alberta Energy Regulator, BC Oil and Gas Commission, Crude Oil Logistics Committee.
(3) Forecast includes the impact of GEI/USD Diluent Recovery Unit assuming 2021 on-stream date.
Continued reliance on imported condensate volumes is constructive for Canadian condensate pricing 30Cash Flow Protection
Crude oil and condensate production hedged1 Natural gas production hedged1
Mbbl/day, % MMBtu/day, %
48 60% 720,000 60%
36 45% 540,000 45%
24 30% 360,000 30%
12 15% 180,000 15%
0 0% 0 0%
Q3 2021 Q4 2021 2022 Q3 2021 Q4 2021 2022
Production Hedged % Hedged Production Hedged % Hedged
(1) Positions as at June 30, 2021.
Well-hedged with a long-term focus on reducing downside risk in funds from operations and creating certainty in cash flows 3112
Risk Management Contracts Positions at June 30, 2021
Q3 2021 to Q4 2021 2022 2023 2024 2025
Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day
Ceiling 53.66 23,500 58.91 21,767 62.35 12,000 55.82 1,243 - -
Floor 45.82 23,500 48.45 21,767 51.25 12,000 50.00 1,243 - -
Sold Floor 40.84 8,000 40.11 11,767 45.00 5,000 - - - -
Swap 48.30 19,750 46.90 10,479 48.99 863 - - - -
Total Crude Oil Volumes (bbl/day) 43,250 32,246 12,863 1,243 -
Natural Gas – NYMEX Henry Hub3 US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day
Ceiling 3.13 210,054 3.13 119,932 3.02 60,000 2.74 10,000 - -
Floor 2.60 210,054 2.60 119,932 2.55 60,000 2.50 10,000 - -
Sold Floor 2.13 140,000 2.19 85,000 2.17 30,000 2.10 10,000 - -
Swap 2.57 205,000 2.53 144,959 2.53 52,068 - - - -
Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day
Ceiling 2.41 120,000 2.52 160,000 2.42 95,863 2.40 90,000 2.73 20,000
Floor 1.95 120,000 1.99 160,000 1.88 95,863 1.87 90,000 2.00 20,000
Sold Floor - - 1.75 20,000 - - - - - -
Swap 2.29 80,054 2.23 20,000 2.06 10,000 2.06 10,000 - -
Sold Call 4.50 3,315 4.50 2,466 - - - - - -
Sold Swaption - - 2.00 20,000 - - - - - -
Total Natural Gas Volumes (MMBtu/day) 604,669 435,497 212,407 104,782 18,956
Natural Gas – AECO Basis
(Differential to NYMEX Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day
Sold Swap (0.94) 68,342 (0.88) 35,000 (0.91) 70,000 (0.91) 70,000 (0.65) 50,000
Total AECO Basis Volumes (MMBtu/day) 68,342 35,000 70,000 70,000 50,000
Natural Gas – Other Basis
(Differential to NYMEX Henry Hub) MMBtu/day MMBtu/day MMBtu/day MMBtu/day MMBtu/day
Sold Swap 155,000 152,438 89,918 4,973 -
Notional Rate Notional Rate Notional Rate Notional Rate Notional Rate
Foreign Exchange (US$ millions) (Cdn$/US$) (US$ millions) (Cdn$/US$) (US$ millions) (Cdn$/US$) (US$ millions) (Cdn$/US$) (US$ millions) (Cdn$/US$)
US$ Forward Sale
Swap 128.6 1.3351 116.1 1.3165 - - - - - -
Ceiling 30.8 1.3093 69.9 1.3078 48.0 1.3070 - - - -
Floor 30.8 1.3441 69.9 1.3562 48.0 1.3602 - - - -
US$ Forward Purchase
Ceiling4 10.0 1.2549 - - - - - - - -
Floor4 10.0 1.3000 - - - - - - - -
(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) ARC has also entered into crude oil differential swaps with a fair value deficiency of $(3.0) million and NGLs location differential swaps with a fair value deficiency of $(0.1) million.
(3) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement.
(4) Variable rate collar expiring August 23, 2021, whereby if the Cdn$/US$ spot rate is below $1.2825 at expiry, the ceiling will re-adjust to $1.3000.
32Asset Details
Greater Dawson Sunrise Kakwa Ante Creek Attachie
Net production – Q2 2021
Crude oil & liquids (bbl/day) 19,972 43 99,952 8,461 2,380
Natural gas (MMcf/day) 427.5 259.2 437.6 53.2 12.2
Total (boe/day) 91,219 43,242 172,890 17,331 4,418
1
Land
Net sections 231 36 771 191 308
Net acres 149,800 23,100 493,100 122,000 202,000
Working interest ~97% ~93% ~99% ~100% ~99%
PDP Reserves (MMboe) 139 66 259 22 7
Liquids (MMbbl) 26.5 - 141.2 11.1 3.3
Gas (Bcf) 679 394 708 67 20
(1) Denote Montney sections and acreage only.
Commodity and geographic diversity across asset portfolio provides optionality 33Historical Performance
Production Net debt1 to FFO Dividends2
Mboe/day $ billions, ratio $ billions, % of FFO
350 2.5 2.5 8 120%
280 2.0 2.0
6 90%
210 1.5 1.5
4 60%
140 1.0 1.0
2 30%
70 0.5 0.5
0 0.0 0.0 0 0%
2021 YTD
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2021 YTD
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Montney Natural Gas (boe/day)
Non-Montney Natural Gas (boe/day) Net Debt (LHS)
Montney Crude Oil & Liquids (bbl/day) Annualized Funds from Operations (LHS) Cumulative Dividend (LHS)
Non-Montney Crude Oil & Liquids (bbl/day) Net Debt to Annualized Funds from Operations (RHS) Dividends as a % of Funds from Operations (RHS)
(1) Net Debt presented for 2021 onwards excludes lease obligations. Refer to the “Capital Management” note in ARC’s financial statements.
(2) Dividends as a per cent of funds from operations calculated as dividends before Dividend Reinvestment Plan and Stock Dividend Program.
ARC has managed a profitable business through all commodity price cycles 34
with its efficient Montney assets, capital discipline, and strong balance sheet12
ESG Recognitions and Rankings
Member of MSCI Global Sustainability Index Member of Sustainalytics’ Jantzi Social Index
MSCI ESG Rating: AAA
Voluntary participant since 2007
2020 Climate Change Score: A- Member of FTSE Russell’s FTSE4Good Index Series since 2018
2020 Water Security Score: B
Environment Score: 4
Social Score: 3 Member of the 30% Club since 2018
Governance Score: 7
Score: 31 – High (60th Percentile) Member of Bloomberg’s Gender-Equality Index since 2021
(1) ARC recognitions and rankings represented are prior to the acquisition of Seven Generations Energy Ltd., which closed on April 6, 2021.
(2) ESG recognitions and rankings as of April 30, 2021.
View ARC’s 2020 ESG Report at www.arcresources.com/responsibility 35Advisory Statements
Advisory Statements
Notes Regarding Forward-looking Information
This presentation contains certain forward-looking statements and forward-looking information (collectively referred to as "forward-looking information") within the meaning of applicable securities legislation about current
expectations about the future, based on certain assumptions made by ARC. Although ARC believes that the expectations represented by such forward-looking information are reasonable, there can be no assurance that such
expectations will prove to be correct. Forward-looking information in this presentation is identified by words such as "anticipate", "believe", "ongoing", "may", "expect", "estimate", "plan", "will", "project", "continue", "target",
"strategy", "upholding", or similar expressions and includes suggestions of future outcomes. In particular, but without limiting the foregoing, this presentation contains forward-looking information with respect to: estimated
production amounts and quantities thereof; the expectations with respect to the integration of Seven Generations; the anticipated annual synergies for 2022 and the sources thereof; expected capital expenditures for 2021; the
continued integration of Seven Generations' ESG initiatives; plans to publish ARC's 2020 ESG performance data and highlights in the third quarter of 2021; the anticipated reduction in net debt excluding lease obligations; the
continued assessment of dividends and the payment thereof; plans to maintain capital discipline to maximize profitability and preserve a strong financial position and plans to uphold a strong safety culture and advance its ESG
leadership and performance; plans to sustain production at Greater Dawson, Sunrise, Kakwa, and Ante Creek; the Company's guidance estimates; the continued allocation of capital where risk-adjusted return are greatest; plans
to evaluate return of capital measures with excess free funds flow; and other statements.
Readers are cautioned not to place undue reliance on forward-looking information as ARC's actual results may differ materially from those expressed or implied. ARC undertakes no obligation to update or revise any forward-
looking information except as required by law. Developing forward-looking information involves reliance on a number of assumptions and consideration of certain risks and uncertainties, some of which are specific to ARC and
others that apply to the industry generally. Material factors or assumptions on which the forward-looking information in this presentation include: ARC's ability to successfully integrate the business of Seven Generations Energy
Ltd.; access to sufficient capital to pursue any development plans; ARC's ability to issue securities; the impacts the acquisition of Seven Generations Energy Ltd. may have on the current credit ratings of ARC; forecast
commodity prices and other pricing assumptions; forecast production volumes based on business and market conditions; the accuracy of outlooks and projections contained herein; projected capital investment levels, the
flexibility of capital spending plans, and associated sources of funding; achievement of further cost reductions and sustainability thereof; applicable royalty regimes, including expected royalty rates; future improvements in
availability of product transportation capacity; opportunity for ARC to pay dividends and the approval and declaration of such dividends by the board of directors of ARC; cash flows, cash balances on hand, and access to ARC's
credit facility being sufficient to fund capital investments; foreign exchange rates; near-term pricing and continued volatility of the market; the ability of ARC's existing pipeline commitments and financial hedge transactions to
partially mitigate a portion of ARC's risks against wider price differentials; estimates of quantities of crude oil, natural gas, and liquids from properties and other sources not currently classified as proved; accounting estimates and
judgments; future use and development of technology and associated expected future results; ARC's ability to obtain necessary regulatory approvals; the successful and timely implementation of capital projects or stages thereof;
the ability to generate sufficient cash flow to meet current and future obligations; estimated abandonment and reclamation costs, including associated levies and regulations applicable thereto; ARC's ability to obtain and retain
qualified staff and equipment in a timely and cost-efficient manner; ARC's ability to carry out transactions on the desired terms and within the expected timelines; forecast inflation and other assumptions inherent in the guidance
of ARC; the retention of key assets; the continuance of existing tax, royalty, and regulatory regimes; the accuracy of the estimates of each of ARC's and Seven Generations Energy Ltd.’s reserve volumes; ARC's ability to access
and implement all technology necessary to efficiently and effectively operate its assets; the ongoing impact of COVID-19 on commodity prices and the global economy; and other risks and uncertainties described from time to
time in the filings made by ARC with securities regulatory authorities.
The forward-looking information in this presentation also includes financial outlooks and other related forward-looking information (including production and financial-related metrics) relating to ARC, including: the expectations of
ARC regarding free funds flow, free funds flow yield, net debt excluding lease obligations, production, funds from operations, net debt to funds from operations, netback, dividends, maintenance capital, available liquidity, capital
investments, capital expenditures, returns to shareholders, cash returns, return on average capital employed, expenses and expenditures, and anticipated cost savings. Any financial outlook and forward-looking information
implied by such forward-looking statements are described in ARC's MD&A, and its most recent annual information form, which are available on ARC's website at www.arcresources.com and under ARC's SEDAR profile at
www.sedar.com and are incorporated by reference herein.
37Advisory Statements
Basis of Preparation
All financial figures and information have been prepared in Canadian dollars (which includes references to “dollars” and “$”), except where another currency has been indicated, and in accordance with International Financial
Reporting Standards (“IFRS” or “GAAP”) as issued by the International Accounting Standards Board. Production volumes are presented on a before royalties basis.
Non-GAAP Measures
Certain financial measures in this presentation do not have a standardized meaning as prescribed by IFRS, such as free funds flow, free funds flow yield, return on average capital employed (“ROACE”), and netback, and
therefore are considered non-GAAP measures. See the “Capital Management” note of ARC's unaudited condensed interim consolidated financial statements as at and for the three months ended March 31, 2021 for further
information on other measures contained in this presentation including funds from operations and net debt. These measures may not be comparable to similar measures presented by other issuers. These measures have been
described and presented in order to provide shareholders, potential investors, and analysts with additional measures for analyzing ARC. This additional information should not be considered in isolation or as a substitute for
measures prepared in accordance with IFRS.
Free Funds Flow and Free Funds Flow Yield
Management uses free funds flow as a measure of the efficiency and liquidity of its business, measuring its funds available for capital investment to manage debt levels, pay dividends, and return capital to shareholders. The
Company computes free funds flow as funds from operations generated during the period less capital expenditures before undeveloped land purchases and property acquisitions and dispositions and free funds flow yield by
dividing free funds flow per share by the market price per share. By removing the impact of current period capital expenditures from funds from operations, Management believes this measure provides an indication to investors
and shareholders of the funds the Company has available for future capital allocation decisions.
Netback
ARC calculates netback on a total and per boe basis as commodity sales from production less royalties, operating, and transportation expense. ARC discloses netback both before and after the effect of realized gain or loss on
risk management contracts. Realized gain or loss represent the portion of risk management contracts that have settled in cash during the period and disclosing this impact provides Management and investors with transparent
measures that reflect how ARC’s risk management program can impact its netback. Management believes that netback is a key industry benchmark and a measure of performance for ARC that provides investors with
information that is commonly used by other oil and gas producers. The measurement on a per boe basis assists Management with evaluating operational performance on a comparable basis.
Return on Average Capital Employed
ARC calculates ROACE, expressed as a percentage, as net income (loss) plus interest and total income tax expense (recovery) divided by the average of the opening and closing capital employed for the 12 months preceding
period end. Capital employed is the total of net debt plus shareholders’ equity. ROACE since inception is the annual average net income (loss) plus interest and total income tax expense (recovery) for the years 1996 to 2020
divided by the average of the opening and closing capital employed over the same period. Refer to the “Capital Management” note in ARC’s financial statements for additional discussion on net debt. ARC uses ROACE as a
measure of long-term operational performance, to measure how effectively Management utilizes the capital it has been provided and to demonstrate to shareholders the sustainability of its business model and that capital has
been invested profitably over the long term.
Barrels of Oil Equivalent
Natural gas volumes have been converted to barrels of oil equivalent (“boe”) on the basis of six thousand cubic feet (“Mcf”) to one barrel (“bbl”). Boe may be misleading, particularly if used in isolation. A 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 value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil
compared with natural gas is significantly different from the energy equivalency conversion ratio of 6:1, utilizing a conversion on a 6:1 basis is not an accurate reflection of value.
Throughout this presentation, crude oil refers to tight, light, medium, and heavy crude oil product types as defined by National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”). Natural gas refers
to shale gas and conventional natural gas product types as defined by NI 51-101. ARC’s production of conventional natural gas is considered to be immaterial. ARC’s core producing properties that are considered to be shale
gas include Attachie, Dawson, Parkland (including parts of Tower), and Sunrise, and as such, natural gas, condensate, and natural gas liquids (“NGLs”) are disclosed. ARC’s core producing properties that are considered to be
tight oil include Ante Creek and parts of Tower, and as such, crude oil, natural gas, and NGLs are disclosed. ARC’s core producing property that is considered to be light crude oil is Pembina, and as such, crude oil, natural gas,
and NGLs are disclosed. NGLs for Kakwa refer to natural gas liquids, except for condensate, which is reported separately. Natural gas for Kakwa refers to conventional natural gas and shale gas combined.
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).
38Advisory Statements
Information Regarding Disclosure on Oil and Gas Reserves, Resources, and Other Oil and Gas Metrics
Unless otherwise specified, all reserves estimates disclosed in this presentation are derived from ARC's independent reserve evaluation prepared by GLJ Ltd. (“GLJ”) dated January 29, 2021, evaluating the crude oil, natural
gas, natural gas liquids, and sulphur reserves attributable to ARC's properties as of December 31, 2020 (the “Reserves Report”), and all resources estimates disclosed in this presentation are derived from ARC's independent
evaluation prepared by GLJ of ARC's lands in the Montney region, including Dawson, Parkland/Tower, Sunrise/Sunset, Sundown, Septimus, Attachie, Red Creek, and Mica in northeast British Columbia, and Pouce Coupe and
Ante Creek in Alberta as of December 31, 2018. The reserve and resource estimates contained herein are estimates only and there is no guarantee that the estimated reserves or resources will be recovered. Actual crude oil,
natural gas, and natural gas liquids reserves may be greater than or less than the estimates that are provided herein. ARC's belief that it will establish additional reserves over time with conversion of resources into reserves and
probable undeveloped reserves into proved reserves are forward-looking statements and are based on certain assumptions and is subject to certain risks, as discussed under the heading “Notes Regarding Forward-looking
Information” and in ARC's annual information form for the year ended December 31, 2018, dated March 14, 2019.
This presentation references “Total Petroleum Initially-In-Place” or “TPIIP”. TPIIP, as defined in the COGE Handbook, is that quantity of petroleum that is estimated to exist in naturally occurring accumulations. It includes that
quantity of petroleum that is estimated, as of a given date, to be contained in known accumulations, prior to production, plus those estimated quantities in accumulations yet to be discovered. A portion of the TPIIP is considered
undiscovered and there is no certainty that any portion of such undiscovered resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of such undiscovered
resources. With respect to the portion of the TPIIP that is considered discovered resources, there is no certainty that it will be commercially viable to produce any portion of such discovered resources. A significant portion of the
estimated volumes of TPIIP will never be recovered.
This presentation discloses ARC's expectations of future drilling inventory or locations. While certain of these estimated drilling locations may be consistent with “booked” drilling locations identified in the Reserves Report, as
having associated proved and/or probable reserves, other locations are considered “unbooked” as they have no associated proved and/or probable reserves in the Reserves Report or any associated resources other than
reserves. All drilling locations have been presented on a net basis. Unbooked locations are generated by internal estimates of Management based on prospective acreage and an assumption as to the number of wells that can
be drilled per section based on industry practice and internal review. Unbooked locations do not have attributed reserves or resources. Unbooked locations have been identified by Management as an estimation of the multi-year
drilling activities based on evaluation of applicable geologic, seismic, engineering, historic drilling, production, commodity price assumptions, and reserves information. There is no certainty that all unbooked drilling locations will
be drilled, and if drilled, there is no certainty that such locations will result in additional oil and gas reserves, resources, or production. The drilling locations on which wells are actually drilled will ultimately depend upon the capital
allocation decisions of royalty payors who have working interests in respect of such drilling locations and a number of other factors including, without limitation, availability of capital, regulatory approvals, crude oil and natural gas
prices, costs, actual drilling results, additional reservoir information that is obtained, and other factors. While certain of the unbooked drilling locations have been de-risked by drilling existing wells in relative close proximity to
such unbooked drilling locations, other unbooked drilling locations are farther away from existing wells, where Management has less information about the characteristics of the reservoir and therefore there is more uncertainty
whether wells will be drilled in such locations, and if drilled, there is more uncertainty that such wells will result in additional crude oil and natural gas reserves, resources, or production.
This presentation contains certain oil and gas metrics, including finding and development costs (or “F&D costs”) and reserves life index (or “years to sustain”) which do not have standardized meanings or standard methods of
calculation and therefore such measures may not be comparable to similar measures used by other companies and should not be used to make comparisons. These metrics have been included herein to provide readers with
additional measures to evaluate the Company's performance; however, such measures are not reliable indicators of the future performance of the Company and future performance may not compare to the performance in
previous periods and therefore such metrics should not be unduly relied upon. F&D costs are calculated by dividing the sum of the total capital expenditures for the year, in dollars, by the change in reserves within the applicable
reserves category, in boe. F&D costs, including future development costs (“FDC”), includes all capital expenditures in the year as well as the change in FDC required to bring the reserves, within the specified reserves category,
on production. F&D costs take into account reserves revisions and capital expenditure revisions during the year. The aggregate of the costs incurred in the financial year and changes during that year in estimated FDC may not
reflect total F&D costs related to reserves additions for that year. Management uses F&D costs as a measure of its ability to execute its capital program, the success in doing so, and of ARC's asset quality. Reserves life index or
“years to sustain” are calculated by dividing the reserves (in boe) in the referenced category by the midpoint of the production guidance (in boe) for the following year. Management uses this measure to determine how long the
booked reserves will last at current production rates if no further reserves were added
39Advisory Statements
Advisory – Credit Ratings
Credit ratings are intended to provide investors with an independent measure of credit quality of an issue of securities. Credit ratings are not recommendations to purchase, hold, or sell securities and do not address the market
price or suitability of a specific security for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by the rating agency
in the future if, in its judgment, circumstances so warrant.
Third-party Information
This presentation includes market, industry and economic data which was obtained from various publicly available sources and other sources believed by ARC to be true. Although ARC believes it to be reliable, it has not
independently verified any of the data from third party sources referred to in this presentation or analyzed or verified the underlying reports relied upon or referred to by such sources or ascertained the underlying economic and
other assumptions relied upon by such sources. ARC believes that its market, industry and economic data is accurate and that its estimates and assumptions are reasonable, but there can be no assurance as to the accuracy or
completeness thereof. The accuracy and completeness of the market, industry and economic data used throughout this presentation are not guaranteed and ARC makes no representation as to the accuracy of such information.
40Investor Relations Contacts
Kris Bibby Dale Lewko
Senior Vice President and Chief Financial Officer Manager, Capital Markets
403.503.8675 403.503.8696
KBibby@arcresources.com DLewko@arcresources.com
Martha Wilmot General Investor Relations Enquiries
Senior Investor Relations Advisor 403.503.8600
403.509.7280 1.888.272.4900
MWilmot@arcresources.com IR@arcresources.com
Visit ARC’s website at www.arcresources.com and ARC’s SEDAR profile at www.sedar.com 41You can also read
