Slides
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Photo Caption copy area ARC Resources Ltd. Investor Presentation Q1 2026
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Corporate Profile Premium investment opportunity for Montney exposure, one of the most profitable assets in North America Shares outstanding1 571 million Market capitalization2 $14.0 billion Net debt 3 $2.9 billion Enterprise value $16.9 billion Quarterly dividend $0.21/share Dividend yield2 4 3.4% Production ~410 Mboe/day 1) Common shares outstanding, end of period, as at December 31, 2025. 2) As at January 20, 2026. 3) Capital Management Measure— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 4) Supplementary Financial Measure— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. Sources: Company reports, geoSCOUT, and Peters & Co. Limited estimates (data reflects 2024 actuals) WCP and VRN have been combined. 2 0 50 100 150 200 250 300 350 400 450 ARC 2026E BC & Alberta Montney Producers Liquids (MB/d) Natural Gas (Mboe/d)
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AVERAGE PRODUCTION: ~410 Mboe/d (~2,080 producing wells) AVERAGE PRODUCTION: 110 Mboe/d (~5,700 producing wells) Transformation to the Largest Montney Producer 2014 Swan Hills Redwater Pembina Delburne Ghost Pine Youngstown Jenner South Brooks Jenner Retlaw Grassy Prestville Chinchaga Hotchkiss Hawk Hills NEBC Pouce Valhalla Gull Lake Instow SE SK MB Ante Creek Non Montney Minors Ante Creek Kakwa NEBC 2026E Large concentrated asset base drives efficiency, well positioned for the future >1 million Montney acres >1.1 million Montney acres 3 NEBC Ante Creek Kakwa
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Guiding Principles in Action 30-Year Track Record of Execution 4 • Safety #1 priority • Operational excellence • Long-term focus • 100% working interest • Owned and operated infrastructure • Long-term takeaway to global markets • Low cost and high margin producer • History of strong ROIC and return of capital • Free funds flow per share growth • Strong balance sheet • Sustainable dividend growth Focus on Profitability Risk Managed Value Creation Control Our Own Destiny Culture of Discipline
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Investment Case for ARC Commitment to Shareholder Returns • Clear strategy to grow free funds flow per share • Repurchase shares below intrinsic value • Increase the base dividend annually3 Margin Expansion • Expand margins through LNG agreements and organic growth in condensate rich assets World-class Assets • Canada's largest Montney & condensate producer • Capability to grow >500 Mboe/d and sustain for greater than 10 years Free Funds Flow Per Share1 2 Growth 1) Non-GAAP Financial Ratio— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 2) Based on forward pricing of US$70 WTI; $3.50/GJ AECO. 3) Subject to Board approval. $ per share 5 0.00 1.00 2.00 3.00 4.00 2024 2025 2029E
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2026 Capital Budget
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2026 Guidance – Production & Expenses Production Crude oil and condensate (bbl/day) 105,000 - 115,000 Natural gas (MMcf/day) 1,500 – 1,520 NGLs (bbl/day) 48,000 – 52,000 Total production (boe/day) 405,000 - 420,000 Expenses ($/boe)(1) Operating 5.40 – 5.90 Transportation 5.25 - 5.75 G&A expense before share-based compensation expense 1.00 – 1.10 G&A - share-based compensation expense 0.25 – 0.35 Interest and financing(2) 1.10 - 1.20 Current income tax expense as a per cent of funds from operations(1) 5 - 10 Capital expenditures ($ billions)(1)(3) 1.8 – 1.9 7 1) See "Non-GAAP and Other Financial Measures" in the Annual 2025 MD&A for an explanation of the composition of these supplementary financial measures, which information is incorporated by reference into this presentation. 2) Excludes accretion expense. 3) See "About ARC Resources Ltd." in the 2025 Annual MD&A for historical capital expenditures. 2026 Guidance
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2026 Guidance – Capital Expenditures & Production ~$250MM Attachie ~$100MM ~60,000 boe/day Sunrise ~$70MM ~18,000 boe/day Ante Creek ~$1,100MM ~205,000 boe/day Kakwa ~$200MM ~90,000 boe/day Greater Dawson 1) Capital allocation amongst asset may shift throughout the year and affect asset level production Note: Total capital expenditures includes corporate capital and capitalized G&A. Well counts denote wells completed in calendar year. Total capital expenditures of $1.8 to $1.9billion; ~ 65% allocated to Alberta and ~35% to BC1 8
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Long-term Plan Dawson III & IV, BC
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Long-term Outlook Delivers Significant Value Disciplined plan to grow free funds flow per share1 2 1) Non-GAAP Financial Ratio— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 2) Based on forward pricing of US$70 WTI; $3.50/GJ AECO. 3) Non-GAAP Financial Measure — see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 4) Supplementary Financial Measure— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. Boe/day 10 ~80% Free Funds Flow3 Per Share Growth (~16% CAGR3) ~10% CAGR Production Per Share4 ~20% Return on Average Capital Employed3 300,000 350,000 400,000 450,000 2025 2026 2027 2028 2029 $1,000 $3,000 $5,000 $7,000 $9,000 $0.00 $1.00 $2.00 $3.00 $4.00 2025 2026 2027 2028 2029 Cumulative FFF(2) $MM FFF per share(2) Free Funds Flow per share Cumulative Free Funds Flow Growth Optionality • Attachie • Kakwa • Septimus • Sundown
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Providing reliable and affordable low-cost energy to global demand markets Global Leader in Low-cost Energy Development 11 ~25% Future natural gas production linked to international pricing1 ~50% Natural gas production delivered to the US 1) First LNG contract to receive international pricing expected to begin in 2027.
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Capital Allocation Kakwa, AB
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Track Record of Capital Discipline A disciplined investment framework fundamental to profitable growth Return on Average Capital Employed1 2 1) Non-GAAP Financial Measure — see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 2) 2026E – 2029E based on US$70 WTI; $3.50/GJ AECO. 13 Average 12% -20% -10% 0% 10% 20% 30% 40%
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0 500 1,000 1,500 2,000 2,500 3,000 2025 2026 2027 2028 2029 Free Funds Flow2 WTI US$50/B; AECO C$2.50/GJ WTI US$70/B; AECO C$3.50/GJ WTI US$80/B; AECO C$4.50/GJ Sustaining Outlook Disciplined investment drives free funds flow per share growth Growth optionality is governed by corporate returns and a balance sheet first mentality Boe per day $ millions$ millions 1) Refer to the section entitled "About ARC Resources Ltd." contained within the 2025 Annual MD&A for historical capital expenditures. 2) Non-GAAP Financial Measure — see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 14 ~$11 billion ~$8 billion Cumulative Free Funds Flow (2025 - 2029) Cumulative Free Funds Flow (2025 - 2029) 300,000 350,000 400,000 450,000 2025 2026 2027 2028 2029 Base Production - 500 1,000 1,500 2,000 2025 2026 2027 2028 2029 Capital Expenditures1 2
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Return of Capital Strategy Balancing sustainable dividend growth with share repurchases 1) On April 6, 2021, ARC issued 369.4 million common shares to acquire Seven Generations . Following the business combination, ARC’s outstanding common shares balance was 723.0 million 2) Based on forward pricing of US$70 WTI; $3.50/GJ AECO. 3) Non-GAAP Financial Ratio— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 4) Subject to Board approval. Shares (millions) ~10% Dividend Per Share Growth CAGR22 3 4 ~15% Dividend Payout Ratio3 (% of FFO) Sustainable at Bottom-of-Cycle Commodity Prices Reduce Share Count When Trading Below Intrinsic Value 1 15 ~15% 300 350 400 450 500 550 600 650 700 750 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $1.20 $1.40 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 Dividend per share Outstanding shares Dividend payout ratio
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Asset Portfolio Overview Parkland, BC
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- 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00 4.50 2023 2024 2025 PDP TP 2P Montney Scale & Inventory ARC’s $39 per share before-tax NPV of 2P reserves is based on ~25% of its drilling inventory Consistent reserves per share growth Reserves (boe per share) 17
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>20 years High-quality inventory ~300 metres Thickness ~2.0 Bcf/d ~200 Mbbl/d Owned-and-operated infrastructure Montney Overview ARC’s competitive advantage in a world-class asset 18
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Montney Outcompetes North America Plays 19 Low-cost and deep inventory relative to North American plays 1) Turn-in line (TILs) 2025
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North American Oil Inventory 20 - 2.50 5.00 7.50 10.00 12.50 15.00 17.50 20.00 22.50 25.00 27.50 ARX COP FANG WCP OVV NVA EOG OXY CTRA DVN MTDR PR SM MGY INR CIVI CHRD NOG HPK VTLE APA CRGY BTE NA Onshore Inventory Life at NTM Activity Cadence (Years) PV-10 20:1 WTI:HH Breakeven ($/bbl) Inventory Life by Breakeven <$35 $35-$40 $40-$45 $45-$50 $50-$55 $55-$60 >$60 Note | Ranked by sub-$50/bbl WTI inventory life. BTE and WCP inventory life is based on a capital-weighted approach due to wide variance in DC&T across inventory base. Inventory life defined as total remaining footage divided by expected NTM completed footage. Source | Enverus Intelligence Research, 2025 Large inventory runway relative to North American oil-weighted shale plays
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Montney Inventory ARC has a deep Montney inventory at the low end of the cost curve ~50% of total inventory has a supply cost below C$0/Mcf 1) Inventory as of YE2024. 2) Based on internal type curves and economics calculated with US$70/bbl WTI oil pricing. 21 C$/Mcf 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 Gas AT NPV10 Supply Cost (CAD$/Mcf) Inventory Well Count Supply Cost of Inventory by Property1 2 Ante Creek Attachie Greater Dawson Kakwa Septimus Sundown Sunrise
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Asset Level Inventory ARC has substantial Montney drilling inventory at each of our producing and growth assets 22 1) Breakeven gas supply cost shown is where NPV10 = 0, holding oil price flat at US$70/bbl WTI. Gas price units are C$/mcf AECO. 2) Subject to Board and project approval. Break-even gas supply cost(1) 0 5 10 15 20 25 30 Ante Creek Greater Dawson Kakwa Sunrise Attachie Ph1 Attachie Growth Septimus Sundown Years of Development Inventory <$1.00 /mcf $1.00 - $2.00 /mcf $2.00 - $3.00 /mcf 2 2 2
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- 60,000 120,000 180,000 240,000 300,000 360,000 420,000 480,000 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 Montney Crude Oil & Liquids (bbl/d) Montney Natural Gas (boe/d) 2015 Sunrise Gas Plant & Tower Liquid Expansion 2018 Sunrise Gas Plant Phase II 2020 Dawson Phase IV 2021 ARC acquires Seven Generations Energy 2025 Attachie Phase I 2017 Dawson Gas Plant Phase III 2025 Kakwa Consolidation Montney – Track Record of Execution 23 Accumulate Asset Base Development Boe per day 2005 ARC drills first Montney Horizontal well 2006 – 2008 Building ARC’s Montney land base 2010 Dawson Gas Plant Phase I & Storm Acquisition 2011 Dawson Gas Plant Phase II 2014 Parkland Gas Plant Phase I
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Owned infrastructure results in approximately $300 million of cost avoidance annually Large Network of Owned-and-operated Infrastructure Parkland 03-09 100 MMcf/day 10 Mbbl/day Sunrise 360 MMcf/day Dawson 300 MMcf/day 20 Mbbl/day Cutbank Plant 250 MMcf/day 47 Mbbl/day Gold Creek Plant 250 MMcf/day Ante Creek Facilities 65 MMcf/day 12 Mbbl/day Lator Plants 290 MMcf/day Kakwa River Plant1 200 MMcf/day 18 Mbbl/day Karr Facility 75 Mbbl/day Attachie Phase I 90 MMcf/day 25 Mbbl/day 24 ~2.0 Bcf/d processing capacity ~200 Mbbl/d liquids handling capacity 1) ARC has a third-party processing agreement in place at the Pembina Kakwa River Plant. Acquired Kakwa Plants 90 MMcf/day 14 Mbbl/day 300 MMcf/day (19% ownership)
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Attachie, BC Asset Overview
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SCALE Largest condensate asset in Canada Resource to sustain production at 205,000 boe/d for greater than 10 years July 2025 acquisition consolidates core area • $1.6 billion1, all-cash transaction • 35-40 Mboe/d (50% liquids) • Extends asset inventory EFFICIENCIES Recent efficiency gains Refined well design and subsurface understanding of the reservoir Wider adoption of dual frac systems has reduced cycle times and enhanced capital efficiencies Infrastructure investment in 2026 to reduce operating costs Kakwa Overview Alliance Pembina NGTL Karr Facility Lator Plant Pembina Kakwa River Plant Cutbank Plant Gold Creek Plant Kakwa lands Acquired lands Kakwa Type Well Liquids-rich asset offering a long runway of development KAPS Strathcona Jayar Strathcona Resthaven Pembina Resthaven 1) Purchase price includes $1.6 billion for the Kakwa assets before purchase price adjustments and $20 million for additional unrelated equipment and undeveloped land.26 UM MM
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SCALE Early Stages of Development • 360 net sections in condensate-rich Montney • Over-pressured liquids-rich resource • First Nations support EFFICIENCIES Consolidated Land Drives Efficiencies • Continuous learning to enhance efficiencies • Use learnings to drive efficiencies • Refined well design • Well spacing • Development agreement with TDZE can increase land position by >10% • 100% working interest Attachie Overview Condensate-rich Montney development Attachie Type Well MD UMA LMA 27
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• Land is located directly adjacent to ARC’s Attachie development in the condensate-rich region of the Montney • Resource quality is comparable to existing Attachie development • Extends condensate-rich development runway in the Montney Development agreement to increase ARC’s Attachie land position by >10% to 360 sections TDZE Agreement Lands 28
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Attachie Economics 29 Note | L48 Plays include the Delaware, Permian (Delaware, Midland), Scoop|Stack, Eagle Ford, DJ, Williston Basin, Powder River, Uinta Source | Enverus Intelligence Research Attachie break-evens rank among the lowest in North America
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0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000IP90 BBL/D NEBC Top Oil/Condensate Wells Attachie among the top oil and condensate wells in NEBC 1. ARC forecasts included for wells with minimum 30d 2. IP90 as reported (not normalized) and on production since Aug 1, 2024 ARC Attachie ARC Greater Dawson Peers ARC Attachie ARC Greater Dawson Oil and Condensate Production per Well (IP90)
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SCALE >1 Tcf Natural Gas Produced 64% Undeveloped ~90,000 boe/d (80% natural gas; 20% condensate & NGLs) ECONOMICS Stable free funds flow • Greater Dawson contributes the second highest free funds flow (next to Kakwa) • Low-risk inventory with dual-connected facilities to limit downtime and increase efficiency Dawson Phase I & II Developed (36%) Undeveloped (64%) Dawson Phase III & IV Greater Dawson Overview 1) Non-GAAP Financial Measure — see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. Flagship asset delivering superior free funds flow1 with a long inventory runway MD UMA Dawson Type Well 31 Parkland 03-09
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Sunrise Overview Scale and low-cost – the key ingredients to supply West Coast LNG EFFICIENT Highly efficient dry natural gas play due to stacked development layers Interconnected to Coastal GasLink to move gas volumes to West Coast LNG LOW-COST Lower Sustaining Capital Well design modification has lowered sustaining capital by 10% Low Breakeven Full-cycle breakeven of ~C$1.10 – C$1.50 per Mcf Sunrise Phase I & II Developed (44%) Undeveloped (56%) Coastal GasLink Interconnect Coastal GasLink Sunrise Type Well MD UMA MB 32
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LNG & Marketing Strategy Sunrise, BC
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- 200 400 600 800 1,000 2022 2023 2024 2025 2026 2027 2028 Mbbl/d WCSB Condensate Balances WCSB Condensate Production Condensate Market Overview and Outlook WCSB condensate remains a structurally short market, reliant on imports to satisfy demand 2024 Canadian Oil Sands Blending Demand 785 Mbbl/d 2024 WCSB Production 520 Mbbl/d 2024 Imports from U.S. Natural Gasoline Market 265 Mbbl/d Forecast Source: ARC Risk Research, various third-party reports ~250 Mbbl/d of imports required to meet projected demand 2025-2028 34
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Natural Gas Marketing Strategy Portfolio with well-diversified global price exposure is driving strong realizations 1) Natural gas financial exposure based on internal volume and marketing assumptions, adjusted for ARC’s heat content, exposures subject to ARC renewal elections. Volumes denoted on map indicate 2025E natural gas sales exposure. 2) ARC’s Midwest US exposure is a combination of Alliance Pipeline and various third-party and proprietary contracting arrangements on Northern Border Pipeline. 3) International floating includes JKM and TTF linked pricing. Natural Gas Financial Exposure1 2 110% 11%20% 11% ARC’s Current Natural Gas Portfolio 3 24% 10% 2% 2% 24% 25% 33% 32% 35% 20% 23% 17% 16% 16% 10% 10% 10% 9% 9% 11% 13% 13% 12% 12% 11% 15% 14% 7% 1% 4% 11% 22% 27% 2026E 2027E 2028E 2029E 2030E Hedged WCSB Floating Midwest U.S. Floating Malin Floating Empress/Emerson/Dawn Floating Henry Hub Floating International Floating 35
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1) Supplementary Financial Measure— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. Natural Gas Price Realization – Benchmarking Physical diversification to end markets is a competitive advantage ARC has realized an average premium to AECO of 35% over the past decade 36 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 $9.00 2018 2019 2020 2021 2022 2023 2024 2025 2026E Realized Natural Gas Price 1 AECO ARX
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0 100 200 300 400 500 600 $- $200 $400 $600 $800 $1,000 $1,200 2027 2028 2029 2030 (MMcf per day) ($ millions) Annual Incremental Net Revenue2 vs AECO LNG Revenue Enhancement Sensitivity $10 JKM/TTF $12 JKM/TTF MMcf per day LNG Economics and Agreements Long-term supply agreements to diversify and access global natural gas pricing 37 1) International pricing 2) Economics run at C$3.00/Mcf AECO Shell (40% interest in LNG Canada) Cheniere Corpus Christi Stage III Cheniere Sabine Pass Liquefaction Stage V Cedar LNG/ ExxonMobil Volumes 150 MMcf/day 140 MMcf/day 140 MMcf/day 200 MMcf/day Term Medium-term 15 years 15 years Long-term Pricing Structure Premium to Western Canadian Pricing1 JKM2 TTF3 International pricing4 Start Date 2025 ~2026-2027 ~2029 ~Late 20285 1) Premium calculated as ARC's netback adjusted for marketing and transportation components. 2) Platts JKMTM (Japan Korea Marker), after deductions for fixed LNG shipping costs and a fixed liquefaction fee. 3) Dutch Title Transfer Facility price, after fixed deductions for liquefaction, shipping and regasification fees. 4) After deductions for fixed LNG shipping costs and liquefaction fees. 5) Estimated start date commencing upon commercial operations. Long-term Agreements LNG access is an extension of ARC’s diversification activities Diversify while maintaining low-cost at each end-market ARC’s all-in landed cost to reach JKM is US$5-6/MMBtu 1 1
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Appendix Ante Creek, AB
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Financial Strength Strong financial position has been a foundation of ARC for 29 years 1) Refer to the Advisory Statements to this presentation. 2) Non-GAAP Financial Ratio— see "Non-GAAP and Other Financial Measures" in the Advisory Statements of this presentation. 3) Effective July 2, 2025 – non-renewable Cdn$ millions Long-term notes repayment schedule1 Net debt to funds from operations • Currently below the long-term target range of approximately 1.5x at mid-cycle pricing • Ensures ample flexibility and opportunity at low points in the cycle Simple capital structure with investment-grade credit rating • $2.0 billion unsecured extendible revolving credit facility • $500 million3 two-year term loan 39 2026 forecasted net debt sensitivities1 2 $ billions, ratio 3 0 150 300 450 600 2026 2027 2028 2029 2030 2031 2032 2.354% Cdn$ Note 3.465% Cdn$ Note 3.577% Cdn$ Note 4.409% Cdn$ Note Term Loan 0.0x 0.5x 1.0x 1.5x 0.0 0.5 1.0 1.5 2.0 2.5 3.0 US$50/bbl WTI & US$3.0/Mmbtu NYMEX US$60/bbl WTI & US$3.5/MMbtu NYMEX US$80/bbl WTI & US$4.5/MMbtu NYMEX US$90/bbl WTI & US$5.0/MMbtu NYMEX Net Debt (LHS) Net Debt to Funds from Operations (RHS)
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0 500 1,000 1,500 2,000 2,500 3,000 3,500 ARC Attachie Montney Operational Excellence Best-in-class drilling and completions efficiencies Completions Efficiency Proppant Pumped/Day1Tonnes/day 40 ARC Peers 1) Completion benchmarking data from January 2023 to March 2025. 0 100 200 300 400 500 600 Drilling Efficiency (m/day)1 ARC Peerm/day 1) Benchmarking data from January 2024 to March 2025. Data set only includes monobores; wells with 3 casing string design are excluded
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- 400 800 1,200 1,600 2,000 2,400 2,800 ARC 0 50 100 150 200 250 300 SCR ARC Drilling Efficiency (m/day)1 m/day Greater Kakwa Montney Operational Excellence ARC continues to deliver top-quartile completions and drilling efficiencies in Kakwa Completions Efficiency Proppant Pumped/Day1Tonnes/day 41 ARC Peer 1) Benchmarking data from January 2023 to March 2025. 1) Benchmarking data from January 2024 to March 2025. ARC Peer
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0 500 1,000 1,500 2,000 2,500 ARC 0 100 200 300 400 500 600 700 Greater Dawson Montney Operational Excellence Best-in-class drilling and completions efficiencies in the Greater Dawson area Completions Efficiency Proppant Pumped/Day1Tonnes/day 42 Drilling Efficiency (m/day) 1 2 m/day 1) Benchmarking data from January 2024 to March 2025. 2) Drilling efficiency representsthe Greater Dawson area. 1) Benchmarking data from January 2023 to March 2025.
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BC Landscape ARC’s Northeast BC Assets BRFN High Value Areas Surface Disturbance Limited by 60 – 100% • 100% of ARC’s assets are outside of the Blueberry River First Nations high value areas • Latest agreement removes the disturbance caps in ‘PNG Area A’ that includes Attachie • ARC is the sole oil and gas producer exempt from disturbance caps in ‘PNG Area A’ at this time • ARC’s producing assets Dawson, Parkland, and Sunrise are on freehold (private) lands 43
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U.S. Natural Gas Market Outlook Rising export demand requires ~17 Bcf/d of supply growth through 2030, a significant amount must be supplied by dry gas basins Source: ARC Risk Research, various third-party reports 0 5 10 15 20 25 LNG Exports Mexico Piped Exports Domestic Demand Total Demand Call-on Supply Bcf/d U.S. Natural Gas Outlook: Full-Year 2030 vs. Full-Year 2025 Call-on Dry Gas Associated Gas Growth Forecast 44
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WCSB Natural Gas Market Outlook WCSB demand projections suggest >3.5 Bcf/d of incremental production is required by 2030 Source: ARC Risk Research, various third-party reports 0 1 2 3 4 5 6 7 2025 2026 2027 2028 2029 2030+ Bcf/d WCSB LNG Export Capacity Buildout Ksi Lisims LNG Canada Ph. 2 Cedar LNG Woodfibre LNG Canada Ph. 1 Operational 0 1 2 3 4 5 6 7 8 LNG Exports Piped Exports Local Demand Call-on Supply LNG Exports Call-on Supply Full-Year 2029 vs Full-Year 2025 2030+ vs Full-Year 2025 Bcf/d WCSB Natural Gas Outlook 45
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Risk Management Contracts Positions ARC’s long-term focus is to reduce downside risk and create certainty in cash flows As at December 31, 2025 1 2026 2027 2028 2029 Crude Oil – WTI US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day US$/bbl bbl/day Ceiling 79.19 15,000 – – – – – – Floor 63.33 15,000 – – – – – – Sold Floor 51.67 15,000 – – – – – – Swap 58.60 161 – – – – – – Sold Swaption 2 – – 89.51 4,000 – – – – Total Crude Oil Volumes (bbl/day) 15,161 – – – Natural Gas – NYMEX Henry Hub 3 US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day Ceiling 6.16 50,000 – – – – – – Floor 3.00 5,000 – – – – – – Natural Gas – AECO 7A Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Ceiling 4.04 300,000 3.61 180,000 3.46 30,000 2.46 30,000 Floor 2.71 300,000 2.56 180,000 2.50 30,000 2.50 30,000 Swap 2.87 29,315 – – – – – – Natural Gas – Chicago 4 Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Cdn$/GJ GJ/day Ceiling 5.27 48,301 – – – – – – Floor 3.50 48,301 – – – – – – Total Natural Gas Volumes (MMBtu/day) 410,432 – – Natural Gas – AECO Basis (Differential to NYMEX Henry Hub) US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day US$/MMBtu MMBtu/day Sold Swap (1.05) 84,644 (1.05) 92,500 (1.05) (92,500) (1.05) 21,075 Total AECO Basis Volumes (MMBtu/day) 92,500 92,500 92,500 21,075 Foreign Exchange Notional (US$ millions) Rate (Cdn$/US$) Notional (US$ millions) Rate (Cdn$/US$) Notional (US$ millions) Rate (Cdn$/US$) Notional (US$ millions) Rate (Cdn$/US$) Ceiling 360.0 1.4265 – – – – – – Floor 360.0 1.3700 – – – – – – Sold Floor 240.0 1.3100 – – – – – – 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) The sold swaption allows the counterparty, at a specific 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) Natural gas prices referenced to NYMEX Henry Hub Last Day Settlement. 4) Natural gas prices referenced to NGI Chicago Citygate. 46
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ESG Ratings and Rankings Member of MSCI Global Sustainability Index MSCI ESG Rating: AAA Environment Score: 8 Social Score: 7 Governance Score: 1 Score: 48.2 – (52th Percentile) Member of the 30% Club since 2018 47
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Advisory Statements 48
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Advisory Statements This presentation contains certain forward-looking information within the meaning of applicable Canadian securities laws regarding ARC's current expectations of possible events, conditions or financial performance that are based on certain assumptions about future economic conditions and courses of action. 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 possible future outcomes. In particular, but without limiting the foregoing, this presentation contains forward-looking information with respect to: ARC’s guiding principles, including its focus on free cash flow per share growth, a strong balance sheet, and sustainable dividend growth; expectations that ARC's large concentrated asset base drives efficiency and that ARC is well-positioned for the future; estimated free funds flow per share growth; ARC's intentions and strategy to return essentially all free funds flow in 2026 to shareholders through the base dividend and share repurchases; the growth capability of ARC's assets and the optionality among them; ARC's intentions to expand margins through LNG agreement and organic growth in condensate rich assets; ARC's 2026 capital budget and guidance including, among others, planned capital expenditures, the capital allocation amongst ARC's assets and that capital allocation may shift throughout 2026, the number of wells and the expected production at each asset, anticipated free funds flow, anticipated average annual production including for crude oil and condensate; anticipated operating expenses, transportation expenses, G&A expenses before share-based compensation expense, G&A expenses, interest and financing expenses and current income tax as a per cent of funds from operations; ARC's long-term outlook from 2026 through to 2029 including plans to grow free funds flow per share and anticipated compound annual growth rate, return on average capital employed, capital expenditures, production and free funds flow; expectations that 25% of ARC's future natural gas production is linked to international pricing; anticipated ROACE for 2026 through to 2029; that ARC's pace of growth in the future will be governed by corporate returns and a balance sheet first mentality; ARC's strategy in respect of return of capital including anticipated dividend per share, dividend per share growth CAGR, dividend payout ratio (as a percentage of FFO) and outstanding share capital; the lifespan of ARC's inventory at each of ARC’s assets and that ARC has large inventory runway relative to North American oil-weighted shale plays; that there is substantial Montney drilling inventory at each of ARC's producing and growth assets and the break-even supply cost at each asset; ARC's development plans at the Montney asset, including Attachie Phase I and Phase II; expectations that the Kakwa asset can sustain production at 205,000 boe/d for greater than 10 years and that it’s July 2025 acquisition extended asset inventory; ARC's plan to invest in infrastructure at Kakwa in 2026 to reduce operating costs; ARC's plans to use learnings at Attachie, including learnings related to well design and well spacing, to drive efficiencies in 2026; ARC's plans for Attachie Phase I in 2026 including $250-300MM capital expenditures; that the production from Attachie wells is competitive among oil and condensate wells in NEBC; that the TDZE Agreement extends development runway in the Montney; that the Greater Dawson asset has a long inventory runway; WCSB condensate balances for 2025 through 2028 and anticipated import volumes required to meet projected demand; ARC's estimated natural gas financial exposure for 2026 through 2029 and onwards; ARC's 2026 expected realized natural gas price as compared to AECO; the anticipated volumes, terms and start dates in respect of ARC's long-term supply agreements; ARC's estimated annual incremental net revenue as compared to AECO for 2027 to 2030; the expectation that ARC's all-in landed cost to reach JKM is US$5-6/MMBtu; ARC's 2026 forecasted net debt sensitivities and the long-term notes anticipated repayment schedule; the expectation that rising export demand will require ~17 Bcf/d of supply growth by 2030 and that a significant amount must be supplied by dry gas basins; the expectation that >3.5 Bcf/d of incremental production is required by 2030 and anticipated WCSB LNG export capacity and natural gas outlook until 2030 and beyond; ARC's long-term focus in relation to risk management contracts; and other statements. There can be no assurance that the plans, intentions, or expectations upon which this forward-looking information is based will occur. Notes Regarding Forward-looking Information
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Advisory 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. The material assumptions on which the forward-looking information in this news release are based, and the material risks and uncertainties underlying such forward-looking information, include: forward pricing assumptions; risks and assumptions related to potential natural gas curtailments due to low natural gas prices; volatility of commodity prices; adverse economic conditions; political uncertainty; lack of capacity in, and/or regulatory constraints and uncertainty regarding, gathering and processing facilities, pipeline systems, and railway lines; indigenous land and rights claims; compliance with environmental regulations; risks relating to climate change, including transition and physical risks; ARC's ability to recruit and retain a skilled workforce and key personnel; development and production risks; project risks; risks relating to failure to obtain regulatory approvals; reputational risks; risks relating to a changing investor sentiment; asset concentration; risks relating to information technology systems and cyber security; risks related to hydraulic fracturing (including risks with respect to water production and disposal); liquidity; inflation, cost management and interest rates; third-party credit risks; variations in foreign exchange rates; risks relating to royalty regimes; the impact of competitors; risks related to potential or ongoing litigation; lack of adequate insurance coverage; inaccurate estimation of ARC's reserve volumes; risks related to derivative risk management contracts; limited, unfavorable or a lack of access to capital markets; market access constraints or transportation interruptions, unanticipated operating results or production declines; the ability to shift capital allocation among ARC’s assets; increased debt levels or debt service requirements; increased costs; potential regulatory and industry changes stemming from the results of court actions affecting regions in which ARC holds assets; ARC's ability to successfully close, integrate and realize the anticipated benefits of completed, contemplated, or future acquisitions and divestitures; access to sufficient capital to pursue any development plans; the risk that (i) the tariffs that are currently in effect on goods exported from or imported into Canada continue in effect for an extended period of time, the tariffs that have been threatened are implemented, that tariffs that are currently suspended are reactivated, the rate or scope of tariffs are increased, or new tariffs are imposed, including on oil and natural gas, (ii) the U.S. and/or Canada imposes any other form of tax, restriction or prohibition on the import or export of products from one country to the other, including on oil and natural gas, and (iii) the tariffs imposed or threatened to be imposed by the U.S. on other countries and retaliatory tariffs imposed or threatened to be imposed by other countries on the U.S., will trigger a broader global trade war which could have a material adverse effect on the Canadian, U.S. and global economies, and by extension the Canadian oil and natural gas industry and the Company, including by decreasing demand for (and the price of) oil and natural gas, disrupting supply chains, increasing costs, causing volatility in global financial markets, and limiting access to financing; the impacts of the ongoing Middle-East conflicts, Russia-Ukraine war and geopolitical developments in Venezuela (and any associated sanctions) on the global economy and commodity prices; forecast commodity prices and other pricing assumptions with respect to ARC's 2026 capital expenditure budget; ARC's ability to repurchase its securities under the NCIB; that the previously announced LNG agreements will commence on the timelines anticipated and maintain volumes and pricing as expected; that counterparties to ARC's various agreements will comply with their contractual obligations; expectations and projections made in light of ARC's historical experience; data contained in key modeling statistics; assumptions with respect to global economic conditions and the accuracy of ARC's market outlook expectations for 2026; suspension of or changes to or withdrawals of guidance, and the associated impact to production and capital expenditures; forecast production volumes based on business and market conditions; the accuracy of outlooks and projections contained herein; that future business, regulatory, and industry conditions will be within the parameters expected by ARC, including with respect to prices, margins, demand, supply, product availability, supplier agreements, availability, and cost of labour and interest, exchange, and effective tax rates; projected capital investment levels, the flexibility of capital spending plans, and associated sources of funding; the ability of ARC to complete capital programs and the flexibility of ARC's capital structure; opportunity for ARC to pay dividends and the approval and declaration of such dividends by the Board; the existence of alternative uses for ARC's cash resources which may be superior to payment of dividends or effecting repurchases of outstanding common shares; cash flows, cash balances on hand, and access to ARC's credit facility and other long-term debt being sufficient to fund capital investments; the ability of ARC's existing pipeline commitments and financial risk management transactions to partially mitigate a portion of ARC's risks against wider price differentials; business interruption, property and casualty losses, or unexpected technical difficulties; estimates of quantities of crude oil, natural gas, and liquids from properties and other sources not currently classified as proved; future use and development of technology and associated expected future results; 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; the retention of key assets; the continuance of existing tax, royalty, and regulatory regimes; estimates with respect to commodity pricing; and other assumptions, risks, and uncertainties described in this presentation and from time to time in the filings made by ARC with securities regulatory authorities, including those risks contained under the heading "Risk Factors" in ARC’s management discussion and analysis for the year ended December 31, 2025. Notes Regarding Forward-looking Information
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Advisory Statements ARC's future shareholder distributions, including but not limited to the payment of dividends, if any, and the level thereof is uncertain. Any decision to pay dividends on ARC's shares (including the actual amount, the declaration date, the record date and the payment date in connection therewith and any special dividends) will be subject to the discretion of ARC's board of directors and may depend on a variety of factors, including, without limitation, ARC's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time including, without limitation, contractual restrictions and satisfaction of the solvency tests imposed on ARC under applicable corporate law. Further, the actual amount, the declaration date, the record date and the payment date of any dividend are subject to the discretion of ARC's board of directors. There can be no assurance that ARC will pay dividends in the future. 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, but not limited to: production, capital expenditures, operating expenses, transportation expenses, G&A expenses before share-based compensation expense, G&A expenses – share based compensation expense, interest and financing expenses, current income tax as a per cent of funds from operations, free funds flow, free funds flow per share, return on average capital employed, dividend per share, dividend per share growth CAGR, dividend payout ratio (as a percentage of FFO), expected realized natural gas prices, annual incremental net revenue, all-in landed cost to reach JKM and forecasted net debt sensitivities. The internal projections, expectations, or beliefs are based on the 2026 capital budget and ARC's long-term plan through 2029, which are subject to change in light of ongoing results, prevailing economic conditions, commodity prices, and industry conditions and regulations. ARC's budgets after 2026, including the board of directors sanctioning further development of Attachie Phase II, have not been finalized and will be subject to the approval of ARC's board of directors and may depend on a variety of factors at such time, including, without limitation, ARC's business performance, financial condition, financial requirements, growth plans, expected capital requirements and other conditions existing at such future time. These financial outlook and other related forward-looking information are also subject to the same assumptions, risk factors, limitations, and qualifications as set forth above. The forward-looking information contained herein is expressly qualified in their entirety by this cautionary statement. The forward-looking information included in this presentation is made as of February 5, 2026 and, except as required by applicable securities laws, ARC undertakes no obligation to publicly update such forward-looking information to reflect new information, subsequent events or otherwise. Notes Regarding Forward-looking Information
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Advisory 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 and Other Financial Measures Throughout this presentation and in other materials disclosed by the Company, ARC employs certain measures to analyze its financial performance, financial position, and cash flow. These non-GAAP and other financial measures are not standardized financial measures under IFRS and may not be comparable to similar financial measures disclosed by other issuers. The non-GAAP and other financial measures should not be considered to be more meaningful than GAAP measures which are determined in accordance with IFRS, such as net income (loss), cash flow from operating activities, and cash flow used in investing activities, as indicators of ARC's 2025 and 2024's performance. See the section entitled "Non-GAAP and Other Financial Measures" in the Company's MD&A for the year ended December 30, 2025 ("2025 Annual MD&A"), which section is incorporated by reference into this presentation. The 2025 Annual MD&A is available on ARC's website at www.arcresources.com and under ARC's SEDAR+ profile at www.sedarplus.ca.
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Advisory Statements Non-GAAP Financial Measures Capital Expenditures ARC uses capital expenditures to measure its capital investment level compared to the Company's annual budgeted capital expenditures. ARC's budgeted capital expenditures exclude any acquisition or disposition activities as well as the accounting impact of any accrual changes and payments under lease arrangements. The directly comparable GAAP measure to capital expenditures is cash flow used in investing activities. Please see "Non-GAAP and Other Financial Measures – Non-GAAP Financial Measures – Capital Expenditures" in the 2025 Annual MD&A for a quantitative reconciliation of capital expenditures against cash flow used in investing activities, its more directly comparable GAAP measure. Free Funds Flow ARC uses free funds flow as an indicator of the efficiency and liquidity of ARC's business, measuring its funds after capital expenditures available to manage debt levels, pay dividends, and return capital to shareholders. ARC computes free funds flow as funds from operations generated during the period less capital expenditures. Capital expenditures is a non-GAAP financial measure. By removing the impact of current period capital expenditures from funds from operations, Management monitors its free funds flow to inform its capital allocation decisions. The most directly comparable GAAP measure to free funds flow is cash flow from operating activities. Please see "Non-GAAP and Other Financial Measures – Non-GAAP Financial Measures – Free Funds Flow" in the 2025 Annual MD&A for a quantitative reconciliation of free funds flow against cash flow from operating activities, its most directly comparable GAAP measure. Netback ARC computes netback as commodity sales from production less royalties, operating, and transportation expense. Management believes that netback is a key industry performance indicator and one that provides investors with information that is also commonly presented by other crude oil and natural gas producers. The most directly comparable GAAP measure is commodity sales from production. Please see "Non-GAAP and Other Financial Measures – Non-GAAP Financial Measures – Netback" in the 2025 Annual MD&A for a quantitative reconciliation of netbacks against commodity sales from production, its most directly comparable GAAP measure. Adjusted Earnings before Interest and Taxes ("EBIT") ARC calculates adjusted EBIT as net income (loss) plus interest and financing, less accretion of ARO, plus total income taxes (recovery). ARC uses adjusted EBIT as a measure of long-term operating performance and as a component in the calculation for ROACE, which is calculated by ARC on an annual basis and a five-year basis. The most directly comparable GAAP measure is net income (loss). Please see "Non-GAAP and Other Financial Measures – Non-GAAP Financial Measures – Adjusted EBIT" in the 2025 Annual MD&A for a quantitative reconciliation of adjusted EBIT against net income (loss), its most directly comparable GAAP measure. Average Capital Employed ARC calculates average capital employed as the total of net debt plus current and long-term portions of lease obligations and shareholders' equity. ARC uses average capital employed as a measure of long-term capital management and operating performance, and as a component in the calculation for ROACE. The most directly comparable GAAP measure is shareholders' equity. Please see "Non-GAAP and Other Financial Measures – Non-GAAP Financial Measures – Average Capital Employed" in the 2025 Annual MD&A for a quantitative reconciliation of average capital employed against shareholders' equity, its most directly comparable GAAP measure.
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Advisory Statements Non-GAAP Ratios Netback per boe ARC calculates netback per boe as netback divided by weighted average daily production. Netback is a non-GAAP financial measure component of netback per boe. Management believes that netback per boe is a key industry performance measure of operational efficiency and one that provides investors with information that is also commonly presented by other oil and gas producers. Free Funds Flow per Share ARC presents free funds flow per share by dividing free funds flow by the Company's diluted or basic weighted average common shares outstanding. Free funds flow is a non-GAAP financial measure. Management believes that free funds flow per share provides investors an indicator of funds generated from the business that could be allocated to each shareholder's equity position. Return on Average Capital Employed ("ROACE") ARC calculates ROACE, expressed as a percentage, as EBIT divided by the average capital employed. The components EBIT and average capital employed are non-GAAP financial measures. ARC uses ROACE as a measure of long-term financial performance, to measure how effectively Management utilizes the capital it has been provided and to demonstrate to shareholders the returns generated over the long term. Capital Management Measures Funds from Operations ARC considers funds from operations to be a key measure of capital management as it demonstrates ARC’s ability to generate the necessary funds to maintain production at current levels and fund future growth through capital investment. Management believes that such a measure provides an insightful assessment of ARC’s operations on a continuing basis by eliminating certain non-cash charges and actual settlements of ARO, of which the nature and timing of expenditures are discretionary. Funds from operations is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities. Please see "Non- GAAP and Other Financial Measures – Capital Management Measures – Funds from Operations" in the 2025 Annual MD&A for a quantitative reconciliation of funds from operations against cash flow from operating activities, the most directly comparable financial measure disclosed in the Company's primary financial statements. Net Debt and Net Debt to Funds from Operations Net debt and net debt to funds from operations are used by Management as key measures to assess the Company's liquidity position at a point in time. Previously, net debt was computed including current and long-term portions of lease obligations and a similar measure; "net debt excluding lease obligations" was also presented. At December 31, 2025 and 2024, net debt has been computed excluding lease obligations. The current determination of net debt and net debt to funds from operations is reflective of the measures used by Management to monitor its liquidity in light of operating and capital budgeting decisions. Net debt is not a standardized measure and therefore may not be comparable with the calculation of similar measures by other entities. Please see "Non-GAAP and Other Financial Measures – Capital Management Measures – Net Debt and Net Debt to Funds from Operations" in the 2025 Annual MD&A for a quantitative reconciliation of net debt and net debt to funds from operations against long term debt, the most directly comparable financial measure disclosed in the Company's primary financial statements.
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Advisory Statements Supplementary Financial Measures "Average realized natural gas price" is comprised of natural gas commodity sales from production, as determined in accordance with IFRS, divided by the Company's natural gas production. “Break-even” is comprised as funds from operation less capital to sustain base production less dividends equals zero. "CAGR" is defined as the compounded annual growth rate. "Current income tax expense, as a per cent of funds from operations" is comprised of current income tax expense, as determined in accordance with IFRS Accounting Standards, divided by funds from operations. “Dividend Payout” is comprised of dividends declared, as determined in accordance with IFRS, divided by funds from operations. “Dividend Yield” is comprised of the dividend as a percent of current share price. "Funds from operations per basic share" is comprised of funds from operations divided by basic weighted average common shares. “Reinvestment rate” is comprised capital expenditures as a percent of funds from operations. 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") of natural gas to one barrel ("bbl") of liquids. 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 to 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. Product Types 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. 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).
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Advisory Statements Information Regarding Disclosure on Crude Oil and Natural Gas Reserves and Operational Information In accordance with Canadian practice, production volumes and revenues are reported on a company gross basis, before deduction of Crown and other royalties, and without including any royalty interests, unless otherwise stated. Unless otherwise specified, all reserves volumes in this presentation (and all information derived therefrom) are based on company gross reserves using forecast prices and costs. Drilling Locations This presentation discloses booked as well as unbooked potential future drilling locations for the Montney area. The drilling locations on which ARC will actually drill wells ultimately depends upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual drilling results and other factors. While certain drilling locations have beenderisked by drilling existing wells in relative close proximity to such drilling locations, certain other 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 oil and gas reserves, resources or production. 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.
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Investor Relations Contacts Manager, Capital Markets 403.503.8696 DLewko@arcresources.com Dale Lewko General Investor Relations Enquiries 403.503.8600 1.888.272.4900 IR@arcresources.com 57