Company Presentation May 2022 - Seeking Alpha
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Company Presentation
May 2022
Legal Disclaimer
This presentation includes “forward-looking statements.” Such forward-looking statements are subject to a number of risks and uncertainties, many of which are not under AR’s control. All
statements, except for statements of historical fact, made in this presentation regarding activities, events or developments AR expects, believes or anticipates will or may occur in the future,
such as those regarding expected results, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future
capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil
prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and
type of drilling rigs and the number of wells per pad), projected well costs and cost savings initiatives, future financial position, future technical improvements, future marketing and asset
monetization opportunities, the amount and timing of any contingent payments, the participation level of our drilling partner and the financial and operational results to be achieved as a result
of the drilling partnership, estimated Free Cash Flow and the key assumptions underlying its projection and AR’s environmental goals are forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All forward-looking statements speak only as of the date of this presentation. Although AR
believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or
expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Except as required by law, AR
expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.
In addition, many of the standards and metrics used by AR in preparing this presentation and the AR ESG Report continue to evolve and are based on management expectations and
assumptions believed to be reasonable at the time of preparation but should not be considered guarantees. The standards and metrics used, and the expectations and assumptions they are
based on, have not been verified by any third party. In addition, while AR seeks to align these disclosures with the recommendations of various third-party frameworks, such as the Task Force
on Climate-Related Financial Disclosures ("TCFD"), AR cannot guarantee strict adherence to these framework recommendations. Additionally, AR’s disclosures based on these frameworks
may change due to revisions in framework requirements, availability of information, changes in our business or applicable governmental policy, or other factors, some of which may be beyond
AR’s control. The calculation of AR’s methane leak loss rate disclosed in this presentation conforms with ONE Future protocol, which is based on the EPA Greenhouse Gas Reporting
Program. With respect to its Scope 1 emissions goal, Antero Resources anticipates achieving Net Zero Scope 1 emissions by 2025 through operational efficiencies and the purchase of
carbon offsets. Scope 1 emissions are the Company’s direct greenhouse gas emissions, and Scope 2 emissions are the Company’s indirect greenhouse gas emissions associated with the
purchase of electricity, steam, heat or cooling; however, such goals are aspirational and we could face unexpected material costs as a result of our efforts to meet these goals.
AR cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and the development, production, gathering and sale of
natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond AR’s control. These risks include, but are not limited to, commodity price volatility, inflation, lack
of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and
oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, impacts of geopolitical events and world health events,
including the COVID-19 pandemic, cybersecurity risks, our ability to achieve our greenhouse gas reduction targets and costs associated therewith, the state of markets for and availability of
verified carbon offsets and the other risks described under the heading "Item 1A. Risk Factors" in AR’s Annual Report on Form 10-K for the year ended December 31, 2021. Any forward
looking statement speaks only as of the date on which such statement is made and AR undertakes no obligation to correct or update any forward looking statement whether as a result of new
information, future events or otherwise, except as required by applicable law.
This presentation and the AR ESG Report contain statements based on hypothetical or severely adverse scenarios and assumptions, and these statements should not necessarily be viewed
as being representative of current or actual risk or forecasts of expected risk. These scenarios cannot account for the entire realm of possible risks and have been selected based on what we
believe to be a reasonable range of possible circumstances based on information currently available to us and the reasonableness of assumptions inherent in certain scenarios; however, our
selection of scenarios may change over time as circumstances change. While future events discussed in this presentation or the report may be significant, any significance should not be read
as necessarily rising to the level of materiality of certain disclosures included in Antero Resources' SEC filings. The goals discussed in this presentation are aspirational; we could face
unexpected material costs as a result of our efforts to meet these goals and may ultimately meet such goals through the purchase of offsets or credits and not reductions in our actual GHG
emissions. Moreover, given uncertainties related to the use of emerging technologies, the state of markets for and the availability of verified quality carbon offsets, we cannot predict whether or
not we will be able to timely meet these goals, if at all. Moreover, with regards to our participation in, or certification under, various frameworks, we may incur certain costs associated with such
frameworks and cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile.
This presentation also includes the following AR non-GAAP measures (i) Free Cash Flow, (ii) Adjusted EBITDAX, (iii) Adjusted EBITDAX Margin, (iv) Net Debt and (v) leverage which are a
financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). Please see “Antero Non-GAAP Measures” for definitions of these
measures as well as certain additional information regarding these measures.
Antero Resources Corporation is denoted as “AR” in the presentation and Antero Midstream Corporation is denoted
as “AM”, which are their respective New York Stock Exchange ticker symbols.
2
Premier Pure-Play Appalachian E&P
$13.1 Bn Ohio
Utica Shale
West Virginia
Marcellus Shale
ENTERPRISE VALUE (1)
5th Largest
U.S. GAS PRODUCER (2)
Headquarters:
2nd Largest Denver, CO
U.S. NGL PRODUCER (2)
20+ Years
OF PREMIUM DRILLING
INVENTORY (3)
$10.0 Bn+
FORECAST FREE CASH FLOW
2022-2026 (4)
$1.4 Bn Top LNG Supplier Top NGL Exporter
AM VALUE HELD BY AR’s 29% ~2.3 BCF/d OF NATURAL GAS PRODUCTION ~65 MBbl/d OF NGLs SUPPLIED TO EUROPE
OWNERSHIP (1) TO THE GULF COAST AND LNG FAIRWAY AND FAR EAST VIA MARCUS HOOK
1) Indebtedness as of 3/31/2022. Market cap as of 4/29/2022.
2) Natural gas and NGL rankings based on 2021 reported production.
3
3) Based on undeveloped premium locations as of 12/31/2021, assuming 2022 drilled wells held flat. See appendix for 2022 program guidance.
4) Free Cash Flow is a Non-GAAP metric. Please see appendix for additional disclosures, definitions, and assumptions.
Antero Family at a Glance
50/50 JV
Exploration & Gathering & Natural Gas C3+ NGL
Production Compression Processing Fractionation
Water Delivery
& Blending
4
Antero Strategy Evolution
Antero’s business strategy has evolved to match the U.S. shale industry life cycle
AR Net Production (Right Axis) & Capital Investment (Left Axis)
($MMs) (1) (MMcfe/d)
We are
$3,500 Production (MMcfe/d) Capital Spend here 4,000
$3,000 3,500
$2,500 3,000
2,500
$2,000
2,000
$1,500
1,500
$1,000 1,000
$500 500
$0 -
2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022E
Shale 1.0 Shale 2.0 Shale 3.0
• Acquire acreage • Grow production • Maintain production
• Support infrastructure • Aggressively hedge • Generate Free Cash Flow
through long-term • Consolidate acreage • Reduce debt &
commitments commitments
• Innovate through drilling and
• Delineate resource • Maintain commodity
completion techniques
exposure
• Access low cost capital
• Optimize FT
• Return capital
• Prioritize ESG
1) Represents drilling and completion + leasehold capital expenditures. 5
2014 vs Now - Why This Cycle is Different for Antero
Scale & Diversity Balance Sheet
Average Liquids & Total Production Net Debt ($MM) & Leverage (1)
200,000
Liquids Production (Bbl/d)
Net Debt Leverage
160,000 1Q22
+215% 120,000 $5,000
$4,117
4.5x
TOTAL PRODUCTION
INCREASE; ~137 MBbl/d
80,000
$4,000 3.5x 3.5x
($2.2) Bn
INCREASE IN LIQUIDS 40,000
$3,000 2.5x REDUCTION IN
$1,960
2014
$2,000 1.5x TOTAL DEBT
- 1.1x
- 1,000 2,000 3,000 4,000
$1,000 0.5x
Total Production (MMcfe/d) YE 2014 1Q22
Cash Flow Generation Valuation
Free Cash Flow ($Bn) (2) EV / EBITDAX & FCF Yield (3)
$3.0 $2.5+ EV / EBITDAX FCF Yield
$2.0
16.0x 25%
13.6x 23%
(9.6x)
$1.0
+$5.6 Bn
20%
$0.0 12.0x
15%
FREE CASH FLOW ($1.0)
8.0x 10%
DECREASE IN
INCREASE ($2.0)
4.0x
EV/EBITDAX
5%
($3.0) 4.0x MULTIPLES
0%
($4.0) (3%)
2014A 2022E 0.0x -5%
Updated Target 2014E 2022E
1) Balance sheet data as of 3/31/2014 and 3/31/2022, respectively. Net Debt and Leverage are Non-GAAP measures. See appendix for further details.
2) Free Cash Flow, which is shown before changes in working capital, is a Non-GAAP metric. Please see appendix for additional disclosures, definitions, and pricing assumptions.
3) Represents 2014E EV/EBITDAX and Free Cash Flow Yield as of 3/31/2014. 2022E EV/EBITDAX as of 4/29/2022 per consensus estimates. 6
Why Antero Resources?
Antero is well positioned with a strong balance sheet and a business model that
can generate substantial, sustainable free cash flow
Balance Sheet Deep drilling Supportive
Strength Inventory Fundamentals
Sustainable Optimal ESG
Free Cash Flow Takeaway Leader
& Return of
Capital
7
Strong and Sustainable Balance Sheet
Balance Sheet Strength
Balance Sheet AR Debt Term Structure (Pro Forma 3/31/2022) (1)
Enhancements $1,400 Called Remaining
2025s
CALLED NO $1,200
(3/1/2022)
$585 MM NEAR-TERM Revolver expected to
be paid off by 2Q22
SENIOR NOTES MATURITIES $1,000 via Free Cash Flow
DUE 2025
< $2.0 Bn LOWEST $800
$388
$584 $600
NET DEBT COMPANY DEBT $600
LEVEL SINCE 2013 No near-term maturities
1.1X < 0.5X $400
$82
LEVERAGE EXPECTED IN $200 $325
RATIO 2H 2022 (2)
Four
8.375% 7.625% 5.375%
BB+/Ba2 $0
2021 2022 2023 2024 2025 2026 2027 2028 2029 2030
S&P/MOODY’S RATINGS UPGRADES
CREDIT RATINGS SINCE JAN-21 AR Senior Notes AR Convertible Notes AR Revolver Borrowings
Note: Please see appendix for additional disclosures, definitions, and assumptions.
1)
2)
As of 3/31/22 unless otherwise indicated.
Assumes strip pricing as of 4/26/2022. 8
Significant Debt Reduction
Balance Sheet Strength
Antero Resources Total Debt Since 12/31/19
$4,000
$3,759
$1.8 Bn
$3,500
($757)
$3,002
$3,000 ABSOLUTE DEBT REDUCTION
SINCE YE 2019
$2,500 ($876)
$2,125
$1,960
$2,000 ($166)
$1,500 Asset sale ~$850+ MM of FCF, ~$315 MM of FCF,
proceeds, debt paid off revolver, Called 2025s, includes
$1,000 redemptions termed out 2023s $100 MM in share
buybacks
$500
$0
Net Debt 1Q20 - 4Q20 Net Debt 1Q21 - 4Q21 Net Debt 1Q22 Net Debt
12/31/19 (Repurchases 12/31/2020 (Repaid 12/31/2021 (Called Senior 3/31/2022
Senior Notes Revolver / Notes due
at Discount) Termed 2025)
out 2023s)
9
Strongest Balance Sheet in Appalachia
Balance Sheet Strength
Appalachian Peer Net Debt (1)
1 $6.0
$4.9 $5.0
$5.0
$4.0
< $2.0 Bn $3.0
$2.0
< $2.0 $2.2 $2.5
NET DEBT:
LOWEST AMONG $1.0
APPALACHIAN PEERS $0.0
AR Peer 1 Peer 2 Peer 3 Peer 4
Net Debt to LTM Adjusted EBITDAX (1)
1 3.0x 2.8x
1.9x
2.0x 1.7x 1.7x
1.6x
1.1X 1.0x
0.9x
1.1x
LEVERAGE RATIO:
LOWEST AMONG
0.0x
APPALACHIAN PEERS Majors AR Peer 2 Peer 3 Peer 1 Peer 4 S&P 500
Average
Source: Company public filings and press releases. FactSet for consensus figures.
Note: Peers include CNX, EQT, RRC and SWN.
1) Balance sheet data and LTM EBITDAX as of 3/31/2022. S&P 500 represents average consensus Net Debt to LTM EBITDA as of 4/29/2022. 10Increased Free Cash Flow Profile
Sustainable Free Cash Flow
Free Cash Flow ($MM) (1)
$12.0 5-Year Avg. Strip
Through YE 2026
$10.0 Bn
$10.0 TARGETED FREE CASH FLOW
NYMEX: $4.65/MMBtu
$10.0 THROUGH 2026, >90% OF
WTI: $80.50/Bbl
CURRENT MARKET VALUE (2)
C3+ NGLs: $46.50/Bbl
$8.0
$6.0
23%+
2022E FREE CASH FLOW YIELD
(MARKET VALUE) (3)
$4.0 HIGHEST AMONG APPALACHIAN
$2.5+ PEERS
$2.0
$0.9 20%+
2022E CORPORATE FREE CASH
$0.0
FLOW YIELD (4)
2021A 2022E 2022E - 2026E
HIGHEST AMONG APPALACHIAN
Cumulative FCF
(5-Year strip) PEERS
Note: Free Cash Flow, which is shown before changes in working capital, is a Non-GAAP metric. Excludes $51 MM contingent payment that was received in 2Q 2021 upon meeting certain
volume thresholds. Please see appendix for additional disclosures, definitions, and assumptions.
1) Assumes strip pricing as of 4/26/2022. See appendix for pricing assumptions.
2) Represents updated 2022-2026 Free Cash Flow target divided by market value as of 4/29/2022.
3) Represents updated 2022 Free Cash Flow target divided by market value as of 4/29/2022. AR ranking assumes consensus estimates as of 4/29/2022 for Appalachian peers.
4) Represents updated 2022 Free Cash Flow target divided by enterprise value as of 4/29/2022. AR ranking assumes consensus estimates as of 4/29/2022 for Appalachian peers. 11Leading Commodity Price Exposure
Sustainable Return of Capital
% Hedged 2Q’22 – 4Q’22 (1) % Hedged 2023 (1)
% Total Production Hedged % Total Production Hedged
% Natural Gas Production Hedged % Natural Gas Production Hedged
100% 80%
72%
90% 86% 68%
82% 83% 70%
Peer average hedged natural
80% gas production: 74% Peer average hedged natural 62%
76%
60% gas production: 57%
70%
65% 56%
63% Peer average hedged
50%
60% 60% total production: 67% 49% 45% Peer average hedged
50% 42%
total production: 50%
50% 47% 40%
35%
40% Antero
33% 30% Virtually
Unhedged
30%
20%
20%
10%
10%
1% 2%
0% 0%
AR RRC EQT CNX SWN AR RRC EQT SWN CNX
12
1) Represents percent of hedged 2022 and 2023 total production and natural gas production. AR and peer total production and natural gas production represents consensus as of
4/29/2022. Hedge positions as of 3/31/2022 based on company filings. Pro forma for any acquisitions announced to date.Return of Capital – Why Share Buybacks?
Sustainable Return of Capital
2022E Free Cash Flow / Market Cap (1) 2022E EV/ EBITDAX
14.9x
25% 6.5x 5.7x
20% 5.5x
5.2x
20% 4.7x
17% 4.1x
15% 15% 4.5x 3.9x 3.9x
15% 3.5x
11% 10%
10% 7% 2.5x
1.5x
5%
0.5x
0% -0.5x AR Majors Peer 3 Peer 1 Peer 2 Peer 4 S&P 500
AR Peer 1 Peer 2 Majors Peer 3 Peer 4 S&P
Average
Average 500
2022E Free Cash Flow / Enterprise Value (2) 2022E Cash Return as % of Market Cap (3)
20% 12%
16% 10%
10%
15% 12% 8% 8%
12% 11% 8%
10% 6% 5%
7% 7% 4%
5% 4% 3%
5%
2%
0%
0% 0%
AR Majors Peer 2 Peer 1 Peer 4 Peer 3 S&P AR Majors Peer 4 Peer 1 S&P 500 Peer 2 Peer 3
Average 500 Average
Source: Company public filings and press releases. FactSet for consensus figures.
Note: Please see appendix for additional disclosures, definitions, and assumptions. Consensus data as of 4/29/2022. Balance sheet data as of 3/31/2022.
1) Represents consensus Free Cash Flow divided by Market Cap.
2)
3)
Represents consensus Free Cash Flow divided by Enterprise Value.
Represents announced annual cash returned to shareholders as a percentage of market cap. AR represents mid-point of 25% to 50% of mid-point of Free Cash Flow as a percentage of market cap. 13AR: Lowest Leverage, Highest Return - “Major-Like” Metrics
Sustainable Return of Capital
Cash Return (1) vs. Leverage (2)
High Return
10%
1.1x Leverage /
10% Cash Return 9%
Peer 1
8%
Cash Return as % of Market Cap
Average of 7%
Majors
6%
Peer 2
5%
4%
Peer 4
Low Return
3%
2%
1%
Peer 3
0%
2.8x 2.4x 2.0x 1.6x 1.2x 0.8x 0.4x
Net Debt to LTM EBITDAX
High Leverage Low Leverage
Source: Company public filings and press releases. FactSet for consensus figures.
Note: Peers include CNX, EQT, RRC and SWN.
14
1) Represents announced annual cash returned to shareholders as a percentage of market cap. AR represents mid-point of 25% to 50% of updated 2022 Free Cash Flow target as a percentage of market cap.
2) Balance sheet data and LTM EBITDAX as of 3/31/2022. Major average and S&P 500 represent consensus Net Debt to LTM EBITDAX as of 4/29/2022.Peer Leading Premium Core Drilling Inventory
Deep Drilling Inventory
Premium Core Marcellus Inventory Southwest Appalachia Core
33%
AR HOLDS ~1,550 UNDEVELOPED Utica Core
LOCATIONS, OR 33% OF TOTAL
38%
AR HOLDS ~925 UNDEVELOPED
LIQUIDS LOCATIONS, OR 38% OF TOTAL
Premium Core Utica Inventory
23%
AR HOLDS ~180 UNDEVELOPED
LOCATIONS, OR 23% OF TOTAL
SW Marcellus
20+ Years Core
OF PREMIUM DRILLING
INVENTORY (1) Antero Leasehold & Minerals Drilled Wells
(1) Notes: AR drilling inventory as of 12/31/2021. Industry location count based on Antero technical analysis of undeveloped acreage in the core of the
Marcellus and Ohio Utica Shales. Average lateral length on Antero count increased ~1,000 feet from 12/31/2020 average. 15AR’s Peer-Leading Exposure to LNG Fairways
Optimal Takeaway
LNG Access & Exposure
Firm Transport to LNG Fairway Antero Firm Transportation
2.5 2.3 Antero Total = 2.3 Bcf/d
2.0
1.5
1.5
1.0 0.9
1.0
0.5
0.0
0.0
AR SWN EQT RRC CNX 0.33 Bcf/d
% of Total 75% 25% 14% 48% 0%
Production (1) Cove Point
WB LNG
LNG Feedgas Capacity (2021-2026)
Xpress
In Service 13.7 Bcf/d
Under Construction Today:
6.0 Bcf/d Antero is selling ~1.0
or FID Approved
Bcf/d to LNG facilities on
Waiting on FID 9.9 Bcf/d Driftwood 1: 2.4 Bcf/d 1Q’25 short-term and long-term
Total = 29.6 Bcf/d Cameron: 2.4 Bcf/d in service contracts
(Cameron Train 4: 1 Bcf/d 1Q’25)
Plaquemines: 3 Bcf/d - 4Q’24
Sabine Pass: 4.8 Bcf/d
Calcasieu Pass: (0.75 Bcf/d in service)
Freeport: 2.1 Bcf/d
(1.6 Bcf/d – 1Q’23)
Corpus Christi: 2.4 Bcf/d in service
(1.2 Bcf/d waiting on FID) Gulf Coast
Source: Company filings and Antero estimates. LNG Fairway
1) Represents percent of consensus gross gas residue production. 16Antero Has the Firm Transport to Supply LNG Demand
Optimal Takeaway
~2.3 Bcf/d
ANTERO FIRM
TRANSPORT ACCESSES
THE LNG FAIRWAY (1)
~26 Bcf/d
TOTAL LNG CAPACITY
ACCESSIBLE BY ANTERO’S
FIRM TRANSPORT,
~11 Bcf/d IN-SERVICE
~15 Bcf/d IN PROGRESS
Gulf of Mexico
17
1) Includes 330 MMcf/d of transport to
Atlantic Seaboard (Cove Point).Diversity of Product & Destination
Optimal Takeaway
Liquids Production (1) & Realized Pricing Natural Gas Takeaway & Realized Pricing (2)
Liquids Production – 2022 Guidance (MBbl/d) Percent Sold Out of Basin (2022E)
200 180 120%
100%
180 100%
100%
150 83%
80%
107 59% 58%
MBBL/D LIQUIDS 100 92 60% 47%
OF NATURAL GAS
PRODUCTION SOLD OUT OF BASIN
49 40%
(#1 AMONG PEERS) 50 (#1 AMONG PEERS)
20 20%
- 0%
AR RRC SWN EQT CNX AR RRC SWN EQT CNX
2021 C2+ NGL Price as % of WTI Price Differential to NYMEX – 2022 Guidance
60% 55% $0.35 $0.20
$0.20
50% $0.15
55% 50% 46% 46%
42% ($0.05)
NGL PRICE AS 40% ($0.25) PREMIUM GAS PRICE
PERCENT OF WTI ($0.45) DIFFERENTIAL
($0.38)
(#1 AMONG PEERS) 30% TO NYMEX
($0.65)
($0.63)($0.63) ($0.67)(#1 AMONG PEERS)
20% ($0.85)
Source: Company presentation and filings. AR CNX EQT RRC SWN AR RRC SWN EQT CNX
1) Liquids production includes C2+ NGLs and oil.
2) Based on company disclosure of firm transportation commitments. 18Structurally Higher Prices Ahead
Supportive Fundamentals
NYMEX Natural Gas Price and Gas Storage Surplus/Deficit vs. 5-year Avg.
1,000 Storage vs. Previous 5-Year Average Henry Hub Spot Price ($/MMBtu) $8.00
800 Storage surplus → Storage deficit → $7.00
Storage vs. 5-year Average (Bcf)
Gas price trades down Gas price trades up
Natural Gas Price ($/MMBtu)
600
$6.00
400
$5.00
200
0 $4.00
(200)
$3.00
(400)
$2.00
(600) 2022:
>$4.00/MMBtu $1.00
(800)
Historical natural gas price when storage is neutral with 5-year Avg of $2.50 - $3.25/MMBtu
(1,000) $0.00
“Maintenance Era”
“Shale Growth Era” - 2015 to 2019 2020 to-date
• Limited access to capital
• Abundant low cost capital
• Infrastructure constrained
• Excess Appalachia pipeline capacity
• Supply chain constrained
• Friendly regulatory environment
• Inventory exhaustion
• Vast inventory with new “shale” plays being discovered
Source: EIA • LNG in dramatic buildout
• LNG export capacity begins buildout 19
and ICEdata. • Focused on ESG initiativesWorking Gas in Storage
Supportive Fundamentals
2022 Working Gas in Storage Forecast (Bcf)
Remainder of 2022 Assumptions Implied Average Production BEGINNING TODAY
LNG Feedgas: 13.0 Bcf/d Required to Reach 3.5 Tcf Storage
4,250 4,250
Mexico Exports: 6.0 Bcf/d 97 Bcf/d (+3.5 Bcf/d from today)
4,000 Power Gen/Industrial (1): 54.0 Bcf/d 4,000
3,750 Total: 73.0 Bcf/d 3,750
3,500 3,500
3,250 3,250
3,000 3,000
2,800
2,750 2,750
2,500 2,500
2,250 2,250
2,000 Implied Storage 2,000
1,750
Holding today’s production at 1,750
93.5 Bcf/d flat
1,500 Current 1,500
Storage = 2.8 Tcf of refilled storage
1,250 1,450 1,250
1,000 1,000
750 750
500 500
1/7/2022
JAN 2/7/2022
FEB 3/7/2022
MAR 4/7/2022
APR 5/7/2022
MAY 6/7/2022
JUN 7/7/2022
JUL 8/7/2022
AUG 9/7/2022
SEP 10/7/2022
OCT 11/7/2022
NOV 12/7/2022
DEC
5 YR MAX-MIN Range Current 97 Bcf/d Production 5 YR AVE Production Held Flat
Note: Forecasted data takes historical average changes in storage for 2019 and 2021, adjusted by 2022 assumptions for LNG Feedgas and Mexico Exports. LNG Feedgas and Mexico
20
Exports based on Platts Global estimates for remainder of 2022.
1) Reflects average power generation and industrial demand during 2019 and 2021.Natural Gas Remains Essential in Energy Transition
Supportive Fundamentals
Natural gas and renewables displace coal and oil in the global energy
transition as demand increases for low carbon energy sources
U.S. Electricity Generation By Fuel Source Global Energy Demand Mix By Fuel Source
(Billion kilowatt-hours) (Exajoules) Coal Oil
Natural gas Nuclear
2020 Hydro Renewables
6,000 700
625
history projections 575
5,000 600
Natural gas
500
4,000
Natural gas
400
3,000 Renewables
300
2,000
200
Natural gas
1,000 Nuclear
100
Coal
0 0
2010 2020 2030 2040 2050 2018 2050E
Source: U.S. Energy Information Administration, Annual Energy Outlook 2021. Source: BP 2020 Energy Outlook. 2050E represents “Rapid Policy Scenario.”
Note: Exajoules refers to The International System unit of electrical, mechanical, and
thermal energy. 21NGL Price Strength
Supportive Fundamentals
Antero continues to benefit from the strength in NGL prices
AR Monthly Realized C3+ NGL Price
($/Bbl)
$120 WTI Price 100%
$67.02/Bbl
90%
$100 % of WTI
80%
CURRENT AR C3+ NGL
70%
$80 SPOT PRICE
60%
$60 50% 64%
40% OF WTI PRICE
$40
30%
20%
$20
AR C3+ Price 10%
$0 0%
Source: Bloomberg actuals through April 2022. Forecasted C3+ pricing based ICE pricing and on Antero C3+ NGL component barrel consisting of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4)
and 17% natural gasoline (C5+). Assumes blended sales of 50% domestic and 50% international. 22ESG Momentum Continues
ESG Leader
ESG Progress
Project Canary
2020 ESG Report (February 2022):
(October 2021): RECEIVED RESPONSIBLY SOURCED
REPORT IS EXPECTED TO DRIVE GAS CERTIFICATION
FURTHER RATINGS UPSIDE
MSCI UPGRADE
(August 2021):
BBB ESG RATING
Net Zero Scope 2 Emissions:
(February 2022)
World Bank Zero Routine EXPANDED GOALS TO INCLUDE NET
Flaring Initiative: ZERO SCOPE 2 EMISSIONS BY 2025
COMMITMENT TO NO ROUTINE
FLARING IN 2021 23Scope 1 Net Zero
ESG Leader
AR removed or converted ~6,000 pneumatic devices in 2021, a 76% reduction
Pneumatic Devices Replacement
9,000
8,000 76%
7,000 OF PNEUMATIC DEVICES
REPLACED TO DATE
6,000
5,000
4,000
3,000
2,000
1,000
-
Pneumatic Device Pneumatic Current Planned
Devices Removals Device Pneumatic Conversions/Removals
(2021) Conversions Devices (2022-2025)
(2021) (2022)
24Appalachia Responsible for CO2 Emission Reductions
ESG Leader
The natural gas supply growth from Appalachia has powered coal to gas switching,
driving declining CO2 emissions in the U.S. since 2005
U.S. CO2 Emissions (Billion Metric Tons) and Natural Gas Production (Bcf/d)
Appalachia Natural Gas Production (Bcf/d)
7.0 Rest of U.S. Gas Production (Bcf/d) 100.0
23%
CO2 Emissions (Billion Metric Tons)
90.0
6.0
Reduction
Natural Gas Production (Bcf/d)
80.0
Billion Metric Tons of CO2
5.0 70.0 IN U.S. CO2 EMISSIONS SINCE 2005
60.0
4.0
50.0
3.0 APPALACHIA RESPONSIBLE FOR
40.0
2.0 30.0 73% of Total
of U.S. Natural Gas Supply Growth
20.0
Since 2005
1.0
10.0
0.0 0.0
Source: U.S. Energy Information Administration 25AR’s Role in Supporting Global Energy Access
ESG Leader
In 2020, ~20 MBbl/d of AR’s LPG was shipped to developing countries
Antero LPG Cargo Destinations & Uses
Industrial &
Electricity Generation Recyclable food packaging
Manufacturing
Health Care Products &
Heating & Cooking Transportation
Protective Equipment 26Industry-Leader in ESG
ESG Leader
Wells Fargo ESG Scorecard - 2021
Environmental Social Governance
2nd of 27
WELLS FARGO
EQT 73.4
AR 71.4 ESG SCORECARD RANKING
RRC 71
FANG 66
CNX 65
CHK 64
SWN 64
SM 64
EOG 61
Top 5
CTRA 59
CDEV 58
DVN 57
PXD 52 RANKING IN RECENT RYSTAD
OAS 51
OVV 51 ENERGY ESG REPORT
MRO 51
LPI 49
CLR 56
PDCE 48
WLL 47
MTDR 46
CPE 46
MGY 43
BRY 42
ESTE 37
CIVI 32
NOG 27
0 20 40 60 80
Source: Wells Fargo Securities LLC. 27Antero Investment Highlights
BALANCE SHEET STRENGTH
AND FLEXIBILITY
SCALE & DIVERSIFIED PRODUCT MIX
DIRECT EXPOSURE TO RISING
GLOBAL DEMAND
SUSTAINABLE BUSINESS MODEL
INDUSTRY-LEADING ESG METRICS
28Appendix
2022 Capital Plan and Guidance
2022 Guidance Ranges
Net Production (Bcfe/d) 3.2 – 3.3
Net Natural Gas Production (Bcf/d) 2.2 – 2.25
Net Liquids Production (Bbl/d) 175,000 – 185,000
Natural Gas Realized Price Expected Premium to
$0.15 to $0.25
NYMEX ($/Mcf)
C3+ NGL Realized Price - Expected Premium to Mont
$0.00 - $0.00
Belvieu($/Gal) (1)
Oil Realized Price Expected Differential to WTI ($/Bbl) ($7.00) – ($9.00)
Cash Production Expense ($/Mcfe) (2) $2.25 – $2.35
Net Marketing Expense ($/Mcfe) $0.06 – $0.08
G&A Expense ($/Mcfe)
$0.10 – $0.12
(before equity-based compensation)
D&C Capital Expenditures ($MM) $675 - $700
Land Capital Expenditures ($MM) $65 - $75
Average Operated Rigs, Average Completion Crews Rigs: 3 | Completion Crews: 2
Operated Wells Completed Wells Completed: 60 - 65
Operated Wells Drilled Wells Drilled: 70 - 80
Average Lateral Lengths, Completed Completed: 13,800
Average Lateral Lengths, Drilled Drilled: 13,600
1) Based on Antero C3+ NGL component barrel which consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+).
2) Includes lease operating expenses, gathering, compression, processing and transportation expenses (“GP&T”) and production and ad valorem taxes. 30Antero Guidance and Long-Term Target Assumptions
Long-term Outlook Assumptions 2022 2022-2026
NYMEX Henry Hub Natural Gas Price ($/MMBtu) (1) $6.40 $4.65
NYMEX WTI Oil Price ($/Bbl) (1) $99.00 $80.50
AR Weighted C3+ NGL Price ($/Bbl) (1) $62.00 $46.50
AR 29% ownership in AM (shares) and annual AM dividend per share (2) 139 MM shares ($0.90/share annual dividend)
Current Plan (Maintenance Capital) Assumptions: 2022 2022-2026
Annual Net Production (Bcfe/d) – Net to AR 3.2 – 3.3 3.3 – 3.5
Wells Drilled – Net to AR 70 – 80 300 – 340
Wells Completed – Net to AR 60 – 65 280 – 320
Wells Drilled (Gross to AR/QL) 80 – 90 340 – 380
Wells Completed (Gross to AR/QL) 75 – 80 320 – 360
Cash Production & Net Marketing Expense ($/Mcfe) (3) – Net to AR $2.31 - $2.43 $2.25 – $2.35 (4)
G&A Expense (before equity-based compensation) ($/Mcfe) – Net to AR $0.10 - $0.12
D&C Capital ($MM) $675 - $700 $3,275 - $3,500
1) Represents approximate strip pricing as of 04/26/2022 assuming C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17%
natural gasoline (C5+).
2) AM dividend determined quarterly by the Board of Directors of Antero Midstream.
3) Includes lease operating expense, gathering, compression, processing, transportation, production & ad valorem taxes and net marketing expense. Excludes cash G&A.
4) Represents average cash production and net marketing expense for 2022 – 2026. 312022 Activity Summary
Well Completions
~65% of well
60-65 Net Wells Completed 50 completions in 2H 2022
45
40
35
13,800’ Average Lateral 30
25
20
15
1255 Average BTU 10
5
0
1H 2022 2H 2022
Production (Bcfe/d)
3.5
3.2 – 3.3 Bcfe/d 3.4
3.4
Average Production
3.3
4%-5% Exit-to-Exit Production 3.2
3.2
Growth (4Q21/4Q20) 3.3
3.1
3.1
3.0
1H 2022 2H 2022
32Natural Gas and NGLs Are Essential
Antero plays a critical role in producing reliable energy for consumers
5 Largest U.S. 2
Largest U.S.
Natural Gas
NGL Producer
Producer
Natural Gas Natural Gas Liquids (NGLs)
Natural gas is a low-cost, low-emission NGLs play an essential role in the domestic and
hydrocarbon based fuel that can reduce GHG international industrial, residential, commercial
emissions by more than half, as compared to coal and transportation industries
Electricity Generation Transportation
Heating & Cooking Recyclable food packaging
Health Care Products &
Industrial & Manufacturing Protective Equipment
Source: Natural gas and NGL rankings based on 3Q21 reported production. 33Significant Commodity Price Leverage
As one of the largest natural gas and NGL producers in the U.S., Antero has
significant cash flow upside in a rising commodity price environment
Top 5 U.S. Natural Gas Producers (MMcf/d) Top 5 U.S. NGL Producers (MBbls/d)
6,000 250
5th largest U.S. Natural 217
2nd largest NGL
5,000 4,784 Gas producer
200 producer
158
4,000 145 143
150 142
MMcf/d
47
3,000 2,781 2,746 Ethane
2,496
2,263
100 111
2,000
C3+
50 NGLs
1,000
- -
EQT SWN XOM CTRA AR OXY AR EOG PXD COP
AR Leverage to Natural Gas Prices ($MM) (1) AR Leverage to C3+ NGL Prices ($MM) (2)
$450 $450
$407 $407
Every $0.10 per Every $2 per Bbl move
$400 $400
MMBtu move in natural in C3+ NGL prices results
$350 gas prices results in an $326 $350 $326
in a $81 MM unhedged
$300 $81 MM unhedged $300 annual revenue impact (2)
annual revenue impact (1) $244 $244
$250 $250
$200 $200
$163 $163
$150 $150
$100 $81 $100 $81
$50 $50
$0 $0
+$0.10 / +$0.20 / +$0.30 / +$0.40 / +$0.50 / +$2.00 / +$4.00 / +$6.00 / +$8.00 / +$10.00 /
MMBtu MMBtu MMBtu MMBtu MMBtu Bbl Bbl Bbl Bbl Bbl
Note: Natural gas and NGL producer rankings reflect company 2021 reports and public filings.
34
1) Assumes 2021 natural gas production of 2.3 Bcf/d. 1.2 Bcf/d of AR natural gas volumes are hedged in 2023 at a weighted average price of $2.50/MMBtu.
2) Assumes 2021 C3+ NGL production of 158 MBbl/d.FT Protects Basis and Provides Flow Assurance
AR’s firm transportation portfolio provides price stability, production flow
assurance, and premium pricing vs. Appalachia-dependent producers
Antero Basis vs. Appalachia Basis ($/Mcf)
(1) (2)
Appalachia Differentials Antero Realized Differential
Appalchian Average Basis Antero Average Basis
AR’s 1Q22 realized price was an $0.06/Mcf
$2.00
Since the beginning of 2018, AR had premium to NYMEX vs. an average
Appalachian discount of ($0.87)/Mcf
Antero Basis
access to its entire FT portfolio and
has realized an average $0.12/Mcf
$1.50 premium to NYMEX over that time
• Low volatility, high
reliability
$1.00
• Premium to NYMEX
+$0.12 AR • “Insurance policy” for
1Q22: consistent production
$0.50 +$0.06 flow
• Ability to hedge NYMEX
$0.00 Henry Hub index
Appalachia
($0.50) 1Q22:
($0.83) ($0.87) Appalachia Basis
($1.00)
• High volatility, low
reliability
($1.50) • Significant discount to
NYMEX
($2.00) • Frequent shut-ins
• Less liquid hedge
markets
Note: Pricing reflects pre-hedge pricing.
1)
2)
Reflects discount to NYMEX for Appalachia in-basin pricing at Dominion South & TETCO M2 indices.
Represents simple average discount to NYMEX for Antero firm transportation capacity. Includes BTU adjustment for 1100 BTU gas. 35Strategy Transition For Commodity Price Exposure
AR’s significant scale, strong balance sheet, commodity product diversity and
development program flexibility allows AR to capture commodity price upside
AR Hedges as a % of Guided Production at January 1 of Each Year
100%
80%
60%
40%
20%
0%
2014 2015 2016 2017 2018 2019 2020 2021 2022E 2023E
Prudent Hedging Strategy Prudent Exposure Strategy
• Single commodity product (dry gas only) • Diversity of product (NGLs & Oil)
• Growth mode to achieve scale • Maintenance capital mode to harvest free
• Unutilized FT and less flexible capital cash flow
budget • Utilized FT and flexible capital budget to
• Northeast basis exposure & shut-in risk commodity prices
• Near-term maturities • NYMEX exposure & flow assurance
• Contango futures prices • Pushed out maturities 4+ years
• Backwardated futures prices
Note: Percent of production hedged assumes 2021 production guidance and maintenance mode, or flat
production thereafter. • Bullish supply / demand fundamentals 36Natural Gas Liquids Primer
NGLs play an essential role in the domestic and international industrial, residential,
commercial and transportation industries
Gas Linked Pricing Crude Linked Pricing
Iso-
Methane Ethane Propane Butane Butane Pentane
Natural Gas C2 C3 C4 IC4 C5
Industrial
Primary Chemical Residential Industrial
All Industrial Transportation
Sectors Industrial Commercial, Transportation
Chemical
Heating,
Ethylene Winter Alkylate feed
Primary Crop drying, Gasoline blend
Power Production Gasoline to produce
Uses Commercial, and diluent
(For plastics) Blending gasoline
Propylene
Higher Heating Value
1000 BTU 4000 BTU
37Premium NGL Price Realizations
Producer Disadvantaged: Producer Advantaged & Unconstrained:
E&Ps in Permian, Rockies, Mid-Con & Bakken Antero Resources in Appalachia
AR is the largest C3+ producer
with the most international
exposure in Appalachia
Mariner East Anchor shipper on ME2
FROM ROCKIES Conway Who Captures the Arb at Marcus Hook?
Answer: AR and other Appalachian E&P’s
• Direct sales to most attractive international
(ARA & FEI) & domestic markets
• Fixed terminal rates
• Local fractionation & marketing to sell purity
products in-basin for local demand
Results in “Mont Belvieu plus” pricing
netbacks captured “at the dock” by AR
Mont
Belvieu Who Captures the Arb at the Gulf Coast?
Answer: Midstream & LPG off-takers (not E&P’s)
• No direct E&P access to international markets (i.e.
producers only receive Mont Belvieu linked pricing)
• No local fractionation to sell marketable purity
products in-basin
Results in “Mont Belvieu Minus” pricing
“before the dock”
38Antero Non-GAAP Measures
Adjusted EBITDAX: Adjusted EBITDAX as defined by the Company represents income or loss, including noncontrolling interests, before interest
expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on
derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairment, depletion,
depreciation, amortization, and accretion, exploration expense, equity-based compensation, contract termination and rig stacking costs, simplification
transaction fees, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions received with respect to limited partner interests in
Antero Midstream Partners common units prior to the closing of the simplification transaction on March 12, 2019.
The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero’s
condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management
believes that this measure is useful to an investor in evaluating the Company’s financial performance because it:
• is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the
calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of
assets, capital structure, and the method by which assets were acquired, among other factors;
• helps investors to more meaningfully evaluate and compare the results of Antero’s operations from period to period by removing the effect of its
capital and legal structure from its consolidated operating structure; and
• is used by management for various purposes, including as a measure of Antero’s operating performance, in presentations to the Company’s
board of directors, and as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by the board of directors as a
performance measure in determining executive compensation.
There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain
recurring and non-recurring items that materially affect the Company’s net income or loss, the lack of comparability of results of operations of different
companies, and the different methods of calculating Adjusted EBITDAX reported by different companies. In addition, Adjusted EBITDAX provides no
information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.
Net Debt: Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate its financial position, including
its ability to service its debt obligations.
Leverage: Leverage is calculated as LTM Adjusted EBITDAX divided by net debt.
39Antero Non-GAAP Measures
Free Cash Flow:
Free Cash Flow is a measure of financial performance not calculated under GAAP and should not be considered in isolation or as a substitute for cash
flow from operating, investing, or financing activities, as an indicator of cash flow, or as a measure of liquidity. The Company defines Free Cash Flow
as Net Cash Provided by Operating Activities, less drilling and completion capital and leasehold capital plus earnout payments.
The Company has not provided projected Net Cash Provided by Operating Activities or a reconciliation of Free Cash Flow to projected Net Cash
Provided by Operating Activities, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project Net
Cash Provided by Operating Activities for any future period because this metric includes the impact of changes in operating assets and liabilities related
to the timing of cash receipts and disbursements that may not relate to the period in which the operating activities occurred. The Company is unable to
project these timing differences with any reasonable degree of accuracy without unreasonable efforts. See assumptions slide for more information
regarding key assumptions.
Free Cash Flow is a useful indicator of the Company’s ability to internally fund its activities and to service or incur additional debt. There are significant
limitations to using Free Cash Flow as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring
items that materially affect the Company’s net income, the lack of comparability of results of operations of different companies and the different methods
of calculating Free Cash Flow reported by different companies. Free Cash Flow does not represent funds available for discretionary use because those
funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration
expenses, and other commitments and obligations.
40Antero Resources Adjusted EBITDAX Reconciliation
Twelve
Months Ended
Year ended
“Then” December 31, “Now” March 31,
2014 2022
Reconciliation of net loss to Adjusted EBITDAX: Reconciliation of net loss to Adjusted EBITDAX:
Net income (loss) from continuing operations $ 673,625 Net loss and comprehensive loss attributable to Antero Resources Corporation $ (327,819)
Commodity derivative fair value gains losses (868,201) Net income and comprehensive income attributable to noncontrolling interests 10,118
Net cash receipts on settled derivative instruments 135,784 Unrealized commodity derivative losses 1,291,456
Gain on sale of assets (40,000) Payments for derivative monetizations 4,569
Interest expense 160,051
Amortization of deferred revenue, VPP (43,358)
Loss on early extinguishment of debt 20,386
Income tax expense
Gain on sale of assets (446)
445,672
Depreciation, depletion, amortization, and accretion 479,167 Interest expense, net 176,838
Impairment of unproved properties 15,198 Loss on early extinguishment of debt 60,641
Exploration expense 27,893 Loss on convertible note equitizations 11,731
Equity-based compensation expense 112,252 Income tax benefit (124,223)
State franchise taxes. 2,188 Depletion, depreciation, amortization, and accretion 721,847
Less:
Impairment of oil and gas properties 78,923
Net income attributable to non-controlling interests 2,248
Exploration expense 7,245
Consolidated Adjusted EBITDAX from continuing
operations 1,161,767 Equity-based compensation expense 19,444
Less: Equity in earnings of unconsolidated affiliate (83,569)
Net income from discontinued operations 2,210 Dividends from unconsolidated affiliate 125,138
Gain on sale of assets (3,564) Contract termination and rig stacking 4,222
Income tax expense 1,354 Transaction expense and other 1,044
Total Adjusted EBITDAX 1,161,767 1,933,801
Martica related adjustments (1) (129,107)
Adjusted EBITDAX $ 1,804,694
41Free Cash Flow Reconciliation
“Then”
Year Ended
December 31,
2014
Net cash provided by operating activities $ 998,121
Less: Net cash used in investing activities (4,089,650)
Free Cash Flow (3,091,529)
Changes in Working Capital 17,805
Free Cash Flow before Changes in Working Capital $ (3,073,724)
42Total Debt to Net Debt Reconciliation
“Then” “Now”
December 31, March 31,
2014 2022
Credit Facility $ 1,730,000 387,700
7.250% senior notes due 2019 —
6.000% senior notes due 2020 525,000
5.375% senior notes due 2021 1,000,000
5.125% senior notes due 2022 1,100,000
5.000% senior notes due 2025 — —
8.375% senior notes due 2026 — 325,000
7.625% senior notes due 2029 — 584,000
5.375% senior notes due 2030 — 600,000
4.250% convertible senior notes due 2026 — 81,570
Unamortized premium, net 7,550 —
Unamortized debt issuance costs — (18,326)
Total debt $ 4,362,550 1,959,944
Less: Cash and cash equivalents 245,979 —
Net Debt $ 4,116,571 1,959,944
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