Company Presentation
May 2020
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 Antero 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, Adjusted EBITDAX, leverage targets, 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, including with respect to potential incremental flowback and produced water services by AM, future financial position, the amount and timing of any litigation settlements or awards, future technical improvements, and future marketing and asset monetization opportunities, 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.
AR cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and 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 world health events, including the COVID-19 pandemic, potential shut- ins of production due to lack of downstream demand or storage capacity, 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, 2019 and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020.
This presentation includes certain financial measures that are not calculated in accordance with U.S. generally accepted accounting principles ("GAAP"). These measures include (i) Adjusted EBITDAX, (ii) Net Debt, (iii) PUD F&D cost (iv) leverage (v) unhedged recycle ratio and (vi) free cash flow. Please see "Antero Definitions" and "Antero Non-GAAP Measures" for the definition of each of these measures as well as certain additional information regarding these measures, including the most comparable financial measures calculated in accordance with GAAP.
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
Corporate Presentation
- Natural Gas & NGL Macro
- Detailed Asset Overview
- Appendix
3
Antero Family at a Glance
50/50 JV | |||||
Exploration & | Gathering & | Natural Gas | C3+ NGL | ||
Production | Compression | Processing | Fractionation | ||
Water Delivery
& Blending
4
Antero Resources at a Glance
Denver, CO
Antero Resources Acreage Map
HEADQUARTERS | |||||||||
Antero Marcellus Rig | |||||||||
S&P 400 | Industry Marcellus Rig | ||||||||
Industry Utica Rig | |||||||||
Antero Acreage | |||||||||
CONSTITUENT | SW Marcellus Core | ||||||||
5th Largest | Ohio Utica Core | ||||||||
U.S. GAS PRODUCER(1) | |||||||||
2nd Largest | |||||||||
U.S. NGL PRODUCER(1) | |||||||||
Own 40% | |||||||||
OF CORE LIQUIDS-RICH DRILLING | |||||||||
LOCATIONS IN APPALACHIA(2) | |||||||||
1,200 | |||||||||
ADDITIONAL DRY GAS LOCATIONS | |||||||||
IN DRILLING INVENTORY(2) | |||||||||
~97% Hedged | Undrilled Locations(2) | ||||||||
Core Liquids-Rich Appalachian | |||||||||
ON NATURAL GAS THROUGH 2021 | |||||||||
@ $2.83/MMBtu (3) | |||||||||
100% Hedged | |||||||||
) | AR | Peers | |||||||
~40% | ~60% | ||||||||
ON OIL AND PENTANES THROUGH | |||||||||
2020 @ $55.63/bBL (4) | |||||||||
Note: Hedge position as of 4/24/20. Rigs on map as of 4/24/20,) per Rig data. | |||||||||
3) Percentage hedged represents percent of expected natural gas production hedged based on | |||||||||
1) NGLs based on 2020E consensus as of 5/1/20. Natural gas based on 1Q20 reported production. | |||||||||
natural gas production guidance of 2.375 Bcf/d in 2020 and flat production in 2021. | 5 | ||||||||
2) AR drilling inventory as of 3/31/2020. Industry locations based on Antero analysis of undeveloped acreage in the | |||||||||
4) Percentage of oil and pentanes hedges represents percent of expected oil and pentane | |||||||||
core of the Marcellus and Ohio Utica Shales. | |||||||||
production based on 2020 guidance. | |||||||||
Antero Resources Snapshot
Lowered 2020 Capital Budget to $750 MM
- D&C capital target of $750 million in 2020, a 35% decrease from initial 2020 guidance and a 41% decrease from 2019 spending
- Maintaining 2020production growth guidance of 9%, while forecasting ~$175 million of free cash flow (1)
Targeting Asset Sales of $750 MM to $1 B through 2020
- Asset monetization alternatives include lease acreage, minerals, VPP, producing properties, hedge restructuring or additional sales of AM shares to Antero Midstream
- First $100 million asset sale executed (AM share sale to AM Dec. 2019)
Reduced Cost Structure
- 26% well cost reduction to $715/lateral foot in 2020 through efficiency improvement, water initiatives and service cost deflation
- Total of ~$600 million in capital and operating cost savings expected in 2020 relative to 2019 initial budget
Repurchased Bonds at a Steep Discount
- Have bought back ~$608 million of 2020 and 2021 bonds at a ~20% discount eliminating ~$120 million of debt (2)
- Borrowing base reset at $2.85 billion with $2.64 billion of lender commitments unchanged
D&C Capital Spending ($MM)
$1,600 | $1,490 | ||||||||
$1,400 | |||||||||
$1,270 | |||||||||
$1,200 | $1,150 | ||||||||
$1,000 | |||||||||
$750 | |||||||||
$800 | |||||||||
$600 | |||||||||
$400 | |||||||||
$200 | |||||||||
$0 | |||||||||
2018A | 2019A | 2020 | 2020 | ||||||
Initial Budget | Revised | ||||||||
Budget |
Marcellus Well Cost ($/Lateral Foot)
$1,200 | |
$1,000 | $970 |
$800 | $810 |
$715 |
$600
$400
$200
$0
Jan-19 | Initial | Revised |
Budget | 2020 AFE | 2020 AFE |
Note: See appendix for more information regarding certain underlying assumptions. | 6 |
1) | Based on strip pricing as of 4/24/2020. See appendix for free cash flow definition. |
2) | As of 3/31/2020. |
Strategy Aligned with Industry Risks & Reality
Energy Industry Realities | Commodity Price Risk | |
Commodity
prices are
cyclical
Energy is a
capital
intensive business
- AR is ~97% hedged on natural gas through 2021 at prices 31% above current strip pricing (1)
- AR firm transport substantially reduces basis risk
- Drive leverage lower & improve financial flexibility
Capital Intensity
- Develop highest rate of return locations across asset portfolio while living within cash flow
- Ongoing capital efficiency initiatives drive down capital and operating costs and improve capital efficiency
Planning & Execution
Long-term | Integrated upstream and midstream planning |
planning & | process to generate synergies, maximize |
execution | utilization and minimize operational downtime |
are critical | | Stress test commodity prices and evaluate | |
multiple development plan scenarios | |||
Base compensation on plan execution and ESG | |||
performance | 7 | ||
1) Strip pricing as of 4/24/20. Percentage hedged represents percent of expected natural gas production hedged based on natural gas production guidance of 2.375 Bcf/d in 2020 and flat production in 2021. |
Antero is a Leader in Sustainability and ESG Metrics
GHG Emissions | Water Management |
- Antero has zero flaring of produced gas, one of the lowest GHG intensity metrics in the industry (upstream independents and majors) and a very low methane leak loss rate:
Total Direct GHG Emissions and Intensity (CO2e) | Methane Leak Loss Rate | ||||
Thousand Metric Tons | Tons/MBOE | ||||
3.9 | 1% |
506 |
2.7 | 0.28% | |||
2.3 | 0.10% | 0.06% | 0.05% | |
428 | ||||
423 | ||||
OF | Upstream 2018 OF AR 2018 AR 2019 | ||||
2017 | 2018 | 2019 | Industry | Sector | Upstream |
Target | Target | Sector | |||
2025 | Avg. |
2019 Antero vs 2018 Industry GHG Emission Intensity(1)
*
40 | ||||
35 | ||||
e Tons/MBOE | 30 | |||
25 | ||||
20 | ||||
15 | ||||
2 | ||||
CO | ||||
10 | ||||
5 | ||||
0 | I J* K L* | M N* O P Q* | * | |
AR A B C AR D* E F* G H* | R | |||
+ | * | |||
AM* | ||||
- Fresh water pipeline network eliminated 570,000 water truck trips in 2019
- AR recycles and reuses over 90% of flowback and produced water (~50,000 Bbl/d currently)
Safety
- Lost Time Incident Rate in 2018 outperformed the industry benchmark by 75%
- Total Recordable Incident Rate in 2018 outperformed the industry benchmark by 52%
Governance
- Have established ESG Committee on AR and AM Boards for ESG oversight
- Both AR and AM are C-corps and have a majority of independent directors
- Management compensation is tied to free cash flow (AR), ROIC (AM) and safety and environmental performance
For more information, please visit:https://www.anteroresources.com/community-sustainability; OF stands for ONE Future
Source: Data retrieved from 2018 and 2019 sustainability reports or calculated from 2018 sustainability and public disclosures. Antero Resources' intensity is based on the total GHG emissions reported to the EPA under Subpart
W of the Greenhouse Gas Reporting Rule Program (GHGRP). Previous years have been updated as of 4/2020. | |
*Company's GHG intensity includes their midstream and/or downstream operations. | 8 |
1) Comparisons for independents and majors who report include: BP, CHK, CNX, COP, CVX, DVN, ENI, EOG, EQNR, FANG, HES, MPC, NBL, RRC, RDS, SWN and XEC. |
Corporate Presentation
- Antero Resources Executive Overview
- Detailed Asset Overview
- Appendix
9
Natural Gas and NGL Macro Momentum
- Natural gas and NGL prices should strengthen over the coming quarters as global demand remains resilient while supply declines materially (assuming current oil price strip)
- For oil and the resulting transportation fuels, some of the demand destruction from the pandemic may be permanent while supply is abundant
U.S. Natural Gas | U.S. NGLs | ||||||
Supply | Supply | ||||||
• Near-term potential 6 to 7 Bcf/d decrease due | • | U.S. NGL production is projected to decline by 125 | |||||
to oil shut-ins | MBbl/d through 2022, driven by reduced drilling | ||||||
• | Longer-term 5.5 Bcf/d reduction by YE 2020 and | activity in oil shale basins | |||||
8.5 Bcf/d aggregate reduction by YE 2021 due to | • | International NGL production "associated" with OPEC | |||||
decline in associated gas (Permian, Eagle Ford, | oil production decreasing due to OPEC+ supply cut | ||||||
SCOOP/STACK) | • | Lower global refinery utilization results in a decline | |||||
• | Flat production from gas producers who will stick | in NGL supply as a byproduct of refining | |||||
to capital discipline | Demand | ||||||
Demand | • | ||||||
• Near and medium-term 3 to 4 Bcf/d decline due to | Resilient domestic and international demand from | ||||||
petrochem and residential/commercial sectors | |||||||
pandemic | |||||||
• | Rising living standards in developing countries, | ||||||
• 2 to 3 Bcf/d reduction in LNG exports over summer | particularly in Asia, create an inelastic demand pull | ||||||
of 2020 due to cargo cancellations | for LPG and NGL derivative products | ||||||
• Asian economies are beginning to recover from | |||||||
Covid-19 pandemic and Chinese tariffs on LPG were | |||||||
lifted in early 2020 | |||||||
Outlook for Natural Gas | Outlook for NGLs | ||||||
• Significant U.S. associated gas production decline | • | The impact of a decline in oil shale activity on | |||||
with limited medium-term demand destruction | "associated NGL" production is expected to be even | ||||||
more pronounced than the impact on associated gas | |||||||
production while global NGL demand remains stable | |||||||
• Increasing U.S. export capacity expected to tighten | |||||||
Mont Belvieu pricing to international pricing | |||||||
10 | |||||||
Sources: April EIA Short Term Energy Outlook and S&P Global Platts estimates. LPG is comprised of NGL components propane and butane. |
Significant Reduction in Drilling Rigs
- Since March 6th, the total U.S. rig count has declined by 441 rigs, or ~58%
- NGL production "associated" with oil shale activity represents 66% of total U.S. NGL production and is expected to decline due to the recent collapse in oil prices and rig count
U.S. Oil & Gas Drilling Rig Count Since 3/6/2020
Current Dry | Current | |||||||
Change Since 3/6/20 | Gas Production | NGL Production | ||||||
3/6/2020 | 5/15/2020 | Rigs | % | Bcf/d (1) | MBbls/d (2) | |||
Oil Focused | 66% of U.S. | |||||||
Permian | 429 | 195 | (234) | (55%) | 10.9 | 25% of U.S. | 1,835 | |
Eagle Ford | 79 | 23 | (56) | (71%) | 4.9 | dry gas | 679 | NGL |
Bakken | 52 | 17 | (35) | (67%) | 1.5 | production | 502 | production |
SCOOP/STACK | 41 | 11 | (30) | (73%) | 3.0 | 376 | ||
DJ Niobrara | 28 | 7 | (21) | (75%) | 2.1 | 457 | ||
Total | 629 | 253 | (376) | (60%) | 22.3 | 3,848 | ||
Natural Gas Focused | ||||||||
Marcellus | 32 | 24 | (8) | (25%) | 25.4 | 807 | ||
Haynesville | 41 | 32 | (9) | (22%) | 12.9 | 51% of U.S. dry | 43 | 17% of U.S. |
Utica | 14 | 14 | - | 0% | 6.2 | 121 | ||
gas production | NGL production | |||||||
Total | 87 | 70 | (17) | (20%) | 44.5 | 970 | ||
Other | 50 | 2 | (48) | (96%) | 21.1 | 1,027 | ||
Total U.S. | 766 | 325 | (441) | (58%) | 87.9 | 5,846 |
Rig reduction led by oil focused
areas with a 376 rig, or 60% reduction since March 6th
Source: Baker Hughes and S&P Global Platts.
1) Current dry gas production per Platts as of 5/18/2020. Other production represents Platts' "Other US Production" + offshore production.11
2) NGL production per Platts monthly average C2+ NGL estimate for April 2020 as of 5/6/2020. Assumes ~2.7 MMBbl/d of ethane, or 46% of total C2+ NGL forecast.
Significant Reduction in Completion Crews
Since March 6th, total oil and natural gas completion
crews have declined by 258, or 81%
U.S. Oil & Gas Drilling Completion Crew Count Since 3/6/2020
Change Since 3/6/20 | Current Dry | Current | ||||||
Completion | Gas Production | NGL Production | ||||||
3/6/2020 5/15/2020 | Crews | % | Bcf/d (1) | MBbls/d (2) | ||||
Oil Focused | ||||||||
Permian | 125 | 28 | (97) | (78%) | 10.9 | 25% of U.S. | 1,835 | 66% of U.S. |
Eagle Ford | 44 | 1 | (43) | (98%) | 4.9 | 679 | ||
dry gas | NGL | |||||||
Bakken | 31 | 1 | (30) | (97%) | 1.5 | 502 | ||
production | production | |||||||
SCOOP/STACK | 28 | 1 | (27) | (96%) | 3.0 | 376 | ||
DJ Niobrara | 19 | - | (19) | (100%) | 2.1 | 457 | ||
Total | 247 | 31 | (216) | (87%) | 22.3 | 3,848 | ||
Natural Gas Focused | ||||||||
Appalachia | 26 | 24 | (2) | (8%) | 31.6 | 928 | ||
Haynesville | 18 | 1 | (17) | (94%) | 12.9 | 51% of U.S. dry | 43 | 17% of U.S. |
Total | 44 | 25 | (19) | (43%) | 44.5 | gas production | 970 | NGL production |
Other | 26 | 3 | (23) | (88%) | 21.1 | 1,027 | ||
Total U.S. | 317 | 59 | (258) | (81%) | 87.9 | 5,846 |
Completion crew reduction led by oil focused areas with a 216, or 87% crew reduction since March 6th
NGL production "associated" with oil shale activity represents 66% of total U.S. NGL production and is expected to decline due to the recent collapse in oil prices and rig count
Source: Primary Vision and S&P Global Platts. Appalachia completion crew count based on Antero internal estimate to address discrepancies in Primary Vision data for Appalachia. | ||
1) | Current dry gas production represents Platts production as of 5/18/2020. Other production represents Platts' "Other US Production" + offshore production. | 12 |
2) | NGL production represents Platts monthly average C2+ NGL estimate for April 2020. Estimate as of 5/6/2020. Assumes ~2.7 MMBbl/d of ethane, or 46% of total C2+ NGL forecast. |
Material Impact to NGL Production in the U.S.
The oil price decline is expected to have an even more pronounced impact on NGL
supply where two-thirds of the supply comes from oil shale plays
U.S. NGL Production Forecast (MBbl/d) | LPG Export Capacity | |
7,000 | Jan-20 Forecast | May-20 Forecast | 2,500 |
Expected oil shale shut-ins | |||
6,500 | in mid-2020 incorporated | 2,000 | |
with latest forecast | |||
6,000 | 1,500 | ||
1 | |||
MMBbl/d | |||
5,500 | Decrease | 1,000 | |
5,000 | 500 | ||
4,500 | 0 |
Note: Represents Platts Analytics data as of May 6, 2020.
Gulf Coast export capacity is now plentiful, |
which should tighten Mont Belvieu LPG |
pricing to international pricing |
Gulf Coast Export Capacity |
Gulf Coast Propane Exports |
Gulf Coast Butane Exports |
13 |
NGL Price Recovery Expected
Domestic and international LPG prices are improving on a relative basis to crude
oil, driven by inelastic global demand from petrochemicals and res/comm
Mont Belvieu C3+ NGL Prices & % of WTI (1) | FEI Propane Prices & % of Brent |
($/Bbl) | % of WTI | MB C3+ NGL ($/Bbl) | ($/Bbl) | % of Brent | FEI Propane ($/Bbl) | |||||
$35 | Historical % of WTI Avg. | 100% | $35 | FEI Propane Price | ||||||
82% | as % of Brent | |||||||||
90% | C3+ Price as | |||||||||
90% | ||||||||||
$30 | % of WTI | $30 | ||||||||
73% | 72% | |||||||||
80% | ||||||||||
Historical | 75% | |||||||||
64% | ||||||||||
$25 | 5-year avg: | 69% | $25 | |||||||
70% | ||||||||||
~60% | ||||||||||
$20 | 60% | $20 | FEI Propane Price | |||||||
48% | 50% | |||||||||
$15 | 40% | $15 | ||||||||
C3+ NGL Price | ||||||||||
$10 | 30% | $10 | ||||||||
20% | ||||||||||
$5 | 10% | $5 | ||||||||
$0 | 0% | $0 | ||||||||
1Q20A | 2Q20E | 3Q20E | 4Q20E | |||||||
1Q20A | 2Q20E | 3Q20E | 4Q20E | |||||||
90%
80%
70%
60%
50%
40%
30%
20%
10%
0%
Source: ICEdata Mont Belvieu strip pricing as of 5/15/2020 | 14 |
1) Based on Antero C3+ NGL component barrel consists of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+). |
The Impact of the U.S. Shale Revolution
The Shale Revolution dramatically changed the NGL landscape, turning the U.S. into
a net exporterafter decades of importingNGL products
U.S. NGL Production (MBbl/d) (1) | U.S. NGL Exports / (Imports) (MBbl/d) |
6,000 | 2,500 | ||||||||||||
5,000 | 2,000 | ||||||||||||
Driven primarily by oil | |||||||||||||
shale development | |||||||||||||
4,000 | with high oil prices | 1,500 | |||||||||||
MBbl/d | MBbl/d | ||||||||||||
3,000 | 1,000 | ||||||||||||
Pentane | Net importerof NGLs | ||||||||||||
2,000 | 500 | ||||||||||||
IsoButane | |||||||||||||
1,000 | Butane | - | |||||||||||
Propane | |||||||||||||
Ethane(1) | |||||||||||||
0 | (500) | ||||||||||||
1984 | 1990 | 1996 | 2002 | 2008 | 2014 | 2020 | 1984 | 1990 | 1996 | 2002 | 2008 | 2014 | 2020 |
1) | Includes recovered ethane volumes and natural gasoline (C5). | 15 |
Source: U.S. Energy Information Administration. 2020 represents year-to-date data through March 1, 2020. NGL exports/imports includes ethane, propane, normal butane, isobutane and natural gasoline. |
LPG Exports
US exports surpassed the entire Middle East region combined in 2019
LPG Exports: US versus Middle East
MBbl/d
1400
1200
1000
800
600
400
200
0
US is the incremental
supplier for growing world
demand.
Supply from Middle East nations flat,
OPEC policies limit growth potential
US | Qatar | UAE | Saudi Arabia | Algeria | Kuwait | Iran | |||||||||||||||||
2010 | 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | ||||||||||||||
Source: Platts. | 16 |
Notes: Propane and Butane exports only based on cFlow ship tracking data. US Exports do not include exports via land to Canada and Mexico 2020 represents year-to-date data through March 1, 2020. | |
Future U.S. NGL Supply Challenged by Oil Price Decline
- U.S. shale plays were previously forecast (December 2019) to grow C3+ NGL supply through 2022 by almost 500,000 Bbl/d
- Now, with a $30 to $40/Bbl oil strip, U.S. C3+ NGL supply is expected to decline by 125,000 Bbl/d through 2022
Bakken Supply | Forecasted Growth 2019-2022 (MBbl/d) | Current |
Estimate | ||
1,500 | 12/31/19 | |||||||
1,000 | ||||||||
12/31/19 | BAKKEN/ | Estimate | ||||||
500 | +31% | WILLISTON | 12/31/19 | |||||
0 | +73 MBbl/d | Current | SCOOP/STACK | (6%) | ||||
2019 | 2022 | +17% | (24) MBbl/d | |||||
1,500 | Supply | |||||||
+40 MBbl/d | ||||||||
1,000 | Current | |||||||
Rockies Supply | 12/31/19 | Current | 500 | (7%) | ||||
1,500 | (31) MBbl/d | |||||||
+17% | (25%) | 0 | NORTHEAST | |||||
1,000 | +55 MBbl/d | (82) | 12/31/19 | 2019 | 2022 | Appalachian Supply | ||
MBbl/d | Current | |||||||
500 | 1,500 | |||||||
+1% | (40%) | |||||||
ROCKIES | ||||||||
0 | +3 MBbl/d | 1,000 | ||||||
(88) MBbl/d | ||||||||
2022 | ||||||||
2019 | 500 | |||||||
SCOOP/STACK |
Permian Supply
1,500
1,000
500
0
2019 2022
12/31/19
+47%
+407 MBbl/d
Current
+20%
+177
MBbl/d
PERMIAN | Current | |
(34%) | ||
12/31/19 | ||
(141) MBbl/d | ||
(5%) | ||
(20) MBbl/d |
USGC & Eagle Ford | ||
EAGLE FORD | 1,500 | Supply |
1,000
500
0
2019 2022
0
2019 2022
Note: Bubbles reflect growth over the next three years (2018-2022). Supply includes field production , but excludes imports and refinery production.
Source: U.S. Energy Information Administration and S&P Global Platts, as of 12/31/2019 and 5/6/20, respectively.
Volumes have been adjusted by Antero to remove ethane.
17
Corporate Presentation
- Antero Resources Executive Overview
- Natural Gas & NGL Macro
- Appendix
18
AR Business Strategy
Antero Resources Principles
Build Scale with
Natural Gas &
Liquids
Diversification
Maintain Strong | Mitigate |
Commodity Price | |
Balance Sheet | |
Risk With | |
and Financial | |
Hedges and Firm | |
Flexibility | |
Transportation | |
Denotes management & employee compensation plan metrics
Priorities
1
Balance cash flow with
capital spending
2
Maintain liquidity & strengthen balance sheet with leverage target of mid 2-times
3
Develop highest rate of return locations across asset portfolio
4
Hedge commodities to protect cash flow and balance sheet
Note: Leverage is a non-GAAP financial measure. Please see the appendix for more information. | 19 |
1 Balance Cash Flow & Capital - Cost Structure Reset
Drilling and completion efficiencies and midstream cost savings result in approximately
$600 million of savings in 2020 compared to AR's 2019 initial budget
Cost Savings Update | 2020 Savings (1) |
Well Cost Reduction Progress
- $750 MM revised D&C capital budget for 2020, a ~$400 MM reduction from the initial budget and 41% below 2019, with no change to production guidance
- D&C of $715/lateral foot, a 26% reduction from $970/ft at the beginning of 2019
Water Savings Driving LOE Lower
- 1Q20 represented a 33% reduction from 2019
- Expect to save $74 MM in 2020 as a result of increased blending operations combined with reduced trucking costs
GP&T and Net Marketing Expense Reduction
- $80 MM of midstream fee reductions in 2020 with Antero Midstream and other third party midstream providers
- Targeting $100 MM reduction in 2020 net marketing expense (1)
G&A Cost Reduction
- 18% reduction by mid-2020 due to headcount reductions in 2019, natural employee attrition and a reduction across the board in expenses
Grand Total Cost Reset for 2020 | = |
Note: Cost reductions are based on 2020 guidance vs original 2019 guidance
- Based on midpoint 2020 guidance.
$320 MM
($970/ft - $715/ft) x 12,000' = $3.05 MM $3.05 MM per well x 105 wells = $320 MM
+
$74 MM
~50% reduction from 2019
+
$180 MM
+
$24 MM
~$600 MM
20
1 Balance Cash Flow & Capital - Momentum Leads to Lower Capital
Through drilling and completion efficiencies, midstream cost savings, service
cost deflation and deferral of completions Antero has been able
to reduce its D&C capex budget by 41% year-over-year
Antero D&C Capex ($MM)
$1,600 | $1,490 | |||||
$1,400 | $1,270 | |||||
$1,200 | $1,150 | |||||
$1,000 | ||||||
$1,000 | ||||||
$800 | $750 | |||||
Water | ||||||
$600 | ||||||
& Treatment | D&C Capital | |||||
$400 | ||||||
$200 | Well | |||||
163 | 131 | 125 | 125 | 105 | ||
Completions | ||||||
$0 | ||||||
2018 | 2019 | Original | Revised | Current | ||
Actual | Actual | Budget | Budget | Budget | ||
(Feb 2020) | (Mar 2020) | (Apr 2020) | ||||
21 |
1 Balance Cash Flow & Capital - Drilling & Completion Efficiencies
Antero continues to achieve material improvements to drilling and
completion efficiencies which reduces well costs
Average Drilled Lateral Feet per Well | Lateral Feet Drilled per Day |
18,000 | 16,320 | New | 12,000 | ||||||
16,000 | Company | 10,000 | |||||||
14,000 | Marcellus | ||||||||
11,693 | Record | 8,000 | |||||||
12,000 | 11,062 | ||||||||
10,000 | 6,000 | ||||||||
8,000 | 4,000 | ||||||||
6,000 | |||||||||
4,000 | 2,000 | ||||||||
2,000 | - | ||||||||
- | |||||||||
2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 1Q | Record | ||
2020 |
10,453 | |||||||
5,934 | 6,395 | ||||||
2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 1Q | Record |
2020 |
Days to Drill a Well - Spud to Spud | Completion Stages per Day | |
35.0 | 14.0 | 13.0 | |||||||||||||
30.0 | 12.0 | ||||||||||||||
25.0 | 10.0 | ||||||||||||||
20.0 | 8.0 | 7.1 | |||||||||||||
15.0 | 11.4 | 10.7 | 6.0 | 5.8 | |||||||||||
8.0 | |||||||||||||||
10.0 | 4.0 | ||||||||||||||
5.0 | 2.0 | ||||||||||||||
0.0 | - | ||||||||||||||
2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 1Q | Record | 2014 | 2015 | 2016 | 2017 | 2018 | 2019 | 1Q | Record |
2020 | 2020 | 22 | |||||||||||||
Note: Percentage increase and decrease arrows represent change in Marcellus data from 2014 through 2020 year to date through April 24th. |
1 Balance Cash Flow & Capital - Marcellus Well Cost Reductions
- Significant Reduction in Well Costs already "in-hand"
- Reduced well costs by ~26% ($3.05 million per well)
Marcellus Well Cost per Lateral Foot (January 2019 AFE to Current 2020)
($MM)
$12.0
$11.5
$11.0
$10.5
$10.0
$9.5
$9.0
$8.5
$8.0
$7.5
$11.6
$970/ft
$1.59
$9.7
$810/ft
Cost reductions already achieved:
- Service cost deflation
- Sand sourcing logistics
- Completion efficiencies
- Drier completions (100% of wells)
- Water blending by AM
- Trucking savings
- Enhanced drillout methodology
Assumes 12,000 foot lateral
Recent Cost Reductions: | |||||||
• Further drilling & completion | |||||||
efficiencies | |||||||
• | Expanded produced water | ||||||
services via AM pipeline | |||||||
system | |||||||
$1.13 | • | Further service cost deflation | |||||
$8.6 | |||||||
$715/ft | |||||||
2019 Budget | 2019 Achievements | Initial 2020 AFE | 2020 Initiatives | Current 2020 AFE |
(1/1/2019) | Achieved |
23
1 Balance Cash Flow & Capital - LOE Reductions
- Materially Reducing LOE
- Targeting reduced LOE by 35% in 2020 (~$74 MM+)
Antero Lease Operating Expense Reductions (2020 Target)
($MM) | |||
$225 | |||
$200 | $42.0 | ||
$175 | $32.0 | ||
$150 | |||
$125 | $42 MM ($0.03/Mcfe) | ||
reduction driven by | $32 MM ($0.03/Mcfe) | ||
$100 | $194.0 | $6/Bbl savings related | |
reduction driven by | |||
to wells already on sales | |||
$6/Bbl savings related to | |||
$75 | |||
$0.15/Mcfe | new wells in 2020 | ||
$120.0 | |||
$50 | |||
$0.09/Mcfe | |||
$25 | 35% Reduction ($74 MM+) | ||
$0 |
2020E | Existing Wells | New 2020 Completions | 2020E LOE Target |
LOE Pre-Water | Produced Water | Produced Water | |
Savings Initiatives | (after 90 days, 70% of total) | (after 90 days, 30% of total) |
24
1 Balance Cash Flow & Capital - Lower Costs Drive Free Cash Flow Profile
Cost structure reset results in enhanced free cash flow profile. The 2020 capital plan will remain flexible, targeting $175 MM in free cash flow.
AR Free Cash Flow ($ MM)
$800
$600
$400
$200
$0
($200)
($400)
($600)
($800)
Targeting $175 MM in
Free Cash Flow in 2020
2017A | 2018A | 2019A | 2020E |
Note: Free cash flow is a non-GAAP financial measure. Please see the appendix for more information. Based on strip pricing as of 4/24/2020. | 25 |
2 Strengthen Balance Sheet - 2020 Asset Sale Program
AR has multiple assets that can be monetized in 2020 to reduce debt, including producing properties, undeveloped leasehold, overriding royalty, minerals, hedges and midstream ownership
Asset Monetization Opportunity Set
Targeting $650 MM to $900 MM
E&P Assets | Financial / Midstream Assets | |
Land / PDP | Minerals | Hedge Portfolio | |||||
• | 536,000 net acres | • | ~5,000 net mineral | • | ~1.8 Tcfe of natural | ||
in Appalachia (1) | acres | gas hedges with a | |||||
• | 84% NRI | • | High NRI enables | current hedge value | |||
of ~$825 MM (2) | |||||||
• 19 Tcfe of Proved | carveout of | ||||||
• 8.3 MMBbls of crude | |||||||
overriding royalty | |||||||
Reserves | |||||||
interest (ORRI) | oil hedges with a | ||||||
• 3.4 Bcfe/d of net | • | Highest realized | current value of | ||||
production (1Q20) | ~$240 MM (2) | ||||||
• | VPPs | prices in Appalachia | • | 14.8 MMBbls of | |||
due to FT and | |||||||
liquids | propane & pentane | ||||||
hedges with a current | |||||||
value of ~$30 MM (2) | |||||||
AM Ownership
- Current market value of $580 MM (3)
- Divested $100 MM in December 2019
- AM had ~$150 MM remaining under its share repurchase program as of 3/31/20
- As of 3/31/2020.
2) | Based on hedge position and strip pricing as of 3/31/2020. | 26 |
3) | Based on AM share price of $4.18/share as of 5/8/2020. |
2 Strengthen Balance Sheet - Liquidity & Leverage
Antero Resources plans to have substantial capacity to address its November 2021 and December 2022 bond maturities through asset sales and cost and activity reductions
AR 2020 Liquidity Outlook ($MM)
$2,500
$2,000
$1,500
$1,000
$500
$0
Repurchased $608 MM of | ||||||||||||||||||||||
$2,088 | principal through 1Q 2020 | |||||||||||||||||||||
Borrowing Base | at a 20% discount | |||||||||||||||||||||
affirmed at $2.85 Bn | ||||||||||||||||||||||
(in excess of | ||||||||||||||||||||||
$2.64 Bn of lender | $900 | |||||||||||||||||||||
commitments) | $1,491 | |||||||||||||||||||||
Par Value | ||||||||||||||||||||||
$1,028 | $160 | |||||||||||||||||||||
$1,224 | ||||||||||||||||||||||
Market | ||||||||||||||||||||||
Value (2) | ||||||||||||||||||||||
3/31/2020 Liquidity | 2Q20E - 4Q20E | 2020E Asset | YE 2020E | 2021 + 2022 |
Free Cash Flow | Sales Target | Liquidity (1) | Senior Notes |
Note: Liquidity represents borrowing availability under AR's credit facility based on $2.64 Bn of lender commitments, $730 million of letters of credit and $882 million of borrowings as of 03/31/2020. Free Cash Flow is a non-GAAPterm. See appendix for more information, including certain material assumptions in projecting Free Cash Flow.
1) | Forecasted year-end 2020 liquidity assumes no change in bank credit facility. | 27 |
2) | Market value based on bond pricing as of 5/8/2020 of $90 for the senior notes due in 2021 and $74.50 for the senior notes due in 2022. | |
3 Develop Highest ROR Locations - Large Delineated Drilling Inventory
AR Resource Overview
Large Drilling Inventory
- Diverse set of locations
- AR holds ~1,400 liquids-rich locations, or 40% of the core undrilled liquids-rich locations in Appalachia
- ~1,200 dry gas locations
Contiguous Acreage Position
Delivers Efficient Development
- Long-lateralsaverage 12,100' in Marcellus rich-gas drilling inventory
- Efficient gathering, compression and processing utilization, and water re-use opportunities generates synergies and capital savings
High Working and Net Revenue Interest
- 925 horizontal Marcellus producing wells are 100% operated and have 99% average working interest
- AR has 84% average NRI in the Marcellus
AR Marcellus Asset Map
Smithburg Sherwood |
Antero Drilling Rig | Antero Producing Well | |
Antero Completion Crew | Antero Undrilled Location | |
AR drilling rig and completion crew as of 5/1/2020.
28
3 Develop Highest ROR Locations - Premium NGL Price Realizations
Diversified exposure to both international and domestic markets results in
Antero realizing a premium to Mont Belvieu on its C3+ NGL pricing
Domestic Markets | International Markets |
31
of 2019
Antero 2020 C3+ NGL Pricing Outlook (1)
Domestic | International | Combined | |
Sales Point | Hopedale | Marcus Hook | Blended |
% of AR C3+ Volume | 50% | 50% | 100% |
Expected Premium / (Discount) | $0.00 - $0.05 | ||
to Mont Belvieu ($/Gal) | |||
1) Based on Antero C3+ NGL component barrel consisting of 56% C3 (propane), 10% isobutane (Ic4), 17% normal butane (Nc4) and 17% natural gasoline (C5+). | 29 |
3 Develop Highest ROR Locations - Premium NGL Price Realizations
Producer Disadvantaged:
E&Ps in Permian, Rockies, Mid-Con & Bakken
Producer Advantaged & Unconstrained:
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 |
Mont
Belvieu
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
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"
30
4 Hedge Commodities - Natural Gas Price Exposure Mitigated Through 2021
AR continued its consistent hedging program during 1Q20, adding 688 MMBtu/d to its 2022 hedge position (previously unhedged) at a price of $2.48/MMBtu
Antero Natural Gas Hedge Profile
(BBtu/d) | Antero Swap Volumes | NYMEX Strip Price | Antero NYMEX Swap Price (1) ($/MMBtu) | |||||||
3,000 | $3.50 | |||||||||
2,228 | 2,400 | ||||
2,500 | $3.00 | ||||
$2.87 | $2.80 | ||||
$2.70 | $2.50 | $2.44 | $2.50 | ||
2,000 | $2.48 | ||||
$2.19 | $2.38 | ||||
$2.00 | |||||
1,500
~94% | ~100% | $1.50 | |||
1,000 | Hedged | 688 | $1.00 | ||
Hedged | |||||
500 | Swap at | Swap at | Swap at | $0.50 | |
150 | |||||
- | $2.87/MMBtu | $2.80/MMBtu | $2.48/MMBtu | $0.00 | |
2020 | 2021 | 2022 | 2023 |
~$825 MM Forecasted Hedge Value (1)
Note: Percentage hedged represents percent of expected natural gas production hedged based on natural gas production guidance of 2.375 Bcf/d in 2020 and flat production in 2021. | 31 |
1) | Strip pricing and hedge position as of 3/31/2020 (only for natural gas hedges - excludes liquids). |
4 Hedge Commodities - Significant Oil Hedge Position
AR has hedged ~100% of expected oil and "oil-equivalent" pentane production in 2020 at $55.63/Bbl and 10% of oil and oil equivalent production in 2021 at $55.16/Bbl
Antero Oil and Pentane (C5) Hedge Profile
Oil Production | Oil Equivalent Production | WTI Strip Price(1) | AR WTI Swap Price(1) | |||||||
(Bbl/d) | Antero has hedged pentanes as a percent of WTI and then hedged the corresponding WTI | |||||||||
price, effectively converting its pentane production into "oil-equivalent" production | ||||||||||
~100% | 28,340 | ||||
30,000 | Hedged | ||||
25,000 | 26,000 | $55.63 | 26,000 | $55.16 | |
Pentane | Pentane | ||||
20,000 | Volumes x | Volumes x | |||
~80% = Oil | WTI Swap at | ~80% = Oil | |||
Equivalent | $55.63/Bbl | Equivalent | $34.90 | ||
15,000 | Production | Oil | Production | ||
16,000 | $26.50 | 17,440 | |||
10,000 | ~10% | ||||
Hedged | |||||
5,000 | WTI Swap at | ||||||||||||||||||
Oil | Oil | $55.16/Bbl | |||||||||||||||||
10,900 | 3,000 | ||||||||||||||||||
- | 10,000 | ||||||||||||||||||
Production | Hedges | Production | Hedges | ||||||||||||||||
Guidance | Guidance | ||||||||||||||||||
2020 | 2021 |
~$240 MM Forecasted Hedge Value (1)
Note: Percentage hedged represents percent of expected oil production hedged based on 2020 production guidance and flat in 2021.
- Based on hedge position and strip pricing as of 3/31/2020.
$70.00
$60.00
$50.00
$40.00
$30.00
$20.00
$10.00
$0.00
32
2020 Credit Enhancement Momentum
Reduced capital budget and operating cost structure improves free cash flow profile
while targeted asset sales, hedge position and scale support debt profile
2019A | 2020E | Potential Credit | ||||||||
Enhancement | ||||||||||
D&C Capex Budget (1) | $1.275 B | $750 B | ($0.525) B | |||||||
F&D Costs ($/Mcfe)(2) | $0.44 | $0.30 | ($0.14) | |||||||
Cost Structure ($/Mcfe) | $2.48 | $2.30 | ($0.18) | |||||||
Free Cash Flow ($MM) | ($310) | $175 | $485 | |||||||
Asset Sales (YE) | $100 MM | $650 MM (3) | $550 MM | |||||||
Total Debt (YE) | $3.8 B | $3.0 B (3) | ($0.8) B | |||||||
Leverage (YE) | 3.0x | 3.0x (3) | Neutral | |||||||
Gas Hedge Position | 75% @ $2.50 | 94% @ $2.87 | 19% / $0.37 | |||||||
Net Production (1) | 3.2 Bcfe/d | 3.5 Bcfe/d | 0.3 Bcfe/d | |||||||
Liquids (1) | 161 MBbl/d | 188 MBbl/d | 27 MBbl/d | |||||||
PDP Reserves (YE) (2) | 10.4 Tcfe | 11.7 Tcfe | 1.3 Tcfe | |||||||
(1) Represents 2019 actuals and 2020 guidance. | ||||||||||
(2) PUD F&D cost and PDP reserve data as of 12/31/2018 and 12/31/2019, respectively. 12/31/2019 reserves back out 18% based on reduction of well cost AFE from $868/ft. at YE 2019 to current $715/ft. | 33 | |||||||||
(3) Total debt and leverage as of 12/31/2019. 2020E debt and leverage assumes low end of asset sale target of $650 MM and includes 2020E targets Free Cash Flow of $175 MM. See appendix for more | ||||||||||
information on Free Cash Flow. |
Antero Long-Term Strategy
Producer resiliency is a key attribute for a sustainable development plan:
Cost
Reduction
Initiatives
Asset Sale Initiatives
World Class Hedge Book
Free Cash
Flow
Robust
Liquidity
AR has targeted ~$600 MM in reductions to
2020 capital and operating expenses
Substantial asset monetization optionality including land,
minerals, hedge portfolio and AM ownership
~94% and ~100% of projected natural gas production hedged in 2020 and 2021 at $2.87 and $2.80/MMBtu, respectively (1)
2020 D&C capital budget of $750 MM with $175 MM
in projected Free Cash Flow (2)
Ample liquidity of $1.0 B (3) to address the 2021s and,
including asset sales, to address 2022s
The AR business model delivers multiple ways to "Win"
- Percentage hedged represents percent of expected natural gas production hedged based on natural gas production guidance of 2.375 Bcf/d in 2020 and flat in 2021.
(2) | Based on strip pricing as of 4/24/2020. See appendix for Free Cash Flow definition. | 34 |
(3) | Liquidity represents borrowing availability under AR's credit facility based on $2.64 Bn of credit commitments, $730 million of letters of credit and $882 million of borrowings as of 3/31/20. |
Corporate Presentation
- Antero Resources Executive Overview
- Natural Gas & NGL Macro
- Detailed Asset Overview
35
2020 Capital Plan and Guidance
Represents Revised Guidance
2020 Guidance Ranges | |
Net Production (Bcfe/d) | 3.5 |
Net Natural Gas Production (Bcf/d) | 2.375 |
Net Liquids Production (Bbl/d) | 187,500 |
Natural Gas Realized Price Expected Premium to NYMEX | $0.00 to $0.10 |
($/Mcf) | |
C3+ NGL Realized Price - Expected Premium to Mont | $0.00 - $0.05 |
Belvieu($/Gal) (1) | |
Oil Realized Price Expected Differential to NYMEX ($/Bbl) | ($10) - ($12) |
Cash Production Expense ($/Mcfe) (2) | $2.07 - $2.13 |
Net Marketing Expense ($/Mcfe) | $0.10 - $0.12 |
G&A Expense ($/Mcfe) | $0.08 - $0.10 |
(before equity-based compensation) | |
D&C Capital Expenditures ($MM) | $750 |
Land Capital Expenditures ($MM) | $45 |
Average Operated Rigs, Average Completion Crews | Rigs: 1 | Completion Crews: 1 |
Operated Wells Completed | Wells Completed: 105 |
Operated Wells Drilled | Wells Drilled: 95 - 100 |
Average Lateral Lengths, Completed | Completed: 11,400 |
Average Lateral Lengths, Drilled | Drilled: 12,850 |
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+). | 36 |
2) | Includes lease operating expenses, gathering, compression, processing and transportation expenses ("GP&T") and production and ad valorem taxes. |
Antero 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.
The Company has not provided projected net income or a reconciliation of projected Adjusted EBITDAX to projected net income, the most comparable financial measure calculated in accordance with GAAP, because the Company does not provide guidance with respect to income tax expense, depletion and depreciation expense or the revenue impact of changes in the projected fair value of derivative instruments prior to settlement. Therefore, projected net income and a reconciliation of projected adjusted EBITDA to projected net income, are not available without unreasonable effort.
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.
Proved Undeveloped (PUD) F&D Cost: Proved undeveloped F&D costs is a non-GAAP metric commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. PUD F&D costs is a statistical indicator that has limitations, including its predictive and comparative value. This reserve metric may not be comparable to similarly titled measurements used by other companies. There are no directly comparable financial measures presented in accordance with GAAP for PUD F&D costs, and therefore a reconciliation to GAAP is not practicable.
The calculation for PUD F&D cost is based on future development costs required for the development of proved undeveloped reserves, divided by total
proved undeveloped reserves. | 37 |
Antero 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 Cash Flow from Operations, less drilling and completion capital and leasehold capital and earnout payments.
The Company has not provided projected Cash Flow from Operations or reconciliations of Free Cash Flow to projected Cash Flow from Operations, the most comparable financial measure calculated in accordance with GAAP. The Company is unable to project Cash Flow from Operations 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. However, the Company is able to forecast 2020 drilling and completion capital of $750 million and leasehold capital of $45 million. Targeted 2020 Free Cash Flow also includes the $125 million earnout payment received from Antero Midstream in January 2020 associated with the water drop down transaction that occurred in 2015. Targeted 2020 Free Cash Flow is based on current strip pricing and assumes that dividends from Antero Midstream remain flat for the year for aggregate annual dividends from Antero Midstream of $171 million in 2020. Today, Antero Midstream announced that in light of the uncertain market conditions impacting the energy industry, Antero Midstream will continue to evaluate its capital budget as well as the appropriate amount of capital that is returned to shareholders through dividends and share repurchases in order to maintain its financial profile.
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.
38
Antero Resources Net Debt & LTM EBITDAX Reconciliation
December 31, | March 31, | |||||||||||
2019 | 2020 | |||||||||||
AR bank credit facility | $ | 552,000 | $ | 882,000 | ||||||||
5.375% AR senior notes due 2021 | 952,500 | 730,283 | ||||||||||
5.125% AR senior notes due 2022 | 923,041 | 761,337 | ||||||||||
5.625% AR senior notes due 2023 | 750,000 | 750,000 | ||||||||||
5.000% AR senior notes due 2025 | 600,000 | 600,000 | ||||||||||
Net unamortized premium | 791 | 600 | ||||||||||
Net unamortized debt issuance costs | (19,464) | (16,433) | ||||||||||
Total debt | $ | 3,758,868 | 3,707,787 | |||||||||
Less: AR cash and cash equivalents | - | - | ||||||||||
Net debt | $ | 3,758,868 | 3,707,787 | |||||||||
Twelve months | ||||||||||||
ended | ||||||||||||
(in thousands) | March 31, 2020 | |||||||||||
Reconciliation of net loss to Adjusted EBITDAX: | ||||||||||||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (1,657,702) | ||||||||||
Depletion, depreciation, amortization, and accretion | 878,233 | |||||||||||
Impairment of oil and gas properties | 1,308,420 | |||||||||||
Impairment of midstream assets | 7,800 | |||||||||||
Commodity derivative fair gains | (1,107,173) | |||||||||||
Gains on settled commodity derivatives | 438,924 | |||||||||||
Equity-based compensation expense | 17,985 | |||||||||||
Provision for income tax benefit | (472,805) | |||||||||||
Gain on early extinguishment of debt | (116,980) | |||||||||||
Equity in loss of unconsolidated affiliates | 285,352 | |||||||||||
Impairment of equity investment | 1,078,222 | |||||||||||
Distributions/dividends from unconsolidated affiliates | 188,107 | |||||||||||
Loss on sale of equity investments | 108,745 | |||||||||||
Water earnout | (125,000) | |||||||||||
Gain on sale of assets | 920 | |||||||||||
Interest expense, net | 209,263 | |||||||||||
Exploration expense | 968 | |||||||||||
Contract termination and rig stacking | 5,666 | |||||||||||
Adjusted EBITDAX | $ | 1,048,945 |
39
Antero Resources 2019 LTM EBITDAX Reconciliation
Twelve months ended | |||
(in thousands) | December 31, 2019 | ||
Net loss and comprehensive loss attributable to Antero Resources Corporation | $ | (340,129) | |
Net income and comprehensive income attributable to noncontrolling interests | 46,993 | ||
Commodity derivative fair value gains | (463,972) | ||
Losses on settled commodity derivatives | 325,090 | ||
Loss on sale of assets | 951 | ||
Gain on deconsolidation of Antero Midstream | (1,406,042) | ||
Interest expense, net | 228,111 | ||
Gain on early extinguishment of debt | (36,419) | ||
Provision for income tax benefit | (74,110) | ||
Depletion, depreciation, amortization, and accretion | 918,629 | ||
Impairment of oil and gas properties | 1,300,444 | ||
Impairment of midstream assets | 14,782 | ||
Impairment of equity investments | 467,590 | ||
Exploration expense | 884 | ||
Equity-based compensation expense | 23,559 | ||
Equity in loss of unconsolidated affiliate - AMC | 143,216 | ||
Distributions from unconsolidated affiliates | 157,956 | ||
Contract termination and rig stacking | 14,026 | ||
Loss on sale of equity investment shares | 108,745 | ||
Water earnout | (125,000) | ||
Simplification transaction fees | 15,482 | ||
Antero Midstream Related Adjustments | |||
Net income and comprehensive income attributable to noncontrolling interests | (46,993) | ||
Antero Midstream interest expense, net | (16,815) | ||
Antero Midstream loss on extinguishment of debt | (21,770) | ||
Antero Midstream depreciation, accretion of ARO and accretion of contingent consideration | (6,982) | ||
Antero Midstream impairment | (2,477) | ||
Antero Midstream equity-based compensation expense | 12,264 | ||
Antero Midstream gain on sale | (61,319) | ||
Antero Midstream equity in earnings of unconsolidated affiliates | (15,021) | ||
Antero Midstream distributions from unconsolidated affiliates | 95,183 | ||
Equity in earnings of Antero Midstream | - | ||
Distributions from Antero Midstream | - | ||
Antero Midstream simplification transaction fees | (9,185) | ||
Adjusted EBITDAX | $ | 1,247,671 |
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Antero Resources Corporation published this content on 19 May 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 22 May 2020 10:51:10 UTC