First Quarter 2017 Earnings Call Presentation May 9, 2017 - - PowerPoint PPT Presentation

First Quarter 2017 Earnings Call Presentation May 9, 2017

Forward-Looking Statements

This presentation contains 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 statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Resources Corporation and its subsidiaries (collectively, the “Company” or “Antero”) expects, believes or anticipates will or may occur in the future are forward-looking statements. The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “estimate,” “project,” “foresee,” “should,” “would,” “could,” or other similar expressions are intended to identify forward-looking statements. However, the absence of these words does not mean that the statements are not forward-looking. Without limiting the generality of the foregoing, forward- looking statements contained in this presentation specifically include estimates of the Company’s reserves, expectations of plans, strategies,

• bjectives and anticipated financial and operating results of the Company, including as to the Company’s drilling program, production, hedging

activities, capital expenditure levels and other guidance included in this presentation. These statements are based on certain assumptions made by the Company based on management’s experience and perception of historical trends, current conditions, anticipated future developments and

• ther factors believed to be appropriate. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are

beyond the control of the Company, which may cause actual results to differ materially from those implied or expressed by the forward-looking

• statements. These include the factors discussed or referenced under the heading “Item 1A. Risk Factors” in our Annual Report on Form 10-K for

the year ended December 31, 2016 and in the Company’s subsequent filings with the SEC. The Company cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. 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, and the other risks described under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016 and in the Company’s subsequent filings with the SEC. Any forward-looking statement speaks only as of the date on which such statement is made and the Company undertakes no obligation to correct

• r update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

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Antero Resources Corporation is denoted as “AR” and Antero Midstream Partners LP is denoted as “AM” in the presentation, which are their respective New York Stock Exchange ticker symbols.

500 750 1,000 1,250 1,500 1,750 2,000 2,250 2,500 2,750 3,000

Antero Completion Size (lbs/ft) Completion Start Date

Testing higher proppant loads in 2017 – Early results are encouraging Supports 2.0 Bcf/1,000’ type curve and 81 PUD bookings at YE2016

1,000 2,000 3,000 4,000 5,000 Days

Marcellus Completion Evolution

Supports 1.7 Bcf/1,000’ type curve and historical reserve bookings

2,500 2,000 1,750 1,500

Antero is continuing to increase proppant intensity in 2017 primarily utilizing 1,750 and 2,000 lb/ft completions in the Marcellus

Per Well Frac Size Design (lb/ft) 1,250 1,500 1,750 2,000 2,500

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1.5 1.7 2.0 1,750 lb/ft Completions 1,500 lb/ft Completions

32 Bbl/ft Water 34 Bbl/ft Water 36 Bbl/ft Water 42 Bbl/ft Water 48 Bbl/ft Water

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Recent Marcellus Well Results

Dry Gas High-Graded Core Average 2.2 Bcf / 1,000’ Wellhead EUR Southern Rich High-Graded Core Average 2.0 Bcf / 1,000’ Wellhead EUR

Antero Acreage Antero Horizontal Marcellus Wells Industry Horizontal Marcellus Wells

Wellhead EURs from Antero’s recent 1,750 pound per foot completions have continued to

• utperform legacy style completions and range from 2.0 to 2.4 Bcf/1,000’ at the wellhead
• Recent 4-well pad with 2,500 lb/ft completions potentially extends high-graded core areas

Antero - 10 Well Average Advanced 1,700# Completion Wellhead: Processed: C2 Recovery: Lateral: Net F&D Cost: Antero - 4 Well Average Advanced 1,700# Completion Wellhead: Processed: C2 Recovery: Lateral: Net F&D Cost: 2.4 Bcf/1,000’ 2.9 Bcfe/1,000’ 3.6 Bcfe/1,000’ 10,017’ $0.39/Mcfe 2.1 Bcf/1,000’ 2.6 Bcfe/1,000’ 3.3 Bcfe/1,000’ 10,468’ $0.35/Mcfe Antero - 4 Well Average Advanced 2,500# Completion Wellhead: Processed: C2 Recovery: Lateral: Net F&D Cost: 2.2 Bcf/1,000’ 2.5 Bcfe/1,000’ 3.1 Bcfe/1,000’ 5,365’ $0.47/Mcfe (1) Antero - 2 Well Average Advanced 1,750# Completion Wellhead: Processed: C2 Recovery: Lateral: Net F&D Cost: 2.3 Bcf/1,000’ 2.9 Bcfe/1,000’ 3.7 Bcfe/1,000’ 11,567’ $0.38/Mcfe

• 1. Represents actual completion costs and Q1 2017 AFE drilling costs.

Net F&D Cost: $0.38/Mcfe Net F&D Cost: $0.35/Mcfe Net F&D Cost: $0.39/Mcfe Net F&D Cost: $0.47/Mcfe(1)

$5.1 $7.9 $9.7 30% 45% 56% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $0.0 $6.0 $12.0 $18.0 1.7 2.1 2.0 2.5 2.3 2.8 Unhedged Pre-Tax ROR Pre-Tax PV-10 ($MM) Pre-Tax PV-10 Pre-Tax ROR $9.4 $12.4 $15.4 53% 72% 95% 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $0.0 $6.0 $12.0 $18.0 1.7 2.3 2.0 2.7 2.3 3.1 Unhedged Pre-Tax ROR Pre-Tax PV-10 ($MM) Pre-Tax PV-10 Pre-Tax ROR

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• 1. Assumes ethane rejection. Based on commodity pricing as of 3/31/17. Assumes 9,000’ lateral length. See appendix for further assumptions.

Highly-Rich Gas/Condensate (3/31/17 Pricing) (1)

Wellhead Bcf/1,000’: Processed Bcfe/1,000’:

Integrated platform yields attractive well economics and sustainable growth

2.0 2.7 2.0 2.5

683 Undrilled Locations

Wellhead Bcf/1,000’: Processed Bcfe/1,000’:

Highly-Rich Gas (3/31/17 Pricing) (1)

1,184 Undrilled Locations

2016/2017 Advanced Completion Results

1313 Btu 1250 Btu

Improving Marcellus Returns

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A Leading Consolidator in Appalachia

 Antero has grown its acreage position by over 200,000 net acres since its IPO in October 2013  Since the beginning of 2016, Antero has acquired approximately 113,000 net acres in the core of the Marcellus and Utica Shale plays  Virtually all of the acquired acreage is now dedicated to Antero Midstream  Consolidated acreage position drives efficiencies:

– Longer laterals – More wells per pad – Higher utilization of gathering, compression and freshwater infrastructure – Facilitates central water treatment avoiding injection

Activity Acquisitions and Antero Footprint

2016 Acquired Acreage 2017 Acquired Acreage (1)

• 1. Either acquired or under purchase and sale agreement to be acquired.

NGL Infrastructure Buildout in the Northeast

Mariner West (50 Mbbl/d C2) Mariner East (70 Mbbl/d) 61,500 MBbl/d Mariner East 2

Antero / MPLX Joint Venture (1)

• 1. Represents processing and fractionation joint venture between Antero Midstream and MPLX LP that was announced February 6th, 2017.

Utopia (50 Mbbl/d C2) (1Q 2018)

Antero controls 43% of liquids rich locations in the Northeast and thus is a key driver behind the Northeast NGL infrastructure buildout

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2,163 2,015 2,330 710 810

$3.47 $3.91 $3.70 $3.63 $3.31 $3.18

$3.32 $3.03 $2.83 $2.82 $2.83 $2.84 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 400 800 1,200 1,600 2,000 2,400 2017 2018 2019 2020 2021 2022 BBtu/d $/Mcfe

Average Index Hedge Price(1) Hedged Volume Current NYMEX Strip(2)

Commodity Hedge Position

$81 MM $627 MM $702 MM $390 MM $110 MM

Mark-to-Market Value(2)

Largest Gas Hedge Position in U.S. E&P

~ 100% of 2017 Guidance Hedged

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• 1. Weighted average index price based on volumes hedged assuming 6:1 gas to liquids ratio; excludes impact of TCO basis hedges. 27,500 Bbl/d of propane hedged in 2017 and 2,000 Bbl/d hedged in
• 2018. 20,000 Bbl/d of ethane hedged in 2017 and 3,000 Bbl/d of oil hedged in 2017.
• 2. As of 3/31/2017.

$85 MM

~$2.1 billion mark-to-market unrealized gain based on 3/31/2017 prices with 3.4 Tcfe hedged through year-end 2022 at $3.63 per MMBtu

• Hedging is a key component of Antero’s

business model due to the large, repeatable drilling inventory

• Antero has realized $2.8 billion of gains on

commodity hedges since 2008 with gains realized in 34 of last 36 quarters

~ 84% of 2018 Target Gas Production Hedged

1.8 2.2 2.7 3.2 3.9 0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 2016A 2017E 2018E 2019E 2020E Net Daily Production

2017 Guidance

8 D&C Capital:

$1.3 Billion Flat with prior year Modest annual increases within Cash Flow from Operations

Production Growth:

In line with D&C capital Doubling by 2020

Consolidated Cash Flow from Operations(1):

3.0x to 3.5x Declining to mid-2s by 2018

Leverage(1):

98% Hedged at $3.51/Mcfe 58% Hedged at $3.76/Mcfe

Hedging:

2018 - 2020 Long Term Targets

(Bcfe/d)

• 1. Assuming 12/31/2016 4-year strip pricing averaging $3.12/MMBtu for natural gas and $56.23/Bbl for oil. Consolidated cash flow from operations includes realized hedge gains.
• 2. Represents midpoint of 20% - 22% long-term production growth targets.

$3.47 $3.91 $3.70 $3.66

Hedged Volume (Bcfe) Hedged Price ($/Mcfe) Guidance Long-Term Targets $

(2) (2) (2)

2017 Guidance and Long Term Outlook

3,502 1,967 1,937 1,161 913 867 824 736 692 683 635 548

• 500

1,000 1,500 2,000 2,500 3,000 3,500 4,000 AR A B C D E J H K F L I Undrilled Locations Core - NE Pennsylvania Dry Locations Core - SW Marcellus and Ohio Utica Dry Locations Core - Marcellus & Ohio Utica Liquids-Rich Locations

Largest Core Drilling Inventory In Appalachia

• 1. Location count determined by Antero technical review of geology and well control to delineate core areas and peer acreage positions both drilled and undrilled. Pro forma for all acreage acquisitions to date.
• 2. Peers include Ascent, CHK, CNX, COG, CVX, EQT, GPOR, NBL, RICE, RRC and SWN.

* Undrilled location count net of acreage allocated to publicly disclosed joint ventures.

Undrilled Core Marcellus and Utica Locations (1)(2)

Large, repeatable core drilling inventory that averages 8,000’ in lateral length and includes 43% of all liquids-rich undrilled locations in Appalachia

Core Liquids-Rich Appalachia Undrilled Locations (1)

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* * * * *

Avg. Lateral Length

8,081’

6,429’ 6,355’ 7,762’ 8,601’ 5,758’ 8,594’ 9,262’ 7,085’ 7,550’ 8,880’ 6,225’

43%

B 13% C 10% J 8% E 6% F 6% A 4% D 3% K 3% H 2% I 2%

19,500 42,500 73,000 86,500 20,000 40,000 60,000 80,000 100,000 120,000 140,000 160,000 2014 2015 2016 2017 Guidance 2018E Target 2019E Target 2020E Target

Ethane (C2) C3+ Production Propane (C3) Normal Butane (nC4) IsoButane (iC4) Natural Gasoline (C5+)

• 1. Excludes condensate.
• 2. Assumes midpoint of 20 – 22% year-over-year equivalent production growth in 2018-2020. For illustrative purposes C3+ production growth assumed at same rate.

(1)

(Bbl/d) C5+ iC4 nC4 C3

C2 Ethane 17,476 C2 Ethane 19,000

NGL Production Growth by Purity Product (Bbl/d) Antero is the largest NGL producer in the Northeast

Rapidly Growing NGL Production

(2) (2) (2)

20–22% Y-O-Y Long-Term Growth Target

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Gas $2.89 Gas $2.80 Gas $2.80 Gas $2.80 $0.14 Condensate $0.18 Condensate $0.21 NGLs (C3+) $0.89 NGLs (C3+) $1.12 NGLs (C3+) $1.36 $0.00 $0.50 $1.00 $1.50 $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 1050 BTU 1250 BTU / $55 WTI 1250 BTU / $65 WTI 1250 BTU / $75 WTI

Liquids Pricing Upgrade in the Marcellus

• 1. Assumes $2.75/MMBtu NYMEX, $55/Bbl to $75/Bbl WTI and NGL prices equal to 52.5% of WTI (midpoint of 2017 guidance). 45 Bbl/MMcf (ethane rejection) recovery for NGLs and 3 Bbl/MMcf for

condensate, processing shrink included.

Assuming Ethane Rejection

(1100 BTU Tailgate) 8% shrink

Realized Price Per Mcf(1)

($/Mcf)

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+$0.94

Upgrade

+$1.21

Upgrade

Rich Gas Dry Gas

$3.83 $4.10

$2.75/MMBtu NYMEX

Antero realizes a significant upgrade to assumed $2.75/MMBtu NYMEX gas price by producing liquids-rich gas and condensate

+$1.48

Upgrade $4.37 $2.89

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APPENDIX

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Mitigating Service Cost Exposure

Antero has limited its exposure to service cost increases over the next few years through long-term agreements with drilling contractors and completion services

Drilling Rigs Completion Crews

Since 2014, approximately 50% of the reduction in well costs was driven by efficiency gains and 50% through service cost reductions. By maintaining drilling and completion momentum during the commodity downturn, Antero had the opportunity to lock in many of the best crews at attractive long-term contracted rates

4 4 3 4.5 6.5 9.0 1 2 3 4 5 6 7 8 9 10 2017E 2018E 2019E Contracted Rigs Rigs Needed 5 4 2 5.5 7.5 8.0 1 2 3 4 5 6 7 8 9 2017E 2018E 2019E Contracted Completion Crews Completion Crews Needed

• 1. Excludes intermediate rigs used to drill to kick-off point.

(1)

Antero Resources – 2017 Guidance

Key Variable

Updated 2017 Guidance(1)

Net Daily Production (MMcfe/d) 2,160 – 2,250 Net Residue Natural Gas Production (MMcf/d) 1,625 – 1,675 Net C3+ NGL Production (Bbl/d) 65,000 – 70,000 Net Ethane Production (Bbl/d) 18,000 – 20,000 Net Oil Production (Bbl/d) 5,500 – 6,500 Net Liquids Production (Bbl/d) 88,500 – 96,500 Natural Gas Realized Price Premium to NYMEX Henry Hub Before Hedging ($/Mcf)(2)(3) +$0.00 – $0.10 Oil Realized Price Differential to NYMEX WTI Oil Before Hedging ($/Bbl) $(7.00) – $(9.00) C3+ NGL Realized Price (% of NYMEX WTI)(2) 50% – 55% Ethane Realized Price (Differential to Mont Belvieu) ($/Gal) $0.00

Operating:

Cash Production Expense ($/Mcfe)(4) $1.55 – $1.65 Marketing Expense, Net of Marketing Revenue ($/Mcfe) $0.075 – $0.125 G&A Expense ($/Mcfe) $0.15 – $0.20 Operated Wells Completed 170 Drilled Uncompleted Wells 30

Capital Expenditures ($MM):

Drilling & Completion $1,300 Land $200 Total Capital Expenditures ($MM) $1,500

Key Operating & Financial Assumptions

• 3. Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1000 Btu on average.
• 4. Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.
• 1. Updated guidance per press release dated 02/28/2017.
• 2. Based on strip pricing as of February 24, 2017.

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Antero Resources EBITDAX Reconciliation

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EBITDAX Reconciliation

($ in millions) Quarter Ended LTM Ended 03/31/2017 03/31/2017 EBITDAX: Net income including noncontrolling interest $305.6 $(454.5) Commodity derivative fair value (gains) (438.8) 355.3 Net cash receipts on settled derivatives instruments 44.8 723.6 Gain of sale on assets

• (97.6)

Interest expense 66.7 256.9 Loss on early extinguishment of debt

• 16.9

Income tax expense (benefit) 131.3 (369.8) Depreciation, depletion, amortization and accretion 203.4 823.5 Impairment of unproved properties 26.9 174.3 Exploration expense 2.1 8.0 Equity-based compensation expense 25.5 104.4 Equity in earnings of unconsolidated affiliate (2.2) (2.7) Distributions from unconsolidated affiliate

• 7.7

Contract termination and rig stacking

• Consolidated Adjusted EBITDAX

$365.3 $1,546.0