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Transcript of Am website presentation december 2014
Partnership OverviewDecember 2014
FORWARD-LOOKING STATEMENTS
This presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Antero Midstream Partners LP, and its subsidiaries (collectively, the “Partnership”) expect, believe or anticipate 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 expectations of plans, strategies, objectives, and anticipated financial and operating results of the Partnership and Antero Resources Corporation (“Antero”). These statements are based on certain assumptions made by the Partnership and Antero based on management’s experience and perception of historical trends, current conditions, anticipated future developments and other 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 Partnership, which may cause actual results to differ materially from those implied or expressed by the forward-looking statements.
The Partnership cautions you that these forward-looking statements are subject to risks and uncertainties that may cause these statements to be inaccurate, and readers are cautioned not to place undue reliance on such statements. These risks include, but are not limited to, Antero’s ability to meet its drilling and development plan, commodity price volatility, inflation, environmental risks, drilling and completion and other operating risks, regulatory changes, the uncertainty inherent in projecting future rates ofproduction, cash flow and access to capital, the timing of development expenditures, and the other risks discussed in the registration statement on Form S-1 (No. 333-193798) filed by the Partnership under the heading “Risk Factors.”
Any forward-looking statement speaks only as of the date on which such statement is made, and the Partnership 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.
1
ANTERO MIDSTREAM – A GROWTH FOCUSED MLP
2
• AM sponsor is the most active operator in Appalachia• Highest recycle ratio and low F&D cost supports sponsor production growth expectations• Sponsor maintains strong liquidity and significant hedging position• Highly incentivized to maximize value of AM to support AR growth
• Midstream assets located in lowest cost per Mcfe rich gas plays in North America• ~80% of midstream “footprint” is associated with rich gas production• Substantial AR and third-party future infrastructure required• Gathering and compression provide core asset portfolio with additional option to
expand into freshwater distribution and regional pipelines
• Pure play, fee-based midstream MLP with top tier growth rate• Cash flows are supported by 20-year, fee-based agreements with AR• “Best in class” anchor tenant with 90% expected net production growth in 2014 and
45-50% growth in both 2015 and 2016• Growth not dependent on drop-downs, 3rd party business or acquisitions for growth
• Consolidated Marcellus and Utica rich gas acreage dedications• Multiple gathering and compression, processing, pipeline and other expansion
opportunities• Option to acquire AR Fresh Water Distribution system
• Antero Midstream MLP had no leverage at IPO closing plus $250 million cash • $1 billion of undrawn borrowing capacity commitments at IPO• Good high yield access with “Ba3/BB” rated parent (corporate ratings)• Structured to pursue organic growth opportunities
PremierE&P Sponsorship1
“Pure Play” Marcellus/UticaMidstream MLP
2
Top Tier MLP Organic Growth3
Appalachian Midstream Value Chain Opportunity
4
Stacked-Pay Basin Potential Upside5
Financial Flexibility & Strong Capital Structure
6
• Stacked-pay opportunities – Utica, Marcellus, Upper Devonian• Opportunity to develop Utica Shale dry gas pipeline and compression systems in
West Virginia• Future Upper Devonian development will require existing water resource for
completions and gathering and compression systems
AnteroMidstream Management
ANTERO MIDSTREAM OWNERSHIP STRUCTURE
3
Antero ResourcesCorporation (NYSE: AR)
$13.4 Billion Enterprise Value(1)
Ba3/BB Corporate Rating
Antero MidstreamPartners LP (NYSE: AM)
$3.9 Billion Market Cap.(1)
Public
$1 BillionCredit Facility
Midstream Entity
PartnershipCorporation
MarcellusGathering
& Compression
UticaGathering &
Compression
Option(3)
Antero Fresh WaterDistribution System
Option
69.7% Limited Partner Interest
1. As of 12/8/2014. AR enterprise value excludes AM minority interest and cash. 2. Option to acquire up to a 15% non-operating equity interest in a new build Regional Gathering Pipeline.3. Option to acquire 100% interest at fair market value.
100% 100% 100%
Option(2)
Regional GatheringPipeline
15%
Midstream Option
1. Represents inception to date actuals as of 9/30/2014 and 4Q 2014 and next twelve months (NTM) guidance.2. Includes $14.7 million of maintenance capex.
4
• Gathering and compression assets in core of rapidly growing Marcellus and Utica Shale plays
– Acreage dedication of ~390,000 net leasehold acres for gathering and compression services
– 100% fixed fee long term contracts
UticaShale
MarcellusShale
Projected Midstream Infrastructure(1)
Marcellus Shale
Utica Shale Total
YE 2014E Cumulative Gathering/ Compression Capex ($MM) $850 $350 $1,200
Gathering Pipelines(Miles) 180 85 265
Compression Capacity(MMcf/d) 370 - 370
Condensate Gathering Pipelines (Miles) - 20 20
NTM (9/30/2015) Gathering/ Compression Capex ($MM)(2) $473 $129 $602
Gathering Pipelines (Miles) 219 108 327
Compression Capacity(MMcf/d) 835 - 835
Condensate Gathering Pipelines (Miles) - 27 27
Midstream Assets
ANTERO MIDSTREAM PARTNERS OVERVIEW
ANTERO MIDSTREAM ASSETS – RICH GAS MARCELLUS
5
• Provides Marcellus gathering and compression services − Liquids-rich gas is delivered to MWE’s Sherwood
Complex for processing• Significant growth projected over the next twelve
months as set out below:
• Antero sold the Harrison County portion of its gathering system to a 3rd party midstream company in 2012, which is now recognized as the 3rd Party Gathering and Compression Dedication area
• Development upside as AR continues to drill, step-out and add acreage
Marcellus Gathering & Compression
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
YE 2014 9/30/2015
Gathering Pipelines (Miles) 180 219
Compression Capacity (MMcf/d) 370 835
WV/PA Utica Dry Gas Gathering & Compression
• Further development upside in 167,000 net acres of Utica deep rights beneath the Marcellus Shale− Will require a separate dry gas gathering system
6
• Provides Utica natural gas and condensate gathering services− Liquids-rich gas delivered into MWE’s Seneca
Complex for processing− Condensate delivered to centralized stabilization
and truck loading facilities• Significant growth projected over the next twelve
months as set out below:
• Development upside as AR continues to drill, step-out and add acreage
Utica Gathering
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.
ANTERO MIDSTREAM ASSETS – RICH & DRY GAS UTICA
YE 2014 9/30/2015
Gathering Pipelines (Miles) 85 108
Condensate Pipelines (Miles) 20 27
Utica Compression• Opportunity to build up to ten new compressor stations
that are planned to support AR development over the next several years− Compressor stations are not included in AM NTM
forecast
108
216 281 331
386
531
964
0
200
400
600
800
1,000
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q'14 NTM9/30/15
Utica Marcellus
$1.4 $5.0 $6.8 $8.4 $11.4 $18.8
$136.2
0
20
40
60
80
100
120
140
160
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15
EBITDA
HIGH GROWTH THROUGHPUT
Low Pressure Gathering (MMcf/d) Compression (MMcf/d)
High Pressure Gathering (MMcf/d) Antero Midstream Partners EBITDA ($MM)
1. Midstream EBITDA does not include EBITDA contribution from fresh water distribution
(1)
7
26 31 40 36 41
116
249
0
50
100
150
200
250
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15
Marcellus
10 38 80
126
266
531
773
0
200
400
600
800
2Q '13 3Q '13 4Q '13 1Q '14 2Q '14 3Q '14 NTM9/30/15
Utica Marcellus
ORGANIC GROWTH STRATEGY: “BUILD VS. BUY”
8
• Organic growth strategy provides attractive returns and project economics, while avoiding the competitive acquisition market
• Industry leading organic growth story
– ~$875 million in estimated capital spent through 6/30/2014
– $587 million in additional growth capital forecast for the twelve-month period ending 9/30/15 (excludes $15 million of maintenance capital)
Note: Precedent data per IHS Herold’s research and public filings.1. Antero organic multiple calculated as estimated gathering and compression capital expended through Q2 2014 divided by NTM 9/30/15 projected gathering and compression EBITDA.2. Selected gathering and compression drop down acquisitions since 1/1/2011. Drop down multiples are based on NTM EBITDA. Source: Barclays.
6.4x
11.9x
10.7x
10.0x
9.3x9.0x 9.0x 9.0x 8.9x 8.9x 8.8x 8.6x
8.0x 7.9x
7.0x 6.9x
5.5x
0.0x
1.0x
2.0x
3.0x
4.0x
5.0x
6.0x
7.0x
8.0x
9.0x
10.0x
11.0x
12.0x
Drop Down Multiple(2)
Organic EBITDA Multiple vs. Precedent Drop Down Multiples
Median: 8.9x
Value creation for the AM unit holder =Build at 4-6x EBITDA
vs.Drop-Down / Buy at 8-12x EBITDA
Fresh Water
Distribution(1)
Regional Gas Pipelines
Miles Capacity In-Service
Unnamed Regional Pipeline
50 1.4 Bcf/d 4Q 2015
91. Currently owned by AR; AM holds option to purchase 100% of assets at fair market value.
EndUsers
EndUsers
Gas Processing
Y-Grade Pipeline
Long-Haul Interstate
Pipeline
InterConnect
NGL Product Pipelines
Fractionation
Compression
Low Pressure Gathering
Well Pad
Terminalsand
Storage
(Miles) YE 2014 9/30/2015
Marcellus 110 130
Utica 51 72
Total 161 202
AM has option to participate in processing, fractionation,
terminaling and storage projects offered to AR
FULL MIDSTREAM VALUE CHAIN POTENTIAL
(Miles) YE 2014 9/30/2015
Marcellus 70 89
Utica 34 36
Total 104 125
(MMcf/d) YE 2014 9/30/2015
Marcellus 370 835
Utica 0 0
Total 370 835
AM Owned Assets
Condensate GatheringStabilization
(Miles) YE 2014 9/30/2015
Utica 20 27
EndUsers
AM Option Assets
(Ethane, Propane, Butane, etc.)
(De-ethanization)
AM OPTION – FRESH WATER DISTRIBUTION SYSTEMS
10
Marcellus Fresh Water Distribution System• Provides fresh water to support ongoing Marcellus completion
activity • Year-round water supply sources: Ohio River and local rivers• Significant growth projected over the next twelve months as
summarized below:
Note: Antero acreage position reflects tax districts in which greater than 3,000 net acres are owned.1. Estimated fee of $3.50 per barrel at an average of 200,000 Bbls of water per well.
Utica Fresh Water Distribution System• Provides fresh water to support ongoing Utica completion activity • Year-round water supply sources: local reservoirs and rivers• Significant growth projected over the next twelve months as
summarized below:
• Currently owned by AR – AM holds option to purchase 100% of assets at fair market value
Marcellus Water System YE 2014 9/30/2015
Buried Water Pipeline (Miles) 107 127
Fresh Water Storage Impoundments 26 32
NTM 9/30/2015 Projected Wells 162
Water Fees per Well ($)(1) $600K -$800K
Utica Water System YE 2014 9/30/2015
Buried Water Pipeline (Miles) 48 63
Fresh Water Storage Impoundments
8 13
NTM 9/30/2015 Projected Wells 56
Water Fees per Well ($)(1) $600K -$800K
OHIO
25%
15%
10%
25%
30%
10% 15%
35%
25%
20%
35%
25%
20%
40%
0%
10%
20%
30%
40%
Inte
rnal
Rat
e of
Ret
urn
11
DRY GAS LOCATIONS RICH GAS LOCATIONS
HIGHLY RICH GAS
LOCATIONS
Project Economics by Segment(1)
ESTIMATED PROJECT ECONOMICS BY SEGMENT
LPGathering
HPGathering Compression
CondensateGathering
Water Distribution
RegionalPipeline
Processing/Fractionation
Unlevered IRR Range: 25% - 35% 15% - 25% 10% - 20% 25% - 35% 30% - 40% 10% - 25% 15% - 20% Payout (Years): 2.5 - 4.0 3.5 - 4.5 4.0 - 6.5 2.0 - 3.5 2.0 – 3.0 3.5 - 7.0 5.0 - 6.0 Minimum Volume Commitments: N/A 75% 70% N/A N/A 100% 60%
9/30/15 NTM Capex(2) TotalMarcellus $473.3 $155.9 $131.8 $185.6 -Utica 114.0 89.8 15.9 - 8.3
Expansion Capex $587.3 $245.7 $147.7 $185.6 $8.3 % of Capex 100% 42% 25% 32% 1%
Included in NTM Period: Marcellus & Utica
Marcellus & Utica
Marcellus Utica Not Included Not Included Not Included
Additional Opportunities: Dry Utica Dry Utica Rich & Dry Utica
Utica Stabilization
Drop-Downof Water
Distribution System
Regional Gathering
Pipeline
Marcellus Processing/
Fractionation
1. Based on management capex, operating cost and throughput assumptions by project.2. Excludes $14.7 million of maintenance capex.
Wtd. Avg. 23% IRR
AM Option Opportunities
SIGNIFICANT FINANCIAL FLEXIBILITY
12
• Unfunded $1 billion revolver in place at time of IPO to fund future growth capital (5x Debt/EBITDA Cap)
• No leverage and $250 million of cash “post-IPO” provides significant financial flexibility
• Sponsor (NYSE: AR) has Ba3/BB corporate ratings
AM Liquidity
AM Peer Leverage Comparison(2)
($ in millions) At IPO(1)
Revolver Capacity $1,000
Less: Borrowings -
Plus: Cash 250
Liquidity $1,250
0.0x 0.0x 0.1x
1.1x 1.3x 1.5x2.2x 2.4x
3.1x 3.1x 3.3x 3.3x4.0x 4.1x
0.0x
2.0x
4.0x
6.0x
Deb
t / L
TM E
BIT
DA
1. IPO completed on 11/10/2014. 2. Peers include ACMP, EQM, MPLX, MWE, OILT, PSXP, QEPM, RRMS, SXL, TEP, TLLP, VLP and WES.
Sources ($ in millions)
Primary IPO Proceeds $1,150
Total Sources $1,150
Uses
Proceeds to AR $843
Proceeds retained by AM 250
Fees & Expenses 57
Total Uses $1,150
Sources & Uses
Financial Flexibility
13
ANTERO MIDSTREAM MLP INVESTMENT HIGHLIGHTS
Premier E&P Sponsorship
“Pure Play” Marcellus/UticaMidstream MLP
Top Tier MLP Organic Growth
Full Midstream Value Chain Potential
Financial Flexibility & Strong Capital Structure “Best in Class”
Distribution Growth Expected
14
Antero Resources (NYSE: AR)Overview
15
Most Active Operatorin Appalachia
Most ActiveLand Organization
in Appalachia
Largest Firm Transport and Processing
Portfolio in Appalachia
Largest Gas Hedge Position in U.S. E&P +
Strong Financial Liquidity
Highest Growth Large Cap E&P
Largest Liquids-Rich Core Position in
Appalachia
Highest Realizations and Margins Among
Large Cap Appalachian Peers
Growth Land
Liquidity
Midstream
Drilling
LEADING UNCONVENTIONAL BUSINESS MODEL
MLP (NYSE: AM)Highlights
Substantial Value in Midstream Business
Realizations
Takeaway
Liquids-Rich1
2 3
4
5
67
8
Premier AppalachianE&P Company
Run by Co-Founders
DRILLING – MOST ACTIVE OPERATOR IN APPALACHIA
1. All net acres allocated to the WV/PA Utica Shale Dry Gas and Upper Devonian Shale are included among the net acres allocated to the Marcellus Shale as they are stacked pay formations attributable to the same leasehold.
2. Locations as of 9/30/2014 adjusted for additional 130 locations acquired through 11/3/2014.3. Antero and industry rig locations and rig count as of 11/28/2014 per RigData.
16
COMBINED TOTAL – 6/30/14 RESERVESAssumes Ethane RejectionNet Proved Reserves 9.1 TcfeNet 3P Reserves 37.5 TcfePre-Tax 3P PV-10 $25.9 BnNet 3P Reserves & Resource 47.0 TcfeNet 3P Liquids 966 MMBbls% Liquids – Net 3P 15%3Q 2014 Net Production 1,080 MMcfe/d- 3Q 2014 Net Liquids 25,000 Bbl/dNet Acres(1) 524,000Undrilled 3P Locations(2) 5,244
UTICA SHALE CORE
Net Proved Reserves 537 BcfeNet 3P Reserves 6.4 TcfePre-Tax 3P PV-10 $6.5 BnNet Acres 135,000Undrilled 3P Locations(2) 997
MARCELLUS SHALE CORE
Net Proved Reserves 8.5 TcfeNet 3P Reserves 26.4 TcfePre-Tax 3P PV-10 $19.4 BnNet Acres 389,000Undrilled 3P Locations 3,131
UPPER DEVONIAN SHALE
Net Proved Reserves 40 BcfeNet 3P Reserves 4.6 TcfePre-Tax 3P PV-10 NMUndrilled 3P Locations 1,116
WV/PA UTICA SHALE DRY GASNet Resource 9.5 TcfNet Acres 167,000Undrilled Locations 1,390
0
5
10
15
20
25
Rig
Cou
nt
Operators
SW Marcellus + Utica Rigs(3)
1. 2012, 2013 and 6/30/2014 proved reserves assuming ethane rejection.2. Midpoint of production guidance of 990-1,010 MMcfe/d for 2014.3. Based on 45-50% production growth targets for 2015 and 2016. 4. Per current First Call median estimate from Bloomberg.
0
600
1,200
1,800
2,400
2010 2011 2012 2013 1H 2014 3Q2014
4Q 2014
2015E 2016E
Marcellus Utica Guidance
30 124 239522
(2)
1,237
838
1,500
2,200
(3) (3)
1,080
0
2,000
4,000
6,000
8,000
10,000
2010 2011 2012 2013 6/30/2014
Marcellus Utica
677
2,844
4,283
7,632
(1) (1) (1)
9,107
17
AVERAGE NET DAILY PRODUCTION (MMcfe/d)NET PROVED SEC RESERVES (Bcfe)
0255075
100125150175200225
2010 2011 2012 2013 2014E
Marcellus Utica
29 36
86
162
215
GROWTH – STRONG TRACK RECORD
OPERATED GROSS WELLS SPUD EBITDAX ($MM)
$0
$200
$400
$600
$800
$1,000
$1,200
$1,400
2010 2011 2012 2013 2014E
$28$160
$285
$649
$1,145
(4)
45-50% Annual Growth Target
92% Growth –Guidance of
1,000 MMcfe/dfor 2014E
Assembled a 524,000 net acre position in the core of the Marcellus and Utica shale plays over the past 6 years
December 2008
Net Acreage 118,000
Net Production (MMcfe/d) NM
3P Reserves (Bcfe) NM
3P PV-10 ($MM) NM
Rigs Running NM
Dec 2008 Dec 2011 Dec 2014
December 2011(1)
Net Acreage 214,000
Net Production (MMcfe/d) 167
3P Reserves (Bcfe) 18,400
3P PV-10 ($MM) $9,000
Rigs Running 5
December 2014(1)
Net Acreage 524,000
Net Production (MMcfe/d) 1,080
6/30/14 3P Reserves (Bcfe) 37,500
6/30/14 3P PV-10 ($MM) $25,900
Rigs Running 21
1. Reserves and PV-10 data for December 2014 reflect data as of 6/30/2014 and for December 2011 reflects data as of 12/31/2011. Daily net production for December 2011 and December 2014 is for third quarter respectively.
LAND – MOST ACTIVE LAND ORGANIZATIONIN APPALACHIA
18
118,000 118,000 118,000 162,000 189,000 213,000
285,000 371,000
420,000 450,000 486,000
524,000
0
100,000
200,000
300,000
400,000
500,000
600,000
12/2008 12/2009 6/2010 12/2010 6/2011 12/2011 6/2012 12/2012 6/2013 12/2013 6/2014 12/2014
Antero Net Acreage
Utica Marcellus
19
LIQUIDS-RICH – LARGEST CORE POSITION
Source: Core outlines and peer net acreage positions based on peer presentations, news releases and 10-K/10-Qs.1. Pending Southwestern Energy acquisition of Chesapeake southern Marcellus acreage position.
(1)
Antero has the largest liquids-rich core position in Appalachia ≈366,000 net acres
TAKEAWAY – LARGEST FIRM TRANSPORTATION AND PROCESSING PORTFOLIO IN APPALACHIA
Odebrecht / Braskem30 MBbl/d Commitment
Ascent Cracker(Pending Final
Investment Decision)
Antero Long Term Firm Processing & Takeaway Position (2018) – Accessing Favorable Markets
Mariner East II62 MBbl/d Commitment(2)
Marcus Hook Export
Shell25 MBbl/d CommitmentBeaver County Cracker
(Pending FinalInvestment Decision)
Sabine Pass (Trains 1-4)50 MMcf/d per Train
1. 2015 and 2016 futures basis, respectively, provided by Wells Fargo dated 11/28/2014. Favorable gas markets shaded in green.2. As an anchor shipper on Mariner East II, Antero has the right to expand its NGL commitment with notice to operator.
Chicago(1)
+$0.18 / $(0.04)
CGTLA(1)
$(0.10) / $(0.09)
Dom South(1)
$(1.32) / $(1.16)
TCO(1)
$(0.29) / $(0.47)
20
4 Bcf/dFirm Gas TakeawayBy 2018
Cove Point
788 1,168 943 780 1,073 818
$4.97$4.38 $4.46 $4.34 $4.50 $4.41
$4.07 $3.82 $3.83 $3.96 $4.09 $4.21
$0.00$1.00$2.00$3.00$4.00$5.00$6.00$7.00
0
200
400
600
800
1,000
1,200
4Q 2014 2015 2016 2017 2018 2019
BBtu/d $/MMBtu
21
Average Index Hedge Price(1)Hedged Volume Current NYMEX Strip(2)
COMMODITY HEDGE POSITION
1. Reflects weighted average index price per annum based on volumes hedged and 6:1 gas to oil ratio. Antero has hedged 3,000 Bbl/d of oil for 2014 and 2,000 Bbl/d of propane for 2015. 2. As of 11/28/2014.3. Percentage of net gas equivalent production target hedged for respective years.
~$1,109 million mark-to-market unrealized gain based on current prices 1.8 Tcfe hedged from October 1, 2014 through year-end 2019 and 256 Bcf of TCO basis hedges from 2015 to 2017
$72 MM $345 MM $349 MM $123 MM $160 MM $60 MM
Mark-to-Market Value(2)
LIQUIDITY – LARGEST GAS HEDGE POSITION IN U.S. E&P + STRONG FINANCIAL LIQUIDITY
$3,000
$2,012
($1,505)
($332) $6 $843
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Credit Facility9/30/2014
Bank Debt9/30/2014
L/Cs Outstanding9/30/2014
Cash9/30/2014
AM IPOProceeds
to AR
Pro FormaLiquidity
9/30/2014
AR LIQUIDITY POSITION ($MM) AM LIQUIDITY POSITION ($MM)
$1,000$1,250
$0 $0 $0
$250
$0
$500
$1,000
$1,500
$2,000
$2,500
$3,000
Credit Facility9/30/2014
Bank Debt9/30/2014
L/Cs Outstanding9/30/2014
Cash9/30/2014
AM IPO Proceeds
to AM
Pro FormaLiquidity
9/30/2014
≈ 78% of 2015ETarget
Production(3)
≈ 43% of 2015ETarget
Production(3)
Over $3 billion of combined AR and AM financial liquidity as of 9/30/2014, pro forma for AM IPO closed on 11/10/2014
1. Gulf Coast differential represents contractual deduct to NYMEX-based sales.2. Includes firm sales. 3. Includes natural gas hedges.4. Source: Public data from 3Q 2014 10-Qs. Peers include Cabot Oil & Gas, CONSOL Energy, EQT Corp. and Range Resources. 5. Includes realized hedge gains and losses. Operating costs include lease operating expenses, production taxes, gathering, processing and firm transport costs and general and administrative costs. 4-year
proved reserve average all-in F&D from 2010-2013. Calculation = (Development costs + exploration costs + leasehold costs) / Total reserves added (2013 ending reserves – 2010 beginning reserves + 4-year reserve sales – 4-year reserve purchases + 4-year accumulated production). AR price realization includes $0.04 of midstream revenues.
$4.16 $3.97
$0.58 $0.95 $0.74 $0.77 $0.81
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
Antero Peer 1 Peer 2 Peer 3 Peer 4
$/M
cfe
LOE Production Taxes GPT G&A EBITDAX 4-year Avg. All-in F&D ($/Mcfe)
$4.96
$3.25
$4.48
$2.93
$2.40$2.64
$2.11 $2.09
22
Region3Q 2014 % Sales
Average NYMEX Price
AverageDifferential(2)
AverageBTU Upgrade
Hedge Effect
Average 3Q 2014Realized Gas Price(3)
Average Premium/Discount
TCO 39% $4.06 $(0.12) $0.48 $0.58 $5.00 $0.94Dom South/TETCO 41% $4.06 $(1.83) $0.32 $1.10 $3.65 $(0.41)Gulf Coast(1) 10% $4.06 $(0.25) $0.39 $0.01 $4.21 $0.15Chicago 10% $4.06 $(0.07) $0.52 - $4.51 $0.45Total Wtd. Avg. 100% $4.06 $(0.84) $0.41 $0.68 $4.31 $0.25
REALIZATIONS – HIGHEST REALIZATIONS & MARGINSAMONG LARGE-CAP APPALACHIAN PEERS
3Q 2014 Natural Gas Realizations ($/Mcf)
3Q 2014 Natural Gas Realizations(3) 3Q 2014 Price Realization & EBITDAX Margin vs F&D(4)
$4.31
$4.12$3.66 $3.62 $3.60
$2.98 $2.87 $2.75
$0.00
$2.00
$4.00
$6.00
AR EQT GPOR RRC CNX RICE ECR COG
$/M
cf
3Q 2014 NYMEX = $4.06/Mcf
AR Peer 1 Peer 2 Peer 3 Peer 4
DOM S28% DOM S
22% DOM S8%
TETCO M24% TETCO M2
8%
TETCO M210%
TCO43%
TCO23%
TCO15%
NYMEX9%
NYMEX7%
NYMEX10%
Gulf Coast18% Gulf Coast
47%
Chicago16% Chicago
22%
Chicago10%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
($/Mcf) 4Q 2014E 2015E 2016ENYMEX Strip Price(1) $4.00 $3.82 $3.83Basis Differential to NYMEX(1) $(0.52) $(0.45) $(0.35)BTU Upgrade(5) $0.35 $0.34 $0.35 Estimated Realized Hedge Gains $0.67 $0.63 $0.45Realized Gas Price with Hedges $4.50 $4.34 $4.28 Premium to NYMEX +$0.50 +$0.52 +$0.45Liquids Impact(6) +$0.54 +$0.50 +$0.58Premium to NYMEX w/ Liquids +$1.04 +$1.02 +$1.03Realized Gas-Equivalent Price $5.04 $4.84 $4.86
4. Represents 60,000 MMBtu/d of TCO index hedges and 205,000 MMBtu/d of TCO basis hedges that are matched with NYMEX hedges for presentation purposes.
5. Assumes ethane rejection resulting in 1100 BTU residue sales gas.6. Represents equivalent price upgrade associated with NGL (C3+) and oil production.
REALIZATIONS – REALIZED PRICE “ROAD MAP”
1. Based on 11/28/2014 strip pricing.2. Differential represents contractual deduct to NYMEX-based firm sales contract.3. Represents 120,000 MMBtu/d of TCO index hedges and 390,000 MMBtu/d of TCO basis hedges that are
matched with NYMEX hedges for presentation purposes.
4Q 2014Basis(1)
2015 Basis(1)
2016 Basis(1)
4Q 2014Hedges
2015Hedges
2016Hedges
Mar
kete
d %
of T
arge
t Re
sidu
e G
as P
rodu
ctio
n
+$0.33/MMBtu
$(0.25)/MMBtu(2)
$(1.63)/MMBtu
$(0.07)/MMBtu
+$0.18/MMBtu
$(0.25)/MMBtu(2)
$(1.32)/MMBtu
$(0.29)/MMBtu
$(0.04)/MMBtu
$(0.25)/MMBtu(2)
$(1.16)/MMBtu
$(0.46)/MMBtu
$(0.10)/MMBtu
$(0.09)/MMBtu
340,000 MMBtu/d
@ $4.18/MMBtu
160,000 MMBtu/d
@ $5.27/MMBtu
210,000 MMBtu/d
@ $5.24/MMBtu
40,000 MMBtu/d
@ $4.00/MMBtu
230,000 MMBtu/d
@ $5.60/MMBtu
510,000 MMBtu/d
@ $3.87/MMBtu(3)
170,000 MMBtu/d
@ $4.09/MMBtu
272,500 MMBtu/d
@ $5.35/MMBtu
265,000 MMBtu/d
@ $3.89/MMBtu(4)
$0.56/Mcfe in estimated hedge gains(1)
70% exposure to favorable price indices
$0.67/Mcfe in estimated hedge gains(1)
68% exposure to favorable price indices
$0.43/Mcfe in estimated hedge gains(1)
82% exposure to favorable price indices
Antero is forecasting realized gas prices including hedges at a premium to NYMEX strip prices for Q4 2014 through 2016, assuming current strip prices and basis, existing firm transportation and hedges, and targeted 2015 and 2016 production figures
$(1.57)/MMBtu
$(1.18)/MMBtu
$(1.05)/MMBtu
Wtd. Avg.Basis ($0.52)
770,000 MMBtu/d@ $4.97/MMBtu
Wtd. Avg.Basis $(0.45)
1,160,000 MMBtu/d@ $4.34/MMBtu
Wtd. Avg.Basis $(0.35)
942,500 MMBtu/d@ $4.46/MMBtu
10,000 MMBtu/d
@ $3.98/MMBtu
4Q 2014E 2015E 2016E
23
380,000 MMBtu/d
@ $3.88/MMBtu
235,000 MMBtu/d
@ $4.00/MMBtu
50,000 MMBtu/d
@ $4.72/MMBtu
0%
20%
40%
60%
80%
248
143 87
265 254
14%
57%76%
50% 45%
050100150200250300
0%
25%
50%
75%
100%
Condensate Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3P
Loca
tions
RO
R
Locations ROR
MARCELLUS SSL WELL ECONOMICS(1)
727896
633
875
55%37%
17% 16%
0
200
400
600
800
1000
0%
25%
50%
75%
100%
Highly-RichGas/
Condensate
Highly-RichGas
Rich Gas Dry Gas
Tota
l 3PL
loca
tions
RO
R
Locations ROR
MULTI-YEAR DRILLING INVENTORY SUPPORTS LOW RISK, HIGH RETURN GROWTH PROFILE
Large 3P Drilling Inventory of High Return Projects(3)
1. Pre-tax well economics based on 11/28/2014 natural gas and WTI strip pricing for 2014-2019, flat thereafter, NGLs at 55% of oil price and applicable firm transportation costs. 2. Adjusted for additional 130 gross locations acquired as of 11/3/2014.3. Source: Credit Suisse report dated October 2014 – After-tax internal rate of return based on 10/27/2014 strip pricing.
59%57%
71%
21%
Inte
rnal
Rat
e of
Ret
urn
(%)
37%
24
UTICA WELL ECONOMICS(1)(2)
1,000
72% of Marcellus locations are processable (1100-plus Btu) 75% of Utica locations are processable (1100-plus Btu)
3,000 Antero Liquids-Rich Locations
37%
2H 2014 / 2015Drilling Plan
1,129 Antero Dry Gas Locations
WORLD CLASS MARCELLUS SHALE DEVELOPMENT PROJECT
100% operatedOperating 14 drilling rigs
including 5 intermediate rigs389,000 net acres in
Southwestern Core (73% includes processable rich gas assuming an 1100 Btu cutoff)– 50% HBP with additional 27%
not expiring for 5+ years339 horizontal wells completed
and online– Laterals average 7,400’– 100% drilling success rate5 plants in-service at Sherwood
Processing Complex capable of processing 1 Bcf/d of rich gas−Over 800 MMcf/d being
processed currentlyNet production of 937 MMcfe/d in
3Q 2014, including 17,300 Bbl/d of liquids 3,131 future drilling locations in
the Marcellus (2,256 or 72% are processable rich gas)26.4 Tcfe of net 3P (18% liquids),
includes 8.5 Tcfe of proved reserves (assuming ethane rejection) Highly-Rich Gas
119,000 Net Acres896 Gross Locations
Rich Gas91,000 Net Acres
633 Gross Locations
Dry Gas104,000 Net Acres
875 Gross Locations
Highly-Rich/Condensate75,000 Net Acres
727 Gross Locations
HEFLIN UNIT30-Day Rate
2H: 21.4 MMcfe/d (21% liquids)
CONSTABLE UNIT30-Day Rate
1H: 14.3 MMcfe/d (26% liquids)
142 Horizontals Completed30-Day Rate8.1 MMcf/d
6,915’ average lateral length
SherwoodProcessing
Complex
Source: Company presentations and press releases. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held. Note: Rates in ethane rejection.
NERO UNIT30-Day Rate
1H: 18.2 MMcfe/d(27% liquids)
BEE LEWIS PAD30-Day Rate
4-well combined 30-Day Rate of
67 MMcfe/d (26% liquids)
RJ SMITH PAD30-Day Rate
4-well combined 30-Day Rate of
56 MMcfe/d (21% liquids)
25
MHR COLLINS UNIT30-Day Rate
4-well average9.3 MMcfe/d (26% liquids)
HENDERSHOT UNIT30-Day Rate
1H: 16.3 MMcfe/d2H: 18.1 MMcfe/d
(29% liquids)
HORNET UNIT30-Day Rate
1H: 21.8 MMcfe/d (26% liquids)
HINTERER UNIT30-Day Rate
1H: 12.9 MMcfe/d(20% liquids)
Source: Company presentations and press releases. Note: Antero acreage position reflects townships in which greater than 3,000 net acres are held. Note: Third party peak rates assume ethane recovery; Antero 30-day rates in ethane rejection.1. For non-Antero wells, Antero has converted rich gas rates where BTU has been disclosed to NGLs, assuming ethane recovery. Where BTU has not been disclosed, Antero has estimated BTU and gas
composition.2. 30-day rate reflects restricted choke regime.
• 100% operated• Operating 7 rigs including 2 intermediate rigs• 135,000 net acres in the core rich gas/
condensate window (76% includes processable rich gas assuming an 1100 Btu cutoff)
– 20% HBP with additional 79% not expiring for 5+ years
• 44 operated horizontal wells completed and online in Antero core areas
− 100% drilling success rate• 3 plants at Seneca Processing Complex capable
of processing 600 MMcf/d of rich gas
− Over 500 MMcf/d being processed currently, including third party production
• Net production of 143 MMcfe/d in 3Q 2014 including 7,700 Bbl/d of liquids− Seneca 3 processing plant online in July
2014− Fourth third party compressor station
expected in-service December 2014 with a capacity of 120 MMcf/d
• 997 future gross drilling locations (743 or 75% are processable gas)
• 6.4 Tcfe of net 3P (13% liquids), includes 537 Bcfe of proved reserves (assuming ethane rejection)
LEADING UTICA SHALE CORE POSITION DELIVERS CONDENSATE AND NGLS
26
Utica Shale Industry Activity(1)
CadizProcessing
Plant
NORMAN UNIT30-Day Rate
2 wells average17.2 MMcfe/d (17% liquids)
RUBEL UNIT30-Day Rate
3 wells average17.3 MMcfe/d(22% liquids)
GULFPORT24-Hour IP
McCort1-28H, 2-28H, Stutzman 1-14H
Average 13.1 MMcf/d + 922 Bbl/d NGL
+ 21 Bbl/d Oil
GULFPORT24-Hour IP
Wagner 1-28H, Shugert 1-1H, 1-12H
Average 21.0 MMcf/d + 2,270 Bbl/d NGL
+ 292 Bbl/d Oil
Utica Core Area
GARY UNIT30-Day Rate
3 wells average24.3 MMcfe/d(22% liquids)
Highly-Rich/Cond19,000 Net Acres
143 Gross Locations
Highly-Rich Gas20,000 Net Acres
87 Gross Locations
Rich Gas31,000 Net Acres
265 Gross Locations
Dry Gas32,000 Net Acres
254 Gross Locations
NEUHART UNIT 3H30-Day Rate16.4 MMcfe/d(56% liquids)
Condensate33,000 Net Acres
248 Gross Locations
DOLLISON UNIT 1H30-Day Rate19.0 MMcfe/d(36% liquids)
MYRON UNIT 1H30-Day Rate26.0 MMcfe/d(50% liquids)
SenecaProcessingComplex
LAW UNIT30-Day Rate
2 wells average15.7 MMcfe/d(48% liquids)
SCHAFER UNIT30-Day Rate(2)
2 wells average13.7 MMcfe/d(46% liquids)
McDOUGAL UNIT30-Day Rate
2 wells average20.6 MMcfe/d(14% liquids)
APPENDIX
27
MAINTENANCE CAPITAL METHODOLOGY
• Maintenance Capital Calculation Methodology– Estimate the number of new well connections needed during the forecast period in order to offset the natural
production decline and maintain the average throughput volume on our system over the LTM period
– (1) Compare this number of well connections to the total number of well connections estimated to be made during such period and
– (2) Designate an equal percentage of our estimated gathering capital expenditures as maintenance capital expenditures
28Source: Antero Midstream S-1; maintenance capital calculation per management estimates.
Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain, over the long term, our operating capacity or revenue
• Illustrative Example
LTM Forecast Period
Decline of LTM average throughput to be replaced with production volume
from new well connections
• NTM Maintenance Capital ($ in millions)
NTM Wells to be placed online 183Wells required to maintain LTM throughput 10.3
% of total wells to be placed online 5.6%
NTM Low-Pressure Gathering Capital $260.4
Forecasted NTM Maintenance Capital $14.7
LTM ProductionNTM Production ForecastAverage LTM Production
CONTRACTUAL ARRANGEMENTS WITH ANTERO PROVIDE SIGNIFICANT GROWTH OPPORTUNITIES
29
• Gathering and Compression – 20-year agreement
– Dedication of all current and future AR acreage in West Virginia, Ohio, and Pennsylvania, outside of current
third-party commitments
– Option to gather and compress natural gas produced by Antero on any future acquired acreage outside of the
aforementioned areas
– Low-pressure gathering fee of $0.30/Mcf(1)
– High-pressure gathering fee of $0.18/Mcf(1)
– Compression fee of $0.18/Mcf(1)
– Minimum volume commitments on newly constructed high-pressure lines and compressor stations, respectively
– Compression minimum volume commitments of 70% of design capacity
– High-pressure gathering minimum volume commitments of 75% of design capacity
• Processing (“ROFO”)– Right of first offer on future processing services
– Agreement stipulates that AR has agreed not to procure any gas processing or NGLs fractionation,
transportation or marketing services (other than production subject to a pre-existing dedication) without first
offering AM the right to provide such services
1. All subject to CPI-based adjustments.
FORECASTED CASH FLOW AVAILABLEFOR DISTRIBUTIONS
30
Next 12 Months Ending($ in millions) September 30, 2015
Antero Midstream Adjusted EBITDA(1) $136.2
Less:
Cash interest, net ($2.7)
Expansion capital expenditures ($587.3)
Ongoing maintenance capital expenditures ($14.7)
Add:
Borrowings and cash to fund expansion capital expenditures $587.3
Minimum estimated cash available for distribution $118.8
Assumed Coverage 1.15x
Distributed Cash Flow $103.3
Distribution per Unit(2) $0.68
1. Includes incremental public company expenses.2. Based on 151.9 million units outstanding.
AM OPPORTUNITY SET
31
ACTIVITY CURRENTLY DEDICATED TO AM
Gas Gathering and Compression (High-Pressure and Low-Pressure)
Condensate and Liquids Gathering
Fresh Water Distribution System
Processing, Fractionation, Transportation, Marketing
and Other Services
• Existing dedication of ≈390,000 acres• Option to expand outside dedicated area, including ROFR• Minimum Volume Commitments on newly constructed
compression (70%) and high pressure gathering (75%)
Regional Pipeline Projects • Option to participate up to 15% in another regional pipeline project
• Relevant liquids production can be added to the existing dedication; AR must request AM to provide a fee proposal
• Option to acquire at fair market value 100% of AR’s fresh water distribution assets covering 524,000 net acres, including ROFO on future services
• AR must request a bid from AM and can only reject if third party service fees are lower. AM has right to match lower fee offer.
0.0%
25.0%
50.0%
75.0%
100.0%
125.0%
150.0%
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Pre-
Tax
RO
R (%
)
Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas
MARCELLUS ROR% AND GAS PRICE SENSITIVITY
321. Assumes 11/28/2014 strip pricing, market differentials and relevant transportation cost.
• Large portfolio of Highly-Rich Gas/Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 11/28/2014 WTI strip pricing for 2014-2019, flat thereafter; NGL price of 55% of WTI
NYMEX Price Sensitivity(1)
ROR% at 5-Year Strip
Highly-Rich Gas/Condensate: 55%
Highly-Rich Gas: 37%
Rich Gas: 17%
Dry Gas: 16%727 Locations
896 Locations
633 Locations
875 Locations
Antero Rigs Employed
2H 2014 / 2015Drilling Plan
0.0%
50.0%
100.0%
150.0%
200.0%
$3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00
Condensate Highly-Rich Gas/Condensate Highly-Rich Gas Rich Gas Dry Gas Antero Rigs Employed
UTICA ROR% AND GAS PRICE SENSITIVITY
33
NYMEX Price Sensitivity(1)
87 LocationsROR% at 5-Year Strip
Condensate: 14%
Highly-Rich Gas/Condensate: 57%
Highly-Rich Gas: 76%
Rich Gas: 50%
Dry Gas: 45%
• Large portfolio of Condensate to Dry Gas locations• Focused on drilling highly economic rich gas locations – rig symbols represent current rig location by Btu regime• Assumes 11/28/2014 WTI strip pricing for 2014-2019, flat thereafter; NGL price of 55% of WTI
1. Assumes 11/28/2014 strip pricing, market differentials and relevant transportation cost.
265 Locations
143 Locations
254 Locations
248 Locations
2H 2014 / 2015Drilling Plan
LARGE UTICA SHALE DRY GAS POSITION
34
Antero has ≈200,000 net acres of exposure to Utica dry gas play− 32,000 net acres in Ohio with net 3P reserves of 1.9 Tcf as of
6/30/2014− 167,000 net acres in West Virginia and Pennsylvania with net
resource of 9.5 Tcf as of 6/30/2014 (not included in 37.5 Tcfe of net 3P reserves)
− 1,390 locations underlying current Marcellus Shale leasehold in West Virginia and Pennsylvania as of 9/30/2014
Expect to drill and complete a Utica Shale dry gas well in West Virginia in 2015
Other operators have reported strong Utica Shale dry gas results including the following wells:
ChesapeakeHubbard BRK #3H
3,550’ LateralIP 11.1 MMcf/d
HessPorterfield 1H-17
5,000’ LateralIP 17.2 MMcf/d
GulfportIrons #1-4H
5,714’ LateralIP 30.3 MMcf/d
EclipseTippens #6H5,858’ Lateral
IP 23.2 MMcf/d
Magnum HunterStalder #3UH5,050’ Lateral
IP 32.5 MMcf/d
AnteroPlanned
Utica Well2015Well Operator
IP(MMcf/d)
Lateral Length (Ft)
Stewart Winland 1300U Magnum Hunter 46.5 5,289
Bigfoot 9H Rice Energy 41.7 6,957
Stalder #3UH Magnum Hunter 32.5 5,050
Irons #1-4H Gulfport 30.3 5,714
Pribble 6HU Stone Energy ≈30 3,605
Simms U-5H Gastar 29.4 4,447
Conner 6H Chevron 25.0 6,451
Tippens #6H Eclipse 23.2 5,858
Porterfield 1H-17 Hess 17.2 5,000
Hubbard BRK #3H Chesapeake 11.1 3,550
1. Antero acreage position reflects tax districts in which greater than 3,000 net acres are held in OH, WV and PA.
Magnum HunterStewart Winland 1300U
5,289’ LateralIP 46.5 MMcf/d
RangeUtica Well
Flow Testing
ChevronConner 6H
6,451’ LateralIP 25.0 MMcf/d
GastarSimms U-5H4,447’ Lateral
IP 29.4 MMcf/d
Utica Shale Dry Gas Acreage in OH/WV/PA(1)
RiceBigfoot 9H
6,957’ LateralIP 41.7 MMcf/d
Utica Shale Dry GasWV/PA
Net Resource9.5 Tcf
1,390 Gross Locations167,000 Net Acres
Utica Shale Dry GasOhio
3P Reserves1.9 Tcf
226 Gross Locations32,000 Net Acres
Utica Shale Dry GasTotal OH/WV/PA
Net Resource11.4 Tcf
1,616 Gross Locations≈200,000 Net Acres
Stone EnergyPribble 6HU
3,605’ LateralIP ≈30 MMcf/d
ChesapeakeUtica Well
Drilling
RiceBlue Thunder
10H, 12H≈9,000’ Lateral
Needed to make up for base declines in conventional and GOM production
? ??
3,000 Antero Drilling Locations
Perm
ian
Nio
brar
a
Gra
nite
Was
h
Bar
nett
Hay
nesv
ille
U.S. INCREMENTAL GAS SUPPLY BREAK-EVEN PRICE CURVE(1)
35
Low cost, liquids-rich Utica and Marcellus Shales will remain attractive in most commodity price environments
Utica Shale
SW (Rich) Marcellus
Shale
1. Source: Credit Suisse report dated January 2014 – Break even price for 15% after tax rate-of-return; assumes $90.00/Bbl WTI
NE (Dry) Marcellus
ShaleEagle Ford
Shale
MARCELLUS & UTICA – ADVANTAGED ECONOMICS
CAUTIONARY NOTE
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserve estimates (collectively, “3P”). Antero has provided internally generated estimates for proved, probable and possible reserves in this presentation in accordance with SEC guidelines and definitions, which have been audited by Antero’s third-party engineers. Unless otherwise noted, reserve estimates as of June 30, 2014 assume ethane rejection and strip pricing.
Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
In this presentation:
• “3P reserves” refer to Antero’s estimated aggregate proved, probable and possible reserves as of June 30, 2014. The SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.
• “EUR,” or “Estimated Ultimate Recovery,” refers to Antero’s internal estimates of per well hydrocarbon quantities that may bepotentially recovered from a hypothetical future well completed as a producer in the area. These quantities do not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules.
• “Condensate” refers to gas having a heat content between 1250 BTU and 1300 BTU in the Utica Shale.
• “Highly-rich gas/condensate” refers to gas having a heat content between 1275 BTU and 1350 BTU in the Marcellus Shale and 1225 BTU and 1250 BTU in the Utica Shale.
• “Highly-rich gas” refers to gas having a heat content between 1200 BTU and 1275 BTU in the Marcellus Shale and 1200 BTU and 1225 BTU in the Utica Shale.
• “Rich gas” refers to gas having a heat content of between 1100 BTU and 1200 BTU.
• “Dry gas” refers to gas containing insufficient quantities of hydrocarbons heavier than methane to allow their commercial extraction or to require their removal in order to render the gas suitable for fuel use.
36
Regarding Hydrocarbon Quantities