Third Quarter 2016 Earnings Call Presentation October 27,...
Transcript of Third Quarter 2016 Earnings Call Presentation October 27,...
Third Quarter 2016 Earnings Call Presentation October 27, 2016
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 Resources”). These statements are based on certain assumptions made by the Partnership and Antero Resources 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. 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, 2015 and in the Partnership’s subsequent filings with the SEC.
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 Resources’ expected future growth, Antero Resources’ 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 of production, cash flow and access to capital, the timing of development expenditures, and the other risks discussed or referenced under the heading “Item 1A. Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 and in the Partnership’s subsequent filings with the SEC.
Our ability to make future distributions is substantially dependent upon the development and drilling plan of Antero Resources, which itself is substantially dependent upon the review and approval by the board of directors of Antero Resources of its capital budget on an annual basis. In connection with the review and approval of the annual capital budget by the board of directors of Antero Resources, the board of directors will take into consideration many factors, including expected commodity prices and the existing contractual obligations and capital resources and liquidity of Antero Resources at the time.
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 Partners LP is denoted as “AM” and Antero Resources Corporation is denoted as “AR” in the presentation, which are their respective New York Stock Exchange ticker symbols.
$0.170 $0.180 $0.190 $0.205
$0.235 $0.250
$0.265 1.1x
1.2x 1.3x
1.4x
1.8x
1.6x 1.7x
2.0x
0.0x
0.5x
1.0x
1.5x
2.0x
2.5x
$0.000
$0.100
$0.200
$0.300
$0.400
$0.500
$0.600
4Q14A 1Q15A 2Q15A 3Q15A 4Q15A 1Q16A 2Q16A 3Q16A 4Q16E 1Q17E 2Q17E 3Q17E 4Q17E
Distribution Per Unit (Left Axis) DCF Coverage (Right Axis)
$0.220
2
• Antero Midstream is targeting 28% to 30% annual distribution growth through 2017 • AM has delivered on those targets with DCF coverage of 2.0x in the third quarter of 2016
Note: Future distributions subject to AM Board approval.
TOP TIER DISTRIBUTION GROWTH AND COVERAGE
77
125 140
186
105 95 67
113 97 105
140
0
50
100
150
200
250 Utica Marcellus
36 41 116
222 358
454 435 478 606 658
777
0
200
400
600
800
1,000
1,200 Utica Marcellus
126 266
531
908 1,134 1,197 1,216 1,195 1,222 1,253
1,351
0200400600800
1,0001,2001,4001,6001,8002,000 Utica Marcellus
331 386 532
738 935 965 1,038 1,124
1,303 1,353 1,431
0200400600800
1,0001,2001,4001,6001,8002,000 Utica Marcellus
Low Pressure Gathering (MMcf/d)
Compression (MMcf/d)
High Pressure Gathering (MMcf/d)
Fresh Water Delivery Volumes (MBbl/d)
3
Note: Y-O-Y growth based on 3Q’15 to 3Q’16.
HIGH GROWTH MIDSTREAM THROUGHPUT
32 32 32 34
36 39
43 40
20
25
30
35
40
45
50
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 2016E
Bar
rels
of W
ater
Per
Fo
ot o
f Lat
eral
1,146 1,012 999
1,235 1,412
1,603 1,672 1,650
- 200 400 600 800
1,000 1,200 1,400 1,600 1,800 2,000
1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16 2016E
Sand
Pla
ced
Per F
oot o
f La
tera
l
4
AR Has Increased Proppant Load by Over 33% in the Marcellus and Utica
Pilot Testing Demonstrated Improved Recoveries While
Maintaining Well Density
AR Advanced Marcellus Completion Designs Utilizing 38 to 45 Barrels of Water Per Lateral Foot, a 19% to 41% Increase
New AR completion designs result in more water utilization driving higher AM fees, while increased proppant load generates encouraging early results with potential long-term benefits to AM throughput
ADVANCED COMPLETIONS DRIVE INCREASED WATER VOLUMES
ANTERO CLEARWATER FACILITY UPDATE
Antero Clearwater Facility – October 2016
Antero Clearwater advanced wastewater treatment facility is on schedule to be placed on line in late 2017 ‒ 2016 capital budget includes $130 million to be invested in 2016 ‒ Approximately 75% of the $275 million project cost will be invested by year-end 2016
Trucking bays
Crystallizers
Grit removal and pre-treatment
Crystallizer feed tank
Solids removal
5
Largest Oil and Gas Wastewater Treatment Facility in the World
$5.3 $4.6 $5.3 $4.7 $4.7 $4.7 $4.0 $3.9
$8.7 $7.8 $7.6
$7.1 $7.1 $5.6
$5.4 $5.2
$14.0
$12.4 $12.9 $11.8 $11.8
$10.3 $9.4 $9.1
$0
$2
$4
$6
$8
$10
$12
$14
$16
Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016
($M
M)
COMPLETION COST DRILLING COST
PROVEN TRACK RECORD OF WELL COST REDUCTIONS
6
Marcellus Well Cost Reductions for a 9,000’ Lateral ($MM)(1)
NOTE: Based on statistics for drilled and completed wells within each respective period. 1. Based on 200 ft. stage spacing. 2. Based on 175 ft. stage spacing.
35% Reduction in Utica well costs since
Q4 2014
Utica Well Cost Reductions for a 9,000’ Lateral ($MM)(2)
36% Reduction in Marcellus well costs
since Q4 2014
18% Reduction vs. well costs assumed in YE
2015 reserves
15% Reduction vs. well costs assumed in YE
2015 reserves
$4.0 $3.8 $3.4 $3.2 $3.2 $3.1 $2.8 $2.6
$8.3 $7.3 $7.4 $7.0 $7.0
$5.4 $5.3 $5.2
$12.3 $11.1 $10.8 $10.2 $10.2
$8.5 $8.1 $7.8
$0
$2
$4
$6
$8
$10
$12
$14
Q4 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 Q3 2016
($M
M)
COMPLETION COST DRILLING COST
$0.86 / 1,000’
$1.01 / 1,000’
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
Cum
ulat
ive
Wel
lhea
d G
as P
rodu
ctio
n (M
Mcf
)
Days
OPTIMIZING WELL RECOVERIES WITH ADVANCED COMPLETIONS
7
Vintage 2013 2014 2015 2016E Change Stage Length (Feet) 280 196 196 185 (34)% Proppant (Pounds/ft) 913 1,158 1,134 1,500 64% Water (Bbl/ft) 26 32 34 40 54% Wellhead EUR/1,000' 1.5 1.7 1.7 2.0 33% 1st Year Production (MMcf Cum.) 2,215 2,461 2,461 2,895 33% 2nd Year Production (MMcf Cum.) 3,357 3,730 3,730 4,389 33%
Marcellus Cumulative Gas Production Curves (Normalized to 9,000’ Lateral)
1.5
1.7
2.0
Wellhead EUR/1,000’
2016 Advanced Completions
Year 1
Driving value by drilling more productive wells in the Marcellus
Year 2
2.0 Bcf/1,000’ at the wellhead equates to 2.5 Bcfe/1,000’ after C3+ processing assuming 1275 Btu gas, and 3.2 Bcfe/1,000’ processed with
full ethane recovery
118 118 118 162 214 371
450 543 569
44 52
157
79 93
26 60
118 118 162 214
371 450
543 569 629
0
100
200
300
400
500
600
700
2008 2009 2010 2011 2012 2013 2014 2015 2016 PF
Net Acres Added Annually
Marcellus/Utica Net Acres Year-End
Antero continues to consolidate acreage in the core and expand its footprint in Appalachia as a pure-play operator
December 2008
Net Acreage 118,000
Net Production (MMcfe/d)
NM
3P Reserves (Bcfe)
NM
Dec 2008 Dec 2011
December 2011(1)
Net Acreage 214,000
Net Production (MMcfe/d)
167
3P Reserves (Bcfe)
18,400
December 2014(1)
Net Acreage 543,000
Net Production (MMcfe/d)
1,265
3P Reserves (Bcfe)
40,700
1. Net daily production for December 2011 and December 2014 is for the fourth quarter, respectively. 2. Pro forma for Pennsylvania divestiture announced on October 26th, 2016 and additional leasing and acquisitions year-to-date. 3. Net daily production represents third quarter 2016. 4. 3P reserves are as of year-end 2015, pro forma for announced acreage acquisitions.
LEADING CONSOLIDATOR IN APPALACHIA
8
YTD 2016
Net Acreage (2) 629,000
Net Production (MMcfe/d)(3)
1,875
3P Reserves (Bcfe) (4)
42,100
Dec 2014 2016 Pro Forma
Net Acres (000’s)
APPENDIX
9
ANTERO MIDSTREAM EBITDA RECONCILIATION
10
EBITDA Reconciliation Reconciliation of Net Income to Adjusted EBITDA and DCF (Dollars in thousands):
Three months ended September 30,
2015 2016
Net income $ 42,648 $
70,524
Add: Interest expense 2,044 5,303 Depreciation expense 21,561 26,136 Accretion of contingent acquisition consideration — 3,527 Equity-based compensation 5,284 6,599 Less: Equity in earnings of unconsolidated affiliate — (1,544) Adjusted EBITDA $ 71,537 $ 110,545
Less: Pre-water acquisition net income attributed to parent (7,841) —
Pre-water acquisition depreciation expense attributed to parent (6,485)
—
Pre-water acquisition equity-based compensation expense attributed to parent (1,079)
—
Pre-water acquisition interest expense attributed to parent (770) — Adjusted EBITDA attributable to the Partnership $ 55,362 $ 110,545 Less:
Cash interest paid, net – attributable to the Partnership (1,038) (4,043) Cash reserved for payment of income tax withholding upon vesting of Antero Midstream equity–based compensation awards — (1,000)
Maintenance capital expenditures (4,214) (4,638)
Add:
Cash distribution to be received from unconsolidated affiliate — 2,221
Distributable cash flow $ 50,110 $ 103,085
Total distributions declared $ 36,333 $ 51,702
DCF coverage ratio 1.38x 1.99x