DENVER, Feb. 13, 2019 /PRNewswire/ -- Antero
Resources Corporation (NYSE: AR) ("Antero," "Antero
Resources" or the "Company") today released its fourth quarter
and full year 2018 financial and operational results and announced
estimated proved reserves as of December
31, 2018. The relevant consolidated and consolidating
financial statements are included in Antero's Annual Report on Form
10-K for the year ended December 31, 2018, which has been
filed with the Securities and Exchange Commission
("SEC"). The relevant Stand-alone financial statements
are also included in Antero's Form 10-K within the Parent column of
the guarantor footnote (Note 17).
Fourth Quarter 2018 Highlights:
- Net daily gas equivalent production averaged a record 3,213
MMcfe/d (30% liquids), a 37% increase over the prior year period
and an 18% increase sequentially
- Liquids production averaged 162,077 Bbl/d, a 51% increase
over the prior year period and included oil production of 12,229
MBbl/d, C3+ NGL production of 102,860 MBbl/d and recovered ethane
production of 46,988 MBbl/d
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- Ethane production represented about 27% of the potential
recoverable ethane, with 122,000 Bbl/d remaining in the gas
stream
- Realized natural gas price averaged $3.83 per Mcf, a $0.19 premium to the NYMEX Henry Hub natural gas
price per MMBtu before hedges
- Realized natural gas equivalent price averaged $4.05 per Mcfe before hedges, driven by a
$0.22 per Mcfe uplift from liquids
production and prices
- Reported $122 million net
loss, or $0.39 per share,
$145 million Adjusted Net Income, or
$0.46 per diluted share, and
$175 million Stand-alone Adjusted Net
Income, or $0.56 per diluted share
(adjusted items are non-GAAP measures)
- Reported $584 million of
Adjusted EBITDAX and $475
million of Stand-alone Adjusted EBITDAX, representing a 34%
and 27% increase over the prior year period, respectively
(non-GAAP measures)
- Full year 2019 Stand-alone drilling and completion capital
expenditures expected to be at low end of guidance range and a 20%
reduction from 2018, due to fourth quarter 2018 pre-spend related
to roads, pads and facilities to be utilized in 2019 and
2020
Full Year 2018 Highlights:
- Net daily gas equivalent production averaged 2,709 MMcfe/d
(28% liquids), a 20% increase over the prior year
- Reported $398 million net
loss, or $1.26 per share,
$315 million Adjusted Net Income, or
$1.00 per diluted share, and
$365 million Stand-alone Adjusted Net
Income, or $1.15 per diluted share
(adjusted items are non-GAAP measures)
- Reported $2.0 billion of
Adjusted EBITDAX and $1.7
billion of Stand-alone Adjusted EBITDAX, representing a 42%
and 38% increase over the prior year period, respectively
(non-GAAP measures)
- Proved reserves increased 4% to 18.0 Tcfe at year-end 2018
compared to year-end 2017
- Standardized measure of proved reserves increased 21% to
$10.5 billion at year-end 2018
compared to year-end 2017
- SEC PV-10 proved reserve value increased 24% to $12.6 billion at year-end 2018 compared to
year-end 2017
- Proved developed reserves increased 22% to 10.4 Tcfe at
year-end 2018 compared to year-end 2017 and comprised 58% of total
proved reserves
- Future development costs for 7.6 Tcfe of proved undeveloped
reserves estimated to be $0.44 per
mcfe
- The previously announced simplification transaction between
Antero Midstream and AMGP expected to be completed in March 2019 results in a minimum of $300 million in cash proceeds to Antero
Resources
- Following the simplification transaction, Antero Resources
will no longer consolidate Antero Midstream's financial statements
in Antero Resources' consolidated financial statements, but will
account for its interest in New AM using the equity method of
accounting
- Reduced Stand-alone Net Debt to trailing twelve months
Stand-alone Adjusted EBITDAX to 2.2x at year-end 2018
Paul Rady, Chairman and CEO said,
"2018 was a great year for the Antero family, as we significantly
reduced leverage, grew production above the 3 Bcfe/d mark, and
announced the midstream simplification. We enter 2019 with
significant scale as the largest NGL producer and the
5th largest natural gas producer in the U.S.
Driven by the fourth quarter capital invested on pads and
roads, we expect to be in a position to invest at the low end of
our 2019 drilling and completion guidance range. The 2019
budget represents a 20% reduction relative to capital spending in
2018. On the liquids front, we are excited that Mariner East
2 has been placed in service. Our commitment on this pipeline
will allow us to move nearly half of our expected 2019 C3+ NGL
production to the export market and realize stronger NGL netback
pricing than we have received over the last several years. We
believe that our 2019 plan will deliver superior returns to
shareholders over the long-term while also keeping capital spending
within cash flow. "
Fourth Quarter 2018 Financial Results
As of December 31, 2018, Antero Resources owned a 53%
limited partner interest in Antero Midstream Partners LP ("Antero
Midstream"). Pro forma for the previously announced midstream
simplification transaction which is expected to close in
March 2019, Antero Resources will own
approximately 31% of the common stock of Antero Midstream
Corporation ("New AM" or "New Antero Midstream") assuming Antero
Midstream unitholders make a mixed consideration election in the
transaction. Antero Midstream's results are consolidated within
Antero Resources' results for 2018 and 2017, but will be
deconsolidated in 2019 assuming the close of the midstream
simplification transaction. Antero believes the
deconsolidation will provide more transparency to investors around
the Stand-alone upstream business and a greater ability to compare
results across Antero's peer group.
For the three months ended December 31, 2018, Antero
reported a net loss of $122 million,
or $0.39 per share, compared to net
income of $487 million, or
$1.54 per diluted share, in the prior
year period. Excluding items detailed in "Non-GAAP Financial
Measures," Adjusted Net Income was $145
million, or $0.46 per diluted
share, compared to $74 million, or
$0.23 per diluted share, in the prior
year period. Stand-alone Adjusted Net Income was $175 million, or $0.56 per diluted share, compared to $55 million, or $0.17 per diluted share, in the prior year
period.
Consolidated Adjusted EBITDAX was $584
million, a 34% increase compared to $437 million in the prior year period, and
Stand-alone Adjusted EBITDAX was $475
million, a 27% increase compared to $372 million in the prior year period.
The following table details the components of average net
production and average realized prices for the three months ended
December 31, 2018:
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Three Months Ended
December 31, 2018
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Natural Gas
(MMcf/d)
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Oil
(Bbl/d)
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C3+ NGLs
(Bbl/d)
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Ethane
(Bbl/d)
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Combined Natural
Gas Equivalent (MMcfe/d)
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Average Net
Production
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2,240
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12,229
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102,860
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46,988
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3,213
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Average Realized
Prices
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Natural Gas
($/Mcf)
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Oil
($/Bbl)
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C3+ NGLs
($/Bbl)
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Ethane
($/Bbl)
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Combined Natural
Gas Equivalent ($/Mcfe)
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Average realized
prices before settled derivatives
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$
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3.83
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$
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51.83
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$
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30.92
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$
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13.12
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$
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4.05
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Settled commodity
derivatives
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(0.10)
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(0.91)
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(0.32)
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—
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(0.08)
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Average realized
prices after settled derivatives
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$
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3.73
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$
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50.92
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$
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30.60
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$
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13.12
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$
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3.97
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NYMEX average
price
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$
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3.64
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$
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59.08
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$
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3.64
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Premium /
(Differential) to NYMEX
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$
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0.09
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$
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(8.16)
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$
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0.33
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Net daily natural gas equivalent production in the fourth
quarter averaged 3,213 MMcfe/d, including 162,077 Bbl/d of liquids
(30% of production), an increase of 37% compared to the prior year
period and an 18% increase sequentially. Natural gas
production averaged 2,240 MMcf/d, an increase of 32% over the prior
year period.
Total liquids production grew 51% compared to the prior year
period and 25% sequentially. Liquids revenue represented
approximately 34% of total product revenue before hedges. Oil
production averaged 12,229 Bbl/d, an increase of 97% over the prior
year period. C3+ NGLs production averaged 102,860 Bbl/d, an
increase of 47% over the prior year period. Recovered ethane
production averaged 46,988 Bbl/d, an increase of 50% over the prior
year period. Recovered ethane production represented
approximately 27% of potential ethane that could have been
recovered during the period, with the remaining 122,000 Bbl/d of
ethane remaining in the gas stream.
Antero's average realized natural gas price before hedging was
$3.83 per Mcf, a $0.19 per Mcf premium to the average NYMEX Henry
Hub price per MMBtu during the period, representing a 37% increase
versus the prior year period. Including hedges, Antero's
average realized natural gas price was $3.73 per Mcf, a $0.09 premium to the average NYMEX price,
reflecting the realization of a cash settled natural gas hedge loss
of $21 million, or $0.10 per Mcf.
Antero's average realized C3+ NGL price before hedging was
$30.92 per barrel, or 52% of the
average NYMEX WTI oil price, representing a 21% decline versus the
prior year period due to widening NGL differentials to Mont Belvieu
prior to the startup of Mariner East 2. Including hedges,
Antero's average realized C3+ NGL price was $30.60 per barrel, reflecting the realization of
a cash settled C3+ hedge loss of $3
million, or $0.32 per
barrel.
Antero's average realized oil price before hedging was
$51.83 per barrel, a $7.25 negative differential to the average NYMEX
WTI price and a 5% increase versus the prior year period. Including
hedges, the average realized oil price was $50.92 per barrel, reflecting the realization of
a cash settled WTI crude oil loss of $1.0
million, or $0.91 per
barrel. The average realized ethane price was $0.31 per gallon, or $13.12 per barrel, compared to $0.24 per gallon increase in the prior year
period, representing a 31% increase over $10.02 per barrel before hedging and a 29%
increase over $10.17 per barrel after
hedging.
Antero's average natural gas equivalent price including
recovered C2+ NGLs and oil, but excluding hedge settlements, was
$4.05 per Mcfe, representing a 17%
increase compared to the prior year period. Including hedges,
the Company's average natural gas equivalent price was $3.97 per Mcfe, a 4% increase from the prior year
period, primarily driven by higher realized natural gas
prices. The net cash settled commodity derivative loss on all
products was $25 million, or
$0.08 per Mcfe.
Total revenue in the fourth quarter was $1.0 billion, nearly equivalent to the prior year
period. Revenue included a $567
million commodity derivative fair value loss primarily
driven by a $370 million hedge
monetization, while the prior year included a $123 million commodity derivative fair value
gain. Revenue Excluding Unrealized Derivative Gains (Losses)
and Derivative Monetizations (non-GAAP) was $1.2 billion, a 35% increase versus the prior
year period. Please see "Non-GAAP Financial Measures" for a
description of Revenue Excluding Unrealized Derivative Gains
(Losses) and Derivative Monetizations.
The following table presents a calculation of Stand-alone
Adjusted EBITDAX margin and Adjusted EBITDAX margin (non-GAAP
measures), in each case on a per Mcfe basis with and without the
effect of cash receipts for settled commodity derivatives, and
reconciliation to realized price before cash receipts for settled
derivatives, the nearest GAAP financial measure. Adjusted
EBITDAX and Stand-alone Adjusted EBITDAX margin represents Adjusted
EBITDAX divided by production, a measure that helps investors to
more meaningfully evaluate and compare the results of Antero's
operations (both on a consolidated and Stand-alone basis) from
period to period by removing the effect of its capital structure
from its operating structure.
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Stand-alone
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Consolidated
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Three months
ended December 31,
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Three months
ended December 31,
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2017
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2018
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2017
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2018
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Adjusted EBITDAX
margin ($ per Mcfe):
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Realized price before
cash receipts for settled derivatives
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$
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3.46
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4.05
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$
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3.46
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4.05
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Gathering,
compression, and water handling and treatment revenues
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N/A
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N/A
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0.02
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0.02
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Distributions from
unconsolidated affiliates
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N/A
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N/A
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0.05
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0.06
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Distributions from
Antero Midstream
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0.16
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0.15
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N/A
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N/A
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Gathering,
compression, processing and transportation costs
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(1.71)
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(1.88)
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(1.30)
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(1.40)
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Lease operating
expense
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(0.17)
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(0.15)
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(0.15)
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(0.15)
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Marketing, net
(1)
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(0.13)
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(0.22)
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(0.13)
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(0.22)
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Production and ad
valorem taxes
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(0.11)
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(0.15)
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(0.11)
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(0.15)
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General and
administrative (excluding equity-based compensation)
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(0.13)
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(0.11)
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(0.17)
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(0.15)
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Adjusted EBITDAX
margin before settled commodity derivatives
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1.37
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1.69
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1.67
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2.06
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Cash receipts
(payments) for settled commodity derivatives
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0.35
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(0.08)
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0.35
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(0.08)
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Adjusted EBITDAX
margin ($ per Mcfe):
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$
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1.72
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1.61
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$
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2.02
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1.98
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(1)Includes cash payments for settled
marketing derivative losses of $0.02
per Mcfe in 2018.
Stand-alone per unit distributions from Antero Midstream
contributed $0.15 per Mcfe compared
to $0.16 per Mcfe in the prior year
period.
The per unit Stand-alone cash production expense for the quarter
included $1.88 per Mcfe for
gathering, compression, processing and transportation costs,
$0.15 per Mcfe for lease operating
costs, and $0.15 per Mcfe for
production and ad valorem taxes. Gathering, compression,
processing and transportation costs increased in the fourth quarter
due to higher transport costs related to new pipeline commitments
that were placed in service during the quarter and higher fuel
costs related to the higher gas sales price reported for the
quarter. New pipeline transportation included phase 2 of the
Rover pipeline that enabled Antero to transport natural gas
production from the Sherwood Processing Facility in West Virginia that had previously been shipped
to local Appalachia markets to the attractively priced Midwest and
Gulf Coast markets. Lease operating expenses decreased in the
fourth quarter of 2018 compared to the fourth quarter of 2017 due
to commissioning costs relating to Antero's Clearwater Facility
that occurred in the fourth quarter of 2017 that did not occur in
the fourth quarter of 2018.
Stand-alone per unit net marketing expense was $0.22 per Mcfe compared to $0.13 per Mcfe reported in the prior year
period. Net marketing expense increased due to higher
unutilized capacity related to incremental firm transportation that
was placed in service during the quarter. Net marketing
expense included a $0.02 per Mcfe
loss for settled marketing derivatives related to contracts that
had resulted in realized gains in the first quarter of 2018.
See Note 11 to the consolidated financial statements in Antero's
Annual Report on Form 10-K for the year ended December 31, 2018, for more information on these
contracts.
Stand-alone per unit general and administrative expense,
excluding non-cash equity-based compensation expense, decreased by
15% to $0.11 per Mcfe, compared to
the prior year period. General and administrative expense on
a per Mcfe basis decreased due to increased production
levels.
Realized price before cash receipts for settled derivatives was
$4.05 per Mcfe, a 17% increase from
the prior year period, primarily due to higher natural gas prices.
Stand-alone Adjusted EBITDAX margins before commodity
derivative were $1.69 per Mcfe, a 24%
increase from the prior year period, primarily due to higher
realized natural gas prices. Stand-alone Adjusted EBITDAX
margin after cash payments for settled commodity derivatives was
$1.61 per Mcfe, a 6% decrease from
the prior year period due to losses on commodity derivatives.
Consolidated Adjusted EBITDAX margin was $1.98 per Mcfe, compared to $2.02 per Mcfe in the prior year
period.
Stand-alone net cash provided by operating activities was
$729 million for the period.
Stand-alone Adjusted Operating Cash Flow was $775 million (non-GAAP), a 149% increase from the
prior year period, as cash flow included a $357 million in net proceeds from restructuring
the hedge portfolio. Excluding the hedge restructuring,
Stand-alone Adjusted Operating Cash Flow increased 34% over the
prior year period.
Consolidated net cash provided by operating activities was
$822 million for the period.
Consolidated Adjusted Operating Cash Flow was $863 million during the fourth quarter
(non-GAAP), including a $357 million
in net proceeds from restructuring the hedge portfolio, a 135%
increase compared to the prior year period. Excluding the
$357 million hedge restructuring,
consolidated Adjusted Operating Cash Flow increased by 38% over the
prior year period.
Operating Update
Fourth Quarter 2018
Marcellus Shale — Antero placed 39 horizontal
Marcellus wells to sales during the fourth quarter of 2018 with an
average lateral length of 10,600 feet and an average 30-day initial
rate per well of 21.6 MMcfe/day on choke. The 30-day average rate
per well included 1,268 Bbl/d of liquids, including oil, C3+ NGLs
and 25% ethane recovery. Notable results from the wells
placed to sales during the fourth quarter are below:
- A 10-well pad with an average lateral length of 9,700 feet and
average BTU of 1230, produced a 60-day average rate of 195 MMcfe/d,
including 1,400 Bbl/d of oil, 5,700 Bbl/d of C3+ NGLs and 3,000
Bbl/d of recovered ethane, at 25% ethane recovery
- A 1300 BTU well with a lateral length of 15,100 feet, produced
a 60-day rate of 29.0 MMcfe/d, including 660 Bbl/d of oil, 1,030
Bbl/d of C3+ NGLs and 410 Bbl/d of recovered ethane, at 25% ethane
recovery
During the period, Antero drilled 31 wells with an average
lateral length of 10,100 feet in an average of 11.5 total days from
spud to final rig release, which represents a 7% reduction in total
drilling time from 2017 levels. In addition, Antero drilled
an average of 5,100 lateral feet per day in the quarter, a 12%
increase in lateral footage performance compared to 2017.
Completion efficiencies further improved during the fourth quarter,
increasing to 5.7 stages per day from 5.5 stages per day in the
third quarter of 2018. Notably, Antero averaged 6.0 stages
per day in October and November. For the full year of 2018,
Antero averaged 5.2 stages per day, which is an increase of one
full stage per day from the 2017 average of 4.2 stages per day.
As recently announced, in 2019 Antero plans to operate an
average of five drilling rigs, including four large rigs, and an
average of four completion crews. Development plans reflect a
reduction of one to two completions crews on average from 2018
levels. In 2019, the Company expects to drill 120 to 130
wells and place 115 to 125 wells to service.
Glen Warren, President and CFO,
commented, " Entering 2019, our strategy centers on prudent
capital deployment, a continued focus on full-cycle rates of return
and generating free cash flow, all while maintaining a strong
balance sheet. We have already taken actions to demonstrate
our commitment to maintain discipline and achieve these priorities,
including a significant reduction in our 2019 drilling and
completion capital budget and a reduction in our land budget by 50%
from 2018 levels. Our significant scale, diversified product
portfolio, industry-leading natural gas hedge book and
wide-reaching firm transportation portfolio are amongst our
greatest assets, giving us the flexibility to thrive in a volatile
commodity price environment."
Fourth Quarter 2018 Capital Investment
Antero invested $363 million in
drilling and completion costs for the three months ended
December 31, 2018, which included $273
million for drilling and completion activity, $78 million for pads, roads and facilities and
$12 million for unit leasehold and
permitting costs. The increased activity related to pads,
roads and facilities in the fourth quarter results in Antero having
18 pads in progress that are planned to be turned to sales in 2019
and 2020. The pads were also built on larger footprints to
optimize drilling and completion efficiencies and significantly
reduce cycle times from spud to first sales. Driven by
continued efficiencies in stages per day, Antero also placed three
additional liquids-rich wells to sales during the quarter than
previously forecasted. The additional wells had an average
BTU content of 1260 and produced 56 MMcfe/d during the first 30
days, including 2,650 Bbl/d of liquids. As a result of the
capital spent on pads and roads in the latter part of 2018 and the
three additional liquids-rich wells during the fourth quarter,
Antero expects to be at the lower end of its 2019 drilling and
completion capital budget of $1.1 to
$1.25 billion on a consolidated basis
and $1.3 billion to $1.45 billion on a Stand-alone basis.
On a Stand-alone basis, Antero invested $415 million in drilling and completion costs for
the three months ended December 31, 2018, which included
$325 million for drilling and
completion activity, $78 million for
pads, roads and facilities and $12
million for unit leasehold and permitting costs.
In addition to capital invested in drilling and completion
costs, the Company invested $42
million for land, $107 million
for gathering and compression systems and $20 million for water infrastructure projects.
For a reconciliation between cash paid for drilling and completion
capital expenditures outlined above and drilling and completion
accrued capital expenditures during the period, please see the
capital expenditures section below.
Year End Proved Reserves
At December 31, 2018, Antero's
estimated proved reserves were 18.0 Tcfe, a 4% increase over the
prior year. Estimated proved reserves were comprised of 63%
natural gas, 35% NGLs and 2% oil. The Marcellus Shale
accounted for 89% of estimated proved reserves and the Ohio Utica
Shale accounted for 11%. For 2018, Antero added 2.8 Tcfe of
estimated proved reserves organically, which reflects delineation
and developmental drilling. Approximately 1.2 Tcfe was
removed from Antero's proved reserves due to the SEC 5-year rule,
primarily related to changes in our 5-year development plan.
Estimated proved developed reserves were 10.4 Tcfe, a 22%
increase over the prior year. The percentage of estimated
proved reserves classified as proved developed increased to 58% at
year-end 2018, compared to 49% at year-end 2017. Antero's 427
proved undeveloped locations average an estimated 1247 BTU, with an
average lateral length of approximately 11,100 feet.
Antero invested drilling and completion capital of $1.5 billion during 2018, resulting in proved
developed finding and development costs, including revisions, of
$0.52 per Mcfe. Antero's 7.6
Tcfe of estimated proved undeveloped reserves will require an
estimated $3.3 billion of future
development capital over the next five years, resulting in an
estimated average future development cost for proved undeveloped
reserves of $0.44 per Mcfe. For
further discussion of proved developed F&D costs, please read
"Non-GAAP Financial Measures."
The reserve life of the Company's estimated proved reserves is
approximately 18 years based on 2018 production.
The following table presents a summary of changes in estimated
proved reserves (in Bcfe).
Proved reserves,
December 31, 2017
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17,261
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Extensions,
discoveries, and other additions
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2,781
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Revisions to prior
estimates
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(1,042)
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Production
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(989)
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Proved reserves,
December 31, 2018
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18,011
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The following table summarizes SEC pricing as
of December 31, 2018 and the associated Standardized Measure
and PV-10 for estimated proved reserves and hedge values:
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SEC
Pricing
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Benchmark
Pricing:
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2018
Year-End
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2017
Year-End
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Variance
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%
Variance
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WTI Oil
Price ($/Bbl)
|
$65.66
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$51.03
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$14.63
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29%
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Appalachian Oil
Price ($/Bbl) (1)
|
$56.62
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$45.35
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$11.27
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25%
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Nymex Natural Gas
Price ($/MMBtu)
|
$3.09
|
|
$3.11
|
|
($0.02)
|
|
-1%
|
Appalachian
Natural Gas Price ($/MMBtu) (1)
|
$2.93
|
|
$2.91
|
|
$0.02
|
|
1%
|
C3+ Natural Gas
Liquids ($/Bbl) (2)
|
$39.29
|
|
$32.37
|
|
$6.92
|
|
21%
|
C2+ Natural Gas
Liquids ($/Bbl) (2)
|
$25.05
|
|
$20.40
|
|
$4.65
|
|
23%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Reserve
Value ($Bn):
|
|
|
|
|
|
|
|
Standardized
measure
|
$10.5
|
|
$8.6
|
|
$1.9
|
|
21%
|
Pre-tax estimated
proved reserves PV-10 (3)
|
$12.6
|
|
$10.2
|
|
$2.4
|
|
24%
|
|
(1) Represents SEC prices
as of December 31 for each respective year on a weighted average
Appalachian index basis related to company-specific sales
points.
|
(2) Represents realized NGL
price including regional market differentials for a 1250 BTU
area.
|
(3)
For a reconciliation of PV-10 to standardized measure, see
"Non-GAAP Financial Measures."
|
Balance Sheet and Liquidity
As of December 31, 2018, Antero's Stand-alone Net Debt was
$3.8 billion, of which $405 million were borrowings outstanding under
the Company's revolving credit facility. Total lender
commitments under this facility are $2.5
billion and the borrowing base is $4.5 billion. After deducting letters of
credit outstanding, the Company had $1.4
billion in available Stand-alone liquidity as of
December 31, 2018. As of December 31, 2018,
Antero's Stand-alone Net Debt to trailing twelve months Stand-alone
Adjusted EBITDAX ratio was 2.2x.
Commodity Derivative Positions
Antero's estimated natural gas production for 2019 is fully
hedged. In total, Antero has hedged 2.0 Tcfe of future
natural gas equivalent production using fixed price swaps, basis
swaps and collar agreements covering the period from January 1, 2019, through December 31, 2023. As of December 31,
2018, the Company's estimated fair value of commodity derivative
instruments was $607 million.
The following tables summarize Antero's hedge position as of
December 31, 2018:
|
|
|
|
|
|
|
|
|
Natural gas
MMbtu/day
|
|
Weighted
average index
price
|
|
Three months ending
March 31, 2019:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
2,330,000
|
|
$
|
3.62
|
|
Three months ending
June 30, 2019:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
755,000
|
|
$
|
3.26
|
|
Three months ending
September 30, 2019:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
755,000
|
|
$
|
3.32
|
|
Three months ending
December 31, 2019:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
755,000
|
|
$
|
3.45
|
|
Year ending
December 31, 2020:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
1,417,500
|
|
$
|
3.00
|
|
Year ending
December 31, 2021:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
710,000
|
|
$
|
3.00
|
|
Year ending
December 31, 2022:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
850,000
|
|
$
|
3.00
|
|
Year ending
December 31, 2023:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
90,000
|
|
$
|
2.91
|
|
Natural gas collar positions from April
1, 2019 through December 31,
2019 were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas
|
|
Weighted average
index price
|
|
|
|
MMbtu/day
|
|
Ceiling
price
|
|
Floor
price
|
|
Three months ending
June 30, 2019:
|
|
|
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
1,575,000
|
|
$
|
3.30
|
|
$
|
2.50
|
|
Three months ending
September 30, 2019:
|
|
|
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
1,575,000
|
|
$
|
3.30
|
|
$
|
2.50
|
|
Three months ending
December 31, 2019:
|
|
|
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
1,575,000
|
|
$
|
3.52
|
|
$
|
2.50
|
|
As of December 31, 2018, the
Company's natural gas basis swap positions, which settle on the
basis differential of Chicago City Gate to the NYMEX Henry Hub
natural gas price, totaled 225,000 MMbtu/day for January 2019 with pricing premiums ranging from
$0.215 to $0.40 per MMBtu.
Antero Midstream Financial Results
Antero Midstream results were released today and are available
at www.anteromidstream.com. A summary of the results are
provided below:
Average Daily
Volumes:
|
Three months
ended
|
|
Years
ended
|
December
31,
|
|
December
31,
|
2017
|
|
2018
|
|
%
Change
|
|
2017
|
|
2018
|
|
%
Change
|
Low Pressure Gathering
(MMcf/d)
|
|
1,711
|
|
|
2,602
|
|
52%
|
|
|
1,660
|
|
|
2,148
|
|
29%
|
Compression
(MMcf/d)
|
|
1,355
|
|
|
2,215
|
|
63%
|
|
|
1,196
|
|
|
1,738
|
|
45%
|
High Pressure
Gathering (MMcf/d)
|
|
1,842
|
|
|
2,569
|
|
39%
|
|
|
1,770
|
|
|
2,112
|
|
19%
|
Fresh Water Delivery
(MBbl/d)
|
|
149
|
|
|
136
|
|
(9)%
|
|
|
153
|
|
|
195
|
|
27%
|
Clearwater Treatment
Volumes (MBbl/d)
|
|
—
|
|
|
9
|
|
*
|
|
|
—
|
|
|
7
|
|
*
|
Gross Joint Venture
Processing (MMcf/d)
|
|
425
|
|
|
796
|
|
87%
|
|
|
267
|
|
|
622
|
|
133%
|
Gross Joint Venture
Fractionation (Bbl/d)
|
|
9,096
|
|
|
18,672
|
|
105%
|
|
|
5,099
|
|
|
13,107
|
|
157%
|
|
* Not meaningful or
applicable.
|
Net income for the fourth quarter of 2018 was $249 million, a 288% increase compared to the
prior year quarter. Net income per diluted limited partner unit was
$1.19, a 395% increase compared to
the prior year quarter. Adjusted EBITDA was $194 million, a 36% increase compared to the
prior year quarter. Distributable Cash Flow was $167 million, resulting in a DCF coverage ratio
of 1.3x. For a description of Antero Midstream's Adjusted
EBITDA and Distributable Cash Flow, and reconciliations to their
nearest GAAP measures, please read "Non-GAAP Financial
Measures."
In connection with Antero Midstream's acquisition of the water
business from Antero Resources in 2015, Antero Midstream agreed to
pay Antero Resources (a) $125 million
in cash if the Partnership delivered 176 million barrels or more of
fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional
$125 million in cash if the
Partnership delivered 219 million barrels or more of fresh water
during the period between January 1,
2018 and December 31, 2020. As
of December 31, 2018, Antero
Midstream expects to pay the amount of the contingent consideration
for the delivery of 176 million barrels or more of fresh water for
the first earn-out, but no longer expects to pay the amount of the
contingent consideration to deliver 219 million barrels or more of
fresh water for the second earn-out payment based on Antero
Resources' recently announced 2019 budget and long-term
outlook.
Conference Call
A conference call is scheduled on Thursday, February 14, 2019 at 9:00 am MT to discuss the financial and
operational results. A brief Q&A session for security
analysts will immediately follow the discussion of the results for
the quarter. To participate in the call, dial in at
1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and
reference "Antero Resources". A telephone replay of the call
will be available until Thursday, February
28, 2019 at 9:00 am MT at
1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the
passcode 10123136.
A simultaneous webcast of the call may be accessed over the
internet at www.anteroresources.com. The webcast will be
archived for replay on the Company's website until Thursday, February 28, 2019 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website
before the February 14, 2019
conference call. The presentation can be found at
www.anteroresources.com on the homepage. Information on the
Company's website does not constitute a portion of this press
release.
Also available at www.anteroresources.com is a presentation
detailing results of a fundamental analysis on the natural gas
industry entitled Natural Gas Fundamentals.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses and
Derivative Monetizations
Revenue Excluding Unrealized Derivative (Gains) Losses and
Derivative Monetizations as set forth in this release represents
total revenue adjusted for derivative fair value (gains) losses and
derivative monetizations. Antero believes that Revenue
Excluding Unrealized Derivative (Gains) Losses and Derivative
Monetizations is useful to investors in evaluating operational
trends of the Company and its performance relative to other oil and
gas producing companies. Revenue Excluding Unrealized
Derivative (Gains) Losses and Derivative Monetizations is not a
measure of financial performance under GAAP and should not be
considered in isolation or as a substitute for total revenue as an
indicator of financial performance. The following table
reconciles total revenue to Revenue Excluding Unrealized Derivative
(Gains) Losses and Derivative Monetizations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
December 31,
2018
|
|
Years
Ended
December 31,
2018
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenue
|
$
|
1,021,726
|
|
$
|
1,045,648
|
|
$
|
3,655,574
|
|
$
|
4,139,626
|
|
Commodity derivative
fair value (gains) losses
|
|
(199,824)
|
|
|
222,387
|
|
|
(658,283)
|
|
|
87,594
|
|
Marketing derivative
fair value (gains) losses
|
|
21,394
|
|
|
—
|
|
|
21,394
|
|
|
(94,081)
|
|
Gains (losses) on
settled commodity derivatives
|
|
76,548
|
|
|
(25,257)
|
|
|
213,940
|
|
|
243,112
|
|
Gains (losses) on
settled marketing derivatives
|
|
—
|
|
|
(5,411)
|
|
|
—
|
|
|
72,687
|
|
Revenue Excluding
Unrealized Derivative (Gains) Losses and Derivative
Monetizations
|
$
|
919,844
|
|
$
|
1,237,367
|
|
$
|
3,232,625
|
|
$
|
4,448,938
|
|
Adjusted Net Income & Stand-alone Adjusted Net
Income
Adjusted Net Income as set forth in this release represents net
income, adjusted for certain items. Stand-alone Adjusted Net
Income as presented in this release represents net income that will
be reported in the Parent column of Antero's guarantor footnote to
its financial statements, adjusted for certain items. Antero
believes that Adjusted Net Income and Adjusted Net Income per
share is useful to investors in evaluating operational trends
of the Company and its performance relative to other oil and gas
producing companies. Adjusted Net Income and Stand-alone
Adjusted Net Income are not measures of financial performance under
GAAP and should not be considered in isolation or as a substitute
for net income as an indicator of financial performance. The
following table reconciles net income (loss) to Adjusted Net
Income and Stand-alone net (loss) to Stand-alone Adjusted Net
Income (in thousands):
|
Stand-alone
|
|
Consolidated
|
|
|
Three months
ended
|
|
Three months
ended
|
|
|
December 31,
2018
|
|
December 31,
2018
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss)
attributable to Antero Resources Corp.
|
$
|
486,869
|
|
$
|
(121,546)
|
|
$
|
486,869
|
|
$
|
(121,546)
|
|
Commodity derivative
fair value (gains) losses
|
|
(199,824)
|
|
|
222,387
|
|
|
(199,824)
|
|
|
222,387
|
|
Gains (losses) on
settled commodity derivatives
|
|
76,548
|
|
|
(25,257)
|
|
|
76,548
|
|
|
(25,257)
|
|
Marketing derivative
fair value losses
|
|
21,394
|
|
|
—
|
|
|
21,394
|
|
|
—
|
|
Losses on settled
marketing derivatives
|
|
—
|
|
|
(5,411)
|
|
|
—
|
|
|
(5,411)
|
|
Impairment of unproved
properties
|
|
76,500
|
|
|
143,369
|
|
|
76,500
|
|
|
143,369
|
|
Impairment of gathering
systems and facilities
|
|
—
|
|
|
—
|
|
|
23,431
|
|
|
—
|
|
Equity-based
compensation
|
|
17,673
|
|
|
9,518
|
|
|
24,520
|
|
|
13,984
|
|
(Gain) loss on change
in fair value of contingent acquisition consideration
|
|
—
|
|
|
104,860
|
|
|
—
|
|
|
—
|
|
Loss on early
extinguishment of debt
|
|
1,205
|
|
|
—
|
|
|
1,500
|
|
|
—
|
|
Tax effect of
reconciling items (1)
|
|
2,447
|
|
|
(105,804)
|
|
|
(9,056)
|
|
|
(82,171)
|
|
Other tax items
(2)
|
|
(427,962)
|
|
|
(47,550)
|
|
|
(427,962)
|
|
|
—
|
|
Adjusted Net Income
|
$
|
54,850
|
|
$
|
174,566
|
|
$
|
73,920
|
|
$
|
145,355
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Shares
Outstanding
|
|
316,682
|
|
|
314,298
|
|
|
316,682
|
|
|
314,298
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per Diluted Share
Amounts
|
Net Income (loss)
attributable to Antero Resources Corp
|
|
1.54
|
|
|
(0.39)
|
|
|
1.54
|
|
|
(0.39)
|
|
Commodity derivative
fair value (gains) losses
|
|
(0.63)
|
|
|
0.71
|
|
|
(0.63)
|
|
|
0.71
|
|
Gains (losses) on
settled commodity derivatives
|
|
0.24
|
|
|
(0.08)
|
|
|
0.24
|
|
|
(0.08)
|
|
Marketing derivative
fair value losses
|
|
0.07
|
|
|
—
|
|
|
0.07
|
|
|
—
|
|
Losses on settled
marketing derivatives
|
|
—
|
|
|
(0.02)
|
|
|
—
|
|
|
(0.02)
|
|
Impairment of
unproved properties
|
|
0.24
|
|
|
0.46
|
|
|
0.24
|
|
|
0.46
|
|
Impairment of
gathering systems and facilities
|
|
—
|
|
|
—
|
|
|
0.07
|
|
|
—
|
|
Equity-based
compensation
|
|
0.05
|
|
|
0.03
|
|
|
0.08
|
|
|
0.04
|
|
(Gain) loss on change
in fair value of contingent
acquisition
consideration
|
|
—
|
|
|
0.34
|
|
|
—
|
|
|
—
|
|
Loss on early
extinguishment of debt
|
|
0.00
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Tax effect of
reconciling items (1)
|
|
0.01
|
|
|
(0.34)
|
|
|
(0.03)
|
|
|
(0.26)
|
|
Other tax items
(2)
|
|
(1.35)
|
|
|
(0.15)
|
|
|
(1.35)
|
|
|
—
|
|
Adjusted Net
Income
|
$
|
0.17
|
|
$
|
0.56
|
|
$
|
0.23
|
|
$
|
0.46
|
|
|
|
(1)
|
Blended tax rates
of approximately 38% for 2017 and 24% for 2018 were applied to
reconciling items above.
|
(2)
|
Tax impact of
valuation allowance on Colorado net operating losses, changes to
Colorado tax law, tax reform legislation enacted in late 2017 and
items effecting the Stand-alone financial
statements.
|
|
Stand-alone
|
|
Consolidated
|
|
|
Year
ended
|
|
Year
ended
|
|
|
December 31,
2018
|
|
December 31,
2018
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss)
attributable to Antero Resources Corp.
|
$
|
615,070
|
|
$
|
(397,517)
|
|
$
|
615,070
|
|
$
|
(397,517)
|
|
Commodity derivative
fair value (gains) losses
|
|
(658,283)
|
|
|
87,594
|
|
|
(658,283)
|
|
|
87,594
|
|
Gains (losses) on
settled commodity derivatives
|
|
213,940
|
|
|
243,112
|
|
|
213,940
|
|
|
243,112
|
|
Marketing derivative
fair value losses
|
|
21,394
|
|
|
(94,081)
|
|
|
21,394
|
|
|
(94,081)
|
|
Losses on settled
marketing derivatives
|
|
—
|
|
|
72,687
|
|
|
—
|
|
|
72,687
|
|
Impairment of unproved
properties
|
|
159,598
|
|
|
553,907
|
|
|
159,598
|
|
|
559,095
|
|
Impairment of gathering
systems and facilities
|
|
—
|
|
|
—
|
|
|
23,431
|
|
|
—
|
|
Equity-based
compensation
|
|
76,162
|
|
|
49,341
|
|
|
103,445
|
|
|
70,413
|
|
(Gain) loss on change
in fair value of contingent acquisition consideration
|
|
—
|
|
|
93,019
|
|
|
—
|
|
|
—
|
|
Loss on early
extinguishment of debt
|
|
1,205
|
|
|
—
|
|
|
1,500
|
|
|
—
|
|
Tax effect of
reconciling items (1)
|
|
69,976
|
|
|
(240,513)
|
|
|
50,784
|
|
|
(223,045)
|
|
Other tax items
(2)
|
|
(427,962)
|
|
|
(2,987)
|
|
|
(427,962)
|
|
|
(2,987)
|
|
Adjusted Net Income
|
$
|
71,100
|
|
$
|
364,562
|
|
$
|
102,917
|
|
$
|
315,271
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Shares
Outstanding
|
|
316,283
|
|
|
316,675
|
|
|
316,283
|
|
|
316,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Income (loss)
attributable to Antero Resources Corp
|
|
1.94
|
|
|
(1.26)
|
|
|
1.94
|
|
|
(1.26)
|
|
Commodity derivative
fair value (gains) losses
|
|
(2.08)
|
|
|
0.28
|
|
|
(2.08)
|
|
|
0.28
|
|
Gains (losses) on
settled commodity derivatives
|
|
0.68
|
|
|
0.77
|
|
|
0.68
|
|
|
0.77
|
|
Marketing derivative
fair value losses
|
|
0.07
|
|
|
(0.30)
|
|
|
0.07
|
|
|
(0.30)
|
|
Losses on settled
marketing derivatives
|
|
—
|
|
|
0.23
|
|
|
—
|
|
|
0.23
|
|
Impairment of
unproved properties
|
|
0.50
|
|
|
1.75
|
|
|
0.50
|
|
|
1.77
|
|
Impairment of
gathering systems and facilities
|
|
0.00
|
|
|
—
|
|
|
0.07
|
|
|
—
|
|
Equity-based
compensation
|
|
0.24
|
|
|
0.16
|
|
|
0.33
|
|
|
0.22
|
|
(Gain) loss on change
in fair value of contingent
acquisition
consideration
|
|
—
|
|
|
0.29
|
|
|
—
|
|
|
—
|
|
Loss on early
extinguishment of debt
|
|
0.00
|
|
|
—
|
|
|
0.00
|
|
|
—
|
|
Tax effect of
reconciling items (1)
|
|
0.22
|
|
|
(0.76)
|
|
|
0.16
|
|
|
(0.70)
|
|
Other tax items
(2)
|
|
(1.35)
|
|
|
(0.01)
|
|
|
(1.35)
|
|
|
(0.01)
|
|
Adjusted Net
Income
|
$
|
0.22
|
|
$
|
1.15
|
|
$
|
0.33
|
|
$
|
1.00
|
|
|
|
(1)
|
Blended tax rates
of approximately 38% for 2017 and 24% for 2018 were applied to
reconciling items above.
|
(2)
|
Tax impact of
valuation allowance on Colorado net operating losses, changes to
Colorado tax law, tax reform legislation enacted in late 2017 and
items effecting the Stand-alone financial
statements.
|
Adjusted Operating Cash Flow, Stand-alone Adjusted Operating
Cash Flow and Free Cash Flow
Adjusted Operating Cash Flow as presented in this release
represents net cash provided by operating activities before changes
in working capital items. Stand-alone Adjusted Operating Cash
Flow as presented in this release represents net cash provided by
operating activities that will be reported in the Parent column of
Antero's guarantor footnote to its financial statements before
changes in working capital items. Adjusted Operating Cash
Flow is widely accepted by the investment community as a financial
indicator of an oil and gas company's ability to generate cash to
internally fund exploration and development activities and to
service debt. Adjusted Operating Cash Flow is also useful
because it is widely used by professional research analysts in
valuing, comparing, rating and providing investment recommendations
of companies in the oil and gas exploration and production
industry. In turn, many investors use this published research
in making investment decisions. Free Cash Flow as defined by
the Company represents Stand-alone Adjusted Operating Cash Flow,
less Stand-alone Drilling and Completion capital, less Land
Maintenance Capital.
Management believes that Adjusted Operating Cash Flow,
Stand-alone Adjusted Operating Cash Flow and Free Cash Flow are
useful indicators of the company's ability to internally fund its
activities and to service or incur additional debt on a
consolidated and Stand-alone basis. Management believes that
changes in current assets and liabilities, which are excluded from
the calculation of these measures, relate to the timing of cash
receipts and disbursements and therefore may not relate to the
period in which the operating activities occurred and generally do
not have a material impact on the ability of the company to fund
its operations.
There are significant limitations to using Adjusted Operating
Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash
Flow as measures of performance, including the inability to analyze
the effect of certain recurring and non-recurring items that
materially affect the company's net income on a consolidated and
Stand-alone basis, the lack of comparability of results of
operations of different companies and the different methods of
calculating Adjusted Operating Cash Flow, Stand-alone Adjusted
Operating Cash Flow and Free Cash Flow reported by different
companies. Adjusted Operating Cash Flow, Stand-alone Adjusted
Operating Cash Flow and Free Cash Flow do 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.
Adjusted Operating Cash Flow and Free Cash Flow are not measures
of financial performance under GAAP and should not be considered in
isolation or as a substitute for cash flows from operating,
investing, or financing activities, as an indicator of cash flows,
or as a measure of liquidity.
The following table reconciles net cash provided by operating
activities to Adjusted Operating Cash Flow as used in this release
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stand-alone
|
|
Consolidated
|
|
|
|
Three months
ended
|
|
Three months
ended
|
|
|
|
December 31,
2018
|
|
December 31,
2018
|
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net cash provided by
operating activities
|
$
|
254,078
|
|
|
729,082
|
|
$
|
313,483
|
|
|
821,589
|
|
|
Net change in working
capital
|
|
57,666
|
|
|
46,074
|
|
|
54,054
|
|
|
41,656
|
|
|
Adjusted Operating Cash
Flow
|
$
|
311,744
|
|
|
775,156
|
|
$
|
367,537
|
|
|
863,245
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt, Net Debt and Stand-alone Net Debt
Net Debt is calculated as total debt less cash and cash
equivalents. Management uses Consolidated Net Debt and
Stand-alone Net Debt to evaluate its financial position, including
its ability to service its debt obligations.
The following table reconciles consolidated total debt to
Consolidated Net Debt and Stand-alone Net Debt as used in this
release (in thousands):
Adjusted EBITDAX and Stand-alone Adjusted EBITDAX
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
December 31,
|
|
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
AR bank credit
facility
|
|
$
|
185,000
|
|
|
405,000
|
|
AM bank credit
facility
|
|
|
555,000
|
|
|
990,000
|
|
5.375% AR senior
notes due 2021
|
|
|
1,000,000
|
|
|
1,000,000
|
|
5.125% AR senior
notes due 2022
|
|
|
1,100,000
|
|
|
1,100,000
|
|
5.625% AR senior
notes due 2023
|
|
|
750,000
|
|
|
750,000
|
|
5.375% AM senior
notes due 2024
|
|
|
650,000
|
|
|
650,000
|
|
5.000% AR senior
notes due 2025
|
|
|
600,000
|
|
|
600,000
|
|
Net unamortized
premium
|
|
|
1,520
|
|
|
1,241
|
|
Net unamortized debt
issuance costs
|
|
|
(41,430)
|
|
|
(34,553)
|
|
Consolidated total
debt
|
|
$
|
4,800,090
|
|
|
5,461,688
|
|
Less: AR cash and cash
equivalents
|
|
|
20,078
|
|
|
—
|
|
Less: AM cash and cash
equivalents
|
|
|
8,363
|
|
|
—
|
|
Consolidated net
debt
|
|
$
|
4,771,649
|
|
|
5,461,688
|
|
|
|
|
|
|
|
|
|
Less: Antero Midstream
debt net of cash and unamortized premium and debt issuance
costs
|
|
$
|
1,187,637
|
|
|
1,632,147
|
|
Stand-alone Net
Debt
|
|
$
|
3,584,012
|
|
|
3,829,541
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted EBITDAX as defined by the Company represents net income
or loss from continuing operations, 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,
franchise taxes, equity-based compensation, gain or loss on early
extinguishment of debt, gain or loss on sale of assets, and
contract termination and rig stacking costs. Adjusted EBITDAX
also includes distributions from unconsolidated affiliates and
excludes equity in earnings or losses of unconsolidated
affiliates.
Stand-alone Adjusted EBITDAX as defined by the Company
represents income or loss as reported in the Parent column of
Antero's guarantor footnote to its financial statements before
interest expense, interest income, derivative fair value gains or
losses (excluding net cash receipts or payments on derivative
instruments included in derivative fair value gains or losses other
than proceeds from derivative monetizations), taxes, impairments,
depletion, depreciation, amortization, and accretion, exploration
expense, equity-based compensation, gain or loss on early
extinguishment of debt, gain or loss on sale of assets, equity in
earnings or loss of Antero Midstream and gain or loss on changes in
the fair value of contingent acquisition consideration. Stand-alone
Adjusted EBITDAX also includes distributions received from limited
partner interests in Antero Midstream common units.
The GAAP financial measure nearest to Adjusted EBITDAX is net
income or loss including noncontrolling interest that will be
reported in Antero's consolidated financial statements. The
GAAP financial measure nearest to Stand-alone Adjusted EBITDAX is
Stand-alone net income or loss that will be reported in the Parent
column of Antero's guarantor footnote to its financial statements.
While there are limitations associated with the use of Adjusted
EBITDAX and Stand-alone Adjusted EBITDAX described below,
management believes that these measures are useful to an investor
in evaluating the company's financial performance because these
measures:
- are widely used by investors in the oil and gas industry to
measure a company's operating performance without regard to items
excluded from the calculation of such term, which can vary
substantially from company to company depending upon accounting
methods and 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 (both on a consolidated and
Stand-alone basis) from period to period by removing the effect of
its capital structure from its operating structure; and
- is used by management for various purposes, including as a
measure of Antero's operating performance (both on a consolidated
and Stand-alone basis), 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. Adjusted
EBITDAX, as defined by our credit facility, is used by our lenders
pursuant to covenants under our revolving credit facility and the
indentures governing the company's senior notes.
There are significant limitations to using Adjusted EBITDAX and
Stand-alone Adjusted EBITDAX as measures of performance, including
the inability to analyze the effect of certain recurring and
non-recurring items that materially affect the company's net income
on a consolidated and Stand-alone basis, 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 and Stand-alone
Adjusted EBITDAX provide no information regarding a company's
capital structure, borrowings, interest costs, capital
expenditures, and working capital movement or tax position.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stand-alone
|
|
Consolidated
|
|
|
|
Three months
ended December 31,
|
|
Three months
ended December 31,
|
|
(in
thousands)
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
Net (loss) and
comprehensive (loss) attributable to Antero Resources
Corporation
|
|
$
|
486,869
|
|
$
|
(121,546)
|
|
$
|
486,869
|
|
|
$
(121,546)
|
|
Net income and
comprehensive income attributable to noncontrolling
interest
|
|
|
—
|
|
|
—
|
|
|
42,745
|
|
|
140,282
|
|
Commodity derivative
fair value (gains) losses
|
|
|
(199,824)
|
|
|
222,387
|
|
|
(199,824)
|
|
|
222,387
|
|
Gains (losses) on
settled commodity derivatives
|
|
|
76,548
|
|
|
(25,257)
|
|
|
76,548
|
|
|
(25,257)
|
|
Marketing derivative
fair value losses
|
|
|
21,394
|
|
|
—
|
|
|
21,394
|
|
|
—
|
|
Losses on settled
marketing derivatives
|
|
|
—
|
|
|
(5,411)
|
|
|
—
|
|
|
(5,411)
|
|
Interest
expense
|
|
|
53,687
|
|
|
59,458
|
|
|
63,390
|
|
|
78,440
|
|
Loss on early
extinguishment of debt
|
|
|
1,205
|
|
|
—
|
|
|
1,500
|
|
|
—
|
|
Income tax expense
(benefit)
|
|
|
(400,138)
|
|
|
(131,357)
|
|
|
(400,138)
|
|
|
(131,357)
|
|
Depletion,
depreciation, amortization, and accretion
|
|
|
183,439
|
|
|
240,977
|
|
|
214,397
|
|
|
263,703
|
|
Impairment of unproved
properties
|
|
|
76,500
|
|
|
143,369
|
|
|
76,500
|
|
|
143,369
|
|
Impairment of
gathering systems and facilities
|
|
|
—
|
|
|
—
|
|
|
23,431
|
|
|
—
|
|
Exploration
expense
|
|
|
3,028
|
|
|
936
|
|
|
3,028
|
|
|
936
|
|
Gain on change in fair
value of contingent acquisition consideration
|
|
|
(3,804)
|
|
|
104,860
|
|
|
—
|
|
|
—
|
|
Equity-based
compensation expense
|
|
|
17,673
|
|
|
9,518
|
|
|
24,520
|
|
|
13,984
|
|
Equity in earnings of
unconsolidated affiliates
|
|
|
—
|
|
|
—
|
|
|
(7,307)
|
|
|
(12,448)
|
|
Distributions from
unconsolidated affiliates
|
|
|
—
|
|
|
—
|
|
|
10,075
|
|
|
16,755
|
|
Equity in (earnings)
loss of Antero Midstream Partners LP
|
|
|
22,128
|
|
|
(66,753)
|
|
|
—
|
|
|
—
|
|
Distributions from
Antero Midstream Partners LP
|
|
|
33,614
|
|
|
43,503
|
|
|
—
|
|
|
—
|
|
Adjusted
EBITDAX
|
|
|
372,319
|
|
|
474,684
|
|
|
437,128
|
|
|
583,837
|
|
Interest
expense
|
|
|
(53,687)
|
|
|
(59,458)
|
|
|
(63,390)
|
|
|
(78,440)
|
|
Exploration
expense
|
|
|
(3,028)
|
|
|
(936)
|
|
|
(3,028)
|
|
|
(936)
|
|
Changes in current
assets and liabilities
|
|
|
(57,666)
|
|
|
(46,074)
|
|
|
(54,054)
|
|
|
(41,656)
|
|
Proceeds from
derivative monetizations
|
|
|
—
|
|
|
370,365
|
|
|
—
|
|
|
370,365
|
|
Premium paid on
derivative contracts
|
|
|
—
|
|
|
(13,318)
|
|
|
—
|
|
|
(13,318)
|
|
Other non-cash
items
|
|
|
(3,860)
|
|
|
3,829
|
|
|
(3,173)
|
|
|
1,736
|
|
Net cash provided by
operating activities
|
$
|
|
254,078
|
|
$
|
729,092
|
|
$
|
313,483
|
|
$
|
821,588
|
|
Adjusted
EBITDAX
|
$
|
|
372,319
|
|
$
|
474,684
|
|
$
|
437,128
|
|
$
|
583,837
|
|
Production
(MMcfe)
|
|
|
215,921
|
|
|
295,576
|
|
|
215,921
|
|
|
295,576
|
|
Adjusted EBITDAX
margin per Mcfe
|
$
|
|
1.72
|
|
|
1.61
|
|
$
|
2.02
|
|
$
|
1.98
|
|
The following table reconciles net income as reported in the
Parent column of Antero's guarantor footnote to its financial
statements to Stand-alone Adjusted EBITDAX for the twelve months
ended December 31, 2018, as used in this release (in
thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stand-alone
|
|
|
|
|
|
|
|
|
|
Twelve months
ended
|
|
(in
thousands)
|
|
|
|
|
|
|
|
December 31,
2018
|
|
Net (loss) and
comprehensive (loss) attributable to Antero Resources
Corporation
|
|
|
|
|
|
|
|
$
|
|
|
|
(397,517)
|
|
Commodity derivative
fair value (gains) losses
|
|
|
|
|
|
|
|
|
|
|
|
87,594
|
|
Gains on settled
commodity derivatives
|
|
|
|
|
|
|
|
|
|
|
|
243,112
|
|
Marketing derivative
fair value gains
|
|
|
|
|
|
|
|
|
|
|
|
(94,081)
|
|
Gains on settled
marketing derivatives
|
|
|
|
|
|
|
|
|
|
|
|
72,687
|
|
Interest
expense
|
|
|
|
|
|
|
|
|
|
|
|
224,977
|
|
Income tax
benefit
|
|
|
|
|
|
|
|
|
|
|
|
(128,857)
|
|
Depletion,
depreciation, amortization, and accretion
|
|
|
|
|
|
|
|
|
|
|
|
845,136
|
|
Impairment of unproved
properties
|
|
|
|
|
|
|
|
|
|
|
|
549,437
|
|
Impairment of gathering
systems and facilities
|
|
|
|
|
|
|
|
|
|
|
|
4,470
|
|
Exploration
expense
|
|
|
|
|
|
|
|
|
|
|
|
4,958
|
|
Gain on change in fair
value of contingent acquisition consideration
|
|
|
|
|
|
|
|
|
|
|
|
93,019
|
|
Equity-based
compensation expense
|
|
|
|
|
|
|
|
|
|
|
|
49,341
|
|
Equity in (earnings)
loss of Antero Midstream Partners LP
|
|
|
|
|
|
|
|
|
|
|
|
3,664
|
|
Distributions from
Antero Midstream Partners LP
|
|
|
|
|
|
|
|
|
|
|
|
159,181
|
|
Stand-alone
Adjusted EBITDAX
|
|
|
|
|
|
|
|
$
|
|
|
|
1,717,121
|
|
The following tables reconcile Antero's drilling and completion
costs as reported on a cash basis to drilling and completion costs
on an accrual basis:
Drilling and Completion Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
December 31,
2018
|
|
Years
Ended
December 31,
2018
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and
completion costs (as reported; cash basis)
|
$
|
335,476
|
|
$
|
362,912
|
|
$
|
1,281,985
|
|
$
|
1,488,573
|
|
Change in accrued
capital costs
|
|
(14,391)
|
|
|
(25,539)
|
|
|
(14,005)
|
|
|
(2,363)
|
|
Drilling and
completion costs (accrual basis)
|
$
|
321,086
|
|
$
|
337,374
|
|
$
|
1,267,980
|
|
$
|
1,486,210
|
|
Stand-alone Drilling and Completion Costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
December 31,
2018
|
|
Years
Ended
December 31,
2018
|
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stand-alone drilling
and completion costs (as reported; cash basis)
|
$
|
373,350
|
|
$
|
415,298
|
|
$
|
1,455,554
|
|
$
|
1,743,587
|
|
Change in accrued
capital costs
|
|
(2,820)
|
|
|
(36,633)
|
|
|
241,303
|
|
|
(15,238)
|
|
Stand-alone drilling
and completion costs (accrual basis)
|
$
|
370,530
|
|
$
|
378,665
|
|
$
|
1,696,857
|
|
$
|
1,728,349
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed F&D Cost Per Unit & Pre-Tax PV-10
Value
Proved developed F&D costs per unit and pre-tax PV-10 are
non-GAAP metrics 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. Proved developed F&D costs per unit is a
statistical indicator that has limitations, including its
predictive and comparative value. In addition, because proved
developed F&D costs per unit do not consider the cost or timing
of future production of new reserves, such measures may not be
adequate measures of value creation. 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 proved developed
F&D costs per unit, and therefore a reconciliation to GAAP is
not practicable.
The calculation for proved developed F&D cost per unit is
based on costs incurred in 2018. The calculation for proved
developed F&D cost per unit does not include future development
costs required for the development of proved undeveloped
reserves.
The pre-tax PV-10 value is a non-GAAP financial measure
as defined by the SEC. Antero believes that the presentation
of pre-tax PV-10 is relevant and useful to its investors
because it presents the discounted future net cash flows
attributable to reserves prior to taking into account corporate
future income taxes and the Company's current tax structure.
The Company further believes investors and creditors use pre-tax
PV-10 values as a basis for comparison of the relative size and
value of its reserves as compared with other
companies. Antero believes that PV-10 estimates
using strip pricing can be used within the industry and by
creditors and securities analysts to evaluate estimated net cash
flows in the current commodity price
environment.
The GAAP financial measure most directly comparable to pre-tax
PV-10 is the standardized measure of discounted future net
cash flows ("Standardized Measure"). The following sets forth
the estimated future net cash flows from our proved reserves
(without giving effect to our commodity derivatives), the present
value of those net cash flows before income tax (PV-10) and the
present value of those net cash flows after income tax
(Standardized measure) at December
31,
2018:
(In millions,
except per Mcf data)
|
|
|
At December 31,
2018
|
|
|
|
|
|
Future net cash
flows
|
$
|
30,739
|
|
Present value of
future net cash flows:
|
|
|
|
Before income tax
(PV-10)
|
$
|
12,589
|
|
Income
taxes
|
$
|
(2,111)
|
|
After income tax
(Standardized measure)
|
$
|
10,478
|
|
Notwithstanding their use for comparative purposes, the
Company's non-GAAP financial measures may not be comparable to
similarly titled measures employed by other companies.
Antero Midstream Adjusted EBITDA & Distributable Cash
Flow
Antero Midstream views Adjusted EBITDA as an important
indicator of its performance. Antero Midstream defines
Adjusted EBITDA as Net Income before interest expense, gain on sale
of assets, depreciation expense, impairment expense, change in fair
value of contingent acquisition consideration, accretion,
equity-based compensation expense, excluding equity in earnings of
unconsolidated affiliates and including cash distributions from
unconsolidated affiliates.
Antero Midstream uses Adjusted EBITDA to assess:
- the financial performance of Antero Midstream's assets, without
regard to financing methods in the case of Adjusted EBITDA, capital
structure or historical cost basis;
- its operating performance and return on capital as compared to
other publicly traded partnerships in the midstream energy sector,
without regard to financing or capital structure; and
- the viability of acquisitions and other capital expenditure
projects.
Antero Midstream defines Distributable Cash Flow as Adjusted
EBITDA less interest paid, income tax withholding payments and cash
reserved for payments of income tax withholding upon vesting of
equity-based compensation awards, cash reserved for bond interest
and ongoing maintenance capital expenditures
paid. Antero Midstream uses Distributable Cash Flow
as a performance metric to compare the cash generating performance
of Antero Midstream from period to period and to compare the cash
generating performance for specific periods to the cash
distributions (if any) that are expected to be paid to
unitholders. Distributable Cash Flow does not reflect changes
in working capital balances.
Adjusted EBITDA and Distributable Cash Flow are Non-GAAP
financial measures. The GAAP measure most directly comparable
to Adjusted EBITDA and Distributable Cash Flow is Net Income.
The Non-GAAP financial measures of Adjusted EBITDA and
Distributable Cash Flow should not be considered as alternatives to
the GAAP measure of Net Income. Adjusted EBITDA and
Distributable Cash Flow are not presentations made in accordance
with GAAP and have important limitations as an analytical tool
because they include some, but not all, items that affect Net
Income and Adjusted EBITDA. You should not consider Adjusted
EBITDA and Distributable Cash Flow in isolation or as a substitute
for analyses of results as reported under GAAP. Antero
Midstream's definition of Adjusted EBITDA and Distributable Cash
Flow may not be comparable to similarly titled measures of other
partnerships.
|
Three months
ended
|
|
Years
ended
|
December
31,
|
|
December
31,
|
2017
|
|
2018
|
|
2017
|
|
2018
|
Net
income
|
$
|
64,155
|
|
$
|
248,609
|
|
$
|
307,315
|
|
$
|
585,944
|
Impairment of property
and equipment
|
|
23,431
|
|
|
—
|
|
|
23,431
|
|
|
5,771
|
Change in fair value
of contingent acquisition consideration
|
|
—
|
|
|
(105,872)
|
|
|
—
|
|
|
(105,872)
|
Adjusted Net
Income
|
$
|
87,586
|
|
$
|
142,737
|
|
$
|
344,872
|
|
$
|
485,843
|
Interest expense,
net
|
|
10,395
|
|
|
18,993
|
|
|
37,557
|
|
|
61,906
|
Depreciation
|
|
30,958
|
|
|
22,692
|
|
|
119,562
|
|
|
130,013
|
Accretion of
contingent acquisition consideration
|
|
3,804
|
|
|
1,012
|
|
|
13,476
|
|
|
12,853
|
Accretion of asset
retirement obligation
|
|
—
|
|
|
34
|
|
|
|
|
|
135
|
Equity-based
compensation
|
|
6,847
|
|
|
4,467
|
|
|
27,283
|
|
|
21,073
|
Equity in earnings of
unconsolidated affiliates
|
|
(7,307)
|
|
|
(12,448)
|
|
|
(20,194)
|
|
|
(40,280)
|
Distributions from
unconsolidated affiliates
|
|
10,075
|
|
|
16,755
|
|
|
20,195
|
|
|
46,415
|
Gain on sale of assets
– Antero Resources
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(583)
|
Adjusted
EBITDA
|
$
|
142,358
|
|
$
|
194,242
|
|
$
|
528,625
|
|
$
|
717,375
|
Interest
paid
|
|
(4,136)
|
|
|
(9,268)
|
|
|
(46,666)
|
|
|
(62,844)
|
Decrease (increase) in
cash reserved for bond interest (1)
|
|
(8,734)
|
|
|
(8,734)
|
|
|
291
|
|
|
0
|
Income tax withholding
upon vesting of Antero Midstream Partners LP equity-based
compensation awards
|
|
(514)
|
|
|
(1,029)
|
|
|
(5,945)
|
|
|
(5,529)
|
Maintenance capital
expenditures(2)
|
|
(12,063)
|
|
|
(7,988)
|
|
|
(55,159)
|
|
|
(52,729)
|
Distributable Cash
Flow
|
$
|
116,911
|
|
$
|
167,223
|
|
$
|
421,146
|
|
$
|
596,273
|
|
|
|
|
|
|
|
|
|
|
|
|
Distributions
Declared to Antero Midstream Holders
|
|
|
|
|
|
|
|
|
|
|
|
Limited
partners
|
|
68,231
|
|
|
88,045
|
|
|
247,132
|
|
|
320,915
|
Incentive
distribution rights
|
|
23,772
|
|
|
43,492
|
|
|
69,720
|
|
|
142,906
|
Total Aggregate
Distributions
|
$
|
92,003
|
|
$
|
131,537
|
|
$
|
316,852
|
|
$
|
463,821
|
|
|
|
|
|
|
|
|
|
|
|
|
DCF coverage
ratio
|
|
1.27x
|
|
|
1.27x
|
|
|
1.33x
|
|
|
1.29x
|
|
|
(1)
|
Cash reserved for
bond interest expense on Antero Midstream's 5.375% senior notes
outstanding during the period that is paid on a semi-annual basis
on March 15th and September 15th of each year.
|
(2)
|
Maintenance
capital expenditures represent the portion of our estimated capital
expenditures associated with (i) the connection of new wells to our
gathering and processing systems that we believe will be necessary
to offset the natural production declines Antero Resources will
experience on all of its wells over time, and (ii) water delivery
to new wells necessary to maintain the average throughput volume on
our systems.
|
Antero Resources is an independent natural gas and oil
company engaged in the acquisition, development and production of
unconventional liquids-rich natural gas properties located in the
Appalachian Basin in West Virginia
and Ohio. The Company's website is
located at www.anteroresources.com.
This release includes "forward-looking statements".
Such forward-looking statements are subject to a number of risks
and uncertainties, many of which are beyond Antero's control. All
statements, except for statements of historical fact, made in this
release regarding activities, events or developments Antero
expects, believes or anticipates will or may occur in the future,
such as those regarding the expected sources of funding and timing
for completion of the share repurchase program if at all,
statements regarding the simplification transaction, including the
expected consideration to be received in connection with the
closing of the simplification transaction, future commodity prices,
future production targets, completion of natural gas or natural gas
liquids transportation projects, future earnings, Free Cash Flow
and 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, future financial
position, future technical improvements and future marketing
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 release. Although
Antero 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.
Antero 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 the
Antero's control, incident to the exploration for and development,
production, gathering and sale of natural gas, NGLs and oil. These
risks include, but are not limited to, the expected timing and
likelihood of completion of the simplification transaction,
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 "Item 1A. Risk Factors" in
Antero's Annual Report on Form 10-K for the year ended December 31, 2018.
This release provides a summary of Antero's reserves as of
December 31, 2018, assuming partial
ethane "rejection" where sales demand for ethane is not
available. Ethane rejection occurs when ethane is left in the
wellhead natural gas stream when the natural gas is processed,
rather than being separated out and sold as a liquid after
fractionation. When ethane is left in the gas stream, the Btu
content of the residue natural gas at the outlet of the processing
plant is higher. Producers will generally elect to "reject"
ethane at the processing plant when the price received for the
ethane in the natural gas stream is greater than the price received
for the ethane being sold as a liquid after fractionation, net of
fractionation costs. When ethane is recovered in the
processing plant, the Btu content of the residue natural gas is
lower, but a producer is then able to recover the value of the
ethane sold as a separate natural gas liquid product. In
addition, natural gas processing plants can produce the other NGL
products (propane, normal butane, isobutene and natural gasoline)
while rejecting ethane.
No Offer or Solicitation
This communication includes a discussion of a proposed
business combination transaction between Antero Midstream and AMGP.
This communication is for informational purposes only and does not
constitute an offer to sell or the solicitation of an offer to buy
any securities or a solicitation of any vote or approval, in any
jurisdiction, pursuant to the transaction or otherwise, nor shall
there be any sale, issuance, exchange or transfer of the securities
referred to in this document in any jurisdiction in contravention
of applicable law. No offer of securities shall be made except by
means of a prospectus meeting the requirements of Section 10 of the
Securities Act of 1933, as amended.
Additional Information And Where To Find It
In connection with the transaction, AMGP has filed with the
U.S. Securities and Exchange Commission ("SEC") a registration
statement on Form S-4, that includes a joint proxy statement of
Antero Midstream and AMGP and a prospectus of AMGP. The transaction
will be submitted to Antero Midstream unitholders and AMGP
shareholders for their consideration. Antero Midstream and AMGP may
also file other documents with the SEC regarding the transaction.
The registration statement on Form S-4 became effective on
January 30, 2019, and the definitive
joint proxy statement/prospectus is being sent to the shareholders
of AMGP and unitholders of Antero Midstream of record as of
January 11, 2019. This document is
not a substitute for the registration statement and joint proxy
statement/prospectus that has been filed with the SEC or any other
documents that AMGP or Antero Midstream may file with the SEC or
send to shareholders of AMGP or unitholders of Antero Midstream in
connection with the transaction. INVESTORS AND SECURITY HOLDERS OF
ANTERO MIDSTREAM AND AMGP ARE URGED TO READ THE REGISTRATION
STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE
TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL
BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO
THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL
CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED
MATTERS.
Investors and security holders are able to obtain free copies
of the registration statement and the joint proxy
statement/prospectus (when available) and all other documents filed
or that will be filed with the SEC by AMGP or Antero Midstream
through the website maintained by the SEC at http://www.sec.gov.
Copies of documents filed with the SEC by Antero Midstream will be
made available free of charge on Antero Midstream's website at
http://investors.anteromidstream.com/investor-relations/AM, under
the heading "SEC Filings," or by directing a request to Investor
Relations, Antero Midstream Partners LP, 1615 Wynkoop Street,
Denver, Colorado 80202, Tel. No.
(303) 357-7310. Copies of documents filed with the SEC by AMGP will
be made available free of charge on AMGP's website at
http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or
by directing a request to Investor Relations, Antero Midstream GP
LP, 1615 Wynkoop Street, Denver,
Colorado 80202, Tel. No. (303) 357-7310.
ANTERO RESOURCES
CORPORATION
Consolidated
Balance Sheets
December 31,
2017 and 2018
(In thousands,
except per share amounts)
|
|
|
|
2017
|
|
2018
|
Assets
|
Current
assets:
|
|
|
|
|
|
|
Cash and cash
equivalents
|
|
$
|
28,441
|
|
|
—
|
Accounts receivable,
net of allowance for doubtful accounts of $1,320 and $-0- at
December 31, 2017 and 2018, respectively
|
|
|
34,896
|
|
|
51,073
|
Accrued
revenue
|
|
|
300,122
|
|
|
474,827
|
Derivative
instruments
|
|
|
460,685
|
|
|
245,263
|
Other current
assets
|
|
|
8,943
|
|
|
35,450
|
Total current
assets
|
|
|
833,087
|
|
|
806,613
|
Property and
equipment:
|
|
|
|
|
|
|
Natural gas
properties, at cost (successful efforts method):
|
|
|
|
|
|
|
Unproved
properties
|
|
|
2,266,673
|
|
|
1,767,600
|
Proved
properties
|
|
|
11,096,462
|
|
|
12,705,672
|
Water handling and
treatment systems
|
|
|
946,670
|
|
|
1,013,818
|
Gathering systems and
facilities
|
|
|
2,050,490
|
|
|
2,470,708
|
Other property and
equipment
|
|
|
57,429
|
|
|
65,842
|
|
|
|
16,417,724
|
|
|
18,023,640
|
Less accumulated
depletion, depreciation, and amortization
|
|
|
(3,182,171)
|
|
|
(4,153,725)
|
Property and
equipment, net
|
|
|
13,235,553
|
|
|
13,869,915
|
Derivative
instruments
|
|
|
841,257
|
|
|
362,169
|
Investments in
unconsolidated affiliates
|
|
|
303,302
|
|
|
433,642
|
Other
assets
|
|
|
48,291
|
|
|
47,125
|
Total
assets
|
|
$
|
15,261,490
|
|
|
15,519,464
|
|
|
|
|
|
|
|
Liabilities and
Equity
|
Current
liabilities:
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
62,982
|
|
|
66,289
|
Accrued
liabilities
|
|
|
443,225
|
|
|
465,070
|
Revenue distributions
payable
|
|
|
209,617
|
|
|
310,827
|
Derivative
instruments
|
|
|
28,476
|
|
|
532
|
Other current
liabilities
|
|
|
17,796
|
|
|
10,822
|
Total current
liabilities
|
|
|
762,096
|
|
|
853,540
|
Long-term
liabilities:
|
|
|
|
|
|
|
Long-term
debt
|
|
|
4,800,090
|
|
|
5,461,688
|
Deferred income tax
liability
|
|
|
779,645
|
|
|
650,788
|
Derivative
instruments
|
|
|
207
|
|
|
—
|
Other
liabilities
|
|
|
43,316
|
|
|
65,971
|
Total
liabilities
|
|
|
6,385,354
|
|
|
7,031,987
|
Commitments and
contingencies (Notes 13 and 14)
|
|
|
|
|
|
|
Equity:
|
|
|
|
|
|
|
Stockholders'
equity:
|
|
|
|
|
|
|
Preferred stock, $0.01
par value; authorized - 50,000 shares; none issued
|
|
|
—
|
|
|
—
|
Common stock, $0.01
par value; authorized - 1,000,000 shares; 316,379 shares and
308,594 shares issued and outstanding at December 31, 2017 and
2018, respectively
|
|
|
3,164
|
|
|
3,086
|
Additional paid-in
capital
|
|
|
6,570,952
|
|
|
6,485,174
|
Accumulated
earnings
|
|
|
1,575,065
|
|
|
1,177,548
|
Total stockholders'
equity
|
|
|
8,149,181
|
|
|
7,665,808
|
Noncontrolling
interests in consolidated subsidiary
|
|
|
726,955
|
|
|
821,669
|
Total
equity
|
|
|
8,876,136
|
|
|
8,487,477
|
Total liabilities and
equity
|
|
$
|
15,261,490
|
|
|
15,519,464
|
ANTERO RESOURCES
CORPORATION
Condensed
Consolidated Statements of Operations and Comprehensive Income
(Loss)
Three Months and
Years Ended December 31, 2017 and 2018
(In thousands,
except per share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
|
|
2017
|
|
2018
|
|
2017
|
|
2018
|
|
Revenue and
other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
439,222
|
|
|
789,614
|
|
$
|
1,769,284
|
|
|
2,287,939
|
|
Natural gas liquids
sales
|
|
|
280,437
|
|
|
349,353
|
|
|
870,441
|
|
|
1,177,777
|
|
Oil sales
|
|
|
28,196
|
|
|
58,310
|
|
|
108,195
|
|
|
187,178
|
|
Commodity derivative
fair value gains (losses)
|
|
|
199,824
|
|
|
(222,386)
|
|
|
658,283
|
|
|
(87,594)
|
|
Gathering,
compression, water handling and treatment
|
|
|
4,055
|
|
|
6,047
|
|
|
12,720
|
|
|
21,344
|
|
Marketing
|
|
|
91,386
|
|
|
64,712
|
|
|
258,045
|
|
|
458,901
|
|
Marketing derivative
fair value gains (losses)
|
|
|
(21,394)
|
|
|
(1)
|
|
|
(21,394)
|
|
|
94,081
|
|
Total revenue and
other
|
|
|
1,021,726
|
|
|
1,045,649
|
|
|
3,655,574
|
|
|
4,139,626
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
33,023
|
|
|
42,998
|
|
|
89,057
|
|
|
136,153
|
|
Gathering,
compression, processing, and transportation
|
|
|
279,929
|
|
|
413,130
|
|
|
1,095,639
|
|
|
1,339,358
|
|
Production and ad
valorem taxes
|
|
|
24,180
|
|
|
44,242
|
|
|
94,521
|
|
|
126,474
|
|
Marketing
|
|
|
119,983
|
|
|
125,132
|
|
|
366,281
|
|
|
686,055
|
|
Exploration
|
|
|
3,028
|
|
|
936
|
|
|
8,538
|
|
|
4,958
|
|
Impairment of unproved
properties
|
|
|
76,500
|
|
|
143,370
|
|
|
159,598
|
|
|
549,437
|
|
Impairment of
gathering systems and facilities
|
|
|
23,431
|
|
|
—
|
|
|
23,431
|
|
|
9,658
|
|
Depletion,
depreciation, and amortization
|
|
|
213,731
|
|
|
262,985
|
|
|
824,610
|
|
|
972,465
|
|
Accretion of asset
retirement obligations
|
|
|
666
|
|
|
719
|
|
|
2,610
|
|
|
2,819
|
|
General and
administrative (including equity-based compensation
expense)
|
|
|
60,196
|
|
|
58,767
|
|
|
251,196
|
|
|
240,344
|
|
Total operating
expenses
|
|
|
834,667
|
|
|
1,092,279
|
|
|
2,915,481
|
|
|
4,067,721
|
|
Operating income
(loss)
|
|
|
187,059
|
|
|
(46,630)
|
|
|
740,093
|
|
|
71,905
|
|
Other income
(expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of
unconsolidated affiliates
|
|
|
7,307
|
|
|
12,449
|
|
|
20,194
|
|
|
40,280
|
|
Interest
|
|
|
(63,390)
|
|
|
(78,440)
|
|
|
(268,701)
|
|
|
(286,743)
|
|
Loss on early
extinguishment of debt
|
|
|
(1,500)
|
|
|
—
|
|
|
(1,500)
|
|
|
—
|
|
Total other
expenses
|
|
|
(57,583)
|
|
|
(65,991)
|
|
|
(250,007)
|
|
|
(246,463)
|
|
Income (loss) before
income taxes
|
|
|
129,476
|
|
|
(112,621)
|
|
|
490,086
|
|
|
(174,558)
|
|
Provision for income
tax benefit
|
|
|
400,138
|
|
|
131,357
|
|
|
295,051
|
|
|
128,857
|
|
Net income (loss) and
comprehensive income (loss) including noncontrolling
interests
|
|
|
529,614
|
|
|
18,736
|
|
|
785,137
|
|
|
(45,701)
|
|
Net income and
comprehensive income attributable to noncontrolling
interests
|
|
|
42,745
|
|
|
140,282
|
|
|
170,067
|
|
|
351,816
|
|
Net income (loss) and
comprehensive income (loss) attributable to Antero Resources
Corporation
|
|
$
|
486,869
|
|
|
(121,546)
|
|
$
|
615,070
|
|
|
(397,517)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per
common share—basic
|
|
$
|
1.54
|
|
|
(0.39)
|
|
$
|
1.95
|
|
|
(1.26)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings (loss) per
common share—assuming dilution
|
|
$
|
1.54
|
|
|
(0.39)
|
|
$
|
1.94
|
|
|
(1.26)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
number of shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
315,875
|
|
|
313,618
|
|
|
315,426
|
|
|
316,036
|
|
Diluted
|
|
|
316,682
|
|
|
313,618
|
|
|
316,283
|
|
|
316,036
|
|
ANTERO RESOURCES
CORPORATION
Consolidated
Statements of Cash Flows
Years Ended
December 31, 2016, 2017 and 2018
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2016
|
|
2017
|
|
2018
|
|
Cash flows provided
by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net income (loss)
including noncontrolling interests
|
|
$
|
(749,448)
|
|
|
785,137
|
|
|
(45,701)
|
|
Adjustments to
reconcile net income (loss) to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
Depletion,
depreciation, amortization, and accretion
|
|
|
812,346
|
|
|
827,220
|
|
|
975,284
|
|
Impairment of unproved
properties
|
|
|
162,935
|
|
|
159,598
|
|
|
549,437
|
|
Impairment of
gathering systems and facilities
|
|
|
—
|
|
|
23,431
|
|
|
9,658
|
|
Commodity derivative
fair value (gains) losses
|
|
|
514,181
|
|
|
(658,283)
|
|
|
87,594
|
|
Gains on settled
commodity derivatives
|
|
|
1,003,083
|
|
|
213,940
|
|
|
243,112
|
|
Premium paid on
derivative contracts
|
|
|
—
|
|
|
—
|
|
|
(13,318)
|
|
Proceeds from
derivative monetizations
|
|
|
—
|
|
|
749,906
|
|
|
370,365
|
|
Marketing derivative
fair value (gains) losses
|
|
|
—
|
|
|
21,394
|
|
|
(94,081)
|
|
Gains on settled
marketing derivatives
|
|
|
—
|
|
|
—
|
|
|
72,687
|
|
Deferred income tax
benefit
|
|
|
(485,392)
|
|
|
(295,126)
|
|
|
(128,857)
|
|
Gain on sale of
assets
|
|
|
(97,635)
|
|
|
—
|
|
|
—
|
|
Equity-based
compensation expense
|
|
|
102,421
|
|
|
103,445
|
|
|
70,414
|
|
Loss on early
extinguishment of debt
|
|
|
16,956
|
|
|
1,500
|
|
|
—
|
|
Equity in earnings of
unconsolidated affiliates
|
|
|
(485)
|
|
|
(20,194)
|
|
|
(40,280)
|
|
Distributions of
earnings from unconsolidated affiliates
|
|
|
7,702
|
|
|
20,195
|
|
|
46,415
|
|
Other
|
|
|
(12,488)
|
|
|
(1,907)
|
|
|
4,681
|
|
Changes in current
assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
39,857
|
|
|
(5,214)
|
|
|
(15,156)
|
|
Accrued
revenue
|
|
|
(133,718)
|
|
|
(38,162)
|
|
|
(174,706)
|
|
Other current
assets
|
|
|
1,774
|
|
|
(2,755)
|
|
|
(5,817)
|
|
Accounts
payable
|
|
|
7,365
|
|
|
9,462
|
|
|
9,307
|
|
Accrued
liabilities
|
|
|
18,853
|
|
|
64,862
|
|
|
63,562
|
|
Revenue distributions
payable
|
|
|
34,040
|
|
|
45,628
|
|
|
101,210
|
|
Other current
liabilities
|
|
|
(1,091)
|
|
|
2,214
|
|
|
(3,823)
|
|
Net cash provided by
operating activities
|
|
|
1,241,256
|
|
|
2,006,291
|
|
|
2,081,987
|
|
Cash flows provided
by (used in) investing activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to proved
properties
|
|
|
(134,113)
|
|
|
(175,650)
|
|
|
—
|
|
Additions to unproved
properties
|
|
|
(611,631)
|
|
|
(204,272)
|
|
|
(172,387)
|
|
Drilling and
completion costs
|
|
|
(1,327,759)
|
|
|
(1,281,985)
|
|
|
(1,488,573)
|
|
Additions to water
handling and treatment systems
|
|
|
(188,188)
|
|
|
(194,502)
|
|
|
(97,699)
|
|
Additions to gathering
systems and facilities
|
|
|
(231,044)
|
|
|
(346,217)
|
|
|
(444,413)
|
|
Additions to other
property and equipment
|
|
|
(2,694)
|
|
|
(14,127)
|
|
|
(7,514)
|
|
Investments in
unconsolidated affiliates
|
|
|
(75,516)
|
|
|
(235,004)
|
|
|
(136,475)
|
|
Change in other
assets
|
|
|
3,977
|
|
|
(12,029)
|
|
|
(3,663)
|
|
Proceeds from asset
sales
|
|
|
171,830
|
|
|
2,156
|
|
|
—
|
|
Net cash used in
investing activities
|
|
|
(2,395,138)
|
|
|
(2,461,630)
|
|
|
(2,350,724)
|
|
Cash flows provided
by (used in) financing activities:
|
|
|
|
|
|
|
|
|
|
|
Issuance of common
stock
|
|
|
1,012,431
|
|
|
—
|
|
|
—
|
|
Issuance of common
units by Antero Midstream Partners LP
|
|
|
65,395
|
|
|
248,956
|
|
|
—
|
|
Proceeds from sale of
common units of Antero Midstream Partners LP held by Antero
Resources Corporation
|
|
|
178,000
|
|
|
311,100
|
|
|
—
|
|
Repurchases of common
stock
|
|
|
—
|
|
|
—
|
|
|
(129,084)
|
|
Issuance of senior
notes
|
|
|
1,250,000
|
|
|
—
|
|
|
—
|
|
Repayment of senior
notes
|
|
|
(525,000)
|
|
|
—
|
|
|
—
|
|
Borrowings
(repayments) on bank credit facilities, net
|
|
|
(677,000)
|
|
|
90,000
|
|
|
660,379
|
|
Make-whole premium on
debt extinguished
|
|
|
(15,750)
|
|
|
—
|
|
|
—
|
|
Payments of deferred
financing costs
|
|
|
(18,759)
|
|
|
(16,377)
|
|
|
(2,169)
|
|
Distributions to
noncontrolling interests in consolidated subsidiary
|
|
|
(75,082)
|
|
|
(152,352)
|
|
|
(267,271)
|
|
Employee tax
withholding for settlement of equity compensation awards
|
|
|
(26,895)
|
|
|
(24,174)
|
|
|
(17,020)
|
|
Other
|
|
|
(5,321)
|
|
|
(4,983)
|
|
|
(4,539)
|
|
Net cash provided by
financing activities
|
|
|
1,162,019
|
|
|
452,170
|
|
|
240,296
|
|
Net increase
(decrease) in cash and cash equivalents
|
|
|
8,137
|
|
|
(3,169)
|
|
|
(28,441)
|
|
Cash and cash
equivalents, beginning of period
|
|
|
23,473
|
|
|
31,610
|
|
|
28,441
|
|
Cash and cash
equivalents, end of period
|
|
$
|
31,610
|
|
|
28,441
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
disclosure of cash flow information:
|
|
|
|
|
|
|
|
|
|
|
Cash paid during the
period for interest
|
|
$
|
239,369
|
|
|
263,919
|
|
|
275,769
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in accounts
payable and accrued liabilities for additions to property and
equipment
|
|
$
|
(152,093)
|
|
|
(547)
|
|
|
(47,717)
|
|
ANTERO RESOURCES
CORPORATION
The following tables
set forth selected operating data for the three months ended
December 31, 2017 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Amount of
Increase
|
|
Percent
|
|
|
(in thousands)
|
|
2017
|
|
2018
|
|
(Decrease)
|
|
Change
|
|
|
Operating revenues
and other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
439,222
|
|
$
|
789,614
|
|
$
|
350,392
|
|
80
|
%
|
|
NGLs sales
|
|
|
280,437
|
|
|
349,353
|
|
|
68,916
|
|
25
|
%
|
|
Oil sales
|
|
|
28,196
|
|
|
58,310
|
|
|
30,114
|
|
107
|
%
|
|
Commodity derivative
fair value gains (losses)
|
|
|
199,824
|
|
|
(222,386)
|
|
|
(422,210)
|
|
(211)
|
%
|
|
Gathering, compression,
water handling and treatment
|
|
|
4,055
|
|
|
6,047
|
|
|
1,992
|
|
49
|
%
|
|
Marketing
|
|
|
91,386
|
|
|
64,712
|
|
|
(26,674)
|
|
(29)
|
%
|
|
Marketing derivative
fair value gains
|
|
|
(21,394)
|
|
|
(1)
|
|
|
21,393
|
|
(100)
|
%
|
|
Total operating
revenues and other
|
|
|
1,021,726
|
|
|
1,045,649
|
|
|
23,923
|
|
2
|
%
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
33,023
|
|
|
42,998
|
|
|
9,975
|
|
30
|
%
|
|
Gathering, compression,
processing, and transportation
|
|
|
279,929
|
|
|
413,130
|
|
|
133,201
|
|
48
|
%
|
|
Production and ad
valorem taxes
|
|
|
24,180
|
|
|
44,242
|
|
|
20,062
|
|
83
|
%
|
|
Marketing
|
|
|
119,983
|
|
|
125,132
|
|
|
5,149
|
|
4
|
%
|
|
Exploration
|
|
|
3,028
|
|
|
936
|
|
|
(2,092)
|
|
(69)
|
%
|
|
Impairment of unproved
properties
|
|
|
76,500
|
|
|
143,370
|
|
|
66,870
|
|
87
|
%
|
|
Impairment of gathering
systems and facilities
|
|
|
23,431
|
|
|
—
|
|
|
(23,431)
|
|
(100)
|
%
|
|
Depletion,
depreciation, and amortization
|
|
|
213,731
|
|
|
262,985
|
|
|
49,254
|
|
23
|
%
|
|
Accretion of asset
retirement obligations
|
|
|
666
|
|
|
719
|
|
|
53
|
|
8
|
%
|
|
General and
administrative (excluding equity-based compensation)
|
|
|
35,676
|
|
|
44,782
|
|
|
9,106
|
|
26
|
%
|
|
Equity-based
compensation
|
|
|
24,520
|
|
|
13,985
|
|
|
(10,535)
|
|
(43)
|
%
|
|
Total operating
expenses
|
|
|
834,667
|
|
|
1,092,279
|
|
|
257,612
|
|
31
|
%
|
|
Operating income
(loss)
|
|
|
187,059
|
|
|
(46,630)
|
|
|
(233,689)
|
|
(125)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other earnings
(expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of
unconsolidated affiliates
|
|
|
7,307
|
|
|
12,449
|
|
|
5,142
|
|
70
|
%
|
|
Interest
expense
|
|
|
(63,390)
|
|
|
(78,440)
|
|
|
(15,050)
|
|
24
|
%
|
|
Loss on early
extinguishment of debt
|
|
|
(1,500)
|
|
|
—
|
|
|
1,500
|
|
(100)
|
%
|
|
Total other
expenses
|
|
|
(57,583)
|
|
|
(65,991)
|
|
|
(8,408)
|
|
15
|
%
|
|
Income (loss) before
income taxes
|
|
|
129,476
|
|
|
(112,621)
|
|
|
(242,097)
|
|
(187)
|
%
|
|
Income tax (expense)
benefit
|
|
|
400,138
|
|
|
(131,357)
|
|
|
(531,495)
|
|
(66)
|
%
|
|
Net income (loss) and
comprehensive income (loss) including noncontrolling
interest
|
|
|
529,614
|
|
|
18,736
|
|
|
(510,878)
|
|
(96)
|
%
|
|
Net income and
comprehensive income attributable to noncontrolling
interest
|
|
|
42,745
|
|
|
140,282
|
|
|
97,537
|
|
228
|
%
|
|
Net income (loss) and
comprehensive income (loss) attributable to Antero Resources
Corporation
|
|
$
|
486,869
|
|
$
|
(121,546)
|
|
$
|
(608,415)
|
|
(125)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDAX
|
|
$
|
437,128
|
|
$
|
583,837
|
|
$
|
146,709
|
|
34
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31,
|
|
Amount of
Increase
|
|
Percent
|
|
|
(Exploration and
Production segment)
|
|
2017
|
|
2018
|
|
(Decrease)
|
|
Change
|
|
|
Production
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(Bcf)
|
|
|
157
|
|
|
206
|
|
|
49
|
|
31
|
%
|
|
C2 Ethane
(MBbl)
|
|
|
2,891
|
|
|
4,323
|
|
|
1,432
|
|
50
|
%
|
|
C3+ NGLs
(MBbl)
|
|
|
6,422
|
|
|
9,463
|
|
|
3,041
|
|
47
|
%
|
|
Oil (MBbl)
|
|
|
571
|
|
|
1,125
|
|
|
554
|
|
97
|
%
|
|
Combined
(Bcfe)
|
|
|
216
|
|
|
296
|
|
|
80
|
|
37
|
%
|
|
Daily combined
production (MMcfe/d)
|
|
|
2,347
|
|
|
3,213
|
|
|
866
|
|
37
|
%
|
|
Average prices
before effects of derivative settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
$
|
2.80
|
|
$
|
3.83
|
|
$
|
1.03
|
|
37
|
%
|
|
C2 Ethane (per
Bbl)
|
|
$
|
10.02
|
|
$
|
13.12
|
|
$
|
3.10
|
|
31
|
%
|
|
C3+ NGLs (per
Bbl)
|
|
$
|
39.16
|
|
$
|
30.92
|
|
$
|
(8.24)
|
|
(21)
|
%
|
|
Oil (per
Bbl)
|
|
$
|
49.37
|
|
$
|
51.83
|
|
$
|
2.46
|
|
5
|
%
|
|
Weighted Average
Combined (per Mcfe)
|
|
$
|
3.46
|
|
$
|
4.05
|
|
$
|
0.59
|
|
17
|
%
|
|
Average realized
prices after effects of derivative settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
$
|
3.67
|
|
$
|
3.73
|
|
$
|
0.06
|
|
2
|
%
|
|
C2 Ethane (per
Bbl)
|
|
$
|
10.17
|
|
$
|
13.12
|
|
$
|
2.95
|
|
29
|
%
|
|
C3+ NGLs (per
Bbl)
|
|
$
|
29.92
|
|
$
|
30.60
|
|
$
|
0.68
|
|
2
|
%
|
|
Oil (per
Bbl)
|
|
$
|
49.06
|
|
$
|
50.92
|
|
$
|
1.86
|
|
4
|
%
|
|
Weighted Average
Combined (per Mcfe)
|
|
$
|
3.82
|
|
$
|
3.97
|
|
$
|
0.15
|
|
4
|
%
|
|
Average Costs (per
Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
$
|
0.17
|
|
$
|
0.15
|
|
$
|
(0.02)
|
|
(12)
|
%
|
|
Gathering,
compression, processing, and transportation
|
|
$
|
1.72
|
|
$
|
1.88
|
|
$
|
0.16
|
|
9
|
%
|
|
Production and ad
valorem taxes
|
|
$
|
0.11
|
|
$
|
0.15
|
|
$
|
0.04
|
|
36
|
%
|
|
Marketing expense,
net
|
|
$
|
0.13
|
|
$
|
0.20
|
|
$
|
0.07
|
|
54
|
%
|
|
Depletion,
depreciation, amortization, and accretion
|
|
$
|
0.85
|
|
$
|
0.82
|
|
$
|
(0.03)
|
|
(4)
|
%
|
|
General and
administrative (excluding equity-based compensation)
|
|
$
|
0.13
|
|
$
|
0.11
|
|
$
|
(0.02)
|
|
(15)
|
%
|
|
ANTERO RESOURCES
CORPORATION
The following tables
set forth selected operating data for the years ended
December 31, 2017 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
Amount of
Increase
|
|
Percent
|
|
|
(in thousands)
|
|
2017
|
|
2018
|
|
(Decrease)
|
|
Change
|
|
|
Operating revenues
and other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
1,769,284
|
|
$
|
2,287,939
|
|
$
|
518,655
|
|
29
|
%
|
|
NGLs sales
|
|
|
870,441
|
|
|
1,177,777
|
|
|
307,336
|
|
35
|
%
|
|
Oil sales
|
|
|
108,195
|
|
|
187,178
|
|
|
78,983
|
|
73
|
%
|
|
Commodity derivative
fair value gains (losses)
|
|
|
658,283
|
|
|
(87,594)
|
|
|
(745,877)
|
|
(113)
|
%
|
|
Gathering, compression,
water handling and treatment
|
|
|
12,720
|
|
|
21,344
|
|
|
8,624
|
|
68
|
%
|
|
Marketing
|
|
|
258,045
|
|
|
458,901
|
|
|
200,856
|
|
78
|
%
|
|
Marketing derivative
fair value gains
|
|
|
(21,394)
|
|
|
94,081
|
|
|
115,475
|
|
(540)
|
%
|
|
Total operating
revenues and other
|
|
|
3,655,574
|
|
|
4,139,626
|
|
|
484,052
|
|
13
|
%
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
89,057
|
|
|
136,153
|
|
|
47,096
|
|
53
|
%
|
|
Gathering, compression,
processing, and transportation
|
|
|
1,095,639
|
|
|
1,339,358
|
|
|
243,719
|
|
22
|
%
|
|
Production and ad
valorem taxes
|
|
|
94,521
|
|
|
126,474
|
|
|
31,953
|
|
34
|
%
|
|
Marketing
|
|
|
366,281
|
|
|
686,055
|
|
|
319,774
|
|
87
|
%
|
|
Exploration
|
|
|
8,538
|
|
|
4,958
|
|
|
(3,580)
|
|
(42)
|
%
|
|
Impairment of unproved
properties
|
|
|
159,598
|
|
|
549,437
|
|
|
389,839
|
|
244
|
%
|
|
Impairment of gathering
systems and facilities
|
|
|
23,431
|
|
|
9,658
|
|
|
(13,773)
|
|
(59)
|
%
|
|
Depletion,
depreciation, and amortization
|
|
|
824,610
|
|
|
972,465
|
|
|
147,855
|
|
18
|
%
|
|
Accretion of asset
retirement obligations
|
|
|
2,610
|
|
|
2,819
|
|
|
209
|
|
8
|
%
|
|
General and
administrative (excluding equity-based compensation)
|
|
|
147,751
|
|
|
169,930
|
|
|
22,179
|
|
15
|
%
|
|
Equity-based
compensation
|
|
|
103,445
|
|
|
70,414
|
|
|
(33,031)
|
|
(32)
|
%
|
|
Total operating
expenses
|
|
|
2,915,481
|
|
|
4,067,721
|
|
|
1,152,240
|
|
40
|
%
|
|
Operating income
(loss)
|
|
|
740,093
|
|
|
71,905
|
|
|
(668,188)
|
|
(90)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other earnings
(expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity in earnings of
unconsolidated affiliates
|
|
|
20,194
|
|
|
40,280
|
|
|
20,086
|
|
99
|
%
|
|
Interest
expense
|
|
|
(268,701)
|
|
|
(286,743)
|
|
|
(18,042)
|
|
7
|
%
|
|
Loss on early
extinguishment of debt
|
|
|
(1,500)
|
|
|
—
|
|
|
1,500
|
|
(100)
|
%
|
|
Total other
expenses
|
|
|
(250,007)
|
|
|
(246,463)
|
|
|
3,544
|
|
(1)
|
%
|
|
Income (loss) before
income taxes
|
|
|
490,086
|
|
|
(174,558)
|
|
|
(664,644)
|
|
(136)
|
%
|
|
Income tax
benefit
|
|
|
295,051
|
|
|
128,857
|
|
|
(166,194)
|
|
(56)
|
%
|
|
Net income (loss) and
comprehensive income (loss) including noncontrolling
interest
|
|
|
785,137
|
|
|
(45,701)
|
|
|
(830,838)
|
|
(106)
|
%
|
|
Net income and
comprehensive income attributable to noncontrolling
interest
|
|
|
170,067
|
|
|
351,816
|
|
|
181,749
|
|
107
|
%
|
|
Net income (loss) and
comprehensive income (loss) attributable to Antero Resources
Corporation
|
|
$
|
615,070
|
|
$
|
(397,517)
|
|
$
|
(1,012,587)
|
|
(165)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDAX
|
|
$
|
1,459,571
|
|
$
|
2,037,382
|
|
$
|
577,811
|
|
40
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended
December 31,
|
|
Amount of
Increase
|
|
Percent
|
|
|
(Exploration and
Production segment)
|
|
2017
|
|
2018
|
|
(Decrease)
|
|
Change
|
|
|
Production
data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(Bcf)
|
|
|
591
|
|
|
710
|
|
|
119
|
|
20
|
%
|
|
C2 Ethane
(MBbl)
|
|
|
10,539
|
|
|
14,221
|
|
|
3,682
|
|
35
|
%
|
|
C3+ NGLs
(MBbl)
|
|
|
25,507
|
|
|
28,913
|
|
|
3,406
|
|
13
|
%
|
|
Oil (MBbl)
|
|
|
2,451
|
|
|
3,265
|
|
|
814
|
|
33
|
%
|
|
Combined
(Bcfe)
|
|
|
822
|
|
|
989
|
|
|
167
|
|
20
|
%
|
|
Daily combined
production (MMcfe/d)
|
|
|
2,253
|
|
|
2,709
|
|
|
456
|
|
20
|
%
|
|
Average prices
before effects of derivative settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
$
|
2.99
|
|
$
|
3.22
|
|
$
|
0.23
|
|
8
|
%
|
|
C2 Ethane (per
Bbl)
|
|
$
|
8.83
|
|
$
|
12.14
|
|
$
|
3.31
|
|
37
|
%
|
|
C3+ NGLs (per
Bbl)
|
|
$
|
30.48
|
|
$
|
34.76
|
|
$
|
4.28
|
|
14
|
%
|
|
Oil (per
Bbl)
|
|
$
|
44.14
|
|
$
|
57.34
|
|
$
|
13.20
|
|
30
|
%
|
|
Weighted Average
Combined (per Mcfe)
|
|
$
|
3.34
|
|
$
|
3.69
|
|
$
|
0.35
|
|
10
|
%
|
|
Average realized
prices after effects of derivative settlements:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
$
|
3.61
|
|
$
|
3.65
|
|
$
|
0.04
|
|
1
|
%
|
|
C2 Ethane (per
Bbl)
|
|
$
|
9.04
|
|
$
|
12.14
|
|
$
|
3.10
|
|
34
|
%
|
|
C3+ NGLs (per
Bbl)
|
|
$
|
24.27
|
|
$
|
33.25
|
|
$
|
8.98
|
|
37
|
%
|
|
Oil (per
Bbl)
|
|
$
|
45.85
|
|
$
|
52.11
|
|
$
|
6.26
|
|
14
|
%
|
|
Weighted Average
Combined (per Mcfe)
|
|
$
|
3.60
|
|
$
|
3.94
|
|
$
|
0.34
|
|
9
|
%
|
|
Average Costs (per
Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
$
|
0.11
|
|
$
|
0.14
|
|
$
|
0.03
|
|
27
|
%
|
|
Gathering,
compression, processing, and transportation
|
|
$
|
1.75
|
|
$
|
1.81
|
|
$
|
0.06
|
|
3
|
%
|
|
Production and ad
valorem taxes
|
|
$
|
0.11
|
|
$
|
0.12
|
|
$
|
0.01
|
|
9
|
%
|
|
Marketing expense,
net
|
|
$
|
0.13
|
|
$
|
0.23
|
|
$
|
0.10
|
|
77
|
%
|
|
Depletion,
depreciation, amortization, and accretion
|
|
$
|
0.86
|
|
$
|
0.85
|
|
$
|
(0.01)
|
|
(1)
|
%
|
|
General and
administrative (excluding equity-based compensation)
|
|
$
|
0.14
|
|
$
|
0.13
|
|
$
|
(0.01)
|
|
(7)
|
%
|
|
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SOURCE Antero Resources Corporation