DENVER, Feb. 17, 2021 /PRNewswire/ -- Antero
Resources Corporation (NYSE: AR) ("Antero
Resources", "Antero", or the "Company") today announced its
fourth quarter and full year 2020 financial and operational results
as well as its 2021 capital budget, guidance and proved reserves as
of December 31, 2020. In
addition, Antero announced the formation of a drilling
partnership. The relevant consolidated financial statements
are included in Antero Resource's Annual Report on Form 10-K for
the year ended December 31,
2020.
Fourth Quarter 2020 Highlights Include:
- Net production averaged 3,650 MMcfe/d, including 199,000
Bbl/d of liquids
- Realized natural gas equivalent price including hedges
averaged $3.12 per Mcfe, a
$0.46 premium to NYMEX
pricing
- Net income was $70
million
- Adjusted EBITDAX was $299
million (Non-GAAP); net cash provided by operating
activities was $243 million
- Drilling and completion capital expenditures were
$84 million, a 69% reduction from the
year ago period
- Free Cash Flow before changes in working capital was
$155 million (Non-GAAP)
- Achieved record 60-day rate per well of 33.9 MMcfe/d for 10
wells placed on-line during the quarter
- Proved reserves were 17.6 Tcfe at year end 2020 and proved
developed reserves increased to 11.9 Tcfe (67% Proved
Developed)
- Future development cost for 5.8 Tcfe of proved undeveloped
reserves is $0.27 per Mcfe
2021 Guidance and Other Highlights:
- Announced formation of a $500
to $550 million drilling partnership
to fund drilling of 60 incremental wells from 2021 through 2024,
enabling Antero to fill unutilized firm transportation capacity,
receive additional low pressure gathering fee rebates and realize a
cash drilling carry. This partnership
begins immediately and includes all wells spud since January 1, 2021.
- Drilling and completion capital budget of
$590 million net to Antero, down
21% from 2020
- Maintenance level capital program includes 60 to 65 well
completions in 2021, average lateral length of 13,150 feet
- Well cost average of $660 per
lateral foot, declining to $635 per
lateral foot for the second half of 2021
- Net production is expected to average 3.3 to 3.4 Bcfe/d,
including 170,000 to 175,000 Bbl/d of liquids (NGLs and
oil)
- Natural gas realizations expected to be a $0.10 to $0.20 per
MMBtu premium to NYMEX, before hedges
- Received $85 million in net
litigation proceeds in February 2021
for underpayment of a natural gas contract
Paul Rady, Chairman and Chief
Executive Officer of Antero Resources commented, "Antero's unique
position of having market leading exposure to attractive C3+ NGL
prices, a premium firm transportation portfolio and extensive
premium core drilling inventory creates a highly accretive
development program in 2021. In addition, the drilling
partnership announced today and the incremental gross production
generated thereby is estimated to add incremental free cash flow to
Antero of $400 million through 2025,
assuming current strip prices. This significant incremental
free cash flow results from filling of our premium firm
transportation capacity, capturing additional LP gathering
incentive fees from Antero Midstream and realizing carry payments
from our drilling partner."
Mr. Rady continued, "Our 2021 capital budget reflects our shift
to a maintenance level capital plan and the benefit from our well
cost savings initiatives that we launched in 2019. We are
targeting total well costs of $635
per lateral foot for the second half of 2021, a 35% reduction from
$970 in the initial 2019
budget. Our ability to reduce costs and lower capital
spending, combined with the benefits of the drilling partnership,
puts us in position to generate over $500
million of free cash flow in 2021 and exceed $1.5 billion of cumulative free cash flow through
2025, based on today's commodity strip. We intend to use the
free cash flow to reduce debt, which will rapidly decrease our
leverage profile from 3.1x at year end 2020 to below 2-times in
2021, at current strip prices."
Glen Warren, President, and Chief
Financial Officer of Antero Resources said, "Through a combination
of asset sales and discounted debt repurchases, we reduced absolute
debt by over $800 million since the
start of our deleveraging program. Assuming strip pricing, we
are in position to achieve our leverage target of below 2-times
this year. Longer term, we will remain focused on maintaining
a low leverage profile, while maximizing free cash flow.
Finally, as we approach our leverage targets, we can begin to
consider further return of capital to our
shareholders."
For a discussion of the non-GAAP financial measures including
Adjusted EBITDAX and Free Cash Flow please see "Non-GAAP Financial
Measures."
Drilling Partnership Announcement
Antero announced the
formation of a $500 to $550 million drilling partnership with QL Capital
Partners ("QL"), an affiliate of Quantum Energy Partners. Antero is
uniquely positioned to take on a drilling partner due to unutilized
firm transportation, a deep liquids-rich drilling inventory and
already established LP gathering incentive program with Antero
Midstream. Under the terms of the agreement, QL will fund 20%
of total development capital spending in 2021 and between 15% and
20% of total development capital spending on an annual basis from
2022 through 2024 in exchange for a proportionate working interest
percentage in each well spud. Each calendar year represents a
tranche including 2021 which begins with wells spud as of
January 1, 2021. In addition,
QL will pay a drilling carry to Antero on a tranche by tranche
basis, at the end of the year following the tranche year, if
certain return thresholds are achieved. Assuming QL's full
participation through 2024, the partnership will enable the
drilling and completion of approximately 60 incremental wells
relative to Antero's prior base case of maintenance level capital
plans. Antero's 2021 net capital spending and net production
remains unchanged at the maintenance capital level. Please
see Antero's Annual Report on Form 10-K for additional details on
the drilling partnership. RBC Capital Markets and Vinson
& Elkins LLP acted as exclusive financial and legal advisors,
respectively, to the Company.
The following tables provide a guidance summary for 2021 and
targets for 2022 through 2024 for the prior base case compared to
the full commitment by QL under the drilling partnership. The
Company's board of directors has not approved any capital budget or
development plan beyond 2021. The first incremental wells
will be completed in the fourth quarter of 2021, and therefore will
have limited impact on the 2021 development plan. Under these
assumptions, from 2022 through 2024 there would be minimal impact
to production, capital expenditures or wells drilled and completed
on a net basis to Antero.
2021 Prior Base vs
Drilling Partnership
|
|
Prior Base
Case
|
|
Drilling
Partnership (1)
|
|
Incremental
|
|
|
Low
|
|
High
|
|
Low
|
|
High
|
|
Gross
Wells
|
Drilled
Wells
Completed
Wells
|
|
65
60
|
|
70
65
|
|
80
65
|
|
85
70
|
|
15
5
|
2021 – 2024 Prior
Base vs Drilling Partnership
|
|
Prior Base
Case
|
|
Drilling
Partnership
(1)
|
|
Incremental
Gross
Wells
|
|
Drilled
Wells Completed
Wells
|
|
250
255
|
|
310
315
|
|
60
60
|
|
(1) Represents
gross wells pro forma for the drilling partnership
|
|
|
|
|
|
|
|
|
|
2022 - 2025 Base
Case vs Drilling Partnership
|
|
Prior
Base
|
|
Drilling
Partnership
|
|
Delta
|
|
Free
Cash
|
|
|
Low
|
|
High
|
|
Low
|
|
High
|
|
(Midpoint)
|
|
Flow Impact
(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GP&T Expense
($/Mcfe) (1)
Net Marketing Expense
($/Mcfe)
Net Interest Expense
($/Mcfe)
|
|
$1.90
$0.10
$0.05
|
|
$2.05
$0.12
$0.06
|
|
$1.87
$0.03
$0.04
|
|
$2.04
$0.05
$0.05
|
|
($0.02)
($0.07)
($0.01)
|
|
$75
$260
$20
|
Estimated carry
Payments ($MM)
|
|
|
|
|
|
|
|
|
|
|
|
$50
|
Free Cash Flow
($MM) (2)
|
|
|
|
|
|
|
|
|
|
|
|
$405
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1)
|
Represents $75 MM of
incremental midstream fee rebates earned due to drilling
partnership.
|
(2)
|
For a description of
the non-GAAP financial measure Free Cash Flow, please read
"Non-GAAP Financial Measures."
|
(3)
|
Assumes maintenance
level net capital spending in 2022, 2023, 2024 and 2025.
|
The drilling partnership is forecast to increase Antero's Free
Cash Flow by approximately $400
million through 2025 compared to Antero's prior base case
plan by accelerating the decline in unutilized firm transportation
expense, capturing midstream fee rebates, achieving carry payments
from our drilling partner, as well as lower interest costs due to
lower total debt. As a result, Antero expects to achieve its
absolute debt target of below $2.0
billion in 2023, based on current strip pricing.
Resolution of Washington Gas Light Company Litigation
Antero received proceeds of $85
million, net of royalty payments, from Washington Gas Light
Company ("WGL") in February 2021. The payment is due to a
favorable judgment on previously disclosed contractual disputes
involving firm gas sales contracts between Antero and WGL during
the years 2016 to 2018. The judgment was affirmed on December 10, 2020, and the judgment was satisfied
in full with WGL's payment. The net proceeds from the
litigation judgement were realized as gas revenue in the first
quarter of 2021 and are included in EBITDAX and Free Cash Flow. In addition, the
proceeds were used to pay down Antero's credit facility. For
further information on this litigation, please see Antero's Annual
Report on Form 10-K for the year ended December 31, 2020.
February Winter Weather Event
Antero has not been
faced with curtailments to date due to the winter weather in
February across the U.S. This has enabled Antero through its firm transportation
portfolio to deliver certain equity and third party volumes that
had not been contractually committed on a first of month basis, to locations that required
additional gas volumes. This sales point flexibility enabled
Antero to redirect equity volumes as well as purchase third party
gas and market those volumes in the Midwest and on the Gulf Coast
where gas was most needed
and prices were elevated due to freeze offs throughout
much of the central and southwestern U.S. Antero has realized
incremental revenue of $75 million to
date, net of royalties and taxes that will result in improved
natural gas realizations and reduced net marketing expense during
the first quarter of 2021.
2021 Capital Budget and Guidance
The following is a
summary of Antero Resources' 2021 capital budget.
Capital Budget ($
in Millions)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling &
Completion
|
|
|
|
$590
|
|
|
Land
|
|
|
|
$45
|
|
|
Total E&P Capital
|
|
|
|
$635
|
|
|
|
|
|
|
|
Gross
|
|
Average
|
|
With Drilling
Partnership
|
|
|
|
|
Wells
|
|
Lateral
Length
|
|
Drilled
Wells
|
|
|
|
|
80 to 85
|
|
13,250
feet
|
|
Completed
Wells
|
|
|
|
|
65 to 70
|
|
13,150
feet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following is a summary of Antero Resources' 2021 production,
pricing and cash expense guidance.
Production
Guidance
|
|
|
|
|
|
Net Daily Natural Gas
Equivalent Production (MMcfe/d)
|
|
|
3,300 -
3,400(1)
|
|
Net Daily Natural Gas
Production (MMcf/d)
|
|
|
2,300 –
2,350
|
|
Total Net Daily
Liquids Production (Bbl/d):
|
|
|
170,000 –
175,000
|
|
Realized Pricing
Guidance
|
|
|
|
|
|
Natural Gas Realized
Price vs. NYMEX Henry Hub ($/Mcf)
|
|
$0.10 –
$0.20
|
|
C3+ NGL Realized
Price vs. Mont Belvieu ($/Gal)
|
|
$0.00 –
$0.05
|
|
Oil Realized Price
vs. WTI Oil ($/Bbl)
|
|
($9.00) –
($11.00)
|
|
|
|
|
|
|
|
|
|
Cash Expense
Guidance
|
|
|
Low
|
|
High
|
Cash Production
Expense ($/Mcfe)(2)
|
|
|
$2.18
|
|
$2.23
|
Marketing Expense,
Net of Marketing Revenue ($/Mcfe)
|
|
|
$0.08
|
|
$0.10
|
G&A Expense
($/Mcfe)(3)
|
|
|
$0.08
|
|
$0.10
|
|
|
|
|
|
|
|
(1)
|
Assumes C3+ NGL price
strip as of February 15, 2021 of $35 per Bbl. At this price, all
NGL volumes are economic to process and are allocated to the
royalty owner. In 2020, C3+ NGL prices averaged $21.68 per
Bbl and were uneconomic to process. This resulted in Antero
being allocated all gross NGL volumes relative to royalty owners.
The net impact in 2020 was an increase to production of 140 MMcfe/d
and a $0.04 per Mcfe decrease in realizations. Based on gross
wellhead volume, Antero's 2021 production guidance approximates
2020 production volumes.
|
(2)
|
Includes lease
operating expenses and gathering, compression, processing and
transportation expenses ("GP&T") and production and ad valorem
taxes. Assumes no LP gathering fee rebates are received during
2021.
|
(3)
|
Excludes equity-based
compensation.
|
Natural Gas and NGL Price Realizations
The
Company expects to realize a $0.10 to
$0.20 per MMBtu price premium
compared to the NYMEX Henry Hub price for its natural gas sales
during 2021, as Antero's firm transportation portfolio delivers
access to premium priced markets in the Gulf Coast and
Midwest. The winter weather event in February is expected to
result in first quarter 2020 realized natural gas prices at a
$0.30 to $0.40 premium to NYMEX. Antero is
forecasting an average realized price for C3+ NGLs in the range of
a $0.00 to a $0.05 per gallon premium relative to Mont Belvieu
pricing. Antero expects to sell at least 50% of its C3+ NGL
production in 2021 at Marcus Hook,
PA for export at a premium to Mont Belvieu
pricing.
Cash Production Expense and Net Marketing
Expense
Antero forecasts cash production expenses to be
in the range of $2.18 to $2.23 per Mcfe. The slight increase in
production expenses as compared to 2020 reflects the expectation
that Antero Resources will not receive any low pressure gathering
fee rebates from Antero Midstream in 2021 and reflects the expected
incremental 5,000 Bbl/d of NGL volume commitments on Mariner East
2, beginning April 1,
2021.
Antero forecasts net marketing expense to be in the range of
$0.08 to $0.10 per Mcfe. This guidance reflects the
impact from the winter weather in February and the current narrow
strip for local basis in 2021. However, if local basis
widens, as it did in 2020, net marketing expense is expected to be
near the low end of the guidance range as more long-haul
transportation is utilized.
Well Cost Savings
Antero's drilling and
completion capital budget is based on an average well cost of
$660 per lateral foot during 2021,
normalized for a 12,000 foot lateral. Well costs are expected
to average $675 per lateral foot
during the first half of 2021, before declining to $635 per lateral foot in the second half of 2021
driven by various sand and completion initiatives.
Antero plans to complete 65 to 70 gross wells in 2021. The
average lateral length on completed wells is expected to be 13,150
feet. Antero plans to drill 80 to 85 gross wells with an average
lateral length of 13,250 feet. Drilled wells include 70 in
the Marcellus and 10 to 15 in the Ohio Utica. The 2021 capital
budget assumes an average of 3 drilling rigs and 2 completion crews
on a gross basis for the drilling partnership.
Fourth Quarter 2020 Free Cash Flow
Antero generated
$155 million in Free Cash Flow before
changes in working capital during the fourth quarter. After
adjusting for working capital investments, Free Cash Flow was
$125 million.
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
|
December
31,
|
|
|
|
2019
|
|
2020
|
|
Net cash provided by
operating activities
|
|
$
|
147,940
|
|
|
243,130
|
|
Less: Capital
expenditures, including land (accrual basis)
|
|
|
(315,358)
|
|
|
(99,212)
|
|
Less: Distributions
to non-controlling interests in Martica
|
|
|
—
|
|
|
(18,671)
|
|
Free Cash
Flow
|
|
$
|
(167,418)
|
|
|
125,247
|
|
Changes in working
capital
|
|
|
91,780
|
|
|
30,156
|
|
Free Cash Flow
before Changes in Working Capital
|
|
$
|
(75,638)
|
|
|
155,403
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fourth Quarter 2020 Financial Results
For the three
months ended December 31, 2020,
Antero reported GAAP net income of $70
million, or $0.24 per diluted
share, compared to a GAAP net loss of $482
million, or $1.61 per diluted
share, in the prior year period. Adjusted Net Loss (non-GAAP
measure) for the three months ended December
31, 2020 was $11 million, or
$0.03 per diluted share, compared to
Adjusted Net Loss of $6 million
during the three months ended December 31,
2019, or $0.02 per diluted
share.
Adjusted EBITDAX (non-GAAP measure) for the three months ended
December 31, 2020 was $299 million, an increase of 1% versus the prior
year period as lower operating costs and increased production
offset a decrease in realized prices due to lower realized hedge
gains. The $299 million of
reported Adjusted EBITDAX includes a non-cash adjustment that
increased fuel expense by $19 million
or $0.07 per Mcfe during the fourth
quarter.
The following table details the components of average net
production and average realized prices for the three months ended
December 31, 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
Natural
Gas
|
|
Oil
|
|
C3+
NGLs
|
|
Ethane
|
|
Gas
Equivalent
|
|
|
|
(MMcf/d)
|
|
(Bbl/d)
|
|
(Bbl/d)
|
|
(Bbl/d)
|
|
(MMcfe/d)
|
|
Average Net
Production
|
|
|
2,457
|
|
|
12,000
|
|
|
132,326
|
|
|
54,598
|
|
|
3,650
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Combined
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
|
|
|
|
Natural
Gas
|
|
Oil
|
|
C3+
NGLs
|
|
Ethane
|
|
Gas
Equivalent
|
|
Average Realized
Prices
|
|
($/Mcf)
|
|
($/Bbl)
|
|
($/Bbl)
|
|
($/Bbl)
|
|
($/Mcfe)
|
|
Average realized
prices before settled derivatives
|
|
$
|
2.63
|
|
$
|
30.83
|
|
$
|
27.64
|
|
$
|
5.56
|
|
$
|
2.96
|
|
Settled commodity
derivatives
|
|
|
0.13
|
|
|
10.80
|
|
|
1.20
|
|
|
(0.12)
|
|
|
0.16
|
|
Average realized
prices after settled derivatives
|
|
$
|
2.76
|
|
$
|
41.63
|
|
$
|
28.84
|
|
$
|
5.44
|
|
$
|
3.12
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX average
price
|
|
$
|
2.66
|
|
$
|
42.45
|
|
|
|
|
|
|
|
$
|
2.66
|
|
Premium /
(Differential) to NYMEX
|
|
$
|
0.10
|
|
$
|
(0.82)
|
|
|
|
|
|
|
|
$
|
0.46
|
|
Net daily natural gas equivalent production in the fourth
quarter averaged 3,650 MMcfe/d, including 198,924 Bbl/d of liquids
(67% natural gas by volume). Net gas equivalent production
increased 15% from the prior year period. Throughput on
Antero Midstream's low pressure gathering system exceeded the
growth incentive fee threshold of 2,900 MMcf/d during the fourth
quarter of 2020, resulting in a $12
million rebate to Antero Resources.
Antero's average realized natural gas price before hedging was
$2.63 per Mcf, representing a 5%
increase versus the prior year period. Despite a sharp widening in
the regional basis differential during the quarter, Antero realized
a $0.03 per Mcf discount to the
average NYMEX Henry Hub price through the use of its premium firm
transportation to NYMEX-based markets. Including hedges,
Antero's average realized natural gas price was $2.76 per Mcf, a $0.10 premium to the average NYMEX
price.
Antero's average realized C3+ NGL price before hedging was
$27.64 per barrel, a 26% sequential
improvement and a 7% decrease versus the prior year period.
Antero shipped 43% of its total C3+ NGL net production on Mariner
East 2 for export and realized an $0.11 per gallon premium to Mont Belvieu pricing
on these volumes at Marcus Hook,
PA. Antero sold the remaining 57% of C3+ NGL net production
at a $0.06 per gallon discount to
Mont Belvieu pricing at Hopedale, OH. The resulting blended
price on 132,326 Bbl/d of net C3+ NGL production was $27.64 per barrel, which was a $0.02 per gallon premium to Mont Belvieu
pricing. Antero expects to sell at least 50% of its C3+ NGL
production in 2021 at Marcus Hook
for export at a premium to Mont
Belvieu.
|
|
|
|
|
|
|
|
|
|
|
|
Three months ended
December 31, 2020
|
|
|
|
Pricing
Point
|
|
Net C3+
NGL
Production
(Bbl/d)
|
|
% by
Destination
|
|
Premium
(Discount)
To Mont
Belvieu
($/Gal)
|
Propane / Butane
exported on ME2
|
Marcus Hook,
PA
|
|
57,225
|
|
43%
|
|
$0.11
|
Remaining C3+ NGL
volume
|
Hopedale,
OH
|
|
75,101
|
|
57%
|
|
($0.06)
|
Total C3+
NGLs/Blended Premium
|
|
|
|
132,326
|
|
100%
|
|
$0.02
|
All-in cash expense, which includes lease operating, gathering,
compression, processing and transportation, production and ad
valorem taxes was $2.14 per Mcfe in
the fourth quarter, a 3% increase compared to $2.08 per Mcfe average during the fourth quarter
of 2019. The increase from a year ago was due to an increase
in transportation expense as Antero utilized higher tariff
long-haul firm transportation to capture higher realized natural
gas prices. Lease operating expense was $0.08 per Mcfe in the fourth quarter, an 11%
decline from the year ago period driven by a decrease in water
handling costs as Antero increased water blending and reuse in
completion operations.
G&A expense was $0.08 per
Mcfe, a 20% decrease from the fourth quarter of 2019 primarily due
to a lower employee headcount and a 15% increase in
production.
Per unit net marketing expense declined to $0.08 per Mcfe in the fourth quarter, compared to
$0.17 per Mcfe reported in the prior
year period. The decline was driven primarily by higher
production volumes during the quarter and wide regional basis
differentials resulting in less unutilized transportation
capacity. This fourth quarter net marketing expense was the
lowest since Antero's full firm transportation portfolio was
completed in 2018. As basis differentials widened during the
fourth quarter of 2020, Antero's firm transportation portfolio
allowed for the flow of its production without any shut-ins or
curtailments and shielded it from the wide regional basis to NYMEX
prices.
Fourth Quarter 2020 Operating
Update
Marcellus Shale
— Antero placed 11 horizontal Marcellus wells to sales
during the fourth quarter with an average lateral length of 15,788
feet. Ten of the 11 new wells have been on-line for at least 60
days and the average 60-day rate per well was a company record 33.9
MMcfe/d, including approximately 1,822 Bbl/d of liquids assuming
25% ethane recovery. For the full year 2020, Antero averaged
over 6,400 feet per day when drilling the lateral section of its
wells. Additionally, Antero's ongoing emphasis on completion
efficiencies resulted in an improvement during 2020 to 8.0 stages
completed per day, up from 5.8 stages per day in 2019.
These efficiency gains led to average all-in well costs of
$690 per lateral foot during the
fourth quarter, normalized to a 12,000 foot lateral. This
represents a nearly 30% reduction in all-in well cost per lateral
foot since the beginning of 2019. The vast majority of the
improvement in well costs has been driven by operational efficiency
and process changes and are therefore expected to be
sustainable.
Fourth Quarter and 2020 Capital Investment
Antero's
drilling and completion capital expenditures for the three months
ended December 31, 2020, were
$84 million. For the full year
2020 drilling and completion capital expenditures were $735 million, 2% below full year guidance of
$750 million. In addition to
capital invested in drilling and completion costs, the Company
invested $13 million in land during
the fourth quarter and $48 million
for the full year. For a reconciliation of accrued capital
expenditures to cash capital expenditures see the table in the
Non-GAAP Financial Measures section.
Balance Sheet and Liquidity
As of December 31, 2020, Antero's total debt was
$3.0 billion, of which $1.0 billion were borrowings outstanding under
the Company's revolving credit facility. Antero has a
borrowing base of $2.85 billion with
lender commitments that total $2.64
billion. After deducting letters of credit outstanding
of $730 million, the Company had
approximately $900 million in
available liquidity at December 31,
2020. Net debt to trailing twelve month Adjusted EBITDA ratio
(non-GAAP) was 3.1x as of December 31,
2020.
Pro forma for the closing of Antero's 8.375% senior notes due in
2026 and 7.625% senior notes due in 2029, the convertible senior
note equitization transaction, the redemptions of the remaining
senior notes due 2022 and receipt of proceeds from the WGL
litigation judgement, all of which occurred subsequent to year end
2020, Antero had $471 outstanding
under its credit facility and $1.4
billion of liquidity.
The following table reconciles Antero's pro forma credit
facility outstanding with the credit facility amount outstanding as
of December, 31st 2020:
|
|
|
|
|
|
|
$(MM)
|
|
|
|
Bank credit
facility outstanding as of December 31, 2020
|
|
$
|
|
|
1,017
|
|
Net proceeds from
8.375% senior note offering used to repay credit
facility
|
|
|
|
|
(144)
|
|
Net proceeds from
7.625% senior note offering used to repay credit
facility
|
|
|
|
|
(381)
|
|
WGL litigation net
proceeds
|
|
|
|
|
(85)
|
|
Convertible senior
note equitization transaction
|
|
|
|
|
64
|
|
Pro forma bank
credit facility outstanding
|
|
$
|
|
|
471
|
|
|
|
|
|
|
|
|
|
Year End Proved Reserves
At December 31, 2020, Antero's estimated proved
reserves were 17.6 Tcfe, a 7% decrease versus the prior year.
Estimated proved reserves were comprised of 57% natural gas, 42%
NGLs and 1% oil.
Estimated proved developed reserves were 11.9 Tcfe, a 1%
increase over the prior year. The percentage of estimated
proved reserves classified as proved developed increased to 67% at
year-end 2020, compared to 62% at year-end 2019. Antero's
proved undeveloped locations have an average estimated BTU of 1264,
with an average lateral length of approximately 13,261 feet.
At year end 2020, Antero's five year development plan included 256
PUD locations compared to 328 at year end 2019. The year over
year decrease was driven by the shift to a maintenance capital
program, which had a net impact of reducing the year end 2020 five
year plan by 72 PUD locations.
Antero's 5.8 Tcfe of estimated proved undeveloped reserves will
require an estimated $1.5 billion of
future development capital over the next five years, resulting in
an estimated average future development cost for proved undeveloped
reserves of $0.27 per Mcfe.
The following table presents a summary of changes in estimated
proved reserves (in Tcfe).
Proved reserves,
December 31, 2019
|
|
18.9
|
Extensions,
discoveries, and other additions
|
|
1.1
|
Performance
revisions
|
|
0.5
|
Revisions to five-year
development plan
|
|
(0.8)
|
Price
revisions
|
|
(1.1)
|
Sales of reserves in
place
|
|
(0.1)
|
Revisions to ethane
recovery
|
|
0.5
|
Production
|
|
(1.3)
|
Proved reserves,
December 31, 2020 (1)
|
|
17.6
|
|
|
|
|
(1)
|
2020 proved reserves
are reported consolidated with Martica Holdings, LLC. Martica
Holdings, LLC had 254 Bcfe of proved reserves as of year end
2020.
|
Commodity Derivative Positions
As of December 31, 2020, the Company has hedged 1.3 Tcf
of natural gas at a weighted average index price of $2.67 per MMBtu through 2023 with fixed price
swap positions. Antero also has oil and ethane fixed price
swap positions, including oil positions that total 3,000 Bbl/d for
2021 and ethane positions that total 19,000 Bbl/d during the first
quarter of 2021.
Please see Antero's Annual Report on Form 10-K for the year
ended December 31, 2020, for more
information on all commodity derivative positions, including basis
swaps and natural gas calls.
The following tables summarize Antero's hedge position as of
December 31, 2020:
Fixed price natural gas positions from January 1, 2021 through December 31, 2023 were as follows:
|
|
|
|
|
|
|
|
|
Natural gas
MMBtu/day
|
|
Weighted
average index
price
|
|
Year ending
December 31, 2021:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
2,160,000
|
|
|
$2.77
|
|
Year ending
December 31, 2022:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
1,155,486
|
|
|
$2.50
|
|
Year ending
December 31, 2023:
|
|
|
|
|
|
|
NYMEX
($/MMBtu)
|
|
43,000
|
|
|
$2.37
|
|
Ethane and oil derivative contract positions from January 1, 2021 through December 31, 2021 were as follows:
|
|
|
|
|
|
|
|
Derivative
Contract
Type
|
Liquids Hedges
(Bbl/d)
|
|
Weighted
average
index price
($/Gal)
|
Weighted
average basis
differential
$/Gal
|
Weighted
average
index price
($/Bbl)
|
Quarter ending
March 31, 2021:
|
|
|
|
|
|
|
Total OPIS Ethane Mt
Belvieu
|
Fixed
swap
|
19,000
|
|
$0.20
|
|
|
|
|
|
|
|
|
|
Year ending
December 31, 2021:
|
|
|
|
|
|
|
Total NYMEX Crude
Oil
|
|
3,000
|
|
|
|
$55.16
|
|
|
|
|
|
2020 Asset Sales Program Accounting Treatment
For the
three months and twelve months ended December 31, 2020, Martica Holdings, LLC
("Martica"), the entity associated with the previously announced
ORRI transaction, is included in the Company's consolidated
financial statements and all significant intercompany accounts and
transactions have been eliminated. The noncontrolling
interest in the Company's consolidated financial statements for the
three and twelve months ended December 31,
2020 represents the interest in Martica, not owned by
Antero.
Under the VPP transaction entered into during the third quarter
of 2020, all production volumes and reserves are treated as a
divestiture and not included in the results. Net proceeds are
recorded as deferred revenue as of December
31, 2020. Revenue is recognized as volumes and are
delivered using the unit-of-production method over the term of the
VPP.
For more information, please see Antero's Annual Report on
Form 10-K for the year ended December 31,
2020.
Conference Call
A conference call is scheduled on
Thursday, February 18, 2021 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
877-407-9079 (U.S.), or 201-493-6746 (International) and reference
"Antero Resources". A telephone replay of the call will be
available until Thursday, February 25,
2021 at 9:00 am MT at
877-660-6853 (U.S.) or 201-612-7415 (International) using the
conference ID: 13714534.
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 25, 2021 at 9:00 am MT.
Presentation
An updated presentation will be posted to
the Company's website before the 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, and is not incorporated by reference into, this press
release.
Non-GAAP Financial Measures
Adjusted Net Loss
Adjusted Net Loss as set
forth in this release represents net income (loss), adjusted for
certain items. Antero believes that Adjusted Net Loss and
Adjusted Net Loss 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 Loss is not a measure of financial performance under GAAP and
should not be considered in isolation or as a substitute for net
income loss as an indicator of financial performance. The
following tables reconcile net income (loss) to Adjusted Net Loss
(in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
|
December
31,
|
|
December
31,
|
|
|
|
2019
|
|
2020
|
|
2019
|
|
2020
|
|
Net income (loss)
attributable to Antero Resources Corp
|
|
$
|
(482,196)
|
|
|
69,830
|
|
$
|
(340,129)
|
|
|
(1,267,897)
|
|
Unrealized commodity
derivative gains (losses)
|
|
|
71,171
|
|
|
(152,038)
|
|
|
(138,882)
|
|
|
723,773
|
|
Amortization of
deferred revenue, VPP
|
|
|
—
|
|
|
(9,332)
|
|
|
—
|
|
|
(14,507)
|
|
Impairment of oil and
gas properties
|
|
|
46,732
|
|
|
67,808
|
|
|
1,300,444
|
|
|
223,770
|
|
Impairment of
midstream assets
|
|
|
—
|
|
|
—
|
|
|
7,800
|
|
|
—
|
|
Impairment of equity
method investment
|
|
|
467,590
|
|
|
—
|
|
|
467,590
|
|
|
610,632
|
|
Equity-based
compensation
|
|
|
4,232
|
|
|
6,316
|
|
|
21,082
|
|
|
23,317
|
|
Income from water
earnout
|
|
|
(125,000)
|
|
|
—
|
|
|
(125,000)
|
|
|
—
|
|
Gain on
deconsolidation of Antero Midstream LP
|
|
|
—
|
|
|
—
|
|
|
(1,406,042)
|
|
|
—
|
|
Gain on early
extinguishment of debt
|
|
|
(36,419)
|
|
|
(597)
|
|
|
(36,419)
|
|
|
(175,962)
|
|
Loss on sale of
assets
|
|
|
—
|
|
|
348
|
|
|
951
|
|
|
348
|
|
Loss on the sale of
equity method investment shares
|
|
|
108,745
|
|
|
—
|
|
|
108,745
|
|
|
—
|
|
Equity in earnings
(loss) of unconsolidated affiliates
|
|
|
53,023
|
|
|
(20,748)
|
|
|
155,481
|
|
|
62,660
|
|
Contract termination
and rig stacking
|
|
|
—
|
|
|
1,973
|
|
|
14,026
|
|
|
14,290
|
|
Simplification
transaction fees
|
|
|
—
|
|
|
—
|
|
|
15,482
|
|
|
—
|
|
Tax effect of
reconciling items (1)
|
|
|
(138,097)
|
|
|
25,478
|
|
|
(90,163)
|
|
|
(352,031)
|
|
Other tax
items
|
|
|
24,041
|
|
|
—
|
|
|
17,528
|
|
|
—
|
|
Adjusted Net
Loss
|
|
$
|
(6,178)
|
|
|
(10,962)
|
|
$
|
(27,506)
|
|
|
(151,607)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fully Diluted Shares
Outstanding
|
|
|
300,142
|
|
|
304,172
|
|
|
306,400
|
|
|
272,433
|
|
(1)
|
Deferred taxes
were approximately 23% for 2019 and 24% for 2020.
|
Per Share Amounts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
|
December
31,
|
|
December
31,
|
|
|
|
2019
|
|
2020
|
|
2019
|
|
2020
|
|
Net income (loss)
attributable to Antero Resources Corp
|
|
$
|
(1.61)
|
|
|
0.24
|
|
$
|
(1.11)
|
|
|
(4.65)
|
|
Unrealized commodity
derivative gains (losses)
|
|
|
0.24
|
|
|
(0.51)
|
|
|
(0.45)
|
|
|
2.66
|
|
Amortization of
deferred revenue, VPP
|
|
|
—
|
|
|
(0.03)
|
|
|
—
|
|
|
(0.05)
|
|
Impairment of oil and
gas properties
|
|
|
0.16
|
|
|
0.22
|
|
|
4.24
|
|
|
0.82
|
|
Impairment of
midstream assets
|
|
|
—
|
|
|
—
|
|
|
0.03
|
|
|
—
|
|
Impairment of equity
method investment
|
|
|
1.56
|
|
|
—
|
|
|
1.53
|
|
|
2.24
|
|
Equity-based
compensation
|
|
|
0.01
|
|
|
0.02
|
|
|
0.07
|
|
|
0.09
|
|
Income from water
earnout
|
|
|
(0.42)
|
|
|
—
|
|
|
(0.41)
|
|
|
—
|
|
Gain on
deconsolidation of Antero Midstream LP
|
|
|
—
|
|
|
—
|
|
|
(4.59)
|
|
|
—
|
|
Gain on early
extinguishment of debt
|
|
|
(0.12)
|
|
|
—
|
|
|
(0.12)
|
|
|
(0.65)
|
|
Loss on the sale of
equity method investment shares
|
|
|
0.36
|
|
|
—
|
|
|
0.35
|
|
|
—
|
|
Equity in earnings
(loss) of unconsolidated affiliates
|
|
|
0.18
|
|
|
(0.07)
|
|
|
0.51
|
|
|
0.23
|
|
Contract termination
and rig stacking
|
|
|
—
|
|
|
0.01
|
|
|
0.05
|
|
|
0.05
|
|
Simplification
transaction fees
|
|
|
—
|
|
|
—
|
|
|
0.05
|
|
|
—
|
|
Tax effect of
reconciling items (1)
|
|
|
(0.46)
|
|
|
0.08
|
|
|
(0.30)
|
|
|
(1.30)
|
|
Other tax
items
|
|
|
0.08
|
|
|
—
|
|
|
0.06
|
|
|
—
|
|
Adjusted Net
Loss
|
|
$
|
(0.02)
|
|
|
(0.03)
|
|
$
|
(0.09)
|
|
|
(0.56)
|
|
(1)
|
Deferred taxes
were approximately 23% for 2019 and 24% for 2020.
|
Net Debt
Net Debt is calculated as total debt less
cash and cash equivalents. Management uses Net Debt to
evaluate the Company's financial position, including its ability to
service its debt obligations.
The following table reconciles consolidated total debt to Net
Debt as used in this release (in thousands):
|
|
|
|
|
|
|
|
|
|
December
31,
|
|
|
|
2019
|
|
2020
|
|
AR bank credit
facility
|
|
$
|
552,000
|
|
|
1,017,000
|
|
5.375% AR senior
notes due 2021
|
|
|
952,500
|
|
|
—
|
|
5.125% AR senior
notes due 2022
|
|
|
923,041
|
|
|
660,516
|
|
5.625% AR senior
notes due 2023
|
|
|
750,000
|
|
|
574,182
|
|
5.000% AR senior
notes due 2025
|
|
|
600,000
|
|
|
590,000
|
|
4.250% AR convertible
senior notes due 2026
|
|
|
—
|
|
|
287,500
|
|
Net unamortized
premium
|
|
|
791
|
|
|
(111,886)
|
|
Net unamortized debt
issuance costs
|
|
|
(19,464)
|
|
|
(15,719)
|
|
Consolidated total
debt
|
|
$
|
3,758,868
|
|
|
3,001,593
|
|
Less: AR cash and cash
equivalents
|
|
|
—
|
|
|
—
|
|
Net Debt
|
|
$
|
3,758,868
|
|
|
3,001,593
|
|
Free Cash Flow
Free Cash Flow is a measure of
financial performance not calculated under GAAP and should not be
considered in isolation or as a substitute for cash flow from
operating, investing, or financing activities, as an indicator of
cash flow, or as a measure of liquidity. The Company defines
Free Cash Flow as net cash provided by operating activities, less
drilling and completion capital and leasehold capital, less
distributions to non-controlling interests in Martica.
The Company has not provided projected net cash provided by
operating activities or a reconciliation of Free Cash Flow to
projected net cash provided by operating activities, the most
comparable financial measure calculated in accordance with
GAAP. The Company is unable to project net cash provided by
operating activities for any future period because this metric
includes the impact of changes in operating assets and liabilities
related to the timing of cash receipts and disbursements that may
not relate to the period in which the operating activities
occurred. The Company is unable to project these timing
differences with any reasonable degree of accuracy without
unreasonable efforts. 2021 Free Cash Flow estimate is based on
current strip pricing and assumes aggregate dividends from Antero
Midstream of $137 million in 2021,
based on Antero Midstream's publicly announced 2021 dividend
guidance and net proceeds of $85
million from the WGL litigation settlement. In
addition, Free Cash Flow through 2025 assumes annual maintenance
level capital spending of $635
million, annual dividends from Antero Midstream of
$125 million, based on Antero
Midstream's publicly announced 2021 dividend guidance, full
participation by QL in the drilling partnership and strip pricing
as of February 16, 2021.
Free Cash Flow is a useful indicator of the Company's ability to
internally fund its activities and to service or incur additional
debt. There are significant limitations to using Free Cash Flow as
a measure of performance, including the inability to analyze the
effect of certain recurring and non-recurring items that materially
affect the Company's net income, the lack of comparability of
results of operations of different companies and the different
methods of calculating Free Cash Flow reported by different
companies. Free Cash Flow does not represent funds available for
discretionary use because those funds may be required for debt
service, land acquisitions and lease renewals, other capital
expenditures, working capital, income taxes, exploration expenses,
and other commitments and obligations.
Adjusted EBITDAX
Adjusted EBITDAX is a non-GAAP
financial measure that we define as net income (loss), adjusted for
certain items detailed below.
Through March 12, 2019, the
financial results of Antero Midstream Partners were included in our
consolidated results. Effective March
13, 2019, we no longer consolidate Antero Midstream Partners
and account for our interest in Antero Midstream using the equity
method of accounting. Adjusted EBITDAX includes distributions
received with respect to limited partner interests in Antero
Midstream Partners common units through March 12, 2019.
Adjusted EBITDAX as used and defined by us, may not be
comparable to similarly titled measures employed by other companies
and is not a measure of performance calculated in accordance with
GAAP. Adjusted EBITDAX should not be considered in isolation
or as a substitute for operating income or loss, net income or
loss, cash flows provided by operating, investing, and financing
activities, or other income or cash flow statement data prepared in
accordance with GAAP. Adjusted EBITDAX provides no
information regarding our capital structure, borrowings, interest
costs, capital expenditures, working capital movement, or tax
position. Adjusted EBITDAX does not represent funds available
for discretionary use because those funds may be required for debt
service, capital expenditures, working capital, income taxes,
exploration expenses, and other commitments and obligations.
However, our management team believes Adjusted EBITDAX is useful to
an investor in evaluating our financial performance because this
measure:
- is widely used by investors in the oil and natural gas industry
to measure operating performance without regard to items excluded
from the calculation of such term, which may vary substantially
from company to company depending upon accounting methods and the
book value of assets, capital structure and the method by which
assets were acquired, among other factors;
- helps investors to more meaningfully evaluate and compare the
results of our operations from period to period by removing the
effect of our capital and legal structure from our operating
structure;
- is used by our management team for various purposes, including
as a measure of our operating performance, in presentations to our
Board of Directors, and as a basis for strategic planning and
forecasting: and
- is used by our Board of Directors as a performance measure in
determining executive compensation.
There are significant limitations to using Adjusted EBITDAX as a
measure of performance, including the inability to analyze the
effects of certain recurring and non-recurring items that
materially affect our net income or loss, the lack of comparability
of results of operations of different companies, and the different
methods of calculating Adjusted EBITDAX reported by different
companies.
The following table represents a reconciliation of our net
income (loss), including noncontrolling interest, to Adjusted
EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash
provided by operating activities per our consolidated statements of
cash flows, in each case, for the three months and years ended
December 31, 2019 and 2020.
Adjusted EBITDAX also excludes the noncontrolling interests in
Martica and these adjustments are disclosed in the table below as
Martica related adjustments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Year
Ended
|
|
|
|
December 31,
|
|
December 31,
|
|
(in
thousands)
|
|
2019
|
|
2020
|
|
2019
|
|
2020
|
|
Reconciliation of
net income (loss) to Adjusted EBITDAX:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) and
comprehensive income (loss) attributable to Antero
Resources Corporation
|
|
$
|
(482,196)
|
|
|
69,830
|
|
$
|
(340,129)
|
|
|
(1,267,897)
|
|
Net income and
comprehensive income attributable to noncontrolling
interests
|
|
|
—
|
|
|
25,483
|
|
|
46,993
|
|
|
7,486
|
|
Unrealized commodity
derivative gains (losses)
|
|
|
71,171
|
|
|
(150,925)
|
|
|
(138,882)
|
|
|
725,011
|
|
Proceeds from
derivative monetizations
|
|
|
—
|
|
|
9,066
|
|
|
—
|
|
|
(9,007)
|
|
Amortization of
deferred revenue, VPP
|
|
|
—
|
|
|
(9,332)
|
|
|
—
|
|
|
(14,507)
|
|
Loss on sale of
assets
|
|
|
—
|
|
|
348
|
|
|
951
|
|
|
348
|
|
Gain on
deconsolidation of Antero Midstream Partners LP
|
|
|
—
|
|
|
—
|
|
|
(1,406,042)
|
|
|
—
|
|
Interest expense,
net
|
|
|
54,243
|
|
|
46,916
|
|
|
228,111
|
|
|
199,872
|
|
Gain on early
extinguishment of debt
|
|
|
(36,419)
|
|
|
(597)
|
|
|
(36,419)
|
|
|
(175,962)
|
|
Provision for income
tax expense (benefit)
|
|
|
(107,442)
|
|
|
23,685
|
|
|
(74,110)
|
|
|
(397,482)
|
|
Depletion,
depreciation, amortization, and accretion
|
|
|
191,802
|
|
|
209,831
|
|
|
918,629
|
|
|
865,291
|
|
Impairment of oil and
gas properties
|
|
|
46,732
|
|
|
67,808
|
|
|
1,300,444
|
|
|
223,770
|
|
Impairment of
midstream assets
|
|
|
—
|
|
|
—
|
|
|
14,782
|
|
|
—
|
|
Impairment of equity
method investment
|
|
|
467,590
|
|
|
—
|
|
|
467,590
|
|
|
610,632
|
|
Exploration
expense
|
|
|
236
|
|
|
188
|
|
|
884
|
|
|
1,083
|
|
Equity-based
compensation expense
|
|
|
4,232
|
|
|
6,316
|
|
|
23,559
|
|
|
23,317
|
|
Equity in (earnings)
loss of unconsolidated affiliates
|
|
|
53,023
|
|
|
(20,748)
|
|
|
143,216
|
|
|
62,660
|
|
Distributions/dividends from unconsolidated
affiliates
|
|
|
48,715
|
|
|
42,755
|
|
|
157,956
|
|
|
171,022
|
|
Loss on the sale of
equity method investment shares
|
|
|
108,745
|
|
|
—
|
|
|
108,745
|
|
|
—
|
|
Contract termination
and rig stacking
|
|
|
—
|
|
|
1,973
|
|
|
14,026
|
|
|
14,290
|
|
Water
earnout
|
|
|
(125,000)
|
|
|
—
|
|
|
(125,000)
|
|
|
—
|
|
Simplification
transaction fees
|
|
|
—
|
|
|
—
|
|
|
15,482
|
|
|
—
|
|
Transaction
expense
|
|
|
—
|
|
|
582
|
|
|
—
|
|
|
7,244
|
|
|
|
|
295,432
|
|
|
323,179
|
|
|
1,320,786
|
|
|
1,047,171
|
|
Antero Midstream
Partners related adjustments (1)
|
|
|
—
|
|
|
—
|
|
|
(73,115)
|
|
|
—
|
|
Martica related
adjustments (2)
|
|
|
—
|
|
|
(23,983)
|
|
|
—
|
|
|
(45,155)
|
|
Adjusted
EBITDAX
|
|
$
|
295,432
|
|
|
299,196
|
|
$
|
1,247,671
|
|
|
1,002,016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reconciliation of
our Adjusted EBITDAX to net cash provided by
operating activities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDAX
|
|
$
|
295,432
|
|
|
299,196
|
|
$
|
1,247,671
|
|
|
1,002,016
|
|
Antero Midstream
Partners related adjustments (1)
|
|
|
—
|
|
|
—
|
|
|
73,115
|
|
|
—
|
|
Martica related
adjustments (2)
|
|
|
—
|
|
|
23,983
|
|
|
—
|
|
|
45,155
|
|
Interest expense,
net
|
|
|
(54,243)
|
|
|
(46,916)
|
|
|
(228,111)
|
|
|
(199,872)
|
|
Exploration
expense
|
|
|
(236)
|
|
|
(188)
|
|
|
(884)
|
|
|
(1,083)
|
|
Changes in current
assets and liabilities
|
|
|
(91,780)
|
|
|
(30,156)
|
|
|
35,542
|
|
|
(109,047)
|
|
Simplification
transaction fees
|
|
|
—
|
|
|
—
|
|
|
(15,482)
|
|
|
—
|
|
Transaction
expense
|
|
|
—
|
|
|
(582)
|
|
|
—
|
|
|
(7,244)
|
|
Proceeds from
derivative monetizations
|
|
|
—
|
|
|
(9,066)
|
|
|
—
|
|
|
9,007
|
|
Other items
|
|
|
(1,233)
|
|
|
6,859
|
|
|
(8,393)
|
|
|
(3,292)
|
|
Net cash provided by
operating activities
|
|
$
|
147,940
|
|
|
243,130
|
|
$
|
1,103,458
|
|
|
735,640
|
|
|
|
(1)
|
Amounts reflected
are net of any elimination adjustments for intercompany activity
and include activity related to Antero Midstream
Partners through March 12, 2019. Effective
March 13, 2019, Antero accounts for its unconsolidated investment
in Antero Midstream Corporation using the equity method of
accounting.
|
(2)
|
Adjustments
reflect noncontrolling interests in Martica not otherwise adjusted
in amounts above.
|
Drilling and Completion Capital Expenditures
For a
reconciliation between cash paid for drilling and completion
capital expenditures and drilling and completion accrued capital
expenditures during the period, please see the capital expenditures
section below (in thousands):
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
|
|
December
31,
|
|
|
|
2019
|
|
2020
|
|
Drilling and
completion costs (as reported; cash basis)
|
|
$
|
296,187
|
|
|
132,345
|
|
Change in accrued
capital costs
|
|
|
3,441
|
|
|
(47,931)
|
|
Adjusted drilling and
completion costs (accrual basis)
|
|
$
|
299,628
|
|
|
84,414
|
|
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 Resources is an independent natural gas and natural
gas liquids company engaged in the acquisition, development and
production of unconventional properties located in the Appalachian
Basin in West Virginia and
Ohio. In conjunction with its
affiliate, Antero Midstream (NYSE: AM), Antero is one of the most
integrated natural gas producers in the U.S. 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 not under Antero Resources'
control. All statements, except for statements of historical fact,
made in this release regarding activities, events or developments
Antero Resources expects, believes or anticipates will or may occur
in the future, such as those regarding expected results, future
commodity prices, future production targets, realizing potential
future fee rebates or reductions, including those related to
certain levels of production, future earnings, leverage targets and
debt repayment, future capital spending plans, improved and/or
increasing capital efficiency, estimated realized natural gas, NGL
and oil prices, expected drilling and development plans, projected
well costs and cost savings initiatives, future financial position,
the participation level of our drilling partner and the financial
and production results to be achieved as a result of that drilling
partnership, the other key assumptions underlying our projections,
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 Resources believes that the plans,
intentions and expectations reflected in or suggested by the
forward-looking statements are reasonable, there is no assurance
that these plans, intentions or expectations will be achieved.
Therefore, actual outcomes and results could materially differ from
what is expressed, implied or forecast in such statements. Except
as required by law, Antero Resources expressly disclaims any
obligation to and does not intend to publicly update or revise any
forward-looking statements.
Antero Resources cautions you that these forward-looking
statements are subject to all of the risks and uncertainties,
incident to the exploration for and development, production,
gathering and sale of natural gas, NGLs and oil most of which are
difficult to predict and many of which are beyond the Antero
Resources' control. These risks include, but are not limited to,
commodity price volatility, inflation, lack of availability of
drilling and production equipment and services, environmental
risks, drilling and other operating risks, regulatory changes, the
uncertainty inherent in estimating natural gas and oil reserves and
in projecting future rates of production, cash flow and access to
capital, the timing of development expenditures, impacts of world
health event, including the COVID-19 pandemic and the other risks
described under the heading "Item 1A. Risk Factors" in Antero
Resources' Annual Report on Form 10-K for the year ended
December 31, 2020.
|
|
|
|
|
|
|
|
ANTERO RESOURCES
CORPORATION
Consolidated Balance
Sheets
(In thousands,
except per share amounts)
|
|
|
|
December
31,
|
|
|
|
2019
|
|
2020
|
|
Assets
|
|
Current
assets:
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
$
|
46,419
|
|
|
28,457
|
|
Accounts receivable,
related parties
|
|
|
125,000
|
|
|
—
|
|
Accrued
revenue
|
|
|
317,886
|
|
|
425,314
|
|
Derivative
instruments
|
|
|
422,849
|
|
|
105,130
|
|
Other current
assets
|
|
|
10,731
|
|
|
15,238
|
|
Total current
assets
|
|
|
922,885
|
|
|
574,139
|
|
Property and
equipment:
|
|
|
|
|
|
|
|
Oil and gas
properties, at cost (successful efforts method):
|
|
|
|
|
|
|
|
Unproved
properties
|
|
|
1,368,854
|
|
|
1,175,178
|
|
Proved
properties
|
|
|
11,859,817
|
|
|
12,260,713
|
|
Gathering systems and
facilities
|
|
|
5,802
|
|
|
5,802
|
|
Other property and
equipment
|
|
|
71,895
|
|
|
74,361
|
|
|
|
|
13,306,368
|
|
|
13,516,054
|
|
Less accumulated
depletion, depreciation, and amortization
|
|
|
(3,327,629)
|
|
|
(3,869,116)
|
|
Property and
equipment, net
|
|
|
9,978,739
|
|
|
9,646,938
|
|
Operating leases
right-of-use assets
|
|
|
2,886,500
|
|
|
2,613,603
|
|
Derivative
instruments
|
|
|
333,174
|
|
|
47,293
|
|
Investment in
unconsolidated affiliate
|
|
|
1,055,177
|
|
|
255,082
|
|
Other
assets
|
|
|
21,094
|
|
|
13,790
|
|
Total
assets
|
|
$
|
15,197,569
|
|
|
13,150,845
|
|
|
|
|
|
|
|
|
|
Liabilities and
Equity
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$
|
14,498
|
|
|
26,728
|
|
Accounts payable,
related parties
|
|
|
97,883
|
|
|
69,860
|
|
Accrued
liabilities
|
|
|
400,850
|
|
|
343,524
|
|
Revenue distributions
payable
|
|
|
207,988
|
|
|
198,117
|
|
Derivative
instruments
|
|
|
6,721
|
|
|
31,242
|
|
Short-term lease
liabilities
|
|
|
305,320
|
|
|
266,023
|
|
Deferred revenue,
VPP
|
|
|
—
|
|
|
45,257
|
|
Other current
liabilities
|
|
|
6,879
|
|
|
2,303
|
|
Total current
liabilities
|
|
|
1,040,139
|
|
|
983,054
|
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
Long-term
debt
|
|
|
3,758,868
|
|
|
3,001,593
|
|
Deferred income tax
liability
|
|
|
781,987
|
|
|
412,252
|
|
Derivative
instruments
|
|
|
3,519
|
|
|
99,172
|
|
Long-term lease
liabilities
|
|
|
2,583,678
|
|
|
2,348,785
|
|
Deferred revenue,
VPP
|
|
|
—
|
|
|
156,024
|
|
Other
liabilities
|
|
|
58,635
|
|
|
59,694
|
|
Total
liabilities
|
|
|
8,226,826
|
|
|
7,060,574
|
|
Commitments and
contingencies (Notes 15 and 16)
|
|
|
|
|
|
|
|
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; 295,941 shares and
268,672 shares issued and outstanding
at December 31, 2019 and 2020, respectively
|
|
|
2,959
|
|
|
2,686
|
|
Additional paid-in
capital
|
|
|
6,130,365
|
|
|
6,195,497
|
|
Accumulated earnings
(deficit)
|
|
|
837,419
|
|
|
(430,478)
|
|
Total stockholders'
equity
|
|
|
6,970,743
|
|
|
5,767,705
|
|
Noncontrolling
interests
|
|
|
—
|
|
|
322,566
|
|
Total
equity
|
|
|
6,970,743
|
|
|
6,090,271
|
|
Total liabilities and
equity
|
|
$
|
15,197,569
|
|
|
13,150,845
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
ANTERO RESOURCES
CORPORATION
Consolidated
Statements of Operations and Comprehensive Income (Loss)
(In thousands,
except per share amounts)
|
|
|
|
Three Months Ended
December 31,
|
|
Year Ended
December 31,
|
|
|
|
2019
|
|
2020
|
|
2019
|
|
2020
|
|
Revenue and
other:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
512,076
|
|
|
595,151
|
|
$
|
2,247,162
|
|
|
1,809,952
|
|
Natural gas liquids
sales
|
|
|
316,556
|
|
|
364,387
|
|
|
1,219,162
|
|
|
1,161,683
|
|
Oil sales
|
|
|
39,874
|
|
|
34,037
|
|
|
177,549
|
|
|
112,270
|
|
Commodity derivative
fair value gains (losses)
|
|
|
(7,875)
|
|
|
196,851
|
|
|
463,972
|
|
|
79,918
|
|
Gathering,
compression, water handling and treatment
|
|
|
—
|
|
|
—
|
|
|
4,478
|
|
|
—
|
|
Marketing
|
|
|
91,296
|
|
|
108,717
|
|
|
292,207
|
|
|
310,572
|
|
Amortization of
deferred revenue, VPP
|
|
|
—
|
|
|
9,332
|
|
|
—
|
|
|
14,507
|
|
Other
income
|
|
|
811
|
|
|
648
|
|
|
4,160
|
|
|
2,797
|
|
Total
revenue
|
|
|
952,738
|
|
|
1,309,123
|
|
|
4,408,690
|
|
|
3,491,699
|
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
27,203
|
|
|
27,029
|
|
|
145,720
|
|
|
98,865
|
|
Gathering,
compression, processing, and transportation
|
|
|
551,424
|
|
|
653,754
|
|
|
2,146,647
|
|
|
2,530,838
|
|
Production and ad
valorem taxes
|
|
|
29,633
|
|
|
35,294
|
|
|
125,142
|
|
|
106,775
|
|
Marketing
|
|
|
140,975
|
|
|
134,498
|
|
|
549,814
|
|
|
469,404
|
|
Exploration
|
|
|
236
|
|
|
188
|
|
|
884
|
|
|
1,083
|
|
Impairment of oil and
gas properties
|
|
|
46,732
|
|
|
67,808
|
|
|
1,300,444
|
|
|
223,770
|
|
Impairment of
midstream assets
|
|
|
—
|
|
|
—
|
|
|
14,782
|
|
|
—
|
|
Depletion,
depreciation, and amortization
|
|
|
190,861
|
|
|
209,740
|
|
|
914,867
|
|
|
861,870
|
|
Accretion of asset
retirement obligations
|
|
|
941
|
|
|
91
|
|
|
3,762
|
|
|
3,421
|
|
General and
administrative (including equity-based compensation
expense)
|
|
|
32,189
|
|
|
33,218
|
|
|
178,696
|
|
|
134,482
|
|
Contract termination
and rig stacking
|
|
|
—
|
|
|
1,973
|
|
|
14,026
|
|
|
14,290
|
|
Loss on sale of
assets
|
|
|
—
|
|
|
348
|
|
|
951
|
|
|
348
|
|
Total operating
expenses
|
|
|
1,020,194
|
|
|
1,163,941
|
|
|
5,395,735
|
|
|
4,445,146
|
|
Operating income
(loss)
|
|
|
(67,456)
|
|
|
145,182
|
|
|
(987,045)
|
|
|
(953,447)
|
|
Other income
(expense):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense,
net
|
|
|
(54,243)
|
|
|
(46,916)
|
|
|
(228,111)
|
|
|
(199,872)
|
|
Equity in earnings
(loss) of unconsolidated affiliates
|
|
|
(53,023)
|
|
|
20,748
|
|
|
(143,216)
|
|
|
(62,660)
|
|
Gain on early
extinguishment of debt
|
|
|
36,419
|
|
|
597
|
|
|
36,419
|
|
|
175,962
|
|
Gain on
deconsolidation of Antero Midstream Partners LP
|
|
|
—
|
|
|
—
|
|
|
1,406,042
|
|
|
—
|
|
Water
earnout
|
|
|
125,000
|
|
|
—
|
|
|
125,000
|
|
|
—
|
|
Loss on the sale of
equity method investment shares
|
|
|
(108,745)
|
|
|
—
|
|
|
(108,745)
|
|
|
—
|
|
Impairment of equity
method investment
|
|
|
(467,590)
|
|
|
—
|
|
|
(467,590)
|
|
|
(610,632)
|
|
Transaction
expense
|
|
|
—
|
|
|
(582)
|
|
|
—
|
|
|
(7,244)
|
|
Total other income
(expenses)
|
|
|
(522,182)
|
|
|
(26,153)
|
|
|
619,799
|
|
|
(704,446)
|
|
Loss before income
taxes
|
|
|
(589,638)
|
|
|
119,029
|
|
|
(367,246)
|
|
|
(1,657,893)
|
|
Provision for income
tax benefit (expense)
|
|
|
107,442
|
|
|
(23,685)
|
|
|
74,110
|
|
|
397,482
|
|
Net income (loss) and
comprehensive income (loss) including
noncontrolling interests
|
|
|
(482,196)
|
|
|
95,344
|
|
|
(293,136)
|
|
|
(1,260,411)
|
|
Less: net income
(loss) and comprehensive income (loss) attributable to
noncontrolling interests
|
|
|
—
|
|
|
25,483
|
|
|
46,993
|
|
|
7,486
|
|
Net income (loss) and
comprehensive income (loss) attributable to
Antero Resources Corporation
|
|
$
|
(482,196)
|
|
|
69,861
|
|
$
|
(340,129)
|
|
|
(1,267,897)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (loss) per
share—basic
|
|
$
|
(1.61)
|
|
|
0.26
|
|
$
|
(1.11)
|
|
|
(4.65)
|
|
Income (loss) per
share—diluted
|
|
$
|
(1.61)
|
|
|
0.21
|
|
$
|
(1.11)
|
|
|
(4.65)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average
number of shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
300,142
|
|
|
268,653
|
|
|
306,400
|
|
|
272,433
|
|
Diluted
|
|
|
300,142
|
|
|
338,967
|
|
|
306,400
|
|
|
272,433
|
|
|
|
|
|
|
|
|
|
|
|
|
ANTERO RESOURCES
CORPORATION
Consolidated
Statements of Cash Flows
(In
thousands)
|
|
|
|
Year Ended
December 31,
|
|
|
|
2018
|
|
2019
|
|
2020
|
|
Cash flows provided
by (used in) operating activities:
|
|
|
|
|
|
|
|
|
|
|
Net loss including
noncontrolling interests
|
|
$
|
(45,701)
|
|
|
(293,136)
|
|
|
(1,260,411)
|
|
Adjustments to
reconcile net loss to net cash provided by operating
activities:
|
|
|
|
|
|
|
|
|
|
|
Depletion,
depreciation, amortization, and accretion
|
|
|
975,284
|
|
|
918,629
|
|
|
865,291
|
|
Impairments
|
|
|
559,095
|
|
|
1,782,816
|
|
|
834,402
|
|
Commodity derivative
fair value losses (gains)
|
|
|
87,594
|
|
|
(463,972)
|
|
|
(79,918)
|
|
Gains on settled
commodity derivatives
|
|
|
243,112
|
|
|
325,090
|
|
|
794,684
|
|
Premium paid on
derivative contract
|
|
|
(13,318)
|
|
|
—
|
|
|
—
|
|
Proceeds from
derivative monetizations
|
|
|
370,365
|
|
|
—
|
|
|
9,007
|
|
Gains on settled
marketing derivatives
|
|
|
72,687
|
|
|
—
|
|
|
—
|
|
Marketing derivative
fair value gains
|
|
|
(94,081)
|
|
|
—
|
|
|
—
|
|
Loss on sale of
assets
|
|
|
—
|
|
|
951
|
|
|
348
|
|
Equity-based
compensation expense
|
|
|
70,414
|
|
|
23,559
|
|
|
23,317
|
|
Deferred income tax
benefit
|
|
|
(128,857)
|
|
|
(79,158)
|
|
|
(397,482)
|
|
Gain on early
extinguishment of debt
|
|
|
—
|
|
|
(36,419)
|
|
|
(175,962)
|
|
Loss on the sale of
equity method investment shares
|
|
|
—
|
|
|
108,745
|
|
|
—
|
|
Equity in (earnings)
loss of unconsolidated affiliates
|
|
|
(40,280)
|
|
|
143,216
|
|
|
62,660
|
|
Water
earnout
|
|
|
—
|
|
|
(125,000)
|
|
|
—
|
|
Gain on
deconsolidation of Antero Midstream Partners LP
|
|
|
—
|
|
|
(1,406,042)
|
|
|
—
|
|
Distributions/dividends of earnings from
unconsolidated affiliates
|
|
|
46,415
|
|
|
157,956
|
|
|
171,022
|
|
Amortization of
deferred revenue
|
|
|
—
|
|
|
—
|
|
|
(14,507)
|
|
Amortization of debt
issuance costs, debt discount, debt premium and other
|
|
|
4,681
|
|
|
10,681
|
|
|
12,236
|
|
Changes in current
assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(15,156)
|
|
|
31,631
|
|
|
(9,492)
|
|
Accrued
revenue
|
|
|
(174,706)
|
|
|
156,941
|
|
|
(107,428)
|
|
Other current
assets
|
|
|
(5,817)
|
|
|
(1,025)
|
|
|
(5,507)
|
|
Accounts payable
including related parties
|
|
|
9,307
|
|
|
(27,996)
|
|
|
(19,282)
|
|
Accrued
liabilities
|
|
|
63,562
|
|
|
(25,762)
|
|
|
37,954
|
|
Revenue distributions
payable
|
|
|
101,210
|
|
|
(102,839)
|
|
|
(5,203)
|
|
Other current
liabilities
|
|
|
(3,823)
|
|
|
4,592
|
|
|
(89)
|
|
Net cash provided by
operating activities
|
|
|
2,081,987
|
|
|
1,103,458
|
|
|
735,640
|
|
Cash flows provided
by (used in) investing activities:
|
|
|
|
|
|
|
|
|
|
|
Additions to unproved
properties
|
|
|
(172,387)
|
|
|
(88,682)
|
|
|
(45,129)
|
|
Drilling and
completion costs
|
|
|
(1,488,573)
|
|
|
(1,254,118)
|
|
|
(826,265)
|
|
Additions to water
handling and treatment systems
|
|
|
(97,699)
|
|
|
(24,416)
|
|
|
—
|
|
Additions to gathering
systems and facilities
|
|
|
(444,413)
|
|
|
(48,239)
|
|
|
—
|
|
Additions to other
property and equipment
|
|
|
(7,514)
|
|
|
(6,700)
|
|
|
(2,963)
|
|
Settlement of water
earnout
|
|
|
—
|
|
|
—
|
|
|
125,000
|
|
Investments in
unconsolidated affiliates
|
|
|
(136,475)
|
|
|
(25,020)
|
|
|
—
|
|
Proceeds from sale of
common stock of Antero Midstream Corporation
|
|
|
—
|
|
|
100,000
|
|
|
—
|
|
Proceeds from the
Antero Midstream Partners LP Transactions
|
|
|
—
|
|
|
296,611
|
|
|
—
|
|
Proceeds from asset
sales
|
|
|
—
|
|
|
1,983
|
|
|
701
|
|
Proceeds from VPP
sale, net
|
|
|
—
|
|
|
—
|
|
|
215,789
|
|
Change in other
assets
|
|
|
(3,663)
|
|
|
7,091
|
|
|
2,806
|
|
Net cash used in
investing activities
|
|
|
(2,350,724)
|
|
|
(1,041,490)
|
|
|
(530,061)
|
|
Cash flows provided
by (used in) financing activities:
|
|
|
|
|
|
|
|
|
|
|
Repurchases of common
stock
|
|
|
(129,084)
|
|
|
(38,772)
|
|
|
(43,443)
|
|
Issuance of senior
notes by Antero Midstream Partners LP
|
|
|
—
|
|
|
650,000
|
|
|
—
|
|
Issuance of
convertible notes
|
|
|
—
|
|
|
—
|
|
|
287,500
|
|
Repayment of senior
notes
|
|
|
—
|
|
|
(191,092)
|
|
|
(1,219,019)
|
|
Borrowings
(repayments) on bank credit facilities, net
|
|
|
660,379
|
|
|
232,000
|
|
|
465,000
|
|
Payments of deferred
financing costs
|
|
|
(2,169)
|
|
|
(4,547)
|
|
|
(8,984)
|
|
Sale of noncontrolling
interest
|
|
|
—
|
|
|
—
|
|
|
351,000
|
|
Distributions to
noncontrolling interests in Antero Midstream Partners LP
|
|
|
(267,271)
|
|
|
(85,076)
|
|
|
—
|
|
Distributions to
noncontrolling interests in Martica Holdings LLC
|
|
|
—
|
|
|
—
|
|
|
(35,920)
|
|
Employee tax
withholding for settlement of equity compensation awards
|
|
|
(17,020)
|
|
|
(2,389)
|
|
|
(422)
|
|
Other
|
|
|
(4,539)
|
|
|
(2,560)
|
|
|
(1,291)
|
|
Net cash provided by
(used in) financing activities
|
|
|
240,296
|
|
|
557,564
|
|
|
(205,579)
|
|
Effect of
deconsolidation of Antero Midstream Partners LP
|
|
|
—
|
|
|
(619,532)
|
|
|
—
|
|
Net decrease in cash
and cash equivalents
|
|
|
(28,441)
|
|
|
—
|
|
|
—
|
|
Cash and cash
equivalents, beginning of period
|
|
|
28,441
|
|
|
—
|
|
|
—
|
|
Cash and cash
equivalents, end of period
|
|
$
|
—
|
|
|
—
|
|
|
—
|
|
The following table set forth selected operating data for the
three months ended December 31, 2019
and 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Amount of
|
|
|
|
|
|
December 31,
|
|
Increase
|
|
Percent
|
|
(in thousands)
|
|
2019
|
|
2020
|
|
(Decrease)
|
|
Change
|
|
Revenue:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
sales
|
|
$
|
512,076
|
|
|
595,151
|
|
$
|
83,075
|
|
16
|
%
|
Natural gas liquids
sales
|
|
|
316,556
|
|
|
364,387
|
|
|
47,831
|
|
15
|
%
|
Oil sales
|
|
|
39,874
|
|
|
34,037
|
|
|
(5,837)
|
|
(15)
|
%
|
Commodity derivative
fair value gains (losses)
|
|
|
(7,875)
|
|
|
196,851
|
|
|
204,726
|
|
(2,600)
|
%
|
Marketing
|
|
|
91,296
|
|
|
108,717
|
|
|
17,421
|
|
19
|
%
|
Amortization of
deferred revenue, VPP
|
|
|
—
|
|
|
9,332
|
|
|
9,332
|
|
*
|
|
Other
income
|
|
|
810
|
|
|
617
|
|
|
(193)
|
|
(24)
|
%
|
Total
revenue
|
|
|
952,737
|
|
|
1,309,092
|
|
|
356,355
|
|
37
|
%
|
Operating
expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
|
27,203
|
|
|
27,029
|
|
|
(174)
|
|
(1)
|
%
|
Gathering and
compression
|
|
|
193,078
|
|
|
217,973
|
|
|
24,895
|
|
13
|
%
|
Processing
|
|
|
180,886
|
|
|
211,322
|
|
|
30,436
|
|
17
|
%
|
Transportation
|
|
|
177,460
|
|
|
224,459
|
|
|
46,999
|
|
26
|
%
|
Production and ad
valorem taxes
|
|
|
29,633
|
|
|
35,294
|
|
|
5,661
|
|
19
|
%
|
Marketing
|
|
|
140,975
|
|
|
134,498
|
|
|
(6,477)
|
|
(5)
|
%
|
Exploration
|
|
|
236
|
|
|
188
|
|
|
(48)
|
|
(20)
|
%
|
Impairment of oil and
gas properties
|
|
|
46,732
|
|
|
67,808
|
|
|
21,076
|
|
45
|
%
|
Depletion,
depreciation, and amortization
|
|
|
190,861
|
|
|
209,740
|
|
|
18,879
|
|
10
|
%
|
Accretion of asset
retirement obligations
|
|
|
941
|
|
|
91
|
|
|
(850)
|
|
(90)
|
%
|
General and
administrative (excluding equity-based compensation)
|
|
|
27,957
|
|
|
26,902
|
|
|
(1,055)
|
|
(4)
|
%
|
Equity-based
compensation
|
|
|
4,232
|
|
|
6,316
|
|
|
2,084
|
|
49
|
%
|
Contract termination
and rig stacking
|
|
|
—
|
|
|
1,973
|
|
|
1,973
|
|
*
|
|
Loss on sale of
assets
|
|
|
—
|
|
|
348
|
|
|
348
|
|
*
|
|
Total operating
expenses
|
|
|
1,020,194
|
|
|
1,163,941
|
|
|
143,747
|
|
14
|
%
|
Operating income
(loss)
|
|
|
(67,457)
|
|
|
145,151
|
|
|
212,608
|
|
(315)
|
%
|
Other earnings
(expenses):
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest expense,
net
|
|
|
(54,243)
|
|
|
(46,916)
|
|
|
7,327
|
|
(14)
|
%
|
Equity in earnings
(loss) of unconsolidated affiliates
|
|
|
(53,023)
|
|
|
20,748
|
|
|
73,771
|
|
(139)
|
%
|
Gain on early
extinguishment of debt
|
|
|
36,419
|
|
|
597
|
|
|
(35,822)
|
|
(98)
|
%
|
Water
earnout
|
|
|
125,000
|
|
|
—
|
|
|
(125,000)
|
|
*
|
|
Loss on the sale of
equity method investment shares
|
|
|
(108,745)
|
|
|
—
|
|
|
108,745
|
|
*
|
|
Impairment of equity
method investments
|
|
|
(467,590)
|
|
|
—
|
|
|
467,590
|
|
*
|
|
Transaction
expense
|
|
|
—
|
|
|
(582)
|
|
|
(582)
|
|
*
|
|
Total other
expense
|
|
|
(522,182)
|
|
|
(26,153)
|
|
|
496,029
|
|
(95)
|
%
|
Income (loss) before
income taxes
|
|
|
(589,639)
|
|
|
118,998
|
|
|
708,637
|
|
(120)
|
%
|
Provision for income
tax (expense) benefit
|
|
|
107,442
|
|
|
(23,685)
|
|
|
(131,127)
|
|
(122)
|
%
|
Net income (loss) and
comprehensive income (loss) including noncontrolling
interests
|
|
|
(482,197)
|
|
|
95,313
|
|
|
577,510
|
|
(120)
|
%
|
Less: net income and
comprehensive income attributable to noncontrolling
interests
|
|
|
—
|
|
|
25,483
|
|
|
25,483
|
|
*
|
|
Net income (loss) and
comprehensive income (loss) attributable to Antero
Resources Corporation
|
|
|
(482,197)
|
|
|
69,830
|
|
|
552,027
|
|
(114)
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Adjusted
EBITDAX
|
|
$
|
295,432
|
|
|
299,196
|
|
$
|
3,764
|
|
1
|
%
|
|
* Not
meaningful
|
The following table set forth selected operating data for the
three months ended December 31, 2019
and 2020:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
Ended
|
|
Amount of
|
|
|
|
|
|
December 31,
|
|
Increase
|
|
Percent
|
|
|
|
2019
|
|
2020
|
|
(Decrease)
|
|
Change
|
|
Production data
(1):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas
(Bcf)
|
|
|
205
|
|
|
226
|
|
|
21
|
|
10
|
%
|
C2 Ethane
(MBbl)
|
|
|
4,325
|
|
|
5,023
|
|
|
698
|
|
16
|
%
|
C3+ NGLs
(MBbl)
|
|
|
9,603
|
|
|
12,174
|
|
|
2,571
|
|
27
|
%
|
Oil (MBbl)
|
|
|
809
|
|
|
1,104
|
|
|
295
|
|
36
|
%
|
Combined
(Bcfe)
|
|
|
293
|
|
|
336
|
|
|
43
|
|
15
|
%
|
Daily combined
production (MMcfe/d)
|
|
|
3,185
|
|
|
3,650
|
|
|
465
|
|
15
|
%
|
Average prices
before effects of derivative settlements
(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
$
|
2.50
|
|
|
2.63
|
|
|
0.13
|
|
5
|
%
|
C2 Ethane (per
Bbl)
|
|
$
|
7.44
|
|
|
5.56
|
|
|
(1.88)
|
|
(25)
|
%
|
C3+ NGLs (per
Bbl)
|
|
$
|
29.61
|
|
|
27.64
|
|
|
(1.97)
|
|
(7)
|
%
|
Oil (per
Bbl)
|
|
$
|
49.29
|
|
|
30.83
|
|
|
(18.46)
|
|
(37)
|
%
|
Weighted Average
Combined (per Mcfe)
|
|
$
|
2.96
|
|
|
2.96
|
|
|
—
|
|
—
|
%
|
Average realized
prices after effects of derivative settlements
(2):
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per
Mcf)
|
|
$
|
2.87
|
|
|
2.76
|
|
|
(0.11)
|
|
(4)
|
%
|
C2 Ethane (per
Bbl)
|
|
$
|
7.44
|
|
|
5.44
|
|
|
(2.00)
|
|
(27)
|
%
|
C3+ NGLs (per
Bbl)
|
|
$
|
27.95
|
|
|
28.84
|
|
|
0.89
|
|
3
|
%
|
Oil (per
Bbl)
|
|
$
|
53.57
|
|
|
41.63
|
|
|
(11.94)
|
|
(22)
|
%
|
Weighted Average
Combined (per Mcfe)
|
|
$
|
3.18
|
|
|
3.12
|
|
|
(0.06)
|
|
(2)
|
%
|
Average costs (per
Mcfe):
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating
|
|
$
|
0.09
|
|
|
0.08
|
|
|
(0.01)
|
|
(11)
|
%
|
Gathering and
compression
|
|
$
|
0.66
|
|
|
0.65
|
|
|
(0.01)
|
|
(2)
|
%
|
Processing
|
|
$
|
0.62
|
|
|
0.63
|
|
|
0.01
|
|
2
|
%
|
Transportation
|
|
$
|
0.61
|
|
|
0.67
|
|
|
0.06
|
|
10
|
%
|
Production
taxes
|
|
$
|
0.10
|
|
|
0.11
|
|
|
0.01
|
|
10
|
%
|
Marketing,
net
|
|
$
|
0.17
|
|
|
0.08
|
|
|
(0.09)
|
|
(53)
|
%
|
Depletion,
depreciation, amortization and accretion
|
|
$
|
0.65
|
|
|
0.62
|
|
|
(0.03)
|
|
(5)
|
%
|
General and
administrative (excluding equity-based compensation)
|
|
$
|
0.10
|
|
|
0.08
|
|
|
(0.02)
|
|
(20)
|
%
|
|
|
(1)
|
Production volumes
exclude volumes related to VPP transaction.
|
(2)
|
Average sales
prices shown in the table reflect both the before and after effects
of our settled commodity derivatives. Our calculation of such
after effects includes gains on settlements of commodity
derivatives, which do not qualify for hedge accounting because we
do not designate or document them as hedges for accounting
purposes. Oil and NGLs production was converted at 6 Mcf per
Bbl to calculate total Bcfe production and per Mcfe amounts.
This ratio is an estimate of the equivalent energy content of the
products and does not necessarily reflect their relative economic
value.
|
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SOURCE Antero Resources Corporation