Antero Resources Reports Second Quarter 2018 Financial and Operational Results
DENVER, Aug. 1, 2018 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its second quarter 2018 financial and operational results. The relevant consolidated and consolidating financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended June 30, 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-Q within the Parent column of the guarantor footnote (Note 16).
Second Quarter 2018 Highlights:
-- Net daily gas equivalent production averaged a record 2,520 MMcfe/d (27%
liquids), a 15% increase over the prior year period and a 6% increase
sequentially
-- Liquids production averaged 113,581 Bbl/d, an 11% increase over the
prior year period and a 10% increase sequentially, and contributed 38%
of total product revenue before hedging
-- Realized natural gas price averaged $2.83 per Mcf, a $0.03 premium to
the NYMEX Henry Hub natural gas price before hedging
-- Realized natural gas equivalent price averaged $3.35 per Mcfe before
hedges, driven by a $0.52 per Mcfe uplift from liquids production
-- Realized natural gas equivalent price averaged $3.77 per Mcfe after
hedges
-- GAAP net loss was reported at $136 million, or $(0.43) per diluted
share, non-GAAP adjusted net income at $6 million, or $0.02 per diluted
share, and non-GAAP Stand-Alone adjusted net loss at $2 million
-- Reported Adjusted EBITDAX of $405 million and Stand-Alone Adjusted
EBITDAX of $335 million, a 26% and 25% increase over the prior year
period, respectively
-- Stand-Alone Net Debt to trailing twelve months Stand-Alone Adjusted
EBITDAX was 2.6x at quarter-end
-- Drilled longest lateral in West Virginia history at 15,100 lateral feet
-- Antero targeted 2018 and 2019 natural gas production is 100% hedged at
$3.50 per MMBtu
Commenting on the quarter, Paul Rady, Chairman and CEO said, "We have made significant progress towards achieving our financial and operating objectives during the first half of 2018. Our focus on operations execution resulted in meaningful efficiency gains during the first half of the year. This has positioned us to reduce the number of completion crews that we plan to operate in the field during the remainder of the year, while production growth of 20% and capital spending guidance remain on target. We continue to execute on our long-term 5-year plan in which we expect attractive production growth while generating significant free cash flow."
Recent Developments
2018 Guidance Update
Based on the first half realizations and current strip prices for the second half of the year, Antero is raising its full year realized natural gas price guidance before hedges from a range of $0.00 to $0.05 per Mcf premium to NYMEX Henry Hub to a range of $0.05 to $0.10 per Mcf premium to NYMEX. Importantly, the Rover Phase 2 Sherwood Lateral is expected to allow Antero's Marcellus gas to be transported on Rover to attractively priced Chicago and Gulf Coast markets, highlighting the optionality that the Sherwood Lateral brings to Antero's long-term development plan. The ability to consistently realize natural gas prices above NYMEX reflects the competitive advantage of Antero's diversified firm transportation portfolio and ability to sell gas into favorably priced markets.
Driven primarily by a delay of the in-service date of the Mariner East 2 pipeline, now expected in the fourth quarter of 2018, Antero is lowering its guidance on C3+ NGL realized prices as a percentage of WTI from a range of 62.5% to 67.5% to a range of 57.5% to 62.5%. Additionally, although NGL prices on an absolute dollar per barrel basis have remained in line with prior guidance assumptions, NGL prices have not increased at the same rate as WTI during 2018. The Mariner East 2 pipeline and terminal project is expected to result in a significant reduction in propane and butane differentials to Mont Belvieu, driven by lower transportation costs to the market and sales to international markets at a premium to Mont Belvieu pricing.
In conjunction with the Mariner East 2 pipeline delay, Antero is also lowering its cash cost guidance for 2018 from $2.10 to $2.20 per Mcfe on a Stand-Alone basis to $2.05 to $2.15 per Mcfe, and from $1.65 to $1.75 per Mcfe on a consolidated basis to $1.60 to $1.70 per Mcfe. Cash costs include lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes.
The following table is a comparison of the initial 2018 guidance issued in January 2018 and the revised 2018 guidance. Except as mentioned below, our previously issued 2018 guidance remains unchanged.
Guidance 2018 - Revised 2018 - Initial Variance
-------- -------------- -------------- --------
Low High Low High Midpoint
--- --------
Price Realizations
Natural Gas Realized Price Premium to NYMEX Henry Hub $0.05 - $0.10 $0.00 - $0.05 $0.05
C3+ NGL Realized Price as a Percent of NYMEX WTI 57.5% - 62.5% 62.5% - 67.5% (5.0%)
Benchmark WTI Price ($/Bbl) (1) $67.00 $60.00 $7.00
Implied C3+ NGL Pricing Guidance ($/Bbl) $38.53 - $41.88 $37.50 - $40.50 $1.20
Cash Production Expense ($/Mcfe) - Stand-Alone $2.05 - $2.15 $2.10 - $2.20 ($0.05)
Cash Production Expense ($/Mcfe) - Consolidated $1.60 - $1.70 $1.65 - $1.75 ($0.05)
(1) Revised benchmark WTI price
guidance reflects actual
year-to-date WTI prices and
futures as of 7/31/18.
Initial benchmark WTI price
guidance based on strip
prices as of 12/31/17.
Financial and operational results are reported and discussed on a consolidated basis, unless otherwise noted. Please read "Non-GAAP Financial Measures" for:
-- A description of consolidated and Stand-Alone non-GAAP measures,
including Adjusted EBITDAX and adjusted net income and reconciliations
to their nearest comparable GAAP measures
-- A reconciliation of revenue excluding unrealized derivative gains
(losses) to operating revenue, the most comparable GAAP measure
-- A reconciliation of Net Debt to total debt, the most comparable GAAP
measure
-- A reconciliation of Antero Midstream's Adjusted EBITDA and Distributable
Cash Flow to their nearest comparable GAAP measure
Please read "Second Quarter 2018 Financial Results" for a reconciliation of consolidated and Stand-Alone Adjusted EBITDAX margin to realized price before cash receipts for settled commodity derivatives, the most comparable GAAP measure.
Second Quarter 2018 Financial Results
As of June 30, 2018, Antero Resources owned a 53% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Antero Midstream's results are consolidated within Antero Resources' results.
For the three months ended June 30, 2018, Antero reported a GAAP net loss of $136 million, or $(0.43) per diluted share, compared to a net loss of $5 million, or $(0.02) per diluted share, in the prior year period. Excluding items detailed in "Non-GAAP Financial Measures," adjusted net income was $6 million, or $0.02 per diluted share, compared to a $13 million loss, or $(0.04) per diluted share, in the prior year period. Stand-Alone adjusted net loss was $2 million compared to a loss of $17 million in the prior year period. Adjusted EBITDAX was $405 million, a 26% increase compared to $321 million in the prior year period, and Stand-Alone Adjusted EBITDAX was $335 million, a 25% increase compared to $267 million in the prior year period. Second quarter 2018 results include settled marketing derivative losses of $16 million.
The following table details the components of average net production and average realized prices for the three months ended June 30, 2018:
Three Months Ended June 30, 2018
--------------------------------
Natural Gas Oil (Bbl/d) C3+ NGLs Ethane Combined
(MMcf/d) (Bbl/d) (Bbl/d) Natural Gas
Equivalent
(MMcfe/d)
---------
Average Net Production 1,838 6,940 70,485 36,156 2,520
Average Realized Prices Gas ($/Mcf) Oil ($/Bbl) C3+ NGLs Ethane Combined Gas
($/Bbl) ($/Bbl) Equivalent
($/Mcfe)
----------------------- ----------- ----------- --------- ------- ------------
Average realized prices before settled
derivatives $2.83 $61.55 $34.81 $9.93 $3.35
Settled commodity derivatives 0.67 (9.44) (1.71) - 0.42
---- ----- ----- --- ----
Average realized prices after settled
derivatives $3.50 $52.11 $33.10 $9.93 $3.77
NYMEX average price $2.80 $68.03 $2.80
----- ------ -----
Premium / (Differential) to NYMEX $0.70 $(15.92) $0.97
===== ======= =====
Net daily natural gas equivalent production in the second quarter averaged 2,520 MMcfe/d, including 113,581 Bbl/d of liquids (27% of production), an increase of 15% compared to the prior year period and a 6% increase sequentially. Natural gas production averaged 1,838 MMcf/d, oil production averaged 6,940 Bbl/d, C3+ NGLs production averaged 70,485 Bbl/d, and recovered ethane production averaged 36,156 Bbl/d. Total liquids production grew 11% compared to the prior year period and 10% sequentially. Liquids revenue represented approximately 38% of total product revenue before hedges, an increase from 30% of total product revenue in the prior year period. This increase reflects the substantial increase in liquids pricing year over year.
Antero's average realized natural gas price before hedging was $2.83 per Mcf, a $0.03 per Mcf premium to the average NYMEX Henry Hub price during the period. Including hedges, Antero's average realized natural gas price was $3.50 per Mcf, a $0.70 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $113 million, or $0.67 per Mcf.
Antero's average realized C3+ NGL price before hedging was $34.81 per barrel, or 51% of the average NYMEX WTI oil price, representing a 44% increase versus the prior year period. Including hedges, Antero's average realized C3+ NGL price was $33.10 per barrel, reflecting the realization of a cash settled C3+ hedge loss of $11 million, or $1.71 per barrel.
Antero's average realized oil price before hedging was $61.55 per barrel, a $6.48 negative differential to average NYMEX WTI and a 42% increase versus the prior year period. Including hedges, the average realized oil price was $52.11 per barrel, reflecting the realization of a cash settled WTI crude oil loss of $6 million, or $9.44 per barrel. The average realized ethane price was $0.24 per gallon, or $9.93 per barrel, compared to $0.20 per gallon, or $8.40 per barrel, in the prior year period.
Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.35 per Mcfe, representing a 3% increase compared to the prior year period. Including hedges, the Company's average natural gas equivalent price was $3.77 per Mcfe, an 11% increase from the prior year period, primarily driven by higher realized liquids prices and hedge gains. Net cash settled hedge gains on all products were $96 million, or $0.42 per Mcfe.
Operating revenues in the second quarter were $989 million, compared to $790 million in the prior year period. Revenue included a $41 million non-cash loss on unsettled commodity derivatives and a $16 million non-cash gain on unsettled marketing derivatives, while the prior year included a $55 million non-cash gain on unsettled commodity derivatives. Revenue excluding gains and losses on unsettled derivatives was $1.0 billion, a 38% increase versus the prior year period. Liquids production contributed 38% of total product revenues before hedges, compared to a 30% contribution in the prior year period. Please see "Non-GAAP Financial Measures" for a description of revenue excluding unrealized derivative (gains) losses.
The following table presents a reconciliation of Stand-Alone and consolidated realized price before cash receipts for settled derivatives to Adjusted EBITDAX margin for the three months ended June 30, 2017 and 2018:
Stand-Alone Consolidated
Three months ended June 30, Three months ended June 30,
--------------------------- ---------------------------
2017 2018 2017 2018
---- ---- ---- ----
Adjusted EBITDAX margin ($ per Mcfe):
Realized price before cash receipts for settled derivatives $3.26 3.35 $3.26 3.35
Gathering, compression, and water handling and treatment revenues - - 0.01 0.02
Distributions from unconsolidated affiliates - - 0.03 0.05
Distributions from Antero Midstream 0.17 0.18 - -
Gathering, compression, processing and transportation costs (1.76) (1.79) (1.33) (1.34)
Lease operating expense (0.09) (0.14) (0.08) (0.13)
Marketing, net (1) (0.14) (0.30) (0.14) (0.30)
Production and ad valorem taxes (0.11) (0.11) (0.11) (0.11)
General and administrative (excluding equity-based compensation) (0.15) (0.15) (0.19) (0.19)
----- ----- ----- -----
Adjusted EBITDAX margin before settled commodity derivatives 1.18 1.04 1.45 1.35
---- ---- ---- ----
Cash receipts for settled commodity derivatives 0.15 0.42 0.15 0.42
---- ---- ---- ----
Adjusted EBITDAX margin ($ per Mcfe): $1.33 1.46 $1.60 1.77
===== ==== ===== ====
(1) Includes cash payments for
settled marketing
derivative losses of $0.07
per Mcfe in 2018.
Stand-Alone per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) was $2.04 per Mcfe, a 4% increase compared to $1.96 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.79 per Mcfe for gathering, compression, processing and transportation costs, $0.14 per Mcfe for lease operating costs, and $0.11 per Mcfe for production and ad valorem taxes. Lease operating expenses increased in the second quarter due to an increase in produced water from newer wells that were completed with higher water intensity advanced completions.
Stand-Alone per unit net marketing expense was $0.30 per Mcfe compared to $0.14 per Mcfe reported in the prior year period. Net marketing expense increased due to higher unutilized excess capacity related to Rover pipeline capacity that was placed in service in late 2017. Net marketing expense included a $0.07 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 condensed consolidated financial statements in Antero's Form 10-Q for more information on these contracts.
Stand-Alone per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.15 per Mcfe, consistent with the prior year period.
Stand-Alone Adjusted EBITDAX was $335 million for the second quarter of 2018, a 25% increase compared to $267 million in the prior year period. The increase was primarily driven by increased production and pricing. Stand-Alone Adjusted EBITDAX margin was $1.46 per Mcfe, a 10% increase from the prior year period. Consolidated Adjusted EBITDAX was $405 million, compared to $321 million in the prior year period, a 26% increase over the prior year period. Consolidated Adjusted EBITDAX margin was $1.77 per Mcfe, compared to $1.60 per Mcfe in the prior year period.
Stand-Alone net cash provided by operating activities was $229 million for the period. Stand-Alone Adjusted Operating Cash Flow was $279 million, a 36% increase over the prior year period. Consolidated net cash provided by operating activities was $297 million for the period. Consolidated Adjusted Operating Cash Flow was $335 million during the second quarter, a 34% increase compared to the prior year period. Stand-Alone Adjusted Operating Cash Flow and Adjusted Operating Cash Flow increased versus the prior year period primarily due to higher production and liquids prices during the quarter.
Operating Update
Second Quarter 2018
Marcellus Shale -- Antero placed 25 horizontal Marcellus wells to sales during the second quarter of 2018 with an average lateral length of 9,500 feet and a 30-day gross average rate per well of 16.9 MMcfe/day on choke. The 30-day gross rate included 914 Bbl/d of liquids, representing oil, C3+ NGLs and 25% of the ethane that could be recovered ("25% ethane recovery"). Current average well costs are $0.86 million per 1,000 feet of lateral in the Marcellus assuming the 2018 average lateral length of 10,000 feet and 2,000 pounds of proppant per foot.
During the quarter, Antero drilled 22 wells in the Marcellus with an average lateral length of 9,600 feet in approximately 12 total days from spud to final rig release on average. Antero also set a state of West Virginia record for the longest lateral drilled to date at 15,100 lateral feet during the period. Antero completed 5.0 stages per day on average during the second quarter and achieved a record 5.5 stages per day during the month of April. Completion efficiencies improved from 4.3 stages per day in the prior quarter and exceeded the 4.5 stages per day budgeted for 2018. The trend continues with 6.5 stages per day completed on average in late July 2018. Antero recently completed its first remote completion which involved locating crews and equipment on a separate pad from the well pad, enabling improved logistics for completion operations. These operational efficiencies led to an acceleration of total stages completed during the first half of the year. As a result, Antero expects to place a total of 50 to 60 Marcellus wells to sales during the third quarter of 2018, including the Company's largest pad to date, a 14-well pad that recently commenced production in July. Because of these efficiency gains, Antero expects to release two completion crews in the coming weeks, resulting in an average of four crews operating during the second half of 2018, compared to six crews in the first half of 2018. Antero's operating plan contemplates a reduction in capital spending during the second half of the year, as compared to the first half of 2018.
Two Marcellus pads completed late in the first quarter of 2018 have now been online for more than 90 days with noteworthy gross production rates. One 9-well pad with an average lateral length of 8,300' produced a 90-day gross average rate of 157 MMcfe per day, which is on average 17.5 MMcfe/d day per well with 25% ethane recovery, including 7,715 Bbl/d of liquids. A second 3-well pad representing the most westerly wells completed on Antero's Marcellus acreage to date averaged 9,000 feet in lateral length per well and produced a 90-day gross average rate of 18.5 MMcfe/d per well with 25% ethane recovery, including 1,112 Bbl/d of liquids per well.
During the latter part of the second quarter and into the third quarter, Antero has experienced production curtailments due to tightness in the local crude trucking takeaway market. This is at present a common issue industry-wide. The Company's crude buyers have been challenged to secure an adequate number of licensed trucks and drivers to move Antero's growing crude production. The Company expects these production curtailments to be temporary in nature as Antero has recently executed direct agreements for additional trucking capacity. This additional capacity will enable Antero to lift existing curtailments as well as move the 100,000 barrel-plus crude inventory that has built up over the past couple of months. Currently, approximately 100 MMcfe/d is curtailed, including 4,000 Bbl/d of NGLs and 2,000 Bbl/d of crude oil. With truck capacity expected to match oil production beginning in September, Antero anticipates that the production curtailment will be alleviated by the fourth quarter of 2018.
Ohio Utica Shale -- Antero placed five horizontal Ohio Utica wells to sales during the second quarter of 2018 with an average lateral length of approximately 15,900 feet and an average 30-day rate of 12.9 MMcfe/d per well on choke. Current average well costs are $0.95 million per 1,000 feet of lateral in the Ohio Utica assuming the 2018 average lateral length of 12,000 feet and 2,000 pounds of proppant per foot. The Company does not plan to operate any drilling rigs or completion crews in the Ohio Utica Shale during the remainder of 2018 as the second half 2018 development plan shifts to liquids-rich locations in the Marcellus due to the continued strength in liquids pricing. The Company's current five year plan does include the resumption of drilling and completion activity in the Ohio Utica Shale in 2019.
During the period, Antero drilled six wells in the Utica dry gas regime with an average lateral length of 12,900 feet in 20 total days from spud to final rig release. This represents a 4% decrease in drilling days and a 22% increase in lateral length in the Utica dry gas regime compared to 2017. In addition, Antero drilled nearly 5,200 lateral feet in a 24-hour period, which is a company record for drilled lateral footage in 24 hours in the Utica. During the second quarter, the Company completed 5.4 stages per day on average, above the 5.1 stages per day achieved during the first quarter.
During the third quarter of 2018, the Company expects to place a total of 15 wells to sales in the Utica with an average lateral length of 10,200 feet per well.
President and CFO, Glen Warren, commented, "Earlier this year, we set our sights on delivering an attractive plan of living within cash flow and reducing leverage while maintaining disciplined production growth over our five year plan. Our continued focus on strong execution has propelled us to reach drilling and completion efficiencies faster than anticipated. As a result, our full year capital spending targets remain the same, but capital is weighted toward the first half of the year and production growth is weighted toward the back half of the year. Notably, we expect to place 65 to 75 wells to sales in the third quarter, a sizeable increase from the 51 wells placed to sales in the first six months of the year. Our operational momentum gives us confidence in the execution of our operating plan for 2018 and in future years."
Second Quarter 2018 Capital Investment
Antero invested $393 million on drilling and completion capital expenditures for the three months ended June 30, 2018. In addition, the Company invested $38 million for land, $113 million for gathering and compression systems and $18 million for water infrastructure projects, including $8 million for the Antero Clearwater Treatment Facility. Antero's Stand-Alone drilling and completion capital expenditures for the three months ended June 30, 2018, were $467 million.
Balance Sheet and Liquidity
As of June 30, 2018, Antero's Stand-Alone Net Debt was $3.8 billion, of which $455 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under this facility were $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 June 30, 2018. As of June 30, 2018, Antero's Stand-Alone Net Debt to trailing twelve months Stand-Alone Adjusted EBITDAX ratio was 2.6x.
Commodity Derivative Positions
Antero's estimated natural gas production for the second half of 2018 at the midpoint of guidance is fully hedged at an average index price of $3.49 per MMBtu. The Company's target natural gas production for 2019 is fully hedged at an average index price of $3.50 per MMBtu. In total, Antero has hedged 2.3 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from July 1, 2018, through December 31, 2023, at an average index price of $3.35 per MMBtu. As of June 30, 2018, the Company's estimated fair value of commodity derivative instruments was $1.2 billion. The following table summarizes Antero's hedge position as of June 30, 2018:
Period Natural Gas Average Liquids Average
MMBtu/d Index price Bbl/d Index price
($/MMBtu)
--- ---------
3Q 2018:
--------
NYMEX Henry Hub 2,002,500 $3.45 - -
Propane MB
($/Gal) - - 26,000 $0.76
NYMEX WTI ($/Bbl) - - 6,000 $56.99
4Q 2018:
--------
NYMEX Henry Hub 2,002,500 $3.53 - -
Propane MB
($/Gal) - - 26,000 $0.77
NYMEX WTI ($/Bbl) - - 6,000 $56.99
----------------- --- --- ----- ------
2H 2018 Total 2,002,500 $3.49 32,000 N/A (1)
2019:
-----
NYMEX Henry Hub 2,330,000 $3.50 - -
2020:
-----
NYMEX Henry Hub 1,417,500 $3.25 - -
2021:
-----
NYMEX Henry Hub 710,000 $3.00 - -
2022:
-----
NYMEX Henry Hub 850,000 $3.00 - -
2023:
-----
NYMEX Henry Hub 90,000 $2.91 - -
(1) Average index price is not
applicable as 2018 liquids
hedges include propane and
oil hedges.
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:
Three Months Ended
June 30,
--------
Average Daily Volumes: 2017 2018 % Change
---- ---- --------
Low Pressure Gathering (MMcf/d) 1,683 1,981 18%
Compression (MMcf/d) 1,192 1,558 31%
High Pressure Gathering (MMcf/d) 1,734 1,932 11%
Fresh Water Delivery (MBbl/d) 173 228 32%
Wastewater Treatment (MBbl/d) - 8 *
Gross Joint Venture Processing (MMcf/d) 216 571 164%
Gross Joint Venture Fractionation (MBbl/d) 4,039 10,046 148%
Net income for the second quarter of 2018 was $76 million, a 6% increase compared to the prior year quarter. Net income per limited partner unit was $0.41 per unit, a 5% increase compared to the prior year quarter. Adjusted EBITDA was $176 million, a 26% increase compared to the prior year quarter. Distributable Cash Flow was $142 million, a 30% increase over the prior year quarter, 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."
Antero Midstream declared a distribution of $0.39 per limited partner unit attributable to the first quarter of 2018, resulting in $39 million of distributions received by Antero Resources from Antero Midstream during the second quarter of 2018. On July 18, 2018, Antero Midstream declared a distribution of $0.415 per limited partner unit attributable to the second quarter of 2018.
Conference Call
A conference call is scheduled on Thursday, August 2, 2018 at 9:00 am MT to discuss the quarterly 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 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference "Antero Resources". A telephone replay of the call will be available until Thursday, August 9, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10120010.
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, August 9, 2018 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the August 2, 2018 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.
Non-GAAP Financial Measures
Revenue Excluding Unrealized Derivative (Gains) Losses
Revenue excluding unrealized derivative (gains) losses as set forth in this release represents total operating revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that revenue excluding unrealized derivative (gains) losses 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 is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance. The following table reconciles total operating revenue to revenue excluding unrealized derivative (gains) losses:
Three months ended
June 30,
--------
2017 2018
---- ----
Total operating revenue $790,389 $989,344
Commodity derivative fair
value gains (85,641) (55,336)
Marketing derivative fair
value losses - 110
Gains on settled commodity
derivatives 31,064 95,884
Losses on settled marketing
derivatives - (15,884)
--- -------
Revenue excluding
unrealized derivative
(gains) losses $735,812 $1,014,118
======== ==========
Adjusted Net Income (Loss) & Stand-Alone Adjusted Net Income (Loss)
Adjusted net income (loss) as set forth in this release represents net income, adjusted for certain items. Stand-Alone adjusted net income (loss) 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 (loss) 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 (loss) and Stand-Alone adjusted net income (loss) 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 (loss) to adjusted net income (loss) and Stand-Alone net (loss) to Stand-Alone adjusted net (loss) (in thousands):
Stand-Alone Consolidated
Three months ended Three months ended
June 30, June 30,
-------- --------
2017 2018 2017 2018
---- ---- ---- ----
Net (loss) $(5,132) $(136,385) $(5,132) $(136,385)
Commodity derivative
fair value gains (85,641) (55,336) (85,641) (55,336)
Gains on settled
commodity derivatives 31,064 95,884 31,064 95,884
Marketing derivative
fair value losses - 110 - 110
Losses on settled
marketing derivatives - (15,884) - (15,884)
Impairment of unproved
properties 15,199 134,437 15,199 134,437
Impairment of gathering
systems and facilities - 4,470 - 8,501
Equity-based
compensation 20,024 13,204 26,975 19,071
Income tax effect of
reconciling items 7,323 (42,214) 4,693 (44,577)
----- ------- ----- -------
Adjusted net income
(loss) $(17,163) $(1,714) $(12,842) $5,821
======== ======= ======== ======
Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating 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.
Management believes that Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating 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 and Stand-Alone Adjusted Operating 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 and Stand-Alone Adjusted Operating Cash Flow reported by different companies. Adjusted Operating Cash Flow and Stand-Alone Adjusted Operating 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 is not a measure 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
June 30, June 30,
-------- --------
2017 2018 2017 2018
---- ---- ---- ----
Net
cash
provided
by
operating
activities $202,460 228,503 $253,647 297,391
Net
change
in
working
capital 2,420 50,513 (2,853) 37,803
----- ------ ------ ------
Adjusted
Operating
Cash
Flow $204,880 279,016 $250,794 335,194
======== ======= ======== =======
Total Debt and Net Debt
The following table reconciles consolidated total debt to Net Debt as used in this release (in thousands):
December 31, June 30,
2017 2018
---- ----
AR bank credit facility $185,000 455,000
AM bank credit facility 555,000 770,000
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 1,382
Net unamortized debt
issuance costs (41,430) (38,038)
------- -------
Consolidated total debt $4,800,090 5,288,344
Less: AR cash and cash
equivalents 20,078 31,083
Less: AM cash and cash
equivalents 8,363 19,525
----- ------
Consolidated Net Debt $4,771,649 5,237,736
========== =========
Stand-Alone Net Debt $3,584,012 3,845,695
========== =========
Adjusted EBITDAX and Stand-Alone Adjusted EBITDAX
Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses, but including net cash receipts or payments on derivative instruments included in derivative fair value gains or losses, taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. 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, 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, income 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 condensed 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 June 30, Three months ended June 30,
--------------------------- ---------------------------
(in thousands) 2017 2018 2017 2018
------------- ---- ---- ---- ----
Net income (loss) including
noncontrolling interest $(5,132) (136,385) $39,965 (67,275)
Commodity derivative fair
value gains (85,641) (55,336) (85,641) (55,336)
Gains on settled commodity
derivatives 31,064 95,884 31,064 95,884
Marketing derivative fair
value losses - 110 - 110
Losses on settled marketing
derivatives - (15,884) - (15,884)
Interest expense 59,735 54,388 68,582 69,349
Income tax expense (benefit) 18,819 (25,573) 18,819 (25,573)
Depletion, depreciation,
amortization, and accretion 171,319 202,283 201,831 238,750
Impairment of unproved
properties 15,199 134,437 15,199 134,437
Impairment of gathering
systems and facilities - 4,470 - 8,501
Exploration expense 1,804 1,471 1,804 1,471
Gain on change in fair value
of contingent acquisition
consideration (3,590) (3,947) - -
Equity-based compensation
expense 20,024 13,204 26,975 19,071
Equity in earnings of
unconsolidated affiliates - - (3,623) (9,264)
Distributions from
unconsolidated affiliates - - 5,820 10,810
Equity in (earnings) loss of
Antero Midstream Partners LP 10,408 26,926 - -
Distributions from Antero
Midstream Partners LP 32,661 38,559 - -
------ ------ --- ---
Adjusted EBITDAX 266,670 334,607 320,795 405,051
------- ------- ------- -------
Interest expense (59,735) (54,388) (68,582) (69,349)
Exploration expense (1,804) (1,471) (1,804) (1,471)
Changes in current assets and
liabilities (2,420) (50,513) 2,853 (37,803)
Other non-cash items (251) 268 385 963
---- --- --- ---
Net cash provided by
operating activities $202,460 228,503 $253,647 297,391
======== ======= ======== =======
The following table reconciles Antero's Stand-Alone net income to Adjusted EBITDAX for the twelve months ending June 30, 2018, as used in this release (in thousands):
Stand-Alone
Twelve months ended
June 30,
--------
(in thousands) 2018
------------- ----
Net income including noncontrolling interest $230,254
Commodity derivative fair value gains (211,640)
Gains on settled commodity derivatives 335,252
Marketing derivative fair value gains (72,730)
Gains on settled marketing derivatives 94,158
Interest expense 222,479
Loss on early extinguishment of debt 1,205
Income tax benefit (461,669)
Depletion, depreciation, amortization, and
accretion 759,260
Impairment of unproved properties 302,473
Impairment of gathering systems and
facilities 4,470
Exploration expense 7,983
Gain on change in fair value of contingent
acquisition consideration (14,181)
Equity-based compensation expense 65,070
Equity in (earnings) loss of Antero
Midstream 74,056
Distributions from Antero Midstream 143,100
-------
Adjusted EBITDAX $1,479,540
==========
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, 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 June 30,
---------------------------
2017 2018
---- ----
Net income $87,175 109,466
Interest expense 9,015 14,628
Impairment of property and equipment expense - 4,614
Depreciation expense 30,512 36,433
Gain on sale of assets - (583)
Accretion of contingent acquisition consideration 3,590 3,947
Accretion of asset retirement obligations - 34
Equity-based compensation 6,951 5,867
Equity in earnings of unconsolidated affiliates (3,623) (9,264)
Distributions from unconsolidated affiliates 5,820 10,810
----- ------
Adjusted EBITDA 139,440 175,952
Interest paid (2,308) (6,270)
Decrease in cash reserved for bond interest (1) (8,734) (8,734)
Income tax withholding upon vesting of Antero Midstream Partners LP equity-based
compensation awards (2) (2,431) (1,500)
Maintenance capital expenditures (3) (16,422) (17,289)
------- -------
Distributable Cash Flow $109,545 142,159
======== =======
Distributions Declared to Antero Midstream Holders
Limited Partners $59,695 77,624
Incentive distribution rights 15,328 33,137
------ ------
Total Aggregate Distributions $75,023 110,762
======= =======
DCF coverage ratio 1.46x 1.28x
(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) Estimate of current period portion of
expected cash payment for income tax
withholding attributable to vesting
of Midstream LTIP equity-based
compensation awards to be paid in
the fourth quarter.
(3) 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 future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Adjusted EBITDAX, Stand-Alone Adjusted EBITDAX, Adjusted Operating Cash Flow, Stand-Alone Adjusted Operating Cash Flow, Free Cash Flow, 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, 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, 2017.
In this press release, Antero uses terms such as "resource potential" to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC. Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties. These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery. Actual quantities that may be ultimately recovered from Antero's interests may differ substantially from the estimates in this press release. Factors affecting ultimate recovery include the scope of Antero's ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.
ANTERO RESOURCES CORPORATION
Condensed Consolidated Balance Sheets
December 31, 2017 and June 30, 2018
(unaudited)
(In thousands, except per share amounts)
December 31, 2017 June 30, 2018
----------------- -------------
Assets
Current assets:
Cash and cash equivalents $28,441 50,608
Accounts receivable, net of allowance for doubtful
accounts of $1,320 at December 31, 2017 and $1,195
at June 30, 2018, respectively 34,896 35,676
Accrued revenue 300,122 321,214
Derivative instruments 460,685 420,842
Other current assets 8,943 6,590
----- -----
Total current assets 833,087 834,930
------- -------
Property and equipment:
Natural gas properties, at cost (successful efforts
method):
Unproved properties 2,266,673 2,108,109
Proved properties 11,096,462 11,924,864
Water handling and treatment systems 946,670 979,937
Gathering systems and facilities 2,050,490 2,255,385
Other property and equipment 57,429 60,766
------ ------
16,417,724 17,329,061
Less accumulated depletion, depreciation, and
amortization (3,182,171) (3,647,910)
---------- ----------
Property and equipment, net 13,235,553 13,681,151
---------- ----------
Derivative instruments 841,257 763,592
Investments in unconsolidated affiliates 303,302 358,830
Other assets 48,291 52,104
------ ------
Total assets $15,261,490 15,690,607
=========== ==========
Liabilities and Equity
Current liabilities:
Accounts payable $62,982 96,477
Accrued liabilities 443,225 438,829
Revenue distributions payable 209,617 211,234
Derivative instruments 28,476 30,661
Other current liabilities 17,796 11,532
------ ------
Total current liabilities 762,096 788,733
Long-term liabilities:
Long-term debt 4,800,090 5,288,344
Deferred income tax liability 779,645 763,192
Derivative instruments 207 -
Other liabilities 43,316 47,427
------ ------
Total liabilities 6,385,354 6,887,696
--------- ---------
Commitments and contingencies (notes 12 and 13)
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 317,052
shares issued and outstanding at December 31, 2017
and June 30, 2018, respectively 3,164 3,171
Additional paid-in capital 6,570,952 6,597,537
Accumulated earnings 1,575,065 1,453,513
--------- ---------
Total stockholders' equity 8,149,181 8,054,221
Noncontrolling interests in consolidated subsidiary 726,955 748,690
------- -------
Total equity 8,876,136 8,802,911
--------- ---------
Total liabilities and equity $15,261,490 15,690,607
=========== ==========
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Loss
Three Months Ended June 30, 2017 and 2018
(unaudited)
(In thousands, except per share amounts)
Three Months Ended June 30,
---------------------------
2017 2018
---- ----
Revenue:
Natural gas sales $454,257 473,540
Natural gas liquids sales 170,819 255,985
Oil sales 26,512 38,873
Commodity derivative fair value gains 85,641 55,336
Gathering, compression, water handling and treatment 3,192 5,518
Marketing 49,968 160,202
Marketing derivative fair value losses - (110)
--- ----
Total revenue 790,389 989,344
------- -------
Operating expenses:
Lease operating 16,992 30,164
Gathering, compression, processing, and transportation 266,747 307,786
Production and ad valorem taxes 22,553 25,891
Marketing 77,421 213,420
Exploration 1,804 1,471
Impairment of unproved properties 15,199 134,437
Impairment of gathering systems and facilities - 8,501
Depletion, depreciation, and amortization 201,182 238,050
Accretion of asset retirement obligations 649 700
General and administrative (including equity-based compensation expense of $26,975 and $19,071 in 2017 and 2018, respectively) 64,099 61,687
------ ------
Total operating expenses 666,646 1,022,107
------- ---------
Operating income (loss) 123,743 (32,763)
------- -------
Other income (expenses):
Equity in earnings of unconsolidated affiliates 3,623 9,264
Interest (68,582) (69,349)
------- -------
Total other expenses (64,959) (60,085)
------- -------
Income (loss) before income taxes 58,784 (92,848)
Provision for income tax (expense) benefit (18,819) 25,573
------- ------
Net income (loss) and comprehensive income (loss) including noncontrolling interests 39,965 (67,275)
Net income and comprehensive income attributable to noncontrolling interests 45,097 69,110
------ ------
Net loss and comprehensive loss attributable to Antero Resources Corporation $(5,132) (136,385)
======= ========
Loss per common share-basic $(0.02) (0.43)
Loss per common share-assuming dilution $(0.02) (0.43)
Weighted average number of shares outstanding:
Basic 315,401 316,992
Diluted 315,401 316,992
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Cash Flows
Six Months Ended June 30, 2017 and 2018
(unaudited)
(In thousands)
Six Months Ended June 30,
-------------------------
2017 2018
---- ----
Cash flows provided by (used in) operating
activities:
Net income including noncontrolling interests $345,523 13,535
Adjustments to reconcile net income to net
cash provided by operating activities:
Depletion, depreciation, amortization, and
accretion 405,197 467,684
Impairment of unproved properties 42,098 184,973
Impairment of gathering systems and
facilities - 8,501
Commodity derivative fair value gains (524,416) (77,773)
Gains on settled commodity derivatives 75,913 197,225
Marketing derivative fair value gains - (94,124)
Gains on settled marketing derivatives - 94,158
Deferred income tax expense (benefit) 150,165 (16,453)
Equity-based compensation expense 52,478 40,227
Equity in earnings of unconsolidated
affiliates (5,854) (17,126)
Distributions of earnings from unconsolidated
affiliates 5,820 17,895
Other 472 1,932
Changes in current assets and liabilities:
Accounts receivable 13,188 10,237
Accrued revenue 43,339 (21,092)
Other current assets (2,385) 2,353
Accounts payable 2,072 2,948
Accrued liabilities 4,204 24,065
Revenue distributions payable 39,162 1,617
Other current liabilities 610 (1,842)
--- ------
Net cash provided by operating activities 647,586 838,940
------- -------
Cash flows used in investing activities:
Additions to proved properties (179,318) -
Additions to unproved properties (129,876) (87,861)
Drilling and completion costs (629,308) (752,781)
Additions to water handling and treatment
systems (95,451) (58,127)
Additions to gathering systems and facilities (155,365) (206,753)
Additions to other property and equipment (6,564) (3,502)
Investments in unconsolidated affiliates (191,364) (56,297)
Change in other assets (12,452) (7,026)
Other 2,156 -
----- ---
Net cash used in investing activities (1,397,542) (1,172,347)
---------- ----------
Cash flows provided by (used in) financing
activities:
Issuance of common units by Antero Midstream
Partners LP 246,585 -
Borrowings on bank credit facilities, net 585,000 485,000
Distributions to noncontrolling interests in
consolidated subsidiary (61,869) (119,023)
Employee tax withholding for settlement of
equity compensation awards (8,433) (7,967)
Other (2,747) (2,436)
------ ------
Net cash provided by financing activities 758,536 355,574
------- -------
Net increase in cash and cash equivalents 8,580 22,167
Cash and cash equivalents, beginning of
period 31,610 28,441
------ ------
Cash and cash equivalents, end of period $40,190 50,608
======= ======
Supplemental disclosure of cash flow
information:
Cash paid during the period for interest $125,284 130,231
Increase in accounts payable and accrued
liabilities for additions to property and
equipment $31,182 2,089
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended June 30, 2017 and 2018:
Three Months Ended June 30, Amount of
Increase Percent
---------------------------
(in thousands) 2017 2018 (Decrease) Change
------------- ---- ---- --------- ------
Operating revenues and other:
Natural gas sales $454,257 $473,540 $19,283 4%
NGLs sales 170,819 255,985 85,166 50%
Oil sales 26,512 38,873 12,361 47%
Commodity derivative gains 85,641 55,336 (30,305) (35)%
Gathering, compression, water handling
and treatment 3,192 5,518 2,326 73%
Marketing 49,968 160,202 110,234 221%
Marketing derivative loss - (110) (110) *
--- ---- ----
Total operating revenues and other 790,389 989,344 198,955 25%
------- ------- -------
Operating expenses:
Lease operating 16,992 30,164 13,172 78%
Gathering, compression, processing, and
transportation 266,747 307,786 41,039 15%
Production and ad valorem taxes 22,553 25,891 3,338 15%
Marketing 77,421 213,420 135,999 176%
Exploration 1,804 1,471 (333) (18)%
Impairment of unproved properties 15,199 134,437 119,238 785%
Impairment of gathering systems and
facilities - 8,501 8,501 *
Depletion, depreciation, and
amortization 201,182 238,050 36,868 18%
Accretion of asset retirement
obligations 649 700 51 8%
General and administrative (before
equity-based compensation) 37,124 42,616 5,492 15%
Equity-based compensation 26,975 19,071 (7,904) (29)%
------ ------ ------
Total operating expenses 666,646 1,022,107 355,461 53%
------- --------- -------
Operating income (loss) 123,743 (32,763) (156,506) *
------- ------- --------
Other earnings (expenses):
Equity in earnings of unconsolidated
affiliate 3,623 9,264 5,641 156%
Interest expense (68,582) (69,349) (767) 1%
------- ------- ----
Total other expenses (64,959) (60,085) 4,874 (8)%
------- ------- -----
Income (loss) before income taxes 58,784 (92,848) (151,632) *
Income tax (expense) benefit (18,819) 25,573 44,392 *
------- ------ ------
Net income (loss) and comprehensive
income (loss) including noncontrolling
interest 39,965 (67,275) (107,240) *
Net income and comprehensive income
attributable to noncontrolling
interest 45,097 69,110 24,013 53%
------ ------ ------
Net income (loss) and comprehensive
income (loss) attributable to Antero
Resources Corporation $(5,132) $(136,385) $(131,253) 2,558%
======= ========= =========
Adjusted EBITDAX $320,795 $405,051 $84,256 26%
======== ======== =======
Production data:
Natural gas (Bcf) 144 167 23 16%
C2 Ethane (MBbl) 2,548 3,290 742 29%
C3+ NGLs (MBbl) 6,190 6,414 224 4%
Oil (MBbl) 613 632 19 3%
Combined (Bcfe) 200 229 29 15%
Daily combined production (MMcfe/d) 2,200 2,520 320 15%
Average prices before effects of
derivative settlements:
Natural gas (per Mcf) $3.15 $2.83 $(0.32) (10)%
C2 Ethane (per Bbl) $8.40 $9.93 $1.53 18%
C3+ NGLs (per Bbl) $24.14 $34.81 $10.67 44%
Oil (per Bbl) $43.24 $61.55 $18.31 42%
Weighted Average Combined (per Mcfe) $3.26 $3.35 $0.09 3%
Average realized prices after effects
of derivative settlements(2):
Natural gas (per Mcf) $3.53 $3.50 $(0.03) (1)%
C2 Ethane (per Bbl) $8.61 $9.93 $1.32 15%
C3+ NGLs (per Bbl) $19.92 $33.10 $13.18 66%
Oil (per Bbl) $46.12 $52.11 $5.99 13%
Weighted Average Combined (per Mcfe) $3.41 $3.77 $0.36 11%
Average Costs (per Mcfe):
Lease operating $0.08 $0.13 $0.05 63%
Gathering, compression, processing, and
transportation $1.33 $1.34 $0.01 1%
Production and ad valorem taxes $0.11 $0.11 $ - - %
Marketing expense (gain), net $0.14 $0.23 $0.09 64%
Depletion, depreciation, amortization,
and accretion $1.01 $1.04 $0.03 3%
General and administrative (before
equity-based compensation) $0.19 $0.19 $ - - %
*Not meaningful or applicable
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SOURCE Antero Resources Corporation
