Antero Resources Reports Third Quarter 2017 Financial and Operational Results
DENVER, Nov. 1, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its third quarter 2017 financial and operational results. The relevant condensed consolidated financial statements are included in Antero's Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, which has been filed with the Securities and Exchange Commission (the "SEC").
Highlights Include:
-- Net daily gas equivalent production averaged a record 2,317 MMcfe/d, a
24% increase over the prior year quarter
-- Includes record liquids production of 112,393 Bbl/d, a 38% increase over
the prior year quarter
-- Realized natural gas price of $2.71 per Mcf, a $0.29 differential to the
average Nymex natural gas price before hedging. This includes a net
$0.26 per Mcf negative impact from two contractual disputes on natural
gas sales contracts where Antero expects to recover damages as detailed
further below.
-- Realized C3+ NGL price of $28.92 per barrel before hedging, or 60% of
the average WTI oil price
-- Realized natural gas equivalent price of $3.39 per Mcfe including NGLs,
oil and hedges
-- Liquids revenue of $251 million, comprising 38% of total product
revenues, a Company record
-- GAAP net loss of $135 million, or $(0.43) per share, compared to net
income of $238 million, or $0.78 per share, in the prior year quarter
-- Adjusted EBITDAX of $336 million, a 10% decrease compared to the prior
year quarter and a 5% increase sequentially. This Adjusted EBITDAX does
not include the $47 million impact from the contractual disputes
detailed below.
-- Successfully monetized over $1 billion of non-E&P assets through
combination of the sale of Antero Midstream common units and the
restructuring of the hedge portfolio
-- Entered into a new upstream credit facility with a borrowing base of
$4.5 billion and lender commitments of $2.5 billion
Commenting on the quarter and long-term outlook, Paul Rady, Chairman and CEO, said, "We took a number of steps during the quarter to delever the balance sheet, and have positioned Antero to generate attractive growth and returns while spending within cash flow in 2018 and beyond. This is a testament to the capital efficiencies and EUR improvements that we have achieved to date. Through increased EURs and lower well costs, we have been able to reduce our drilling and completion capital spending plans over the 2018 through 2020 period by approximately $1.5 billion while delivering the same production growth. Importantly, this production growth includes rapid NGL production growth, providing us with substantial upside exposure to a continuing rise in liquids pricing. The combination of the sizeable reduction in capital needs with the increased liquids cash flow provides Antero with declining leverage and an improving balance sheet. This trend positions Antero to be able to return capital to shareholders in the coming years, subject to Board review and approval."
Recent Developments
Antero Three Year Outlook
Based on the Company's internal development plan, Antero is targeting a compound annual production growth rate of 20% over the four year period of 2017 to 2020, with a drilling and completion capital program that is self-funded with E&P stand-alone cash flow. The current development plan assumes flat $3.00/MMBtu NYMEX gas and $54/Bbl WTI oil, in line with 2018 strip pricing, and a targeted drilling and completion capital program of approximately $1.3 billion in 2018, $1.5 billion in 2019 and $1.5 billion in 2020. These capital budget targets have not been approved by Antero's Board. The $1.3 billion targeted drilling and completion capital program in 2018 reflects the third consecutive year of maintaining a flat capital program while still delivering top tier production growth. Additionally, as a result of increased EURs, lower well costs, and land consolidation efforts supporting long lateral drilling, this development plan represents a reduction of 200 wells and approximately $1.5 billion in capital through 2020 when compared to the prior development plan targeting the same production growth. This capital plan focuses on liquids-rich, high margin locations designed to deliver significant per share cash flow and production growth over the next three years.
Updated NGL Pricing Realizations Forecast
Based on public company disclosure, Antero is now the largest NGL producer in the U.S. with 105,609 Bbl/d produced in the third quarter of 2017, representing 37% growth compared to the prior year quarter. This includes 75,290 Bbl/d of C3+ NGLs and 30,319 Bbl/d of recovered ethane. Antero's average realized C3+ NGL price before hedging for the third quarter of 2017 was $28.92 per barrel, or 60% of the average Nymex WTI oil price, which represents a 65% increase as compared to the prior year quarter. Due to continued strength in domestic C3+ NGL markets and export demand, Antero is forecasting realizations of 70% to 75% of WTI on its C3+ NGL production for the fourth quarter of 2017. In addition, based on strip pricing, Antero is forecasting realizations of approximately $35/Bbl, or 65% of WTI for 2018. Based on current strip prices and production targets, Antero estimates that cash flow from liquids production is forecast to be approximately $390 million higher in 2018 as compared to 2017.
Completion of $1 Billion Delevering Program
Antero previously announced that it monetized over $1 billion of non-exploration and production ("E&P") assets in September 2017. This includes the sale of 10 million common units representing limited partner interests in Antero Midstream Partners LP (NYSE:AM) ("Antero Midstream") and the restructuring of a portion of its commodity hedge portfolio. Proceeds from the monetization program were used to repay credit facility borrowings. The monetization program was tax-efficient due to the utilization of a portion of Antero's $1.6 billion of net operating losses. Antero Resources' stand-alone E&P net debt to last twelve months stand-alone adjusted EBITDAX ratio was 2.6x and its consolidated net debt to last twelve months consolidated adjusted EBITDAX ratio was 3.0x as of September 30, 2017, a reduction of 0.4x and 0.6x, respectively, as compared to June 30, 2017. For a description of stand-alone E&P net debt and Adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
New Credit Facility Agreement
Antero has entered into a new upstream credit facility with a borrowing base of $4.5 billion and lender commitments of $2.5 billion. The $4.5 billion borrowing base under the credit facility represents a $250 million reduction from the Company's previous borrowing base of $4.75 billion net of the $750 million hedge monetization executed in September 2017. Lender commitments were reduced by $1.5 billion from the previous commitments of $4.0 billion. The decision to materially reduce lender commitments reflects Antero's current essentially undrawn balance on its facility and its plan to primarily fund its drilling program with cash flow from operations. The new credit facility matures in October 2022, subject to certain exceptions, and includes fall away covenants that are triggered if and when Antero is assigned an investment grade credit rating by the rating agencies. The credit facility is supported by a bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A. The bank syndicate is comprised of 24 banks, 23 of which were lenders in the prior credit facility.
Commenting on liquids exposure, the recent delevering program and the new credit facility, Glen Warren, President and CFO, said, "As the largest NGL producer in the U.S. during the third quarter, Antero continues to benefit from the significant increase in NGL pricing that has occurred over the last several months. NGL production has been a key pillar of our business strategy for a number of years and we believe that it will be a key differentiator for Antero for many years to come. The Mariner East 2 NGL pipeline project will be completed soon and export demand continues to grow. The increase in cash flow associated with our liquids-rich drilling inventory is one of the many drivers behind our decision to lower commitments on our new credit facility to $2.5 billion. The $1.5 billion reduction in commitments not only reflects the fact that we are essentially undrawn on our facility today, but is also a function of Antero's plan to primarily fund our drilling program with cash flow from operations and distributions from our ownership in Antero Midstream."
Contract Disputes
During the third quarter of 2017, Antero's realized natural gas price was negatively impacted by contract disputes with two counterparties related to two separate long-term natural gas sales agreements.
WGL's Natural Gas Sales Contract
Antero is currently contracted to sell and deliver natural gas volumes varying between 500,000 MMBtu/d and 600,000 MMBtu/d to Washington Gas Light Company, a regulated utility based in Washington, D.C. and WGL Midstream, Inc. (collectively, "WGL") at a delivery point in Braxton, West Virginia where the Stonewall Pipeline interconnects with Columbia's WB Pipeline. Beginning in April 2017, WGL failed to take delivery of a portion of the contracted sales volume in direct violation of the contract terms due to WGL's lack of downstream primary firm transportation capacity to move the purchased gas. WGL's nonperformance under the contract has resulted in Antero selling approximately 380,000 MMBtu/d, on average, of natural gas volumes that WGL was obligated to take at other regional indices at a lower price relative to the contracted price. Per its contracts, Antero has invoiced WGL for cover damages resulting from reselling the contracted natural gas at lower prices, which WGL has failed to pay. For the three months ended September 30, 2017, this has resulted in a loss of approximately $40 million net to Antero and resulted in a $(0.22)/Mcf negative impact to Antero's total company realized natural gas pricing. Year to date through September 30, 2017, cover damages net to Antero have totaled approximately $55 million. Antero will continue to vigorously seek recovery of its cover damages, as clearly defined in the contracts, and other unpaid amounts as part of its claims against WGL. Antero has not accrued for these amounts in the Company's financial statements.
As it relates to this contractual dispute, WGL and Antero have also recently been involved in two previous lawsuits related to pricing and delivery points on these contracts. In the first lawsuit, which was ultimately referred to arbitration, the arbitration panel ruled in Antero's favor and the award was confirmed by the Colorado District Court in April 2017. In the second lawsuit, the Colorado District Court dismissed with prejudice WGL's claims against Antero and found that Antero had not breached its contracts with WGL. For further information on this dispute, please see note 10 to Antero's condensed consolidated financial statements included in Antero's Form 10-Q for the period ending September 30, 2017.
South Jersey Natural Gas Sales Contract
Antero's third quarter 2017 realized gas price was also negatively impacted by an ongoing breach of contract by South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, "SJGC") related to two long term natural gas sales contracts that total 80,000 MMBtu/d. The price for natural gas sales was specifically based on the Platt's Columbia Appalachia Index outlined in the contracts. Beginning in October 2014, SJGC began short paying Antero based on price indices unilaterally selected by SJGC and not the Platt's Columbia Appalachia Index specified in the contracts. SJGC claimed that a market disruption event had occurred and, as a result, a new index price was required to be determined by the parties. Antero filed a lawsuit against SJGC in the U.S. District Court in Colorado to recover against SJGC for their breach of the contracts. In early May 2017, a jury returned a unanimous verdict finding in favor of Antero's positions in the lawsuit against SJGC. In July 2017, final judgment on the jury's unanimous verdict was entered by the court. SJGC continues to short pay the Company while it challenges the court's final judgment, resulting in approximately $7 million in damages net to Antero and a $(0.04)/Mcf negative impact to Antero's total company realized natural gas pricing for the three months ended September 30, 2017. From January 1, 2015 through September 30, 2017, damages net to Antero total approximately $47 million. Antero has not accrued for this amount in the Company's financial statements. Antero will continue to vigorously seek recovery from SJGC of all underpayments and damages, including those short payments continuing after the court's final judgment. For further information on this dispute, please see note 10 to Antero's condensed consolidated financial statements included in Antero's Form 10-Q for the period ending September 30, 2017.
In combination, the Company does not expect a material impact to its realized natural gas pricing and cash flow beyond year-end 2017 from these contractual disputes due to the start-up of the Cove Point LNG export facility expected in the first quarter of 2018, additional takeaway capacity expected to be placed in service throughout 2018, and narrower regional basis differentials based on current strip pricing.
For the third quarter and first nine months of 2017, these two disputes resulted in the following impact to Antero's realized natural gas pricing:
As Adjusted
As For WGL and Variance
South Jersey
Reported Gas Contract
Disputes
Three months ended 9/30/17
Realized Natural Gas Price ($/Mcf) $2.71 $2.97 ($0.26)
Discount to Nymex ($/Mcf) ($0.29) ($0.03) ($0.26)
Nine months ended 9/30/17
Realized Natural Gas Price ($/Mcf) $3.06 $3.18 ($0.12)
Discount to Nymex ($/Mcf) ($0.11) $0.01 ($0.12)
Revised 2017 Guidance
As a result of the two aforementioned contract disputes and the significant increase in realized NGL pricing both on an absolute basis and on a relative basis to WTI oil, Antero is revising its 2017 realized pricing guidance and is also providing new guidance for the fourth quarter of 2017.
Full Year 2017 Guidance
2017 - OLD 2017 - NEW
Realized Pricing (Unhedged) Low High Low High
Natural Gas Differential to Nymex Henry Hub ($/Mcf)(1)(2) $0.00 $0.10 $(0.15) $(0.10)
Oil Realized Price Differential to Nymex WTI Oil ($/Bbl) $(7.00) $(9.00) $(7.00) $(6.50)
C3+ NGL Price (% of Nymex WTI) (1) 50% 55% 57.5% 62.5%
4Q 2017 Guidance
4Q 2017
Realized Pricing (Unhedged) Low High
Natural Gas Premium/(Discount) to Nymex Henry Hub ($/Mcf)(1)(2) $(0.20) $(0.15)
Oil Realized Price Differential to Nymex WTI Oil ($/Bbl) $(6.00) $(5.00)
C3+ NGL Price (% of Nymex WTI) (1) 70% 75%
Consolidated Adjusted EBITDAX ($MM) (3)(4) $410 $440
(1) Based on strip pricing as of
October 27, 2017, before hedging.
(2) Includes Btu upgrade as Antero's
processed tailgate and
unprocessed dry gas production is
greater than 1000 Btu on average.
(3) Based on strip pricing as of
October 27, 2017.
(4) For a description of the non-GAAP
financial measure Adjusted
EBITDAX, please read "Non-GAAP
Financial Measures." Antero has
not included a reconciliation of
consolidated Adjusted EBITDAX to
net income for the fourth quarter
of 2017 because it cannot do so
without unreasonable effort and
any attempt to do so would be
inherently imprecise. Antero is
able to forecast interest expense
and depreciation, depletion,
amortization and accretion
expense for the fourth quarter of
2017 between a range of $63
million and $67 million and $210
million and $220 million,
respectively, each of which is a
reconciling item between Adjusted
EBITDAX and net income. However,
Antero has a significant
portfolio of commodity derivative
contracts that it does not
account for using hedge
accounting, and forecasting
unrealized (gains) losses on this
portfolio is impracticable and
imprecise due to the price
volatility of the underlying
commodities.
Third Quarter 2017 Financial and Operating Results
As of September 30, 2017, Antero owned a 53% limited partner interest in Antero Midstream. Antero Midstream's results are consolidated with Antero's results.
For the three months ended September 30, 2017, the Company reported a net loss of $135 million on a GAAP basis, or $0.43 per basic and diluted share, compared to net income of $238 million, or $0.78 per basic and $0.77 per diluted share, in the third quarter of 2016. The net loss for the third quarter of 2017 included the following items:
-- Non-cash loss on unsettled hedges of $878 million
-- Gain on hedge monetization of $750 million
-- Non-cash equity-based compensation expense of $26 million
-- Impairment of unproved properties of $41 million
-- Income tax effect of these reconciling items of $(74) million
Excluding the items detailed above, the Company's results for the third quarter of 2017 were as follows:
-- Adjusted net loss of $14 million, or $0.04 per basic and diluted share,
a 125% decrease compared to adjusted net income of $55 million in the
third quarter of 2016
-- Adjusted EBITDAX of $336 million, a 10% decrease compared to the third
quarter of 2016
Antero's net daily production for the third quarter of 2017 averaged 2,317 MMcfe/d, including a record 112,393 Bbl/d of liquids (29% liquids by volume). Third quarter 2017 production represents an organic production growth rate of 24% from the third quarter of 2016 and a 5% increase compared to the second quarter of 2017. Third quarter 2017 C3+ natural gas liquids ("NGLs") and oil production averaged 75,290 Bbl/d and 6,784 Bbl/d, respectively. Propane made up approximately 43,000 Bbl/d of the C3+ NGL production volume. Ethane (C2) production averaged 30,319 Bbl/d while leaving approximately 124,000 Bbl/d of ethane in the natural gas stream. Total liquids production of 112,393 Bbl/d for the third quarter of 2017 represents an organic production growth rate of 38% and 9% as compared to the third quarter of 2016 and second quarter of 2017, respectively. Liquids revenues made up approximately 38% of total product revenues during the third quarter of 2017, an increase from 25% of total product revenues during the prior year quarter.
Antero's average natural gas price before hedging decreased by 5% from the prior year quarter to $2.71 per Mcf, a $0.29 differential to the average Nymex natural gas price for the period. Excluding the $(0.26) negative impact from the aforementioned natural gas contract disputes, Antero's average natural gas price before hedging would have been $2.97 per Mcf, a $0.03 negative differential to the average Nymex natural gas price for the period. Antero's average realized natural gas price after hedging for the third quarter of 2017 was $3.37 per Mcf, a $0.37 premium to the Nymex average natural gas price for the period, and a 22% decrease compared to the prior year quarter. During the third quarter, Antero realized a cash settled natural gas hedge gain of $100 million on swaps that matured during the quarter, or $0.66 per Mcf compared to $184 million, or $1.44 per Mcf in the prior year quarter.
The Company's average realized C3+ NGL price before hedging for the third quarter of 2017 was $28.92 per barrel, or 60% of the average Nymex WTI oil price, which represents a 65% increase as compared to the prior year quarter. Further, the Company's average realized C3+ price was $33.23 per barrel ($0.79 per gallon) for the month of September as NGL prices improved throughout the third quarter. The improvement in realized C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing driven by exports combined with an improvement in local differentials. During the quarter, Antero realized a cash settled C3+ NGL hedge loss of $40 million, or $5.77 per barrel. Antero's average realized C3+ NGL price including hedges was $23.15 per barrel, a 16% increase compared to the third quarter of 2016. The Company's average realized ethane price before hedging for the third quarter of 2017 was $0.21 per gallon, or $8.68 per barrel. During the quarter, Antero realized a cash settled ethane hedge loss of $0.4 million, or $0.15 per barrel. Antero's average realized ethane price including hedges for the third quarter of 2017 was $0.20 per gallon, or $8.53 per barrel. The average realized oil price before hedging was $42.50 per barrel, a $5.66 differential to Nymex WTI for the period and a 22% increase as compared to the third quarter of 2016. Antero's average realized oil price including hedges was $45.40 per barrel, a $2.76 differential to Nymex WTI for the period. During the quarter, Antero realized a cash settled hedge gain on oil of $2 million, or $2.90 per barrel.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by $0.28 to $3.10 per Mcfe. Liquids production increased equivalent pricing for dry gas by $0.39 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 14% to $3.39 per Mcfe compared to the prior year quarter. For the third quarter of 2017, Antero realized a total cash settled hedge gain on all products of $61 million, or $0.29 per Mcfe.
Total operating revenue for the third quarter of 2017 was $648 million as compared to $1.1 billion for the third quarter of 2016. Operating revenue for the third quarter of 2017 included an $878 million non-cash loss on unsettled hedges, while the third quarter of 2016 included a $334 million non-cash gain on unsettled hedges. The non-cash loss on unsettled hedges was primarily driven by the $750 million hedge monetization where Antero reduced the average fixed index price on some of its 2018 through 2022 natural gas hedges while maintaining the total volume hedged. Liquids production contributed 38% of total product revenues before hedges in the third quarter of 2017 as compared to 25% in the prior year quarter. For a reconciliation of revenue excluding unrealized hedge (gains) losses to operating revenue, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Marketing revenue for the third quarter of 2017 was $51 million. Antero's marketing revenue was primarily associated with the sale of third party gas purchased to utilize the Company's excess firm transportation capacity on the Tennessee, Columbia Gas and Rockies Express Pipelines. Marketing expense for the third quarter of 2017 was $79 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $28 million, or $0.13 per Mcfe, for the third quarter of 2017, representing a $0.03 per Mcfe increase from the third quarter of 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the third quarter of 2017 was $1.54 per Mcfe, which was in line with the prior year quarter. The per unit cash production expense for the quarter included $0.11 per Mcfe for lease operating costs, $1.32 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes. Per unit general and administrative expense for the third quarter of 2017, excluding non-cash equity-based compensation expense, was $0.17 per Mcfe, a 6% decrease from the third quarter of 2016, driven by a 24% increase in production. Per unit depreciation, depletion and amortization expense decreased 16% from the prior year quarter to $0.97 per Mcfe, primarily driven by increases in our estimated recoverable reserves, improved well performance, and decreases in our per-unit development costs. For the Marcellus alone, per unit depreciation, depletion and amortization expense also decreased 16% from the prior year quarter to $0.83 per Mcfe.
Adjusted EBITDAX of $336 million for the third quarter of 2017 represents a 10% decrease compared to the prior year quarter. Adjusted EBITDAX does not include $750 million of realized gains from the partial monetization of certain natural gas hedges or $47 million impact from the natural gas contract disputes. Adjusted EBITDAX margin for the quarter was $1.58 per Mcfe, representing a 27% decrease from the prior year quarter. For the third quarter of 2017, cash flow from operations was $1.0 billion, a 220% increase from the prior year quarter. Cash flow from operations before changes in working capital was $1.0 billion, a 228% increase from the third quarter of 2016.
Adjusted EBITDAX is a non-GAAP financial measure. For a description of Adjusted EBITDAX, Adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended September 30, 2017:
Three Months Ended
September 30, 2017
------------------
Gas Oil C3+ NGLs Ethane Combined
(MMcf/d) (Bbl/d) (Bbl/d) (Bbl/d) Gas
Equivalent
(MMcfe/d)
---------
Average Net
Production 1,643 6,784 75,290 30,319 2,317
Gas Oil C3+ NGLs Ethane Combined
($/Mcf) ($/Bbl) ($/Bbl) ($/Bbl) Gas
Equivalent
($/Mcfe)
--------
Average Realized
Prices
Average realized
price before
settled
derivatives $2.71 $42.50 $28.92 $8.68 $3.10
Settled
derivatives 0.66 2.90 (5.77) (0.15) 0.29
---- ---- ----- ----- ----
Average realized
price after
settled
derivatives $3.37 $45.40 $23.15 $8.53 $3.39
===== ====== ====== ===== =====
Nymex average
price $3.00 $48.16 $3.00
----- ------ -----
Premium /
(Differential)
to Nymex $0.37 $(2.76) $0.39
===== ====== =====
Marcellus Shale -- Antero completed and placed on line 31 horizontal Marcellus wells during the third quarter of 2017 with an average lateral length of 9,500 feet. During the period, Antero drilled an average of 4,884 lateral feet per day, which represents a 42% increase compared to 2016. Out of the 31 wells completed in the third quarter, 25 have been on line for more than 30 days and had an average 30-day rate on choke of 17 MMcfe/d (17% liquids), assuming 25% ethane recovery.
Current average well costs are $0.91 million per 1,000 feet of lateral in the Marcellus assuming a 2,000 pounds of proppant per foot completion. Average drilling days from spud to final rig release was 12 days in the third quarter of 2017, a 20% reduction from 2016. Antero is currently operating five drilling rigs and three completion crews in the Marcellus Shale.
In early July 2017, Antero drilled its longest laterals to date in the Marcellus, with three laterals averaging 14,000 feet. These wells are expected to be completed during the fourth quarter of 2017 and placed to sales in the first quarter of 2018. Additionally, Antero completed a four-well pad using 2,500 pounds of proppant per foot and with an average lateral of 11,100 feet, that had a 90-day rate of 20 MMcfe/d per well including 921 Bbl/d of NGLs and 31 Bbl/d of oil, and an unprocessed EUR of approximately 2.2 Bcf/1,000' (2.7 Bcfe/1,000' assuming 25% ethane recovery). Antero also put to sales another four-well pilot pad that was completed using 2,500 pounds of proppant per foot and had an average lateral of 5,400 feet. The pad delivered an average 90-day rate of 12 MMcfe/d per well including 438 Bbl/d of NGLs and an unprocessed EUR of approximately 2.3 Bcf/1,000' (2.8 Bcfe/1,000' assuming 25% ethane recovery).
Furthermore, in the first quarter of 2017, Antero completed a four-well pad using 2,000 pounds of proppant per foot and with an average lateral length of 11,100 feet, that had a 90-day rate of 22.4 MMcfe/d per well (30% liquids) and an unprocessed EUR of approximately 2.2 Bcf/1,000' (2.6 Bcfe/1,000' assuming 25% ethane recovery). This pad included a 14,000 foot lateral that had a 90-day rate of 27.1 MMcfe/d (30% liquids).
Ohio Utica Shale - Antero completed and placed on line six horizontal Utica wells during the third quarter of 2017 with an average lateral length of approximately 9,600 feet. During the period, Antero drilled four 17,000' laterals and set a record for drilling its longest lateral to date at 17,445 feet. This lateral was drilled within a 7 foot target zone and was drilled in five days. The wells are expected to be placed to sales in the second quarter of 2018.
Current average well costs are $0.99 million per 1,000 feet of lateral in the Ohio Utica assuming a 2,000 pounds of proppant per foot completion. Antero is currently operating one drilling rig and one completion crew in the Utica Shale. Upon Rover phase 1B being placed in service, Antero expects to turn in line two dry focused Ohio Utica pads that total ten wells.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
For the three months ended September 30, 2017, Antero Midstream reported revenues of $194 million, comprised of $101 million from the Gathering and Processing segment and $93 million from the Water Handling and Treatment segment. Revenues increased 29% compared to the prior year quarter, driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $45 million from wastewater handling and high rate water transfer services provided to Antero Resources, which is billed at cost plus 3%.
Direct operating expenses for the Gathering and Processing and Water Handling and Treatment segments were $11 million and $52 million, respectively, for a total of $63 million compared to $33 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $44 million from produced water handling and high rate water transfer services. General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the third quarter of 2016. General and administrative expenses excluding equity-based compensation were $7 million during the third quarter of 2017, in line with the third quarter of 2016. Total operating expenses were $111 million, including $31 million of depreciation and $3 million of accretion of contingent acquisition consideration.
Net income for the third quarter of 2017 was $81 million, a 15% increase compared to the prior year quarter. Net income per limited partner unit was $0.33 per unit, an 11% decrease compared to the prior year quarter. Adjusted EBITDA was $128 million, a 16% increase compared to the prior year quarter. The increase in net income and Adjusted EBITDA is primarily driven by increased throughput and fresh water delivery volumes. Adjusted EBITDA for the quarter included $4 million in distributions from Stonewall Gathering LLC ("Stonewall") and the processing and fractionation joint venture. Cash interest paid was $21 million. Decrease in cash reserved for bond interest during the quarter decreased $9 million and cash reserved for payment of income tax withholding upon vesting of Antero Midstream equity-based compensation awards was $2 million. Maintenance capital expenditures during the quarter totaled $11 million and distributable cash flow was $104 million, resulting in a DCF coverage ratio of 1.3x.
Antero Midstream Distribution
The Board of Directors of Antero Midstream Partners GP LLC, the general partner of Antero Midstream, declared a cash distribution of $0.34 per unit ($1.36 per unit annualized) for the third quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 6% increase sequentially. The distribution is Antero Midstream's eleventh consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on November 16, 2017 to unitholders of record as of November 1, 2017.
Stand-alone Balance Sheet and Liquidity
As of September 30, 2017, Antero's stand-alone total debt and net debt were $3.4 billion, of which $25 million were borrowings outstanding under the Company's revolving credit facility. Total lender commitments under the new upstream credit facility are $2.5 billion. Reduced for $700 million in letters of credit outstanding, the company had $1.8 billion in available stand-alone liquidity as of September 30, 2017. Antero Resources' stand-alone E&P net debt to last twelve months adjusted EBITDAX ratio was 2.6x as of September 30, 2017. For a reconciliation of stand-alone net debt to stand-alone total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Consolidated Balance Sheet and Liquidity
As of September 30, 2017, Antero's consolidated total debt and net debt was $4.5 billion, of which $452 million were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two new facilities is now $4.0 billion. Reduced for $700 million in letters of credit outstanding, the company had $2.9 billion in available consolidated liquidity as of September 30, 2017. Antero Resources' consolidated net debt to last twelve months consolidated Adjusted EBITDAX ratio was 3.0x as of September 30, 2017. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Third Quarter 2017 Capital Spending
Antero's drilling and completion costs for the three months ended September 30, 2017 were $317 million. In addition, the Company invested $52 million for land. Antero Midstream invested $99 million for gathering and compression systems and $48 million for water infrastructure projects, including $33 million on the Antero Clearwater Treatment Facility. Investments in unconsolidated affiliates for Antero Midstream's processing and fractionation joint venture were $26 million during the quarter.
Hedge Position
Antero currently has hedged 2.9 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from October 1, 2017 through December 31, 2023 at an average index price of $3.36 per MMBtu. At September 30, 2017, the Company's estimated fair value of commodity derivative instruments was $1.2 billion.
The following table summarizes Antero's hedge position as of September 30, 2017:
Period Natural Gas Average Liquids Average
MMBtu/d Index price Bbl/d Index price
($/MMBtu)
--- ---------
4Q 2017:
--------
Nymex Henry Hub 1,370,000 $3.46 - -
CGTLA 420,000 $4.37 - -
Chicago 70,000 $4.68 - -
Propane MB ($/Gal) - - 27,500 $0.40
Ethane MB ($/Gal) - - 20,000 $0.25
Nymex WTI ($/Bbl) - - 3,000 $54.75
----------------- --- --- ----- ------
Total 1,860,000 $3.71 50,500 N/A (1)
2018:
-----
Nymex Henry Hub 2,002,500 $3.50 - -
Propane MB ($/Gal) - - 3,000 $0.67
Nymex WTI ($/Bbl) - - 1,000 49.96
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 2017 liquids
hedges include propane,
ethane and oil hedges.
Conference Call
A conference call is scheduled on Thursday, November 2, 2017 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 Friday, November 10, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10111894.
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 Friday, November 10, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the November 2, 2017 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 hedge (gains) losses as set forth in this release represents total operating revenue adjusted for non-cash (gains) losses on unsettled hedges. Antero believes that revenue excluding unrealized hedge (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 hedge (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 hedge (gains) losses (in thousands):
Three months ended Nine months ended
September 30, September 30,
------------- -------------
2016 2017 2016 2017
---- ----
Total
operating
revenue $1,116,503 $647,880 $1,588,309 $2,633,848
Hedge (gains)
losses (530,334) 65,957 (125,624) (458,459)
Cash receipts
for settled
hedges 196,712 61,479 813,559 137,392
------- -------
Revenue
excluding
unrealized
hedge
(gains)
losses $782,881 $775,316 $2,276,244 $2,312,781
======== ======== ========== ==========
Adjusted net income (loss) as set forth in this release represents net income (loss), 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) 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 table reconciles net income (loss) to adjusted net income (loss) (in thousands):
Three months ended Nine months ended
September 30, September 30,
------------- -------------
2016 2017 2016 2017
---- ---- ---- ----
Net income (loss) $238,255 $(135,063) $(363,044) $128,201
Hedge (gains) losses (530,334) 65,957 (125,624) (458,459)
Cash receipts for settled hedges 196,712 61,479 813,559 137,392
Impairment of unproved properties 11,753 41,000 47,223 83,098
Equity-based compensation 26,381 26,447 75,667 78,925
Income tax effect of reconciling
items 112,490 (73,735) (308,675) 60,175
------- ------- -------- ------
Adjusted net income (loss) $55,257 $(13,915) $139,106 $29,332
======= ======== ======== =======
Cash flow from operations before changes in working capital as presented in this release represents net cash provided by operating activities before changes in working capital items. Cash flow from operations before changes in working capital 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. Cash flow from operations before changes in working capital 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. Cash flow from operations before changes in working capital 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 cash flow from operations before changes in working capital as used in this release (in thousands):
Three months ended Nine months ended
September 30, September 30,
------------- -------------
2016 2017 2016 2017
---- ---- ---- ----
Net cash provided by
operating activities $326,991 $1,045,222 $905,697 $1,692,808
Net change in working
capital (17,327) (29,899) (35,939) (130,089)
------- ------- ------- --------
Cash flow from operations
before changes in working
capital $309,664 $1,015,323 $869,758 $1,562,719
======== ========== ======== ==========
The following table reconciles total debt to net debt on a consolidated basis and a stand-alone E&P basis (in thousands):
December 31, September 30,
------------ -------------
2016 2017
---- ----
AR Bank credit
facility $440,000 $25,000
AM Bank credit
facility 210,000 427,000
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
AR net unamortized
premium 1,749 1,588
AR net unamortized
debt issuance
costs (37,690) (33,789)
AM net unamortized
debt issuance
costs (10,086) (9,278)
------- ------
Consolidated total
debt $4,703,973 $4,510,521
Less: AR cash and
cash equivalents 17,568 21,199
Less: AM cash and
cash equivalents 14,042 2,495
------ -----
Consolidated net
debt $4,672,363 $4,486,827
---------- ----------
Stand-alone E&P
net debt $3,836,491 $3,421,600
========== ==========
Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income from continuing operations including noncontrolling interest after adjusting for those items shown in the table below. Adjusted EBITDAX, as used and defined by the Company, 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, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding a company's capital structure, borrowings, interest costs, capital expenditures, and 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, franchise taxes, exploration expenses, and other commitments and obligations. However, Antero's management team believes Adjusted EBITDAX is useful to an investor in evaluating the Company's financial performance because this measure:
-- is 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 from period to period by removing the effect of its
capital structure from its operating structure; and
-- is used by the Company's management team for various purposes, including
as a measure of operating performance, in presentations to its Board of
Directors, as a basis for strategic planning and forecasting. Adjusted
EBITDAX is also used by our 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 as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect Antero's net income, 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 tables represent a reconciliation of the Company's net income (loss) from continuing operations including noncontrolling interest to Adjusted EBITDAX, a reconciliation of Adjusted EBITDAX to net cash provided by operating activities and a reconciliation of realized price before cash receipts for settled hedges to Adjusted EBITDAX margin (in thousands except Adjusted EBITDAX margin).
Three months ended Nine months ended
September 30, September 30,
-------------
2016 2017 2016 2017
---- ---- ---- ----
Net income (loss) including
noncontrolling interest $268,196 $(90,000) $(296,644) $255,523
Commodity derivative (gains) losses (530,334) 65,957 (125,624) (458,459)
Gains on settled derivative instruments 196,712 61,479 813,559 137,392
Interest expense 59,755 70,059 185,634 205,311
Income tax expense (benefit) 140,924 (45,078) (230,755) 105,087
Depreciation, depletion, amortization, and
accretion 199,741 207,626 589,903 612,823
Impairment of unproved properties 11,753 41,000 47,223 83,098
Exploration expense 1,166 1,599 3,289 5,510
Equity-based compensation expense 26,381 26,447 75,667 78,925
Equity in earnings of unconsolidated affiliate (1,543) (7,033) (2,027) (12,887)
Distributions from unconsolidated affiliates - 4,300 - 10,120
State franchise taxes - - 39 -
Consolidated Adjusted EBITDAX 372,751 336,356 1,060,264 1,022,443
Interest expense (59,755) (70,059) (185,634) (205,311)
Exploration expense (1,166) (1,599) (3,289) (5,510)
Changes in current assets and liabilities 17,327 29,899 35,939 130,089
State franchise taxes - - (39) -
Proceeds from derivative monetization - 749,906 - 749,906
Other non-cash items (2,166) 719 (1,544) 1,191
------ --- ------ -----
Net cash provided by
operating activities $326,991 $1,045,222 $905,697 $1,692,808
======== ========== ======== ==========
Three months ended Nine months ended
September 30, September 30,
------------- -------------
Adjusted EBITDAX margin ($ per Mcfe): 2016 2017 2016 2017
---- ---- ---- ----
Realized price before cash receipts for settled hedges $2.82 $3.10 $2.36 $3.30
Gathering, compression, water handling and treatment revenues 0.01 0.01 0.03 0.01
Distributions from unconsolidated affiliates - 0.02 - 0.02
Lease operating expense (0.08) (0.11) (0.08) (0.09)
Gathering, compression, processing and transportation costs (1.36) (1.32) (1.32) (1.35)
Marketing, net (0.10) (0.13) (0.19) (0.13)
Production taxes (0.09) (0.11) (0.11) (0.12)
General and administrative(1) (0.18) (0.17) (0.20) (0.18)
----- ----- ----- -----
Adjusted EBITDAX margin before settled hedges $1.02 $1.29 $0.49 $1.46
----- ----- ----- -----
Cash receipts for settled hedges 1.14 0.29 1.66 0.23
---- ---- ---- ----
Adjusted EBITDAX margin ($ per Mcfe): $2.16 $1.58 $2.15 $1.69
===== ===== ===== =====
(1) Excludes equity-based stock
compensation
The following table reconciles Antero's consolidated net income to consolidated Adjusted EBITDAX for the twelve months ending September 30, 2017 as used in this release (in thousands):
Twelve months ended
September 30,
-------------
2017
----
Net loss including noncontrolling interest $(197,281)
Commodity derivative losses 181,346
Net cash receipts on settled derivative
instruments 326,916
Gain on sale of assets (97,635)
Interest expense 273,229
Loss on early extinguishment of debt 16,956
Income tax benefit (160,534)
Depreciation, depletion, amortization and
accretion 835,266
Impairment of unproved properties 198,810
Exploration expense 9,083
Equity-based compensation expense 105,679
Equity in earnings of unconsolidated
affiliates (11,345)
Distributions from unconsolidated
affiliates 17,822
State franchise taxes 11
Total Adjusted EBITDAX $1,498,323
==========
"Stand-alone E&P Adjusted EBITDAX" is also used by our management team for various purposes, including as a measure of operating performance of our exploration and production and marketing segments and as a basis for strategic planning and forecasting. Stand-alone E&P Adjusted EBITDAX is a non-GAAP financial measure that we define as operating income or loss before derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units. Operating income or loss represents net income or loss, including noncontrolling interests, before interest expense and interest income, income taxes, and equity in earnings of unconsolidated affiliates. Operating income is the most directly comparable GAAP financial measure to Stand-alone E&P Adjusted EBITDAX because we do not account for income tax expense or interest expense on a segment basis.
The following table reconciles operating income to total Adjusted EBITDAX on a stand-alone E&P basis. Stand-alone E&P basis includes operations from both the exploration and production segment and marketing segment (in thousands):
Twelve months ended
September 30,
-------------
2017
----
Stand-alone E&P operating loss $(235,777)
Commodity derivative gains 181,346
Net cash receipts on settled derivatives instruments 326,916
Depreciation, depletion, amortization and accretion 719,999
Impairment of unproved properties 198,810
Exploration expense 9,083
Change in fair value of contingent acquisition
consideration (15,777)
Equity-based compensation expense 78,560
Gain on sale of assets (93,776)
State franchise taxes 11
Distributions from limited partner interest in
Antero Midstream 126,833
Stand-alone E&P Adjusted EBITDAX $1,296,228
The following table reconciles Antero Midstream's net income to Adjusted EBITDA and distributable cash flow as used in this release (in thousands):
Three months ended
September 30,
2016 2017
---- ----
Net income $70,524 $80,893
Interest expense 5,303 9,311
Depreciation expense 26,136 30,556
Accretion of contingent
acquisition consideration 3,527 2,556
Equity-based compensation 6,599 7,199
Equity in earnings of
unconsolidated affiliates (1,544) (7,033)
Distributions from
unconsolidated affiliates - 4,300
Adjusted EBITDA $110,545 $127,782
-------- --------
Interest paid (4,043) (20,554)
Decrease in cash reserved
for bond interest (1) - 8,831
Cash reserved for payment of
income tax withholding upon
vesting of Antero Midstream
Partners LP equity-based
compensation awards(2) (1,000) (1,500)
Cash distribution to be
received from
unconsolidated affiliate 2,221 -
Maintenance capital
expenditures(3) (4,638) (10,771)
------ -------
Distributable cash flow $103,085 $103,788
======== ========
Distributions Declared to
Antero Midstream Holders
Limited Partners $47,025 $63,454
Incentive distribution
rights 4,820 19,067
----- ------
Total Aggregate
Distributions $51,845 $82,521
------- -------
DCF coverage ratio 2.0x 1.3x
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 the Company expects, believes or anticipates will or may occur in the future, such as those regarding future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas and natural gas liquids prices, acreage quality, access to multiple gas markets, expected drilling and development plans, 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 Company'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, 2016.
ANTERO RESOURCES CORPORATION
Condensed Consolidated Balance Sheets
December 31, 2016 and September 30, 2017
(unaudited)
(In thousands, except per share amounts)
December 31, 2016 September 30, 2017
----------------- ------------------
Assets
Current assets:
Cash and cash equivalents $31,610 23,694
Accounts receivable, net of allowance for doubtful
accounts of $1,195 and $1,320 at December 31, 2016
and September 30, 2017, respectively 29,682 43,854
Accrued revenue 261,960 233,585
Derivative instruments 73,022 299,796
Other current assets 6,313 10,024
----- ------
Total current assets 402,587 610,953
------- -------
Property and equipment:
Natural gas properties, at cost (successful efforts
method):
Unproved properties 2,331,173 2,305,749
Proved properties 9,549,671 10,779,043
Water handling and treatment systems 744,682 891,869
Gathering systems and facilities 1,723,768 1,977,510
Other property and equipment 41,231 54,571
------ ------
14,390,525 16,008,742
Less accumulated depletion, depreciation, and
amortization (2,363,778) (2,973,544)
---------- ----------
Property and equipment, net 12,026,747 13,035,198
---------- ----------
Derivative instruments 1,731,063 876,293
Investments in unconsolidated affiliates 68,299 287,842
Other assets 26,854 38,928
------ ------
Total assets $14,255,550 14,849,214
=========== ==========
Liabilities and Equity
Current liabilities:
Accounts payable $38,627 47,457
Accrued liabilities 393,803 429,696
Revenue distributions payable 163,989 220,971
Derivative instruments 203,635 4,285
Other current liabilities 17,334 15,267
------ ------
Total current liabilities 817,388 717,676
Long-term liabilities:
Long-term debt 4,703,973 4,510,521
Deferred income tax liability 950,217 1,180,564
Derivative instruments 234 427
Other liabilities 55,160 52,764
------ ------
Total liabilities 6,526,972 6,461,952
--------- ---------
Commitments and contingencies
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; 314,877 shares and 315,470
shares issued and outstanding at December 31, 2016
and September 30, 2017, respectively 3,149 3,155
Additional paid-in capital 5,299,481 6,564,320
Accumulated earnings 959,995 1,088,196
------- ---------
Total stockholders' equity 6,262,625 7,655,671
Noncontrolling interests in consolidated subsidiary 1,465,953 731,591
--------- -------
Total equity 7,728,578 8,387,262
--------- ---------
Total liabilities and equity $14,255,550 14,849,214
=========== ==========
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
Three Months Ended September 30, 2016 and 2017
(unaudited)
(In thousands, except per share amounts)
Three Months Ended
September 30,
-------------
2016 2017
---- ----
Revenue:
Natural gas sales $364,373 409,141
Natural gas liquids sales 106,958 224,533
Oil sales 14,793 26,527
Gathering, compression, water handling and treatment 2,969 2,869
Marketing 97,076 50,767
Commodity derivative fair value gains (losses) 530,334 (65,957)
------- -------
Total revenue 1,116,503 647,880
--------- -------
Operating expenses:
Lease operating 13,854 23,491
Gathering, compression, processing, and transportation 234,915 282,134
Production and ad valorem taxes 15,554 22,995
Marketing 114,611 78,884
Exploration 1,166 1,599
Impairment of unproved properties 11,753 41,000
Depletion, depreciation, and amortization 199,113 206,968
Accretion of asset retirement obligations 628 658
General and administrative (including equity-based compensation expense of $26,381 and $26,447 in 2016 and 2017,
respectively) 57,577 62,203
------ ------
Total operating expenses 649,171 719,932
------- -------
Operating income (loss) 467,332 (72,052)
------- -------
Other income (expenses):
Equity in earnings of unconsolidated affiliates 1,543 7,033
Interest (59,755) (70,059)
------- -------
Total other expenses (58,212) (63,026)
------- -------
Income (loss) before income taxes 409,120 (135,078)
Provision for income tax (expense) benefit (140,924) 45,078
-------- ------
Net income (loss) and comprehensive income (loss) including noncontrolling interests 268,196 (90,000)
Net income and comprehensive income attributable to noncontrolling interests 29,941 45,063
------ ------
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $238,255 (135,063)
======== ========
Earnings (loss) per common share-basic $0.78 (0.43)
Earnings (loss) per common share-assuming dilution $0.77 (0.43)
Weighted average number of shares outstanding:
Basic 306,785 315,463
Diluted 308,657 315,463
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
Nine Months Ended September 30, 2016 and 2017
(unaudited)
(In thousands, except per share amounts)
Nine Months Ended
September 30,
-------------
2016 2017
---- ----
Revenue and other:
Natural gas sales $848,936 1,330,062
Natural gas liquids sales 274,736 590,004
Oil sales 41,712 79,999
Gathering, compression, water handling and treatment 10,107 8,665
Marketing 287,194 166,659
Commodity derivative fair value gains 125,624 458,459
------- -------
Total revenue and other 1,588,309 2,633,848
--------- ---------
Operating expenses:
Lease operating 37,190 56,034
Gathering, compression, processing, and transportation 649,713 815,710
Production and ad valorem taxes 52,296 70,341
Marketing 378,521 246,298
Exploration 3,289 5,510
Impairment of unproved properties 47,223 83,098
Depletion, depreciation, and amortization 588,057 610,879
Accretion of asset retirement obligations 1,846 1,944
General and administrative (including equity-based compensation expense of $75,667 and $78,925 in 2016 and 2017,
respectively) 173,966 191,000
------- -------
Total operating expenses 1,932,101 2,080,814
--------- ---------
Operating income (loss) (343,792) 553,034
-------- -------
Other income (expenses):
Equity in earnings of unconsolidated affiliates 2,027 12,887
Interest (185,634) (205,311)
-------- --------
Total other expenses (183,607) (192,424)
-------- --------
Income (loss) before income taxes (527,399) 360,610
Provision for income tax (expense) benefit 230,755 (105,087)
------- --------
Net income (loss) and comprehensive income (loss) including noncontrolling interests (296,644) 255,523
Net income and comprehensive income attributable to noncontrolling interests 66,400 127,322
------ -------
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation $(363,044) 128,201
========= =======
Earnings (loss) per common share-basic $(1.26) 0.41
Earnings (loss) per common share-assuming dilution $(1.26) 0.41
Weighted average number of shares outstanding:
Basic 288,607 315,275
Diluted 288,607 316,140
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Cash Flows
Nine Months Ended September 30, 2016 and 2017
(Unaudited)
(In thousands)
Nine Months Ended September 30,
-------------------------------
2016 2017
---- ----
Cash flows from operating activities:
Net income (loss) including noncontrolling interests $(296,644) 255,523
Adjustment to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion 589,903 612,823
Impairment of unproved properties 47,223 83,098
Derivative fair value gains (125,624) (458,459)
Gains on settled derivatives 813,559 137,392
Proceeds from derivative monetizations - 749,906
Deferred income tax expense (benefit) (230,755) 105,087
Equity-based compensation expense 75,667 78,925
Equity in earnings of unconsolidated affiliates (2,027) (12,887)
Distributions of earnings from unconsolidated affiliates - 10,120
Other (1,544) 1,191
Changes in current assets and liabilities:
Accounts receivable 10,077 1,771
Accrued revenue (68,248) 28,375
Other current assets 4,685 (3,836)
Accounts payable 5,683 4,731
Accrued liabilities 41,386 43,043
Revenue distributions payable 42,253 56,982
Other current liabilities 103 (977)
--- ----
Net cash provided by operating activities 905,697 1,692,808
------- ---------
Cash flows used in investing activities:
Additions to proved properties (64,789) (179,318)
Additions to unproved properties (559,572) (182,207)
Drilling and completion costs (1,009,851) (946,508)
Additions to water handling and treatment systems (137,355) (143,470)
Additions to gathering systems and facilities (154,136) (254,619)
Additions to other property and equipment (1,747) (11,417)
Investments in unconsolidated affiliates (45,044) (216,776)
Change in other assets (2,173) (16,148)
Other - 2,156
--- -----
Net cash used in investing activities (1,974,667) (1,948,307)
---------- ----------
Cash flows from financing activities:
Issuance of common stock 837,414 -
Issuance of common units by Antero Midstream Partners LP 19,605 248,949
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation 178,000 311,100
Issuance of senior notes 650,000 -
Repayments on bank credit facilities, net (552,000) (198,000)
Payments of deferred financing costs (9,029) -
Distributions to noncontrolling interests in consolidated subsidiary (51,238) (102,053)
Employee tax withholding for settlement of equity compensation awards (4,876) (8,500)
Other (3,867) (3,913)
------ ------
Net cash provided by financing activities 1,064,009 247,583
--------- -------
Net decrease in cash and cash equivalents (4,961) (7,916)
Cash and cash equivalents, beginning of period 23,473 31,610
------ ------
Cash and cash equivalents, end of period $18,512 23,694
======= ======
Supplemental disclosure of cash flow information:
Cash paid during the period for interest $132,928 174,324
Supplemental disclosure of noncash investing activities:
Decrease in accounts payable and accrued liabilities for additions to property and equipment $(189,234) (3,084)
The following tables set forth selected consolidated operating data for the three months ended September 30, 2016 compared to the three months ended September 30, 2017:
Three Months Ended September Amount of Percent
30, Increase
---
(in thousands) 2016 2017 (Decrease) Change
------------- ---- ---- --------- ------
Operating revenues and other:
Natural gas sales $364,373 $409,141 $44,768 12%
NGLs sales 106,958 224,533 117,575 110%
Oil sales 14,793 26,527 11,734 79%
Gathering, compression, water handling
and treatment 2,969 2,869 (100) (3)%
Marketing 97,076 50,767 (46,309) (48)%
Commodity derivative fair value gains
(losses) 530,334 (65,957) (596,291) *
------- ------- --------
Total operating revenues and other 1,116,503 647,880 (468,623) (42)%
--------- ------- --------
Operating expenses:
Lease operating 13,854 23,491 9,637 70%
Gathering, compression, processing, and
transportation 234,915 282,134 47,219 20%
Production and ad valorem taxes 15,554 22,995 7,441 48%
Marketing 114,611 78,884 (35,727) (31)%
Exploration 1,166 1,599 433 37%
Impairment of unproved properties 11,753 41,000 29,247 249%
Depletion, depreciation, and
amortization 199,113 206,968 7,855 4%
Accretion of asset retirement
obligations 628 658 30 5%
General and administrative (before
equity-based compensation) 31,196 35,756 4,560 15%
Equity-based compensation 26,381 26,447 66 - %
------ ------ ---
Total operating expenses 649,171 719,932 70,761 11%
------- ------- ------
Operating income (loss) 467,332 (72,052) (539,384) *
------- ------- --------
Other earnings (expenses):
Equity in earnings of unconsolidated
affiliate 1,543 7,033 5,490 356%
Interest expense (59,755) (70,059) (10,304) 17%
------- ------- -------
Total other expenses (58,212) (63,026) (4,814) 8%
------- ------- ------
Income (loss) before income taxes 409,120 (135,078) (544,198) *
Income tax (expense) benefit (140,924) 45,078 186,002 *
-------- ------ -------
Net income (loss) and comprehensive
income (loss) including noncontrolling
interest 268,196 (90,000) (358,196) *
Net income and comprehensive income
attributable to noncontrolling
interest 29,941 45,063 15,122 51%
------ ------ ------
Net income (loss) and comprehensive
income (loss) attributable to Antero
Resources Corporation $238,255 $(135,063) $(373,318) *
======== ========= =========
Adjusted EBITDAX (1) $372,751 $336,356 $(36,395) (10)%
======== ======== ========
Three Months Ended September Amount of Percent
30, Increase
---
2016 2017 (Decrease) Change
---- ---- --------- ------
Production data:
Natural gas (Bcf) 128 151 23 18%
C2 Ethane (MBbl) 1,801 2,789 988 55%
C3+ NGLs (MBbl) 5,270 6,927 1,657 31%
Oil (MBbl) 423 624 201 47%
Combined (Bcfe) 172 213 41 24%
Daily combined production (MMcfe/d) 1,875 2,317 442 24%
Average prices before effects of
derivative settlements(2):
Natural gas (per Mcf) $2.86 $2.71 $(0.15) (5)%
C2 Ethane (per Bbl) $8.00 $8.68 $0.68 9%
C3+ NGLs (per Bbl) $17.56 $28.92 $11.36 65%
Oil (per Bbl) $34.93 $42.50 $7.57 22%
Combined (per Mcfe) $2.82 $3.10 $0.28 10%
Average realized prices after effects
of derivative settlements(2):
Natural gas (per Mcf) $4.30 $3.37 $(0.93) (22)%
C2 Ethane (per Bbl) $8.00 $8.53 $0.53 7%
C3+ NGLs (per Bbl) $19.96 $23.15 $3.19 16%
Oil (per Bbl) $34.93 $45.40 $10.47 30%
Combined (per Mcfe) $3.96 $3.39 $(0.57) (14)%
Average Costs (per Mcfe):
Lease operating $0.08 $0.11 $0.03 38%
Gathering, compression, processing, and
transportation $1.36 $1.32 $(0.04) (3)%
Production and ad valorem taxes $0.09 $0.11 $0.02 22%
Marketing expense, net $0.10 $0.13 $0.03 30%
Depletion, depreciation, amortization,
and accretion $1.16 $0.97 $(0.19) (16)%
General and administrative (before
equity-based compensation) $0.18 $0.17 $(0.01) (6)%
(1) Please see "Non-GAAP
Financial Measures" for
a description of
Adjusted EBITDAX
(2) Calculation excludes the impact
of hedge monetization *Not meaningful or applicable
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SOURCE Antero Resources Corporation
