Antero Resources Reports Second Quarter 2017 Financial and Operational Results and Increases 2017 Production Guidance
DENVER, Aug. 2, 2017 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero" or the "Company") today released its second 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 June 30, 2017, which has been filed with the Securities and Exchange Commission (the "SEC").
Highlights Include:
-- Net daily gas equivalent production averaged a record 2,200 MMcfe/d (28%
liquids), a 25% increase over the prior year quarter
-- Achieved record 102,766 Bbl/d of liquids production, a 37% increase over
the prior year quarter
-- Raising 2017 production guidance range to 2,250 to 2,300 MMcfe/d, a 3%
increase from previous guidance range with no change to the drilling and
completion capital budget
-- Realized natural gas price of $3.15 per Mcf, a $0.03 differential to the
average Nymex natural gas price before hedging
-- Realized natural gas equivalent price of $3.41 per Mcfe including NGLs,
oil and hedges
-- GAAP net loss of $(5) million, or $(0.02) per share, compared to a net
loss of $(596) million, or $(2.12) per share, in the prior year quarter
-- Adjusted EBITDAX of $321 million, a 3% decrease compared to the prior
year quarter
-- Increased type curve for almost 600 proved undeveloped and probable
Marcellus locations from 1.7 Bcf/1,000' to approximately 2.0 Bcf/1,000'
of lateral with an average lateral length of 8,600 feet for mid-year
reserves
-- Increased mid-year 3P reserves by 14% to 53.0 Tcfe (29% liquids) from
year-end 2016
-- Pre-tax PV-10 of 3P reserves was $17.0 billion at 6/30/2017 strip
pricing, including hedges
-- Completed two laterals in the Marcellus averaging 13,700 feet of lateral
length and drilled a 17,400 foot lateral in the Ohio Utica
Recent Developments
Raising 2017 Guidance
The Company is raising its 2017 net production guidance from a range of 2,160 to 2,250 Bcfe/d to a range of 2,250 to 2,300 Bcfe/d. This represents a 3% increase from the previously announced guidance. The increase in production guidance is primarily a function of the improved recoveries Antero continues to achieve through its advanced completions. Antero's advanced completions have utilized 1,500 to 2,500 pounds of proppant per foot, averaging 2,045 pounds of proppant per foot year to date in 2017. These techniques have yielded encouraging results with initial wellhead EURs ranging from 1.9 to 2.7 Bcf per 1,000' of lateral as compared to the Company's historical 1.7 Bcf per 1,000' type curve.
While the net production guidance is being raised, there is no change to the Company's $1.3 billion drilling and completion budget for 2017 due to continued efficiency gains. Drilling efficiencies include a reduction in drilling days in the Marcellus from 15 days in 2016 to 12 days in the second quarter of 2017 despite drilling longer laterals. In the second quarter of 2017, Antero drilled an average of 5,200 lateral feet per day in the Marcellus and the Company's average completed lateral was 9,400 feet and 11,200 feet in the Marcellus and Ohio Utica, respectively. Further, the Company continues to increase pad sizes and is currently drilling both a 12-well and a 14-well pad in the Marcellus.
Year to date in 2017, Antero has placed 59 total wells to sales. Of the 54 wells Antero has completed in the Marcellus, 46, or 85%, have used greater than 1,750 pounds of proppant per foot and have generated aggregate production in excess of the Company's 2.0 Bcf/1,000' type curve target through 180 days.
The following table is a comparison of the original 2017 production guidance issued in January 2017 and the revised 2017 guidance.
Guidance 2017 - New 2017 - Previous
-------- ---------- ---------------
Low High Low High
---
Production
Net Daily Production (MMcfe/d) 2,250 2,300 2,160 2,250
Net Daily Residue Natural Gas
Production (MMcf/d) 1,650 1,675 1,625 1,675
Net Daily Liquids Production (Bbl/d) 100,000 105,000 88,500 96,500
Net Daily C3+ NGL Production (Bbl/d) 68,000 71,000 65,000 70,000
Net Daily Ethane Production (Bbl/d) 26,000 27,000 18,000 20,000
Net Daily Oil Production (Bbl/d) 6,000 7,000 5,500 6,500
Capital Expenditures ($MM)
Drilling and Completion Capital $1,300 $1,300
Land $200 $200
Mid-Year 2017 Proved and 3P Reserves
Antero announced today that internally estimated proved reserves at mid-year 2017 were 16.5 Tcfe, a 7% increase compared to estimated proved reserves at December 31, 2016. Assuming futures strip benchmark pricing and applying company-specific production weighting for Appalachian index pricing, the pre-tax present value discounted at 10% ("pre-tax PV-10") of the June 30, 2017 estimated proved reserves was $10.1 billion, including $1.7 billion of hedge value. All-in finding and development cost for proved reserve additions was $0.48 per Mcfe. Drill bit only finding and development cost for proved reserve additions was $0.47 per Mcfe. Proved developed reserves increased by 20% from year-end 2016 to 8.3 Tcfe at June 30, 2017 and the percentage of proved reserves classified as proved developed increased to 50%. The Company's proved, probable and possible ("3P") reserves at mid-year 2017 totaled 53.0 Tcfe, which represents a 14% increase compared to year-end 2016. Assuming futures strip benchmark pricing and applying the same company-specific production weighting for Appalachian index pricing, the pre-tax PV-10 of the June 30, 2017 3P reserves was $17.0 billion, including hedges. The 3P reserve figures exclude virtually all of the Company's Upper Devonian and West Virginia Utica resource.
Included in the mid-year 2017 reserves are 199 proved undeveloped and 398 probable locations that were upgraded to an approximate 2.0 Bcf/1,000' type curve from a 1.7 Bcf/1,000' type curve at year-end 2016. There are now 294 proved undeveloped locations, or 83% of the total proved undeveloped locations in the Marcellus that are booked at an approximate 2.0 Bcf/1,000' type curve. The remaining 60 Marcellus proved undeveloped locations are booked at a 1.7 Bcf/1,000' type curve.
Commenting on the continued enhanced recoveries and the impact on production and reserves, Paul Rady, Chairman and CEO, said, "We continue to see outstanding results from our advanced completions in the Marcellus that we began implementing in early 2016. In recognition of these productivity gains, our reserve engineers have now upgraded nearly 600 proved and probable drilling locations in the Marcellus from our previous 1.7 Bcf/1,000' type curve to an approximate 2.0 Bcf/1,000' type curve. The enhanced productivity from these completions combined with continued operational efficiencies has resulted in a further reduction in per unit development costs and a further increase in capital efficiency. The enhanced completions program has also resulted in a 3% increase to our production guidance without raising capital spending guidance."
Asset Acquisition
In early June of 2017, Antero closed on a 10,300 net acre Marcellus acquisition primarily located in Doddridge and Wetzel Counties, West Virginia for approximately $130 million. The acquisition included approximately 17 MMcfe/d of net equivalent production, 15 drilled but uncompleted wells with an average lateral length of 8,200 feet and one undeveloped drilling pad. Antero estimates the undeveloped properties include 418 Bcfe and 958 Bcfe of unaudited Marcellus proved reserves and 3P reserves, respectively, which were included in Antero's mid-year reserve analysis. In total, the acquisition adds 89 undeveloped 3P locations and enhances 74 existing 3P locations with incremental working interests and/or increased lateral length. The lateral length of the new or enhanced 3P locations average 8,700 feet.
Second Quarter 2017 Financial and Operating Results
As of June 30, 2017, Antero owned a 58% limited partner interest in Antero Midstream Partners LP ("Antero Midstream"). Antero Midstream's results are consolidated with Antero's results.
For the three months ended June 30, 2017, the Company reported a net loss of $5 million, or $(0.02) per basic and diluted share, compared to a net loss of $596 million, or $(2.12) per basic and diluted share, in the second quarter of 2016. The net loss for the second quarter of 2017 included the following items:
-- Non-cash gain on unsettled hedges of $55 million
-- Non-cash equity-based compensation expense of $27 million
-- Impairment of unproved properties of $15 million
-- Income tax effect of these reconciling items of $5 million
Excluding the items detailed above, the Company's results for the second quarter of 2017 were as follows:
-- Adjusted net loss of $13 million, or $(0.04) per basic and diluted
share, a 132% decrease compared to adjusted net income of $41 million in
the second quarter of 2016
-- Adjusted EBITDAX of $321 million, a 3% decrease compared to the second
quarter of 2016
For a description of adjusted net loss and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
Antero's net daily production for the second quarter of 2017 averaged 2,200 MMcfe/d, including 102,766 Bbl/d of liquids (28% liquids). Second quarter 2017 production represents an organic production growth rate of 25% from the second quarter of 2016 and a 3% increase compared to the first quarter of 2017. Second quarter 2017 C3+ natural gas liquids ("NGLs") and oil production averaged 68,026 Bbl/d and 6,738 Bbl/d, respectively. Ethane (C2) production averaged 28,003 Bbl/d while leaving approximately 91,710 Bbl/d of ethane in the natural gas stream. Total liquids production of 102,766 Bbl/d for the second quarter of 2017 represents an organic production growth rate of 37% and 4% as compared to the second quarter of 2016 and first quarter of 2017, respectively.
Commenting on capital spending and cash flow levels, Glen Warren, President and CFO, said, "Our ability to grow production 25% year-over-year while essentially holding capital spending flat speaks to our material gains in capital efficiency, especially in the face of the commodity down cycle. These gains are driven by a combination of drilling efficiencies which we have continued to achieve and the operational momentum we have been able to sustain through the downturn due to our ability to lock in volumes and pricing through our hedge book and firm transportation portfolio. Looking ahead, we expect to continue to build off this momentum as we are targeting 20% to 22% production growth in 2018 while maintaining a D&C budget at or below 2017 levels. Furthermore, we are targeting drilling and completion capital to be within discretionary cash flow in 2018."
Antero's average natural gas price before hedging increased 63% from the prior year quarter to $3.15 per Mcf, a $0.03 differential to the average Nymex natural gas price for the period. Antero's average realized natural gas price after hedging for the second quarter of 2017 was $3.53 per Mcf, a $0.35 premium to the Nymex average natural gas price for the period, and an 18% decrease compared to the prior year quarter. During the quarter, Antero realized a cash settled natural gas hedge gain of $55 million, or $0.38 per Mcf compared to $283 million, or $2.38 per Mcf in the prior year quarter.
The Company's average realized C3+ NGL price before hedging for the second quarter of 2017 was $24.14 per barrel, or 50% of the average Nymex WTI oil price, which represents a 41% increase as compared to the prior year quarter. The improvement in C3+ NGL pricing is primarily due to an increase in Mont Belvieu pricing combined with an improvement in local differentials. Antero's average realized C3+ NGL price including hedges was $19.92 per barrel, a 5% increase compared to the second quarter of 2016. The Company's average realized ethane price before hedging for the second quarter of 2017 was $0.20 per gallon, or $8.40 per barrel. Antero's average realized ethane price including hedges for the second quarter of 2017 was $0.21 per gallon, or $8.61 per barrel. The average realized oil price before hedging was $43.24 per barrel, a $5.00 differential to Nymex WTI for the period and a 23% increase as compared to the second quarter of 2016. Antero's average realized oil price including hedges was $46.12 per barrel, a $2.12 differential to Nymex WTI for the period.
Antero's average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by $1.13 to $3.26 per Mcfe. The Company's average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, decreased by 14% to $3.41 per Mcfe compared to the prior year quarter. For the second quarter of 2017, Antero realized a total cash settled hedge gain on all products of $31 million, or $0.16 per Mcfe.
Total operating revenue for the second quarter of 2017 was $790 million as compared to a $249 million loss for the second quarter of 2016. Operating revenue for the second quarter of 2017 included a $55 million non-cash gain on unsettled hedges, while the second quarter of 2016 included a $977 million non-cash loss on unsettled hedges. Revenue excluding the unrealized hedge gain for the quarter was $736 million, which was in line with the second quarter of 2016. Liquids production contributed 30% of total product revenues before hedges in the second quarter of 2017. 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 second quarter of 2017 was $50 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 second quarter of 2017 was $77 million, including costs related to excess capacity and the cost of purchasing third party gas. Net marketing expense was $27 million, or $0.14 per Mcfe, for the second quarter of 2017, representing a 36% or $0.08 per Mcfe decrease from the second quarter of 2016. The reduction in net marketing expense was primarily driven by the decrease in unutilized excess firm transportation capacity, a portion of which was assumed by a third party beginning July 1, 2016.
Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) for the second quarter of 2017 was $1.52 per Mcfe, a 3% increase compared to $1.48 per Mcfe in the prior year quarter. The increase is primarily a result of an increase in fuel costs as compared to the prior year due to higher natural gas prices. The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.33 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 second quarter of 2017, excluding non-cash equity-based compensation expense, was $0.19 per Mcfe, a 10% decrease from the second quarter of 2016, driven by a 25% increase in production. Per unit depreciation, depletion and amortization expense decreased 18% from the prior year quarter to $1.01 per Mcfe, primarily driven by increases in Antero's estimated recoverable reserves combined with decreases in its per unit development costs. For the Marcellus, per unit depreciation, depletion and amortization expense decreased 19% from the prior year quarter to $0.85 per Mcfe.
Adjusted EBITDAX of $321 million for the second quarter of 2017 represents a 3% decrease compared to the prior year quarter. Adjusted EBITDAX margin for the quarter was $1.60 per Mcfe, representing a 23% decrease from the prior year quarter, driven primarily by a reduction in gains on settled derivatives. For the second quarter of 2017, cash flow from operations was $254 million, a 6% increase from the prior year quarter. Cash flow from operations before changes in working capital was $251 million, a 7% decrease from the second quarter of 2016.
For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read "Non-GAAP Financial Measures."
The following table details the components of average net production and average realized prices for the three months ended June 30, 2017:
Three Months Ended
June 30, 2017
-------------
Gas Oil C3+ NGLs Ethane Combined
(MMcf/d) (Bbl/d) (Bbl/d) (Bbl/d) Gas
Equivalent
(MMcfe/d)
---------
Average Net Production 1,583 6,738 68,026 28,003 2,200
Gas Oil C3+ NGLs Ethane Combined
($/Bbl) ($/Bbl) Gas
($/Mcf) ($/Bbl) Equivalent
($/Mcfe)
--------
Average Realized Prices
Average realized price before settled derivatives $3.15 $43.24 $24.14 $8.40 $3.26
Settled derivatives 0.38 2.88 (4.22) 0.21 0.15
---- ---- ----- ---- ----
$3.53 $46.12 $19.92 $8.61 $3.41
Average realized price after settled derivatives
Nymex average price $3.18 $48.24 $3.18
----- ------ -----
Premium / (Differential) to Nymex $0.35 $(2.12) $0.23
===== ====== =====
Marcellus Shale -- Antero completed and placed on line 29 horizontal Marcellus wells during the second quarter of 2017 with an average lateral length of 9,380 feet. During the period, Antero drilled an average of 5,200 lateral feet per day, which represents a 50% increase compared to 2016.
Current average well costs are $0.9 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 second quarter of 2017, a 4% reduction from 2016. Antero is currently operating four drilling rigs and three completion crews in the Marcellus Shale.
In late March 2017, Antero placed two wells to sales on a pad with average lateral lengths of 13,700 feet. The 13,700' laterals each averaged 26 MMcfe/d of production in the first 30 days and have an average wellhead EUR of 2.1 Bcf/1000' and a processed EUR of 2.5 Bcfe/1,000'. The two wells have an average EUR of approximately 34 Bcfe per well.
In mid-July of 2017, the Sherwood 8 processing plant (200 MMcf/d) was placed into service. The Sherwood 8 plant is the second Antero Midstream / MPLX joint venture (the "Joint Venture") plant placed in service during the year and is already 100% utilized. The Joint Venture's next plant, Sherwood 9 (200 MMcf/d), is expected to be in service in January of 2018.
Ohio Utica Shale -- Antero completed and placed on line 5 horizontal Utica wells during the second quarter of 2017 with an average lateral length of 11,222 feet. During the period, Antero set a record for drilling its longest lateral to date at 17,380 feet. This lateral was drilled within a 7 foot target zone and was drilled in 12 days. The well is expected to be placed to sales in the third quarter of 2017.
Current average well costs are $1.0 million per 1,000 feet of lateral in the Utica. Antero is currently operating two drilling rigs and two completion crews in the Utica Shale.
Antero Midstream Financial Results
Antero Midstream results were released today and are available at www.anteromidstream.com.
Low pressure gathering volumes for the second quarter of 2017 averaged 1,683 MMcf/d, a 24% increase from the second quarter of 2016 and a 3% increase sequentially. Compression volumes for the second quarter of 2017 averaged 1,192 MMcf/d, an 81% increase from the second quarter of 2016 and a 17% increase sequentially. High pressure gathering volumes for the second quarter of 2017 averaged 1,734 MMcf/d, a 38% increase from the second quarter of 2016 and an 11% increase sequentially. The increase in gathering and compression volumes was driven by production growth from Antero Resources in Antero Midstream's area of dedication. Joint Venture processing volumes for the second quarter of 2017 averaged 216 MMcf/d and fractionation volumes averaged 4,039 Bbl/d. Fresh water delivery volumes averaged 173 MBbl/d during the quarter, a 64% increase compared to the prior year quarter and an 18% increase sequentially.
For the three months ended June 30, 2017, Antero Midstream reported revenues of $194 million, comprised of $99 million from the Gathering and Processing segment and $95 million from the Water Handling and Treatment segment. Revenues increased 42% compared to the prior year quarter, driven by growth in throughput volumes and fresh water delivery volumes. Water Handling and Treatment segment revenues include $36 million from produced water 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 $10 million and $42 million, respectively, for a total of $52 million compared to $43 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $35 million from produced water handling and high rate water transfer services. General and administrative expenses including equity-based compensation were $15 million, a $2 million increase compared to the second quarter of 2016. General and administrative expenses excluding equity-based compensation were $8 million during the second quarter of 2017, a $1 million increase compared to the second quarter of 2016. Total operating expenses were $101 million, including $30 million of depreciation and $4 million of accretion of contingent acquisition consideration. During the quarter, Antero Midstream continued construction on the Antero Clearwater Facility, which is expected to be placed into service in the fourth quarter of 2017 and have up to 60,000 Bbl/d of treating capacity.
Antero Midstream Distribution
Antero Midstream declared a cash distribution of $0.32 per unit ($1.28 per unit annualized) for the second quarter of 2017. The distribution represents a 28% increase compared to the prior year quarter and a 7% increase sequentially. The distribution is Antero Midstream's tenth consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on August 16, 2017 to unitholders of record as of August 3, 2017.
Balance Sheet and Liquidity
As of June 30, 2017, Antero's consolidated net debt was $5.3 billion, of which $1.2 billion were borrowings outstanding under the Company's and Antero Midstream's revolving credit facilities. Total borrowing capacity under these two facilities is currently $5.5 billion. Reduced for $706 million in letters of credit outstanding, the company had $3.6 billion in available consolidated liquidity as of June 30, 2017. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read "Non-GAAP Financial Measures."
Second Quarter 2017 Capital Spending
Antero's drilling and completion costs for the three months ended June 30, 2017 were $322 million. In addition, the Company invested $74 million for land and $130 million for proved property acquisitions. Antero Midstream invested $88 million for gathering and compression systems and $58 million for water infrastructure projects, including $46 million on the Antero Clearwater Treatment Facility. Investments in unconsolidated affiliates for Antero Midstream's processing and fractionation joint venture were $31 million during the quarter.
Hedge Position
Antero currently has hedged 3.1 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from July 1, 2017 through December 31, 2023 at an average index price of $3.62 per MMBtu. At June 30, 2017, the Company's estimated fair value of commodity derivative instruments was $2.0 billion.
The following table summarizes Antero's hedge position as of June 30, 2017:
Period Average Liquids Average
Natural Gas Index price Bbl/d Index price
MMBtu/d ($/MMBtu)
--- ------- ---------
3Q 2017:
--------
Nymex Henry Hub 1,370,000 $3.33 - -
CGTLA 420,000 $4.20 - -
Chicago 70,000 $4.45 - -
Propane MB ($/Gal) - - 27,500 $0.39
Ethane MB ($/Gal) - - 20,000 $0.25
Nymex WTI ($/Bbl) - - 3,000 $54.75
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
----------------- --- --- ----- ------
2017 Total 1,860,000 $3.64 50,500 N/A (1)
2018:
-----
Nymex Henry Hub 2,002,500 $3.91 - -
Propane MB ($/Gal) - - 2,000 $0.65
2019 Nymex Henry Hub 2,330,000 $3.70 - -
2020 Nymex Henry Hub 1,417,500 $3.63 - -
2021 Nymex Henry Hub 710,000 $3.31 - -
2022 Nymex Henry Hub 850,000 $3.16 - -
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, August 3, 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, August 11, 2017 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10108841.
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, August 11, 2017 at 9:00 am MT.
Presentation
An updated presentation will be posted to the Company's website before the August 3, 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 Six months ended
June 30,
June 30,
--------
2016 2017 2016 2017
---- ----
Total
operating
revenue $(249,198) $790,389 $471,806 $1,985,968
Hedge (gains)
losses 684,634 (85,641) 404,710 (524,416)
Cash receipts
for settled
hedges 292,500 31,064 616,847 75,913
------- ------
Revenue
excluding
unrealized
hedge
(gains)
losses $727,936 $735,812 $1,493,363 $1,537,465
======== ======== ========== ==========
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 Six months ended
June 30, June 30,
-------- --------
2016 2017 2016 2017
---- ---- ---- ----
Net income (loss) $(596,244) $(5,132) $(601,299) $263,264
Hedge (gains) losses 684,634 (85,641) 404,710 (524,416)
Cash receipts for settled
hedges 292,500 31,064 616,847 75,913
Impairment of unproved
properties 19,944 15,199 35,470 42,098
Equity-based compensation 25,816 26,975 49,286 52,478
Income tax effect of
reconciling items (385,928) 4,693 (417,401) 133,918
-------- ----- -------- -------
Adjusted net income (loss) $40,722 $(12,842) $87,613 $43,255
======= ======== ======= =======
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 Six months ended
June 30,
June 30,
--------
2016 2017 2016 2017
---- ---- ---- ----
Net cash provided by
operating activities $238,538 $253,647 $578,706 $647,586
Net change in working
capital 30,218 (2,853) (18,612) (100,190)
------ ------ ------- --------
Cash flow from operations
before changes in working
capital $268,756 $250,794 $560,094 $547,396
======== ======== ======== ========
The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):
December 31, June 30,
------------ --------
2016 2017
---- ----
Bank credit
facilities $650,000 $1,235,000
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 1,749 1,655
Net unamortized debt
issuance costs (47,776) (44,682)
------- -------
Consolidated total
debt $4,703,973 $5,291,973
Less: Cash and cash
equivalents 31,610 40,190
------ ------
Consolidated net
debt $4,672,363 $5,251,783
========== ==========
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 Six months ended
June 30, June 30,
--------
2016 2017 2016 2017
---- ---- ---- ----
Net Income (loss) including noncontrolling interest $(575,490) $39,965 $(564,840) $345,523
Commodity derivative (gains) losses 684,634 (85,641) 404,710 (524,416)
Gains on settled derivative instruments 292,500 31,064 616,847 75,913
Interest expense 62,595 68,582 125,879 135,252
Income tax expense (benefit) (376,494) 18,819 (371,679) 150,165
Depreciation, depletion, amortization, and accretion 197,982 201,831 390,162 405,197
Impairment of unproved properties 19,944 15,199 35,470 42,098
Exploration expense 1,109 1,804 2,123 3,911
Equity-based compensation expense 25,816 26,975 49,286 52,478
Equity in earnings of unconsolidated affiliate (484) (3,623) (484) (5,854)
Distributions from unconsolidated affiliates - 5,820 - 5,820
State franchise taxes - - 39 -
Total Adjusted EBITDAX 332,112 320,795 687,513 686,087
Interest expense (62,595) (68,582) (125,879) (135,252)
Exploration expense (1,109) (1,804) (2,123) (3,911)
Changes in current assets and liabilities (30,218) 2,853 18,612 100,190
State franchise taxes - - (39) -
Other non-cash items 348 385 622 472
--- --- --- ---
Net cash provided by operating activities $238,538 $253,647 $578,706 $647,586
======== ======== ======== ========
Three months ended Six months ended
June 30, June 30,
-------- --------
Adjusted EBITDAX margin ($ per Mcfe): 2016 2017 2016 2017
---- ---- ---- ----
Realized price before cash receipts for settled hedges $2.13 $3.26 $2.12 $3.41
Gathering, compression, water handling and treatment revenues 0.02 0.04 0.02 0.03
Lease operating expense (0.08) (0.08) (0.07) (0.08)
Gathering, compression, processing and transportation costs (1.29) (1.33) (1.29) (1.36)
Marketing, net (0.22) (0.14) (0.23) (0.13)
Production taxes (0.11) (0.11) (0.11) (0.12)
General and administrative(1) (0.21) (0.19) (0.21) (0.19)
----- ----- ----- -----
Adjusted EBITDAX margin before settled hedges 0.24 1.45 0.23 1.56
---- ---- ---- ----
Cash receipts for settled hedges 1.82 0.15 1.93 0.19
---- ---- ---- ----
Adjusted EBITDAX margin ($ per Mcfe): $2.06 $1.60 $2.16 $1.75
===== ===== ===== =====
(1) Excludes equity-based stock compensation
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.
Reserves Disclosure
In this release, Antero has provided a number of unaudited reserve metrics, which include all-in finding and development cost per unit and drill bit only finding and development cost per unit. These non-GAAP metrics are commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost. The finding and development costs per unit are statistical indicators that have limitations, including their predictive and comparative value. In addition, because the finding and development costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. These reserve metrics may not be comparable to similarly titled measurements used by other companies. The calculations for both all-in and drill bit only finding and development cost per unit do not include future development costs required for the development of proved undeveloped reserves.
Pre-tax PV-10 values and pre-tax PV-10 values including hedges are non-GAAP financial measures as defined by the SEC. Antero believes that the presentation of these pre-tax PV-10 values are relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves and hedges prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves and hedges as compared with other companies. Antero believes that PV-10 estimates using strip pricing and including hedges can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment. PV-10 estimates using strip pricing are not adjusted for the likelihood that the pricing scenario will occur, and thus they may not be comparable to PV-10 value using SEC pricing.
The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). With respect to PV-10 calculated as of an interim date, it is not practical to calculate the taxes for the related interim period because GAAP does not provide for disclosure of standardized measure on an interim basis.
ANTERO RESOURCES CORPORATION
Condensed Consolidated Balance Sheets
December 31, 2016 and June 30, 2017
(unaudited)
(In thousands, except per share amounts)
December 31, 2016 June 30, 2017
----------------- -------------
Assets
Current assets:
Cash and cash equivalents $31,610 40,190
Accounts receivable, net of allowance for doubtful accounts of
$1,195 in 2016 and 2017 29,682 16,494
Accrued revenue 261,960 218,621
Derivative instruments 73,022 452,005
Other current assets 6,313 8,573
----- -----
Total current assets 402,587 735,883
------- -------
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties 2,331,173 2,309,839
Proved properties 9,549,671 10,493,932
Water handling and treatment systems 744,682 840,183
Gathering systems and facilities 1,723,768 1,884,712
Other property and equipment 41,231 48,537
------ ------
14,390,525 15,577,203
Less accumulated depletion, depreciation, and amortization (2,363,778) (2,767,358)
---------- ----------
Property and equipment, net 12,026,747 12,809,845
---------- ----------
Derivative instruments 1,731,063 1,600,165
Investments in unconsolidated affiliates 68,299 259,697
Other assets 26,854 36,631
------ ------
Total assets $14,255,550 15,442,221
=========== ==========
Liabilities and Equity
Current liabilities:
Accounts payable $38,627 51,567
Accrued liabilities 393,803 418,352
Revenue distributions payable 163,989 203,151
Derivative instruments 203,635 3,279
Other current liabilities 17,334 16,711
------ ------
Total current liabilities 817,388 693,060
Long-term liabilities:
Long-term debt 4,703,973 5,291,973
Deferred income tax liability 950,217 1,100,382
Derivative instruments 234 172
Other liabilities 55,160 53,772
------ ------
Total liabilities 6,526,972 7,139,359
--------- ---------
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; issued
and outstanding 314,877 shares and 315,448 shares, respectively 3,149 3,154
Additional paid-in capital 5,299,481 6,435,047
Accumulated earnings 959,995 1,223,259
------- ---------
Total stockholders' equity 6,262,625 7,661,460
Noncontrolling interests in consolidated subsidiary 1,465,953 641,402
--------- -------
Total equity 7,728,578 8,302,862
--------- ---------
Total liabilities and equity $14,255,550 15,442,221
=========== ==========
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Loss
Three Months Ended June 30, 2016 and 2017
(unaudited)
(In thousands, except per share amounts)
Three Months Ended June 30,
---------------------------
2016 2017
---- ----
Revenue:
Natural gas sales $229,787 454,257
Natural gas liquids sales 94,713 170,819
Oil sales 16,740 26,512
Gathering, compression, water handling and treatment 3,294 3,192
Marketing 90,902 49,968
Commodity derivative fair value gains (losses) (684,634) 85,641
-------- ------
Total revenue (249,198) 790,389
-------- -------
Operating expenses:
Lease operating 12,043 16,992
Gathering, compression, processing, and transportation 206,060 266,747
Production and ad valorem taxes 17,458 22,553
Marketing 125,977 77,421
Exploration 1,109 1,804
Impairment of unproved properties 19,944 15,199
Depletion, depreciation, and amortization 197,362 201,182
Accretion of asset retirement obligations 620 649
General and administrative (including equity-based compensation expense of $25,816 and $26,975 in 2016 and 2017, respectively) 60,102 64,099
------ ------
Total operating expenses 640,675 666,646
------- -------
Operating income (loss) (889,873) 123,743
-------- -------
Other income (expenses):
Equity in earnings of unconsolidated affiliates 484 3,623
Interest (62,595) (68,582)
------- -------
Total other expenses (62,111) (64,959)
------- -------
Income (loss) before income taxes (951,984) 58,784
Provision for income tax (expense) benefit 376,494 (18,819)
------- -------
Net income (loss) and comprehensive income (loss) including noncontrolling interests (575,490) 39,965
Net income and comprehensive income attributable to noncontrolling interests 20,754 45,097
------ ------
Net loss and comprehensive loss attributable to Antero Resources Corporation $(596,244) (5,132)
========= ======
Loss per common share-basic $(2.12) (0.02)
Loss per common share-assuming dilution $(2.12) (0.02)
Weighted average number of shares outstanding:
Basic 281,786 315,401
Diluted 281,786 315,401
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)
Six Months Ended June 30, 2016 and 2017
(unaudited)
(In thousands, except per share amounts)
Six Months Ended June 30,
-------------------------
2016 2017
---- ----
Revenue and other:
Natural gas sales 484,563 920,921
Natural gas liquids sales 167,778 365,471
Oil sales 26,919 53,472
Gathering, compression, water handling and treatment 7,138 5,796
Marketing 190,118 115,892
Commodity derivative fair value gains (losses) (404,710) 524,416
-------- -------
Total revenue and other 471,806 1,985,968
------- ---------
Operating expenses:
Lease operating 23,336 32,543
Gathering, compression, processing, and transportation 414,798 533,576
Production and ad valorem taxes 36,742 47,346
Marketing 263,910 167,414
Exploration 2,123 3,911
Impairment of unproved properties 35,470 42,098
Depletion, depreciation, and amortization 388,944 403,911
Accretion of asset retirement obligations 1,218 1,286
General and administrative (including equity-based compensation expense of $49,286 and $52,478 in 2016 and 2017, respectively) 116,389 128,797
------- -------
Total operating expenses 1,282,930 1,360,882
--------- ---------
Operating income (loss) (811,124) 625,086
-------- -------
Other income (expenses):
Equity in earnings of unconsolidated affiliates 484 5,854
Interest (125,879) (135,252)
-------- --------
Total other expenses (125,395) (129,398)
-------- --------
Income (loss) before income taxes (936,519) 495,688
Provision for income tax (expense) benefit 371,679 (150,165)
------- --------
Net income (loss) and comprehensive income (loss) including noncontrolling interests (564,840) 345,523
Net income and comprehensive income attributable to noncontrolling interests 36,459 82,259
------ ------
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation (601,299) 263,264
======== =======
Earnings (loss) per common share-basic $(2.15) 0.84
Earnings (loss) per common share-assuming dilution $(2.15) 0.83
Weighted average number of shares outstanding:
Basic 279,418 315,179
Diluted 279,418 315,927
ANTERO RESOURCES CORPORATION
Condensed Consolidated Statements of Cash Flows
Six Months Ended June 30, 2016 and 2017
(unaudited)
(In thousands)
Six Months Ended June 30,
-------------------------
2016 2017
---- ----
Cash flows from operating activities:
Net income (loss) including noncontrolling
interests $(564,840) 345,523
Adjustment to reconcile net income (loss) to
net cash provided by operating activities:
Depletion, depreciation, amortization, and
accretion 390,162 405,197
Impairment of unproved properties 35,470 42,098
Derivative fair value (gains) losses 404,710 (524,416)
Gains on settled derivatives 616,848 75,913
Deferred income tax expense (benefit) (371,679) 150,165
Equity-based compensation expense 49,286 52,478
Equity in earnings of unconsolidated
affiliates (484) (5,854)
Distributions of earnings from unconsolidated
affiliates - 5,820
Other 621 472
Changes in current assets and liabilities:
Accounts receivable 7,798 13,188
Accrued revenue (5,237) 43,339
Other current assets 1,559 (2,385)
Accounts payable 13,223 2,072
Accrued liabilities (3,362) 4,204
Revenue distributions payable 5,105 39,162
Other current liabilities (474) 610
---- ---
Net cash provided by operating activities 578,706 647,586
------- -------
Cash flows used in investing activities:
Additions to proved properties - (179,318)
Additions to unproved properties (58,195) (129,876)
Drilling and completion costs (709,974) (629,308)
Additions to water handling and treatment
systems (78,625) (95,451)
Additions to gathering systems and facilities (97,300) (155,365)
Additions to other property and equipment (1,296) (6,564)
Investments in unconsolidated affiliates (45,044) (191,364)
Change in other assets (47,925) (12,452)
Other - 2,156
--- -----
Net cash used in investing activities (1,038,359) (1,397,542)
---------- ----------
Cash flows from financing activities:
Issuance of common stock 752,599 -
Issuance of common units by Antero Midstream
Partners LP - 246,585
Proceeds from sale of common units of Antero
Midstream Partners LP held by Antero
Resources Corporation 178,000 -
Borrowings (repayments) on bank credit
facilities, net (427,000) 585,000
Payments of deferred financing costs (96) -
Distributions to noncontrolling interests in
consolidated subsidiary (31,681) (61,869)
Employee tax withholding for settlement of
equity compensation awards (4,819) (8,433)
Other (2,572) (2,747)
------ ------
Net cash provided by financing activities 464,431 758,536
------- -------
Net increase in cash and cash equivalents 4,778 8,580
Cash and cash equivalents, beginning of period 23,473 31,610
------ ------
Cash and cash equivalents, end of period $28,251 40,190
======= ======
Supplemental disclosure of cash flow
information:
Cash paid during the period for interest $121,128 125,284
Supplemental disclosure of noncash investing
activities:
Increase (decrease) in accounts payable and
accrued liabilities for additions to property
and equipment $(155,671) 31,182
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the three months ended June 30, 2016 compared to the three months ended June 30, 2017:
Three Months Ended June 30, Amount of Percent
Increase
(in thousands) 2016 2017 (Decrease) Change
------------- ---- ---- --------- ------
Operating revenues and other:
Natural gas sales $229,787 $454,257 $224,470 98%
NGLs sales 94,713 170,819 76,106 80%
Oil sales 16,740 26,512 9,772 58%
Gathering, compression, water handling and
treatment 3,294 3,192 (102) (3)%
Marketing 90,902 49,968 (40,934) (45)%
Commodity derivative fair value gains (losses) (684,634) 85,641 770,275 *
-------- ------ -------
Total operating revenues and other (249,198) 790,389 1,039,587 *
-------- ------- ---------
Operating expenses:
Lease operating 12,043 16,992 4,949 41%
Gathering, compression, processing, and
transportation 206,060 266,747 60,687 29%
Production and ad valorem taxes 17,458 22,553 5,095 29%
Marketing 125,977 77,421 (48,556) (39)%
Exploration 1,109 1,804 695 63%
Impairment of unproved properties 19,944 15,199 (4,745) (24)%
Depletion, depreciation, and amortization 197,362 201,182 3,820 2%
Accretion of asset retirement obligations 620 649 29 5%
General and administrative (before equity-based
compensation) 34,286 37,124 2,838 8%
Equity-based compensation 25,816 26,975 1,159 4%
------ ------ -----
Total operating expenses 640,675 666,646 25,971 4%
------- ------- ------
Operating income (loss) (889,873) 123,743 1,013,616 *
-------- ------- ---------
Other earnings (expenses):
Equity in earnings of unconsolidated affiliate 484 3,623 3,139 649%
Interest expense (62,595) (68,582) (5,987) 10%
------- ------- ------
Total other expenses (62,111) (64,959) (2,848) 5%
------- ------- ------
Income (loss) before income taxes (951,984) 58,784 1,010,768 *
Income tax (expense) benefit 376,494 (18,819) (395,313) *
------- ------- --------
Net income (loss) and comprehensive income
(loss) including noncontrolling interest (575,490) 39,965 615,455 *
Net income and comprehensive income attributable
to noncontrolling interest 20,754 45,097 24,343 117%
------ ------ ------
Net loss and comprehensive loss attributable to
Antero Resources Corporation $(596,244) $(5,132) $591,112 (99)%
========= ======= ========
Adjusted EBITDAX (1) $332,112 $320,795 $(11,317) (3)%
======== ======== ========
Production data:
Natural gas (Bcf) 119 144 25 21%
C2 Ethane (MBbl) 1,581 2,548 967 61%
C3+ NGLs (MBbl) 4,771 6,190 1,419 30%
Oil (MBbl) 477 613 136 29%
Combined (Bcfe) 160 200 40 25%
Daily combined production (MMcfe/d) 1,762 2,200 438 25%
Average prices before effects of derivative
settlements:
Natural gas (per Mcf) $1.93 $3.15 $1.22 63%
C2 Ethane (per Bbl) $8.36 $8.40 $0.04 *
C3+ NGLs (per Bbl) $17.08 $24.14 $7.06 41%
Oil (per Bbl) $35.08 $43.24 $8.16 23%
Combined (per Mcfe) $2.13 $3.26 $1.13 53%
Average realized prices after effects of
derivative settlements:
Natural gas (per Mcf) $4.31 $3.53 $(0.78) (18)%
C2 Ethane (per Bbl) $8.36 $8.61 $0.25 3%
C3+ NGLs (per Bbl) $18.98 $19.92 $0.94 5%
Oil (per Bbl) $35.08 $46.12 $11.04 31%
Combined (per Mcfe) $3.95 $3.41 $(0.54) (14)%
Average Costs (per Mcfe):
Lease operating $0.08 $0.08 $ - *
Gathering, compression, processing, and
transportation $1.29 $1.33 $0.04 3%
Production and ad valorem taxes $0.11 $0.11 $ - *
Marketing expense, net $0.22 $0.14 $(0.08) (36)%
Depletion, depreciation, amortization, and
accretion $1.23 $1.01 $(0.22) (18)%
General and administrative (before equity-based
compensation) $0.21 $0.19 $(0.02) (10)%
(1) Please see "Non-GAAP
Financial Measures" for a
description of Adjusted
EBITDAX
*Not meaningful or applicable
ANTERO RESOURCES CORPORATION
The following tables set forth selected operating data for the six months ended June 30, 2016 compared to the six months ended June 30, 2017:
Six Months Ended June 30, Amount of Percent
Increase
(in thousands) 2016 2017 (Decrease) Change
------------- ---- ---- --------- ------
Operating revenues and other:
Natural gas sales $484,563 $920,921 $436,358 90%
NGLs sales 167,778 365,471 197,693 118%
Oil sales 26,919 53,472 26,553 99%
Gathering, compression, water handling and
treatment 7,138 5,796 (1,342) (19)%
Marketing 190,118 115,892 (74,226) (39)%
Commodity derivative fair value gains (losses) (404,710) 524,416 929,126 *
-------- ------- -------
Total operating revenues and other 471,806 1,985,968 1,514,162 321%
------- --------- ---------
Operating expenses:
Lease operating 23,336 32,543 9,207 39%
Gathering, compression, processing, and
transportation 414,798 533,576 118,778 29%
Production and ad valorem taxes 36,742 47,346 10,604 29%
Marketing 263,910 167,414 (96,496) (37)%
Exploration 2,123 3,911 1,788 84%
Impairment of unproved properties 35,470 42,098 6,628 19%
Depletion, depreciation, and amortization 388,944 403,911 14,967 4%
Accretion of asset retirement obligations 1,218 1,286 68 6%
General and administrative (before equity-based
compensation) 67,103 76,319 9,216 14%
Equity-based compensation 49,286 52,478 3,192 6%
------ ------ -----
Total operating expenses 1,282,930 1,360,882 77,952 6%
--------- --------- ------
Operating income (loss) (811,124) 625,086 1,436,210 *
-------- ------- ---------
Other earnings (expenses):
Equity in earnings of unconsolidated affiliates 484 5,854 5,370 1,110%
Interest expense (125,879) (135,252) (9,373) 7%
-------- -------- ------
Total other expenses (125,395) (129,398) (4,003) 3%
-------- -------- ------
Income (loss) before income taxes (936,519) 495,688 1,432,207 *
Income tax (expense) benefit 371,679 (150,165) (521,844) *
------- -------- --------
Net income (loss) and comprehensive income (loss)
including noncontrolling interest (564,840) 345,523 910,363 *
Net income and comprehensive income attributable
to noncontrolling interest 36,459 82,259 45,800 126%
------ ------ ------
Net income (loss) and comprehensive income (loss)
attributable to Antero Resources Corporation $(601,299) $263,264 $864,563 *
========= ======== ========
Adjusted EBITDAX (1) $687,513 $686,087 $(1,426) *
======== ======== =======
Production data:
Natural gas (Bcf) 242 284 42 17%
C2 Ethane (MBbl) 2,662 4,858 2,196 82%
C3+ NGLs (MBbl) 9,452 12,159 2,707 29%
Oil (MBbl) 949 1,256 307 32%
Combined (Bcfe) 320 393 73 23%
Daily combined production (MMcfe/d) 1,760 2,172 412 23%
Average prices before effects of derivative
settlements:
Natural gas (per Mcf) $2.00 $3.25 $1.25 63%
C2 Ethane (per Bbl) $7.68 $8.21 $0.53 7%
C3+ NGLs (per Bbl) $15.59 $26.78 $11.19 72%
Oil (per Bbl) $28.36 $42.58 $14.22 50%
Combined (per Mcfe) $2.12 $3.41 $1.29 61%
Average realized prices after effects of
derivative settlements:
Natural gas (per Mcf) $4.42 $3.71 $(0.71) (16)%
C2 Ethane (per Bbl) $7.68 $8.67 $0.99 13%
C3+ NGLs (per Bbl) $18.93 $21.92 $2.99 16%
Oil (per Bbl) $28.36 $44.61 $16.25 57%
Combined (per Mcfe) $4.05 $3.60 $(0.45) (11)%
Average Costs (per Mcfe):
Lease operating $0.07 $0.08 $0.01 14%
Gathering, compression, processing, and
transportation $1.29 $1.36 $0.07 5%
Production and ad valorem taxes $0.11 $0.12 $0.01 9%
Marketing expense, net $0.23 $0.13 $(0.10) (43)%
Depletion, depreciation, amortization, and
accretion $1.22 $1.03 $(0.19) (16)%
General and administrative (before equity-based
compensation) $0.21 $0.19 $(0.02) (10)%
(1) Please see "Non-GAAP
Financial Measures" for a
description of Adjusted
EBITDAX
*Not meaningful or applicable
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SOURCE Antero Resources Corporation
