EXHIBIT 99.1

 

 

Antero Resources Reports Fourth Quarter and Full Year 2016 Financial and Operational Results

 

Denver, Colorado, February 28, 2017—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its fourth quarter and full-year 2016 financial and operating results.  The relevant financial statements are included in Antero’s Annual Report on Form 10-K for the year ended December 31, 2016, which has been filed with the Securities and Exchange Commission (“SEC”).

 

Fourth Quarter Highlights Include:

 

·                  Net daily gas equivalent production averaged a record 1,990 MMcfe/d (26% liquids), a 33% increase over the prior year quarter

·                  This includes a record 86,857 Bbl/d of liquids production, a 59% increase over the prior year quarter

·                  Liquids production contributed 30% of total product revenues, before hedging

·                  Realized $0.07 per Mcf premium to Nymex natural gas price before hedging, or $3.05 per Mcf

·                  Realized C3+ NGL price of $25.22 per barrel, 51% of Nymex WTI price before hedging

·                  Realized natural gas equivalent price of $4.26 per Mcfe including NGLs, oil and hedges

·                  GAAP net loss of $486 million, or $(1.55) per share including $829 million of unrealized hedge losses, compared to net income of $158 million, or $0.57 per share, in the prior year quarter

·                  Adjusted net income of $68 million, or $0.22 per share, a 26% increase compared to the prior year quarter

·                  Adjusted EBITDAX of $476 million, a 55% increase compared to the prior year quarter

·                  Increased 2017 guidance for NGL price realizations, before hedging, to 50% to 55% of WTI oil prices

 

Full Year 2016 Highlights Include:

 

·                  Net daily gas equivalent production averaged 1,847 MMcfe/d (25% liquids), a 24% increase over the prior year

·                  GAAP net loss of $849 million, or $(2.88) per share including $1.5 billion of unrealized hedge losses, compared to net income of $941 million in the prior year

·                  Adjusted net income of $209 million, or $0.71 per share, a 37% increase compared to the prior year

·                  Adjusted EBITDAX of $1.54 billion, a 26% increase compared to the prior year

·                  Net debt to trailing twelve months adjusted EBITDAX of 3.0x

 

Recent Developments

 

Increased 2017 NGL Pricing Guidance and NGL Infrastructure Update

 

Driven by the recent strength in Mont Belvieu prices and regional demand in the Northeast, Antero has increased its 2017 C3+ natural gas liquids (“NGL”) price realization guidance before hedging to 50% to 55% of WTI oil prices, up from previous guidance of 45% to 50% of WTI.  Importantly, the updated 2017 NGL price realization guidance does not include the anticipated positive effect of the Mariner East 2 pipeline project described below.

 

On February 13, 2017, the Pennsylvania Department of Environmental Protection issued permits for Sunoco Logistics Partners LP’s (“Sunoco”) Mariner East 2 pipeline project, which enables Sunoco to begin construction on the 350-mile NGL pipeline.  The pipeline will transport NGLs from Southwestern Pennsylvania and Eastern Ohio to the Marcus Hook terminal and export facility near Philadelphia, Pennsylvania, which is also owned by Sunoco.  As previously announced, Antero is an anchor shipper on Mariner East 2 with a 61,500 barrels per day commitment (35,000 barrels of propane / 15,000 barrels of butane / 11,500 barrels of ethane).  The pipeline is expected to be placed into service by the end of the third quarter of 2017.

 

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On February 6, 2017, Antero Midstream Partners LP (NYSE: AM) (“Antero Midstream” or the “Partnership”) announced the formation of a joint venture (the “Joint Venture”) to develop processing and fractionation assets in Appalachia with MarkWest Energy Partners, L.P., a wholly owned subsidiary of MPLX, LP. The Joint Venture will develop cryogenic processing assets at the Sherwood Processing Facility in Doddridge County, West Virginia, and also at an additional site still to be designated, also located in West Virginia, to support Antero’s continued liquids-rich production growth in the southwestern core of the Marcellus Shale. The Joint Venture participation will begin with the next three 200 MMcf/d plants at the Sherwood Processing Facility (Plants 7, 8 and 9), which are under development and scheduled to be placed into service during the first quarter of 2017, third quarter of 2017, and first quarter of 2018.  In addition, Antero Resources recently committed to Plant 10 at the Sherwood facility, which is expected to be placed into service in the third quarter of 2018. The Joint Venture will also own C3+ fractionation capacity at the Hopedale complex in Harrison County, Ohio supported by Antero and other third party producers and will have the option to participate in incremental fractionation capacity to be built in the future as needed.

 

Natural Gas Firm Transportation Update

 

In early February 2017, Energy Transfer Partners, L.P. (“Energy Transfer”) received FERC approval to proceed with the construction of the Rover Pipeline.  Antero is an anchor shipper on the Rover Pipeline with an 800,000 MMBtu/d firm commitment. The pipeline will connect Antero’s Marcellus and Utica Shale assets to the Midwest and Gulf Coast via additional downstream firm transportation that Antero already holds.  The project will also enable Antero to transport natural gas both from the Sherwood and Seneca processing facilities, allowing for maximum optionality on its firm transportation portfolio.  Energy Transfer plans to place the Rover Pipeline into service in the third quarter of 2017.

 

Year-End 2016 Proved and 3P Reserves

 

On February 1, 2017, Antero announced that estimated proved reserves at year-end 2016 were 15.4 Tcfe, a 16% increase compared to estimated proved reserves at December 31, 2015. All-in finding and development cost for proved reserve additions was $0.52 per Mcfe. This finding and development cost includes drilling and completion capital as well as costs incurred for well pads, roads, certain production facilities, acquisitions, land additions and gives effect to performance and price revisions.  Drill bit only finding and development cost for proved reserve additions was $0.39 per Mcfe.  Proved developed reserves increased by 18% from year-end 2015 to 6.9 Tcfe at December 31, 2016. Additionally, the percentage of proved reserves classified as proved developed increased to 45% at December 31, 2016.

 

The Company’s proved, probable and possible (“3P”) reserves at year-end 2016 totaled 46.4 Tcfe, which represents a 25% increase compared to the previous year.  Antero’s Marcellus and Utica 3P drilling inventory totaled 3,630 locations at year-end 2016 with an average lateral length of 8,250’, of which approximately 81% were in the Marcellus.

 

Fourth Quarter 2016 Financial and Operating Results

 

As of December 31, 2016, pro forma for Antero Midstream’s common unit offering in February 2017, Antero owned a 59% limited partner interest in Antero Midstream Partners.  Antero Midstream’s results are consolidated with Antero’s results.

 

For the three months ended December 31, 2016, the Company reported a net loss of $486 million, or $(1.55) per basic share and diluted share, compared to net income of $158 million, or $0.57 per basic and diluted share, in the fourth quarter of 2015. Net loss for the fourth quarter of 2016 included the following items:

 

·                  Non-cash loss on unsettled hedges of $829 million due to increasing commodity prices during the quarter

·                  Non-cash equity-based compensation expense of $27 million

·                  Impairment of unproved properties of $116 million

·                  Loss on early extinguishment of debt of $17 million

·                  Gain on sale of assets of $98 million

·                  Income tax effect of these reconciling items of $(337) million

 

Excluding the items detailed above, the Company’s results for the fourth quarter of 2016 were as follows:

 

·                  Adjusted net income of $68 million, or $0.22 per basic and diluted share, a 26% increase compared to the fourth quarter of 2015

·                  Adjusted EBITDAX of $476 million, a 55% increase compared to the fourth quarter of 2015

 

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For a description of adjusted net income and adjusted EBITDAX and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”

 

Antero’s net daily production for the fourth quarter of 2016 averaged 1,990 MMcfe/d, including 86,857 Bbl/d of liquids (26% liquids).  Fourth quarter 2016 production represents an organic production growth rate of 33% from the fourth quarter of 2015 and a 6% increase compared to the third quarter of 2016.  Fourth quarter 2016 C3+ NGL and oil production averaged 60,405 Bbl/d and 5,439 Bbl/d, respectively.  Recovered ethane (C2) production averaged 21,013 Bbl/d, while leaving approximately 66,000 Bbl/d of ethane in the natural gas stream. Total liquids production for the fourth quarter of 2016 represents an organic production growth rate of 59% and 7% from the fourth quarter of 2015 and third quarter of 2016, respectively.

 

Antero’s average natural gas price before hedging increased 43% from the prior year quarter to $3.05 per Mcf, a $0.07 per Mcf premium to the average Nymex price for the period.  Virtually all of Antero’s fourth quarter 2016 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Gulf Coast and Nymex.  Antero’s average realized natural gas price after hedging for the fourth quarter of 2016 was $4.43 per Mcf, a $1.45 premium to the Nymex average price for the period, which was consistent with the prior year quarter.  During the quarter, Antero realized a cash settled natural gas hedge gain of $187 million, or $1.38 per Mcf.

 

The Company’s average realized C3+ NGL price before hedging for the fourth quarter of 2016 was $25.22 per barrel, or 51% of the average Nymex WTI oil price, which represents a 45% increase as compared to the prior year quarter.  Antero’s average realized C3+ NGL price including hedges was $25.60 per barrel, a 17% increase compared to the fourth quarter of 2015.  Antero’s average realized ethane price for the fourth quarter of 2016 was $0.22 per gallon, or $9.36 per barrel.  The average realized oil price before hedging was $39.18 per barrel, a $9.96 differential to average Nymex WTI and a 37% increase as compared to the fourth quarter of 2015.

 

Antero’s average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased from the prior year quarter by 39% to $3.22 per Mcfe.  The Company’s average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, was $4.26 per Mcfe which was in line with the prior year quarter.  For the fourth quarter of 2016, Antero realized a total cash settled hedge gain on all products of $190 million, or $1.04 per Mcfe.

 

Commenting on liquids pricing and exposure, Glen Warren, President and CFO, said, “During the fourth quarter, Antero was the largest producer of C3+ natural gas liquids in Appalachia and realized a C3+ natural gas liquids price before hedging of $25.22, which was 51% of the average Nymex WTI oil price and 45% higher than the prior year quarter.  This realization was also well above the top of our full year NGL pricing guidance range of 35% to 40% of WTI.  When this improvement in NGL pricing outlook is combined with our continued growth in liquids production and the buildout of the Mariner East 2 project, we believe we have the most powerful NGL story in the Northeast.”

 

Total operating revenue for the fourth quarter of 2016 was $156 million as compared to $905 million for the fourth quarter of 2015.  Operating revenue for the fourth quarter of 2016 included an $829 million non-cash loss on unsettled hedges and a $98 million gain on the sale of assets, while the fourth quarter of 2015 included a $275 million non-cash gain on unsettled hedges.  Revenue excluding the unrealized hedge loss and gain on the sale of assets was $888 million, a 41% increase compared to the fourth quarter of 2015.  Liquids production contributed 30% of total product revenues before hedges in the fourth quarter of 2016, as compared to a 28% contribution for the prior year quarter.  For a reconciliation of revenue excluding unrealized hedge gain (loss) and gain on sale of assets to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Marketing revenue for the fourth quarter of 2016 was $106 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 fourth quarter of 2016 was $121 million, including costs related to excess capacity and the cost of purchasing third party gas.  Net marketing expense was $15 million, or $0.08 per Mcfe, for the fourth quarter of 2016, representing a 79%, or $0.30 per Mcfe decrease from the fourth quarter of 2015.  The significant decrease in net marketing expense from the prior year quarter is primarily attributable to a third party contractual commitment that commenced on July 1, 2016, in which Antero released certain unutilized firm transportation capacity and the costs associated with the unutilized capacity. Additionally, Antero’s marketed volumes increased year-over-year and the Company generated a higher spread on its marketed volumes due to wider local northeast indices relative to the end market indices reached through Antero’s firm transportation capacity.

 

Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem tax) for the fourth quarter of 2016 was $1.42 per Mcfe, a 3% decrease compared to $1.46 per Mcfe in the prior year quarter.  The per unit cash production expense for the quarter included $0.07 per Mcfe for lease operating costs, $1.27 per Mcfe for gathering, compression, processing and transportation costs and $0.08 per Mcfe for production and ad valorem taxes.  Per unit general and administrative expense for the fourth quarter of 2016, excluding non-cash equity-based compensation expense, was $0.21 per Mcfe, a 22% decrease from the fourth quarter of 2015.  The significant per unit decrease in general and administrative expenses was primarily

 

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driven by the increase in production while overall general and administrative expense remained relatively flat.  Per unit depreciation, depletion and amortization expense increased 3% from the prior year quarter to $1.22 per Mcfe, primarily due to an increase in the total drilling and completion costs subject to depletion.

 

Adjusted EBITDAX of $476 million for the fourth quarter of 2016 represents a 55% increase compared to the prior year quarter.  Adjusted EBITDAX margin for the quarter was $2.60 per Mcfe, representing a 16% increase from the prior year quarter.  For the fourth quarter of 2016, cash flow from operations before changes in working capital was $404 million, a 69% increase from the prior year quarter and well in excess of drilling and completion capital expenditures of $318 million.

 

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 December 31, 2016:

 

		Three Months Ended December 31, 2016
		Gas (MMcf/d)		Oil (Bbl/d)		C3+ NGLs (Bbl/d)		Ethane (Bbl/d)		Combined Gas Equivalent (MMcfe/d)
Average Net Production		1,469		5,439		60,405		21,013		1,990

 

Average Realized Prices		Gas ($/Mcf)			Oil ($/Bbl)			C3+ NGLs ($/Bbl)			Ethane ($/Bbl)			Combined Gas Equivalent ($/Mcfe)
Average realized price before settled derivatives		$	3.05		$	39.18		$	25.22		$	9.36		$	3.22
Settled derivatives		1.38			—			0.38			—			1.04
Average realized price after settled derivatives		$	4.43		$	39.18		$	25.60		$	9.36		$	4.26
Nymex average price		$	2.98		$	49.14								$	2.98
Premium / (Differential) to Nymex		$	1.45		$	(9.96	)							$	1.28

 

Marcellus Shale — Antero completed and placed on line 33 horizontal Marcellus wells during the fourth quarter of 2016 with an average lateral length of 9,900 feet.  During the quarter, Antero drilled an average of 4,100 feet per day in its laterals while drilling and casing 29 wells.  The Company’s contracted completion crews averaged four stages per day in the Marcellus.  All 33 wells completed in the fourth quarter of 2016 have been on line for more than 30 days and had an average 30-day rate of 18.8 MMcfe/d while rejecting ethane (26% liquids).  In 2016, Antero completed 88 wells that have an average EUR of 21.5 Bcfe assuming ethane rejection, an average Btu of 1245 and an average lateral length of 9,200 feet.  Approximately 80% of the 88 wells completed in 2016 in the Marcellus utilized advanced completion techniques. The Company is currently operating three drilling rigs and five completion crews in the Marcellus Shale play.

 

Current average well costs are $0.84 million per 1,000 feet of lateral in the Marcellus, which represents a 29% reduction from 2015 and a 2% reduction from the third quarter of 2016.  The reduction in average well costs is primarily driven by continuing operational efficiencies.  In the Marcellus, average drilling days from spud to final rig release declined to 12 days in the fourth quarter of 2016, a 50% reduction from 2015 and a 14% reduction from the third quarter of 2016.

 

One notable Marcellus pad that was completed in the fourth quarter had ten wells with an average lateral length of 10,500 feet and was completed with 1,750 pounds of proppant per foot.  The average EUR for this pad is 2.1 Bcf/1,000 at the wellhead and 2.6 Bcfe/1,000’ processed (ethane rejection), and the combined 30-day rate for the 10-well pad was 200 MMcfe/d, including 7,800 Bbl/d of C3+ NGLs and 2,300 Bbl/d of oil.  The average cost per well on the pad was $7.9 million, or $0.75 million per 1,000 feet of lateral.  This pad had an all-in development cost of $0.36 per Mcfe and is expected to deliver a cash on cash payout of 1.7 years.  Antero plans to average nine wells per pad in the Marcellus in 2017.

 

Ohio Utica Shale — Antero completed and placed on line ten horizontal Ohio Utica wells during the fourth quarter of 2016 with an average lateral length of 8,600 feet.  During the quarter, Antero drilled on average of 2,850 feet per day in its laterals while drilling

 

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and casing six wells during the quarter.  The Company’s contracted completion crews averaged six stages per day in the Utica, a record for the Company.  All ten of the wells completed in the fourth quarter of 2016 have been on line for more than 30 days and had an average restricted 30-day rate of 17.5 MMcfe/d while rejecting ethane (26% liquids).  Antero is currently operating three drilling rigs and one completion crew in the Utica Shale play.

 

Current average well costs are $0.99 million per 1,000 feet of lateral in the Utica, which represents a 27% reduction from 2015 and a 2% reduction from the third quarter of 2016.  The reduction in average well costs is primarily driven by lower service costs and continued operational efficiencies.  Drilling days from spud to final rig release declined to 13 days in the Utica in the fourth quarter of 2016, a 58% reduction from 2015.

 

The one Utica pad that was completed in the fourth quarter had ten wells with an average lateral length of 8,600 feet.  The combined 30-day rate for the 10-well pad, was 178 MMcfe/d, flowing at a constrained rate, including 5,800 Bbl/d of C3+ NGLs and 1,400 Bbl/d of oil.  The average cost per well on the pad was $8.4 million, or $0.97 million per 1,000 feet of lateral.  Antero plans to average six wells per pad in the Utica in 2017 and plans to utilize existing pads for a portion of the planned wells.

 

Commenting on Antero’s 2016 results and future development plan, Paul Rady, Chairman of the Board and CEO said, “In 2016, through strategic acreage consolidation, we increased our extensive core drilling inventory to over 3,400 locations.  From 2017 through 2020, we are targeting the completion of just over 800 of these core locations, or less than 25% of our overall core inventory. This provides us with significant visibility around our long-term growth plans.  Looking ahead, we are well positioned to achieve our production guidance of 20% to 25% in 2017 and our production targets of 20% to 22%, on a compounded annual basis through 2020.  Importantly, the significant operational improvements resulting in increased EUR’s and lower well costs now position us to achieve this production growth while driving down leverage and spending within operating cash flow.”

 

Antero Midstream Financial Results

 

Antero Midstream results were released today and are available at www.anteromidstream.com.

 

Low pressure gathering volumes for the fourth quarter of 2016 averaged 1,522 MMcf/d, a 35% increase from the fourth quarter of 2015 and a 6% increase sequentially from the third quarter of 2016.  Compression volumes for the fourth quarter of 2016 averaged 920 MMcf/d, a 92% increase from the fourth quarter of 2015 and an 18% increase sequentially.  High pressure gathering volumes for the fourth quarter of 2016 averaged 1,437 MMcf/d, a 20% increase from the fourth quarter of 2015 and a 6% increase sequentially.    The increase in throughput volumes was driven by Antero’s production growth in Antero Midstream’s area of dedication. Fresh water delivery volumes averaged 149,682 Bbl/d during the quarter, a 25% increase compared to the prior year quarter and a 7% increase sequentially.  The increase in volumes was driven by an increase in wells serviced by the fresh water delivery system and higher water intensity advanced completions.

 

For the three months ended December 31, 2016, Antero Midstream reported revenues of $167 million, comprised of $88 million from the Gathering and Processing segment and $79 million from the Water Handling and Treatment segment.  Revenues increased 27% compared to the prior year quarter, primarily driven by growth in natural gas throughput volumes and fresh water delivery volumes.  Gathering and Processing revenues included a $4 million gain on asset sale related to the divestiture of certain gathering and compression assets in Pennsylvania during the quarter.  Water Handling and Treatment segment revenues include $28 million from fluid 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 $8 million and $29 million, respectively, for a total of $37 million compared to $40 million in direct operating expenses in the prior year quarter.  Water Handling and Treatment direct operating expenses include $27 million from fluid handling and high rate water transfer services.  The decrease in direct operating expenses was driven primarily by a reduction in fluid handling and high rate transfer expenses.  General and administrative expenses including equity-based compensation were $14 million, a $1 million increase compared to the fourth quarter of 2015.  General and administrative expenses excluding equity-based compensation were $8 million during the fourth quarter of 2016, in line with the fourth quarter of 2015.  Total operating expenses were $83 million, including $26 million of depreciation, $7 million of equity-based compensation, and $6 million of accretion of contingent acquisition consideration.

 

The Board of Directors of Antero Resources Midstream Management LLC, the general partner of the Partnership, declared a cash distribution of $0.28 per unit ($1.12 per unit annualized) for the fourth quarter of 2016. The distribution represents a 27% increase compared to the prior year quarter and a 6% increase sequentially.  The distribution is the Partnership’s eighth consecutive quarterly distribution increase since its initial public offering in November 2014 and was paid on February 8, 2017 to unitholders of record as of February 1, 2017.  Upon payment of this distribution, the 75,940,957 subordinated units owned by Antero Resources were converted into common units on a one-for-one basis under the terms of the Partnership agreement.

 

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Fourth Quarter 2016 Capital Spending

 

Antero’s drilling and completion capital expenditures for the three months ended December 31, 2016 were $318 million.  In addition, the Company invested $47 million for land, excluding $74 million for leasehold and proved property acquisitions.  Antero Midstream invested $77 million for gathering and compression systems and $51 million for water infrastructure projects, including $36 million for the Antero Clearwater Treatment Facility.

 

2016 Financial Results

 

Antero’s net daily production for 2016 averaged 1,847 MMcfe/d, which was 3% above the previously increased 2016 guidance and included 78,002 Bbl/d of liquids (25%).  Full year 2016 production represents an organic growth rate of 24% from the prior year. Full year 2016 C3+ NGL and oil production averaged 55,408 Bbl/d and 5,118 Bbl/d, which were 4% and 14% above 2016 guidance, respectively.  Ethane (C2) production averaged 17,476 Bbl/d.  Total liquids production for 2016 represents an organic growth rate of 62% over 2015 liquids production.

 

Antero’s average natural gas price before hedging increased 5% from the prior year to $2.50 per Mcf, a $0.04 per Mcf premium to the average Nymex price for the period and at the high end of 2016 guidance of a $0.00 per Mcf to $0.05 per Mcf premium to Nymex.  Approximately 99% of Antero’s 2016 natural gas production was priced at favorable indices, including Columbia Gas Transmission (TCO), Chicago, MichCon, Gulf Coast and Nymex.  Antero’s average realized natural gas price after hedging for 2016 was $4.39 per Mcf, a $1.93 premium to the Nymex average price for the period, which was a 6% increase as compared to 2015.  During the year, Antero realized a cash settled natural gas hedge gain of $957 million, or $1.90 per Mcf.

 

The Company’s average realized C3+ NGL price before hedging for 2016 was $18.74 per barrel, or 43% of the average Nymex WTI oil price, which represents a 9% increase as compared to the prior year and exceeds the 2016 guidance of 35% to 40% of WTI.  Antero’s realized C3+ NGL price including hedges was $21.03 per barrel, which was in line with 2015.  Antero’s average realized ethane price in 2016 was $0.20 per gallon, or $8.28 per barrel, a 34% increase as compared to the prior year.  Antero’s average realized oil price before hedging was $32.73 per barrel, a $10.42 differential to average Nymex WTI and a 4% decrease as compared to the prior year.

 

Antero’s average natural gas-equivalent price including C2+ NGLs and oil, but excluding hedge settlements, increased 3% from the prior year to $2.60 per Mcfe, despite an 8% and 11% decrease in average Nymex Henry Hub natural gas and average Nymex WTI oil prices, respectively.  The increase in natural gas equivalent price was driven by improved realized natural gas and NGL prices as a result of Antero selling at more favorably priced indices and contracting for a portion of its NGL production at tighter differentials to Mont Belvieu.  Antero’s average natural gas-equivalent price including NGLs, oil and hedge settlements was in line with the prior year at $4.08 per Mcfe.  For 2016, Antero realized a total cash settled hedge gain on all products of $1.0 billion, or $1.48 per Mcfe.

 

Total operating revenue for 2016 was $1.7 billion as compared to $4.0 billion for the prior year.  Operating revenue for 2016 included a $1.5 billion non-cash loss on unsettled hedges and a $98 million gain on the sale of assets, while 2015 included a $1.5 billion non-cash gain on unsettled hedges.  For 2016, revenue excluding the unrealized hedge gain (loss) and gain on the sale of assets was $3.2 billion, a 30% increase compared to 2015.  Liquids production contributed 28% of total product revenues before hedges in 2016, compared to 24% during 2015.  For a reconciliation of revenue excluding the unrealized hedge loss and gain on sale of assets to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Marketing revenue for 2016 was $393 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 Rockies Express Pipeline, Columbia Gas Pipeline and Tennessee Gas Pipeline.  Marketing expense for 2016 was $499 million.  The largest components of marketing expense include firm transportation costs related to current excess capacity as well as the cost of third-party purchased gas and NGLs.  Net marketing expense for 2016 was $106 million, or $0.16 per Mcfe, which was at the low end of the Company’s 2016 guidance of $0.15 to $0.20 per Mcfe.

 

Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and ad valorem tax) for 2016 was $1.48 per Mcfe which is a 4% increase compared to $1.42 per Mcfe in the prior year and at the high end of 2016 guidance of $1.40 to $1.50 per Mcfe.  The per unit cash production expense for 2016 included $0.07 per Mcfe for lease operating costs, $1.31 per Mcfe for gathering, compression and transportation costs and $0.10 per Mcfe for production and ad valorem taxes.  The increase from the prior year was primarily due to higher transportation costs associated with Antero’s increasing firm transportation, which in turn enabled the Company to sell its gas at more favorably priced indices.  Per unit general and administrative expense for 2016, excluding non-cash equity based compensation expense, was $0.20 per Mcfe, a 20% decrease from 2015 and at the low end of Antero’s 2016 guidance of $0.20 to $0.22 per Mcfe.  The decrease was primarily driven by the significant increase in net production.  Per unit depreciation, depletion and amortization expense decreased by 8% to $1.20 per Mcfe compared to 2015.

 

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The Company reported a net loss from continuing operations attributable to common stockholders of $849 million (($2.88) per basic and diluted share) for 2016, including:

 

·                  $1.5 billion of non-cash losses on unsettled hedges

·                  $102 million of non-cash equity-based compensation expense

·                  $163 million of impairments of unproved properties

·                  $17 million loss on early extinguishment of debt

·                  $98 million gain on sale of assets

·                  Income tax effect of these reconciling items of $(644) million

 

Excluding these items, the Company’s results for 2016 were as follows:

 

·                  Adjusted net income was $209 million ($0.71 per basic and diluted share) for 2016, representing a 37% increase over the prior year

·                  Adjusted EBITDAX of $1.54 billion, a 26% increase compared to the prior year

 

Adjusted EBITDAX margin for 2016 was $2.27 per Mcfe, which was 1% higher than the prior year. For 2016, cash flow from operations before changes in working capital was $1.3 billion, 31% higher than the prior year, in line with drilling and completion capital expenditures of $1.3 billion.

 

For a description of Adjusted EBITDAX and EBITDAX margin, cash flow from operations before changes in working capital and adjusted net income from continuing operations attributable to common stockholders and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”

 

2016 Capital Spending

 

Antero’s drilling and completion capital expenditures for the year ended December 31, 2016 were $1.3 billion, in line with guidance and a 21% decrease compared to the prior year.  In addition, the Company invested $153 million for land, excluding $593 million for leasehold and proved property acquisitions.  Antero Midstream invested $231 million for gathering and compression systems and $188 million for water infrastructure projects, including $149 million for the Antero Clearwater Treatment Facility.

 

Balance Sheet and Liquidity

 

As of December 31, 2016, Antero’s consolidated net debt was $4.7 billion, of which $650 million were borrowings outstanding under the Company’s and Antero Midstream’s revolving credit facilities.  Total borrowing capacity under these two facilities is currently $5.4 billion(1).  After deducting $710 million in letters of credit outstanding to support pipeline commitments, the Company had $4.0 billion in available consolidated liquidity as of December 31, 2016.  At year-end, the Company’s net debt to trailing twelve months adjusted EBITDAX ratio was 3.0-times. For a reconciliation of consolidated net debt to consolidated total debt, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.” For a description of adjusted EBITDAX to its nearest comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

(1)         Liquidity calculation assumes Antero Midstream’s borrowings under its credit facility limited to EBITDA covenant of 5.0x LTM EBITDA, less Senior Note Issuances as of December 31, 2016.

 

Hedge Position

 

The Company’s estimated natural gas production for 2017 is fully hedged at an average index price of $3.63 per MMBtu.  Antero’s target natural gas production for 2018 is also fully hedged at an average index price of $3.91 per MMBtu. Antero has hedged 3.4 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from January 1, 2017 through December 31, 2022 at an average index price of $3.63 per MMBtu.  At December 31, 2016, the Company’s estimated fair value of commodity derivative instruments was $1.6 billion.

 

7

 

The following table summarizes Antero’s hedge position as of December 31, 2016:

 

Period		Natural Gas MMBtu/d		Average Index price ($/MMBtu)			Liquids Bbl/d		Average Index price
1Q 2017:
Nymex Henry Hub		1,370,000		$	3.52		—		—
CGTLA		420,000		$	4.39		—		—
Chicago		70,000		$	4.76		—		—
Propane MB ($/Gal)		—		—			27,500		$	0.40
Ethane MB ($/Gal)		—		—			20,000		$	0.25
Nymex WTI ($/Bbl)		—		—			3,000		$	54.75
2Q 2017:
Nymex Henry Hub		1,370,000		$	3.26		—		—
CGTLA		420,000		$	4.13		—		—
Chicago		70,000		$	4.38		—		—
Propane MB ($/Gal)		—		—			27,500		$	0.38
Ethane MB ($/Gal)		—		—			20,000		$	0.25
Nymex WTI ($/Bbl)		—		—			3,000		$	54.75
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		$	3.63		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		1,367,500		$	3.66		—		—
2021:
Nymex Henry Hub		660,000		$	3.35		—		—
2022:
Nymex Henry Hub		760,000		$	3.20		—		—

 

(1)         Average index price is not applicable as 2017 liquids hedges include propane, ethane and oil hedges.

 

8

 

Conference Call

 

A conference call is scheduled on Wednesday, March 1, 2017 at 9:00 am MT to discuss the 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, March 10, 2017 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10098004.

 

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, March 10, 2017 at 9:00 am MT.

 

Presentation

 

An updated presentation will be posted to the Company’s website before the March 1, 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) and gain on sale of assets as set forth in this release represents total operating revenue adjusted for non-cash gains (losses) on unsettled hedges and gain on sale of assets.  Antero believes that revenue excluding unrealized hedge gains (losses) and gain on sale of assets 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) and gain on sale of assets 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) and gain on sale of assets (in thousands):

 

		Three months ended December 31,						Years ended December 31,
		2015			2016			2015			2016
Total operating revenue		$	905,122		$	156,216		$	3,954,858		$	1,744,525
Commodity derivative fair value (gains) losses		(545,103		)	639,805			(2,381,501		)	514,181
Cash receipts for settled hedges		269,933			189,524			856,572			1,003,083
Gain on sale of assets		—			(97,635		)	—			(97,635		)
Revenue excluding unrealized hedge gains (losses) and gain on sale of assets		$	629,952		$	887,910		$	2,429,929		$	3,164,154

 

Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items.  Antero believes that adjusted net income 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 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 (in thousands):

 

		Three months ended						Years ended
		December 31,						December 31,
		2015			2016			2015			2016
Net income (loss)		$	158,464		$	(485,772	)	$	941,364		$	(848,816	)
Non-cash commodity derivative (gains) losses on unsettled derivatives		(275,170		)	829,329			(1,524,929		)	1,517,264
Impairment of unproved properties		60,651			115,712			104,321			162,935
Equity-based compensation		18,597			26,754			97,877			102,421
Loss on early extinguishment of debt		—			16,956			—			16,956
Gain on sale of assets		—			(97,635		)	—			(97,635		)
Contract termination and rig stacking		27,629			—			38,531			—
Income tax effect of reconciling items		63,938			(337,179		)	495,215			(643,977		)
Adjusted net income		$	54,109		$	68,165		$	152,379		$	209,148

 

9

 

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 December 31,						Years ended December 31,
		2015			2016			2015			2016
Net cash provided by operating activities		$	174,658		$	335,559		$	1,015,812		$	1,241,256
Net change in working capital		63,965			68,859			(39,498		)	32,920
Cash flow from operations before changes in working capital		238,623			404,418			976,314			1,274,176

 

The following table reconciles consolidated total debt to consolidated net debt as used in this release (in thousands):

 

		December 31,			December 31,
		2015			2016
Bank credit facilities		$	1,327,000		$	650,000
6.00% AR senior notes due 2020		525,000			—
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
5.000% AR senior notes due 2025		—			600,000
Net unamortized premium		6,513			1,749
Net unamortized debt issuance costs		(39,731		)	(47,776		)
Consolidated total debt		$	4,668,782		$	4,703,973
Less: Cash and cash equivalents		23,473			31,610
Consolidated net debt		$	4,645,309		$	4,672,363

 

Adjusted EBITDAX is a non-GAAP financial measure that the Company defines as net income (loss) 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

10

 

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 by its lenders pursuant to covenants under its 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						Years ended
		December 31,						December 31,
		2015			2016			2015			2016
Net income (loss) from continuing operations including noncontrolling interest		$	175,574		$	(452,804	)	$	979,996		$	(749,448	)
Commodity derivative fair value (gains)		(545,103		)	639,805			(2,381,501		)	514,181
Gains on settled derivative instruments		269,933			189,524			856,572			1,003,083
Gain on sale of assets		—			(97,635		)	—			(97,635		)
Interest expense		60,471			67,918			234,400			253,552
Loss on early extinguishment of debt		—			16,956			—			16,956
Income tax expense (benefit)		77,181			(265,621		)	575,890			(496,376		)
Depreciation, depletion, amortization, and accretion		162,178			222,443			711,418			812,346
Impairment of unproved properties		60,651			115,712			104,321			162,935
Exploration expense		760			3,573			3,846			6,862
Equity-based compensation expense		18,597			26,754			97,877			102,421
Equity in loss (earnings) of unconsolidated affiliate		—			1,542			—			(485		)
Distributions from unconsolidated affiliate		—			7,702			—			7,702
State franchise taxes .		(59		)	11			72			50
Contract termination and rig stacking		27,629			—			38,531			—
Total Adjusted EBITDAX		307,812			475,880			1,221,422			1,536,144
Interest expense		(60,471		)	(67,918		)	(234,400		)	(253,552		)
Exploration expense		(760		)	(3,573		)	(3,846		)	(6,862		)
Changes in current assets and liabilities		(63,965		)	(68,859		)	39,498			(32,920		)
State franchise taxes		59			(11		)	(72		)	(50		)
Other non-cash items		(8,017		)	40			(6,790		)	(1,504		)
Net cash provided by operating activities		$	174,658		$	335,559		$	1,015,812		$	1,241,256

 

11

 

		Three months ended December 31,						Years ended December 31,
		2015			2016			2015			2016
Adjusted EBITDAX margin ($ per Mcfe):
Realized price before cash receipts for settled hedges		$	2.32		$	3.22		$	2.52		$	2.60
Gathering, compression, and water handling and treatment revenues		0.05			0.01			0.04			0.02
Distributions from unconsolidated affiliate		—			0.04			—			0.01
Lease operating expense		(0.08		)	(0.07		)	(0.07		)	(0.07		)
Gathering, compression, processing and transportation costs		(1.23		)	(1.27		)	(1.21		)	(1.31		)
Marketing, net		(0.38		)	(0.08		)	(0.23		)	(0.16		)
Production and ad valorem taxes		(0.15		)	(0.08		)	(0.14		)	(0.10		)
General and administrative(1)		(0.26		)	(0.21		)	(0.24		)	(0.20		)
Adjusted EBITDAX margin before settled hedges		0.27			1.56			0.67			0.79
Cash receipts for settled hedges		1.96			1.04			1.57			1.48
Adjusted EBITDAX margin ($ per Mcfe):		$	2.23		$	2.60		$	2.24		$	2.27

 

(1)         Excludes equity-based stock compensation that is included in G&A

 

Non-GAAP Disclosure

 

Certain selected financial information in this release is unaudited.  Audited financial results are provided in Antero’s Annual Report on Form 10-K for the year ended December 31, 2016, which the Company filed with the SEC on February 28, 2017.  In this release, Antero has provided a number of unaudited 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.

 

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.

 

In this press release, Antero uses terms such as “resource potential” to describe potentially recoverable hydrocarbon quantities that are not permitted to be used in filings with the SEC.  Antero includes these estimates to demonstrate what management believes to be the potential for future drilling and production on our properties.  These estimates are by their nature much more speculative than estimates of proved reserves and would require substantial additional capital spending over significant number of years to implement recovery.  Actual quantities that may be ultimately recovered from Antero’s interests may differ substantially from the estimates in this press release.  Factors affecting ultimate recovery include the scope of Antero’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates.

 

The SEC permits oil and gas companies to disclose probable and possible reserves in their filings with the SEC. Antero does not plan to include probable and possible reserve estimates in its filings with the SEC.  Antero has provided internally generated estimates that have been audited by its third party reserve engineer in this release.  Antero’s estimate of proved, probable and possible reserves is provided in this release because management believes it is useful information that is widely

 

12

 

used by the investment community in the valuation, comparison and analysis of companies.  However, the Company notes that the SEC prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category.

 

This release provides a summary of Antero’s reserves as of December 31, 2016, assuming partial ethane “rejection” where sales demand for ethane is not available.  Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation.  When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher.  Producers will generally elect to “reject” ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs.  When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product.  In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.

 

For more information, contact Michael Kennedy — SVP — Finance, at (303) 357-6782 or mkennedy@anteroresources.com.

 

13

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2015 and December 31, 2016

(In thousands, except per share amounts)

 

		2015			2016
Assets
Current assets:
Cash and cash equivalents		$	23,473		31,610
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016		79,404			29,682
Accrued revenue		128,242			261,960
Derivative instruments		1,009,030			73,022
Other current assets		8,087			6,313
Total current assets		1,248,236			402,587
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		1,996,081			2,331,173
Proved properties		8,211,106			9,549,671
Water handling and treatment systems		565,616			744,682
Gathering systems and facilities		1,502,396			1,723,768
Other property and equipment		46,415			41,231
		12,321,614			14,390,525
Less accumulated depletion, depreciation, and amortization		(1,589,372		)	(2,363,778	)
Property and equipment, net		10,732,242			12,026,747
Derivative instruments		2,108,450			1,731,063
Other assets		26,565			95,153
Total assets		$	14,115,493		14,255,550
Liabilities and Equity
Current liabilities:
Accounts payable		$	69,911		38,627
Accrued liabilities		488,325			393,803
Revenue distributions payable		129,949			163,989
Derivative instruments		—			203,635
Other current liabilities		19,085			17,334
Total current liabilities		707,270			817,388
Long-term liabilities:
Long-term debt		4,668,782			4,703,973
Deferred income tax liability		1,370,686			950,217
Derivative instruments		—			234
Other liabilities		82,077			55,160
Total liabilities		6,828,815			6,526,972
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 277,036 shares and 314,877 shares, respectively		2,770			3,149
Additional paid-in capital		4,122,811			5,299,481
Accumulated earnings		1,808,811			959,995
Total stockholders’ equity		5,934,392			6,262,625
Noncontrolling interest in consolidated subsidiary		1,352,286			1,465,953
Total equity		7,286,678			7,728,578
Total liabilities and equity		$	14,115,493		14,255,550

 

14

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income

Years Ended December 31, 2014, 2015 and 2016
(In thousands, except per share amounts)

 

		2014			2015		2016
Revenue and other:
Natural gas sales		$	1,301,349		1,039,892		1,260,750
Natural gas liquids sales		328,323			264,483		432,992
Oil sales		107,080			70,753		61,319
Gathering, compression, and water handling and treatment		22,075			22,000		12,961
Marketing		53,604			176,229		393,049
Commodity derivative fair value gains (losses)		868,201			2,381,501		(514,181	)
Gain on sale of assets		40,000			—		97,635
Total revenue and other		2,720,632			3,954,858		1,744,525
Operating expenses:
Lease operating		29,341			36,011		50,090
Gathering, compression, processing, and transportation		461,413			659,361		882,838
Production and ad valorem taxes		87,918			78,325		66,588
Marketing		103,435			299,062		499,343
Exploration		27,893			3,846		6,862
Impairment of unproved properties		15,198			104,321		162,935
Depletion, depreciation, and amortization		477,896			709,763		809,873
Accretion of asset retirement obligations		1,271			1,655		2,473
General and administrative (including equity-based compensation expense of $112,252, $97,877, and $102,421 in 2014, 2015, and 2016, respectively)		216,533			233,697		239,324
Contract termination and rig stacking		—			38,531		—
Total operating expenses		1,420,898			2,164,572		2,720,326
Operating income (loss)		1,299,734			1,790,286		(975,801	)
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—			—		485
Interest		(160,051		)	(234,400	)	(253,552	)
Loss on early extinguishment of debt		(20,386		)	—		(16,956	)
Total other expenses		(180,437		)	(234,400	)	(270,023	)
Income (loss) before income taxes		1,119,297			1,555,886		(1,245,824	)
Provision for income tax (expense) benefit		(445,672		)	(575,890	)	496,376
Income (loss) from continuing operations		673,625			979,996		(749,448	)
Discontinued operations:
Income from sale of discontinued operations, net of income tax expense of $1,354 in 2014		2,210			—		—
Net income (loss) and comprehensive income (loss) including noncontrolling interest		675,835			979,996		(749,448	)
Net income and comprehensive income attributable to noncontrolling interest		2,248			38,632		99,368
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation		$	673,587		941,364		(848,816	)
Earnings (loss) per common share—basic:
Continuing operations		$	2.56		3.43		(2.88	)
Discontinued operations		0.01			—		—
Total		$	2.57		3.43		(2.88	)
Earnings (loss) per common share—assuming dilution:
Continuing operations		$	2.56		3.43		(2.88	)
Discontinued operations		0.01			—		—
Total		$	2.57		3.43		(2.88	)
Weighted average number of shares outstanding:
Basic		262,054			274,123		294,945
Diluted		262,068			274,143		294,945

 

15

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Years Ended December 31, 2014, 2015 and 2016

(In thousands)

 

		Year Ended December 31,
		2014			2015		2016
Cash flows from operating activities:
Net income (loss) including noncontrolling interest		$	675,835		979,996		(749,448	)
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		479,167			711,418		812,346
Impairment of unproved properties		15,198			104,321		162,935
Derivative fair value (gains) losses		(868,201		)	(2,381,501	)	514,181
Gains on settled derivatives		135,784			856,572		1,003,083
Deferred income tax expense (benefit)		445,672			575,890		(485,392	)
Gain on sale of assets		(40,000		)	—		(97,635	)
Equity-based compensation expense		112,252			97,877		102,421
Loss on early extinguishment of debt		20,386			—		16,956
Gain on sale of discontinued operations		(3,564		)	—		—
Deferred income tax expense—discontinued operations		1,354			—		—
Equity in earnings of unconsolidated affiliate		—			—		(485	)
Distributions of earnings from unconsolidated affiliates		—			—		7,702
Other		6,433			31,741		(12,488	)
Changes in current assets and liabilities:
Accounts receivable		(45,593		)	(3,201	)	39,857
Accrued revenue		(94,733		)	63,316		(133,718	)
Other current assets		(2,891		)	(2,221	)	1,774
Accounts payable		(20,681		)	(8,536	)	7,365
Accrued liabilities		95,066			36,377		18,853
Revenue distributions payable		85,763			(52,403	)	34,040
Other current liabilities		1,016			6,166		(1,091	)
Net cash provided by operating activities		998,263			1,015,812		1,241,256
Cash flows used in investing activities:
Additions to proved properties		(64,066		)	—		(134,113	)
Additions to unproved properties		(777,422		)	(198,694	)	(611,631	)
Drilling and completion costs		(2,477,150		)	(1,651,282	)	(1,327,759	)
Additions to water handling and treatment systems		(196,675		)	(131,051	)	(188,188	)
Additions to gathering systems and facilities		(558,037		)	(360,287	)	(231,044	)
Additions to other property and equipment		(13,218		)	(6,595	)	(2,694	)
Investment in unconsolidated affiliate		—			—		(75,516	)
Change in other assets		(3,082		)	9,750		3,977
Proceeds from asset sales		—			40,000		171,830
Net cash used in investing activities		(4,089,650		)	(2,298,159	)	(2,395,138	)
Cash flows from financing activities:
Issuance of common stock		—			537,832		1,012,431
Issuance of common units by Antero Midstream Partners LP		1,087,224			240,703		65,395
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation		—			—		178,000
Issuance of senior notes		1,102,500			750,000		1,250,000
Repayment of senior notes		(260,000		)	—		(525,000	)
Repayments on bank credit facilities, net		1,442,000			(403,000	)	(677,000	)
Make-whole premium on debt extinguished		(17,383		)	—		(15,750	)
Payments of deferred financing costs		(31,543		)	(17,293	)	(18,759	)
Distributions to noncontrolling interest in consolidated subsidiary		—			(34,129	)	(75,082	)
Employee tax withholding for settlement of equity compensation awards		(142		)	(9,431	)	(26,895	)
Other		(2,777		)	(4,841	)	(5,321	)
Net cash provided by financing activities		3,319,879			1,059,841		1,162,019
Net increase (decrease) in cash and cash equivalents		228,492			(222,506	)	8,137
Cash and cash equivalents, beginning of period		17,487			245,979		23,473
Cash and cash equivalents, end of period		$	245,979		23,473		31,610
Supplemental disclosure of cash flow information:
Cash paid during the period for interest		$	163,055		219,945		239,369
Supplemental disclosure of noncash investing activities:
Increase (decrease) in accounts payable and accrued liabilities for additions to property and equipment		$	181,591		(169,783	)	(152,093	)

 

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