Exhibit 99.1

 

 

Antero Resources Reports Fourth Quarter and Full Year 2017 Financial and Operating Results

 

Denver, Colorado, February 13, 2018—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its fourth quarter and full year 2017 financial and operational results.  The relevant consolidated and consolidating financial statements are included in Antero’s Annual Report on Form 10-K for the year ended December 31, 2017, which has been filed with the Securities and Exchange Commission (“SEC”).  The relevant Stand-Alone E&P financial statements are also included in Antero’s Form 10-K within the Parent column of the guarantor footnote (Note 18).

 

Fourth Quarter 2017 Highlights and Updated 2018 Guidance:

 

·                  Net daily gas equivalent production averaged a record 2,347 MMcfe/d (27% liquids), an 18% increase over the prior year period

·                  Liquids production averaged 107,433 Bbl/d, a 24% increase over the prior year period, and contributed 41% of total product revenues (before hedging)

·                  Realized C3+ NGL price of $39.16 per barrel, which is 71% of NYMEX WTI price, before hedging

·                  Realized natural gas price of $2.80 per Mcf, a $0.13 per Mcf negative differential to the average NYMEX natural gas price, before hedging

·                  Realized a combined natural gas equivalent price of $3.46 per Mcfe before hedges, driven by a $0.66 per Mcfe uplift from NGL and oil production and pricing

·                  Realized natural gas equivalent price of $3.82 per Mcfe including NGLs, oil and hedges

·                  GAAP net income of $487 million, or $1.54 per diluted share, adjusted net income of $74 million, or $0.23 per diluted share, and Stand-Alone E&P adjusted net income of $55 million

·                  Adjusted EBITDAX of $437 million and Stand-Alone E&P adjusted EBITDAX of $372 million

·                  Corporate debt ratings improved to Ba2/BB+/BBB- (Moody’s/S&P/Fitch)

·                  Reducing 2018 net marketing expense guidance to a range of $0.10 to $0.125 per Mcfe (from a range of $0.10 to $0.15 Mcfe) and forecasting a first quarter 2018 net marketing gain

 

Full Year 2017 Highlights:

 

·                  Net daily gas equivalent production averaged 2,253 MMcfe/d (28% liquids), a 22% increase over the prior year

·                  GAAP net income of $615 million, or $1.94 per diluted share, adjusted net income of $103 million, or $0.33 per diluted share, and Stand-Alone E&P adjusted net income of $71 million

·                  Adjusted EBITDAX of $1.46 billion and Stand-Alone E&P adjusted EBITDAX of $1.24 billion

·                  Drilling & completion capital expenditures of $1.282 billion, 1% below guidance

·                  Stand-Alone E&P net debt to trailing twelve months adjusted EBITDAX was 2.9x with over $1.6 billion of liquidity

 

2018 Guidance Update

 

The Company’s first quarter 2018 net production is estimated to be flat with the fourth quarter 2017 net production due primarily to the timing of completions throughout 2018, the impact from severe winter weather on the Sherwood processing plant operations in the West Virginia Marcellus in the early part of January, and a shutdown for several days at the Seneca plant in the Ohio Utica due to a third-party downstream pipeline rupture.  Both of these processing plant issues have since been rectified.  The Company continues to expect to meet its full year 2018 net production guidance of approximately 2.7 Bcfe/d.  Additionally, the extreme cold weather in January resulted in attractive pricing on natural gas sales and the ability to generate significant marketing revenues during the first

 

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quarter of 2018 that more than offset the reduced production.  Antero is now forecasting a net marketing gain for the first quarter of 2018 and is reducing its net marketing expense guidance for the full year of 2018 to a range of $0.10/Mcfe to $0.125/Mcfe.

 

“During 2017, Antero reached an inflection point by executing on its long-term strategic plan,” commented Paul Rady, Chairman and CEO.  “We are now positioned to generate free cash flow and reduce financial leverage, while maintaining a 20%-plus debt-adjusted production growth profile.  We were pleased to host our first Analyst Day last month, where we highlighted a clear, measurable plan to achieve these goals.  Our proven operational track record coupled with our high-quality liquids-rich asset portfolio gives us confidence in delivering on this plan.”

 

Financial and operational results are reported and discussed on a consolidated basis, unless otherwise noted.  Please read “Non-GAAP Financial Measures” for:

 

·                  A description of consolidated and Stand-Alone E&P non-GAAP measures, including adjusted EBITDAX and adjusted net income, and reconciliations to their nearest comparable GAAP measures

·                  A reconciliation of revenue excluding unrealized hedge gains (losses) and unrealized marketing derivative losses to operating revenue, the most comparable GAAP measure

·                  A reconciliation of net debt to total debt, the most comparable GAAP measure

·                  A reconciliation of Antero Midstream’s adjusted EBITDA and Distributable Cash Flow to their nearest comparable GAAP measure

 

Please read “Fourth Quarter 2017 Financial Results” and “2017 Financial Results” for reconciliations of consolidated and Stand-Alone E&P adjusted EBITDAX margin to realized price before cash receipts for settled hedges, the most comparable GAAP measure.

 

Tax Reform

 

As a result of the new tax legislation that was enacted in late December, the following items affecting Antero have occurred:

 

·                  The Company recognized a deferred tax benefit of $428 million in the fourth quarter primarily due to the remeasurement of the Company’s net deferred tax liability for the reduction in the U.S. statutory rate from 35% to 21%.

 

·                  Under the new tax legislation, Antero is limited in the utilization of net operating loss (“NOLs”) carryforwards generated after tax year 2017 to 80% of taxable income. As a result, the Company deducted all of its intangible drilling costs for U.S. federal income tax purposes for tax year 2017 in order to maximize the NOLs generated prior to tax year 2018, which are not subject to the 80% limitation. The deduction of the intangible drilling costs resulted in an increase in NOLs from approximately $1.6 billion at December 31, 2016 to $3.0 billion at December 31, 2017.

 

Other significant provisions that are not yet effective, but may impact income taxes in future years, are included in Antero’s Form 10-K under the 2017 Recent Developments and Highlights (Part I, Items 1 and 2).

 

Fourth Quarter 2017 Financial Results

 

As of December 31, 2017, Antero owned a 53% limited partner interest in Antero Midstream.  Antero Midstream’s results are consolidated within Antero’s results.

 

Antero reported fourth quarter net income of $487 million, or $1.54 per diluted share, compared to a net loss of $486 million, or $1.55 per diluted share, in the prior year period.  Excluding the items detailed in our “Non-GAAP Financial Measures,” fourth quarter adjusted net income was $74 million, or $0.23 per diluted share, and adjusted EBITDAX was $437 million.

 

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The following table details the components of average net production and average realized prices for the three months ended December 31, 2017:

 

		Three Months Ended December 31, 2017
		Gas (MMcf/d)		Oil (Bbl/d)		C3+ NGLs (Bbl/d)		Ethane (Bbl/d)		Combined Gas Equivalent (MMcfe/d)
Average Net Production		1,702		6,207		69,801		31,425		2,347

 

Average Realized Prices		Gas ($/Mcf)			Oil ($/Bbl)			C3+ NGLs ($/Bbl)			Ethane ($/Bbl)			Combined Gas Equivalent ($/Mcfe)
Average realized price before settled derivatives		$	2.80		$	49.37		$	39.16		$	10.02		$	3.46
Settled derivatives		0.87			(0.31		)	(9.24		)	0.15			0.36
Average realized price after settled derivatives		$	3.67		$	49.06		$	29.92		$	10.17		$	3.82
NYMEX average price		$	2.93		$	55.37								$	2.93
Premium / (Differential) to NYMEX		$	0.74		$	(6.31	)							$	0.89

 

Net daily production in the fourth quarter averaged 2,347 MMcfe/d, including 107,433 Bbl/d of liquids (27% liquids), representing an organic growth rate of 18% versus the prior year period and a 1% increase sequentially.  Production was negatively impacted by the delayed in-service date of the Rover Pipeline, resulting in an approximate 45 day delay in placing 10 newly completed Utica wells to sales until the end of 2017.  C3+ NGLs, oil, and recovered ethane production averaged 69,801 Bbl/d, 6,207 Bbl/d, and 31,425 Bbl/d, respectively.  Total liquids production represents an organic growth rate of 24% versus the prior year period and a 4% decrease sequentially.  The sequential decline in liquids production was a result of higher NGL allocations to royalty owners due to the improvement in liquids pricing.  Liquids revenue represented approximately 41% of total product revenues, increasing from 30% of total product revenues in the prior year period.

 

Antero’s average realized natural gas price before hedging decreased 8% from the prior year period to $2.80 per Mcf, a $0.13 per Mcf differential to the average NYMEX price.  Excluding the $0.20 negative impact from the Company’s previously disclosed natural gas contract disputes with South Jersey Gas Company and South Jersey Resources Group, LLC (collectively, “SJGC”) and Washington Gas Light Company and WGL Midstream, Inc. (collectively, “WGL”), the average natural gas price before hedging would have been $3.00 per Mcf, a $0.07 premium to the average NYMEX natural gas price.  In 2018, Antero does not expect a material impact to its realized price and cash flow from these contractual disputes due to both additional takeaway capacity that is expected to be placed in service throughout the year and narrower regional basis differentials based on current strip pricing.  Additionally, Antero recently amended its natural gas sales contract with WGL Midstream, Inc.  As a result, effective February 1, 2018 the total aggregate volumes to be delivered to WGL at the delivery point in Braxton County, West Virginia were reduced from 500,000 MMBtu/d to 200,000 MMBtu/d.  Upon both (1) the in service of the Dominion Cove Point LNG facility and (2) the earlier of in service of the WB East expansion and January 1, 2019, the aggregate contract volumes to be delivered to WGL will increase by 330,000 MMBtu/day.  This increase will be in effect for the remaining term of our gas sales contract with WGL Midstream, which expires in 2038, and these increased volumes will be subject to NYMEX-based pricing.  Following the increase of 330,000 MMBtu/d, the aggregate contract volumes to be delivered to WGL will total 530,000 MMBtu/d.  Antero will continue to vigorously seek recovery from SJGC and WGL of all unpaid amounts, including interest, as part of its pending claims against these counterparties.  Through December 31, 2017, damages net to Antero have totaled approximately $86 million for WGL and $51 million for SJGC. Substantially all of these amounts have not been accrued in the Company’s financial statements.

 

Including hedges, Antero’s average realized natural gas price was $3.67 per Mcf, a $0.74 premium to the NYMEX average price and consistent with the prior year period, reflecting the realization of a cash settled natural gas hedge gain of $136 million, or $0.87 per Mcf.

 

Antero’s average realized C3+ NGL price before hedging was $39.16 per barrel, or 71% of the average NYMEX WTI oil price, representing a 55% increase versus the prior year period.  Including hedges, Antero’s average realized C3+ NGL price was $29.92 per barrel, a 17% increase versus the prior year period, reflecting the realization of a cash settled C3+ hedge loss of $59 million, or $9.24

 

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per barrel.  The average realized ethane price before hedging was $0.24 per gallon, or $10.02 per barrel, and the average realized oil price before hedging was $49.37 per barrel, a $6.00 negative differential to average NYMEX WTI and a 26% increase versus the prior year period.

 

Antero’s average natural gas equivalent price including C2+ NGLs and oil, but excluding hedge settlements, was $3.46 per Mcfe, an increase of 7% versus the prior year period.  Including hedges, the Company’s average natural gas equivalent price was $3.82 per Mcfe, a 10% decrease from the prior year period, driven by lower realized hedge gains compared to the prior year period.  The net cash settled hedge gain on all products was $77 million, or $0.35 per Mcfe, primarily reflecting the impact of gains on natural gas hedges partially offset by losses from C3+ hedges.

 

Operating revenues were $1.022 billion, compared to $156 million in the prior year period.  Revenue included a $123 million non-cash gain on unsettled hedges and a $21 million loss on unsettled marketing derivatives, while the prior year included an $829 million non-cash loss on unsettled hedges and a $98 million gain on the sale of assets.  Revenue excluding the unrealized hedge gain and unrealized marketing derivative loss was $920 million, a 4% increase versus the prior year period.  Liquids production contributed 41% of total product revenues before hedges, compared to a 30% contribution in the prior year period.  Please see “Non-GAAP Financial Measures” for a description of revenue excluding the unrealized hedge gain and unrealized marketing derivative loss.

 

The following table presents a reconciliation of realized price before cash receipts for settled hedges to consolidated and Stand-Alone adjusted EBITDAX margin for the three months ended December 31, 2016 and 2017:

 

		Stand-Alone E&P Three Months Ended						Consolidated Three Months Ended
		December 31,						December 31,
		2016			2017			2016			2017
Adjusted EBITDAX margin ($ per Mcfe):
Realized price before cash receipts for settled hedges		$	3.22		$	3.46		$	3.22		$	3.46
Gathering, compression, and water handling and treatment revenues		N/A			N/A			0.01			0.02
Distributions from unconsolidated affiliate		N/A			N/A			0.04			0.05
Distributions from Antero Midstream		0.16			0.16			N/A			N/A
Gathering, compression, processing and transportation costs		(1.68		)	(1.71		)	(1.27		)	(1.30		)
Lease operating expense		(0.07		)	(0.17		)	(0.07		)	(0.15		)
Marketing, net		(0.08		)	(0.13		)	(0.08		)	(0.13		)
Production and ad valorem taxes		(0.10		)	(0.11		)	(0.08		)	(0.11		)
General and administrative(1)		(0.17		)	(0.13		)	(0.21		)	(0.17		)
Adjusted EBITDAX margin before settled hedges		1.28			1.37			1.56			1.67
Cash receipts for settled hedges		1.04			0.35			1.04			0.35
Adjusted EBITDAX margin ($ per Mcfe):		$	2.32		1.72			$	2.60		$	2.02

 

(1)         Excludes non-cash equity-based compensation

 

Per unit cash production expense (lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes) was $1.56 per Mcfe, a 10% increase compared to $1.42 per Mcfe in the prior year period.  The per unit cash production expense for the quarter included $0.15 per Mcfe for lease operating costs, $1.30 per Mcfe for gathering, compression, processing and transportation costs and $0.11 per Mcfe for production and ad valorem taxes.  The increase in lease operating expenses to $0.15 per Mcfe in the fourth quarter is due to an increase in produced water on new well pads, which is attributable to an increase in the amount of water used in our advanced well completions throughout the year, and a one-time impact from well pad slip repairs.  In 2018, Antero expects lease operating expenses to decline due to lower costs to truck produced water to Antero’s Clearwater facility as compared to trucking to water disposal sites.

 

Per unit general and administrative expense, excluding non-cash equity-based compensation expense, was $0.17 per Mcfe, a 19% decrease from the prior year period.  Per unit depreciation, depletion and amortization expense declined by 19% from the prior year to $0.99 per Mcfe, primarily due to an increase in estimated recoverable reserves, improved well performance, and a decrease in per-unit development costs.

 

Adjusted EBITDAX was $437 million, at the high end of the Company’s previously announced guidance range of $410 million to $440 million.  Adjusted EBITDAX margin before settled hedges for the quarter was $1.67, a 6% increase from the prior year period.  Adjusted EBITDAX margin including hedges, was $2.02 per Mcfe, a 22% decrease from the prior year period due to lower realized

 

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hedge gains.  Stand-Alone E&P Adjusted EBITDAX was $372 million for the fourth quarter of 2017.  Stand-Alone E&P adjusted EBITDAX margin was $1.37 per Mcfe before settled hedges and $1.72 per Mcfe including settled hedges for the quarter.

 

Adjusted Operating Cash Flow was $368 million during the fourth quarter, compared to $404 million in the prior year period.  Stand-Alone E&P Adjusted Operating Cash Flow was $312 million, compared to $361 million in the prior year period.  Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow declined versus the prior year period due to lower realized hedge gains.

 

Operating Update

 

Fourth Quarter 2017

 

Marcellus Shale — Antero completed and placed on line 28 horizontal Marcellus wells during the fourth quarter of 2017.  Current average well costs are $0.87 million per 1,000’ of lateral in the Marcellus assuming a 9,000’ lateral and 2,000 pounds of proppant per foot completion, representing a 2% reduction from the third quarter of 2017. Antero is operating five drilling rigs and five completion crews in the Marcellus Shale play.

 

Antero drilled 27 horizontal Marcellus wells during the fourth quarter, including nine wells that had laterals greater than 12,000’.  Antero recently drilled its two longest Marcellus laterals, both over 14,000’, on a 12 well pad. This is the Company’s largest pad to date, with approximately 120,000’ of drilled lateral planned and approximately 300 Bcfe in anticipated pad reserves assuming 25% ethane recovery.  Antero is in the process of drilling a nine well pad with average lateral lengths of 13,200’ which the Company expects to place to sales in the first quarter of 2019.

 

Ohio Utica Shale — Antero placed 10 horizontal Utica wells to sales at the end of the fourth quarter of 2017.  The 10 wells are currently flowing at a combined (facility) constrained rate of over 200 MMcf/d with wellhead pressures in excess of 3,000 psi.  These are the first wells completed by Antero in the Ohio Utica dry gas regime.  Despite running only one rig since 2016, Antero recently achieved record gross production in the Utica of 632 MMcf/d with only 22 wells completed during 2017.  Current average well costs are $0.98 million per 1,000 feet of lateral in the Utica, representing a 2% reduction from the third quarter of 2017.  Antero is operating one drilling rig and one completion crew in the Utica Shale play.

 

2017 Performance Highlights

 

Antero achieved a number of operational successes during the year including:

 

Marcellus Shale

 

·                  Drilled the longest Marcellus lateral in Company history at 14,376’

·                  Achieved 16 of the Company’s top 20 drilling lateral footage days during the year

·                  Over 25% of wells drilled averaged greater than one mile per day of drilling for the entire lateral

·                  Achieved the fewest total days to drill an entire well at 8.4 days

·                  Record Marcellus lateral footage drilled for one day of 8,178’

 

Ohio Utica Shale

 

·                  Drilled the longest Utica lateral in Company history at 17,445’

·                  Achieved 13 of the Company’s top 20 lateral footage days during the year

·                  Achieved a record Utica lateral footage drilled for one day of 5,029’

·                  Recently achieved record production with only one rig running during the year

 

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Antero Midstream Financial Results

 

Antero Midstream results were released today and are available at www.anteromidstream.com.  A summary of the results are provided below:

 

		Three Months Ended December 31,
		2016		2017		% Change
Average Daily Volumes:
Low Pressure Gathering (MMcf/d)		1,522		1,711		12	%
Compression (MMcf/d)		920		1,355		47	%
High Pressure Gathering (MMcf/d)		1,437		1,842		28	%
Fresh Water Delivery (MBbl/d)		150		149		(1	)%
Gross Joint Venture Processing (MMcf/d)		—		425		*
Gross Joint Venture Fractionation (Bbl/d)		—		9,096		*

 

*                 Not applicable.  Antero Midstream has a 50% interest in a processing and fractionation Joint Venture with MarkWest, a wholly-owned subsidiary of MPLX, which was formed in February 2017.

 

Net income for the fourth quarter of 2017 was $64 million, a 13% decrease compared to the prior year quarter. The decrease in net income was driven by a $23 million non-cash impairment expense of the condensate pipelines in the Utica not expected to be utilized in Antero Midstream’s high-graded infrastructure plan.  Net income per limited partner unit was $0.22, a 41% decrease compared to the prior year quarter. Adjusted EBITDA was $142 million, a 13% increase compared to the prior year quarter. The increase in Adjusted EBITDA is primarily driven by increased throughput volumes and contribution from the Joint Venture.  Distributable Cash Flow for the fourth quarter of 2017 was $117 million, resulting in a DCF coverage ratio of 1.3x.  Distributable Cash Flow is a non-GAAP financial measure.  For a description of Distributable Cash Flow and reconciliation to its nearest GAAP measure, please read “Non-GAAP Financial Measures.”

 

Antero Midstream declared a distribution of $0.34 per limited partner unit attributable to the third quarter of 2017, resulting in $34 million of distributions received from Antero Midstream during the fourth quarter of 2017. On January 16, 2018 Antero Midstream declared a distribution of $0.365 per limited partner unit attributable to the fourth quarter of 2017.

 

Fourth Quarter 2017 Capital Investment

 

Antero’s drilling and completion capital expenditures for the three months ended December 31, 2017, were $335 million.  In addition, the Company invested $22 million for land, $92 million for gathering and compression systems and $51 million for water infrastructure projects, including $25 million for the Antero Clearwater Treatment Facility.

 

2017 Full Year Financial Results

 

For the year ending December 31, 2017, Antero’s net daily production averaged 2,253 MMcfe/d, including 105,470 Bbl/d of liquids (28%).  Reported net income was $615 million, or $1.94 per diluted share.  Excluding the items detailed in the Company’s “Non-GAAP Financial Measures,” adjusted net income was $103 million, or $0.33 per diluted share, and adjusted EBITDAX was $1.46 billion. Adjusted EBITDAX margin before settled hedges for the year was $1.52, 92% above the prior year period.  Adjusted EBITDAX margin including settled hedges for 2017 was $1.78 per Mcfe, 22% below prior year levels due to lower realized hedge gains.  Stand-Alone E&P adjusted EBITDAX for 2017 was $1.24 billion, or $1.51 per Mcfe, 10% below prior year levels due to lower realized hedge gains.

 

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The following table presents a reconciliation of realized price before cash receipts for settled hedges to consolidated and Stand-Alone adjusted EBITDAX margin for the year ended December 31, 2016 and 2017:

 

		Stand-Alone E&P Years Ended					Consolidated Years Ended
		December 31,					December 31,
		2016			2017		2016			2017
Adjusted EBITDAX margin ($ per Mcfe):
Realized price before cash receipts for settled hedges		$	2.60		3.34		$	2.60		$	3.34
Gathering, compression, and water handling and treatment revenues		N/A			N/A		0.02			0.02
Distributions from unconsolidated affiliate		N/A			N/A		0.01			0.02
Distributions from Antero Midstream		0.16			0.16		N/A			N/A
Gathering, compression, processing and transportation costs		(1.70		)	(1.75	)	(1.31		)	(1.33		)
Lease operating expense		(0.07		)	(0.11	)	(0.07		)	(0.11		)
Marketing, net		(0.16		)	(0.13	)	(0.16		)	(0.13		)
Production and ad valorem taxes		(0.10		)	(0.11	)	(0.10		)	(0.11		)
General and administrative(1)		(0.16		)	(0.15	)	(0.20		)	(0.18		)
Adjusted EBITDAX margin before settled hedges		0.57			1.25		0.79			1.52
Cash receipts for settled hedges		1.48			0.26		1.48			0.26
Adjusted EBITDAX margin ($ per Mcfe):		$	2.05		1.51		$	2.27		$	1.78

 

(1)         Excludes non-cash equity-based compensation

 

2017 Capital Investment

 

In 2017, Antero’s drilling and completion capital expenditures were $1.282 billion, 1% below guidance and a 3% decrease compared to the prior year.  In addition, the Company invested $204 million for land, excluding $176 million for proved property acquisitions, $346 million for gathering and compression systems, and $195 million for water infrastructure projects, including $123 million for the Antero Clearwater Treatment Facility.

 

Balance Sheet and Liquidity

 

As of December 31, 2017, Antero’s Stand-Alone E&P net debt was $3.6 billion, of which $185 million were borrowings outstanding under the Company’s revolving credit facility.  Total lender commitments under this facility are $2.5 billion.  After deducting $705 million in letters of credit outstanding to support pipeline commitments, the Company had $1.6 billion in available Stand-Alone E&P liquidity.  As of December 31, 2017, Antero’s Stand-Alone E&P net debt to trailing twelve months adjusted EBITDAX ratio was 2.9x.

 

President and CFO, Glen Warren, commented, “We expect to see a declining leverage profile over the next year as a result of spending within growing cash flow, reduced unutilized marketing expense and fully hedged gas production at $3.50 per MMBtu.  The recent decision by S&P to upgrade Antero’s corporate debt to BB+ and the initiation by Fitch of a BBB- rating is recognition of Antero’s ability to deliver on these strategic and financial goals.”

 

Commodity Hedge Positions

 

The Company’s estimated natural gas production for 2018 at the midpoint of guidance is fully hedged at an average index price of $3.50 per MMBtu.  Antero’s target natural gas production for 2019 is also fully hedged at an average index price of $3.50 per MMBtu. Antero has hedged 2.8 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from January 1, 2018, through December 31, 2023, at an average index price of $3.39 per MMBtu.  As of December 31, 2017, the Company’s estimated fair value of commodity derivative instruments was $1.3 billion.

 

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The following table summarizes Antero’s hedge position as of December 31, 2017:

 

Period		Natural Gas MMBtu/d		Average Index price ($/MMBtu)			Liquids Bbl/d		Average Index price
1Q 2018:
NYMEX Henry Hub		2,002,500		$	3.60		—		—
Propane MB ($/Gal)		—		—			19,000		$	0.75
NYMEX WTI ($/Bbl)		—		—			4,000		$	55.97
2Q 2018:
NYMEX Henry Hub		2,002,500		$	3.42		—		—
Propane MB ($/Gal)		—		—			19,000		$	0.75
NYMEX WTI ($/Bbl)		—		—			4,000		$	55.97
3Q 2018:
NYMEX Henry Hub		2,002,500		$	3.45		—		—
Propane MB ($/Gal)		—		—			19,000		$	0.75
NYMEX WTI ($/Bbl)		—		—			4,000		$	55.97
4Q 2018:
NYMEX Henry Hub		2,002,500		$	3.53		—		—
Propane MB ($/Gal)		—		—			19,000		$	0.75
NYMEX WTI ($/Bbl)		—		—			4,000		$	55.97
2018 Total(1)		2,002,500		$	3.50		23,000		N/A		(2)
2019:
NYMEX Henry Hub		2,330,000		$	3.50		—		—
2020:
NYMEX Henry Hub		1,417,500		$	3.25		—		—
2021:
NYMEX Henry Hub		710,000		$	3.00		—		—
2022:
NYMEX Henry Hub		850,000		$	3.00		—		—
2023:
NYMEX Henry Hub		90,000		$	2.91		—		—

 

(1)         Since December 31, 2017, Antero has added an incremental 7,000 Bbl/d of Propane MB hedges at $0.80/Gal and 2,000 Bbl/d of NYMEX WTI hedges at $59.03/Bbl

(2)         Average index price is not applicable as 2018 liquids hedges include propane and oil hedges.

 

Conference Call

 

A conference call is scheduled on Wednesday, February 14, 2018 at 9:00 am MT to discuss the quarterly results.  A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter and full year.  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 Wednesday, February 21, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10114470.

 

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 Wednesday, February 21, 2018 at 9:00 am MT.

 

8

 

Presentation

 

An updated presentation will be posted to the Company’s website before the February 14, 2018 conference call.  The presentation can be found at www.anteroresources.com on the homepage.  Information on the Company’s website does not constitute a portion of this press release.

 

Non-GAAP Financial Measures

 

Revenue Excluding Unrealized Hedge Gains (Losses) and Gain on Sale of Assets

 

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,
		2016			2017			2016			2017
Total operating revenue		$	156,216		$	1,021,726		$	1,744,525		$	3,655,574
Commodity derivative fair value (gains) losses		639,805			(178,430		)	514,181			(636,889		)
Cash receipts for settled hedges		189,524			76,548			1,003,083			213,940
Gain on sale of assets		(97,635		)	—			(97,635		)	—
Revenue excluding unrealized hedge gains (losses) and gain on sale of assets		$	887,910		$	919,844		$	3,164,154		$	3,232,625

 

Adjusted Net Income & Stand-Alone E&P Adjusted Net Income

 

Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items.  Stand-Alone E&P adjusted net income as presented in this release represents net income (loss) that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements, adjusted for certain items.  Antero believes that adjusted net income 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 and Stand-Alone E&P adjusted net income are not measures 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.

 

9

 

The following table reconciles net income (loss) to adjusted net income (in thousands) and Stand-Alone E&P net income (loss) to Stand-Alone E&P adjusted net income (in thousands):

 

		Stand-Alone E&P					Consolidated
		Three Months Ended					Three Months Ended
		December 31,					December 31,
		2016			2017		2016			2017
Net income (loss)		$	(485,772	)	486,869		$	(485,772	)	486,869
Non-cash commodity derivative (gains) losses on unsettled derivatives		639,805			(178,430	)	639,805			(178,430	)
Cash receipts for settled hedges		189,524			76,548		189,524			76,548
Impairment of unproved properties		115,712			76,500		115,712			76,500
Impairment of gathering systems and facilities		N/A			N/A		—			23,431
Equity-based compensation		20,071			17,673		26,754			24,520
Loss on early extinguishment of debt		16,956			1,205		16,956			1,500
Gain on sale of assets		(93,776		)	—		(97,635		)	—
Income tax effect of reconciling items		(336,110		)	2,447		(337,179		)	(9,056	)
Impact of tax reform legislation		—			(427,962	)	—			(427,962	)
Adjusted net income		$	66,410		54,850		$	68,165		73,920

 

		Stand-Alone E&P					Consolidated
		Years Ended					Years Ended
		December 31,					December 31,
		2016			2017		2016			2017
Net income (loss)		$	(848,816	)	615,070		$	(848,816	)	615,070
Non-cash commodity derivative (gains) losses on unsettled derivatives		514,181			(636,889	)	514,181			(636,889	)
Cash receipts for settled hedges		1,003,083			213,940		1,003,083			213,940
Impairment of unproved properties		162,935			159,598		162,935			159,598
Impairment of gathering systems and facilities		N/A			N/A		—			23,431
Equity-based compensation		76,372			76,162		102,421			103,445
Loss on early extinguishment of debt		16,956			1,205		16,956			1,500
Gain on sale of assets		(93,776		)	—		(97,635		)	—
Income tax effect of reconciling items		(635,581		)	69,976		(643,977		)	50,784
Impact of tax reform legislation		—			(427,962	)	—			(427,962	)
Adjusted net income		$	195,354		71,100		$	209,148		102,917

 

Adjusted Operating Cash Flow, Stand-Alone E&P Adjusted Operating Cash Flow and Free Cash Flow

 

Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities before changes in working capital items.  Stand-Alone E&P Adjusted Operating Cash Flow as presented in this release represents net cash provided by operating activities that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements before changes in working capital items.  Adjusted Operating Cash Flow is widely accepted by the investment community as a financial indicator of an oil and gas company’s ability to generate cash to internally fund exploration and development activities and to service debt.  Adjusted Operating Cash Flow is also useful because it is widely used by professional research analysts in valuing, comparing, rating and providing investment recommendations of companies in the oil and gas exploration and production industry.  In turn, many investors use this published research in making investment decisions.  Free cash flow as defined by the Company represents Stand-Alone E&P Adjusted operating cash flow, less Stand-Alone E&P Drilling and Completion capital, less Land Maintenance Capital.

 

10

 

Management believes that Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow are useful indicators of the company’s ability to internally fund its activities and to service or incur additional debt on a consolidated and Stand-Alone E&P basis. Management believes that changes in current assets and liabilities, which are excluded from the calculation of these measures, relate to the timing of cash receipts and disbursements and therefore may not relate to the period in which the operating activities occurred and generally do not have a material impact on the ability of the company to fund its operations.  Management believes that Free Cash Flow is a useful measure for assessing the company’s financial performance and measuring its ability to generate excess cash from its operations.

 

There are significant limitations to using Adjusted Operating Cash Flow, Stand-Alone E&P Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income on a consolidated and Stand-Alone E&P basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow reported by different companies.  Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow do 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.

 

Adjusted Operating Cash Flow is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity.

 

The following table reconciles net cash provided by operating activities to adjusted cash flow from operations as used in this release (in thousands):

 

		Stand-Alone E&P					Consolidated
		Three Months Ended December 31,					Three Months Ended December 31,
		2016			2017		2016			2017
Net cash provided by operating activities		$	285,637		254,078		$	335,559		$	313,483
Net change in working capital		75,253			57,666		68,859			54,054
Adjusted operating cash flow		360,890			311,744		404,418			367,537

 

		Stand-Alone E&P					Consolidated
		Years Ended December 31,					Years Ended December 31,
		2016			2017		2016			2017
Net cash provided by operating activities		$	1,105,238		1,836,322		$	1,241,256		$	2,006,291
Net change in working capital		36,519			(87,466	)	32,920			(76,035		)
Adjusted cash flow from operations		1,141,757			1,748,856		1,274,176			1,930,256

 

11

 

Total Debt and Net Debt

 

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

 

		December 31,			December 31,
		2016			2017
Bank credit facilities		$	650,000		$	740,000
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			1,520
Net unamortized debt issuance costs		(47,776		)	(41,430		)
Consolidated total debt		$	4,703,973		$	4,800,090
Less: Cash and cash equivalents		31,610			28,441
Consolidated net debt		$	4,672,363		$	4,771,649

 

Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX

 

Adjusted EBITDAX as defined by the Company represents net income or loss, including noncontrolling interests, before interest expense, interest income, derivative fair value gains or losses (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), taxes, impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, and gain or loss on sale of assets. Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.

 

Stand-Alone E&P Adjusted EBITDAX as defined by the Company represents income or loss as reported in the Parent column of Antero’s guarantor footnote to its financial statements before interest expense, interest income, derivative fair value gains or losses from exploration and production and marketing (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses), impairment, depletion, depreciation, amortization, and accretion, exploration expense, franchise taxes, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-Alone E&P Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units.

 

The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero’s consolidated financial statements.  The GAAP financial measure nearest to Stand-Alone E&P Adjusted EBITDAX is Stand-Alone E&P net income or loss that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements. While there are limitations associated with the use of Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX described below, management believes that these measures are useful to an investor in evaluating the company’s financial performance because these measures:

 

·                  are widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;

 

·                  helps investors to more meaningfully evaluate and compare the results of Antero’s operations (both on a consolidated and Stand-Alone E&P basis) from period to period by removing the effect of its capital structure from its operating structure; and

 

·                  is used by management for various purposes, including as a measure of Antero’s operating performance (both on a consolidated and Stand-Alone E&P basis), in presentations to the company’s board of directors, and as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the company’s senior notes.

 

12

 

There are significant limitations to using Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income on a consolidated and Stand-Alone E&P basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted EBITDAX reported by different companies.  In addition, Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX provide no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.

 

		Stand-Alone E&P					Consolidated
		Three Months Ended					Three Months Ended
		December 31,					December 31,
		2016			2017		2016			2017
Net income (loss) including noncontrolling interest		$	(485,772	)	486,869		$	(452,804	)	$	529,614
Commodity derivative fair value (gains)		639,805			(178,430	)	639,805			(178,430		)
Gains on settled derivative instruments		189,524			76,548		189,524			76,548
Gain on sale of assets		(93,776		)	—		(97,635		)	—
Interest expense		59,091			53,687		67,918			63,390
Loss on early extinguishment of debt		16,956			1,205		16,956			1,500
Income tax expense (benefit)		(265,621		)	(400,138	)	(265,621		)	(400,138		)
Depreciation, depletion, amortization, and accretion		196,682			183,439		222,443			214,397
Impairment of unproved properties		115,712			76,500		115,712			76,500
Impairment of gathering systems and facilities		N/A			N/A		—			23,431
Exploration expense		3,573			3,028		3,573			3,028
Gain on change in fair value of contingent acquisition consideration		(6,105		)	(3,804	)	N/A			N/A
Equity-based compensation expense		20,071			17,673		26,754			24,520
Equity in loss (earnings) of unconsolidated affiliate		N/A			N/A		1,542			(7,307		)
Distributions from unconsolidated affiliates		N/A			N/A		7,702			10,075
Distributions from Antero Midstream		28,850			33,614		N/A			N/A
Equity in net income of Antero Midstream		5,153			22,128		N/A			N/A
State franchise taxes .		11			—		11			—
Total Adjusted EBITDAX		424,154			372,319		475,880			437,128
Interest expense		(59,091		)	(53,687	)	(67,918		)	(63,390		)
Exploration expense		(3,573		)	(3,028	)	(3,573		)	(3,028		)
Changes in current assets and liabilities		(75,253		)	(57,666	)	(68,859		)	(54,054		)
State franchise taxes		(11		)	—		(11		)	—
Other non-cash items		(589		)	(3,860	)	40			(3,173		)
Net cash provided by operating activities		$	285,637		254,078		$	335,559		$	313,483

 

13

 

		Stand-Alone E&P						Consolidated
		Years Ended						Years Ended
		December 31,						December 31,
		2016			2017			2016			2017
Net income (loss) including noncontrolling interest		$	(848,816	)	$	615,070		$	(749,448	)	$	785,137
Commodity derivative fair value (gains)		514,181			(636,889		)	514,181			(636,889		)
Gains on settled derivative instruments		1,003,083			213,940			1,003,083			213,940
Gain on sale of assets		(93,776		)	—			(97,635		)	—
Interest expense		232,455			232,331			253,552			268,701
Loss on early extinguishment of debt		16,956			1,205			16,956			1,500
Income tax expense (benefit)		(496,376		)	(295,051		)	(496,376		)	(295,051		)
Depreciation, depletion, amortization, and accretion		712,485			707,658			812,346			827,220
Impairment of unproved properties		162,935			159,598			162,935			159,598
Impairment of gathering systems and facilities		N/A			N/A			—			23,431
Exploration expense		6,862			8,538			6,862			8,538
Gain on change in fair value of contingent acquisition consideration		(16,489		)	(13,476		)	N/A			N/A
Equity-based compensation expense		76,372			76,162			102,421			103,445
Equity in loss (earnings) of unconsolidated affiliate		N/A			N/A			(485		)	(20,194		)
Distributions from unconsolidated affiliate		N/A			N/A			7,702			20,195
Distributions from Antero Midstream		107,364			131,598			N/A			N/A
Equity in net income of Antero Midstream		7,156			43,710			N/A			N/A
State franchise taxes		50			—			50			—
Total Adjusted EBITDAX		1,384,442			1,244,394			1,536,144			1,459,571
Interest expense		(232,455		)	(232,331		)	(253,552		)	(268,701		)
Exploration expense		(6,862		)	(8,538		)	(6,862		)	(8,538		)
Changes in current assets and liabilities		(36,519		)	87,466			(32,920		)	76,035
State franchise taxes		(50		)	—			(50		)	—
Proceeds from derivative monetizations		—			749,906			—			749,906
Other non-cash items		(3,318		)	(4,575		)	(1,504		)	(1,982		)
Net cash provided by operating activities		$	1,105,238		1,836,322			$	1,241,256		$	2,006,291

 

Antero Midstream Adjusted EBITDA & Distributable Cash Flow

 

Antero Midstream views Adjusted EBITDA as an important indicator of its performance.  Antero Midstream defines Adjusted EBITDA as Net Income before interest expense, depreciation expense, impairment expense, accretion of contingent acquisition consideration, equity-based compensation expense, excluding equity in earnings of unconsolidated affiliates and including cash distributions from unconsolidated affiliates.

 

Antero Midstream uses Adjusted EBITDA to assess:

 

·                  the financial performance of Antero Midstream’s assets, without regard to financing methods in the case of Adjusted EBITDA, capital structure or historical cost basis;

 

·                  its operating performance and return on capital as compared to other publicly traded partnerships in the midstream energy sector, without regard to financing or capital structure; and

 

·                  the viability of acquisitions and other capital expenditure projects.

 

Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid.  Antero Midstream uses Distributable Cash Flow as a performance metric

 

14

 

to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders.  Distributable Cash Flow does not reflect changes in working capital balances.

 

Adjusted EBITDA and Distributable Cash Flow are non-GAAP financial measures.  The GAAP measure most directly comparable to Adjusted EBITDA and Distributable Cash Flow is Net Income.  The non-GAAP financial measures of Adjusted EBITDA and Distributable Cash Flow should not be considered as alternatives to the GAAP measure of Net Income.  Adjusted EBITDA and Distributable Cash Flow are not presentations made in accordance with GAAP and have important limitations as an analytical tool because they include some, but not all, items that affect Net Income and Adjusted EBITDA.  You should not consider Adjusted EBITDA and Distributable Cash Flow in isolation or as a substitute for analyses of results as reported under GAAP.  Antero Midstream’s definition of Adjusted EBITDA and Distributable Cash Flow may not be comparable to similarly titled measures of other partnerships.

 

		Three months ended						Years ended
		December 31,						December 31,
		2016			2017			2016			2017
Net income		$	73,351		64,155			$	236,703		$	307,315
Interest expense		9,008			10,395			21,893			37,557
Depreciation expense		25,761			30,958			99,861			119,562
Impairment of property and equipment expense		—			23,431			—			23,431
Accretion of contingent acquisition consideration		6,105			3,804			16,489			13,476
Equity-based compensation		6,683			6,847			26,049			27,283
Equity in earnings of unconsolidated affiliates		1,542			(7,307		)	(485		)	(20,194		)
Distributions from unconsolidated affiliates		7,702			10,075			7,702			20,195
Gain on asset sale		(3,859		)	—			(3,859		)	—
Adjusted EBITDA		$	126,293		$	142,358		$	404,353		$	528,625
Interest paid		6,115			(4,136		)	(13,494		)	(46,666		)
Decrease in cash reserved for bond interest (1)		(1,743		)	(8,734		)	(10,481		)	291
Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2)		(10,481		)	(514		)	(5,636		)	(5,945		)
Cash distribution to be received from unconsolidated affiliate		(2,636		)	—			—			—
Maintenance capital expenditures(3)		(5,466		)	(12,063		)	(21,622		)	(55,159		)
Distributable cash flow		$	102,928		$	116,911		$	353,120		$	421,146
Distributions Declared to Antero Midstream Holders
Limited Partners		50,090			68,231			182,559			247,132
Incentive distribution rights		7,543			23,772			16,945			69,720
Total Aggregate Distributions		$	57,633		$	92,003		$	199,504		$	316,852
DCF coverage ratio		1.79x			1.27x			1.78x			1.33x

 

Antero Resources is an independent natural gas and oil company engaged in the acquisition, development and production of unconventional liquids-rich natural gas properties located in the Appalachian Basin in West Virginia and Ohio. The Company’s website is located at www.anteroresources.com.

 

This release includes “forward-looking statements”.  Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments Antero expects, believes or anticipates will or may occur in the future, such as those regarding future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, future capital spending plans, improved and/or increasing capital efficiency, continued utilization of existing infrastructure, gas marketability, estimated realized natural gas, natural gas liquids and oil prices, acreage quality, access to multiple gas markets, expected drilling and development plans (including the number, type, lateral length and location of wells to be drilled, the number and type of drilling rigs and the number of wells per pad), projected well costs, future financial position, future technical improvements and future marketing opportunities, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  All forward-looking statements speak only as of the date of this release. Although Antero believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements.

 

Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are

 

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