Exhibit 99.1

 

 

Antero Resources Reports Third Quarter 2016 Financial and Operational Results

 

Denver, Colorado, October 26, 2016—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its third quarter 2016 financial and operational results. The relevant condensed consolidated financial statements are included in Antero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, which has been filed with the Securities and Exchange Commission.

 

Third Quarter Highlights Include:

 

·                  Average net daily gas equivalent production was a record 1,875 MMcfe/d (26% liquids), a 25% increase over the prior year quarter and a 6% increase sequentially

 

·                  Includes a record 81,460 Bbl/d of liquids production, a 56% increase over the prior year quarter and a 9% increase sequentially

 

·                  Realized $0.05 per Mcf premium to Nymex natural gas price, or $2.86 per Mcf, before hedging

 

·                  Realized C3+ NGL price of $17.56 per barrel, 39% of Nymex WTI price before hedging

 

·                  Realized natural gas equivalent price of $3.96 per Mcfe including NGLs, oil and hedges, a 3% increase over the prior year quarter

 

·                  Net marketing expense decreased to $0.10 per Mcfe

 

·                  Net income of $238 million, or $0.78 per share, compared to net income of $534 million, or $1.93 per share, in the prior year quarter

 

·                  Adjusted net income of $55 million, or $0.18 per share, a 293% increase compared to the prior year quarter

 

·                  Record adjusted EBITDAX of $373 million, a 28% increase compared to the prior year quarter

 

·                  Signed a definitive agreement to sell approximately 17,000 net acres in Pennsylvania for $170 million

 

·                  Borrowing base under the Company’s credit facility was increased by $250 million to $4.75 billion

 

Recent Developments

 

On October 25th, 2016, Antero signed a definitive agreement for the sale of approximately 17,000 net acres primarily located in Washington and Westmoreland Counties, Pennsylvania for $170 million.  The transaction monetizes acreage that is outside of Antero’s infrastructure build-out and beyond its five year drilling plan.  It is expected to close in the fourth quarter of 2016. Tudor, Pickering, Holt & Co. acted as financial advisor to Antero in connection with the transaction.

 

On October 24th, 2016, Antero’s borrowing base under its credit facility was increased to $4.75 billion, a $250 million increase over the Company’s previous borrowing base of $4.5 billion.  Lender commitments under the facility remain at $4.0 billion.  The bank syndicate, which is co-led by JPMorgan Chase Bank, N.A. and Wells Fargo Bank, N.A., is currently comprised of 29 banks.

 

On October 7th, 2016, Antero completed a private placement of 6,730,769 shares of common stock at a price of $26.00 per share, resulting in $175 million of net proceeds.  Pro forma for the proceeds from the Pennsylvania divestiture and the private placement, Antero’s September 30, 2016 consolidated net debt to trailing twelve months EBITDAX was 3.2 times and consolidated liquidity was $4.0 billion.

 

Commenting on recent activity, Paul Rady, Chairman of the Board and CEO said, “We are pleased to be in a position to continue to organically grow production at 20% to 25% annually, while de-leveraging the balance sheet.  Since year-end 2015, we have reduced our trailing twelve months leverage by a half a turn to 3.2 times today, while growing production by over 350 MMcfe/d and adding 65,000 net acres in the high-graded core of the Marcellus for long-term development. Virtually all of this acreage has now been dedicated to Antero Midstream for infrastructure build-out.  We are an industry leader in the Marcellus and Utica Shale plays due to our differentiated strategy and that is evident today in our results.”

 

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Third Quarter 2016 Financial Results

 

As of September 30, 2016, Antero owned a 62% limited partner interest in Antero Midstream Partners LP (“Antero Midstream”).  Antero Midstream’s results are consolidated with Antero’s results.

 

For the three months ended September 30, 2016, the Company reported GAAP net income of $238 million, or $0.78 per basic share and $0.77 per diluted share, compared to GAAP net income of $534 million, or $1.93 per basic and diluted share, in the third quarter of 2015.  The GAAP net income for the third quarter of 2016 included the following items:

 

·                  Non-cash gain on unsettled hedges of $334 million due to decreasing commodity prices during the quarter

 

·                  Non-cash equity-based compensation expense of $26 million

 

·                  Impairment of unproved properties of $12 million

 

·                  Income tax effect of these reconciling items of $112 million

 

The Company’s results for the third quarter of 2016 were as follows:

 

·                  Adjusted net income of $55 million, or $0.18 per basic and diluted share, a 293% increase compared to the third quarter of 2015

 

·                  Adjusted EBITDAX of $373 million, a 28% increase compared to the third quarter of 2015

 

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 third quarter of 2016 averaged 1,875 MMcfe/d, including 81,460 Bbl/d of liquids (26% liquids).  Third quarter 2016 production represents an organic production growth rate of 25% from the third quarter of 2015 and a 6% increase compared to the second quarter of 2016.  Third quarter 2016 C3+ natural gas liquids (“NGLs”) and oil production averaged 57,286 Bbl/d and 4,603 Bbl/d, respectively, while ethane (C2) production averaged 19,572 Bbl/d. Total liquids production for the third quarter of 2016 represents an organic production growth rate of 56% and 9% from the third quarter of 2015 and second quarter of 2016, respectively.

 

Antero’s average natural gas price before hedging increased 23% from the prior year quarter to $2.86 per Mcf, a $0.05 per Mcf premium to the average Nymex price for the period.  Virtually all of Antero’s third quarter 2016 natural gas revenue was realized at currently favorable price indices, including Columbia Gas Transmission (TCO), Chicago, Tennessee Gulf and Nymex.  Antero’s average realized natural gas price after hedging for the third quarter of 2016 was $4.30 per Mcf, a $1.49 premium to the Nymex average price for the period.  This represents an 8% increase compared to the prior year quarter.  During the quarter, Antero realized a cash settled natural gas hedge gain of $184 million, or $1.44 per Mcf.

 

The Company’s average realized C3+ NGL price before hedging for the third quarter of 2016 was $17.56 per barrel, or 39% of the 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 $19.96 per barrel, a 21% increase compared to the third quarter of 2015.  Antero’s average realized ethane price for the third quarter of 2016 was $0.19 per gallon, or $8.00 per barrel.  The average realized oil price was $34.93 per barrel, a $9.92 differential to Nymex WTI and a 15% increase as compared to the third 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 21% to $2.82 per Mcfe.  The Company’s average natural gas-equivalent price, including C2+ NGLs, oil and hedge settlements, increased by 3% to $3.96 per Mcfe compared to the prior year quarter.  For the third quarter of 2016, Antero realized a total cash settled hedge gain on all products of $197 million, or $1.14 per Mcfe.

 

Commenting on realized pricing, Glen Warren, President and CFO, said, “For the third quarter, we realized a $0.05 premium to Nymex on natural gas sales, before hedges, which is at the top end of our full year guidance.  Additionally, while many of our peers were forced to shut in production in September due to the widening of Dominion South and TETCO M2 differentials to $1.96 per Mcf back of Nymex, we were able to realize an $0.08 premium to Nymex for the month, or a $2.04 per Mcf premium to these local indices.  This once again highlights the significant value of our firm transport portfolio where we can physically move our gas to more healthy indices.  This demonstrates our ability to mitigate Northeast basis risk, which in turn results in significant visibility for our continued growth plans.”

 

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Total operating revenue for the third quarter of 2016 was $1.1 billion as compared to $1.4 billion for the third quarter of 2015.  Operating revenue for the third quarter of 2016 included a $334 million non-cash gain on unsettled hedges, while the third quarter of 2015 included an $873 million non-cash gain on unsettled hedges.  In both periods, the non-cash gain on unsettled hedges was driven by decreasing natural gas prices during the period.  Adjusted non-GAAP revenue excluding the unrealized hedge gain was $783 million, a 37% increase compared to the third quarter of 2015.  Liquids production contributed 25% of total product revenues before hedges in the third quarter of 2016, as compared to a 22% contribution for the prior year quarter.  For a reconciliation of revenue excluding unrealized hedge gains to operating revenue, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Marketing revenue for the third quarter of 2016 was $97 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 and Columbia Gas Pipelines.  Marketing expense for the third quarter of 2016 was $115 million, including costs related to excess capacity and the cost of purchasing third party gas.  Net marketing expense was $18 million, or $0.10 per Mcfe, for the third quarter of 2016, representing a 55%, or $0.12 per Mcfe decrease from the second quarter of 2016.  The significant decrease in net marketing expense from the prior 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 achieved a higher spread on its marketed volumes due to the widening of 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 third quarter of 2016 was $1.53 per Mcfe, a 16% increase compared to $1.32 per Mcfe in the prior year quarter.  The increase is primarily due to higher transportation costs incurred on new pipelines that were placed in service in late 2015, which deliver gas to better price indices resulting in higher realized gas prices for the period.  The per unit cash production expense for the quarter included $0.08 per Mcfe for lease operating costs, $1.36 per Mcfe for gathering, compression, processing and transportation costs and $0.09 per Mcfe for production and ad valorem taxes.  Per unit general and administrative expense for the third quarter of 2016, excluding non-cash equity-based compensation expense was $0.18 per Mcfe, a 31% decrease from the third quarter of 2015.  The significant per unit decrease in general and administrative expenses was primarily driven by the increase in production while general and administrative expense remained relatively flat.  Per unit depreciation, depletion and amortization expense decreased 15% from the prior year quarter to $1.16 per Mcfe, primarily driven by lower development costs.

 

Adjusted EBITDAX of $373 million for the third quarter of 2016 represents a record for Antero and a 28% increase compared to the prior year quarter.  Adjusted EBITDAX margin for the quarter was $2.16 per Mcfe, representing a 3% increase from the prior year quarter.  For the third quarter of 2016, cash flow from operations before changes in working capital was $310 million, a 31% increase from the prior year quarter.

 

For a description of adjusted EBITDAX, adjusted EBITDAX margin, as well as cash flow from operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures.”

 

The following table details the components of average net production and average realized prices for the three months ended September 30, 2016:

 

		Three Months Ended September 30, 2016
		Gas (MMcf/d)		Oil (Bbl/d)		C3+ NGLs (Bbl/d)		Ethane (Bbl/d)		Combined Gas  Equivalent (MMcfe/d)
Average Net Production		1,386		4,603		57,286		19,572		1,875

 

		Gas ($/Mcf)			Oil ($/Bbl)			C3+ NGLs ($/Bbl)			Ethane ($/Bbl)			Combined Gas Equivalent ($/Mcfe)
Average Realized Prices
Average realized price before settled derivatives		$	2.86		$	34.93		$	17.56		$	8.00		$	2.82
Settled derivatives		1.44			—			2.40			—			1.14
Average realized price after settled derivatives		$	4.30		$	34.93		$	19.96		$	8.00		$	3.96
Nymex average price		$	2.81		$	44.85								$	2.81
Premium / (Differential) to Nymex		$	1.49		$	(9.92	)							$	1.15

 

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Marcellus Shale — Antero completed and placed on line 14 horizontal Marcellus wells during the third quarter of 2016 with an average lateral length of 9,033 feet.  During the quarter, Antero drilled on average approximately 4,000 feet per day in its laterals while drilling and casing 28 wells during the quarter.  The Company’s contracted completion crews averaged 4.5 stages per day in the Marcellus, a record for the Company.  The increase in stages per day was a result of the implementation of zipper fracs on select pads during the quarter.  Antero plans to utilize zipper fracs on virtually all newly constructed pads going forward.  Year-to-date in the Marcellus, Antero has completed 69 wells that have at least 90 days of production history.  The 69 wells have an average EUR of 20.6 Bcfe at 1,245 Btu gas and assuming ethane rejection, an average lateral length of 9,000’ and an average all-in development cost of $0.53 per Mcfe.  The Company is currently operating four drilling rigs and five completion crews in the Marcellus Shale play.

 

Year-to-date, Antero has completed 33 wells using advanced completions, defined as completions using more than 1,300 pounds per foot of proppant.  The preliminary EURs associated with these 33 wells are currently trending to approximately 2.0 Bcf/1,000 or 17% above Antero’s 1.7 Bcf/1,000 type curve.

 

Current well costs are $0.86 million per 1,000 feet of lateral in the Marcellus, which represents a 27% reduction from 2015 and a 4% reduction from the second quarter of 2016.  The reduction in well costs continues to be driven both by reduced service costs through long-term contracts rolling off, resulting in a greater proportion of rigs and completion crews operating at market prices and continuing operational efficiencies.  In the Marcellus, average drilling days from spud to final rig release declined to 14 days in the third quarter of 2016, a 42% reduction from 2015 and a 7% reduction from the second quarter of 2016.

 

Ohio Utica Shale — Antero completed and placed on line eight horizontal Ohio Utica wells during the third quarter of 2016 with an average lateral length of 8,540 feet.  During the quarter, Antero drilled on average approximately 2,700 feet per day in its laterals while drilling and casing five wells during the quarter.  The Company’s contracted completion crews averaged 5.0 stages per day in the Utica, a record for the Company.  Additionally, the Company has averaged 6.3 stages per day in 2016 when utilizing zipper fracs in the Utica.  Four of the eight wells completed in the third quarter of 2016 have been on line for more than 30 days and had an average restricted 30-day rate of 17.0 MMcfe/d while rejecting ethane (14% liquids).  Antero is currently operating one drilling rig and one completion crew in the Utica Shale play.

 

Current well costs are $1.01 million per 1,000 feet of lateral in the Utica, which represents a 26% reduction from 2015 and a 3% reduction from the second quarter of 2016.  The reduction in well costs is primarily driven by lower service costs and continued operational efficiencies.  Drilling days from spud to final rig release declined to 16 days in the Utica in the third quarter of 2016, a 49% reduction from 2015.

 

Antero Midstream Financial Results

 

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

 

Low pressure gathering volumes for the third quarter of 2016 averaged 1,431 MMcf/d, a 38% increase from the third quarter of 2015 and a 6% increase sequentially.  High pressure gathering volumes for the third quarter of 2016 averaged 1,351 MMcf/d, an 11% increase from the third quarter of 2015 and an 8% increase sequentially.  Compression volumes for the third quarter of 2016 averaged 777 MMcf/d, a 78% increase from the third quarter of 2015 and an 18% increase sequentially. The increase in gathering and compression volumes was due to production growth from Antero Resources in Antero Midstream’s area of dedication.  Condensate gathering volumes averaged 521 Bbl/d during the quarter, an 82% decrease compared to the prior year quarter and a 74% decrease sequentially. The sequential decrease in condensate gathering volumes was primarily driven by Antero shifting its Ohio Utica Shale development from its Highly-Rich Gas/Condensate area to currently higher rate of return drilling in the Highly-Rich Gas areas.  Fresh water delivery volumes averaged 140,162 Bbl/d during the quarter, a 109% increase compared to the prior year quarter and a 33% increase sequentially.  The increase in volumes was driven by an increase in the average water used per foot in Marcellus completions to  43 barrels per foot, a 35% increase as compared to 2015 and a 5% increase compared to the second quarter of 2016 as Antero piloted higher water and sand concentration completions.

 

For the three months ended September 30, 2016, the Partnership reported revenues of $150 million, comprised of $78 million from the Gathering and Compression segment and $72 million from the Water Handling and Treatment segment. Revenues increased 84% compared to the prior year quarter, primarily driven by growth in throughput volumes and fresh water delivery volumes. Water

 

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Handling and Treatment segment revenues include $25 million from produced water handling and high rate water transfer services.  Direct operating expenses for the Gathering and Compression and Water Handling and Treatment segments were $5 million and $28 million, respectively, for a total of $33 million compared to $2 million in direct operating expenses in the prior year quarter. Water Handling and Treatment direct operating expenses include $24 million from produced water handling and high rate water transfer services. The increase in direct operating expenses was driven primarily by the inclusion of produced water handling and high rate water transfer services, as well as the expansion of the Partnership’s gathering and compression and fresh water delivery systems to support the production growth of Antero Resources.  General and administrative expenses including equity-based compensation was $13 million, a $0.5 million decrease compared to the third quarter of 2015.  General and administrative expenses excluding equity-based compensation were $7 million during the third quarter of 2016, a 22% decrease compared to the third quarter of 2015, which included additional expenses from the integrated water business drop-down transaction. Total operating expenses were $76 million, including $26 million of depreciation, $7 million of equity-based compensation, and $4 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 $0.265 per unit ($1.06 per unit annualized) for the third quarter of 2016. The distribution represents a 29% increase compared to the prior year quarter and a 6% increase sequentially.  The distribution is the Partnership’s seventh consecutive quarterly distribution increase since its initial public offering in November 2014 and will be payable on November 24, 2016 to unitholders of record as of November 10, 2016.

 

Balance Sheet and Liquidity

 

As of September 30, 2016, Antero’s consolidated net debt was $4.7 billion, of which $775 million were borrowings outstanding under the Company’s and Antero Midstream’s revolving credit facilities.  Total borrowing capacity under these two facilities are currently $5.2 billion(1).  Including $709 million in letters of credit outstanding, the company had $3.7 billion in available consolidated liquidity as of September 30, 2016.  Pro forma for the $175 million private placement of common stock and the $170 million of proceeds from the Pennsylvania divestiture expected to close in the fourth quarter of 2016, Antero’s September 30, 2016 consolidated pro forma net debt to trailing twelve months EBITDAX was 3.2 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 September 30, 2016.

 

Third Quarter 2016 Capital Spending

 

Antero’s drilling and completion costs for the three months ended September 30, 2016 were $300 million.  In addition, the Company invested $48 million for land, excluding acquisitions.  Antero Midstream invested $56 million for gathering and compression systems and $59 million for water infrastructure projects including $52 million on the Antero Clearwater Treatment Facility.

 

Hedge Position

 

Antero currently has hedged 3.5 Tcfe of future natural gas equivalent production using fixed price swaps covering the period from October 1, 2016 through December 31, 2022 at an average index price of $3.65 per MMBtu.  At September 30, 2016, the Company’s estimated fair value of commodity derivative instruments was $2.4 billion.

 

The following table summarizes Antero’s hedge position as of September 30, 2016:

 

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Period		Natural Gas MMBtu/d		Average Index price ($/MMBtu)			Liquids Bbl/d		Average Index price
4Q 2016:
Nymex HH		1,110,000		$	3.57		—		—
Dom South		272,500		$	5.47		—		—
CGTLA		170,000		$	4.20		—		—
TCO		60,000		$	5.01		—		—
Propane MB ($/Gallon)		—		—			30,000		$	0.61
4Q 2016 Total		1,612,500		$	4.01		30,000		$	0.61
2017:
Nymex HH		1,370,000		$	3.39		—		—
CGTLA		420,000		$	4.27		—		—
Chicago		70,000		$	4.57		—		—
Propane MB ($/Gallon)		—		—			27,500		$	0.39
Ethane MB ($/Gallon)		—		—			20,000		$	0.25
Nymex WTI ($/Bbl)		—		—			1,000		$	51.90
2017 Total		1,860,000		$	3.63		48,500		N/A		(1)
2018 Nymex HH		2,002,500		$	3.91		2,000	(2)	$	0.65
2019 Nymex HH		2,330,000		$	3.70		—		—
2020 Nymex HH		1,377,500		$	3.66		—		—
2021 Nymex HH		660,000		$	3.35		—		—
2022 Nymex HH		470,000		$	3.26		—		—

 

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

(2)         Represents 2,000 Bbl/d of propane hedged at Mont Belvieu.

 

Conference Call

 

A conference call is scheduled on Thursday, October 27, 2016 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, November 4, 2016 at 9:00 am MT at 877-870-5176 (U.S.) or 858-384-5517 (International) using the passcode 10091479.

 

A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com.  The webcast will be archived for replay on the Company’s website until Friday, November 4, 2016 at 9:00 am MT.

 

Presentation

 

An updated presentation will be posted to the Company’s website before the October 27, 2016 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 as set forth in this release represents total operating revenue adjusted for unsettled hedge gains.  Antero believes that revenue excluding unrealized hedge gains 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 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 (in thousands):

 

		Three months ended September 30,						Nine months ended September 30,
		2015			2016			2015			2016
Total operating revenue		$	1,443,335		$	1,116,503		$	3,049,736		$	1,588,309
Commodity derivative fair value (gains)		(1,079,071		)	(530,334		)	(1,836,398		)	(125,624		)
Cash receipts for settled hedges		205,919			196,712			586,639			813,559
Revenue excluding unrealized hedge gains		$	570,183		$	782,881		$	1,799,977		$	2,276,244

 

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

 

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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						Nine months ended
		September 30,						September 30,
		2015			2016			2015			2016
Net income (loss)		$	533,842		$	238,255		$	782,900		$	(363,044	)
Non-cash commodity derivative (gains) losses on unsettled derivatives		(873,152		)	(333,622		)	(1,249,759		)	687,935
Impairment of unproved properties		8,754			11,753			43,670			47,223
Equity-based compensation		23,915			26,381			79,280			75,667
Contract termination and rig stacking		—			—			10,902			—
Income tax effect of reconciling items		320,711			112,490			435,033			(308,675		)
Adjusted net income		$	14,070		$	55,257		$	102,026		$	139,106

 

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.  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 September 30,						Nine months ended September 30,
		2015			2016			2015			2016
Net cash provided by operating activities		$	246,046		$	326,991		$	841,154		$	905,697
Net change in working capital		(9,119		)	(17,327		)	(103,463		)	(35,939		)
Cash flow from operations before changes in working capital		$	236,927		$	309,664		$	737,691		$	869,758

 

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

 

		December 31,			September 30,
		2015			2016
Bank credit facilities		$	1,327,000		$	775,000
6.00% AR senior notes due 2020		525,000			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
Net unamortized premium		6,513			5,698
Net unamortized debt issuance costs		(39,731		)	(45,794		)
Consolidated total debt		$	4,668,782		$	4,759,904
Cash and cash equivalents		23,473			18,512
Consolidated net debt		$	4,645,309		$	4,741,392

 

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

 

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by the Company, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP.  Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income, net income, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.  Adjusted EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.  Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.  However, Antero’s management team believes adjusted EBITDAX is useful to an investor in evaluating the Company’s financial performance because this measure:

 

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

 

·                  helps investors to more meaningfully evaluate and compare the results of Antero’s operations from period to period by removing the effect of its capital structure from its operating structure; and

 

·                  is used by the Company’s management team for various purposes, including as a measure of operating performance, in presentations to its board of directors, as a basis for strategic planning and forecasting.  Adjusted EBITDAX is also used by our Board of Directors as a performance measure in determining executive compensation.  Adjusted EBITDAX, as defined by our Credit Facility, is used by our lenders pursuant to covenants under our revolving credit facility and 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						Nine months ended
		September 30,						September 30,
		2015			2016			2015			2016
Net income (loss) from continuing operations including noncontrolling interest		$	544,734		$	268,196		$	804,422		$	(296,644	)
Commodity derivative fair value (gains)		(1,079,071		)	(530,334		)	(1,836,398		)	(125,624		)
Gains on settled derivative instruments		205,919			196,712			586,639			813,559
Interest expense		60,921			59,755			173,929			185,634
Income tax expense (benefit)		335,460			140,924			498,709			(230,755		)
Depreciation, depletion, amortization, and accretion		189,086			199,741			549,240			589,903
Impairment of unproved properties		8,754			11,753			43,670			47,223
Exploration expense		1,087			1,166			3,086			3,289
Equity-based compensation expense		23,915			26,381			79,280			75,667
Equity in earnings of unconsolidated affiliate		—			(1,543		)	—			(2,027		)
State franchise taxes		2			—			131			39
Contract termination and rig stacking		—			—			10,902			—
Total Adjusted EBITDAX		290,807			372,751			913,610			1,060,264
Interest expense		(60,921		)	(59,755		)	(173,929		)	(185,634		)
Exploration expense		(1,087		)	(1,166		)	(3,086		)	(3,289		)
Changes in current assets and liabilities		9,119			17,327			103,463			35,939
State franchise taxes		(2		)	—			(131		)	(39		)
Other non-cash items		8,130			(2,166		)	1,227			(1,544		)
Net cash provided by operating activities		$	246,046		$	326,991		$	841,154		$	905,697

 

8

 

		Three months ended						Nine months ended
		September 30,						September 30,
		2015			2016			2015			2016
Adjusted EBITDAX margin ($ per Mcfe):
Realized price before cash receipts for settled hedges		$	2.34		$	2.82		$	2.59		$	2.36
Gathering, compression, and water handling and treatment revenues		0.04			0.01			0.02			0.03
Lease operating expense		(0.08		)	(0.08		)	(0.06		)	(0.08		)
Gathering, compression, processing and transportation costs		(1.16		)	(1.36		)	(1.20		)	(1.32		)
Marketing, net		(0.19		)	(0.10		)	(0.17		)	(0.19		)
Production and ad valorem taxes		(0.08		)	(0.09		)	(0.14		)	(0.11		)
General and administrative(1)		(0.26		)	(0.18		)	(0.24		)	(0.20		)
Adjusted EBITDAX margin before settled hedges		0.61			1.02			0.80			0.49
Cash receipts for settled hedges		1.49			1.14			1.44			1.66
Adjusted EBITDAX margin ($ per Mcfe):		$	2.10		$	2.16		$	2.24		$	2.15

 

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

 

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, Ohio and Pennsylvania. 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, maximized 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, 2015.

 

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

 

9

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2015 and September 30, 2016

(unaudited)

(In thousands, except per share amounts)

 

		December 31, 2015			September 30, 2016
Assets
Current assets:
Cash and cash equivalents		$	23,473		18,512
Accounts receivable, net of allowance for doubtful accounts of $1,195 in 2015 and 2016		79,404			59,462
Accrued revenue		128,242			196,490
Derivative instruments		1,009,030			417,605
Other current assets		8,087			3,402
Total current assets		1,248,236			695,471
Property and equipment:
Natural gas properties, at cost (successful efforts method):
Unproved properties		1,996,081			2,449,995
Proved properties		8,211,106			9,180,705
Water handling and treatment systems		565,616			681,062
Gathering systems and facilities		1,502,396			1,656,676
Other property and equipment		46,415			45,571
		12,321,614			14,014,009
Less accumulated depletion, depreciation, and amortization		(1,589,372		)	(2,176,793	)
Property and equipment, net		10,732,242			11,837,216
Derivative instruments		2,108,450			2,015,090
Other assets		26,565			81,476
Total assets		$	14,115,493		14,629,253
Liabilities and Equity
Current liabilities:
Accounts payable		$	364,160		172,293
Accrued liabilities		194,076			245,174
Revenue distributions payable		129,949			172,202
Derivative instruments		—			3,110
Other current liabilities		19,085			19,125
Total current liabilities		707,270			611,904
Long-term liabilities:
Long-term debt		4,668,782			4,759,904
Deferred income tax liability		1,370,686			1,215,240
Derivative instruments		—			40
Other liabilities		82,077			61,883
Total liabilities		6,828,815			6,648,971
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 307,188 shares, respectively		2,770			3,072
Additional paid-in capital		4,122,811			5,131,909
Accumulated earnings		1,808,811			1,445,767
Total stockholders’ equity		5,934,392			6,580,748
Noncontrolling interest in consolidated subsidiary		1,352,286			1,399,534
Total equity		7,286,678			7,980,282
Total liabilities and equity		$	14,115,493		14,629,253

 

10

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income

Three Months Ended September 30, 2015 and 2016

(unaudited)
 (In thousands, except per share amounts)

 

		Three Months Ended September 30,
		2015			2016
Revenue:
Natural gas sales		$	253,975		364,373
Natural gas liquids sales		50,092			106,958
Oil sales		20,138			14,793
Gathering, compression, and water handling and treatment		4,426			2,969
Marketing		35,633			97,076
Commodity derivative fair value gains		1,079,071			530,334
Total revenue		1,443,335			1,116,503
Operating expenses:
Lease operating		10,786			13,854
Gathering, compression, processing, and transportation		160,302			234,915
Production and ad valorem taxes		10,721			15,554
Marketing		61,799			114,611
Exploration		1,087			1,166
Impairment of unproved properties		8,754			11,753
Depletion, depreciation, and amortization		188,667			199,113
Accretion of asset retirement obligations		419			628
General and administrative (including equity-based compensation expense of $23,915 and $26,381 in 2015 and 2016, respectively)		59,685			57,577
Total operating expenses		502,220			649,171
Operating income		941,115			467,332
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—			1,543
Interest		(60,921		)	(59,755	)
Total other expenses		(60,921		)	(58,212	)
Income before income taxes		880,194			409,120
Provision for income tax expense		(335,460		)	(140,924	)
Net income and comprehensive income including noncontrolling interest		544,734			268,196
Net income and comprehensive income attributable to noncontrolling interest		10,892			29,941
Net income and comprehensive income attributable to Antero Resources Corporation		$	533,842		238,255
Earnings per common share—basic		$	1.93		0.78
Earnings per common share—assuming dilution		$	1.93		0.77
Weighted average number of shares outstanding:
Basic		277,007			306,785
Diluted		277,015			308,657

 

11

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Nine Months Ended September 30, 2015 and 2016

(unaudited)
 (In thousands, except per share amounts)

 

		Nine Months Ended September 30,
		2015			2016
Revenue:
Natural gas sales		$	810,982		848,936
Natural gas liquids sales		188,403			274,736
Oil sales		55,627			41,712
Gathering, compression, and water handling and treatment		15,084			10,107
Marketing		143,242			287,194
Commodity derivative fair value gains		1,836,398			125,624
Total revenue		3,049,736			1,588,309
Operating expenses:
Lease operating		25,561			37,190
Gathering, compression, processing, and transportation		490,633			649,713
Production and ad valorem taxes		57,458			52,296
Marketing		214,201			378,521
Exploration		3,086			3,289
Impairment of unproved properties		43,670			47,223
Depletion, depreciation, and amortization		548,013			588,057
Accretion of asset retirement obligations		1,227			1,846
General and administrative (including equity-based compensation expense of $79,280 and $75,667 in 2015 and 2016, respectively)		177,925			173,966
Contract termination and rig stacking		10,902			—
Total operating expenses		1,572,676			1,932,101
Operating income (loss)		1,477,060			(343,792	)
Other income (expenses):
Equity in earnings of unconsolidated affiliate		—			2,027
Interest		(173,929		)	(185,634	)
Total other expenses		(173,929		)	(183,607	)
Income (loss) before income taxes		1,303,131			(527,399	)
Provision for income tax (expense) benefit		(498,709		)	230,755
Net income (loss) and comprehensive income (loss) including noncontrolling interest		804,422			(296,644	)
Net income and comprehensive income attributable to noncontrolling interest		21,522			66,400
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation		$	782,900		(363,044	)
Earnings (loss) per common share—basic		$	2.87		(1.26	)
Earnings (loss) per common share—assuming dilution		$	2.87		(1.26	)
Weighted average number of shares outstanding:
Basic		273,145			288,607
Diluted		273,154			288,607

 

12

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Nine Months Ended September 30, 2015 and 2016

(unaudited)

(In thousands)

 

		Nine Months Ended September 30,
		2015			2016
Cash flows from operating activities:
Net income (loss) including noncontrolling interest		$	804,422		(296,644	)
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		549,240			589,903
Impairment of unproved properties		43,670			47,223
Derivative fair value gains		(1,836,398		)	(125,624	)
Gains on settled derivatives		586,639			813,559
Deferred income tax expense (benefit)		498,709			(230,755	)
Equity-based compensation expense		79,280			75,667
Equity in earnings of unconsolidated affiliate		—			(2,027	)
Other		12,129			(1,544	)
Changes in current assets and liabilities:
Accounts receivable		15,299			10,077
Accrued revenue		75,765			(68,248	)
Other current assets		4,127			4,685
Accounts payable		(1,302		)	(7,415	)
Accrued liabilities		34,091			54,484
Revenue distributions payable		(20,839		)	42,253
Other current liabilities		(3,678		)	103
Net cash provided by operating activities		841,154			905,697
Cash flows used in investing activities:
Additions to proved properties		—			(64,789	)
Additions to unproved properties		(170,291		)	(559,572	)
Drilling and completion costs		(1,350,498		)	(1,009,851	)
Additions to water handling and treatment systems		(79,227		)	(137,355	)
Additions to gathering systems and facilities		(282,813		)	(154,136	)
Additions to other property and equipment		(5,225		)	(1,747	)
Investment in unconsolidated affiliate		—			(45,044	)
Change in other assets		11,190			(2,173	)
Proceeds from asset sales		40,000			—
Net cash used in investing activities		(1,836,864		)	(1,974,667	)
Cash flows from financing activities:
Issuance of common stock		537,832			837,414
Issuance of common units by Antero Midstream Partners LP		240,972			19,605
Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation		—			178,000
Issuance of senior notes		750,000			650,000
Repayments on bank credit facilities, net		(705,000		)	(552,000	)
Payments of deferred financing costs		(17,190		)	(9,029	)
Distributions to noncontrolling interest in consolidated subsidiary		(21,358		)	(51,238	)
Employee tax withholding for settlement of equity compensation awards		(4,554		)	(4,876	)
Other		(3,561		)	(3,867	)
Net cash provided by financing activities		777,141			1,064,009
Net decrease in cash and cash equivalents		(218,569		)	(4,961	)
Cash and cash equivalents, beginning of period		245,979			23,473
Cash and cash equivalents, end of period		$	27,410		18,512
Supplemental disclosure of cash flow information:
Cash paid during the period for interest		$	116,579		132,928
Supplemental disclosure of noncash investing activities:
Decrease in accounts payable and accrued liabilities for additions to property and equipment		$	(193,288	)	(189,234	)

 

13

 

ANTERO RESOURCES CORPORATION

 

The following tables set forth selected operating data for the three months ended September 30, 2015 compared to the three months ended September 30, 2016:

 

								Amount of
		Three Months Ended September 30,						Increase			Percent
(in thousands)		2015			2016			(Decrease)			Change
Operating revenues:
Natural gas sales		$	253,975		$	364,373		$	110,398		43	%
NGLs sales		50,092			106,958			56,866			114	%
Oil sales		20,138			14,793			(5,345		)	(27	)%
Gathering, compression, and water handling and treatment		4,426			2,969			(1,457		)	(33	)%
Marketing		35,633			97,076			61,443			172	%
Commodity derivative fair value gains		1,079,071			530,334			(548,737		)	(51	)%
Total operating revenues		1,443,335			1,116,503			(326,832		)	(23	)%
Operating expenses:
Lease operating		10,786			13,854			3,068			28	%
Gathering, compression, processing, and transportation		160,302			234,915			74,613			47	%
Production and ad valorem taxes		10,721			15,554			4,833			45	%
Marketing		61,799			114,611			52,812			85	%
Exploration		1,087			1,166			79			7	%
Impairment of unproved properties		8,754			11,753			2,999			34	%
Depletion, depreciation, and amortization		188,667			199,113			10,446			6	%
Accretion of asset retirement obligations		419			628			209			50	%
General and administrative (before equity-based compensation)		35,770			31,196			(4,574		)	(13	)%
Equity-based compensation		23,915			26,381			2,466			10	%
Total operating expenses		502,220			649,171			146,951			29	%
Operating income		941,115			467,332			(473,783		)	(50	)%
Other earnings (expenses):
Equity in earnings of unconsolidated affiliate		—			1,543			1,543			*
Interest expense		(60,921		)	(59,755		)	1,166			(2	)%
Income before income taxes		880,194			409,120			(471,074		)	(54	)%
Income tax expense		(335,460		)	(140,924		)	194,536			(58	)%
Net income and comprehensive income including noncontrolling interest		544,734			268,196			(276,538		)	(51	)%
Net income and comprehensive income attributable to noncontrolling interest		10,892			29,941			19,049			175	%
Net income and comprehensive income attributable to Antero Resources Corporation		$	533,842		$	238,255		$	(295,587	)	(55	)%
Adjusted EBITDAX		$	290,807		$	372,751		$	81,944		28	%

 

								Amount of
		Three Months Ended September 30,						Increase			Percent
		2015			2016			(Decrease)			Change
Production data:
Natural gas (Bcf)		110			128			18			16	%
C2 Ethane (MBbl)		—			1,801			1,801			*
C3+ NGLs (MBbl)		4,147			5,270			1,123			27	%
Oil (MBbl)		660			423			(237		)	(36	)%
Combined (Bcfe)		139			172			33			25	%
Daily combined production (MMcfe/d)		1,506			1,875			369			25	%
Average prices before effects of derivative settlements:
Natural gas (per Mcf)		$	2.32		$	2.86		$	0.54		23	%
C2 Ethane (per Bbl)		$	—		$	8.00		$	*		*
C3+ NGLs (per Bbl)		$	12.08		$	17.56		$	5.48		45	%
Oil (per Bbl)		$	30.49		$	34.93		$	4.44		15	%
Combined (per Mcfe)		$	2.34		$	2.82		$	0.48		21	%
Average realized prices after effects of derivative settlements:
Natural gas (per Mcf)		$	3.99		$	4.30		$	0.31		8	%
C2 Ethane (per Bbl)		$	—		$	8.00		$	*		*
C3+ NGLs (per Bbl)		$	16.47		$	19.96		$	3.49		21	%
Oil (per Bbl)		$	38.18		$	34.93		$	(3.25	)	(9	)%
Combined (per Mcfe)		$	3.83		$	3.96		$	0.13		3	%
Average Costs (per Mcfe):
Lease operating		$	0.08		$	0.08		$	—		*
Gathering, compression, processing, and transportation		$	1.16		$	1.36		$	0.20		17	%
Production and ad valorem taxes		$	0.08		$	0.09		$	0.01		13	%
Marketing, net		$	0.19		$	0.10		$	(0.09	)	(47	)%
Depletion, depreciation, amortization, and accretion		$	1.37		$	1.16		$	(0.21	)	(15	)%
General and administrative (before equity-based compensation)		$	0.26		$	0.18		$	(0.08	)	(31	)%

 

*Not meaningful or applicable

 

14