EXHIBIT 99.1

 

 

Antero Resources Reports Third Quarter 2013 Financial and Operational Results

 

Highlights:

 

·                  Net daily production averaged 566 MMcfe/d, a 25% increase over second quarter 2013 and a 128% increase over third quarter 2012 production from continuing operations

·                  Net daily production included 7,900 Bbl/d of liquids, an 89% increase over second quarter 2013

·                  Reported GAAP earnings were $118 million and adjusted net income was $49 million, a 10% decrease and 45% increase over second quarter 2013, respectively

·                  EBITDAX was $183 million, a 38% increase over second quarter 2013 and a 159% increase over third quarter 2012 EBITDAX from continuing operations

·                  Completed 34 Marcellus wells in the third quarter with an average 24-hour peak rate of 18.3 MMcfe/d (16% liquids in ethane rejection)

·                  First 13 unconstrained Marcellus Shale wells with shorter stage lengths (SSL) are averaging 20% to 30% above the Company’s type curve

·                  Completed one additional Utica Shale well since 2nd quarter 2013 press release with an average 24-hour peak rate of 7,246 Boe/d (44% liquids assuming ethane recovery)

 

Denver, Colorado, November 6, 2013—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today released its third quarter 2013 financial and operating results. The relevant financial statements are included in Antero’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2013, which has been filed with the Securities and Exchange Commission (“SEC”).

 

Recent Developments

 

Initial Public Offering

 

On October 16, 2013 Antero completed its initial public offering (IPO) of 41,083,750 shares of common stock at a price to the public of $44.00 per share, including the full exercise by the underwriters of their options to purchase an additional 3,409,091 shares of common stock from the selling stockholder and an additional 1,949,659 shares of common stock from the Company.  Net proceeds received by the Company from the sale of 37,674,659 shares of common stock were approximately $1.6 billion, after deducting underwriting discounts and expenses of the offering.  A portion of the proceeds will be used to redeem $140 million of the Company’s outstanding 7.25% Senior Notes due 2019 at a price of 107.25% of the principal amount, plus accrued and unpaid interest to the redemption date. Following the IPO, Antero elected to reduce lender commitments to its bank credit facility from $1.75 billion to $1.5 billion.  Pro forma for the IPO closing and reduced lender commitments, Antero’s $3.0 billion of net debt as of September 30, 2013 would be reduced to approximately $1.5 billion, including a fully undrawn credit facility and $32 million in letters of credit outstanding, resulting in $1.5 billion of available liquidity and $2.0 billion of unused borrowing base capacity.

 

Debt Offering

 

On November 5, 2013 Antero closed a private placement of $1.0 billion in aggregate principal amount of 5.375% senior unsecured notes due 2021 at par.  Antero received net proceeds of approximately $987 million, a portion of which will be used to finance the redemption of the Company’s outstanding $525 million of 9.375% senior notes due 2017.  The Company intends to use the remaining net proceeds to repay in full its 9.0% senior note due 2013, repay the outstanding borrowings under its credit facility and fund a portion of its drilling and development program.  Antero’s net debt as of September 30, 2013, pro forma for the IPO, optional redemptions and credit facility repayment, remains unchanged at approximately $1.5 billion, but available liquidity increased to $1.8 billion.

 

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Financial Results

 

Net production for the third quarter of 2013 averaged 566 MMcfe/d, an increase of 25% from the second quarter of 2013 and 128% from continuing operations in the third quarter of 2012.  Net production was comprised of 519 MMcf/d of natural gas (92%), 6,929 Bbl/d of natural gas liquids (NGLs) (7%) and 948 Bbl/d of crude oil (1%).  Third quarter 2013 net liquids production of 7,877 Bbl/d increased 89% from the second quarter of 2013.  The Company had virtually no liquids production in the third quarter of 2012. The net production increase was primarily driven by production from 34 new Marcellus wells and 10 new Utica wells brought on line in the third quarter of 2013.

 

Average natural gas prices before commodity derivatives increased 30% from the prior-year quarter to $3.82 per Mcf, a $0.22 per Mcf premium to NYMEX, due to higher natural gas prices and an increase in Antero’s average residue gas heating value or Btu.  Additionally, 67% of Antero’s third quarter 2013 natural gas revenues were realized at the Columbia Gas Transmission (TCO) index price at a $0.07 per Mcf negative differential to NYMEX but at a net $0.34 per Mcf positive differential to NYMEX after Btu upgrade.  The Company’s remaining natural gas revenues were realized at various other index pricing points at a $0.21 per Mcf negative differential to NYMEX but at a net $0.01 per Mcf negative differential to NYMEX after Btu upgrade.

 

Average realized propane-plus (C3+) NGL prices for the third quarter of 2013 were $50.13 per barrel and average realized oil prices were $97.10 per barrel.  Average natural gas-equivalent prices including NGLs and oil, before hedge settlements, increased 45% to $4.27 per Mcfe from the prior year quarter.

 

Average realized natural gas prices including commodity derivatives were $4.81 per Mcf for the third quarter of 2013, a 2% decrease as compared to the third quarter of 2012.  Average natural gas-equivalent prices including NGLs, oil and hedge settlements, increased by 6% to $5.18 per Mcfe for the third quarter of 2013 as compared to the third quarter of 2012.  For the third quarter of 2013, Antero realized natural gas hedging gains of $0.91 per Mcfe.

 

Revenues for the third quarter of 2013 were $385 million as compared to $(92) million for the third quarter of 2012.  Revenues for the third quarter of 2013 included a $115 million non-cash gain on unsettled commodity derivatives while the third quarter of 2012 included a $204 million non-cash loss on unsettled commodity derivatives.  Liquids production contributed 18% of oil, NGLs and natural gas revenues before commodity derivatives in the third quarter of 2013 compared to less than 1% during the third quarter of 2012.  Non-GAAP adjusted net revenues increased 141% to $270 million compared to the third quarter of 2012 (including cash-settled derivative gains and losses but excluding unsettled derivative gains and losses).  For a reconciliation of adjusted net revenue to operating revenues, the most comparable GAAP measure, please read “Non-GAAP Financial Measures.”

 

Per unit cash production expense (lease operating, gathering, compression, processing and transportation, and production tax) for the third quarter of 2013 was $1.40 per Mcfe which is a 4% increase compared to $1.34 per Mcfe in the prior year quarter.  The increase was primarily driven by processing costs associated with liquids production in the third quarter of 2013.  The Company had no access to gas processing capacity in the third quarter of 2012.  Per unit general and administrative expense for the third quarter of 2013 was $0.28 per Mcfe, a 46% decrease from the third quarter of 2012.  The decrease was primarily driven by the increase in net production.  Per unit depreciation, depletion and amortization expense increased 8% from the prior year quarter to $1.27 per Mcfe, primarily driven by higher depreciation on gathering and compression assets as the Company continued to build out its gathering system in the rich gas areas of the Marcellus and Utica Shales.

 

EBITDAX from continuing operations of $183 million for the third quarter of 2013 was 159% higher than the prior-year quarter due to increased production and revenues.  For the third quarter of 2013, cash flow from continuing operations before changes in working capital, a non-GAAP financial measure, increased 309% from the prior-year quarter to $141 million.

 

The Company had net income of $118 million ($0.45 per basic and diluted share on a pro forma basis) on a GAAP basis for the third quarter of 2013, including $115 million of non-cash gains on unsettled commodity derivatives and $47 million of settled gains on commodity derivatives during the quarter.  Excluding the non-cash gain on unsettled commodity derivatives and a $2 million non-cash impairment expense, both net of tax, adjusted net income, a non-GAAP measure, was $49 million ($0.19 per basic and diluted share on a pro forma basis) for the third quarter of 2013 as compared to $12 million for the prior year quarter.

 

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

 

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Operational Results

 

All operational figures are as of the date of this release unless otherwise noted.

 

During the third quarter of 2013, Antero completed 44 gross (40 net) operated horizontal wells in the Marcellus and Utica Shales with an average lateral length of 6,800 feet and currently has 65 gross (59 net) operated wells in various stages of drilling, completion, or waiting on completion in the Marcellus and Utica Shale projects.

 

Marcellus Shale — Antero is currently operating 15 drilling rigs in the Marcellus Shale play, including four intermediate rigs that drill the vertical section of some horizontal wells to the kick-off point at approximately 6,000 feet.  The Company plans to maintain this rig count into 2014.  Antero has 53 horizontal wells either in the process of drilling, completing or waiting on completion.  The Company has two dedicated frac crews currently working in West Virginia along with four spot frac crews.  Antero plans to drill a total of 133 horizontal Marcellus wells in 2013 with an average lateral length of 7,600 feet.

 

The 217 horizontal Marcellus wells that Antero has completed and placed on line since project inception had an average 24-hour peak rate of 14.9 MMcfe/d (9% liquids in ethane rejection), an average lateral length of approximately 7,000 feet, an average Btu of 1120 and an average drilling and completion cost of $9.2 million per well.  Additionally, 209 of these wells have been on line for more than 30 days and had an average 30-day rate of 8.5 MMcfe/d in ethane rejection.  In the third quarter of 2013, Antero completed 34 horizontal Marcellus Shale wells with an average 24-hour peak rate of 18.3 MMcfe/d (16% liquids in ethane rejection), an average lateral length of approximately 7,100 feet, an average Btu of 1190 and an average drilling and completion cost of $10.3 million per well.  Additionally, 33 of these wells had an average 30-day rate of 10.4 MMcfe/d in ethane rejection, despite being partially curtailed throughout the quarter due to compression constraints.

 

During the third quarter, Antero completed 19 Marcellus wells with SSL completions meaning average frac stage lengths less than 225 feet.  While Antero wells utilizing SSL completions have limited production history, Antero is encouraged by its well results as well as those of other operators in the southwestern core of the Marcellus who have implemented shorter stage lengths and reduced cluster spacing completions.  To date, Antero has completed and placed on line 13 relatively unconstrained wells utilizing SSL completions.  Having been on line for up to 100 days, these wells are currently 20% to 30% above Antero’s type curve.  The SSL well cost was approximately 20% higher than comparable wells with average stage lengths of 350 feet.  Antero plans to continue with SSL completions as it optimizes completion techniques and expects future completed well costs, assuming SSL completions, access to the Company’s new fresh water distribution system, and a 7,000 foot lateral to average $9.0 to $9.5 million.

 

Antero has access to a total of 400 MMcf/d of cryogenic processing capacity at the MarkWest Sherwood processing facility located in Doddridge County, West Virginia.  Currently the Sherwood complex is running at near full capacity.  Antero has committed to a third 200 MMcf/d cryogenic processing plant, Sherwood III, which is expected to go on line in the fourth quarter of 2013, a fourth 200 MMcf/d plant, Sherwood IV, expected to go on line in the second quarter of 2014 and a fifth 200 MMcf/d plant, Sherwood V, expected to go on line in the fourth quarter of 2014.  These commitments provide Antero access to a total of 1 Bcf/d of Marcellus cryogenic processing capacity.  Ethane is currently being rejected at the processing facility and left in the gas stream.  Recently, additional third-party compression capacity came on line in eastern and central Doddridge County relieving some of the constraints on the Company’s rich gas production.

 

Since the second quarter 2013 earnings release, Antero has increased its Marcellus acreage position by 9,000 net acres resulting in 334,000 net acres in the southwestern core of the Marcellus Shale play.  Approximately 27% of this net acreage was associated with proved reserves at mid-year 2013 and approximately 68% of Antero’s Marcellus leasehold is prospective for processable rich gas assuming an 1100 Btu cutoff.

 

Utica Shale — Antero is currently operating four drilling rigs, including one intermediate rig, in the rich gas/condensate window of the core of the Utica Shale play in southeastern Ohio.  The Company plans to add a fifth rig in the fourth quarter of 2013 and expects to maintain this rig count into 2014.  In addition to its 12 wells on line, Antero has 12 wells either in the process of drilling, completing, or waiting on completion including a 4-well pad and a 2-well pad, both located in Noble County, Ohio, that are currently being completed and expected to be placed on line in the fourth quarter of 2013.  Antero has one dedicated frac crew currently working in Ohio along with several spot crews available as needed.  Antero plans to drill a total of 24 horizontal Utica wells in 2013 with an average lateral length of 7,300 feet.

 

Antero recently placed on line the Gary 2H well that produced at a 24-hour peak rate of 24.2 MMcf/d of natural gas, 162 Bbl/d of condensate and 3,053 Bbl/d of NGLs assuming full ethane recovery (per current industry practice and assuming typical ethane plant product recoveries of 85% to 90%).  The Gary 2H had a natural gas shrink of 16% associated with 1220 Btu wellhead gas and an oil-equivalent rate of 7,246 Boe/d (44% liquids). This rate is the fourth highest peak rate announced in the Utica Shale to date.  The well is located in Monroe County, Ohio, and was drilled with a lateral length of 8,900 feet.  The initial 12 horizontal Utica wells that Antero has completed and placed online to date have an average 24-hour peak rate of 5,635 Boe/d assuming ethane recovery, an average lateral length of approximately 6,500 feet, an average Btu of 1240 and an average drilling and completion cost of $12.3

 

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million per well.  Antero expects well costs to decline as well completions have access to the Company’s fresh water distribution system and drilling and completion efforts are optimized.

 

Rich gas production from all but one of Antero’s 12 completed horizontal Utica wells, previously processed at the MarkWest Cadiz facility, is now being processed at the recently commissioned Seneca processing complex.  MarkWest recently completed Seneca I, a 200 MMcf/d cryogenic processing plant, and is also building Seneca II, a second 200 MMcf/d cryogenic processing plant, which is expected to be in service late in the fourth quarter of 2013.  Antero has firm processing capacity of 200 MMcf/d in Seneca I and an additional 50 MMcf/d of interim capacity at the Seneca II facility until early third quarter 2014.  Antero recently committed to 100 MMcf/d of firm processing capacity at a third 200 MMcf/d facility to be constructed at the Seneca complex, Seneca III, which is expected to be placed on line in the second quarter of 2014.  The Company also has the option to increase the Seneca III commitment to the full 200 MMcf/d of plant capacity by early third quarter 2014.  This results in total firm processing capacity of 350 MMcf/d by second quarter of 2014 with an option to increase to a total of 400 MMcf/d by early third quarter 2014.  Additional processing beyond this timeframe is in the planning stages.  Ethane is currently being rejected at the processing facility and left in the gas stream.

 

Antero’s rich gas production going into the Seneca processing complex is flowing against 1100 psi of line pressure until compression capacity comes on line, resulting in constrained production.  Antero has a compression and condensate stabilization agreement with a third-party midstream provider to construct and operate three compressor stations in Noble and Monroe Counties, Ohio that have a combined capacity of 340 MMcf/d as well as three condensate stabilization facilities with a combined capacity of 16,000 Bbl/d, all of which are fully dedicated to Antero.  The first two compressor stations and condensate stabilization facilities are expected to start up in the fourth quarter of 2013 while the third compressor station and condensate stabilization facility is expected to start up early in the second quarter of 2014.  Antero continues to lay both low- and high-pressure gas gathering pipelines to transport its future production to the Seneca complex.

 

Since the second quarter 2013 earnings release, Antero has added 3,000 net acres and currently holds approximately 104,000 net acres of leasehold in the core of the Utica Shale play.  Approximately 4% of this net acreage was associated with proved reserves at mid-year 2013 and approximately 75% of Antero’s Utica leasehold is prospective for processable rich gas assuming an 1100 Btu cutoff.

 

Antero has an additional 116,000 net acres of deep rights underlying its Marcellus acreage that has Utica dry gas resource potential.  The Company has identified 950 potential drilling locations on this acreage with approximately 5 Tcf of net resource.  Antero plans to drill a Utica dry gas well in West Virginia in early 2014.

 

Capital Spending

 

Antero’s drilling and completion costs for the three months ended September 30, 2013 were $509 million including $73 million for our water-handling infrastructure projects in the Marcellus and Utica Shales.  In addition, during the third quarter of 2013, $72 million was expended on acreage purchases and $88 million on gathering systems and compression.

 

Antero has completed approximately 75% and 60% of its planned 2013 Marcellus and Utica Shale fresh water sourcing infrastructure projects, respectively.  The Company expects these projects to service over 30% of its planned fourth quarter 2013 well completions and over 90% of its planned 2014 well completions.  Additionally, during the third quarter of 2013, Antero constructed and placed into service approximately 26 miles of gathering pipelines in West Virginia and Ohio.

 

Commodity Hedges

 

As of September 30, 2013 Antero has hedged 1,104 Bcf and 1.5 MMBbl of future natural gas and oil production using fixed price swaps covering the period from October 1, 2013 through December 31, 2019 at average index price of $4.71/MMBtu and $98.50/Bbl, respectively.  During the third quarter of 2013, Antero increased its hedge position by 162 Bcf and 1.4 MMBbl.  Approximately 34% of Antero’s financial hedges are NYMEX hedges and 66% are tied to the Appalachian Basin or Chicago.  For the NYMEX hedges, Antero physically delivers its hedged gas through backhaul firm transportation to Henry Hub, the index for NYMEX pricing, which eliminates basis risk on these NYMEX hedges.  Antero has 11 different counterparties to its hedge contracts, all but one of which are lenders under Antero’s bank facility.

 

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As of September 30, 2013, the Company’s positions in fixed price natural gas and oil swaps from October 1, 2013 through December 31, 2019 are summarized in the following table:

 

		MMbtu/d		Bbl/d		Price
Three Months ending December 31, 2013:
CGTAP (TCO)		260,000		—		$	4.56
Dominion South		190,844		—		4.89
NYMEX-WTI		—		4,300		103.97
2013 Total		450,844		4,300
Year ending December 31, 2014:
CGLA		10,000				$	3.87
CGTAP (TCO)		210,000				5.11
Dominion South		160,000				5.15
NYMEX		120,000				4.00
NYMEX-WTI		—		3,000		96.53
2014 Total		500,000		3,000
Year ending December 31, 2015:
CGLA		40,000				$	4.00
CGTAP (TCO)		130,000				4.93
Dominion South		230,000				5.60
NYMEX		80,000				4.10
2015 Total		480,000
Year ending December 31, 2016:
CGLA		170,000				$	4.09
CGTAP (TCO)		80,000				4.67
Dominion South		272,500				5.35
NYMEX		60,000				4.25
2016 Total		582,500
Year ending December 31, 2017:
CGLA		420,000				$	4.27
NYMEX		220,000				4.44
CCG		70,000				4.57
CGTAP (TCO)		20,000				4.02
2017 Total		730,000
Year ending December 31, 2018:
NYMEX		530,000				$	4.73
Year ending December 31, 2019:
NYMEX		87,500				$	4.75

 

Fourth Quarter 2013 Outlook:

 

The Company is using the following key assumptions in its projections for the fourth quarter 2013:

 

4Q 2013 Outlook:

 

Net Production		660 – 690 MMcfe/d
Net Liquids Production		12,000 – 15,000 Bbl/d
Production Expense(1)		$1.40 – $1.50/Mcfe
G&A Expense		$0.25 – 0.30/Mcfe

 

(1)         Includes lease operating expenses, gathering, compression and transportation expenses and production taxes.

 

Antero’s fourth quarter 2013 net production is expected to average in a range of 660 to 690 MMcfe/d which would represent a 17% to 22% increase compared to the third quarter of 2013 production and a 109% to 119% increase as compared to our fourth quarter 2012 average net production of 316 MMcfe/d from continuing operations.  Net liquids production is expected to increase to an average of 12,000 to 15,000 Bbl/d in the fourth quarter of 2013 primarily driven by expanding Marcellus Shale processing capacity and rich gas volumes and the initiation of gas processing and rich gas volumes in our Utica Shale project which would represent a 52% to 90%

 

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increase compared to the third quarter of 2013 production and a 289% to 386% increase as compared to our fourth quarter 2012 average net production of 3,086 Bbl/d from continuing operations.

 

Based on current commodity price markets, Antero expects its natural gas realized price differentials to be a positive $0.20/Mcf to $0.25/Mcf compared to NYMEX.  Realized NGL prices are expected to be 45% to 55% of WTI and realized oil prices are expected to be $8.00/Bbl to $10.00/Bbl below WTI.

 

Antero’s 2013 capital expenditures are expected to total $2,650 million including $1,550 million for drilling and completion, $450 million for land and $650 million for midstream infrastructure including the construction of fresh water sourcing infrastructure and gathering pipelines and facilities.  This revised 2013 capital budget represents a $100 million increase to the drilling and completion budget including an increased number of SSL completions, longer lateral lengths and higher average working interests.  Based on the positive early results on wells utilizing SSL completions, Antero has elected to implement this completion methodology on approximately 75% of its third and fourth quarter 2013 drilling locations.  In addition, due to the success of the in-fill acreage leasing efforts, the Company expects to increase its average drilled lateral length by 4% during the second half of 2013 compared to the prior budget.  The successful acreage adds also had the effect of increasing the average working interest on wells drilled in the second half of 2013 to 97% from 95% in the prior budget.  This updated capital budget also represents a $50 million increase to the midstream budget for the acceleration of compression projects planned in 2014 and $50 million of additional land expenditures due to the assumption of an additional 10,000 processable net acres acquired than in the prior budget in West Virginia and Ohio.

 

Conference Call

 

A conference call to review the results is scheduled on Thursday, November 7 at 9:00 a.m. MT.  To participate in the call, dial in at 877-317-6789 (U.S.), 866-605-3852 (Canada), or 412-317-6789 (International) and reference passcode 10035927. A telephone replay of the call will be available until November 18, 2013 at 877-344-7529 or 412-317-0088 (International) using the same pass code.

 

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 November 18.

 

Presentation

 

An updated presentation will be posted to the Company’s website before the November 7, 2013 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.

 

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Non-GAAP Financial Measures

 

Adjusted net revenue as set forth in this release represents operating revenues adjusted for certain non-cash items, including unsettled derivative gains and losses and gains and losses on asset sales.  The Company believes that adjusted net revenue is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net revenue is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenues as an indicator of financial performance.  The following table reconciles total operating revenues to adjusted net revenues:

 

		Three months ended September 30,						Nine months ended September 30,
		2012			2013			2012			2013
Total operating revenues		$	(92,038	)	$	384,522		$	500,628		$	833,120
Commodity derivative (gains) losses		159,004			(161,968		)	(52,210		)	(285,510		)
Cash receipts for settled derivatives		44,790			47,034			141,506			109,311
Loss (gain) on sale of gathering system		115			—			(291,190		)	—
Adjusted net revenues		$	111,871		$	269,588		$	298,734		$	656,921

 

Adjusted net income as set forth in this release represents income from continuing operations, adjusted for certain non-cash items.  We believe that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) from continuing operations as an indicator of financial performance.  The following table reconciles net income (loss) from continuing operations to adjusted net income:

 

		Three months ended September 30,						Nine months ended September 30,
		2012			2013			2012			2013
Net income (loss) from continuing operations		$	(113,887	)	$	117,794		$	140,431		$	200,990
Non-cash commodity derivative (gains) losses on unsettled derivatives, net of tax		124,518			(71,029		)	54,560			(108,891		)
Impairment of unproved properties, net of tax		1,490			1,981			2,456			5,911
Gain on sale of gathering system, net of tax		—			—			(177,917		)	—
Adjusted net income from continuing operations		$	12,121		$	48,746		$	19,530		$	98,010

 

Cash flow from continuing 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 continuing 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 continuing 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 continuing 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 continuing operations before changes in working capital as used in this release:

 

		Three months ended September 30,						Nine months ended September 30,
		2012			2013			2012			2013
Net cash provided by operating activities		$	64,416		$	139,540		$	225,400		$	331,937
Net change in working capital		(5,470		)	1,194			(9,510		)	(13,529		)
Cash flow from operations before changes in working capital		58,946			140,734			215,890			318,408
Cash flow from discontinued operations before changes in working capital		24,566			—			124,846			—
Cash flow from continuing operations before changes in working capital		$	34,380		$	140,734		$	91,044		$	318,408

 

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EBITDAX is a non-GAAP financial measure that we define as net income (loss) from continuing operations after adjusting for those items shown in the table below.  EBITDAX, as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP.  EBITDAX should not be considered in isolation or as a substitute for operating income, net income or loss, cash flows from operating, investing and financing activities, or other income or cash flow statement data prepared in accordance with GAAP.  EBITDAX provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.  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, our management team believes EBITDAX is useful to an investor in evaluating our 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 our operations from period to period by removing the effect of our capital structure from our operating structure; and

 

·                  is used by our management team for various purposes, including as a measure of operating performance, in presentations to our board of directors, as a basis for strategic planning and forecasting and by our lenders pursuant to covenants under our credit facility and the indentures governing our senior notes.

 

There are significant limitations to using EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies and the different methods of calculating EBITDAX reported by different companies.  The following table represents a reconciliation of our net income (loss) from continuing operations to EBITDAX from continuing operations, a reconciliation of our income (loss) from discontinued operations to EBITDAX from discontinued operations and a reconciliation of our total EBITDAX to net cash provided by operating activities for the three and nine months ended September 30, 2012 and 2013:

 

		Three months ended September 30,						Nine months ended September 30,
		2012			2013			2012			2013
Net income (loss) from continuing operations		$	(113,887	)	$	117,794		$	140,431		$	200,990
Commodity derivative fair value (gains) losses		159,004			(161,968		)	(52,210		)	(285,510		)
Net cash receipts on settled derivative instruments		44,790			47,034			141,506			109,311
(Gain) loss on sale of assets		115			—			(291,190		)	—
Interest expense		22,453			37,444			71,046			100,840
Provision (benefit) for income taxes		(75,444		)	67,370			108,525			120,695
Depreciation, depletion, amortization and accretion		26,883			65,963			65,360			159,447
Impairment of unproved properties		2,438			3,205			4,019			9,564
Exploration expense		3,156			5,372			7,912			17,034
Other		996			620			2,992			1,820
EBITDAX from continuing operations		70,504			182,834			198,391			434,191
Income (loss) from discontinued operations		(13,791		)	3,100			(418,465		)	3,100
Commodity derivative fair value (gains) losses		18,880			—			(46,358		)	—
Net cash receipts on settled derivative instruments		13,862			—			79,736			—
Loss (gain) on sale of assets		—			(5,000		)	427,232			(5,000		)
Provision (benefit) for income taxes		(8,642		)	1,900			4,085			1,900
Depreciation, depletion, amortization and accretion		14,288			—			77,654			—
Impairment of unproved properties		(31		)	—			962			—
Exploration expense		95			—			507			—
EBITDAX from discontinued operations		24,661			—			125,353			—
Total EBITDAX		95,165			182,834			323,744			434,191
Interest expense and other		(22,453		)	(37,444		)	(71,046		)	(100,840		)
Exploration expense		(3,156		)	(5,372		)	(7,912		)	(17,034		)
Changes in current assets and liabilities		5,470			(1,194		)	9,510			13,529
Other		(10,610		)	716			(28,896		)	2,091
Net cash provided by operating activities		$	64,416		$	139,540		$	225,400		$	331,937

 

8

 

Antero Resources is an independent oil and natural gas company engaged in the acquisition, development and production of unconventional oil and liquids-rich natural gas properties located in the Appalachian Basin in West Virginia, Ohio and Pennsylvania. Our 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, other than historical facts included in this release, are forward-looking statements. 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.

 

We caution 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 our 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, NGLs 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 “Risk Factors” in our Final Prospectus dated October 9, 2013 on file with the Securities and Exchange Commission (File No. 333-189284).

 

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

 

9

 

ANTERO RESOURCES LLC

 

Condensed Consolidated Balance Sheets

 

December 31, 2012 and September 30, 2013

 

(Unaudited)

 

(In thousands)

 

		2012			2013
Assets
Current assets:
Cash and cash equivalents		$	18,989		11,584
Accounts receivable		21,296			33,023
Notes receivable — current portion		4,555			3,111
Accrued revenue		46,669			86,122
Derivative instruments		160,579			204,857
Other		22,518			20,816
Total current assets		274,606			359,513
Property and equipment:
Oil and natural gas properties, at cost (successful efforts method):
Unproved properties		1,243,237			1,420,719
Proved properties		1,689,132			3,199,830
Gathering systems and facilities		168,930			455,818
Other property and equipment		9,517			12,741
		3,110,816			5,089,108
Less accumulated depletion, depreciation, and amortization		(173,343		)	(331,993	)
Property and equipment, net		2,937,473			4,757,115
Derivative instruments		371,436			503,666
Notes receivable — long-term portion		2,667			—
Other assets, net		32,611			51,914
Total assets		$	3,618,793		5,672,208
Liabilities and Equity
Current liabilities:
Accounts payable		$	181,478		311,092
Accrued liabilities and other		61,161			103,359
Derivative instruments		—			309
Revenue distributions payable		46,037			68,926
Current portion of long-term debt		25,000			25,000
Deferred income tax liability		62,620			78,199
Total current liabilities		376,296			586,885
Long-term liabilities:
Long-term debt		1,444,058			2,970,455
Deferred income tax liability		91,692			202,708
Other long-term liabilities		33,010			34,333
Total liabilities		1,945,056			3,794,381
Equity:
Members’ equity		1,460,947			1,460,947
Accumulated earnings		212,790			416,880
Total equity		1,673,737			1,877,827
Total liabilities and equity		$	3,618,793		5,672,208

 

10

 

ANTERO RESOURCES LLC

 

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

 

Three Months ended September 30, 2012 and 2013

 

(Unaudited)

 

(In thousands, except per share amounts)

 

		2012			2013
Revenue:
Natural gas sales		$	66,796		182,125
Natural gas liquids sales		—			31,956
Oil sales		285			8,473
Commodity derivative fair value gains (losses)		(159,004		)	161,968
Loss on sale of assets		(115		)	—
Total revenue		(92,038		)	384,522
Operating expenses:
Lease operating		1,513			2,697
Gathering, compression, processing, and transportation		25,291			58,383
Production taxes		3,621			11,851
Exploration		3,156			5,372
Impairment of unproved properties		2,438			3,205
Depletion, depreciation, and amortization		26,858			65,697
Accretion of asset retirement obligations		25			266
General and administrative		11,938			14,443
Total operating expenses		74,840			161,914
Operating income (loss)		(166,878		)	222,608
Interest expense		(22,453		)	(37,444		)
Income (loss) from continuing operations before income taxes and discontinued operations		(189,331		)	185,164
Income tax (expense) benefit		75,444			(67,370		)
Income (loss) from continuing operations		(113,887		)	117,794
Discontinued operations:
Income (loss) from results of operations and sale of discontinued operations		(13,791		)	3,100
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners		$	(127,678	)	120,894
Pro forma information:
Pro forma earnings (loss) per share - basic:
Continuing operations		$	(0.44	)	$	0.45
Discontinued operations		$	(0.05	)	$	.01
Net income (loss)		$	(0.49	)	$	0.46
Pro forma earnings (loss) per share - diluted:
Continuing operations		$	(0.44	)	$	0.45
Discontinued operations		$	(0.05	)	$	.01
Net income (loss)		$	(0.49	)	$	0.46
Pro forma weighted average number of shares outstanding:
Basic		262,050			262,050
Diluted		262,050			262,050

 

11

 

ANTERO RESOURCES LLC

 

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

 

Nine Months ended September 30, 2012 and 2013

 

(Unaudited)

 

(In thousands, except per share amounts)

 

		2012			2013
Revenue:
Natural gas sales		$	156,618		476,403
Natural gas liquids sales		—			59,772
Oil sales		610			11,435
Commodity derivative fair value gains		52,210			285,510
Gain on sale of gathering system		291,190			—
Total revenue		500,628			833,120
Operating expenses:
Lease operating		4,072			5,222
Gathering, compression, processing, and transportation		56,945			148,023
Production taxes		10,734			30,578
Exploration		7,912			17,034
Impairment of unproved properties		4,019			9,564
Depletion, depreciation, and amortization		65,289			158,650
Accretion of asset retirement obligations		71			797
General and administrative		31,584			40,727
Total operating expenses		180,626			410,595
Operating income		320,002			422,525
Interest expense		(71,046		)	(100,840		)
Income from continuing operations before income taxes and discontinued operations		248,956			321,685
Income tax expense		(108,525		)	(120,695		)
Income from continuing operations		140,431			200,990
Discontinued operations:
Income (loss) from results of operations and sale of discontinued operations		(418,465		)	3,100
Net income (loss) and comprehensive income (loss) attributable to Antero equity owners		$	(278,034	)	204,090
Pro forma information:
Pro forma earnings (loss) per share - basic:
Continuing operations		$	0.54		$	0.77
Discontinued operations		$	(1.60	)	$	0.01
Net income (loss)		$	(1.06	)	$	0.78
Pro forma earnings (loss) per share - diluted:
Continuing operations		$	0.54		$	0.77
Discontinued operations		$	(1.60	)	$	0.01
Net income (loss)		$	(1.06	)	$	0.78
Pro forma weighted average number of shares outstanding:
Basic		262,050			262,050
Diluted		262,050			262,050

 

12

 

ANTERO RESOURCES LLC

 

Condensed Consolidated Statements of Cash Flows

 

Nine Months ended September 30, 2012 and 2013

 

(Unaudited)

 

(In thousands)

 

		2012			2013
Cash flows from operating activities:
Net income (loss)		$	(278,034	)	204,090
Adjustment to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, amortization, and accretion		65,360			159,447
Impairment of unproved properties		4,019			9,564
Commodity derivative fair value gains		(52,210		)	(285,510	)
Cash receipts for settled derivatives		141,506			109,311
Gain on sale of assets		(291,190		)	—
Loss (gain) on sale of discontinued operations		427,232			(5,000	)
Deferred income tax expense		87,695			120,695
Depletion, depreciation, amortization, accretion, and impairment of unproved properties — discontinued operations		78,616			—
Commodity derivative fair value gains - discontinued operations		(46,358		)	—
Cash receipts for settled derivatives - discontinued operations		79,736			—
Deferred income tax expense — discontinued operations		4,085			1,900
Other		(4,567		)	3,911
Changes in current assets and liabilities:
Accounts receivable		(16,811		)	(11,727	)
Accrued revenue		17,378			(39,453	)
Other current assets		(3,112		)	1,702
Accounts payable		(9,812		)	(4,602	)
Accrued liabilities		7,281			44,720
Revenue distributions payable		(414		)	22,889
Other		15,000			—
Net cash provided by operating activities		225,400			331,937
Cash flows from investing activities:
Additions to proved properties		(4,451		)	—
Additions to unproved properties		(428,574		)	(342,832	)
Development costs		(619,344		)	(1,267,086	)
Additions to gathering systems and facilities		(58,748		)	(240,119	)
Additions to other property and equipment		(2,786		)	(3,225	)
Proceeds from asset sales		816,167			—
Changes in other assets		2,556			(11,622	)
Net cash used in investing activities		(295,180		)	(1,864,884	)
Cash flows from financing activities:
Issuance of senior notes		—			231,750
Borrowings on bank credit facility, net		82,000			1,295,500
Payments of deferred financing costs		—			(8,334	)
Other		992			6,626
Net cash provided by financing activities		82,992			1,525,542
Net increase (decrease) in cash and cash equivalents		13,212			(7,405	)
Cash and cash equivalents, beginning of period		3,343			18,989
Cash and cash equivalents, end of period		$	16,555		11,584
Supplemental disclosure of cash flow information:
Cash paid during the period for interest		$	(61,930	)	(70,221	)
Supplemental disclosure of noncash investing activities:
Increase in accounts payable for additions to properties, gathering systems, and facilities		$	73,430		134,525

 

13

 

OPERATING DATA

 

The following table sets forth selected operating data (as recast for discontinued operations) for the three months ended September 30, 2012 compared to the three months ended September 30, 2013:

 

		Three Months Ended September 30,						Amount of Increase
		2012			2013			(Decrease)			Percent Change
		(in thousands, except per unit and production data)
Operating revenues:
Natural gas sales		$	66,796		$	182,125		$	115,329		173	%
NGL sales		—			31,956			31,956			*
Oil sales		285			8,473			8,188			2,873
Commodity derivative fair value gains (losses)		(159,004		)	161,968			320,972			*
Loss on sale of assets		(115		)	—			115			*
Total operating revenues		(92,038		)	384,522			476,560			*
Operating expenses:
Lease operating expense		1,513			2,697			1,184			78	%
Gathering, compression, processing, and transportation		25,291			58,383			33,092			131	%
Production taxes		3,621			11,851			8,230			227	%
Exploration expenses		3,156			5,372			2,216			70	%
Impairment of unproved properties		2,438			3,205			767			31	%
Depletion, depreciation, and amortization		26,858			65,697			38,839			145	%
Accretion of asset retirement obligations		25			266			241			964	%
General and administrative		11,938			14,443			2,505			21	%
Total operating expenses		74,840			161,914			87,074			116	%
Operating income (loss)		(166,878		)	222,608			389,486			*
Interest expense		(22,453		)	(37,444		)	(14,991		)	67	%
Income (loss) before income taxes		(189,331		)	185,164			374,495			*
Income tax benefit (expense)		75,444			(67,370		)	(142,814		)	*
Income (loss) from continuing operations		(113,887		)	117,794			231,681			*
Income (loss) from discontinued operations		(13,791		)	3,100			16,891			*
Net income (loss) attributable to Antero members		$	(127,678	)	$	120,894		$	248,572		*
EBITDAX from continuing operations		$	70,504		$	182,834		$	112,330		159	%
Total EBITDAX		$	95,165		$	182,834		$	87,669		92	%
Production data:
Natural gas (Bcf)		23			48			25			109	%
NGLs (MBbl)		—			637			637			*
Oil (MBbl)		4			87			83			2,393	%
Combined (Bcfe)		23			52			29			128	%
Daily combined production (MMcfe/d)		248			566			318			128	%
Average prices before effects of hedges:
Natural gas (per Mcf)		$	2.93		$	3.82		$	0.89		30	%
NGLs (per Bbl)		$	—		$	50.13		$	50.13		*
Oil (per Bbl)		$	81.20		$	97.10		$	15.90		20	%
Combined (per Mcfe)		$	2.94		$	4.27		$	1.33		45	%
Average realized prices after effects of hedges:
Natural gas (per Mcf)		$	4.89		$	4.81		$	(0.08	)	(2	)%
NGLs (per Bbl)		$	—		$	50.13		$	50.13		*
Oil (per Bbl)		$	81.20		$	94.71		$	13.51		17	%
Combined (per Mcfe)		$	4.90		$	5.18		$	0.28		6	%
Average costs (per Mcfe):
Lease operating costs		$	0.07		$	0.05		$	(0.02	)	(29	)%
Gathering, compression, processing, and transportation		$	1.11		$	1.12		$	0.01		1	%
Production taxes		$	0.16		$	0.23		$	0.07		44	%
Depletion, depreciation, amortization, and accretion		$	1.18		$	1.27		$	0.09		8	%
General and administrative		$	0.52		$	0.28		$	(0.24	)	(46	)%

 

14