EX-99.1 2 a13-18588_1ex99d1.htm EX-99.1

EXHIBIT 99.1

 

 

Antero Resources Reports Second Quarter 2013 Financial Results, Utica First Production and Well Rates

 

Highlights:

 

·                  Net daily production averaged 458 MMcfe/d, up 115% over second quarter 2012 production from continuing operations

·                  Net daily liquids production averaged 4,160 Bbl/d, up 74% over first quarter 2013 liquids production

·                  Reported GAAP earnings were $131 million and adjusted net income was $34 million

·                  EBITDAX was $133 million, up 120% over second quarter 2012 EBITDAX from continuing operations

·                  Current estimated combined net production is 580 MMcfe/d including 8,400 Bbl/d of NGLs and condensate

·                  Producing 35 MMcfe/d net (6,200 Boe/d) from Utica including 1,500 Bbl/d of liquids with first two wells flowing to processing

·                  Antero’s first 11 Utica Shale wells had average 24-hour peak rate of 5,600 Boe/d, a 6,300 ft lateral and 57% liquids (ethane recovery assumed)

·                  Antero’s first four Marcellus wells with shorter stage lengths had average 24-hour peak rate of 25.3 MMcfe/d, a 7,000 ft lateral, 190 ft stages and 45% liquids (ethane recovery assumed)

·                  18 Antero-operated drilling rigs currently running in Marcellus and Utica

·                  Lender commitments on credit facility increased by 21% to $1.45 billion

·                  Proved reserves increased 47% from year-end 2012 to 6.3 Tcfe at mid-year in each case assuming ethane rejection

 

Denver, Colorado, August 13, 2013—Antero Resources today released its second quarter 2013 results. The relevant financial statements are included in Antero Resources LLC’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013, which has been filed with the Securities and Exchange Commission (“SEC”).

 

Recent Developments

 

Effective June 27, 2013, the lender commitments under Antero’s credit facility increased to $1.45 billion.  This represents a $250 million increase over Antero’s previous lender commitments of $1.2 billion.  The $1.45 billion in commitments can be expanded to the full $1.75 billion borrowing base upon lender approval. The next borrowing base redetermination is expected to occur in September 2013.  Antero has $25 million of debt maturing prior to the May 2016 maturity date of the credit facility.

 

Antero’s proved reserves at June 30, 2013 were 6.3 Tcfe, a 47% increase compared to reserves at December 31, 2012, in each case assuming ethane rejection.  The June 30, 2013 reserves exclude 178 MMBbls of ethane which are not recovered through processing due to current SEC price assumptions for ethane and methane.  Proved, probable and possible reserves (3P) taken in the aggregate totaled 27.7 Tcfe at June 30, 2013, a 28% increase compared to 3P reserves in the aggregate at December 31, 2012, also assuming ethane rejection.  The aggregate 3P reserves exclude 984 MMBbls of ethane.  The June 30, 2013 3P reserves were comprised of 18.7 Tcfe in the Marcellus Shale, 5.3 Tcfe in the Utica Shale and 3.8 Tcfe in the Upper Devonian Shale.

 

Financial Results

 

Net production for the second quarter of 2013 increased to 42 Bcfe, a 115% increase over net production from continuing operations in the second quarter of 2012.  Second quarter 2013 net production increased 20% from net production of 34 Bcfe in the first quarter 2013.  The sequential net production increase was primarily driven by production from 26 new wells brought on line in the second quarter of 2013 in the Marcellus Shale.  Net production of 42 Bcfe for the second quarter of 2013 was comprised of 39 Bcf of natural gas, 354,000 barrels of NGLs and 25,000 barrels of oil.  Net daily production averaged 458 MMcfe/d for the second quarter of 2013 and was comprised of 433 MMcf/d of natural gas (95%), 3,891 Bbl/d of NGLs (4%) and 269 Bbl/d of crude oil (1%).  Second quarter 2013 net daily liquids production of 4,160 Bbl/d increased 74% from net daily liquids production in the first quarter of 2013.

 

1


 

Revenues for the second quarter of 2013 were $387 million as compared to $39 million for the second quarter of 2012.  Revenues for the second quarter of 2012 included a $56 million unrealized loss on commodity derivative instruments while the second quarter of 2013 included a $181 million unrealized gain on commodity derivatives due to a decline in natural gas prices in the second quarter of 2013.  Liquids production (NGLs and oil) contributed 10% of oil, NGLs and natural gas sales before commodity hedges in the second quarter of 2013 compared to less than 1% during the second quarter of 2012.  Non-GAAP adjusted net revenues increased 117% to $206 million compared to the second quarter of 2012 (including cash-settled derivatives but excluding unrealized 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.”

 

Average natural gas prices before hedges increased 89% from the prior-year quarter to $4.37 per Mcf and average natural gas-equivalent prices before hedges increased 98% to $4.60 per Mcfe.  Average realized gas prices including hedges were $4.74 per Mcf for the second quarter of 2013, a 3% decrease as compared to the second quarter of 2012.  Average gas-equivalent prices including NGLs, oil and hedges, increased by 1% to $4.94 per Mcfe for the second quarter of 2013 as compared to the second quarter of 2012.  For the second quarter of 2013, Antero realized natural gas hedging gains of $0.34 per Mcfe.

 

The Company had net income of $131 million on a GAAP basis for the second quarter of 2013, including $181 million of unrealized gains on commodity derivatives driven by a decrease in futures prices from the previous quarter-end and the realization of $14 million of commodity gains during the quarter.  Excluding the unrealized gain on commodity derivatives and the related income tax expense, adjusted net income, a non-GAAP measure, was $34 million for the second quarter of 2013 as compared to $8 million for the prior year quarter.  For a description of adjusted net income and a reconciliation of adjusted net income to net income, please read “Non-GAAP Financial Measures”.

 

For the second quarter of 2013, cash flow from continuing operations before changes in working capital, a non-GAAP financial measure, increased 195% from the prior-year quarter to $92 million.  EBITDAX from continuing operations of $133 million for the second quarter of 2013 was 120% higher than the prior-year quarter due to increased production and revenues.  For a description of EBITDAX and cash flow from continuing operations before changes in working capital and reconciliations to their nearest comparable GAAP measures, please read “Non-GAAP Financial Measures”.

 

Per unit cash production costs (lease operating, gathering, compression, processing and transportation, and production tax) for the second quarter of 2013 were $1.44 per Mcfe a 10% increase compared to $1.31 per Mcfe in the prior year quarter.  The increase was primarily driven by processing fees incurred in the Marcellus Shale in the second quarter of 2013 following the opening of the MarkWest Energy Partners, L.P. (MarkWest) Sherwood I plant in October 2012.  Per unit depreciation, depletion and amortization expense increased 10% from the prior year quarter to $1.27 per Mcfe, primarily driven by higher depreciation on gas gathering assets as the Company continued to build out its gas gathering system in the rich gas areas of the Marcellus and Utica Shales.  On a per unit basis, general and administrative expense for the second quarter of 2013 was $0.33 per Mcfe, a 39% decrease from the second quarter of 2012, primarily driven by the increase in gas-equivalent production.

 

Capital Spending

 

Antero’s drilling and completion costs for the six months ended June 30, 2013 were $758 million including $84 million for our 200-miles of water-handling infrastructure projects in the Marcellus and Utica Shales.  In addition, during the first half of 2013, $271 million was expended on acreage purchases, $152 million on gas gathering systems and $84 million on water-handling infrastructure.  In the Marcellus, $621 million funded the drilling of 74 (72 net) wells and the completion of previously drilled wells as well as $63 million on water-handling infrastructure.  A further $126 million was expended on acreage purchases and $96 million on gas gathering systems.  In the Utica, $53 million funded the drilling of 11 (9 net) wells and the completion of previously drilled wells and $21 million was expended on water-handling infrastructure, $145 million on acreage purchases and $56 million on gas gathering systems.

 

Antero Operations

 

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

 

During the month of July 2013, Antero estimates that net production averaged 461 MMcfe/d including 4,500 Bbl/d of liquids.  Antero’s current estimated net daily production is 580 MMcfe/d, including non-operated production, NGLs and oil.  Current estimated gross operated production is 660 MMcf/d.  Antero has an additional estimated 160 MMcfe/d of net production associated with 14 completed and tested horizontal wells in the Marcellus and Utica Shales that are shut-in waiting on infrastructure and a number of producing wells that are constrained and waiting on additional pipeline and compression facilities.  The current estimated net daily production is comprised of 533 MMcf/d of natural gas and 8,400 Bbl/d of NGLs and condensate.  During the second quarter of 2013,

 

2


 

Antero completed 33 gross (32 net) operated wells in the Marcellus and Utica Shales and currently has 57 gross (54 net) operated wells in various stages of drilling, completion, or waiting on completion in the Marcellus and Utica Shale projects.

 

Utica Shale — Antero is currently operating three drilling rigs, including one intermediate rig, in the rich gas/condensate window of the core of the Utica Shale play in southern Ohio.  The Company plans to add a fourth drilling rig in the third quarter of 2013 and a fifth rig in the fourth quarter of 2013.

 

Initial production from all but one of Antero’s eleven completed horizontal Utica wells has been delayed for several months pending the completion of third-party high pressure gathering  infrastructure.  The final 16-mile segment of the Seneca to Cadiz pipeline was placed into service last week and enables Antero to transport Utica rich gas production to the MarkWest-owned and operated Cadiz processing facility.  The completion of this pipeline was delayed by approximately two months, primarily due to wet weather.  Antero subsequently brought on line two Utica Shale horizontal wells that now have access to gas processing facilities.  The Seneca to Cadiz pipeline provides Antero with interim access to 185 MMcf/d of combined cryogenic and refrigeration natural gas processing capacity at the Cadiz facility.  As an anchor producer, Antero initially has up to 82 MMcf/d of preferred interim processing capacity at Cadiz.

 

Antero continues to lay both low- and high-pressure gas gathering pipeline to transport its Utica production to the recently completed MarkWest high-pressure gathering and gas processing infrastructure.  Including Antero’s Sanford 1H horizontal well located in western Noble County, which went on line in December 2012, Antero’s wells are producing an estimated 35 MMcfe/d net, including 1,300 Bbl/d of NGLs and 200 Bbl/d of condensate.  The two wells currently being processed are flowing on a restricted choke with an average flowing casing pressure of 3,550 psi.  Ethane is currently being rejected at the processing facility and left in the gas stream.  Antero has an additional estimated 90 MMcfe/d of net production in the Utica associated with eight completed and tested horizontal wells that are shut-in waiting to be brought on line sequentially as Antero completes the well and infrastructure start-up process over the next few weeks.  The full production capacity of the eight wells will likely be somewhat constrained until the fourth quarter of 2013 when Antero-committed processing capacity at Seneca I is expected to be in-service.

 

Antero’s first 11 wells in the Utica Shale play have all been tested in order to establish 24-hour peak rates.  Based on gas composition analysis and assuming full ethane recovery, the respective 24-hour peak rates have been summarized in the following table:

 

 

 

 

 

Antero Utica Shale Wells - 24-Hour Peak Production Rates(2)

 

 

 

 

 

 

 

Well Name

 

County

 

Oil-
Equivalent
Rate
(Boe/d)(1)

 

Wellhead
Gas
(MMcf/d)

 

Condensate
(Bbl/d)

 

Shrunk Gas
(MMcf/d)(1)

 

NGL
(Bbl/d)(1)

 

%
Liquids(1)

 

BTU

 

Lateral
Length
(Feet)

 

Yontz 1H

 

Monroe

 

8,879

 

38.9

 

52

 

33.9

 

3,177

 

36

%

1161

 

5,115

 

Rubel 1H

 

Monroe

 

7,917

 

31.1

 

214

 

25.9

 

3,391

 

46

%

1231

 

6,554

 

Rubel 2H(2)

 

Monroe

 

7,816

 

30.9

 

232

 

25.8

 

3,284

 

45

%

1217

 

6,571

 

Rubel 3H(2)

 

Monroe

 

7,097

 

28.4

 

142

 

23.7

 

3,003

 

44

%

1220

 

6,424

 

Norman 1H

 

Monroe

 

6,181

 

26.1

 

45

 

22.3

 

2,419

 

40

%

1186

 

5,498

 

Wayne 3HA

 

Noble

 

5,852

 

14.7

 

1,905

 

11.6

 

2,018

 

67

%

1272

 

6,712

 

Wayne 4H

 

Noble

 

5,698

 

14.2

 

1,922

 

11.2

 

1,907

 

67

%

1265

 

6,493

 

Wayne 2H

 

Noble

 

4,257

 

10.9

 

1,331

 

8.5

 

1,503

 

67

%

1281

 

6,094

 

Miley 2H

 

Noble

 

3,740

 

8.6

 

1,450

 

6.7

 

1,172

 

70

%

1278

 

6,153

 

Miley 5HA

 

Noble

 

3,369

 

7.7

 

1,285

 

6.0

 

1,090

 

70

%

1291

 

6,296

 

Sanford 1H

 

Noble

 

1,148

 

1.8

 

653

 

1.4

 

256

 

79

%

1316

 

7,159

 

Average — Ethane Recovery

 

5,632

 

19.4

 

839

 

16.1

 

2,111

 

57

%

1247

 

6,279

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average — Ethane Rejection(3)

 

4,682

 

19.4

 

839

 

18.2

 

805

 

42

%

1247

 

6,279

 

 

(1)

24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to lack of ethane pipeline and current market prices.

(2)

Rubel 2H and 3H peak rates based on 6-hour and 4-hour flow tests, respectively.

(3)

Average of Antero’s first 11 wells assuming ethane rejection.

 

The above 24-hour peak rates represent seven of the top eight announced 24-hour peak rates in the Utica Shale play to date.  Additionally, Antero is testing optimal well density in the Utica with the three Wayne wells that were drilled on one pad and represent Antero’s first increased density pilot in the Utica utilizing 500 foot interlateral distance.  All other wells have been drilled on a 1,000 foot interlateral distance development plan.  Antero’s Utica 3P reserves are also based on 1,000 foot interlateral distance.  These first 11 Utica Shale wells had an average drilling and completion cost of $11.5 million per well.  Antero expects well costs to decline as further development occurs and drilling and completion efforts are optimized.

 

3


 

MarkWest is currently constructing the Seneca processing complex in Noble County, Ohio to process Antero’s rich gas production on a long-term basis.  Seneca I, a 200 MMcf/d cryogenic gas processing facility, is expected to begin operations in the fourth quarter 2013.  MarkWest is also building Seneca II, a second 200 MMcf/d cryogenic processing facility, which is expected to be in service late in the fourth quarter of 2013.  Antero has firm processing capacity of 150 MMcf/d in Seneca I with an option to secure the final 50 MMcf/d of capacity at its election.  Should this option be exercised in the third quarter of 2013, Antero will receive an additional 50 MMcf/d of interim capacity at the Seneca II facility until early third quarter 2014.  Antero also 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.  Antero also has the option to increase the Seneca III commitment to the full 200 MMcf/d of plant capacity by early third quarter 2014.

 

Antero has a compression and condensate stabilization agreement with a third-party 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 condensate stabilization facilities are necessary to prevent vaporization.  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 in the first quarter 2014.

 

In addition to its three wells on line, and eight wells in the process of being placed on line, Antero has seven wells either in the process of drilling, completing or waiting on completion.  Antero plans to drill a total of 21 horizontal Utica wells in 2013 with an average lateral length of 6,300 feet.  Antero currently holds approximately 101,000 net acres of leasehold in the core of the Utica Shale play.  Over 90% of Antero’s acreage is believed to be located in the liquids-rich window.

 

Marcellus Shale—Antero is currently operating 15 drilling rigs in the Marcellus Shale play, including three intermediate rigs that will drill the vertical section of some horizontal wells to the kick-off point at approximately 6,000 feet.  All 15 of these rigs are drilling in northern West Virginia.  The Company plans to move one of the drilling rigs to the Utica Shale late in the third quarter of 2013.  Currently, Antero has 620 MMcf/d of gross operated production in the Marcellus Shale virtually all of which is from 182 horizontal wells, resulting in 545 MMcfe/d of estimated net production.  The 545 MMcfe/d of estimated net production is comprised of approximately 505 MMcf/d of tailgate gas, 6,800 Bbl/d of NGLs and 100 Bbl/d of condensate.  Antero has 50 horizontal wells either in the process of drilling, completing or waiting on completion and two dedicated frac crews currently working in West Virginia and several spot frac crews available as needed.

 

The 182 horizontal Marcellus wells that Antero has completed and placed online to date have an average 24-hour peak rate of 15.6 MMcfe/d and an average 30-day rate of 8.6 MMcfe/d assuming ethane recovery, an average lateral length of approximately 7,000 feet, an average Btu of 1115 and an average drilling and completion cost of $8.7 million per well.  In the second quarter of 2013, Antero completed 25 horizontal Marcellus Shale wells with an average 24-hour peak rate of 16.6 MMcfe/d and an average 30-day rate of 9.6 MMcfe/d assuming ethane recovery, an average lateral length of approximately 6,800 feet and an average Btu of 1170.

 

During the second quarter of 2013, Antero began to complete most of its rich gas Marcellus wells with shorter stage lengths.  While Antero’s wells utilizing shorter stage lengths have limited production history, Antero is encouraged by the 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.  The following table summarizes Antero’s initial well results from wells utilizing shorter stage lengths.

 

 

 

 

 

Antero Marcellus Shale Wells - 24-Hour Peak Production Rates

 

 

 

 

 

Frac

 

Well Name

 

County

 

Equivalent
Rate
(MMcfe/d)(1)

 

Wellhead
Gas
(MMcf/d)

 

Condensate
(Bbl/d)

 

Shrunk Gas
(MMcf/d)(1)

 

NGL
(Bbl/d)(1)

 

%
Liquids(1)

 

BTU

 

Lateral
Length
(Feet)

 

Stage
Length
(Feet)

 

Sweeney 2H

 

Tyler

 

26.6

 

17.5

 

96

 

14.5

 

1,924

 

46

%

1230

 

6,395

 

237

 

Little Tom 1H

 

Doddridge

 

25.9

 

17.4

 

—

 

14.4

 

1,915

 

44

%

1225

 

7,832

 

191

 

Sweeney 1H

 

Tyler

 

24.9

 

16.3

 

90

 

13.5

 

1,799

 

46

%

1230

 

6,476

 

180

 

Webley Fork 1H

 

Doddridge

 

23.8

 

16.0

 

—

 

13.3

 

1,764

 

44

%

1225

 

7,261

 

151

 

Average — Ethane Recovery

 

 

 

25.3

 

16.8

 

47

 

13.9

 

1,850

 

45

%

1228

 

6,991

 

190

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average — Ethane Rejection(2)

 

 

 

20.1

 

16.8

 

47

 

15.9

 

659

 

21

%

1228

 

6,991

 

190

 

 

(1)   24-hour peak rates assume full ethane recovery however Antero is currently rejecting ethane due to current market prices.

(2)   Average of Antero’s first 7 wells with shorter stage length completions assuming ethane rejection.

 

4


 

Antero’s previous frac design resulted in stage lengths averaging 350 feet. Recent completions have utilized 150 to 250 foot stage lengths. Antero estimates that the incremental cost of the resulting additional frac stages per 7,000 foot lateral is in the $1.5 to $2.0 million per well range.

 

Antero has access to a total of 400 MMcf/d of cryogenic processing capacity at the MarkWest-owned and operated Sherwood processing facility located in Doddridge County, West Virginia.  Currently the Sherwood complex is running at approximately 66% of capacity.  Ethane is currently being rejected at the processing facility and left in the gas stream.  Antero has committed to a third 200 MMcf/d gas processing plant, Sherwood III, which is expected to go on line in the fourth quarter of 2013, and a fourth 200 MMcf/d plant, Sherwood IV, expected to go online in the second quarter of 2014.  These commitments provide Antero access to a total of 800 MMcf/d of Marcellus gas processing capacity.

 

During the past several months, Antero has experienced capacity constraints in the Marcellus Shale due to delays in the completion of third-party gathering and compression infrastructure.  Antero has an additional estimated 70 MMcfe/d of net production in the Marcellus associated with six horizontal wells that are shut-in waiting on infrastructure as well as a number of producing wells that are constrained and waiting on additional pipeline infrastructure.  After a two month delay, the 55 MMcfd/d third-party-owned and operated West Union compressor station was completed and placed into service in order to connect highly rich western Doddridge County wells to the Sherwood processing facilities.  Additionally, Antero has signed agreements with various third-parties to provide compression services in central and eastern Doddridge County that will add a combined total of 185 MMcf/d of incremental capacity during the remainder of 2013.  The 20-inch Zinnia low-pressure line being constructed by a third-party in our Tichenal area has experienced a three month delay due to wet weather.  The Zinnia line is expected to be completed later this month and will relieve an estimated 40 MMcfe/d of gross constrained Marcellus production.  Further, M3 Appalachia Gathering, LLC recently completed and placed into service the extension of its 16-inch to 24-inch M3 Lateral high pressure pipeline from the Energy Transfer Bobcat Lateral in Harrison County West Virginia to the TETCO interstate pipeline in southern Pennsylvania.  Antero currently has 100,000 MMBtu/d of firm transportation on the M3 Lateral, increasing to 300,000 MMBtu/d in the second quarter of 2014.

 

Antero is currently constructing a 20-inch low pressure gathering line connecting third-party compression located in central Doddridge County to the Sherwood processing facilities to allow for incremental rich gas gathering capacity.  This low pressure pipeline, expected to go into service in the fourth quarter of 2013, is ultimately expected to be converted to a high pressure gathering line serving central Doddridge County.  Additionally, Antero is constructing a 16-inch low pressure gathering line in eastern Ritchie and southern Tyler Counties to further expand its gathering infrastructure in order to connect several completed wells and allow for delivery of highly rich gas to the Sherwood processing facility.  This line is expected to go in service late in the third quarter of 2013.

 

Antero has 325,000 net acres in the southwestern core of the Marcellus Shale play of which 27% was associated with proved reserves at mid-year 2013.  Approximately 80% of Antero’s Marcellus leasehold is prospective for processable rich gas.

 

Commodity Hedges

 

Antero has hedged 956 Bcfe of future production using fixed price swaps covering the period from July 1, 2013 through December 2019 at an average NYMEX-equivalent price of $4.86 per MMBtu.  Approximately 21% of Antero’s financial hedges are NYMEX hedges and 79% are tied to the Appalachian Basin.  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.  For presentation purposes, basin prices are converted by Antero to NYMEX-equivalent prices using current basis differentials in the over-the-counter futures market.  Antero has 11 different counterparties to its hedge contracts, all but one of which are lenders under Antero’s bank facility.

 

The following table summarizes Antero’s hedge positions held as of the date of this release:

 

 

 

Natural gas
equivalent

 

NYMEX-
equivalent

 

Calendar Year

 

MMBtu/day

 

index price

 

2013

 

454,000

 

$

4.71

 

2014

 

380,000

 

$

5.22

 

2015

 

390,000

 

$

5.39

 

2016

 

522,500

 

$

4.99

 

2017

 

630,000

 

$

4.39

 

2018

 

450,000

 

$

4.77

 

2019

 

17,500

 

$

4.86

 

 

5


 

2013 Outlook

 

Due to the pending registration of Antero’s securities with the SEC, Antero will no longer provide its outlook for the remainder of 2013.  In addition, Antero’s previously announced outlook for 2013 should no longer be relied upon.

 

6


 

Non-GAAP Financial Measures

 

Adjusted net revenue as set forth in this release represents operating revenues adjusted for certain non-cash items, including unrealized derivative gains and losses and gains and losses on asset sales.  We believe 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
June 30,

 

Six months ended
June 30,

 

 

 

2012

 

2013

 

2012

 

2013

 

 

 

 

 

 

 

 

 

 

 

Total operating revenues

 

$

38,925

 

$

387,144

 

$

592,666

 

$

448,598

 

Unrealized commodity derivative (gains) losses

 

55,904

 

(181,377

)

(114,498

)

(61,265

)

Gain on sale of gathering system

 

—

 

—

 

(291,305

)

—

 

Adjusted net revenues

 

$

94,829

 

$

205,767

 

$

186,863

 

$

387,333

 

 

Adjusted net income as set forth in this release represents income from operations before deferred income taxes, 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) as an indicator of financial performance.  The following table reconciles income from operations to adjusted net income:

 

 

 

Three months ended
June 30,

 

Six months ended
June 30,

 

 

 

2012

 

2013

 

2012

 

2013

 

 

 

 

 

 

 

 

 

 

 

Net income (loss) from continuing operations

 

$

(33,237

)

$

131,193

 

$

254,318

 

$

83,196

 

Unrealized commodity derivative (gains) losses

 

55,904

 

(181,337

)

(114,498

)

(61,265

)

Gain on sale of gathering system

 

—

 

—

 

(291,305

)

—

 

Provision (benefit) for income taxes

 

(14,442

)

83,725

 

183,969

 

53,325

 

Adjusted net income

 

$

8,225

 

$

33,581

 

$

32,484

 

$

75,256

 

 

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 and exploration expense.  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 continuing operations, 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
June 30,

 

Six months ended
June 30,

 

 

 

2012

 

2013

 

2012

 

2013

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by operating activities

 

$

60,493

 

$

82,190

 

$

160,984

 

$

192,397

 

Net change in working capital

 

16,654

 

10,238

 

(4,040

)

(14,723

)

Cash flow from operations before changes in working capital

 

77,147

 

92,428

 

156,944

 

177,674

 

Cash flow from discontinued operations before changes in working capital

 

45,803

 

—

 

100,280

 

—

 

Cash flow from continuing operations before changes in working capital

 

$

31,344

 

$

92,428

 

$

56,664

 

$

177,674

 

 

7


 

EBITDAX is a non-GAAP financial measure that we define as net income (loss) before interest expense or interest income, realized and unrealized gains or losses on interest rate derivative instruments, taxes, impairments, depletion, depreciation, amortization, exploration expense, unrealized commodity hedge gains or losses, franchise taxes, stock compensation, business acquisition and gain or loss on sale of assets.  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 provided by 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 (loss) from continuing operations to EBITDAX from continuing operations, a reconciliation of our net 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 six months ended June 30, 2012 and 2013:

 

 

 

Three months ended
June 30,

 

Six months ended
June 30,

 

 

 

2012

 

2013

 

2012

 

2013

 

Net income (loss) from continuing operations

 

$

(33,237

)

$

131,193

 

$

254,318

 

$

83,196

 

Unrealized loss (gain) on commodity derivative contracts

 

55,904

 

(181,337

)

(114,498

)

(61,265

)

Interest expense

 

24,223

 

33,468

 

48,593

 

63,396

 

Provision (benefit) for income taxes

 

(14,442

)

83,725

 

183,969

 

53,325

 

Depreciation, depletion, amortization and accretion

 

22,345

 

52,856

 

38,477

 

93,484

 

Impairment of unproved properties

 

1,295

 

4,803

 

1,581

 

6,359

 

Exploration expense

 

2,952

 

7,300

 

4,756

 

11,662

 

Gain on sale of gathering assets

 

—

 

—

 

(291,305

)

—

 

Other

 

1,196

 

600

 

1,996

 

1,200

 

EBITDAX from continuing operations

 

60,236

 

132,608

 

127,887

 

251,357

 

Loss

 

(444,850

)

 

 

(404,674

)

—

 

Unrealized losses on commodity derivative contracts

 

33,197

 

—

 

636

 

—

 

Loss on sale of assets

 

427,232

 

—

 

427,232

 

—

 

Provision (benefit) for income taxes

 

(1,717

)

—

 

12,727

 

—

 

Depreciation, depletion, amortization and accretion

 

31,698

 

—

 

63,366

 

—

 

Impairment of unproved properties

 

243

 

—

 

993

 

—

 

Exploration expense

 

200

 

—

 

412

 

—

 

EBITDAX from discontinued operations

 

46,003

 

—

 

100,692

 

—

 

Total EBITDAX

 

106,239

 

132,608

 

228,579

 

251,357

 

Interest expense and other

 

(24,223

)

(33,468

)

(48,593

)

(63,396

)

Exploration expense

 

(3,152

)

(7,300

)

(5,168

)

(11,662

)

Changes in current assets and liabilities

 

(16,654

)

(10,238

)

4,040

 

14,723

 

Other

 

(1,717

)

588

 

(17,874

)

1,375

 

Net cash provided by operating activities

 

$

60,493

 

$

82,190

 

$

160,984

 

$

192,397

 

 

8


 

The cash prices realized for oil, NGLs and natural gas production, including the amounts realized on cash settled derivatives, are a critical component in the Company’s performance tracked by investors and professional research analysts in valuing, comparing, rating and providing investment recommendations and forecasts of companies in the oil and gas exploration and production industry.  In turn, many investors use this published research in making investment decisions. Due to the GAAP disclosures of various hedging and derivative transactions, such information is now reported in various lines of the income statement.

 

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 primarily 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 “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2012.

 

For more information, contact Chad Green, Finance Director, at (303) 357-7339 or cgreen@anteroresources.com.

 

9


 

ANTERO RESOURCES LLC AND SUBSIDIARIES

 

Condensed Consolidated Balance Sheets

 

December 31, 2012 and June 30, 2013

 

(Unaudited)

 

(In thousands)

 

 

 

2012

 

2013

 

Assets

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

18,989

 

$

10,867

 

Accounts receivable — trade, net of allowance for doubtful accounts of $174 and $10 in 2012 and 2013, respectively

 

21,296

 

29,231

 

Notes receivable — short-term portion

 

4,555

 

4,444

 

Accrued revenue

 

46,669

 

66,432

 

Derivative instruments

 

160,579

 

205,221

 

Other

 

22,518

 

11,710

 

Total current assets

 

274,606

 

327,905

 

Property and equipment:

 

 

 

 

 

Oil and natural gas properties, at cost (successful efforts method):

 

 

 

 

 

Unproved properties

 

1,243,237

 

1,366,023

 

Proved properties

 

1,689,132

 

2,629,529

 

Gathering systems and facilities

 

168,930

 

334,096

 

Other property and equipment

 

9,517

 

11,282

 

 

 

3,110,816

 

4,340,930

 

Less accumulated depletion, depreciation, and amortization

 

(173,343

)

(266,296

)

Property and equipment, net

 

2,937,473

 

4,074,634

 

Derivative instruments

 

371,436

 

388,694

 

Notes receivable — long-term portion

 

2,667

 

—

 

Other assets, net

 

32,611

 

33,915

 

Total assets

 

$

3,618,793

 

$

4,825,148

 

Liabilities and Equity

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Accounts payable

 

$

181,478

 

$

233,751

 

Accrued liabilities and other

 

61,161

 

84,262

 

Derivative instruments

 

—

 

264

 

Revenue distributions payable

 

46,037

 

54,532

 

Current portion of long-term debt

 

25,000

 

25,000

 

Deferred income tax liability

 

62,620

 

79,722

 

Total current liabilities

 

376,296

 

477,531

 

Long-term liabilities:

 

 

 

 

 

Long-term debt

 

1,444,058

 

2,418,217

 

Deferred income tax liability

 

91,692

 

127,915

 

Other long-term liabilities

 

33,010

 

44,552

 

Total liabilities

 

1,945,056

 

3,068,215

 

Equity:

 

 

 

 

 

Members’ equity

 

1,460,947

 

1,460,947

 

Accumulated earnings

 

212,790

 

295,986

 

Total equity

 

1,673,737

 

1,756,933

 

Total liabilities and equity

 

$

3,618,793

 

$

4,825,148

 

 

10


 

ANTERO RESOURCES LLC AND SUBSIDIARIES

 

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

 

Three Months Ended June 30, 2012 and 2013

 

(Unaudited)

 

(In thousands)

 

 

 

2012

 

2013

 

Revenue:

 

 

 

 

 

Natural gas sales

 

$

44,688

 

$

172,332

 

Natural gas liquids sales

 

—

 

17,244

 

Oil sales

 

277

 

2,085

 

Realized and unrealized gain (loss) on derivative instruments (including unrealized gains (losses) of $(55,904) and $181,337 in 2012 and 2013, respectively)

 

(6,040

)

195,483

 

Total revenue

 

38,925

 

387,144

 

Operating expenses:

 

 

 

 

 

Lease operating expenses

 

1,866

 

1,454

 

Gathering, compression, processing, and transportation

 

20,079

 

48,670

 

Production taxes

 

3,371

 

10,108

 

Exploration expenses

 

2,952

 

7,300

 

Impairment of unproved properties

 

1,295

 

4,803

 

Depletion, depreciation and amortization

 

22,321

 

52,589

 

Accretion of asset retirement obligations

 

24

 

267

 

General and administrative

 

10,473

 

13,567

 

Total operating expenses

 

62,381

 

138,758

 

Operating income (loss)

 

(23,456

)

248,386

 

Interest expense

 

(24,223

)

(33,468

)

Income (loss) from continuing operations before income taxes and discontinued operations

 

(47,679

)

214,918

 

Income tax (expense) benefit

 

14,442

 

(83,725

)

Income (loss) from continuing operations

 

(33,237

)

131,193

 

Discontinued operations:

 

 

 

 

 

Loss from results of operations and sale of discontinued operations

 

(444,850

)

—

 

Net income (loss) and comprehensive income (loss) attributable to Antero equity owners

 

$

(478,087

)

$

131,193

 

 

11


 

ANTERO RESOURCES LLC AND SUBSIDIARIES

 

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

 

Six Months Ended June 30, 2012 and 2013

 

(Unaudited)

 

(In thousands)

 

 

 

2012

 

2013

 

Revenue:

 

 

 

 

 

Natural gas sales

 

$

89,822

 

$

294,278

 

Natural gas liquids sales

 

—

 

27,816

 

Oil sales

 

325

 

2,962

 

Realized and unrealized gain on derivative instruments (including unrealized gains of $114,498 and $61,265 in 2012 and 2013, respectively)

 

211,214

 

123,542

 

Gain on sale of gathering system

 

291,305

 

—

 

Total revenue

 

592,666

 

448,598

 

Operating expenses:

 

 

 

 

 

Lease operating expenses

 

2,559

 

2,525

 

Gathering, compression, processing, and transportation

 

31,654

 

89,640

 

Production taxes

 

7,113

 

18,727

 

Exploration expenses

 

4,756

 

11,662

 

Impairment of unproved properties

 

1,581

 

6,359

 

Depletion, depreciation and amortization

 

38,431

 

92,953

 

Accretion of asset retirement obligations

 

46

 

531

 

General and administrative

 

19,646

 

26,284

 

Total operating expenses

 

105,786

 

248,681

 

Operating income

 

486,880

 

199,917

 

Interest expense

 

(48,593

)

(63,396

)

Income from continuing operations before income taxes and discontinued operations

 

438,287

 

136,521

 

Income tax expense

 

(183,969

)

(53,325

)

Income from continuing operations

 

254,318

 

83,196

 

Discontinued operations:

 

 

 

 

 

Loss from results of operations and sale of discontinued operations

 

(404,674

)

—

 

Net income (loss) and comprehensive income (loss) attributable to Antero equity owners

 

$

(150,356

)

$

83,196

 

 

12


 

ANTERO RESOURCES LLC AND SUBSIDIARIES

 

Condensed Consolidated Statements of Cash Flows

 

Six Months Ended June 30, 2012 and 2013

 

(Unaudited)

 

(In thousands)

 

 

 

2012

 

2013

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

(150,356

)

$

83,196

 

Adjustment to reconcile net income to net cash provided by operating activities:

 

 

 

 

 

Depletion, depreciation, amortization, and accretion

 

38,477

 

93,484

 

Impairment of unproved properties

 

1,581

 

6,359

 

Unrealized gains on derivative instruments, net

 

(114,498

)

(61,265

)

Gain on sale of assets

 

(291,305

)

—

 

Loss on sale of discontinued operations

 

427,232

 

—

 

Deferred income tax expense

 

165,669

 

53,325

 

Depletion, depreciation, amortization, accretion, and impairment of unproved properties — discontinued operations

 

64,359

 

—

 

Unrealized losses on derivative instruments, net — discontinued operations

 

636

 

—

 

Deferred income tax expense — discontinued operations

 

12,727

 

—

 

Other

 

2,422

 

2,575

 

Changes in current assets and liabilities:

 

 

 

 

 

Accounts receivable

 

(15,791

)

(7,935

)

Accrued revenue

 

18,535

 

(19,763

)

Other current assets

 

(3,162

)

10,808

 

Accounts payable

 

(17,058

)

(1,436

)

Accrued liabilities

 

10,641

 

20,137

 

Revenue distributions payable

 

575

 

8,495

 

Other

 

10,300

 

4,417

 

Net cash provided by operating activities

 

160,984

 

192,397

 

Cash flows from investing activities:

 

 

 

 

 

Additions to proved properties

 

(4,451

)

—

 

Additions to unproved properties

 

(263,737

)

(271,003

)

Drilling costs

 

(377,199

)

(757,877

)

Additions to gathering systems and facilities

 

(47,982

)

(151,737

)

Additions to other property and equipment

 

(1,300

)

(1,766

)

Proceeds from asset sales

 

811,253

 

—

 

Changes in other assets

 

(257

)

3,975

 

Net cash from (used in) investing activities

 

116,327

 

(1,178,408

)

Cash flows from financing activities:

 

 

 

 

 

Issuance of senior notes

 

—

 

231,750

 

Borrowings (repayments) on bank credit facility, net

 

(275,000

)

743,000

 

Payments of deferred financing costs

 

—

 

(5,663

)

Other

 

(79

)

8,802

 

Net cash provided by (used in) financing activities

 

(275,079

)

977,889

 

Net increase (decrease) in cash and cash equivalents

 

2,232

 

(8,122

)

Cash and cash equivalents, beginning of period

 

3,343

 

18,989

 

Cash and cash equivalents, end of period

 

$

5,575

 

$

10,867

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid during the period for interest

 

$

(45,064

)

$

(62,246

)

Supplemental disclosure of noncash investing activities:

 

 

 

 

 

Increase in accounts payable for additions to properties, gathering systems and facilities

 

$

31,593

 

$

54,051

 

 

13


 

OPERATING DATA

 

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

 

 

 

Three Months Ended
June 30,

 

Amount of
Increase

 

 

 

 

 

2012

 

2013

 

(Decrease)

 

Percent Change

 

 

 

(in thousands, except per unit and production data)

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

44,688

 

$

172,332

 

$

127,644

 

286

%

NGL sales

 

—

 

17,244

 

17,244

 

*

 

Oil sales

 

277

 

2,085

 

1,808

 

653

%

Realized gains on derivative instruments

 

49,864

 

14,146

 

(35,718

)

(72

)%

Unrealized gains (losses) on derivative instruments

 

(55,904

)

181,337

 

237,241

 

*

 

Total operating revenues

 

38,925

 

387,144

 

348,219

 

895

%

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

1,866

 

1,454

 

(412

)

(22

)%

Gathering, compression, processing, and transportation

 

20,079

 

48,670

 

28,591

 

142

%

Production taxes

 

3,371

 

10,108

 

6,737

 

200

%

Exploration expenses

 

2,952

 

7,300

 

4,348

 

147

%

Impairment of unproved properties

 

1,295

 

4,803

 

3,508

 

271

%

Depletion, depreciation, and amortization

 

22,321

 

52,589

 

30,268

 

136

%

Accretion of asset retirement obligations

 

24

 

267

 

243

 

1,013

%

General and administrative

 

10,473

 

13,567

 

3,094

 

30

%

Total operating expenses

 

62,381

 

138,758

 

76,377

 

122

%

Operating income (loss)

 

(23,456

)

248,386

 

271,842

 

*

 

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(24,223

)

(33,468

)

(9,245

)

38

%

Income (loss) before income taxes

 

(47,679

)

214,918

 

262,597

 

*

 

Income tax benefit (expense)

 

14,442

 

(83,725

)

(98,167

)

*

 

Income (loss) from continuing operations

 

(33,237

)

131,193

 

164,430

 

*

 

Loss from discontinued operations

 

(444,850

)

—

 

444,850

 

*

 

Net income (loss) attributable to Antero members

 

$

(478,087

)

$

131,193

 

$

609,280

 

*

 

 

 

 

 

 

 

 

 

 

 

EBITDAX from continuing operations

 

$

60,236

 

$

132,608

 

$

72,372

 

120

%

 

 

 

 

 

 

 

 

 

 

Total EBITDAX

 

$

106,239

 

$

132,608

 

$

26,369

 

25

%

 

 

 

 

 

 

 

 

 

 

Production data:

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

19

 

39

 

20

 

104

%

NGLs (MBbl)

 

—

 

354

 

354

 

*

 

Oil (MBbl)

 

4

 

25

 

21

 

585

%

Combined (Bcfe)

 

19

 

42

 

23

 

115

%

Daily combined production (MMcfe/d)

 

213

 

458

 

245

 

115

%

Average prices before effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

2.31

 

$

4.37

 

$

2.06

 

89

%

NGLs (per Bbl)

 

$

—

 

$

48.70

 

$

*

 

*

 

Oil (per Bbl)

 

$

77.16

 

$

85.07

 

$

7.91

 

10

%

Combined (per Mcfe)

 

$

2.32

 

$

4.60

 

$

2.28

 

98

%

Average realized prices after effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

4.89

 

$

4.74

 

$

(0.15

)

(3

)%

NGLs (per Bbl)

 

$

—

 

$

48.70

 

$

48.70

 

*

 

Oil (per Bbl)

 

$

77.16

 

$

80.70

 

$

3.54

 

5

%

Combined (per Mcfe)

 

$

4.90

 

$

4.94

 

$

0.04

 

1

%

Average costs (per Mcfe):

 

 

 

 

 

 

 

 

 

Lease operating costs

 

$

0.10

 

$

0.03

 

$

(0.07

)

(70

)%

Gathering, compression, processing, and transportation

 

$

1.04

 

$

1.17

 

$

0.13

 

13

%

Production taxes

 

$

0.17

 

$

0.24

 

$

0.07

 

41

%

Depletion, depreciation, amortization, and accretion

 

$

1.15

 

$

1.27

 

$

0.12

 

10

%

General and administrative

 

$

0.54

 

$

0.33

 

$

(0.21

)

(39

)%

 

14


 

OPERATING DATA

 

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

 

 

 

Six Months Ended
June 30,

 

Amount of
Increase

 

 

 

 

 

2012

 

2013

 

(Decrease)

 

Percent Change

 

 

 

(in thousands, except per unit and production data)

 

Operating revenues:

 

 

 

 

 

 

 

 

 

Natural gas sales

 

$

89,822

 

$

294,278

 

$

204,456

 

228

%

NGL sales

 

—

 

27,816

 

27,816

 

*

 

Oil sales

 

325

 

2,962

 

2,637

 

811

%

Realized gains on derivative instruments

 

96,716

 

62,277

 

(34,439

)

(36

)%

Unrealized gains on derivative instruments

 

114,498

 

61,265

 

(53,233

)

(46

)%

Gain on sale of gathering system

 

291,305

 

—

 

(291,305

)

*

 

Total operating revenues

 

592,666

 

448,598

 

(144,068

)

(24

)%

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating expense

 

2,559

 

2,525

 

(34

)

(1

)%

Gathering, compression, processing, and transportation

 

31,654

 

89,640

 

57,986

 

183

%

Production taxes

 

7,113

 

18,727

 

11,614

 

163

%

Exploration expenses

 

4,756

 

11,662

 

6,906

 

145

%

Impairment of unproved properties

 

1,581

 

6,359

 

4,778

 

302

%

Depletion, depreciation, and amortization

 

38,431

 

92,953

 

54,522

 

142

%

Accretion of asset retirement obligations

 

46

 

531

 

485

 

1,054

%

General and administrative

 

19,646

 

26,284

 

6,638

 

34

%

Total operating expenses

 

105,786

 

248,681

 

142,895

 

135

%

Operating income (loss)

 

486,880

 

199,917

 

(286,963

)

(59

)%

 

 

 

 

 

 

 

 

 

 

Interest expense

 

(48,593

)

(63,396

)

(14,803

)

30

%

Income before income taxes

 

438,287

 

136,521

 

(301,766

)

(69

)%

Income tax expense

 

(183,969

)

(53,325

)

130,644

 

(71

)%

Income from continuing operations

 

254,318

 

83,196

 

(171,122

)

(67

)%

Loss from discontinued operations

 

(404,674

)

—

 

404,674

 

*

 

Net income (loss) attributable to Antero members

 

$

(150,356

)

$

83,196

 

$

233,552

 

*

 

 

 

 

 

 

 

 

 

 

 

EBITDAX from continuing operations 

 

$

127,887

 

$

251,357

 

$

123,470

 

97

%

 

 

 

 

 

 

 

 

 

 

Total EBITDAX

 

$

228,579

 

$

251,357

 

$

22,778

 

10

%

 

 

 

 

 

 

 

 

 

 

Production data:

 

 

 

 

 

 

 

 

 

Natural gas (Bcf)

 

35

 

73

 

38

 

105

%

NGLs (MBbl)

 

—

 

559

 

559

 

*

 

Oil (MBbl)

 

4

 

35

 

31

 

764

%

Combined (Bcfe)

 

35

 

76

 

41

 

116

%

Daily combined production (MMcfe/d)

 

195

 

421

 

226

 

116

%

Average prices before effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

2.53

 

$

4.05

 

$

1.52

 

60

%

NGLs (per Bbl)

 

$

—

 

$

49.75

 

$

49.75

 

*

 

Oil (per Bbl)

 

$

80.05

 

$

85.36

 

$

5.31

 

7

%

Combined (per Mcfe)

 

$

2.54

 

$

4.27

 

$

1.73

 

68

%

Average realized prices after effects of hedges:

 

 

 

 

 

 

 

 

 

Natural gas (per Mcf)

 

$

5.26

 

$

4.91

 

$

(0.35

)

(7

)%

NGLs (per Bbl)

 

$

—

 

$

49.75

 

$

49.75

 

*

 

Oil (per Bbl)

 

$

80.05

 

$

79.14

 

$

(0.91

)

(1

)%

Combined (per Mcfe)

 

$

5.26

 

$

5.09

 

$

(0.17

)

(3

)%

Average costs (per Mcfe):

 

 

 

 

 

 

 

 

 

Lease operating costs

 

$

0.07

 

$

0.03

 

$

(0.04

)

(57

)%

Gathering, compression, and transportation

 

$

0.89

 

$

1.18

 

$

0.29

 

33

%

Production taxes

 

$

0.20

 

$

0.25

 

$

0.05

 

25

%

Depletion, depreciation, amortization, and accretion

 

$

1.08

 

$

1.23

 

$

0.15

 

14

%

General and administrative

 

$

0.55

 

$

0.35

 

$

(0.20

)

(36

)%

 

15