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

Antero Resources logo. (PRNewsFoto/Antero Resources Corporation)

Fourth Quarter 2017 Highlights and Updated 2018 Guidance:

  • Net daily gas equivalent production averaged a record 2,347 MMcfe/d (27% liquids), an 18% increase over the prior year period
  • Liquids production averaged 107,433 Bbl/d, a 24% increase over the prior year period, and contributed 41% of total product revenues (before hedging)
  • Realized C3+ NGL price of $39.16 per barrel, which is 71% of NYMEX WTI price, before hedging
  • Realized natural gas price of $2.80 per Mcf, a $0.13 per Mcf negative differential to the average NYMEX natural gas price, before hedging
  • Realized a combined natural gas equivalent price of $3.46 per Mcfe before hedges, driven by a $0.66 per Mcfe uplift from NGL and oil production and pricing
  • Realized natural gas equivalent price of $3.82 per Mcfe including NGLs, oil and hedges
  • GAAP net income of $487 million, or $1.54 per diluted share, adjusted net income of $74 million, or $0.23 per diluted share, and Stand-Alone E&P adjusted net income of $55 million
  • Adjusted EBITDAX of $437 million and Stand-Alone E&P adjusted EBITDAX of $372 million
  • Corporate debt ratings improved to Ba2/BB+/BBB- (Moody’s/S&P/Fitch)
  • Reducing 2018 net marketing expense guidance to a range of $0.10 to $0.125 per Mcfe (from a range of $0.10 to $0.15 Mcfe) and forecasting a first quarter 2018 net marketing gain  

Full Year 2017 Highlights:

  • Net daily gas equivalent production averaged 2,253 MMcfe/d (28% liquids), a 22% increase over the prior year
  • GAAP net income of $615 million, or $1.94 per diluted share, adjusted net income of $103 million, or $0.33 per diluted share, and Stand-Alone E&P adjusted net income of $71 million
  • Adjusted EBITDAX of $1.46 billion and Stand-Alone E&P adjusted EBITDAX of $1.24 billion
  • Drilling & completion capital expenditures of $1.282 billion, 1% below guidance
  • Stand-Alone E&P net debt to trailing twelve months adjusted EBITDAX was 2.9x with over $1.6 billion of liquidity

2018 Guidance Update

The Company’s first quarter 2018 net production is estimated to be flat with the fourth quarter 2017 net production due primarily to the timing of completions throughout 2018, the impact from severe winter weather on the Sherwood processing plant operations in the West Virginia Marcellus in the early part of January, and a shutdown for several days at the Seneca plant in the Ohio Utica due to a third-party downstream pipeline rupture.  Both of these processing plant issues have since been rectified.  The Company continues to expect to meet its full year 2018 net production guidance of approximately 2.7 Bcfe/d.  Additionally, the extreme cold weather in January resulted in attractive pricing on natural gas sales and the ability to generate significant marketing revenues during the first quarter of 2018 that more than offset the reduced production.  Antero is now forecasting a net marketing gain for the first quarter of 2018 and is reducing its net marketing expense guidance for the full year of 2018 to a range of $0.10/Mcfe to $0.125/Mcfe.        

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

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

  • A description of consolidated and Stand-Alone E&P non-GAAP measures, including adjusted EBITDAX and adjusted net income, and reconciliations to their nearest comparable GAAP measures
  • A reconciliation of revenue excluding unrealized hedge gains (losses) and unrealized marketing derivative losses to operating revenue, the most comparable GAAP measure
  • A reconciliation of net debt to total debt, the most comparable GAAP measure
  • A reconciliation of Antero Midstream’s adjusted EBITDA and Distributable Cash Flow to their nearest comparable GAAP measure

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

Tax Reform

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

  • The Company recognized a deferred tax benefit of $428 million in the fourth quarter primarily due to the remeasurement of the Company’s net deferred tax liability for the reduction in the U.S. statutory rate from 35% to 21%.
  • Under the new tax legislation, Antero is limited in the utilization of net operating loss (“NOLs”) carryforwards generated after tax year 2017 to 80% of taxable income. As a result, the Company deducted all of its intangible drilling costs for U.S. federal income tax purposes for tax year 2017 in order to maximize the NOLs generated prior to tax year 2018, which are not subject to the 80% limitation. The deduction of the intangible drilling costs resulted in an increase in NOLs from approximately $1.6 billion at December 31, 2016 to $3.0 billion at December 31, 2017.

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

Fourth Quarter 2017 Financial Results

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

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

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

Three Months Ended

December 31, 2017

Gas
(MMcf/d)

Oil
(Bbl/d)

C3+ NGLs
(Bbl/d)

Ethane  (Bbl/d)

Combined
Gas
Equivalent
(MMcfe/d)

Average Net Production

1,702

6,207

69,801

31,425

2,347

Average Realized Prices

Gas

($/Mcf)

Oil

($/Bbl)

C3+ NGLs
($/Bbl)

Ethane ($/Bbl)

Combined
Gas
Equivalent
($/Mcfe)

Average realized price before settled derivatives

$

2.80

$

49.37

$

39.16

$            10.02

$

3.46

Settled derivatives

0.87

(0.31)

(9.24)

0.15

0.36

Average realized price after settled derivatives

$

3.67

$

49.06

$

29.92

$            10.17

$

3.82

NYMEX average price

$

2.93

$

55.37

$

2.93

Premium / (Differential) to NYMEX

$

0.74

$

(6.31)

$

0.89

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

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

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

Antero’s average realized C3+ NGL price before hedging was $39.16 per barrel, or 71% of the average NYMEX WTI oil price, representing a 55% increase versus the prior year period.  Including hedges, Antero’s average realized C3+ NGL price was $29.92 per barrel, a 17% increase versus the prior year period, reflecting the realization of a cash settled C3+ hedge loss of $59 million, or $9.24 per barrel.  The average realized ethane price before hedging was $0.24 per gallon, or $10.02 per barrel, and the average realized oil price before hedging was $49.37 per barrel, a $6.00 negative differential to average NYMEX WTI and a 26% increase versus the prior year period. 

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

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

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

Stand-Alone E&P

Three Months Ended

Consolidated

Three Months Ended

December 31,

December 31,

Adjusted EBITDAX margin ($ per Mcfe):

2016

2017

2016

2017

Realized price before cash receipts for settled hedges

$

3.22

$

3.46

$

3.22

$

3.46

Gathering, compression, and water handling and treatment revenues

N/A

N/A

0.01

0.02

Distributions from unconsolidated affiliate

N/A

N/A

0.04

0.05

Distributions from Antero Midstream

0.16

0.16

N/A

N/A

Gathering, compression, processing and transportation costs

(1.68)

(1.71)

(1.27)

(1.30)

Lease operating expense

(0.07)

(0.17)

(0.07)

(0.15)

Marketing, net

(0.08)

(0.13)

(0.08)

(0.13)

Production and ad valorem taxes

(0.10)

(0.11)

(0.08)

(0.11)

General and administrative(1)

(0.17)

(0.13)

(0.21)

(0.17)

Adjusted EBITDAX margin before settled hedges

1.28

1.37

1.56

1.67

Cash receipts for settled hedges

1.04

0.35

1.04

0.35

Adjusted EBITDAX margin ($ per Mcfe):

$

2.32

1.72

$

2.60

$

2.02

(1)

Excludes non-cash equity-based compensation

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

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

Adjusted EBITDAX was $437 million, at the high end of the Company’s previously announced guidance range of $410 million to $440 million.  Adjusted EBITDAX margin before settled hedges for the quarter was $1.67, a 6% increase from the prior year period.  Adjusted EBITDAX margin including hedges, was $2.02 per Mcfe, a 22% decrease from the prior year period due to lower realized hedge gains.  Stand-Alone E&P Adjusted EBITDAX was $372 million for the fourth quarter of 2017.  Stand-Alone E&P adjusted EBITDAX margin was $1.37 per Mcfe before settled hedges and $1.72 per Mcfe including settled hedges for the quarter.

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

Operating Update

Fourth Quarter 2017 

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

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

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

2017 Performance Highlights

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

Marcellus Shale

  • Drilled the longest Marcellus lateral in Company history at 14,376′
  • Achieved 16 of the Company’s top 20 drilling lateral footage days during the year
  • Over 25% of wells drilled averaged greater than one mile per day of drilling for the entire lateral
  • Achieved the fewest total days to drill an entire well at 8.4 days
  • Record Marcellus lateral footage drilled for one day of 8,178′

Ohio Utica Shale

  • Drilled the longest Utica lateral in Company history at 17,445′
  • Achieved 13 of the Company’s top 20 lateral footage days during the year
  • Achieved a record Utica lateral footage drilled for one day of 5,029′
  • Recently achieved record production with only one rig running during the year

Antero Midstream Financial Results

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

Three Months Ended

December 31,

Average Daily Volumes:

2016

2017

% Change

Low Pressure Gathering (MMcf/d)

1,522

1,711

12%

Compression (MMcf/d)

920

1,355

47%

High Pressure Gathering (MMcf/d)

1,437

1,842

28%

Fresh Water Delivery (MBbl/d)

150

149

(1)%

Gross Joint Venture Processing (MMcf/d)

425

*

Gross Joint Venture Fractionation (Bbl/d)

9,096

*

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

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

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

Fourth Quarter 2017 Capital Investment

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

2017 Full Year Financial Results

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

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

Stand-Alone E&P

Years Ended

Consolidated

Years Ended

December 31,

December 31,

Adjusted EBITDAX margin ($ per Mcfe):

2016

2017

2016

2017

Realized price before cash receipts for settled hedges

$

2.60

3.34

$

2.60

$

3.34

Gathering, compression, and water handling and treatment revenues

N/A

N/A

0.02

0.02

Distributions from unconsolidated affiliate

N/A

N/A

0.01

0.02

Distributions from Antero Midstream

0.16

0.16

N/A

N/A

Gathering, compression, processing and transportation costs

(1.70)

(1.75)

(1.31)

(1.33)

Lease operating expense

(0.07)

(0.11)

(0.07)

(0.11)

Marketing, net

(0.16)

(0.13)

(0.16)

(0.13)

Production and ad valorem taxes

(0.10)

(0.11)

(0.10)

(0.11)

General and administrative(1)

(0.16)

(0.15)

(0.20)

(0.18)

Adjusted EBITDAX margin before settled hedges

0.57

1.25

0.79

1.52

Cash receipts for settled hedges

1.48

0.26

1.48

0.26

Adjusted EBITDAX margin ($ per Mcfe):

$

2.05

1.51

$

2.27

$

1.78

(1)

Excludes non-cash equity-based compensation

2017 Capital Investment

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

Balance Sheet and Liquidity

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

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

Commodity Hedge Positions

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

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

Period

Natural Gas

MMBtu/d

Average

Index price

($/MMBtu)

Liquids

Bbl/d

Average

Index price

1Q 2018:

NYMEX Henry Hub

2,002,500

$3.60

Propane MB ($/Gal)

19,000

$0.75

NYMEX WTI ($/Bbl)

4,000

$55.97

2Q 2018:

NYMEX Henry Hub

2,002,500

$3.42

Propane MB ($/Gal)

19,000

$0.75

NYMEX WTI ($/Bbl)

4,000

$55.97

3Q 2018:

NYMEX Henry Hub

2,002,500

$3.45

Propane MB ($/Gal)

19,000

$0.75

NYMEX WTI ($/Bbl)

4,000

$55.97

4Q 2018:

NYMEX Henry Hub

2,002,500

$3.53

Propane MB ($/Gal)

19,000

$0.75

NYMEX WTI ($/Bbl)

4,000

$55.97

                    2018 Total(1)

2,002,500

$3.50

23,000

N/A (2)

2019:

NYMEX Henry Hub

2,330,000

$3.50

2020:

NYMEX Henry Hub

1,417,500

$3.25

2021:

NYMEX Henry Hub

710,000

$3.00

2022:

NYMEX Henry Hub

850,000

$3.00

2023:

NYMEX Henry Hub

90,000

$2.91

(1)

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

(2)

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

Conference Call

A conference call is scheduled on Wednesday, February 14, 2018 at 9:00 am MT to discuss the quarterly results.  A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter and full year.  To participate in the call, dial in at 888-347-8204 (U.S.), 855-669-9657 (Canada), or 412-902-4229 (International) and reference “Antero Resources”. A telephone replay of the call will be available until Wednesday, February 21, 2018 at 9:00 am MT at 844-512-2921 (U.S.) or 412-317-6671 (International) using the passcode 10114470.

A simultaneous webcast of the call may be accessed over the internet at www.anteroresources.com.  The webcast will be archived for replay on the Company’s website until Wednesday, February 21, 2018 at 9:00 am MT.

Presentation

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

Non-GAAP Financial Measures

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

Revenue excluding unrealized hedge gains (losses) and gain on sale of assets as set forth in this release represents total operating revenue adjusted for non-cash gains (losses) on unsettled hedges and gain on sale of assets.  Antero believes that revenue excluding unrealized hedge gains (losses) and gain on sale of assets is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Revenue excluding unrealized hedge gains (losses) and gain on sale of assets is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total operating revenue as an indicator of financial performance.  The following table reconciles total operating revenue to revenue excluding unrealized hedge gains (losses) and gain on sale of assets (in thousands):

Three Months Ended

December 31,

Years Ended

December 31,

2016

2017

2016

2017

Total operating revenue

$

156,216

$

1,021,726

$

1,744,525

$

3,655,574

Commodity derivative fair value (gains) losses

639,805

(178,430)

514,181

(636,889)

Cash receipts for settled hedges

189,524

76,548

1,003,083

213,940

Gain on sale of assets

(97,635)

(97,635)

Revenue excluding unrealized hedge gains (losses) and gain on sale of assets

$

887,910

$

919,844

$

3,164,154

$

3,232,625

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

Adjusted net income as set forth in this release represents net income (loss), adjusted for certain items.  Stand-Alone E&P adjusted net income as presented in this release represents net income (loss) that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements, adjusted for certain items.  Antero believes that adjusted net income is useful to investors in evaluating operational trends of the Company and its performance relative to other oil and gas producing companies.  Adjusted net income and Stand-Alone E&P adjusted net income are not measures of financial performance under GAAP and should not be considered in isolation or as a substitute for net income (loss) as an indicator of financial performance. 

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

Stand-Alone E&P

Consolidated

Three Months Ended

Three Months Ended

December 31,

December 31,

2016

2017

2016

2017

Net income (loss)

$

(485,772)

486,869

$

(485,772)

486,869

Non-cash commodity derivative (gains) losses on unsettled derivatives

639,805

(178,430)

639,805

(178,430)

Cash receipts for settled hedges

189,524

76,548

189,524

76,548

      Impairment of unproved properties

115,712

76,500

115,712

76,500

      Impairment of gathering systems and facilities

N/A

N/A

23,431

      Equity-based compensation

20,071

17,673

26,754

24,520

      Loss on early extinguishment of debt

16,956

1,205

16,956

1,500

      Gain on sale of assets

(93,776)

(97,635)

 Income tax effect of reconciling items

(336,110)

2,447

(337,179)

(9,056)

 Impact of tax reform legislation

(427,962)

(427,962)

Adjusted net income

$

66,410

54,850

$

68,165

73,920

Stand-Alone E&P

Consolidated

Years Ended

Years Ended

December 31,

December 31,

2016

2017

2016

2017

Net income (loss)

$

(848,816)

615,070

$

(848,816)

615,070

Non-cash commodity derivative (gains) losses on unsettled derivatives

514,181

(636,889)

514,181

(636,889)

Cash receipts for settled hedges

1,003,083

213,940

1,003,083

213,940

      Impairment of unproved properties

162,935

159,598

162,935

159,598

      Impairment of gathering systems and facilities

N/A

N/A

23,431

      Equity-based compensation

76,372

76,162

102,421

103,445

      Loss on early extinguishment of debt

16,956

1,205

16,956

1,500

      Gain on sale of assets

(93,776)

(97,635)

 Income tax effect of reconciling items

(635,581)

69,976

(643,977)

50,784

 Impact of tax reform legislation

(427,962)

(427,962)

Adjusted net income

$

195,354

71,100

$

209,148

102,917

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

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

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

There are significant limitations to using Adjusted Operating Cash Flow, Stand-Alone E&P Adjusted Operating Cash Flow and Free Cash Flow as measures of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the company’s net income on a consolidated and Stand-Alone E&P basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow reported by different companies.  Adjusted Operating Cash Flow and Stand-Alone E&P Adjusted Operating Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, franchise taxes, exploration expenses, and other commitments and obligations.

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

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

Stand-Alone E&P

Consolidated

Three Months Ended

December 31,

Three Months Ended

December 31,

2016

2017

2016

2017

Net cash provided by operating activities

$

285,637

254,078

$

335,559

$

313,483

Net change in working capital

75,253

57,666

68,859

54,054

Adjusted operating cash flow

360,890

311,744

404,418

367,537

Stand-Alone E&P

Consolidated

Years Ended

December 31,

Years Ended

December 31,

2016

2017

2016

2017

Net cash provided by operating activities

$

1,105,238

1,836,322

$

1,241,256

$

2,006,291

Net change in working capital

36,519

(87,466)

32,920

(76,035)

Adjusted cash flow from operations

1,141,757

1,748,856

1,274,176

1,930,256

Total Debt and Net Debt

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

December 31,

December 31,

2016

2017

Bank credit facilities

$

650,000

$

740,000

6.00% AR senior notes due 2020

5.375% AR senior notes due 2021

1,000,000

1,000,000

5.125% AR senior notes due 2022

1,100,000

1,100,000

5.625% AR senior notes due 2023

750,000

750,000

5.375% AM senior notes due 2024

650,000

650,000

5.000% AR senior notes due 2025

600,000

600,000

Net unamortized premium

1,749

1,520

Net unamortized debt issuance costs

(47,776)

(41,430)

Consolidated total debt

$

4,703,973

$

4,800,090

Less: Cash and cash equivalents

31,610

28,441

Consolidated net debt

$

4,672,363

$

4,771,649

Adjusted EBITDAX and Stand-Alone E&P Adjusted EBITDAX

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

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

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

  • are widely used by investors in the oil and gas industry to measure a company’s operating performance without regard to items excluded from the calculation of such term, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired, among other factors;
  • helps investors to more meaningfully evaluate and compare the results of Antero’s operations (both on a consolidated and Stand-Alone E&P basis) from period to period by removing the effect of its capital structure from its operating structure; and
  • is used by management for various purposes, including as a measure of Antero’s operating performance (both on a consolidated and Stand-Alone E&P basis), in presentations to the company’s board of directors, and as a basis for strategic planning and forecasting. Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Adjusted EBITDAX, as defined by our credit facility, is used by our lenders pursuant to covenants under our revolving credit facility and the indentures governing the company’s senior notes.

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

Stand-Alone E&P

Consolidated

Three Months Ended

Three Months Ended

December 31,

December 31,

2016

2017

2016

2017

Net income (loss) including noncontrolling interest

$

(485,772)

486,869

$

(452,804)

$

529,614

Commodity derivative fair value (gains)

639,805

(178,430)

639,805

(178,430)

Gains on settled derivative instruments

189,524

76,548

189,524

76,548

Gain on sale of assets

(93,776)

(97,635)

Interest expense

59,091

53,687

67,918

63,390

Loss on early extinguishment of debt

16,956

1,205

16,956

1,500

Income tax expense (benefit)

(265,621)

(400,138)

(265,621)

(400,138)

Depreciation, depletion, amortization, and accretion

196,682

183,439

222,443

214,397

Impairment of unproved properties

115,712

76,500

115,712

76,500

Impairment of gathering systems and facilities

N/A

N/A

23,431

Exploration expense

3,573

3,028

3,573

3,028

Gain on change in fair value of contingent acquisition  consideration

(6,105)

(3,804)

N/A

N/A

Equity-based compensation expense

20,071

17,673

26,754

24,520

Equity in loss (earnings) of unconsolidated affiliate

N/A

N/A

1,542

(7,307)

Distributions from unconsolidated affiliates

N/A

N/A

7,702

10,075

Distributions from Antero Midstream

28,850

33,614

N/A

N/A

Equity in net income of Antero Midstream

5,153

22,128

N/A

N/A

State franchise taxes

11

11

Total Adjusted EBITDAX

424,154

372,319

475,880

437,128

Interest expense

(59,091)

(53,687)

(67,918)

(63,390)

Exploration expense

(3,573)

(3,028)

(3,573)

(3,028)

Changes in current assets and liabilities

(75,253)

(57,666)

(68,859)

(54,054)

State franchise taxes

(11)

(11)

Other non-cash items

(589)

(3,860)

40

(3,173)

Net cash provided by operating activities

$

285,637

254,078

$

335,559

$

313,483

 

Stand-Alone E&P

Consolidated

Years Ended

Years Ended

December 31,

December 31,

2016

2017

2016

2017

Net income (loss) including noncontrolling interest

$

(848,816)

$

615,070

$

(749,448)

$

785,137

Commodity derivative fair value (gains)

514,181

(636,889)

514,181

(636,889)

Gains on settled derivative instruments

1,003,083

213,940

1,003,083

213,940

Gain on sale of assets

(93,776)

(97,635)

Interest expense

232,455

232,331

253,552

268,701

Loss on early extinguishment of debt

16,956

1,205

16,956

1,500

Income tax expense (benefit)

(496,376)

(295,051)

(496,376)

(295,051)

Depreciation, depletion, amortization, and accretion

712,485

707,658

812,346

827,220

Impairment of unproved properties

162,935

159,598

162,935

159,598

Impairment of gathering systems and facilities

N/A

N/A

23,431

Exploration expense

6,862

8,538

6,862

8,538

Gain on change in fair value of contingent acquisition  consideration

(16,489)

(13,476)

N/A

N/A

Equity-based compensation expense

76,372

76,162

102,421

103,445

Equity in loss (earnings) of unconsolidated affiliate

N/A

N/A

(485)

(20,194)

Distributions from unconsolidated affiliate

N/A

N/A

7,702

20,195

Distributions from Antero Midstream

107,364

131,598

N/A

N/A

Equity in net income of Antero Midstream

7,156

43,710

N/A

N/A

State franchise taxes

50

50

Total Adjusted EBITDAX

1,384,442

1,244,394

1,536,144

1,459,571

Interest expense

(232,455)

(232,331)

(253,552)

(268,701)

Exploration expense

(6,862)

(8,538)

(6,862)

(8,538)

Changes in current assets and liabilities

(36,519)

87,466

(32,920)

76,035

State franchise taxes

(50)

(50)

Proceeds from derivative monetizations

749,906

749,906

Other non-cash items

(3,318)

(4,575)

(1,504)

(1,982)

Net cash provided by operating activities

$

1,105,238

1,836,322

$

1,241,256

$

2,006,291

Antero Midstream Adjusted EBITDA & Distributable Cash Flow

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

Antero Midstream uses Adjusted EBITDA to assess:

  • the financial performance of Antero Midstream’s assets, without regard to financing methods in the case of Adjusted EBITDA, capital structure or historical cost basis;
  • its operating performance and return on capital as compared to other publicly traded partnerships in the midstream energy sector, without regard to financing or capital structure; and
  • the viability of acquisitions and other capital expenditure projects.

Antero Midstream defines Distributable Cash Flow as Adjusted EBITDA less interest paid, income tax withholding payments and cash reserved for payments of income tax withholding upon vesting of equity-based compensation awards, cash reserved for bond interest and ongoing maintenance capital expenditures paid.  Antero Midstream uses Distributable Cash Flow as a performance metric to compare the cash generating performance of Antero Midstream from period to period and to compare the cash generating performance for specific periods to the cash distributions (if any) that are expected to be paid to unitholders.  Distributable Cash Flow does not reflect changes in working capital balances.

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

Three months ended

Years ended

December 31,

December 31,

2016

2017

2016

2017

Net income

$

73,351

64,155

$

236,703

$

307,315

Interest expense

9,008

10,395

21,893

37,557

Depreciation expense

25,761

30,958

99,861

119,562

Impairment of property and equipment expense

23,431

23,431

Accretion of contingent acquisition consideration

6,105

3,804

16,489

13,476

Equity-based compensation

6,683

6,847

26,049

27,283

Equity in earnings of unconsolidated affiliates

1,542

(7,307)

(485)

(20,194)

Distributions from unconsolidated affiliates

7,702

10,075

7,702

20,195

Gain on asset sale

(3,859)

(3,859)

Adjusted EBITDA

$

126,293

$

142,358

$

404,353

$

528,625

Interest paid

6,115

(4,136)

(13,494)

(46,666)

Decrease in cash reserved for bond interest (1)

(1,743)

(8,734)

(10,481)

291

Cash reserved for payment of income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards(2)

(10,481)

(514)

(5,636)

(5,945)

Cash distribution to be received from unconsolidated affiliate

(2,636)

Maintenance capital expenditures(3)

(5,466)

(12,063)

(21,622)

(55,159)

Distributable cash flow

$

102,928

$

116,911

$

353,120

$

421,146

Distributions Declared to Antero Midstream Holders

Limited Partners

50,090

68,231

182,559

247,132

Incentive distribution rights

7,543

23,772

16,945

69,720

Total Aggregate Distributions

$

57,633

$

92,003

$

199,504

$

316,852

DCF coverage ratio

1.79x

1.27x

1.78x

1.33x

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

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

Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond the Antero’s control, incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading “Item 1A. Risk Factors” in Antero’s Annual Report on Form 10-K for the year ended December 31, 2017.

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

ANTERO RESOURCES CORPORATION

Consolidated Balance Sheets

December 31, 2016 and 2017

 (In thousands, except per share amounts)

2016

2017

Assets

Current assets:

Cash and cash equivalents

$

31,610

28,441

Accounts receivable, net of allowance for doubtful accounts of $1,195 and $1,320 at December 31, 2016 and December 31, 2017, respectively

29,682

34,896

Accrued revenue

261,960

300,122

Derivative instruments

73,022

460,685

Other current assets

6,313

8,943

Total current assets

402,587

833,087

Property and equipment:

Natural gas properties, at cost (successful efforts method):

Unproved properties

2,331,173

2,266,673

Proved properties

9,549,671

11,096,462

Water handling and treatment systems

744,682

946,670

Gathering systems and facilities

1,723,768

2,050,490

Other property and equipment

41,231

57,429

14,390,525

16,417,724

Less accumulated depletion, depreciation, and amortization

(2,363,778)

(3,182,171)

Property and equipment, net

12,026,747

13,235,553

Derivative instruments

1,731,063

841,257

Investments in unconsolidated affiliates

68,299

303,302

Other assets

26,854

48,291

Total assets

$

14,255,550

15,261,490

Liabilities and Equity

Current liabilities:

Accounts payable

$

38,627

62,982

Accrued liabilities

393,803

443,225

Revenue distributions payable

163,989

209,617

Derivative instruments

203,635

28,476

Other current liabilities

17,334

17,796

Total current liabilities

817,388

762,096

Long-term liabilities:

Long-term debt

4,703,973

4,800,090

Deferred income tax liability

950,217

779,645

Derivative instruments

234

207

Other liabilities

55,160

43,316

Total liabilities

6,526,972

6,385,354

Commitments and contingencies

Equity:

Stockholders’ equity:

Preferred stock, $0.01 par value; authorized – 50,000 shares; none issued

Common stock, $0.01 par value; authorized – 1,000,000 shares; 314,877 shares and 316,379 shares issued and outstanding at December 31, 2016 and 2017, respectively

3,149

3,164

Additional paid-in capital

5,299,481

6,570,952

Accumulated earnings

959,995

1,575,065

Total stockholders’ equity

6,262,625

8,149,181

Noncontrolling interests in consolidated subsidiary

1,465,953

726,955

Total equity

7,728,578

8,876,136

Total liabilities and equity

$

14,255,550

15,261,490

 

ANTERO RESOURCES CORPORATION

Consolidated Statements of Operations and Comprehensive Income (Loss)

Years Ended December 31, 2016 and 2017

(In thousands, except per share amounts)

2016

2017

Revenue and other:

Natural gas sales

1,260,750

1,769,284

Natural gas liquids sales

432,992

870,441

Oil sales

61,319

108,195

Gathering, compression, water handling and treatment

12,961

12,720

Marketing

393,049

258,045

Commodity derivative fair value gains (losses)

(514,181)

636,889

Gain on sale of assets

97,635

Total revenue and other

1,744,525

3,655,574

Operating expenses:

Lease operating

50,090

89,057

Gathering, compression, processing, and transportation

882,838

1,095,639

Production and ad valorem taxes

66,588

94,521

Marketing

499,343

366,281

Exploration

6,862

8,538

Impairment of unproved properties

162,935

159,598

Impairment of gathering systems and facilities

23,431

Depletion, depreciation, and amortization

809,873

824,610

Accretion of asset retirement obligations

2,473

2,610

General and administrative (including equity-based compensation expense of $102,421 and $103,445 in 2016 and 2017, respectively)

239,324

251,196

Total operating expenses

2,720,326

2,915,481

Operating income (loss)

(975,801)

740,093

Other income (expenses):

Equity in earnings of unconsolidated affiliates

485

20,194

Interest

(253,552)

(268,701)

Loss on early extinguishment of debt

(16,956)

(1,500)

Total other expenses

(270,023)

(250,007)

Income (loss) before income taxes

(1,245,824)

490,086

Provision for income tax (expense) benefit

496,376

295,051

Net income (loss) and comprehensive income (loss) including noncontrolling interests

(749,448)

785,137

Net income and comprehensive income attributable to noncontrolling interests

99,368

170,067

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

(848,816)

615,070

Earnings (loss) per common share—basic

(2.88)

1.95

Earnings (loss) per common share—assuming dilution

(2.88)

1.94

Weighted average number of shares outstanding:

Basic

294,945

315,426

Diluted

294,945

316,283

 

ANTERO RESOURCES CORPORATION

Consolidated Statements of Cash Flows

Years Ended December 31, 2016 and 2017

 (In thousands)

2016

2017

Cash flows provided by operating activities:

Net income (loss) including noncontrolling interests

(749,448)

785,137

Adjustment to reconcile net income (loss) to net cash provided by operating activities:

Depletion, depreciation, amortization, and accretion

812,346

827,220

Impairment of unproved properties

162,935

159,598

Impairment of gathering systems and facilities

23,431

Derivative fair value (gains) losses

514,181

(636,889)

Gains on settled derivatives

1,003,083

213,940

Proceeds from derivative monetizations

749,906

Deferred income tax expense (benefit)

(485,392)

(295,126)

Gain on sale of assets

(97,635)

Equity-based compensation expense

102,421

103,445

Loss on early extinguishment of debt

16,956

1,500

Equity in earnings of unconsolidated affiliates

(485)

(20,194)

Distributions of earnings from unconsolidated affiliates

7,702

20,195

Other

(12,488)

(1,907)

Changes in current assets and liabilities:

Accounts receivable

39,857

(5,214)

Accrued revenue

(133,718)

(38,162)

Other current assets

1,774

(2,755)

Accounts payable

7,365

9,462

Accrued liabilities

18,853

64,862

Revenue distributions payable

34,040

45,628

Other current liabilities

(1,091)

2,214

Net cash provided by operating activities

1,241,256

2,006,291

Cash flows used in investing activities:

Additions to proved properties

(134,113)

(175,650)

Additions to unproved properties

(611,631)

(204,272)

Drilling and completion costs

(1,327,759)

(1,281,985)

Additions to water handling and treatment systems

(188,188)

(194,502)

Additions to gathering systems and facilities

(231,044)

(346,217)

Additions to other property and equipment

(2,694)

(14,127)

Investments in unconsolidated affiliates

(75,516)

(235,004)

Change in other assets

3,977

(12,029)

Proceeds from asset sales

171,830

2,156

Net cash used in investing activities

(2,395,138)

(2,461,630)

Cash flows provided by financing activities:

Issuance of common stock

1,012,431

Issuance of common units by Antero Midstream Partners LP

65,395

248,956

Proceeds from sale of common units of Antero Midstream Partners LP held by Antero Resources Corporation

178,000

311,100

Issuance of senior notes

1,250,000

Repayment of senior notes

(525,000)

Borrowings (repayments) on bank credit facilities, net

(677,000)

90,000

Make-whole premium on debt extinguished

(15,750)

Payments of deferred financing costs

(18,759)

(16,377)

Distributions to noncontrolling interests in consolidated subsidiary

(75,082)

(152,352)

Employee tax withholding for settlement of equity compensation awards

(26,895)

(24,174)

Other

(5,321)

(4,983)

Net cash provided by financing activities

1,162,019

452,170

Net increase (decrease) in cash and cash equivalents

8,137

(3,169)

Cash and cash equivalents, beginning of period

23,473

31,610

Cash and cash equivalents, end of period

31,610

28,441

Supplemental disclosure of cash flow information:

Cash paid during the period for interest

239,369

263,919

Supplemental disclosure of noncash investing activities:

Decrease in accounts payable and accrued liabilities for additions to property and equipment

(152,093)

(547)

 

ANTERO RESOURCES CORPORATION

The following tables set forth selected operating data for the three months ended December 31, 2016, and December 31, 2017:

Three Months Ended December 31,

Amount of

Increase

Percent

(in thousands)

2016

2017

(Decrease)

Change

Operating revenues and other:

Natural gas sales

$

411,814

$

439,222

$

27,408

7

%

NGLs sales

158,256

280,437

122,181

77

%

Oil sales

19,607

28,196

8,589

44

%

Gathering, compression, and water handling and treatment

2,854

4,055

1,201

42

%

Marketing

105,855

91,386

(14,469)

(14)

%

Commodity derivative fair value gains (losses)

(639,805)

178,430

818,235

*

Gain on sale of assets

97,635

(97,635)

*

Total operating revenues and other

156,216

1,021,726

865,510

554

%

Operating expenses:

Lease operating

12,900

33,023

20,123

156

%

Gathering, compression, processing, and transportation

233,125

279,929

46,804

20

%

Production and ad valorem taxes

14,292

24,180

9,888

69

%

Marketing

120,822

119,983

(839)

(1)

%

Exploration

3,573

3,028

(545)

(15)

%

Impairment of unproved properties

115,712

76,500

(39,212)

(34)

%

Impairment of gathering systems and facilities

23,431

23,431

*

Depletion, depreciation, and amortization

221,816

213,731

(8,085)

(4)

%

Accretion of asset retirement obligations

627

666

39

6

%

General and administrative (before equity-based compensation)

38,604

35,676

(2,928)

(8)

%

Equity-based compensation

26,754

24,520

(2,234)

(8)

%

Total operating expenses

788,225

834,667

46,442

6

%

Operating income (loss)

(632,009)

187,059

819,068

*

Other earnings (expenses):

Equity in earnings of unconsolidated affiliates

(1,542)

7,307

8,849

*

Interest expense

(67,918)

(63,390)

4,528

(7)

%

Loss on early extinguishment of debt

(16,956)

(1,500)

15,456

(91)

%

Total other expenses

(86,416)

(57,583)

28,833

(33)

%

Income (loss) before income taxes

(718,425)

129,476

847,901

*

Income tax benefit

265,621

400,138

134,517

51

%

Net income (loss) and comprehensive income (loss) including noncontrolling interest

(452,804)

529,614

982,418

*

Net income and comprehensive income attributable to noncontrolling interest

32,968

42,745

9,777

30

%

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$

(485,772)

$

486,869

$

972,854

*

Adjusted EBITDAX (1)

$

475,880

$

437,128

$

(38,752)

(8)

%

Production data:

Natural gas (Bcf)

135

157

22

16

%

C2 Ethane (MBbl)

1,933

2,891

958

50

%

C3+ NGLs (MBbl)

5,557

6,422

865

16

%

Oil (MBbl)

500

571

71

14

%

Combined (Bcfe)

183

216

33

18

%

Daily combined production (MMcfe/d)

1,990

2,347

357

18

%

Average prices before effects of derivative settlements:

Natural gas (per Mcf)

$

3.05

$

2.80

$

(0.25)

(8)

%

C2 Ethane (per Bbl)

$

9.36

$

10.02

$

0.66

7

%

C3+ NGLs (per Bbl)

$

25.22

$

39.16

$

13.94

55

%

Oil (per Bbl)

$

39.18

$

49.37

$

10.19

26

%

Combined (per Mcfe)

$

3.22

$

3.46

$

0.24

7

%

Average realized prices after effects of derivative settlements:

Natural gas (per Mcf)

$

4.43

$

3.67

$

(0.76)

(17)

%

C2 Ethane (per Bbl)

$

9.36

$

10.17

$

0.81

9

%

C3+ NGLs (per Bbl)

$

25.60

$

29.92

$

4.32

17

%

Oil (per Bbl)

$

39.18

$

49.06

$

9.88

25

%

Combined (per Mcfe)

$

4.26

$

3.82

$

(0.44)

(10)

%

Average Costs (per Mcfe):

Lease operating

$

0.07

$

0.15

$

0.08

114

%

Gathering, compression, processing, and transportation

$

1.27

$

1.30

$

0.03

2

%

Production and ad valorem taxes

$

0.08

$

0.11

$

0.03

38

%

Marketing, net

$

0.08

$

0.13

$

0.05

63

%

Depletion, depreciation, amortization, and accretion

$

1.22

$

0.99

$

(0.23)

(19)

%

General and administrative (before equity-based compensation)

$

0.21

$

0.17

$

(0.04)

(19)

%

(1)    Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX

*Not meaningful or applicable

 

ANTERO RESOURCES CORPORATION

The following tables set forth selected operating data for the year ended December 31, 2016 compared to the year ended December 31, 2017:

Year Ended December 31,

Amount of

Increase

Percent

(in thousands)

2016

2017

(Decrease)

Change

Operating revenues and other:

Natural gas sales

$

1,260,750

$

1,769,284

$

508,534

40

%

NGLs sales

432,992

870,441

437,449

101

%

Oil sales

61,319

108,195

46,876

76

%

Gathering, compression, and water handling and treatment

12,961

12,720

(241)

(2)

%

Marketing

393,049

258,045

(135,004)

(34)

%

Commodity derivative fair value gains (losses)

(514,181)

636,889

1,151,070

*

Gain on sale of assets

97,635

(97,635)

*

Total operating revenues and other

1,744,525

3,655,574

1,911,049

110

%

Operating expenses:

Lease operating

50,090

89,057

38,967

78

%

Gathering, compression, processing, and transportation

882,838

1,095,639

212,801

24

%

Production and ad valorem taxes

66,588

94,521

27,933

42

%

Marketing

499,343

366,281

(133,062)

(27)

%

Exploration

6,862

8,538

1,676

24

%

Impairment of unproved properties

162,935

159,598

(3,337)

(2)

%

Impairment of property and equipment

23,431

23,431

*

Depletion, depreciation, and amortization

809,873

824,610

14,737

2

%

Accretion of asset retirement obligations

2,473

2,610

137

6

%

General and administrative (before equity-based compensation)

136,903

147,751

10,848

8

%

Equity-based compensation

102,421

103,445

1,024

1

%

Total operating expenses

2,720,326

2,915,481

195,155

7

%

Operating income (loss)

(975,801)

740,093

1,737,288

*

Other earnings (expenses):

Equity in earnings of unconsolidated affiliates

485

20,194

19,709

*

Interest expense

(253,552)

(268,701)

(15,149)

6

%

Loss on early extinguishment of debt

(16,956)

(1,500)

15,456

(91)

%

Total other expenses

(270,023)

(250,007)

20,016

(7)

%

Income (loss) before income taxes

(1,245,824)

490,086

1,735,910

*

Income tax benefit

496,376

295,051

(201,325)

(41)

%

Net income (loss) and comprehensive income (loss) including noncontrolling interest

(749,448)

785,137

1,534,585

*

Net income and comprehensive income attributable to noncontrolling interest

99,368

170,067

70,699

71

%

Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation

$

(848,816)

$

615,070

$

1,463,886

*

Adjusted EBITDAX (1)

$

1,536,144

$

1,459,571

$

(76,573)

26

%

Production data:

Natural gas (Bcf)

505

591

86

17

%

C2 Ethane (MBbl)

6,396

10,539

4,143

65

%

C3+ NGLs (MBbl)

20,279

25,507

5,228

26

%

Oil (MBbl)

1,873

2,451

578

31

%

Combined (Bcfe)

676

822

146

22

%

Daily combined production (MMcfe/d)

1,847

2,253

406

22

%

Average prices before effects of derivative settlements:

Natural gas (per Mcf)

$

2.50

$

2.99

$

0.49

20

%

C2 Ethane (per Bbl)

$

8.28

$

8.83

$

0.55

7

%

C3+ NGLs (per Bbl)

$

18.74

$

30.48

$

11.74

63

%

Oil (per Bbl)

$

32.73

$

44.14

$

11.41

35

%

Combined (per Mcfe)

$

2.60

$

3.34

$

0.74

28

%

Average realized prices after effects of derivative settlements:

Natural gas (per Mcf)

$

4.39

$

3.61

$

(0.78)

(18)

%

C2 Ethane (per Bbl)

$

8.28

$

9.04

$

0.76

9

%

C3+ NGLs (per Bbl)

$

21.03

$

24.27

$

3.24

15

%

Oil (per Bbl)

$

32.73

$

45.85

$

13.12

40

%

Combined (per Mcfe)

$

4.08

$

3.60

$

(0.48)

(12)

%

Average Costs (per Mcfe):

Lease operating

$

0.07

$

0.11

$

0.04

57

%

Gathering, compression, processing, and transportation

$

1.31

$

1.33

$

0.02

2

%

Production and ad valorem taxes

$

0.10

$

0.11

$

0.01

10

%

Marketing, net

$

0.16

$

0.13

$

(0.03)

(19)

%

Depletion, depreciation, amortization, and accretion

$

1.20

$

1.01

$

(0.19)

(16)

%

General and administrative (before equity-based compensation)

$

0.20

$

0.18

$

(0.02)

(10)

%

(1)    Please see “Non-GAAP Financial Measures” for a description of Adjusted EBITDAX

* Not Meaningful Or Applicable.

 

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SOURCE Antero Resources Corporation