Antero Resources Reports Fourth Quarter and Full Year 2018 Financial and Operational Results and 2018 Reserves Image

Antero Resources Reports Fourth Quarter and Full Year 2018 Financial and Operational Results and 2018 Reserves

DENVER, Feb. 13, 2019 /PRNewswire/ -- Antero Resources Corporation (NYSE: AR) ("Antero," "Antero Resources" or the "Company") today released its fourth quarter and full year 2018 financial and operational results and announced estimated proved reserves as of December 31, 2018.  The relevant consolidated and consolidating financial statements are included in Antero's Annual Report on Form 10-K for the year ended December 31, 2018, which has been filed with the Securities and Exchange Commission ("SEC").  The relevant Stand-alone financial statements are also included in Antero's Form 10-K within the Parent column of the guarantor footnote (Note 17).

Antero Resources logo. (PRNewsFoto/Antero Resources Corporation)

Fourth Quarter 2018 Highlights:

  • Net daily gas equivalent production averaged a record 3,213 MMcfe/d (30% liquids), a 37% increase over the prior year period and an 18% increase sequentially
  • Liquids production averaged 162,077 Bbl/d, a 51% increase over the prior year period and included oil production of 12,229 MBbl/d, C3+ NGL production of 102,860 MBbl/d and recovered ethane production of 46,988 MBbl/d
    • Ethane production represented about 27% of the potential recoverable ethane, with 122,000 Bbl/d remaining in the gas stream
  • Realized natural gas price averaged $3.83 per Mcf, a $0.19 premium to the NYMEX Henry Hub natural gas price per MMBtu before hedges
  • Realized natural gas equivalent price averaged $4.05 per Mcfe before hedges, driven by a $0.22 per Mcfe uplift from liquids production and prices
  • Reported $122 million net loss, or $0.39 per share, $145 million Adjusted Net Income, or $0.46 per diluted share, and $175 million Stand-alone Adjusted Net Income, or $0.56 per diluted share (adjusted items are non-GAAP measures)
  • Reported $584 million of Adjusted EBITDAX and $475 million of Stand-alone Adjusted EBITDAX, representing a 34% and 27% increase over the prior year period, respectively (non-GAAP measures)
  • Full year 2019 Stand-alone drilling and completion capital expenditures expected to be at low end of guidance range and a 20% reduction from 2018, due to fourth quarter 2018 pre-spend related to roads, pads and facilities to be utilized in 2019 and 2020

Full Year 2018 Highlights:

  • Net daily gas equivalent production averaged 2,709 MMcfe/d (28% liquids), a 20% increase over the prior year
  • Reported $398 million net loss, or $1.26 per share, $315 million Adjusted Net Income, or $1.00 per diluted share, and $365 million Stand-alone Adjusted Net Income, or $1.15 per diluted share (adjusted items are non-GAAP measures)
  • Reported $2.0 billion of Adjusted EBITDAX and $1.7 billion of Stand-alone Adjusted EBITDAX, representing a 42% and 38% increase over the prior year period, respectively (non-GAAP measures) 
  • Proved reserves increased 4% to 18.0 Tcfe at year-end 2018 compared to year-end 2017
  • Standardized measure of proved reserves increased 21% to $10.5 billion at year-end 2018 compared to year-end 2017
  • SEC PV-10 proved reserve value increased 24% to $12.6 billion at year-end 2018 compared to year-end 2017
  • Proved developed reserves increased 22% to 10.4 Tcfe at year-end 2018 compared to year-end 2017 and comprised 58% of total proved reserves
  • Future development costs for 7.6 Tcfe of proved undeveloped reserves estimated to be $0.44 per mcfe
  • The previously announced simplification transaction between Antero Midstream and AMGP expected to be completed in March 2019 results in a minimum of $300 million in cash proceeds to Antero Resources
  • Following the simplification transaction, Antero Resources will no longer consolidate Antero Midstream's financial statements in Antero Resources' consolidated financial statements, but will account for its interest in New AM using the equity method of accounting
  • Reduced Stand-alone Net Debt to trailing twelve months Stand-alone Adjusted EBITDAX to 2.2x at year-end 2018

Paul Rady, Chairman and CEO said, "2018 was a great year for the Antero family, as we significantly reduced leverage, grew production above the 3 Bcfe/d mark, and announced the midstream simplification.  We enter 2019 with significant scale as the largest NGL producer and the 5th largest natural gas producer in the U.S.  Driven by the fourth quarter capital invested on pads and roads, we expect to be in a position to invest at the low end of our 2019 drilling and completion guidance range.  The 2019 budget represents a 20% reduction relative to capital spending in 2018.  On the liquids front, we are excited that Mariner East 2 has been placed in service.  Our commitment on this pipeline will allow us to move nearly half of our expected 2019 C3+ NGL production to the export market and realize stronger NGL netback pricing than we have received over the last several years. We believe that our 2019 plan will deliver superior returns to shareholders over the long-term while also keeping capital spending within cash flow. "

Fourth Quarter 2018 Financial Results

As of December 31, 2018, Antero Resources owned a 53% limited partner interest in Antero Midstream Partners LP ("Antero Midstream").  Pro forma for the previously announced midstream simplification transaction which is expected to close in March 2019, Antero Resources will own approximately 31% of the common stock of Antero Midstream Corporation ("New AM" or "New Antero Midstream") assuming Antero Midstream unitholders make a mixed consideration election in the transaction. Antero Midstream's results are consolidated within Antero Resources' results for 2018 and 2017, but will be deconsolidated in 2019 assuming the close of the midstream simplification transaction.  Antero believes the deconsolidation will provide more transparency to investors around the Stand-alone upstream business and a greater ability to compare results across Antero's peer group.

For the three months ended December 31, 2018, Antero reported a net loss of $122 million, or $0.39 per share, compared to net income of $487 million, or $1.54 per diluted share, in the prior year period.  Excluding items detailed in "Non-GAAP Financial Measures," Adjusted Net Income was $145 million, or $0.46 per diluted share, compared to $74 million, or $0.23 per diluted share, in the prior year period.  Stand-alone Adjusted Net Income was $175 million, or $0.56 per diluted share, compared to $55 million, or $0.17 per diluted share, in the prior year period. 

Consolidated Adjusted EBITDAX was $584 million, a 34% increase compared to $437 million in the prior year period, and Stand-alone Adjusted EBITDAX was $475 million, a 27% increase compared to $372 million in the prior year period. 

The following table details the components of average net production and average realized prices for the three months ended December 31, 2018:




















Three Months Ended December 31, 2018




Natural Gas (MMcf/d)


Oil (Bbl/d)


C3+ NGLs (Bbl/d)


Ethane (Bbl/d)


Combined Natural Gas Equivalent (MMcfe/d)


Average Net Production



2,240



12,229



102,860



46,988



3,213



















Average Realized Prices


Natural Gas ($/Mcf)


Oil ($/Bbl)


C3+ NGLs ($/Bbl)


Ethane ($/Bbl)


Combined Natural Gas Equivalent ($/Mcfe)


Average realized prices before settled derivatives


$

3.83


$

51.83


$

30.92


$

13.12


$

4.05


Settled commodity derivatives



(0.10)



(0.91)



(0.32)





(0.08)


Average realized prices after settled derivatives


$

3.73


$

50.92


$

30.60


$

13.12


$

3.97



















NYMEX average price


$

3.64


$

59.08








$

3.64


Premium / (Differential) to NYMEX


$

0.09


$

(8.16)








$

0.33


Net daily natural gas equivalent production in the fourth quarter averaged 3,213 MMcfe/d, including 162,077 Bbl/d of liquids (30% of production), an increase of 37% compared to the prior year period and an 18% increase sequentially.  Natural gas production averaged 2,240 MMcf/d, an increase of 32% over the prior year period.

Total liquids production grew 51% compared to the prior year period and 25% sequentially.  Liquids revenue represented approximately 34% of total product revenue before hedges.  Oil production averaged 12,229 Bbl/d, an increase of 97% over the prior year period.  C3+ NGLs production averaged 102,860 Bbl/d, an increase of 47% over the prior year period.  Recovered ethane production averaged 46,988 Bbl/d, an increase of 50% over the prior year period.  Recovered ethane production represented approximately 27% of potential ethane that could have been recovered during the period, with the remaining 122,000 Bbl/d of ethane remaining in the gas stream.

Antero's average realized natural gas price before hedging was $3.83 per Mcf, a $0.19 per Mcf premium to the average NYMEX Henry Hub price per MMBtu during the period, representing a 37% increase versus the prior year period.  Including hedges, Antero's average realized natural gas price was $3.73 per Mcf, a $0.09 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge loss of $21 million, or $0.10 per Mcf. 

Antero's average realized C3+ NGL price before hedging was $30.92 per barrel, or 52% of the average NYMEX WTI oil price, representing a 21% decline versus the prior year period due to widening NGL differentials to Mont Belvieu prior to the startup of Mariner East 2.  Including hedges, Antero's average realized C3+ NGL price was $30.60 per barrel, reflecting the realization of a cash settled C3+ hedge loss of $3 million, or $0.32 per barrel. 

Antero's average realized oil price before hedging was $51.83 per barrel, a $7.25 negative differential to the average NYMEX WTI price and a 5% increase versus the prior year period. Including hedges, the average realized oil price was $50.92 per barrel, reflecting the realization of a cash settled WTI crude oil loss of $1.0 million, or $0.91 per barrel.  The average realized ethane price was $0.31 per gallon, or $13.12 per barrel, compared to $0.24 per gallon increase in the prior year period, representing a 31% increase over $10.02 per barrel before hedging and a 29% increase over $10.17 per barrel after hedging.                

Antero's average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $4.05 per Mcfe, representing a 17% increase compared to the prior year period.  Including hedges, the Company's average natural gas equivalent price was $3.97 per Mcfe, a 4% increase from the prior year period, primarily driven by higher realized natural gas prices.  The net cash settled commodity derivative loss on all products was $25 million, or $0.08 per Mcfe.

Total revenue in the fourth quarter was $1.0 billion, nearly equivalent to the prior year period.  Revenue included a $567 million commodity derivative fair value loss primarily driven by a $370 million hedge monetization, while the prior year included a $123 million commodity derivative fair value gain.  Revenue Excluding Unrealized Derivative Gains (Losses) and Derivative  Monetizations (non-GAAP) was $1.2 billion, a 35% increase versus the prior year period.  Please see "Non-GAAP Financial Measures" for a description of Revenue Excluding Unrealized Derivative Gains (Losses) and Derivative Monetizations.

The following table presents a calculation of Stand-alone Adjusted EBITDAX margin and Adjusted EBITDAX margin (non-GAAP measures), in each case on a per Mcfe basis with and without the effect of cash receipts for settled commodity derivatives, and reconciliation to realized price before cash receipts for settled derivatives, the nearest GAAP financial measure.  Adjusted EBITDAX and Stand-alone Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, a measure that helps investors to more meaningfully evaluate and compare the results of Antero's operations (both on a consolidated and Stand-alone basis) from period to period by removing the effect of its capital structure from its operating structure.

















Stand-alone


Consolidated




Three months ended  December 31,


Three months ended  December 31,




2017


2018


2017


2018


Adjusted EBITDAX margin ($ per Mcfe):














Realized price before cash receipts for settled derivatives


$

3.46



4.05


$

3.46



4.05


Gathering, compression, and water handling and treatment revenues



N/A



N/A



0.02



0.02


Distributions from unconsolidated affiliates



N/A



N/A



0.05



0.06


Distributions from Antero Midstream



0.16



0.15



N/A



N/A


Gathering, compression, processing and transportation costs



(1.71)



(1.88)



(1.30)



(1.40)


Lease operating expense



(0.17)



(0.15)



(0.15)



(0.15)


Marketing, net (1)



(0.13)



(0.22)



(0.13)



(0.22)


Production and ad valorem taxes



(0.11)



(0.15)



(0.11)



(0.15)


General and administrative (excluding equity-based compensation)



(0.13)



(0.11)



(0.17)



(0.15)


Adjusted EBITDAX margin before settled commodity derivatives



1.37



1.69



1.67



2.06


Cash receipts (payments) for settled commodity derivatives



0.35



(0.08)



0.35



(0.08)


Adjusted EBITDAX margin ($ per Mcfe):


$

1.72



1.61


$

2.02



1.98


(1)Includes cash payments for settled marketing derivative losses of $0.02 per Mcfe in 2018. 

Stand-alone per unit distributions from Antero Midstream contributed $0.15 per Mcfe compared to $0.16 per Mcfe in the prior year period. 

The per unit Stand-alone cash production expense for the quarter included $1.88 per Mcfe for gathering, compression, processing and transportation costs, $0.15 per Mcfe for lease operating costs, and $0.15 per Mcfe for production and ad valorem taxes.  Gathering, compression, processing and transportation costs increased in the fourth quarter due to higher transport costs related to new pipeline commitments that were placed in service during the quarter and higher fuel costs related to the higher gas sales price reported for the quarter.  New pipeline transportation included phase 2 of the Rover pipeline that enabled Antero to transport natural gas production from the Sherwood Processing Facility in West Virginia that had previously been shipped to local Appalachia markets to the attractively priced Midwest and Gulf Coast markets.  Lease operating expenses decreased in the fourth quarter of 2018 compared to the fourth quarter of 2017 due to commissioning costs relating to Antero's Clearwater Facility that occurred in the fourth quarter of 2017 that did not occur in the fourth quarter of 2018.

Stand-alone per unit net marketing expense was $0.22 per Mcfe compared to $0.13 per Mcfe reported in the prior year period.  Net marketing expense increased due to higher unutilized capacity related to incremental firm transportation that was placed in service during the quarter.  Net marketing expense included a $0.02 per Mcfe loss for settled marketing derivatives related to contracts that had resulted in realized gains in the first quarter of 2018.  See Note 11 to the consolidated financial statements in Antero's Annual Report on Form 10-K for the year ended December 31, 2018, for more information on these contracts. 

Stand-alone per unit general and administrative expense, excluding non-cash equity-based compensation expense, decreased by 15% to $0.11 per Mcfe, compared to the prior year period.  General and administrative expense on a per Mcfe basis decreased due to increased production levels. 

Realized price before cash receipts for settled derivatives was $4.05 per Mcfe, a 17% increase from the prior year period, primarily due to higher natural gas prices.  Stand-alone Adjusted EBITDAX margins before commodity derivative were $1.69 per Mcfe, a 24% increase from the prior year period, primarily due to higher realized natural gas prices.  Stand-alone Adjusted EBITDAX margin after cash payments for settled commodity derivatives was $1.61 per Mcfe, a 6% decrease from the prior year period due to losses on commodity derivatives.  Consolidated Adjusted EBITDAX margin was $1.98 per Mcfe, compared to $2.02 per Mcfe in the prior year period. 

Stand-alone net cash provided by operating activities was $729 million for the period.  Stand-alone Adjusted Operating Cash Flow  was $775 million (non-GAAP), a 149% increase from the prior year period, as cash flow included a $357 million in net proceeds from restructuring the hedge portfolio.  Excluding the hedge restructuring, Stand-alone Adjusted Operating Cash Flow increased 34% over the prior year period.

Consolidated net cash provided by operating activities was $822 million for the period.  Consolidated Adjusted Operating Cash Flow was $863 million during the fourth quarter (non-GAAP), including a $357 million in net proceeds from restructuring the hedge portfolio, a 135% increase compared to the prior year period.  Excluding the $357 million hedge restructuring, consolidated Adjusted Operating Cash Flow increased by 38% over the prior year period.

Operating Update

Fourth Quarter 2018

Marcellus Shale — Antero placed 39 horizontal Marcellus wells to sales during the fourth quarter of 2018 with an average lateral length of 10,600 feet and an average 30-day initial rate per well of 21.6 MMcfe/day on choke. The 30-day average rate per well included 1,268 Bbl/d of liquids, including oil, C3+ NGLs and 25% ethane recovery.  Notable results from the wells placed to sales during the fourth quarter are below: 

  • A 10-well pad with an average lateral length of 9,700 feet and average BTU of 1230, produced a 60-day average rate of 195 MMcfe/d, including 1,400 Bbl/d of oil, 5,700 Bbl/d of C3+ NGLs and 3,000 Bbl/d of recovered ethane, at 25% ethane recovery
  • A 1300 BTU well with a lateral length of 15,100 feet, produced a 60-day rate of 29.0 MMcfe/d, including 660 Bbl/d of oil, 1,030 Bbl/d of C3+ NGLs and 410 Bbl/d of recovered ethane, at 25% ethane recovery

During the period, Antero drilled 31 wells with an average lateral length of 10,100 feet in an average of 11.5 total days from spud to final rig release, which represents a 7% reduction in total drilling time from 2017 levels.  In addition, Antero drilled an average of 5,100 lateral feet per day in the quarter, a 12% increase in lateral footage performance compared to 2017.  Completion efficiencies further improved during the fourth quarter, increasing to 5.7 stages per day from 5.5 stages per day in the third quarter of 2018.  Notably, Antero averaged 6.0 stages per day in October and November.  For the full year of 2018, Antero averaged 5.2 stages per day, which is an increase of one full stage per day from the 2017 average of 4.2 stages per day.

As recently announced, in 2019 Antero plans to operate an average of five drilling rigs, including four large rigs, and an average of four completion crews.  Development plans reflect a reduction of one to two completions crews on average from 2018 levels.  In 2019, the Company expects to drill 120 to 130 wells and place 115 to 125 wells to service. 

Glen Warren, President and CFO, commented, " Entering 2019, our  strategy centers on prudent capital deployment, a continued focus on full-cycle rates of return and generating free cash flow, all while maintaining a strong balance sheet.  We have already taken actions to demonstrate our commitment to maintain discipline and achieve these priorities, including a significant reduction in our 2019 drilling and completion capital budget and a reduction in our land budget by 50% from 2018 levels.  Our significant scale, diversified product portfolio, industry-leading natural gas hedge book and wide-reaching firm transportation portfolio are amongst our greatest assets, giving us the flexibility to thrive in a volatile commodity price environment."

Fourth Quarter 2018 Capital Investment

Antero invested $363 million in drilling and completion costs for the three months ended December 31, 2018, which included $273 million for drilling and completion activity, $78 million for pads, roads and facilities and $12 million for unit leasehold and permitting costs.  The increased activity related to pads, roads and facilities in the fourth quarter results in Antero having 18 pads in progress that are planned to be turned to sales in 2019 and 2020.  The pads were also built on larger footprints to optimize drilling and completion efficiencies and significantly reduce cycle times from spud to first sales.  Driven by continued efficiencies in stages per day, Antero also placed three additional liquids-rich wells to sales during the quarter than previously forecasted.  The additional wells had an average BTU content of 1260 and produced 56 MMcfe/d during the first 30 days, including 2,650 Bbl/d of liquids.  As a result of the capital spent on pads and roads in the latter part of 2018 and the three additional liquids-rich wells during the fourth quarter, Antero expects to be at the lower end of its 2019 drilling and completion capital budget of $1.1 to $1.25 billion on a consolidated basis and $1.3 billion to $1.45 billion on a Stand-alone basis. 

On a Stand-alone basis, Antero invested $415 million in drilling and completion costs for the three months ended December 31, 2018, which included $325 million for drilling and completion activity, $78 million for pads, roads and facilities and $12 million for unit leasehold and permitting costs. 

In addition to capital invested in drilling and completion costs, the Company invested $42 million for land, $107 million for gathering and compression systems and $20 million for water infrastructure projects. For a reconciliation between cash paid for drilling and completion capital expenditures outlined above and drilling and completion accrued capital expenditures during the period, please see the capital expenditures section below.

Year End Proved Reserves

At December 31, 2018, Antero's estimated proved reserves were 18.0 Tcfe, a 4% increase over the prior year.  Estimated proved reserves were comprised of 63% natural gas, 35% NGLs and 2% oil.  The Marcellus Shale accounted for 89% of estimated proved reserves and the Ohio Utica Shale accounted for 11%.  For 2018, Antero added 2.8 Tcfe of estimated proved reserves organically, which reflects delineation and developmental drilling.  Approximately 1.2 Tcfe was removed from Antero's proved reserves due to the SEC 5-year rule, primarily related to changes in our 5-year development plan.

Estimated proved developed reserves were 10.4 Tcfe, a 22% increase over the prior year.  The percentage of estimated proved reserves classified as proved developed increased to 58% at year-end 2018, compared to 49% at year-end 2017.  Antero's 427 proved undeveloped locations average an estimated 1247 BTU, with an average lateral length of approximately 11,100 feet.

Antero invested drilling and completion capital of $1.5 billion during 2018, resulting in proved developed finding and development costs, including revisions, of $0.52 per Mcfe.  Antero's 7.6 Tcfe of estimated proved undeveloped reserves will require an estimated $3.3 billion of future development capital over the next five years, resulting in an estimated average future development cost for proved undeveloped reserves of $0.44 per Mcfe.  For further discussion of proved developed F&D costs, please read "Non-GAAP Financial Measures."

The reserve life of the Company's estimated proved reserves is approximately 18 years based on 2018 production.

The following table presents a summary of changes in estimated proved reserves (in Bcfe).

Proved reserves, December 31, 2017


17,261

Extensions, discoveries, and other additions


2,781

Revisions to prior estimates


(1,042)

Production


(989)

Proved reserves, December 31, 2018


18,011





The following table summarizes SEC pricing as of December 31, 2018 and the associated Standardized Measure and PV-10 for estimated proved reserves and hedge values: 


SEC Pricing





Benchmark Pricing:

2018   Year-End


2017 Year-End


 Variance


% Variance

WTI Oil Price ($/Bbl)

$65.66


$51.03


$14.63


29%

  Appalachian Oil Price ($/Bbl) (1)

$56.62


$45.35


$11.27


25%

Nymex Natural Gas Price ($/MMBtu)

$3.09


$3.11


($0.02)


-1%

  Appalachian Natural Gas Price ($/MMBtu) (1)

$2.93


$2.91


$0.02


1%

C3+ Natural Gas Liquids ($/Bbl) (2)

$39.29


$32.37


$6.92


21%

C2+ Natural Gas Liquids ($/Bbl) (2)

$25.05


$20.40


$4.65


23%

















Proved Reserve Value ($Bn):








Standardized measure

$10.5


$8.6


$1.9


21%

Pre-tax estimated proved reserves PV-10 (3)

$12.6


$10.2


$2.4


24%


(1) Represents SEC prices as of December 31 for each respective year on a weighted average Appalachian index basis related to company-specific sales points.

(2) Represents realized NGL price including regional market differentials for a 1250 BTU area.

(3) For a reconciliation of PV-10 to standardized measure, see "Non-GAAP Financial Measures." 

Balance Sheet and Liquidity

As of December 31, 2018, Antero's Stand-alone Net Debt was $3.8 billion, of which $405 million were borrowings outstanding under the Company's revolving credit facility.  Total lender commitments under this facility are $2.5 billion and the borrowing base is $4.5 billion.  After deducting letters of credit outstanding, the Company had $1.4 billion in available Stand-alone liquidity as of December 31, 2018.  As of December 31, 2018, Antero's Stand-alone Net Debt to trailing twelve months Stand-alone Adjusted EBITDAX ratio was 2.2x.

Commodity Derivative Positions

Antero's estimated natural gas production for 2019 is fully hedged.  In total, Antero has hedged 2.0 Tcfe of future natural gas equivalent production using fixed price swaps, basis swaps and collar agreements covering the period from January 1, 2019, through December 31, 2023.  As of December 31, 2018, the Company's estimated fair value of commodity derivative instruments was $607 million.

The following tables summarize Antero's hedge position as of December 31, 2018:










Natural gas
MMbtu/day


Weighted
average index
price


Three months ending March 31, 2019:







NYMEX ($/MMBtu)


2,330,000


$

3.62


Three months ending June 30, 2019:







NYMEX ($/MMBtu)


755,000


$

3.26


Three months ending September 30, 2019:







NYMEX ($/MMBtu)


755,000


$

3.32


Three months ending December 31, 2019:







NYMEX ($/MMBtu)


755,000


$

3.45


Year ending December 31, 2020:







NYMEX ($/MMBtu)


1,417,500


$

3.00


Year ending December 31, 2021:







NYMEX ($/MMBtu)


710,000


$

3.00


Year ending December 31, 2022:







NYMEX ($/MMBtu)


850,000


$

3.00


Year ending December 31, 2023:







NYMEX ($/MMBtu)


90,000


$

2.91


Natural gas collar positions from April 1, 2019 through December 31, 2019 were as follows:













Natural gas


Weighted average index price




MMbtu/day


Ceiling price


Floor price


Three months ending June 30, 2019:










NYMEX ($/MMBtu)


1,575,000


$

3.30


$

2.50


Three months ending September 30, 2019:










NYMEX ($/MMBtu)


1,575,000


$

3.30


$

2.50


Three months ending December 31, 2019:










NYMEX ($/MMBtu)


1,575,000


$

3.52


$

2.50


As of December 31, 2018, the Company's natural gas basis swap positions, which settle on the basis differential of Chicago City Gate to the NYMEX Henry Hub natural gas price, totaled 225,000 MMbtu/day for January 2019 with pricing premiums ranging from $0.215 to $0.40 per MMBtu.

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: 

Average Daily Volumes:

Three months ended


Years ended

December 31,


December 31,

2017


2018


% Change


2017


2018


% Change

Low Pressure Gathering (MMcf/d)


1,711



2,602


52%



1,660



2,148


29%

Compression (MMcf/d)


1,355



2,215


63%



1,196



1,738


45%

High Pressure Gathering (MMcf/d)


1,842



2,569


39%



1,770



2,112


19%

Fresh Water Delivery (MBbl/d)


149



136


(9)%



153



195


27%

Clearwater Treatment Volumes (MBbl/d)




9


*





7


*

Gross Joint Venture Processing (MMcf/d)


425



796


87%



267



622


133%

Gross Joint Venture Fractionation (Bbl/d)


9,096



18,672


105%



5,099



13,107


157%


*      Not meaningful or applicable.

Net income for the fourth quarter of 2018 was $249 million, a 288% increase compared to the prior year quarter. Net income per diluted limited partner unit was $1.19, a 395% increase compared to the prior year quarter.  Adjusted EBITDA was $194 million, a 36% increase compared to the prior year quarter.  Distributable Cash Flow was $167 million, resulting in a DCF coverage ratio of 1.3x.  For a description of Antero Midstream's Adjusted EBITDA and Distributable Cash Flow, and reconciliations to their nearest GAAP measures, please read "Non-GAAP Financial Measures."

In connection with Antero Midstream's acquisition of the water business from Antero Resources in 2015, Antero Midstream agreed to pay Antero Resources (a) $125 million in cash if the Partnership delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if the Partnership delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. As of December 31, 2018, Antero Midstream expects to pay the amount of the contingent consideration for the delivery of 176 million barrels or more of fresh water for the first earn-out, but no longer expects to pay the amount of the contingent consideration to deliver 219 million barrels or more of fresh water for the second earn-out payment based on Antero Resources' recently announced 2019 budget and long-term outlook.

Conference Call

A conference call is scheduled on Thursday, February 14, 2019 at 9:00 am MT to discuss the financial and operational results.  A brief Q&A session for security analysts will immediately follow the discussion of the results for the quarter.  To participate in the call, dial in at 1-888-347-8204 (U.S.), 1-855-669-9657 (Canada), or 1-412-902-4229 (International) and reference "Antero Resources".  A telephone replay of the call will be available until Thursday, February 28, 2019 at 9:00 am MT at 1-844-512-2921 (U.S.) or 1-412-317-6671 (International) using the passcode 10123136.

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 Thursday, February 28, 2019 at 9:00 am MT.

Presentation

An updated presentation will be posted to the Company's website before the February 14, 2019 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. 

Also available at www.anteroresources.com is a presentation detailing results of a fundamental analysis on the natural gas industry entitled Natural Gas Fundamentals.

Non-GAAP Financial Measures

Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations

Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations as set forth in this release represents total revenue adjusted for derivative fair value (gains) losses and derivative monetizations.  Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations 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 Derivative (Gains) Losses and Derivative Monetizations is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for total revenue as an indicator of financial performance.  The following table reconciles total revenue to Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations:















Three Months Ended

December 31, 2018


Years Ended

December 31, 2018



2017


2018


2017


2018















Total revenue

$

1,021,726


$

1,045,648


$

3,655,574


$

4,139,626


Commodity derivative fair value (gains) losses


(199,824)



222,387



(658,283)



87,594


Marketing derivative fair value (gains) losses


21,394





21,394



(94,081)


Gains (losses) on settled commodity derivatives


76,548



(25,257)



213,940



243,112


Gains (losses) on settled marketing derivatives




(5,411)





72,687


Revenue Excluding Unrealized Derivative (Gains) Losses and Derivative Monetizations

$

919,844


$

1,237,367


$

3,232,625


$

4,448,938


Adjusted Net Income & Stand-alone Adjusted Net Income

Adjusted Net Income as set forth in this release represents net income, adjusted for certain items.  Stand-alone Adjusted Net Income as presented in this release represents net income 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 and Adjusted Net Income per share 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 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 as an indicator of financial performance.  The following table reconciles net income (loss) to Adjusted Net Income and Stand-alone net (loss) to Stand-alone Adjusted Net Income (in thousands):


Stand-alone


Consolidated



Three months ended


Three months ended



December 31, 2018


December 31, 2018



2017


2018


2017


2018















Net Income (loss) attributable to Antero Resources Corp.

$

486,869


$

(121,546)


$

486,869


$

(121,546)


Commodity derivative fair value (gains) losses


(199,824)



222,387



(199,824)



222,387


Gains (losses) on settled commodity derivatives


76,548



(25,257)



76,548



(25,257)


Marketing derivative fair value losses


21,394





21,394




Losses on settled marketing derivatives




(5,411)





(5,411)


Impairment of unproved properties


76,500



143,369



76,500



143,369


Impairment of gathering systems and facilities






23,431




Equity-based compensation


17,673



9,518



24,520



13,984


(Gain) loss on change in fair value of contingent acquisition consideration




104,860






Loss on early extinguishment of debt


1,205





1,500




Tax effect of reconciling items (1)


2,447



(105,804)



(9,056)



(82,171)


Other tax items (2)


(427,962)



(47,550)



(427,962)




Adjusted Net Income  

$

54,850


$

174,566


$

73,920


$

145,355















Fully Diluted Shares Outstanding


316,682



314,298



316,682



314,298




















 

Per Diluted Share Amounts

Net Income (loss) attributable to Antero Resources Corp


1.54



(0.39)



1.54



(0.39)


Commodity derivative fair value (gains) losses


(0.63)



0.71



(0.63)



0.71


Gains (losses) on settled commodity derivatives


0.24



(0.08)



0.24



(0.08)


Marketing derivative fair value losses


0.07





0.07




Losses on settled marketing derivatives




(0.02)





(0.02)


Impairment of unproved properties


0.24



0.46



0.24



0.46


Impairment of gathering systems and facilities






0.07




Equity-based compensation


0.05



0.03



0.08



0.04


(Gain) loss on change in fair value of contingent

acquisition consideration




0.34






Loss on early extinguishment of debt


0.00








Tax effect of reconciling items (1)


0.01



(0.34)



(0.03)



(0.26)


Other tax items (2)


(1.35)



(0.15)



(1.35)




Adjusted Net Income

$

0.17


$

0.56


$

0.23


$

0.46




(1)

Blended tax rates of approximately 38% for 2017 and 24% for 2018 were applied to reconciling items above.

(2)

Tax impact of valuation allowance on Colorado net operating losses, changes to Colorado tax law, tax reform legislation enacted in late 2017 and items effecting the Stand-alone financial statements.



Stand-alone


Consolidated



Year ended


Year ended



December 31, 2018


December 31, 2018



2017


2018


2017


2018















Net Income (loss) attributable to Antero Resources Corp.

$

615,070


$

(397,517)


$

615,070


$

(397,517)


Commodity derivative fair value (gains) losses


(658,283)



87,594



(658,283)



87,594


Gains (losses) on settled commodity derivatives


213,940



243,112



213,940



243,112


Marketing derivative fair value losses


21,394



(94,081)



21,394



(94,081)


Losses on settled marketing derivatives




72,687





72,687


Impairment of unproved properties


159,598



553,907



159,598



559,095


Impairment of gathering systems and facilities






23,431




Equity-based compensation


76,162



49,341



103,445



70,413


(Gain) loss on change in fair value of contingent acquisition consideration




93,019






Loss on early extinguishment of debt


1,205





1,500




Tax effect of reconciling items (1)


69,976



(240,513)



50,784



(223,045)


Other tax items (2)


(427,962)



(2,987)



(427,962)



(2,987)


Adjusted Net Income  

$

71,100


$

364,562


$

102,917


$

315,271















Fully Diluted Shares Outstanding


316,283



316,675



316,283



316,365




























Net Income (loss) attributable to Antero Resources Corp


1.94



(1.26)



1.94



(1.26)


Commodity derivative fair value (gains) losses


(2.08)



0.28



(2.08)



0.28


Gains (losses) on settled commodity derivatives


0.68



0.77



0.68



0.77


Marketing derivative fair value losses


0.07



(0.30)



0.07



(0.30)


Losses on settled marketing derivatives




0.23





0.23


Impairment of unproved properties


0.50



1.75



0.50



1.77


Impairment of gathering systems and facilities


0.00





0.07




Equity-based compensation


0.24



0.16



0.33



0.22


(Gain) loss on change in fair value of contingent

acquisition consideration




0.29






Loss on early extinguishment of debt


0.00





0.00




Tax effect of reconciling items (1)


0.22



(0.76)



0.16



(0.70)


Other tax items (2)


(1.35)



(0.01)



(1.35)



(0.01)


Adjusted Net Income

$

0.22


$

1.15


$

0.33


$

1.00




(1)

Blended tax rates of approximately 38% for 2017 and 24% for 2018 were applied to reconciling items above.

(2)

Tax impact of valuation allowance on Colorado net operating losses, changes to Colorado tax law, tax reform legislation enacted in late 2017 and items effecting the Stand-alone financial statements.

Adjusted Operating Cash Flow, Stand-alone 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 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 Adjusted Operating Cash Flow, less Stand-alone Drilling and Completion capital, less Land Maintenance Capital.

Management believes that Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free 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 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. 

There are significant limitations to using Adjusted Operating Cash Flow, Stand-alone 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 basis, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow reported by different companies.  Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow and Free Cash Flow do not represent funds available for discretionary use because those funds may be required for debt service, land acquisitions and lease renewals, other capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations.

Adjusted Operating Cash Flow and Free Cash Flow are not measures 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 Operating Cash Flow as used in this release (in thousands):
















Stand-alone


Consolidated




Three months ended


Three months ended




December 31, 2018


December 31, 2018




2017


2018


2017


2018
















Net cash provided by operating activities 

$

254,078



729,082


$

313,483



821,589



Net change in working capital 


57,666



46,074



54,054



41,656



Adjusted Operating Cash Flow 

$

311,744



775,156


$

367,537



863,245


































Total Debt, Net Debt and Stand-alone Net Debt

Net Debt is calculated as total debt less cash and cash equivalents.  Management uses Consolidated Net Debt and Stand-alone Net Debt to evaluate its financial position, including its ability to service its debt obligations.

The following table reconciles consolidated total debt to Consolidated Net Debt and Stand-alone Net Debt as used in this release (in thousands):

Adjusted EBITDAX and Stand-alone Adjusted EBITDAX











December 31,


December 31,




2017


2018










AR bank credit facility


$

185,000



405,000


AM bank credit facility



555,000



990,000


5.375% AR senior notes due 2021



1,000,000



1,000,000


5.125% AR senior notes due 2022



1,100,000



1,100,000


5.625% AR senior notes due 2023



750,000



750,000


5.375% AM senior notes due 2024



650,000



650,000


5.000% AR senior notes due 2025



600,000



600,000


Net unamortized premium



1,520



1,241


Net unamortized debt issuance costs



(41,430)



(34,553)


Consolidated total debt


$

4,800,090



5,461,688


Less: AR cash and cash equivalents



20,078




Less: AM cash and cash equivalents



8,363




Consolidated net debt


$

4,771,649



5,461,688










Less: Antero Midstream debt net of cash and unamortized premium and debt issuance costs


$

1,187,637



1,632,147


Stand-alone Net Debt


$

3,584,012



3,829,541


















Adjusted EBITDAX as defined by the Company represents net income or loss from continuing operations, including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, 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, and contract termination and rig stacking costs.  Adjusted EBITDAX also includes distributions from unconsolidated affiliates and excludes equity in earnings or losses of unconsolidated affiliates.

Stand-alone 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 (excluding net cash receipts or payments on derivative instruments included in derivative fair value gains or losses other than proceeds from derivative monetizations), taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, equity in earnings or loss of Antero Midstream and gain or loss on changes in the fair value of contingent acquisition consideration. Stand-alone 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 Adjusted EBITDAX is Stand-alone 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 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 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 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 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 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 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


Consolidated




Three months ended  December 31,


Three months ended  December 31,


(in thousands)


2017


2018


2017


2018


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


$

486,869


$

(121,546)


$

486,869



$      (121,546)


Net income and comprehensive income attributable to noncontrolling interest







42,745



140,282


Commodity derivative fair value (gains) losses



(199,824)



222,387



(199,824)



222,387


Gains (losses) on settled commodity derivatives



76,548



(25,257)



76,548



(25,257)


Marketing derivative fair value losses



21,394





21,394




Losses on settled marketing derivatives





(5,411)





(5,411)


Interest expense



53,687



59,458



63,390



78,440


Loss on early extinguishment of debt



1,205





1,500




Income tax expense (benefit)



(400,138)



(131,357)



(400,138)



(131,357)


Depletion, depreciation, amortization, and accretion



183,439



240,977



214,397



263,703


Impairment of unproved properties



76,500



143,369



76,500



143,369


Impairment of gathering systems and facilities







23,431




Exploration expense



3,028



936



3,028



936


Gain on change in fair value of contingent acquisition consideration



(3,804)



104,860






Equity-based compensation expense



17,673



9,518



24,520



13,984


Equity in earnings of unconsolidated affiliates







(7,307)



(12,448)


Distributions from unconsolidated affiliates







10,075



16,755


Equity in (earnings) loss of Antero Midstream Partners LP



22,128



(66,753)






Distributions from Antero Midstream Partners LP



33,614



43,503






Adjusted EBITDAX



372,319



474,684



437,128



583,837


Interest expense



(53,687)



(59,458)



(63,390)



(78,440)


Exploration expense



(3,028)



(936)



(3,028)



(936)


Changes in current assets and liabilities



(57,666)



(46,074)



(54,054)



(41,656)


Proceeds from derivative monetizations





370,365





370,365


Premium paid on derivative contracts





(13,318)





(13,318)


Other non-cash items



(3,860)



3,829



(3,173)



1,736


Net cash provided by operating activities

$


254,078


$

729,092


$

313,483


$

821,588


 

Adjusted EBITDAX

$


372,319


$

474,684


$

437,128


$

583,837


Production (MMcfe)



215,921



295,576



215,921



295,576


Adjusted EBITDAX margin per Mcfe

$


1.72



1.61


$

2.02


$

1.98


The following table reconciles net income as reported in the Parent column of Antero's guarantor footnote to its financial statements to Stand-alone Adjusted EBITDAX for the twelve months ended December 31, 2018, as used in this release (in thousands):























Stand-alone










Twelve months ended


(in thousands)








December 31, 2018


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








$




(397,517)


Commodity derivative fair value (gains) losses












87,594


Gains on settled commodity derivatives












243,112


Marketing derivative fair value gains












(94,081)


Gains on settled marketing derivatives












72,687


Interest expense












224,977


Income tax benefit












(128,857)


Depletion, depreciation, amortization, and accretion












845,136


Impairment of unproved properties












549,437


Impairment of gathering systems and facilities












4,470


Exploration expense












4,958


Gain on change in fair value of contingent acquisition consideration












93,019


Equity-based compensation expense












49,341


Equity in (earnings) loss of Antero Midstream Partners LP












3,664


Distributions from Antero Midstream Partners LP












159,181


Stand-alone Adjusted EBITDAX








$




1,717,121


The following tables reconcile Antero's drilling and completion costs as reported on a cash basis to drilling and completion costs on an accrual basis:

Drilling and Completion Costs















Three Months Ended

December 31, 2018


Years Ended

December 31, 2018



2017


2018


2017


2018















Drilling and completion costs (as reported; cash basis)

$

335,476


$

362,912


$

1,281,985


$

1,488,573


Change in accrued capital costs


(14,391)



(25,539)



(14,005)



(2,363)


Drilling and completion costs (accrual basis)

$

321,086


$

337,374


$

1,267,980


$

1,486,210


Stand-alone Drilling and Completion Costs
















Three Months Ended

December 31, 2018


Years Ended

December 31, 2018




2017


2018


2017


2018
















Stand-alone drilling and completion costs (as reported; cash basis)

$

373,350


$

415,298


$

1,455,554


$

1,743,587


Change in accrued capital costs


(2,820)



(36,633)



241,303



(15,238)


Stand-alone drilling and completion costs (accrual basis)

$

370,530


$

378,665


$

1,696,857


$

1,728,349





















Proved Developed F&D Cost Per Unit & Pre-Tax PV-10 Value

Proved developed F&D costs per unit and pre-tax PV-10 are non-GAAP metrics commonly used in the exploration and production industry by companies, investors and analysts in order to measure a company's ability of adding and developing reserves at a reasonable cost.  Proved developed F&D costs per unit is a statistical indicator that has limitations, including its predictive and comparative value. In addition, because proved developed F&D costs per unit do not consider the cost or timing of future production of new reserves, such measures may not be adequate measures of value creation. This reserve metric may not be comparable to similarly titled measurements used by other companies.  There are no directly comparable financial measures presented in accordance with GAAP for proved developed F&D costs per unit, and therefore a reconciliation to GAAP is not practicable.

The calculation for proved developed F&D cost per unit is based on costs incurred in 2018. The calculation for proved developed F&D cost per unit does not include future development costs required for the development of proved undeveloped reserves.  

The pre-tax PV-10 value is a non-GAAP financial measure as defined by the SEC.  Antero believes that the presentation of pre-tax PV-10 is relevant and useful to its investors because it presents the discounted future net cash flows attributable to reserves prior to taking into account corporate future income taxes and the Company's current tax structure.  The Company further believes investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies.  Antero believes that PV-10 estimates using strip pricing can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows in the current commodity price environment.     

The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure").  The following sets forth the estimated future net cash flows from our proved reserves (without giving effect to our commodity derivatives), the present value of those net cash flows before income tax (PV-10) and the present value of those net cash flows after income tax (Standardized measure) at December 31, 2018:                                                                                                                                                               

(In millions, except per Mcf data)



At December 31, 2018






Future net cash flows

$

30,739


Present value of future net cash flows:




Before income tax (PV-10)

$

12,589


Income taxes

$

(2,111)


After income tax (Standardized measure)

$

10,478


Notwithstanding their use for comparative purposes, the Company's non-GAAP financial measures may not be comparable to similarly titled measures employed by other companies.

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, gain on sale of assets, depreciation expense, impairment expense, change in fair value of contingent acquisition consideration, accretion, 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,

2017


2018


2017


2018

Net income

$

64,155


$

248,609


$

307,315


$

585,944

Impairment of property and equipment


23,431





23,431



5,771

Change in fair value of contingent acquisition consideration




(105,872)





(105,872)

Adjusted Net Income

$

87,586


$

142,737


$

344,872


$

485,843

Interest expense, net


10,395



18,993



37,557



61,906

Depreciation


30,958



22,692



119,562



130,013

Accretion of contingent acquisition consideration


3,804



1,012



13,476



12,853

Accretion of asset retirement obligation




34






135

Equity-based compensation


6,847



4,467



27,283



21,073

Equity in earnings of unconsolidated affiliates


(7,307)



(12,448)



(20,194)



(40,280)

Distributions from unconsolidated affiliates


10,075



16,755



20,195



46,415

Gain on sale of assets – Antero Resources








(583)

Adjusted EBITDA

$

142,358


$

194,242


$

528,625


$

717,375

Interest paid


(4,136)



(9,268)



(46,666)



(62,844)

Decrease (increase) in cash reserved for bond interest (1)


(8,734)



(8,734)



291



0

Income tax withholding upon vesting of Antero Midstream Partners LP equity-based compensation awards


(514)



(1,029)



(5,945)



(5,529)

Maintenance capital expenditures(2)


(12,063)



(7,988)



(55,159)



(52,729)

Distributable Cash Flow

$

116,911


$

167,223


$

421,146


$

596,273













Distributions Declared to Antero Midstream Holders












Limited partners


68,231



88,045



247,132



320,915

Incentive distribution rights


23,772



43,492



69,720



142,906

Total Aggregate Distributions

$

92,003


$

131,537


$

316,852


$

463,821













DCF coverage ratio


1.27x



1.27x



1.33x



1.29x



(1)

Cash reserved for bond interest expense on Antero Midstream's 5.375% senior notes outstanding during the period that is paid on a semi-annual basis on March 15th and September 15th of each year.

(2)

Maintenance capital expenditures represent the portion of our estimated capital expenditures associated with (i) the connection of new wells to our gathering and processing systems that we believe will be necessary to offset the natural production declines Antero Resources will experience on all of its wells over time, and (ii) water delivery to new wells necessary to maintain the average throughput volume on our systems.

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 the expected sources of funding and timing for completion of the share repurchase program if at all, statements regarding the simplification transaction, including the expected consideration to be received in connection with the closing of the simplification transaction, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Free Cash Flow and leverage targets,  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, the expected timing and likelihood of completion of the simplification transaction, 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, 2018.

This release provides a summary of Antero's reserves as of December 31, 2018, assuming partial ethane "rejection" where sales demand for ethane is not available.  Ethane rejection occurs when ethane is left in the wellhead natural gas stream when the natural gas is processed, rather than being separated out and sold as a liquid after fractionation.  When ethane is left in the gas stream, the Btu content of the residue natural gas at the outlet of the processing plant is higher.  Producers will generally elect to "reject" ethane at the processing plant when the price received for the ethane in the natural gas stream is greater than the price received for the ethane being sold as a liquid after fractionation, net of fractionation costs.  When ethane is recovered in the processing plant, the Btu content of the residue natural gas is lower, but a producer is then able to recover the value of the ethane sold as a separate natural gas liquid product.  In addition, natural gas processing plants can produce the other NGL products (propane, normal butane, isobutene and natural gasoline) while rejecting ethane.

No Offer or Solicitation

This communication includes a discussion of a proposed business combination transaction between Antero Midstream and AMGP. This communication is for informational purposes only and does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval, in any jurisdiction, pursuant to the transaction or otherwise, nor shall there be any sale, issuance, exchange or transfer of the securities referred to in this document in any jurisdiction in contravention of applicable law. No offer of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, as amended.

Additional Information And Where To Find It

In connection with the transaction, AMGP has filed with the U.S. Securities and Exchange Commission ("SEC") a registration statement on Form S-4, that includes a joint proxy statement of Antero Midstream and AMGP and a prospectus of AMGP. The transaction will be submitted to Antero Midstream unitholders and AMGP shareholders for their consideration. Antero Midstream and AMGP may also file other documents with the SEC regarding the transaction. The registration statement on Form S-4 became effective on January 30, 2019, and the definitive joint proxy statement/prospectus is being sent to the shareholders of AMGP and unitholders of Antero Midstream of record as of January 11, 2019. This document is not a substitute for the registration statement and joint proxy statement/prospectus that has been filed with the SEC or any other documents that AMGP or Antero Midstream may file with the SEC or send to shareholders of AMGP or unitholders of Antero Midstream in connection with the transaction. INVESTORS AND SECURITY HOLDERS OF ANTERO MIDSTREAM AND AMGP ARE URGED TO READ THE REGISTRATION STATEMENT AND THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE TRANSACTION AND ALL OTHER RELEVANT DOCUMENTS THAT ARE FILED OR WILL BE FILED WITH THE SEC, AS WELL AS ANY AMENDMENTS OR SUPPLEMENTS TO THESE DOCUMENTS, CAREFULLY AND IN THEIR ENTIRETY BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE TRANSACTION AND RELATED MATTERS.

Investors and security holders are able to obtain free copies of the registration statement and the joint proxy statement/prospectus (when available) and all other documents filed or that will be filed with the SEC by AMGP or Antero Midstream through the website maintained by the SEC at http://www.sec.gov. Copies of documents filed with the SEC by Antero Midstream will be made available free of charge on Antero Midstream's website at http://investors.anteromidstream.com/investor-relations/AM, under the heading "SEC Filings," or by directing a request to Investor Relations, Antero Midstream Partners LP, 1615 Wynkoop Street, Denver, Colorado 80202, Tel. No. (303) 357-7310. Copies of documents filed with the SEC by AMGP will be made available free of charge on AMGP's website at http://investors.anteromidstreamgp.com/Investor-Relations/AMGP or by directing a request to Investor Relations, Antero Midstream GP LP, 1615 Wynkoop Street, Denver, Colorado 80202, Tel. No. (303) 357-7310.


ANTERO RESOURCES CORPORATION

Consolidated Balance Sheets

December 31, 2017 and 2018

(In thousands, except per share amounts)




2017


2018

Assets

Current assets:







Cash and cash equivalents


$

28,441



Accounts receivable, net of allowance for doubtful accounts of $1,320 and $-0- at December 31, 2017 and 2018, respectively



34,896



51,073

Accrued revenue



300,122



474,827

Derivative instruments



460,685



245,263

Other current assets



8,943



35,450

Total current assets



833,087



806,613

Property and equipment:







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







Unproved properties



2,266,673



1,767,600

Proved properties



11,096,462



12,705,672

Water handling and treatment systems



946,670



1,013,818

Gathering systems and facilities



2,050,490



2,470,708

Other property and equipment



57,429



65,842




16,417,724



18,023,640

Less accumulated depletion, depreciation, and amortization



(3,182,171)



(4,153,725)

Property and equipment, net



13,235,553



13,869,915

Derivative instruments



841,257



362,169

Investments in unconsolidated affiliates



303,302



433,642

Other assets



48,291



47,125

Total assets


$

15,261,490



15,519,464








Liabilities and Equity

Current liabilities:







Accounts payable


$

62,982



66,289

Accrued liabilities



443,225



465,070

Revenue distributions payable



209,617



310,827

Derivative instruments



28,476



532

Other current liabilities



17,796



10,822

Total current liabilities



762,096



853,540

Long-term liabilities:







Long-term debt



4,800,090



5,461,688

Deferred income tax liability



779,645



650,788

Derivative instruments



207



Other liabilities



43,316



65,971

Total liabilities



6,385,354



7,031,987

Commitments and contingencies (Notes 13 and 14)







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; 316,379 shares and 308,594 shares issued and outstanding at December 31, 2017 and 2018, respectively



3,164



3,086

Additional paid-in capital



6,570,952



6,485,174

Accumulated earnings



1,575,065



1,177,548

Total stockholders' equity



8,149,181



7,665,808

Noncontrolling interests in consolidated subsidiary



726,955



821,669

Total equity



8,876,136



8,487,477

Total liabilities and equity


$

15,261,490



15,519,464

 

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months and Years Ended December 31, 2017 and 2018

(In thousands, except per share amounts)


















Three Months Ended December 31,


Year Ended December 31,




2017


2018


2017


2018


Revenue and other:














Natural gas sales


$

439,222



789,614


$

1,769,284



2,287,939


Natural gas liquids sales



280,437



349,353



870,441



1,177,777


Oil sales



28,196



58,310



108,195



187,178


Commodity derivative fair value gains (losses)



199,824



(222,386)



658,283



(87,594)


Gathering, compression, water handling and treatment



4,055



6,047



12,720



21,344


Marketing



91,386



64,712



258,045



458,901


Marketing derivative fair value gains (losses)



(21,394)



(1)



(21,394)



94,081


Total revenue and other



1,021,726



1,045,649



3,655,574



4,139,626


Operating expenses:














Lease operating



33,023



42,998



89,057



136,153


Gathering, compression, processing, and transportation



279,929



413,130



1,095,639



1,339,358


Production and ad valorem taxes



24,180



44,242



94,521



126,474


Marketing



119,983



125,132



366,281



686,055


Exploration



3,028



936



8,538



4,958


Impairment of unproved properties



76,500



143,370



159,598



549,437


Impairment of gathering systems and facilities



23,431





23,431



9,658


Depletion, depreciation, and amortization



213,731



262,985



824,610



972,465


Accretion of asset retirement obligations



666



719



2,610



2,819


General and administrative (including equity-based compensation expense)



60,196



58,767



251,196



240,344


Total operating expenses



834,667



1,092,279



2,915,481



4,067,721


Operating income (loss)



187,059



(46,630)



740,093



71,905


Other income (expenses):














Equity in earnings of unconsolidated affiliates



7,307



12,449



20,194



40,280


Interest



(63,390)



(78,440)



(268,701)



(286,743)


Loss on early extinguishment of debt



(1,500)





(1,500)




Total other expenses



(57,583)



(65,991)



(250,007)



(246,463)


Income (loss) before income taxes



129,476



(112,621)



490,086



(174,558)


Provision for income tax benefit



400,138



131,357



295,051



128,857


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



529,614



18,736



785,137



(45,701)


Net income and comprehensive income attributable to noncontrolling interests



42,745



140,282



170,067



351,816


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


$

486,869



(121,546)


$

615,070



(397,517)






























Earnings (loss) per common share—basic


$

1.54



(0.39)


$

1.95



(1.26)
















Earnings (loss) per common share—assuming dilution


$

1.54



(0.39)


$

1.94



(1.26)
















Weighted average number of shares outstanding:














Basic



315,875



313,618



315,426



316,036


Diluted



316,682



313,618



316,283



316,036


 

ANTERO RESOURCES CORPORATION

Consolidated Statements of Cash Flows

Years Ended December 31, 2016, 2017 and 2018

(In thousands)















2016


2017


2018


Cash flows provided by (used in) operating activities:











Net income (loss) including noncontrolling interests


$

(749,448)



785,137



(45,701)


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











Depletion, depreciation, amortization, and accretion



812,346



827,220



975,284


Impairment of unproved properties



162,935



159,598



549,437


Impairment of gathering systems and facilities





23,431



9,658


Commodity derivative fair value (gains) losses



514,181



(658,283)



87,594


Gains on settled commodity derivatives



1,003,083



213,940



243,112


Premium paid on derivative contracts







(13,318)


Proceeds from derivative monetizations





749,906



370,365


Marketing derivative fair value (gains) losses





21,394



(94,081)


Gains on settled marketing derivatives







72,687


Deferred income tax benefit



(485,392)



(295,126)



(128,857)


Gain on sale of assets



(97,635)






Equity-based compensation expense



102,421



103,445



70,414


Loss on early extinguishment of debt



16,956



1,500




Equity in earnings of unconsolidated affiliates



(485)



(20,194)



(40,280)


Distributions of earnings from unconsolidated affiliates



7,702



20,195



46,415


Other



(12,488)



(1,907)



4,681


Changes in current assets and liabilities:











Accounts receivable



39,857



(5,214)



(15,156)


Accrued revenue



(133,718)



(38,162)



(174,706)


Other current assets



1,774



(2,755)



(5,817)


Accounts payable



7,365



9,462



9,307


Accrued liabilities



18,853



64,862



63,562


Revenue distributions payable



34,040



45,628



101,210


Other current liabilities



(1,091)



2,214



(3,823)


Net cash provided by operating activities



1,241,256



2,006,291



2,081,987


Cash flows provided by (used in) investing activities:











Additions to proved properties



(134,113)



(175,650)




Additions to unproved properties



(611,631)



(204,272)



(172,387)


Drilling and completion costs



(1,327,759)



(1,281,985)



(1,488,573)


Additions to water handling and treatment systems



(188,188)



(194,502)



(97,699)


Additions to gathering systems and facilities



(231,044)



(346,217)



(444,413)


Additions to other property and equipment



(2,694)



(14,127)



(7,514)


Investments in unconsolidated affiliates



(75,516)



(235,004)



(136,475)


Change in other assets



3,977



(12,029)



(3,663)


Proceeds from asset sales



171,830



2,156




Net cash used in investing activities



(2,395,138)



(2,461,630)



(2,350,724)


Cash flows provided by (used in) 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




Repurchases of common stock







(129,084)


Issuance of senior notes



1,250,000






Repayment of senior notes



(525,000)






Borrowings (repayments) on bank credit facilities, net



(677,000)



90,000



660,379


Make-whole premium on debt extinguished



(15,750)






Payments of deferred financing costs



(18,759)



(16,377)



(2,169)


Distributions to noncontrolling interests in consolidated subsidiary



(75,082)



(152,352)



(267,271)


Employee tax withholding for settlement of equity compensation awards



(26,895)



(24,174)



(17,020)


Other



(5,321)



(4,983)



(4,539)


Net cash provided by financing activities



1,162,019



452,170



240,296


Net increase (decrease) in cash and cash equivalents



8,137



(3,169)



(28,441)


Cash and cash equivalents, beginning of period



23,473



31,610



28,441


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



275,769













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


$

(152,093)



(547)



(47,717)


 

ANTERO RESOURCES CORPORATION

 

The following tables set forth selected operating data for the three months ended December 31, 2017 and 2018:


















Three Months Ended December 31,


Amount of
Increase


Percent



(in thousands)


2017


2018


(Decrease)


Change



Operating revenues and other:














Natural gas sales


$

439,222


$

789,614


$

350,392


80

%


NGLs sales



280,437



349,353



68,916


25

%


Oil sales



28,196



58,310



30,114


107

%


Commodity derivative fair value gains (losses)



199,824



(222,386)



(422,210)


(211)

%


Gathering, compression, water handling and treatment



4,055



6,047



1,992


49

%


Marketing



91,386



64,712



(26,674)


(29)

%


Marketing derivative fair value gains



(21,394)



(1)



21,393


(100)

%


Total operating revenues and other



1,021,726



1,045,649



23,923


2

%


Operating expenses:














Lease operating



33,023



42,998



9,975


30

%


Gathering, compression, processing, and transportation



279,929



413,130



133,201


48

%


Production and ad valorem taxes



24,180



44,242



20,062


83

%


Marketing



119,983



125,132



5,149


4

%


Exploration



3,028



936



(2,092)


(69)

%


Impairment of unproved properties



76,500



143,370



66,870


87

%


Impairment of gathering systems and facilities



23,431





(23,431)


(100)

%


Depletion, depreciation, and amortization



213,731



262,985



49,254


23

%


Accretion of asset retirement obligations



666



719



53


8

%


General and administrative (excluding equity-based compensation)



35,676



44,782



9,106


26

%


Equity-based compensation



24,520



13,985



(10,535)


(43)

%


Total operating expenses



834,667



1,092,279



257,612


31

%


Operating income (loss)



187,059



(46,630)



(233,689)


(125)

%
















Other earnings (expenses):














Equity in earnings of unconsolidated affiliates



7,307



12,449



5,142


70

%


Interest expense



(63,390)



(78,440)



(15,050)


24

%


Loss on early extinguishment of debt



(1,500)





1,500


(100)

%


Total other expenses



(57,583)



(65,991)



(8,408)


15

%


Income (loss) before income taxes



129,476



(112,621)



(242,097)


(187)

%


Income tax (expense) benefit



400,138



(131,357)



(531,495)


(66)

%


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



529,614



18,736



(510,878)


(96)

%


Net income and comprehensive income attributable to noncontrolling interest



42,745



140,282



97,537


228

%


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


$

486,869


$

(121,546)


$

(608,415)


(125)

%
















Adjusted EBITDAX 


$

437,128


$

583,837


$

146,709


34

%


















Three Months Ended December 31,


Amount of
Increase


Percent



(Exploration and Production segment)


2017


2018


(Decrease)


Change



Production data:














Natural gas (Bcf)



157



206



49


31

%


C2 Ethane (MBbl)



2,891



4,323



1,432


50

%


C3+ NGLs (MBbl)



6,422



9,463



3,041


47

%


Oil (MBbl)



571



1,125



554


97

%


Combined (Bcfe)



216



296



80


37

%


Daily combined production (MMcfe/d)



2,347



3,213



866


37

%


Average prices before effects of derivative settlements:














Natural gas (per Mcf)


$

2.80


$

3.83


$

1.03


37

%


C2 Ethane (per Bbl)


$

10.02


$

13.12


$

3.10


31

%


C3+ NGLs (per Bbl)


$

39.16


$

30.92


$

(8.24)


(21)

%


Oil (per Bbl)


$

49.37


$

51.83


$

2.46


5

%


Weighted Average Combined (per Mcfe)


$

3.46


$

4.05


$

0.59


17

%


Average realized prices after effects of derivative settlements:














Natural gas (per Mcf)


$

3.67


$

3.73


$

0.06


2

%


C2 Ethane (per Bbl)


$

10.17


$

13.12


$

2.95


29

%


C3+ NGLs (per Bbl)


$

29.92


$

30.60


$

0.68


2

%


Oil (per Bbl)


$

49.06


$

50.92


$

1.86


4

%


Weighted Average Combined (per Mcfe)


$

3.82


$

3.97


$

0.15


4

%


Average Costs (per Mcfe):














Lease operating


$

0.17


$

0.15


$

(0.02)


(12)

%


Gathering, compression, processing, and transportation


$

1.72


$

1.88


$

0.16


9

%


Production and ad valorem taxes


$

0.11


$

0.15


$

0.04


36

%


Marketing expense, net


$

0.13


$

0.20


$

0.07


54

%


Depletion, depreciation, amortization, and accretion


$

0.85


$

0.82


$

(0.03)


(4)

%


General and administrative (excluding equity-based compensation)


$

0.13


$

0.11


$

(0.02)


(15)

%


 


ANTERO RESOURCES CORPORATION

 

The following tables set forth selected operating data for the years ended December 31, 2017 and 2018:


















Year Ended December 31,


Amount of
Increase


Percent



(in thousands)


2017


2018


(Decrease)


Change



Operating revenues and other:














Natural gas sales


$

1,769,284


$

2,287,939


$

518,655


29

%


NGLs sales



870,441



1,177,777



307,336


35

%


Oil sales



108,195



187,178



78,983


73

%


Commodity derivative fair value gains (losses)



658,283



(87,594)



(745,877)


(113)

%


Gathering, compression, water handling and treatment



12,720



21,344



8,624


68

%


Marketing



258,045



458,901



200,856


78

%


Marketing derivative fair value gains



(21,394)



94,081



115,475


(540)

%


Total operating revenues and other



3,655,574



4,139,626



484,052


13

%


Operating expenses:














Lease operating



89,057



136,153



47,096


53

%


Gathering, compression, processing, and transportation



1,095,639



1,339,358



243,719


22

%


Production and ad valorem taxes



94,521



126,474



31,953


34

%


Marketing



366,281



686,055



319,774


87

%


Exploration



8,538



4,958



(3,580)


(42)

%


Impairment of unproved properties



159,598



549,437



389,839


244

%


Impairment of gathering systems and facilities



23,431



9,658



(13,773)


(59)

%


Depletion, depreciation, and amortization



824,610



972,465



147,855


18

%


Accretion of asset retirement obligations



2,610



2,819



209


8

%


General and administrative (excluding equity-based compensation)



147,751



169,930



22,179


15

%


Equity-based compensation



103,445



70,414



(33,031)


(32)

%


Total operating expenses



2,915,481



4,067,721



1,152,240


40

%


Operating income (loss)



740,093



71,905



(668,188)


(90)

%
















Other earnings (expenses):














Equity in earnings of unconsolidated affiliates



20,194



40,280



20,086


99

%


Interest expense



(268,701)



(286,743)



(18,042)


7

%


Loss on early extinguishment of debt



(1,500)





1,500


(100)

%


Total other expenses



(250,007)



(246,463)



3,544


(1)

%


Income (loss) before income taxes



490,086



(174,558)



(664,644)


(136)

%


Income tax benefit



295,051



128,857



(166,194)


(56)

%


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



785,137



(45,701)



(830,838)


(106)

%


Net income and comprehensive income attributable to noncontrolling interest



170,067



351,816



181,749


107

%


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


$

615,070


$

(397,517)


$

(1,012,587)


(165)

%
















Adjusted EBITDAX


$

1,459,571


$

2,037,382


$

577,811


40

%


















Year Ended December 31,


Amount of
Increase


Percent



(Exploration and Production segment)


2017


2018


(Decrease)


Change



Production data:














Natural gas (Bcf)



591



710



119


20

%


C2 Ethane (MBbl)



10,539



14,221



3,682


35

%


C3+ NGLs (MBbl)



25,507



28,913



3,406


13

%


Oil (MBbl)



2,451



3,265



814


33

%


Combined (Bcfe)



822



989



167


20

%


Daily combined production (MMcfe/d)



2,253



2,709



456


20

%


Average prices before effects of derivative settlements:














Natural gas (per Mcf)


$

2.99


$

3.22


$

0.23


8

%


C2 Ethane (per Bbl)


$

8.83


$

12.14


$

3.31


37

%


C3+ NGLs (per Bbl)


$

30.48


$

34.76


$

4.28


14

%


Oil (per Bbl)


$

44.14


$

57.34


$

13.20


30

%


Weighted Average Combined (per Mcfe)


$

3.34


$

3.69


$

0.35


10

%


Average realized prices after effects of derivative settlements:














Natural gas (per Mcf)


$

3.61


$

3.65


$

0.04


1

%


C2 Ethane (per Bbl)


$

9.04


$

12.14


$

3.10


34

%


C3+ NGLs (per Bbl)


$

24.27


$

33.25


$

8.98


37

%


Oil (per Bbl)


$

45.85


$

52.11


$

6.26


14

%


Weighted Average Combined (per Mcfe)


$

3.60


$

3.94


$

0.34


9

%


Average Costs (per Mcfe):














Lease operating


$

0.11


$

0.14


$

0.03


27

%


Gathering, compression, processing, and transportation


$

1.75


$

1.81


$

0.06


3

%


Production and ad valorem taxes


$

0.11


$

0.12


$

0.01


9

%


Marketing expense, net


$

0.13


$

0.23


$

0.10


77

%


Depletion, depreciation, amortization, and accretion


$

0.86


$

0.85


$

(0.01)


(1)

%


General and administrative (excluding equity-based compensation)


$

0.14


$

0.13


$

(0.01)


(7)

%


 

 

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SOURCE Antero Resources Corporation