Exhibit 99.1

Antero Resources Hosts Analyst Day, Announces 2018 Guidance, Extends Long-Term Targets and Provides 2017 Update

Denver, Colorado, January 17, 2018—Antero Resources Corporation (NYSE: AR) (“Antero” or the “Company”) today announced its 2018 capital budget and guidance, extended long-term targets through 2022 and provided an update to 2017. Antero will also host its analyst day tomorrow, January 18, 2018 in New York City. The event will be webcast live beginning at 9:00 am ET. Interested parties may access the live audio webcast and related presentation materials on Antero’s investor relations website at http://investors.anteroresources.com.

2018 Guidance and Long-Term Target Highlights Include:

· Net daily production is expected to average approximately 2.7 Bcfe/d in 2018, a 20% increase over 2017 levels

· Net daily liquids production is projected to grow 23% over 2017 volumes to 130,000 Bbl/d

· Stand-alone E&P Adjusted EBITDAX is expected to be $1,700-$1,800 million with consolidated Adjusted EBITDAX of $2,050-$2,150 million in 2018

· Expect to fully fund 2018 stand-alone E&P drilling and completion capital with Stand-alone E&P Adjusted Operating Cash Flow

· 2018 natural gas realizations before hedges expected to be a $0.00-$0.05/Mcf premium to Henry Hub, with C3+ NGL realized price averaging 62.5% to 67.5% of Nymex WTI

· Increasing 5-year planned average lateral lengths by 2,500 feet, or 28%, to 11,400 feet per well

· Maintaining a compound annual growth rate target in net production of 20% from 2017 through 2020 and introducing a 15% target in each of 2021 and 2022

· Targeting a debt-adjusted compound annual growth rate in net production of 24% through 2020 and 20% to 24% in each of 2021 and 2022

· Targeting flat consolidated drilling and completion capital budget of $1.3 billion annually through 2020

· Targeting reduced 5-year drilling and completion capital by a cumulative $2.9 billion compared to prior year targets, driven by a combination of longer laterals, improved cycle times, capital re-allocation and enhanced recoveries

· Targeting cumulative Free Cash Flow of $1.6 billion through the five-year period ending 2022 based on strip pricing and $2.8 billion based on flat $60 WTI oil and $2.85 natural gas

· Targeting stand-alone net debt to Adjusted EBITDAX of low 2x in 2018 and under 2x leverage in 2019 and beyond

Preliminary Fourth Quarter 2017 Highlights Include:

· Average net daily gas equivalent production was 2,347 MMcfe/d, an 18% increase over the prior year quarter

· Realized natural gas price before settled commodity derivatives averaged $2.80 per Mcf, a $0.13 negative differential to Nymex, and tighter than fourth quarter guidance of a negative differential of $0.15-$0.20

· Realized C3+ NGL price before settled commodity derivatives averaged $39.16 per barrel (71% of WTI), a 55% increase as compared to the fourth quarter of 2016 and a 35% increase sequentially

· Fourth quarter stand-alone E&P net income expected to be in the range of $490 to $510 million, with consolidated net income or loss, including noncontrolling interest, of $525 to $560 million

· Fourth quarter Stand-alone E&P Adjusted EBITDAX expected to be in the range of $370-$385 million with consolidated Adjusted EBITDAX of $430-$445 million, above the midpoint of previous fourth quarter guidance

For a discussion of the non-GAAP financial measures Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted operating cash flow, Consolidated Adjusted operating cash flow and Free Cash Flow, please see “Non-GAAP Financial Measures.”

Commenting on Antero’s long-term targets, Paul Rady, Chairman and CEO, said, “2018 will be a transformational year for the company as we move toward free cash flow generation, while maintaining our peer leading high margin growth profile. Through continued efficiency gains, we reduced our five-year capital spend target by a cumulative $2.9 billion as compared to last year’s internal long term targets, while maintaining our annual production growth targets through 2022. Due to the significant capital efficiencies that we have achieved over the past several years including from longer lateral drilling, we expect to deliver this high growth profile with flat annual drilling and completion spending through 2020 followed by modest spending increases in 2021 and 2022. Antero’s ability to target top-tier production growth, while generating free cash flow and a declining leverage profile, speaks to our extensive high quality liquids rich drilling inventory. As the largest NGL producer in the U.S., we have substantial exposure to the improving liquids commodity price environment, which supports our ability to deliver peer leading Adjusted EBITDAX margins and achieve the long term targets outlined here today.”

2018 Capital Budget

Antero’s consolidated capital budget for 2018 is $1.45 billion, including $1.3 billion for drilling and completion, $25 million for leasehold maintenance and $125 million for discretionary leasehold expenditures. Antero’s drilling and completion budget has remained essentially flat for three consecutive years. Net production is expected to average approximately 2.7 Bcfe/d in 2018, representing year-over-year growth of 20% as compared to 2017, including 23% liquids growth to 130,000 Bbl/d. Approximately 80% of the drilling and completion budget for 2018 is allocated to the Marcellus Shale and the remaining 20% is allocated to the Ohio Utica Shale.

The Company’s 2018 capital budget excludes Antero Midstream Partners LP’s (“Antero Midstream”) (NYSE: AM) $650 million capital budget for the construction of low and high pressure gathering pipelines, compressor stations, processing and fractionation facilities, fresh water delivery and advanced wastewater treatment infrastructure. Antero Midstream announced its 2018 capital budget and guidance today in a separate news release, which can be found at www.anteromidstream.com.

In 2018, Antero plans to operate an average of five drilling rigs and four completion crews in the Marcellus Shale and expects to complete 120 to 125 wells with an average lateral length of 9,300 feet. The drilling plan in the Marcellus averages nine wells per pad. As average lateral lengths continue to increase, total well costs are expected to decline further in 2018 to $0.80 million per 1,000’ of lateral, a 45% decline from 2014 and a 9% reduction from 2017 well costs.

The Company plans to operate one drilling rig and one completion crew in the Ohio Utica Shale in 2018 and expects to complete 20 to 25 wells with an average lateral length of approximately 11,600 feet. Antero is currently drilling and completing its Utica wells at an average budgeted cost of $0.89 million per 1,000’ of lateral, a 43% well cost improvement over 2014 and a 9% improvement from 2017 well costs.

Antero is budgeting to continue to consolidate acreage for development plan purposes in the core of its Marcellus and Ohio Utica leasehold positions in 2018 along with extending leases on acreage that is planned to be developed over the next several years. Antero has budgeted $125 million for discretionary leasehold expenditures and approximately $25 million is budgeted for leasehold maintenance spending required to support the five-year development plan. Consistent with historical practices, the Company does not budget for asset or corporate acquisitions.

The following is a comparison of the 2018 consolidated capital budget to 2017 guidance.

($ in MM)	Year Ended December 31,
Capital Comparison	2017		2018		% Change

Drilling & Completion	$	1,300	$	1,300	0	%
Discretionary Leasehold Capital	$	200	$	125	(38	)%
Leasehold Maintenance Capital (1)	N/A		$	25	N/A
Total Capital	$	1,500	$	1,450	(3	)%
Average Operated Drilling Rigs (2)	6		6		0	%
Average Operated Completion Crews (2)	5		5		0	%
Operated Wells Spud (2)	117		115 – 125		0	%
Operated Wells Completed (2)	135		140 – 150		7	%

(1) Leasehold maintenance capital expenditures were not previously guided to in 2017. Leasehold maintenance capital represents the leasehold capital required to achieve targeted working interest of 95% included in the five year targeted development plan, plus renewals associated with the 5-year development plan.

(2) Adjusted for 2017 actuals.

The 2018 capital budget is expected to be primarily funded through cash flow from operations, with any additional funding coming from available borrowing capacity on Antero’s bank credit facility. As of September 30, 2017, Antero had $2.9 billion of available consolidated liquidity.

2018 Guidance

Antero’s 2018 net daily production, including liquids, is forecast to grow 20% as compared to 2017 volumes to approximately 2.7 Bcfe/d. Net liquids production is forecast to increase approximately 23% to an average of 130,000 Bbl/d in 2018, including 77,500 Bbl/d of C3+ NGLs, 43,000 Bbl/d of ethane and 9,500 Bbl/d of condensate.

Natural Gas and NGL Price Realizations and Cash Costs

The Company expects to realize a $0.00 to $0.05 price premium compared to Nymex for its natural gas sales during 2018. Antero’s firm transportation and sales portfolio allows the Company to transport and sell virtually all of its natural gas production at current favorably priced indices, including TCO, Chicago, MichCon and Gulf Coast hubs. Driven by improved local differentials and the Mariner East 2 project, Antero is forecasting an average realized price for C3+ NGLs of 62.5% to 67.5% of WTI oil prices in 2018 compared to 60% of WTI oil for 2017 C3+ NGL pricing. Accordingly, the sales points for propane and butane are expected to be a combination of Marcus Hook, PA and Houston, PA. Antero is forecasting oil price differentials to WTI of $5.00 to $6.00 per barrel in 2018. Combining the expected improvement in pricing for NGLs and continued strong oil prices, Antero expects an overall increase in Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX of approximately $300 million from liquids in 2018 compared to 2017, before the impact of hedging.

Antero is forecasting a modest increase in Cash Production Expenses due to an increase in transportation expenses. The increase in transportation expenses are associated with Antero’s firm commitments on new pipelines that have recently been placed in service or are expected to be placed in service during 2018. The new pipeline commitments allow Antero to continue to deliver natural gas to premium indices and receive a positive differential to Nymex. Net marketing expense is expected to remain flat at $0.10 to $0.15 per Mcfe in 2018 as the increase in unutilized pipeline capacity due to Antero’s new firm commitment is offset by increasing production throughout the year and mitigation efforts executed in the first quarter of 2018.

The Company is providing the following guidance for 2018 on both a consolidated and an Antero Resources stand-alone basis:

	Consolidated		Stand-alone E&P
2018 Guidance	Low	High	Low	High
Production
Net Daily Production (MMcfe/d)	2,700		2,700
Net Daily Residue Natural Gas Production (MMcf/d)	1,925		1,925
Net Daily Liquids Production (Bbl/d)	130,000		130,000
Net Daily C3+ NGL Production (Bbl/d)	77,500		77,500
Net Daily Ethane Production (Bbl/d)	43,000		43,000
Net Daily Oil Production (Bbl/d)	9,500		9,500

Realized Pricing (1)
Natural Gas Realized Price vs. Nymex Henry Hub ($/Mcf)(2)	$0.00	$0.05	$0.00	$0.05
Oil Realized Price vs. WTI Oil ($/Bbl)	$(5.00)	$(6.00)	$(5.00)	$(6.00)
C3+ NGL Realized Price (% of Nymex WTI) (1)	62.5%	67.5%	62.5%	67.5%
Ethane Realized Price (Differential to Mont Belvieu) ($/Gal)	$(0.03)	$(0.05)	$(0.03)	$(0.05)

Cash Expenses
Cash Production Expense ($/Mcfe)(3)	$1.65	$1.75	$2.10	$2.20
Marketing Expense, Net of Marketing Revenue ($/Mcfe)	$0.10	$0.15	$0.10	$0.15
G&A Expense ($/Mcfe) (4)	$0.15	$0.20	$0.125	$0.175

Adjusted Operating Cash Flow ($MM) (5)	$1,750 - $1,900		$1,480 - $1,600
Adjusted EBITDAX ($MM) (5)	$2,050 - $2,150		$1,700 - $1,800

Capital Expenditures
Drilling and Completion Capital ($MM) (6)	$1,300		$1,500
Leasehold Maintenance Capital ($MM)	$25		$25
Discretionary Land Capital ($MM)	$125		$125
Total	$1,450		$1,650

(1) Based on strip pricing as of December 31, 2017; natural gas price of $2.84/Mcf and WTI of $59.57/Bbl, all prices before hedging.

(2) Includes Btu upgrade as Antero’s processed tailgate and unprocessed dry gas production is greater than 1050 Btu on average.

(3) Includes lease operating expenses, gathering, compression, transportation expenses and production and ad valorem taxes. Stand-alone cash production expense includes 100% of gathering and compression and water fees paid to Antero Midstream that are eliminated on a consolidated basis.

(4) Excludes equity-based compensation.

(5) For a description of the non-GAAP financial measures Adjusted Operating Cash Flow and Adjusted EBITDAX, please read “Non-GAAP Financial Measures.”

(6) Stand-alone Drilling and Completion Capital includes 100% of the water fees paid to Antero Midstream that are eliminated on a consolidated basis and capitalized on a Stand-alone basis.

Extended Long-Term Targets

As a result of continued capital efficiency gains, significant liquids exposure, favorable price realizations due to firm transportation arrangements, attractively hedged gas prices and Appalachian-leading core drilling inventory, Antero is maintaining its 20% compound annual growth rate target for net gas equivalent production through 2020 and is introducing a 15% growth rate target in each of 2021 and 2022. This equates to a debt-adjusted compounded annual production growth rate of 24% through 2020 and 20% to 24% in each of 2021 and 2022. Antero is able to forecast this long-term growth target, despite reducing the targeted 5-year drilling and completion capital by a cumulative $2.9 billion compared to the 2017 long-term outlook. Due to these substantial efficiency improvements, driven by a combination of longer laterals, improved cycle times, capital allocation and enhanced recoveries, Antero is now targeting Free Cash Flow generation of approximately $1.6 billion over the five-year period based on year end 2017 strip pricing of $54.71/Bbl WTI and $2.84/MMBtu natural gas and $2.8 billion over the five-year period assuming flat $60 per barrel WTI oil and $2.85/MMBtu natural gas prices. Antero expects this to result in a declining net debt to Adjusted EBITDAX ratio to the low 2.0-times range by year end 2018 and below 2.0 times in 2019, assuming strip pricing.

Antero forecasts the percentage of natural gas production sold at current favorably priced indices through 2022 to improve relative to 2018 guidance resulting in natural gas price realizations, before hedges, at a $0.05 to $0.10 per Mcf premium to Nymex including the BTU premium. Further enhancing price realizations, Antero has hedged approximately 80% of natural gas production targets for the years 2018 through 2020 at an average hedged price of $3.50 per MMBtu. The Company has 2.8 Tcfe hedged through 2023 with a mark to market value of approximately $1.3 billion, based on December 31, 2017 strip pricing.

Updated for the longer lateral drilling plan, Antero has an inventory of approximately 3,300 undrilled core 3P locations with an average lateral length of 10,800 feet. Approximately 59% of Antero’s drilling inventory is comprised of laterals greater than 10,000 feet and 44% is greater than 12,000 feet.

Supported by Antero Resources’ long-term production growth targets, Antero Midstream today announced a long-term distribution growth target of 28% to 30% per year through 2020 and 20% per year in 2021 and 2022. As of December 31, 2017, Antero Resources owned approximately 53% of Antero Midstream common units.

Commenting on the 2018 capital budget and guidance, Glen Warren, Antero’s President and CFO, said, “Continued drilling efficiency improvements, a longer lateral drilling program, strong production growth and our position as the largest NGL producer in the U.S. provides a significant step-up in free cash flow over our extended five-year outlook. Our $1.6 billion in targeted Free Cash Flow generation through 2022 before discretionary leasehold acquisitions, (based on current strip pricing) is expected to provide significant financial flexibility to pay down debt or return capital to shareholders. We forecast a significant decrease in leverage ratios to the low 2.0-times on a stand-alone basis by year-end 2018, with further declines over the five-year outlook when using the Free Cash Flow to pay down debt. This profile places Antero in an elite group comprised of a handful of upstream companies that are generating double digit percentage production growth and near term free cash flow on the foundation of a strong balance sheet and a large core drilling inventory.”

Fourth Quarter 2017 Operating Update

Antero’s net daily production for the fourth quarter of 2017 averaged 2,347 MMcfe/d, including 1,702 MMcf/d (72%) of natural gas, 101,226 Bbl/d (26%) of natural gas liquids, including 31,425 Bbl/d of ethane, and 6,207 Bbl/d (2%) of oil.

The following table provides an update to Adjusted EBITDAX for the fourth quarter of 2017, including a revised range for Consolidated Adjusted EBITDAX of $430 - $445 million, up from the $410 - $440 million original guidance and Stand-alone E&P Adjusted EBITDAX that is expected to be $370 - $385 million:

($MM)	Consolidated	Stand-alone E&P

Net income or loss including noncontrolling interests	$515 - $550	$480 - $500
Adjusted EBITDAX (1)	$430 - $445	$370 - $385

(1) For a description of the non-GAAP financial measure, Adjusted EBITDAX, please read “Non-GAAP Financial Measures.” Stand-alone E&P Adjusted EBITDAX includes 100% of gathering and compression and water fees paid to Antero Midstream that are eliminated on consolidated basis and expensed on Stand-alone basis.

Fourth quarter 2017 production represents an organic production growth rate of 18% from the fourth quarter of 2016 and a 1% increase compared to the third quarter of 2017. Fourth quarter 2017 production was negatively impacted by the delayed in-service date of the Rover Pipeline, resulting in 10 Utica wells not being placed into sales until year-end 2017. Those 10 wells are currently producing approximately 175 MMcfe/d on restricted choke and were previously scheduled to come on-line in November 2017. Liquids production for the fourth quarter of 2017 represents an organic production growth rate of 24% from the fourth quarter of 2016 and a 4% decrease sequentially. The sequential decline in liquids production reflects the effect of higher NGL distributions to royalty owners as a result of the improvement in liquids pricing.

Antero’s average realized natural gas price before settled derivatives for the fourth quarter of 2017 was $2.80 per Mcf, a $0.13 per Mcf negative differential to the average Nymex price for the period. This differential represents an improvement from the $0.29 per Mcf negative differential to Nymex realized in the third quarter of 2017. The improvement was primarily driven by reduced impacts from the disputes with Washington Gas Light Company and one of its affiliates (collectively, “WGL”) and South Jersey Resources Group and one of its affiliates (collectively, “South Jersey”), which negatively impacted realizations by $0.18 per Mcf and $0.02 per Mcf, respectively during the quarter compared to $0.22 per Mcf and $0.04 per Mcf, respectively, during the third quarter of 2017. Looking ahead to 2018, Antero does not expect a material impact to its realized pricing and cash flow from these contractual disputes due in part to additional takeaway capacity that is expected to be placed in service throughout the year and narrow regional basis differentials based on current strip pricing.

Antero’s average realized C3+ NGL price before settled derivatives for the fourth quarter of 2017 was $39.16 per barrel, or approximately 71% of the average WTI oil price for the period. This reflects a 55% increase in realized price as compared to the fourth quarter of 2016 and a 35% increase sequentially. The increase was driven primarily by the strengthening of Mont Belvieu pricing relative to WTI, which continues to benefit by an increase in export volumes.

Antero’s average realized oil price before hedging for the fourth quarter of 2017 was $49.37 per barrel, a $6.00 per barrel negative differential to the average WTI oil price. The Company’s average realized oil price after hedging for the quarter was $49.06 per barrel, a $6.31 per barrel negative differential to the average WTI oil price.

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

	Three Months Ended December 31, 2017
	Gas (MMcf/d)	Oil (Bbl/d)	NGL (C3+) (Bbl/d)	Ethane (C2) (Bbl/d)	Combined Gas Equivalent (MMcfe/d)
Average Net Production	1,702	6,207	69,801	31,425	2,347

	Gas ($/Mcf)		Oil ($/Bbl)			NGL (C3+) ($/Bbl)			Ethane (C2) ($/Bbl)		Combined Gas Equivalent ($/Mcfe)
Average Realized Prices
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

The information presented above is based upon information available to the Company as of January 17, 2018 and is not a comprehensive statement of the Company’s financial results. These are preliminary non-reviewed unaudited financial results. The Company’s completed results to be reported for the three months ended December 31, 2017 may differ materially from this preliminary data. During the course of the preparation of the Company’s consolidated financial statements and related notes to be included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2017, additional adjustments to the preliminary financial information presented herein may be identified. Any such adjustments may be material.

Analyst Day Presentation and Live Webcast

Antero plans to host an analyst day on Thursday, January 18, 2018 in New York City. Interested parties may access the live audio webcast and related presentation materials by visiting the investor relations section on Antero’s website as detailed below. Paul Rady, Chairman and Chief Executive Officer, and Glen Warren, President and Chief Financial Officer, along with other Antero executives, will present Antero’s corporate strategy and long-term outlook. The event will be webcast live beginning at 9:00 am ET and may be accessed on Antero’s investor relations website at http://investors.anteroresources.com. A replay of the webcast will also be available on Antero’s investor relations website.

Non-GAAP Financial Measures

Debt-adjusted production growth is defined as net production per Debt-Adjusted share for each specified period. Debt-adjusted shares represent period ending projected debt balances divided by ending share price plus ending shares outstanding. Forecasted debt-adjusted shares assumes Antero share price of $19.87 per share as of January 12, 2018.

Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow are financial measures that are not calculated in accordance with U.S. generally accepted accounting principles (“GAAP”). The non-GAAP financial measures used by the company may not be comparable to similarly titled measures utilized by other companies. These measures should not be considered in isolation or as substitutes for their nearest GAAP measures. The Stand-alone measures are presented to isolate the results of the operations of Antero apart from the performance of Antero Midstream, which is otherwise consolidated into the results of Antero.

Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX

Consolidated Adjusted EBITDAX as defined by the Company represents net income or loss from continuing operations, 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. Consolidated 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 from continuing operations 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 Consolidated 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 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 Consolidated 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 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. Consolidated Adjusted EBITDAX is also used by the board of directors as a performance measure in determining executive compensation. Consolidated 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 Consolidated 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 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, Consolidated 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.

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

Consolidated Adjusted Operating Cash Flow as defined by the Company represents net cash provided by operating activities before changes in current assets and liabilities. Stand-alone E&P Adjusted Operating Cash Flow as defined by the Company represents Stand-alone 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 current assets and liabilities, plus earn out payments of $125 million expected in each of 2019 and 2020 from Antero Midstream associated with the water drop down transaction that occurred in 2015. 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.

The GAAP financial measure nearest to Consolidated Adjusted Operating Cash Flow is cash flow from operating activities as reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow is Stand-alone cash flow from operating activities that will be reported in the Parent column of Antero’s guarantor footnote to its financial statements. Management believes that Consolidated 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 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 Consolidated 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 Consolidated Adjusted Operating Cash Flow and Stand-alone E&P Adjusted Operating Cash Flow reported by different companies. Consolidated 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.

The following table provides a range of preliminary results for the fourth quarter of 2017:

	Three Months Ended December 31, 2017
	Consolidated							Stand-alone E&P
($MM)	Low				High			Low				High

Net income including noncontrolling interest (1)	$	525,000		—	$	560,000		$	490,000		—	$	510,000
Commodity derivative (gains)	(175,000		)	—	(180,000		)	(175,000		)	—	(180,000		)
Gains (losses) on settled derivative instruments	76,000			—	78,000			76,000			—	78,000
Interest expense	62,000			—	64,000			50,000			—	55,000
Loss on early extinguishment of debt	1,000			—	2,000			1,000			—	2,000
Provision (benefit) for income taxes	(390,000		)	—	(430,000		)	(390,000		)	—	(430,000		)
Depreciation, depletion, amortization, and accretion	210,000			—	218,000			176,000			—	191,000
Impairment of unproved properties	70,000			—	77,000			70,000			—	77,000
Impairment of fixed assets and other	22,000			—	24,000			—			—	—
Exploration expense	3,000			—	4,000			3,000			—	4,000
Gain on change in fair value of contingent acquisition consideration	—			—	—			(3,000		)	—	(4,000		)
Equity-based compensation expense	23,000			—	25,000			17,000			—	20,000
Equity in earnings of unconsolidated affiliate	(6,000		)	—	(8,000		)	—			—	—
Distributions from unconsolidated affiliates	9,000			—	11,000			—			—	—
Equity in incomeof Antero Midstream	—			—	—			22,000			—	28,000
Distributions from limited partner interest in Antero Midstream	—			—	—			33,000			—	34,000
Adjusted EBITDAX	$	430,000			$	445,000		$	370,000			$	385,000

(1) The GAAP financial measure nearest to Consolidated Adjusted EBITDAX is net income including noncontrolling interest as reported in Antero’s consolidated financial statements. The GAAP financial measure nearest to Stand-alone E&P Adjusted EBITDAX is Stand-alone net income or loss that will be reported in the Parent column of AR’s guarantor footnote to its financial statements.

Antero has not included a reconciliation of Consolidated Adjusted EBITDAX or Stand-alone E&P Adjusted EBITDAX to their nearest GAAP financial measures for 2018 because it cannot do so without unreasonable effort and any attempt to do so would be inherently imprecise. Antero is able to forecast the following reconciling items between Consolidated Adjusted EBITDAX and Stand-alone E&P Adjusted EBITDAX to net income from continuing operations including noncontrolling interest:

	Consolidated				Stand-alone E&P
(in thousands)	Low		High		Low		High
Interest expense	$	250,000	$	300,000	$	200,000	$	220,000
Depreciation, depletion, amortization, and accretion expense	950,000		1,050,000		800,000		900,000
Impairment expense	100,000		125,000		100,000		125,000
Exploration expense	5,000		15,000		5,000		15,000
Equity-based compensation expense	95,000		115,000		70,000		90,000
Equity in earnings of unconsolidated affiliate	30,000		40,000		N/A		N/A
Distributions from unconsolidated affiliates	40,000		50,000		N/A		N/A
Distributions from limited partner interest in Antero Midstream	N/A		N/A		166,000		170,000

Antero has a significant portfolio of commodity derivative contracts that it does not account for using hedge accounting, and forecasting unrealized gains or losses on this portfolio is impracticable and imprecise due to the price volatility of the underlying commodities. Antero is also forecasting no impact from franchise taxes, gain or loss on early extinguishment of debt, or gain or loss on sale of assets, for 2018. For income tax expense (benefit), Antero is forecasting a 2018 effective tax rate of 18% to 19%.

Antero has not included reconciliations of Consolidated Adjusted Operating Cash Flow, Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow to their nearest GAAP financial measures for 2018 because it would be impractical to forecast changes in current assets and liabilities. However, Antero is able to forecast the earn out payments expected from Antero Midstream associated with the water drop down transaction that occurred in 2015, each of which is a reconciling item between Stand-alone E&P Adjusted Operating Cash Flow and Free Cash Flow, as applicable, and cash flow from operating activities as reported in the Parent column of Antero’s guarantor footnote to its financial statements. Antero forecasts these items to be $125 million in each of 2019 and 2020. Additionally, Antero is able to forecast lease maintenance expenditures and Stand-alone drilling and completion capital, each of which is a reconciling item between Free Cash Flow and its most comparable GAAP financial measure. For the 2018 to 2022 period, Antero forecasts cumulative lease maintenance expenditures of $200 million and cumulative Stand-alone E&P drilling and completion capital of $8.6 billion.

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

This release includes “forward-looking statements”. Such forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond AR’s control. All statements, except for statements of historical fact, made in this release regarding activities, events or developments AR 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, Consolidated Adjusted EBITDAX, Stand-alone E&P Adjusted EBITDAX, Consolidated Adjusted Operating Cash Flow, Stand-alone Adjusted Operating Cash Flow, Free Cash Flow, 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.

AR 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 AR’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 AR’s Annual Report on Form 10-K for the year ended December 31, 2016.

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