Exhibit 99.1

Antero Resources Reports Second Quarter 2019 Financial and Operational Results

Denver, Colorado, July 31, 2019—Antero Resources Corporation (NYSE: AR) (“Antero,” “Antero Resources,” or the “Company”) today released its second quarter 2019 financial and operational results. The relevant condensed consolidated and condensed consolidating financial statements are included in Antero’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, which has been filed with the Securities and Exchange Commission (“SEC”).

Second Quarter 2019 Highlights Include:

Paul Rady, Chairman and CEO said, “Antero achieved strong production volumes and incurred its lowest quarterly capital expenditures to date as a public company. We remain highly focused on creating sustained value by prioritizing key initiatives dedicated to reducing costs, streamlining operations and strategically targeting favorably priced markets for our diverse product portfolio of natural gas and liquids. The first half of 2019 showcased these efforts, with technical and operational initiatives that resulted in our ability to reach our previously announced full year well cost reduction targets by midyear, significantly ahead of schedule. Meanwhile, further well cost reduction initiatives are underway, and we expect well costs to be 10% to 14% lower per foot by 2020, compared to our 2019 budgeted costs per foot. This will primarily be driven through water savings initiatives and continued operational efficiencies. These cost savings combined with our expanded hedge position provide us with greater certainty in our ability to continue to execute our development plan in a challenged commodity price environment.”

Recent Developments

Well Cost Savings Update & Outlook

Antero is on track to achieve its targeted reductions in well costs and lease operating expenses. Antero’s 2019 well cost was budgeted at $0.97 million per 1,000 feet of lateral assuming a 12,000 foot lateral. During the second half of 2019, Antero is expecting well costs to average $0.93 million per 1,000 feet of lateral. Well cost reductions are ahead of schedule and have been delivered through service cost deflation, sand logistics optimization and operational efficiency gains. For 2020, Antero is targeting well costs of $0.83 million to $0.87 million per 1,000 feet of lateral, on average, 10% to 14% lower than the 2019 initial budgeted costs, or $1.2 to $1.7 million lower per well for a 12,000 foot lateral. The additional cost savings are expected to come from water savings initiatives that include enhanced flowback water management and completion design optimization. Expanded water services are also anticipated to reduce lease operating expenses by at least 20% in 2020.

Second Half 2019 Well Costs

During the second quarter of 2019, Antero approached its vendors and service providers to reduce pricing to reflect the current deflationary market environment. The price reductions achieved to date are included in the well cost assumptions discussed above.

One of the key areas of focus with vendors continues to be sand sourcing and logistics. Total delivered sand costs continue to decrease materially, through a shift to directly-sourced sand and improved “last mile” logistics. Antero previously executed its first direct sourcing sand supply agreement at the end of 2018. The Company executed a similar agreement with a premier sand supplier in the second quarter of 2019, and expects to increase directly-sourced sand supply from 75% currently to 100% of completion needs going forward. In addition, improvements to last mile logistics for sand are underway, as the Company has lowered sand delivery trucking costs during the second quarter of 2019.

Operational efficiency gains continue on both the drilling and completions side of development. Drilling days from spud to final rig release have been reduced from 12.4 days in 2018 to 12.0 days year to date in the Marcellus, despite lateral lengths increasing from 10,100 feet to 11,000 feet over that same time period. The Company has seen material improvement in stages completed per day, with an average of 5.7 stages per day in the second quarter of 2019, a 10% increase from 5.2 stages per day in 2018. Antero expects to continue pushing the stages completed per day higher through further completion optimization. In addition, top-hole optimization and other related drilling efficiencies have been achieved and are now becoming a part of Antero’s standard drilling process. The service cost deflation initiative, sand savings and efficiency gains have resulted in per well savings of approximately $500,000 per well, or $0.04 million per 1,000 feet of lateral on a 12,000 foot lateral, resulting in second half of 2019 expected well costs of $0.93 million per 1,000 feet of lateral.

Water Savings Initiatives and Other Efficiency Gains Expected in 2020

Targeted well cost savings and lower lease operating expenses for 2020 are expected to be derived primarily from Antero’s water savings initiatives. The water savings initiatives consist of two components (i) a reduction in flowback water costs through the planning and implementation by Antero Midstream of localized water blending and polishing operations and a flowback and produced water pipeline system and (ii) a reduction in fresh water costs from completion design optimization that will consist of both higher mesh sand and lower fresh water usage.

In conjunction with Antero’s well cost savings initiatives, Antero Midstream announced plans to expand the scope of its water business to support the growing flowback and produced water volumes from Antero Resources. Antero Midstream plans to implement localized storage and fresh water blending operations, utilize mobile treatment for flowback and produced water volumes in Antero’s northern fairway, repurpose portions of the existing fresh water system to transport flowback and produced water, and construct a limited amount of new pipelines to deliver flowback and produced water to localized blending and treatment operations and the Antero Clearwater Facility. Antero Midstream has indicated the fresh water blending and mobile treatment options could be implemented as soon as the second half of 2019 in certain areas of development. The infrastructure buildout will be a flexible, fit-for-purpose system based on Antero Resources’ development plan and Antero Midstream believes the system could be phased in beginning in 2020. These localized operations will replace a significant amount of the flowback and produced volumes currently trucked by third parties, which Antero Midstream manages on a cost plus 3% basis. The Company has historically trucked all flowback and produced water, paying third party trucking companies $160 million over the last twelve months. This creates an opportunity for Antero Resources to materially reduce both capital and lease operating costs.

Based on ongoing assessments of drilling and completion designs, Antero also expects to trend lower in water used in completion operations over time. Depending on the areas being developed, Antero expects water use will be reduced by 5 to 7 barrels per foot, from the current design of 40 to 45 barrels per foot to 35 to 38 barrels per foot in the Marcellus beginning in January 2020.

In addition to water savings initiatives, Antero expects further operational efficiency gains related to development plan optimization. Together, Antero expects overall water savings initiatives and operational efficiency gains to result in additional per well savings of $700,000 to $1.2 million, or $0.06 to $0.10 million per 1,000 feet of lateral, which is 6% to 11% of additional savings per well compared to second half of 2019 budgeted well costs.

Lease Operating Expense Reduction

Antero capitalizes the cost of moving flowback water during the first 90 days of a well’s life. Antero’s lease operating expenses include the cost of transporting produced water after the first 90 days of the well’s life. In the first half of 2019, produced water costs represented approximately 80% of total lease operating expenses. Assuming Antero Midstream implements the expanded produced water services, Antero expects it will result in at least a 20% reduction in lease operating costs in 2020 compared to 2019 budgeted costs. Antero estimates lease operating expense savings of at least $50 million on an annualized basis once the expanded produced water services and blending and polishing operations are fully implemented.

Preliminary 2020 Outlook

Antero Resources is targeting 110 to 120 completions in 2020, with an average lateral length of 12,100 feet as compared to 115 to 125 completions in 2019 with an average lateral of 10,200 feet. This represents a 14% increase in total lateral feet completed. Despite the increase in lateral feet completed, Antero’s preliminary drilling and completion capital budget for 2020 is $1.2 billion to $1.3 billion. This is a result of the aforementioned 10% to 14% well cost reduction initiative combined with the 19% increase in the average lateral length to be completed in 2020 compared to 2019. In addition to drilling and completion capital, Antero is targeting a land capital budget of approximately $75 million, resulting in a total preliminary capital budget of $1.275 to $1.375 billion.

Based on current strip pricing of $2.45 per MMBtu natural gas, $29 per barrel C3+ NGLs, and $56 per barrel oil, the 2020 drilling and completion capital budget is expected to be funded with cash flow from operations and $125 million from a water earn-out payment from Antero Midstream. Additionally, approximately $150 million net to Antero from previously disclosed natural gas pricing disputes that have been ruled in favor of Antero are expected to be included in cash flow from operations in 2020. Assuming strip pricing, an estimated $350 million of realized hedge gains will more than offset all of Antero’s expected net marketing expense in 2020. Antero’s 2020 capital budget is subject to Board approval and will be finalized at year-end 2019 based on the commodity price outlook and various other considerations at that time.

Natural Gas Hedges

During the second quarter of 2019, Antero added NYMEX Henry Hub-based natural gas fixed price swaps for 2020 and 2021 of 810 MMBtu/d at a weighted average price of $2.66 per MMBtu and 300 MMBtu/d at a weighted average price of $2.60 per MMBtu, respectively.

As a result, Antero’s natural gas production is nearly fully hedged for the remainder of 2019 and for all of 2020, and partially hedged in future years.

Antero has been at the forefront of commodity price risk management through its comprehensive natural gas hedging program, and actions taken during the second quarter of 2019 further support Antero’s strategic objectives. The mitigation of commodity price volatility risk through hedging provides key benefits to Antero, most importantly the ability to protect the Company from downside commodity price risk and maintain the Company’s development program, which lead to more efficient development at lower overall costs, supporting EBITDAX margins.

2019 Guidance Update

Natural Gas Pricing Update

In 2019, Antero expects to realize a $0.10 to $0.15 per Mcf price premium relative to NYMEX Henry Hub prices for natural gas sales, compared to the original guidance range of a $0.15 to $0.20 per Mcf premium issued in January 2019. The Company continues to see favorable price mix impacts from natural gas volumes sold in higher priced geographic markets including the Gulf Coast and Midwest. However, NYMEX Henry Hub commodity futures prices for the full year have declined by approximately 15% since the issuance of guidance in January. The reduction in natural gas pricing through the year directly results in a lower overall BTU upgrade and premium to NYMEX for Antero’s natural gas sales.

Cash Production and Net Marketing Expense

Antero is forecasting a decrease in cash production expenses during 2019 to a range of $2.15 to $2.20 per Mcfe from the prior guidance range of $2.15 to $2.25 per Mcfe. Cash production expenses includes lease operating expenses (LOE), gathering, compression, processing, transportation expenses and production and ad valorem taxes. The decrease is driven primarily by lower transportation costs as a result of utilizing lower cost transportation for Antero’s gas production. Based on current strip pricing, Antero expects to continue to utilize the lower cost transport and leave higher cost transport unutilized. As a result, Antero is increasing its net marketing expense guidance to a range of $0.225 to $0.25 per Mcfe, as compared to the original guidance of $0.175 to $0.225 per Mcfe.

Any 2019 projections not discussed in this release are unchanged from previously stated guidance.

Second Quarter 2019 Financial Results

For the three months ended June 30, 2019, Antero reported GAAP net income of $42 million, or $0.14 per diluted share, compared to GAAP net loss of $136 million, or $0.43 per diluted share, in the prior year period. Excluding items detailed in “Non-GAAP Financial Measures,” Adjusted Net Loss was $66 million, or $0.21 per diluted share, compared to Adjusted Net Loss of $2 million during the three months ended June 30, 2018, or $0.01 per diluted share.

Adjusted EBITDAX was $252 million, a 25% decrease compared to $335 million in the prior year period due to lower commodity pricing.

The following table details the components of average net production and average realized prices for the three months ended June 30, 2019:

Net daily natural gas equivalent production in the second quarter averaged 3,226 MMcfe/d, including 156,441 Bbl/d of liquids (29% of production), an increase of 28% compared to the prior year period.

Total liquids production grew 38% compared to the prior year period. Liquids revenue represented approximately 39% of total product revenue before hedges. Oil production averaged 10,331 Bbl/d, an increase of 49% over the prior year period. C3+ NGLs production averaged 105,228 Bbl/d, an increase of 49% over the prior year period. Recovered ethane production averaged 40,882 Bbl/d, an increase of 13% over the prior year period.

Antero’s average realized natural gas price before hedging was $2.66 per Mcf, representing a 6% decrease versus the prior year period and a $0.02 per Mcf premium to the average NYMEX Henry Hub price. Including hedges, Antero’s average realized natural gas price was $2.86 per Mcf, a $0.22 premium to the average NYMEX price, reflecting the realization of a cash settled natural gas hedge gain of $43 million, or $0.20 per Mcf.

Antero’s average realized C3+ NGL price before hedging was $28.57 per barrel, representing an 18% decrease versus the prior year period. Antero shipped 55% of total C3+ net volume on Mariner East 2 for export and realized a $0.19 per gallon premium to Mont Belvieu pricing on this volume at Marcus Hook.  Antero sold the remaining 45% of C3+ net volume at a $0.14 per gallon discount to Mont Belvieu pricing at Hopedale. 

⁽¹⁾ Represents Antero C3+ volume sold by third-party midstream providers (domestically or internationally).

Antero’s average realized oil price before hedging was $52.19 per barrel, a $7.59 differential to the average NYMEX WTI price and a 15% decrease versus the prior year period. Including hedges, Antero’s average realized oil price was $53.49 per barrel, a $6.29 differential to the average NYMEX WTI price, reflecting the realization of a cash settled oil hedge gain of $1 million. The average realized ethane price was $0.19 per gallon, or $8.16 per barrel, an 18% decrease compared to $0.24 per gallon, or $9.93 per barrel, in the prior year period.

Antero’s average natural gas equivalent price including recovered C2+ NGLs and oil, but excluding hedge settlements, was $3.09 per Mcfe, representing an 8% decrease compared to the prior year period. Including hedges, the Company’s average natural gas equivalent price was $3.24 per Mcfe, a 14% decrease from the prior year period. The net cash settled commodity derivative gain on all products was $45 million, or $0.15 per Mcfe.

Total revenue in the second quarter was $1.3 billion, a 31% increase compared to $1.0 billion in the prior year quarter. Revenue included a $284 million non-cash gain on unsettled commodity derivatives, while the prior year included a $41 million non-cash loss on unsettled derivatives. Revenue Excluding Unrealized Derivative Gains (Losses) (non-GAAP) was $1.0 billion, nearly equivalent to the prior year period.

The following table presents a calculation of Adjusted EBITDAX margin (non-GAAP measure) on a per Mcfe basis and a reconciliation to realized price before cash receipts for settled derivatives, the nearest GAAP financial measure. Adjusted EBITDAX margin represents Adjusted EBITDAX divided by production, and is a measure that helps investors to more meaningfully evaluate and compare the results of Antero’s operations from period to period by removing the effect of its capital structure from its operating structure.

⁽¹⁾ Includes cash payments for settled marketing derivative losses of $0.07 per Mcfe in 2018.

Per unit cash production expense, which equals the sum of lease operating, gathering, compression, processing, transportation, and production and ad valorem taxes was $2.18 per Mcfe, a 7% increase compared to $2.04 per Mcfe in the prior year period. The per unit cash production expense for the quarter included $1.93 per Mcfe for gathering, compression, processing and transportation costs, $0.14 per Mcfe for lease operating costs, and $0.11 per Mcfe for production and ad valorem taxes. Per unit gathering, compression, processing and transportation costs reflect higher expenses related to the commencement of Mariner East 2 earlier this year that enabled Antero to in turn deliver higher C3+ NGL prices on volumes sold at the Marcus Hook terminal.

Per unit net marketing expense was $0.25 per Mcfe compared to $0.30 per Mcfe reported in the prior year period. Excluding prior year settled marketing derivative losses of $0.07 per Mcfe, net marketing expense modestly increased as the Company elected to utilize lower cost firm transportation based on price differentials in various markets. As a result, while net marketing expenses are tracking slightly above expectations, they are offset by per unit cash production costs modestly below expectations for the full year.

Per unit general and administrative expense, excluding non-cash equity-based compensation expense, decreased by 20% to $0.12 per Mcfe, compared to the prior year period. General and administrative expense on a per Mcfe basis decreased due to increased production levels and lower employee headcount.

Adjusted EBITDAX margin after commodity derivatives was $0.86 per Mcfe, a 41% decrease from the prior year period, primarily due lower realized prices relative to the prior year period.

Operating Update

Second Quarter 2019

Marcellus Shale — 40 horizontal Marcellus wells were placed to sales during the second quarter of 2019 with an average lateral length of 10,227 feet and an average 60-day rate per well of 18.8 MMcfe/d on choke. The 60-day average rate per well included 838 Bbl/d of liquids, representing oil, C3+ NGLs and 25% ethane recovery. Noteworthy results from the wells placed to sales during the quarter are below: 

During the period, Antero drilled 23 wells with an average lateral length of 12,500 feet in an average of 12.6 total days from spud to final rig release, representing a 2% reduction in total drilling time from the prior year period despite a 30% increase in average lateral feet drilled per well. Additionally, Antero drilled an average of 5,470 lateral feet per day in the quarter, achieving its highest quarterly rate in the Company’s history, representing a 3% sequential increase and a 17% increase compared to the 2018 average in lateral footage performance. Antero also recently achieved a new drilling milestone of 9,650 lateral feet drilled in a rolling 24-hour period, which the Company believes is a new world record. Antero’s ongoing emphasis on completion efficiencies also resulted in material improvement during the second quarter, as the Company averaged 5.7 stages completed per day, representing a 14% increase from 5.0 stages per day in the prior year period.

Ohio Utica Shale — Antero placed 6 horizontal Utica wells to sales during the second quarter of 2019 with an average lateral length of 12,900 feet, an average BTU of 1,099 and an average 60-day rate per well of 22.7 MMcf/day on choke.

During the second quarter of 2019, Antero released one drilling rig and one completion crew. Antero plans to operate an average of four drilling rigs, including three large rigs, and an average of three to four completion crews, for the remainder of the year. For the full year, the Company continues to expect to drill 120 to 130 wells and place 115 to 125 wells online, consistent with prior guidance.

Second Quarter 2019 Capital Investment

Antero’s accrued drilling and completion capital expenditures for the three months ended June 30, 2019, were $303 million. For a reconciliation of accrued drilling and completion capital expenditures to cash drilling and completion capital expenditures for the three months ended June 30, 2019, see the supplemental table at the end of this press release. In addition to capital invested in drilling and completion costs, the Company invested $29 million for land.

Balance Sheet and Liquidity

As of June 30, 2019, Antero’s debt was $3.6 billion, of which $175 million were borrowings outstanding under the Company’s revolving credit facility. During the quarter, Antero’s 24 banks affirmed the Company’s $4.5 billion borrowing base and total lender commitments under the facility remain unchanged at $2.5 billion. Antero’s net debt to trailing twelve months Adjusted EBITDAX ratio was 2.3x.

President and CFO, Glen Warren, commented, “Antero remains focused on the best investment opportunities for the Company given the current macroeconomic backdrop. Our strong balance sheet provides us with the flexibility to execute our strategy in the coming years, as financial leverage is at an attractive 2.3x level and we have substantial liquidity. We believe our commodity hedges afford us the ability to advance our position as an industry leader through a measured growth program that captures the best revenue opportunities through our advantaged firm transportation portfolio and results in a reduction in overall costs including net marketing expense going forward. Accordingly, we have prioritized our development program with a commitment to our well cost initiatives that remain front and center at Antero.”

Mr. Warren continued, “Antero’s second quarter results highlighted the value of the Company’s transportation to favorably priced markets. Antero’s first full quarter with Mariner East 2 on line allowed the Company to achieve aggregate C3+ NGL realized prices at a $0.04 per gallon premium to Mont Belvieu, as 55% of volumes were exported at Marcus Hook. This is a particularly noteworthy achievement as C3+ products are typically sold at a substantial discount to Mont Belvieu in basin during the quarter. Antero’s position as an anchor shipper differentiates the Company with access to international markets at a premium to Mont Belvieu.”

Commodity Derivative Positions

Antero has hedged 2.0 Tcf of natural gas at a weighted average index price of $2.94 per MMBtu through 2023 with a combination of fixed price swap positions in 2019 through 2023 and collar agreements in 2019. Antero also has oil and NGL fixed price swap positions, including oil positions that totaled 5,000 Bbl/d at a weighted average price of approximately $60 per barrel from July 2019 through December 2020. As of June 30, 2019, the Company’s estimated fair value of commodity derivative instruments was $716 million based on strip pricing.

Antero's estimated natural gas production for the second half of 2019 is fully hedged with a combination of fixed price swap positions and collars. As of June 30, 2019, the Company had fixed price swaps totaling 755,000 MMBtu/d of natural gas for July 2019 through December 2019 fixed at a weighted average price of $3.39 per MMBtu. Collar agreements for July 2019 through December 2019 total 1,575,000 MMBtu/d of natural gas at a weighted average floor and ceiling of $2.50 per MMBtu and $3.41 per MMBtu, respectively. During 2019, Antero also has oil fixed price swap positions on 5,000 Bbl/d at a weighted average price of $61.83 per barrel from July 2019 through December 2019.

Subsequent to June 30, 2019, and not included in the following tables, Antero added an incremental 4,000 Bbl/d of oil fixed price swap positions at a weighted average price of $56.58 per barrel from August 2019 through December 2019. For the period of August 2019 through December 2019, Antero has oil fixed price swap positions totaling 9,000 Bbl/d at a weighted average price of $59.50 per barrel.

Please see Antero’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, for more information on all commodity derivative positions.

The following tables summarize Antero’s natural gas hedge position as of June 30, 2019:

Fixed price natural gas positions from July 1, 2019 through December 31, 2023 were as follows:

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

Fixed price oil positions from July 1, 2019 through December 31, 2020 are as follows:

Conference Call

A conference call is scheduled on Thursday, August 1, 2019 at 9:00 am MT to discuss 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 877-407-9079 (U.S.), or 201-493-6746 (International) and reference “Antero Resources”. A telephone replay of the call will be available until Thursday, August 8, 2019 at 9:00 am MT at 877-660-6853 (U.S.) or 201-612-7415 (International) using the conference ID: 13689238.

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, August 8, 2019 at 9:00 am MT.

Presentation

An updated presentation will be posted to the Company's website before the 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, and is not incorporated by reference into, this press release.

Basis of Financial Presentation

In connection with the closing of the previously announced simplification transaction between Antero Midstream GP LP and Antero Midstream Partners LP (“Antero Midstream Partners”) on March 12, 2019, among other things, Antero Midstream GP LP converted to a Delaware corporation and changed its name to Antero Midstream Corporation (“Antero Midstream”) and Antero Midstream Partners became Antero Midstream’s wholly owned subsidiary. As of June 30, 2019, Antero Resources owned 31% of the shares of common stock of Antero Midstream. Through March 12, 2019, Antero Midstream Partners’ results were consolidated within Antero Resources’ results. Upon closing, Antero Midstream Partners was deconsolidated from Antero Resources and Antero Resources’ interests in Antero Midstream were accounted for under the equity method of accounting within Antero Resources’ results. The GAAP results discussed below include the results of Antero Midstream Partners from January 1, 2019, through March 12, 2019, on a consolidated basis, and from March 13, 2019, to June 30, 2019, the results of Antero Midstream Partners are no longer consolidated. The non-GAAP results described below reflect the applicable results as if the simplification transaction had occurred at the beginning of the applicable period, unless otherwise noted.

Non-GAAP Financial Measures

Revenue Excluding Unrealized Derivative (Gains) Losses

Revenue Excluding Unrealized Derivative (Gains) Losses as set forth in this release represents total revenue adjusted for non-cash (gains) losses on unsettled derivatives. Antero believes that Revenue Excluding Unrealized Derivative (Gains) Losses 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 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 (in thousands):

Adjusted Net Income (Loss)

Adjusted Net Income (Loss) as set forth in this release represents net income, adjusted for certain items. Antero believes that Adjusted Net Income (Loss) and Adjusted Net Income (Loss) 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 (Loss) is not a measure 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 tables reconcile net income (loss) before income taxes to Adjusted Net Income (Loss) (in thousands):

Per Share Amounts

⁽¹⁾ Deferred taxes were approximately 24% for 2018 and 24% for 2019.

Adjusted Net Cash Provided by Operating Activities

Adjusted Net Cash Provided by Operating Activities as presented in this release represents net cash provided by operating activities excluding net cash provided by operating activities from Antero Midstream Partners consolidated through March 12, 2019. Adjusted Net Cash Provided by Operating Activities is often used 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 Net Cash Provided by Operating Activities is also useful because it is often 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.

Management believes that Adjusted Net Cash Provided by Operating Activities is a useful indicator of the company’s ability to internally fund its activities and to service or incur additional debt.

There are significant limitations to using Adjusted Net Cash Provided by Operating Activities as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company’s net income, the lack of comparability of results of operations of different companies and the different methods of calculating Adjusted Net Cash Provided by Operating Activities reported by different companies. Adjusted Net Cash Provided by Operating Activities 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 Net Cash Provided by Operating Activities is not a measure of financial performance under GAAP and should not be considered in isolation or as a substitute for cash flows from operating, investing, or financing activities, as an indicator of cash flows, or as a measure of liquidity. Furthermore, we may calculate such measures differently from similarly titled measures used by other companies.

The following table reconciles net cash provided by operating activities to Adjusted Net Cash Provided by Operating Activities as used in this release (in thousands):

⁽¹⁾ Represents Antero Midstream Partners net cash provided by operating activities that was consolidated in Antero Resources’ financial results in 2018.

Net Debt

Net Debt is calculated as total debt less cash and cash equivalents. Management uses Net Debt to evaluate the Company’s financial position, including its ability to service its debt obligations.

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

⁽¹⁾ Effective March 13, 2019, Antero Midstream Partners is no longer consolidated in Antero’s results

Adjusted EBITDAX

Adjusted EBITDAX as defined by the Company represents income or loss, 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, equity-based compensation, gain or loss on early extinguishment of debt, gain or loss on sale of assets, gain or loss on changes in the fair value of contingent acquisition consideration, contract termination and rig stacking costs, and equity in earnings or loss of Antero Midstream. Adjusted EBITDAX also includes distributions received from limited partner interests in Antero Midstream common units prior to the closing of the simplification transaction on March 12, 2019.

The GAAP financial measure nearest to Adjusted EBITDAX is net income or loss including noncontrolling interest that will be reported in Antero’s condensed consolidated financial statements. While there are limitations associated with the use of Adjusted EBITDAX described below, management believes that this measure is useful to an investor in evaluating the Company’s financial performance because it:

There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effect of certain recurring and non-recurring items that materially affect the Company’s net income, 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 provides no information regarding a company’s capital structure, borrowings, interest costs, capital expenditures, and working capital movement or tax position.

The following table represents a reconciliation of Adjusted EBITDAX to net income (loss), including noncontrolling interest, and net cash provided by operating activities per our consolidated statements of cash flows.

⁽¹⁾ The adjustments for the derivative fair value gains and losses and gains on settled derivatives have the effect of adjusting net income (loss) from operations for changes in the fair value of unsettled derivatives, which are recognized at the end of each accounting period. As a result, derivative gains included in the calculation Adjusted EBITDAX only reflect derivatives that settled during the period. The adjustments do not include proceeds from derivatives monetization.

⁽²⁾ Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019 (date of deconsolidation). Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements in Antero’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2019 for further discussion on equity method investments.

The following table reconciles Antero's net income to Adjusted EBITDAX for the twelve months ended June 30, 2019, as used in this release (in thousands):

Drilling and Completion Capital Expenditures

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 (in thousands):

⁽¹⁾ Represents drilling and completion costs paid to Antero Midstream Partners that were consolidated in Antero Resources’ financial results in 2018.

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 not under 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 expected results, future commodity prices, future production targets, completion of natural gas or natural gas liquids transportation projects, future earnings, Adjusted EBITDAX, Adjusted Net Cash Provided by Operating Activities, 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 and cost savings initiatives, including with respect to potential incremental flowback and produced water services by Antero Midstream, which are subject to approval by the Board of Antero Midstream, and there can be no assurance that such approval will be obtained, future financial position, future technical improvements, future marketing opportunities, expectations regarding the amount and timing of jury awards, the receipt of which are subject to final orders and the resolutions of appeals processes, 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. Except as required by law, Antero expressly disclaims any obligation to and does not intend to publicly update or revise any forward-looking statements.

Antero cautions you that these forward-looking statements are subject to all of the risks and uncertainties incident to the exploration for and development, production, gathering and sale of natural gas, NGLs and oil, most of which are difficult to predict and many of which are beyond the Antero’s control. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures, and the other risks described under the heading "Item 1A. Risk Factors" in Antero’s Annual Report on Form 10-K for the year ended December 31, 2018.

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

ANTERO RESOURCES CORPORATION

Condensed Consolidated Balance Sheets

December 31, 2018 and June 30, 2019

(Unaudited)

(In thousands, except per share amounts)

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Operations and Comprehensive Income (Loss)

Three Months Ended June 30, 2018 and 2019

(Unaudited)
(In thousands, except per share amounts)

ANTERO RESOURCES CORPORATION

Condensed Consolidated Statements of Cash Flows

Six Months Ended June 30, 2018 and 2019

(Unaudited)

(In thousands)

ANTERO RESOURCES CORPORATION

The following tables set forth selected operating data for the three months ended June 30, 2018 and 2019:

* Not meaningful