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Item 2. Management’s Discussion and Analysis

2020-07-29 compared with 2020-04-29 · 396 added, 211 removed, 318 unchanged (66% of the section changed)

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Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin.

As of March 31, 2020, we held approximately 536,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia and Ohio.

As of June 30, 2020, we held approximately 531,000 net acres of rich gas and dry gas properties located in the Appalachian Basin in West Virginia and Ohio.

Our corporate headquarters are in Denver, Colorado.

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As described below and elsewhere in this Quarterly Report on Form 10-Q, effective March 13, 2019, the results of Antero Midstream Partners are no longer consolidated in Antero’s results.

Address, Internet Website and Availability of Public Filings

Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202, and our telephone number is (303) 357-7310.

Our website is located at www.anteroresources.com .

We furnish or file with the SEC our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K.

We make these documents available free of charge at www.anteroresources.com under the “Investors–SEC Filings” section as soon as reasonably practicable after they are furnished or filed with the SEC.

Information on our website is not incorporated into this Quarterly Report on Form 10-Q or any of our other filings with the SEC.

2020 Developments and Highlights

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While OPEC, Russia and other allied producers reached an agreement in April 2020 to reduce production, oil prices have remained low.

The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices in March and April.

As a producer of natural gas, NGLs and oil, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic.

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We have implemented protocols to reduce the risk of an outbreak within our field operations, and these protocols have not reduced production or efficiency in a significant manner.

A substantial portion of our non-field level employees have transitioned temporarily to remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

To date, we have had no confirmed cases of COVID-19 within our employee group at any of our locations.

A substantial portion of our non-

field level employees continue to operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.

Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin.

Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 3% and 4% of our total revenue for the three months ended March 31, 2020 and the year ended December 31, 2019, respectively.

While natural gas prices also declined during the first quarter of 2020, the decline in natural gas prices has been far less significant than the decline in oil prices.

Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 2% and 4% of our total revenue for the six months ended June 30, 2020 and the year ended December 31, 2019, respectively.

While natural gas prices also declined during the first half of 2020, the decline in natural gas prices has been far less significant than the decline in oil prices.

C3+ NGL prices during the second quarter were negatively impacted by weak demand for normal butane (nC4), isobutane (iC4), and pentane (C5), all of which are used for gasoline.

The COVID-19 induced demand destruction on gasoline forced C5 prices below propane prices for much of April to under $0.40 per gallon.

The benchmark C5 price in July has been in the range of $0.60 to $0.70 per gallon.

In addition, we have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of $2.87 per MMBtu for the remainder of 2020.

Our hedges cover a substantial majority of our expected natural gas production in 2020.

We also have fixed priced contracts for the sale of 10,352 barrels per day of propane at a weighted average price of $0.65 per gallon and 26,000 barrels per day of oil at a weighted average price of $55.63 per barrel for the remainder of 2020.

These fixed price contracts resulted in total commodity derivative fair value gains of $566 million, including settled commodity derivative gains of $211 million, during the three months ended March 31, 2020.

We also have fixed priced contracts for the sale of 10,315 barrels per day of propane at a weighted average price of $0.65 per gallon, 24,500 barrels per day of ethane at a weighted average price of $0.20 per gallon and 26,000 barrels per day of oil at a weighted average price of $55.63 per barrel for the remainder of 2020.

These fixed price contracts resulted in total commodity derivative fair value gains of $398 million during the six months ended June 30, 2020, including settled commodity derivative gains of $314 million and $525 million during the three and six months ended June 30, 2020, respectively.

All of our hedges are financial hedges and do not have physical delivery requirements.

As such, any decreases in anticipated production, whether as a result of decreased development activity or shut-ins, will not impact our ability to realize the benefits of the hedges.

As such, any decreases in anticipated production, whether as a result of decreased development activity, shut-ins, or through transactions under our asset sale plan, will not impact our ability to realize the benefits of the hedges.

Our natural gas and NGLs are primarily used in manufacturing, power generation and heating rather than transportation.

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and, as a result, estimates of future gas supply associated with oil production have declined.

Additionally, the restart of economic activity in Asia, coupled with lower refinery liquefied petroleum gas (“LPG”) production in the U.S., Europe, and other markets such as India, has led to strengthening prices for international LPG.

Our supply chain also has not thus far experienced any significant interruptions.

The industry overall is experiencing storage capacity constraints with respect to oil and certain NGL products, and we may become subject to those constraints if we are not able to sell our production, or certain components of our production, or enter into additional storage arrangements.

The lack of a market or available storage for any one NGL product or oil could result in us having to delay or discontinue well completions and commercial production or shut in production for other products as we cannot curtail the production of individual products in a meaningful way without reducing the production of other products.

Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of or for how long any shut-ins may occur.

However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we have the ability to change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products better than if we had only rich gas or dry gas wells.

We have the ability to shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained.

Additionally, the restart of economic activity in Asia and Europe, coupled with lower LPG production from refineries in the U.S., Europe, and Asia during the second quarter, provided support for international LPG prices relative to oil.

Further, reductions in OPEC+ and North American oil production and the associated NGL volumes are expected to have a supportive effect on propane and butane prices through the remainder of 2020 and into 2021.

During the second quarter of 2020, we shipped 54% of our total C3+ NGL net production on Mariner East 2 for export and realized a $0.04 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA.

We sold the remaining 46% of C3+ NGL net production at a $0.12 per gallon discount to Mont Belvieu pricing at Hopedale, OH.

We expect to sell at least 50% of our C3+ NGL full-year production in 2020 at Marcus Hook for export at a premium to Mont Belvieu.

Condensate differentials to WTI expanded to nearly $20/Bbl during the second quarter, but have begun to return to pre-pandemic levels as gasoline demand improved through the summer months.

Pre-hedge oil realizations were negatively impacted during the quarter as Antero sold volumes at a material discount to WTI in order to keep from shutting in production volumes.

This period of weak condensate demand driven by the pandemic coincided with an active well completion quarter for Antero that brought on large condensate volumes.

The negative impact from wider oil differentials was more than offset by the benefit of maintaining full natural gas and NGL volumes.

Antero expects its full year 2020 realized oil price differential to be $10.00/Bbl to $12.00/Bbl, as the differential normalizes during the second half of 2020.

Our supply chain also has not experienced any significant interruptions.

The industry continues to experience storage capacity constraints for oil and certain NGL products, and we may become subject to those constraints if we are not able to sell our production or certain components thereof, or enter into additional storage arrangements.

The lack of a market or available storage for any one NGL product or oil could result in our having to delay or discontinue well completions and commercial production or shut in production for other products because we cannot curtail the production of individual products in a meaningful way without reducing production of other products.

Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of shut-ins or for how long they may last.

However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we can change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products.

For example, we can shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained.

Also, prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes.

Since the outbreak of the pandemic, we have expanded our customer base and doubled our condensate storage capacity within the basin.

In addition, as discussed below in “—2020 Capital Budget and Capital Spending,” we have reduced our drilling and completion capital budget for 2020 by approximately 34% since the beginning of the year.

We will continue to monitor our five-year drilling plan throughout the year and will make further revisions if deemed necessary.

Reductions in the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells will be brought online.

During the three months ended March 31, 2020 and during the two previous quarters, we have recognized various impairment charges related to the decline in commodity prices and the value of our investment in Antero Midstream Corporation.

At this time, we do not anticipate any further impairment charges in our equity method investment in Antero Midstream Corporation, as the value of our equity method investment has increased since March 31, 2020.

Additional impairment charges related to our assets may occur if we experience disruptions in production, additional or sustained declines in the forward commodity price strip from March 31, 2020, unresolved storage capacity restraints or other consequences of the COVID-19 pandemic.

During the second quarter of 2020, condensate differentials to WTI were notably wider as a result of COVID-19 demand destruction at both the Appalachia regional level and national level.

To protect against production curtailments and shut-ins due to insufficient storage capacity, Antero expanded its customer base and its condensate storage capacity within the basin.

In addition, Antero entered into transactions that required buyers to transport product to more distant markets and storage, which coincided with substantially weakened crack spreads for refined products.

To date, Antero has not shut in or curtailed any production from its assets as a result of COVID-19 demand issues and does not expect to shut in any volumes during 2020.

In addition, as discussed below in “—2020 Capital Budget and Capital Spending,” in April 2020, we announced a 34% reduction in our drilling and completion capital budget for 2020.

During the second quarter, our ongoing emphasis on completion efficiencies resulted in material improvements and these efficiency gains led to average well costs below $700 per foot during the months of May and June, despite only partial vendor cost savings being realized.

We expect further well cost savings during the second half of 2020 as we fully realize vendor cost savings.

We continue to monitor our five-year drilling plan and will make further revisions as appropriate.

Reducing the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells are brought online.

During the first quarter of 2020 and the two preceding quarters, we recognized various impairment charges related to the decline in commodity prices and the value of our investment in Antero Midstream Corporation.

Additional impairment charges related to our assets may occur if we experience disruptions in production, additional or sustained declines in the forward commodity price strip from June 30, 2020, unresolved storage capacity restraints or other consequences caused by the COVID-19 pandemic.

In April 2020, the borrowing base supporting our Credit Facility was subject to its annual redetermination.

The bank prices used in our redetermination were materially lower than the bank prices used in our April 2019 redetermination and were lower than strip prices as of April 27, 2020.

As a result, the lenders under our Credit Facility reduced our borrowing base from the previous level.

The bank prices used in the April 2020 redetermination were materially lower than those used in the April 2019 redetermination and, as a result, the lenders under our Credit Facility reduced our borrowing base to $2.85 billion.

Lender commitments remained unchanged at $2.64 billion, providing us with a consistent amount of available borrowings.

Our borrowing base is now subject to a semi-annual redetermination and, therefore, our available borrowings and liquidity could be impacted by an additional redetermination in 2020.

Our borrowing base is now subject to a semi-annual redetermination and, therefore, our available borrowings and liquidity could be impacted by an additional redetermination in October 2020.

In addition, our borrowing capacity is directly impacted by the amount of financial assurance we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers.

Our ability to limit the financial assurance we are required to provide, while also protecting ourselves from the counterparty risk of our financial hedges, may be impacted by the ongoing effects of the COVID-19 pandemic.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control, which can adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets.

In addition, our plan to strengthen our balance sheet through significant absolute debt reduction depends upon our ability to identify and successfully execute our previously announced asset monetization program.

Instability in the financial markets and uncertainty in the general business environment resulting from the COVID-19 pandemic may impact our ability to execute our asset monetization program on the terms and the timeframe previously anticipated.

To the extent we are not able to execute our asset monetization plan or access the capital markets, we may have to delay or reduce our planned capital expenditures in order to address our upcoming debt obligations.

The amount of financial assurance we must provide has not increased during the COVID-19 pandemic and, thus far, we have not experienced any losses due to counterparty risk.

However, our ability to limit any additional financial assurance we are required to provide, as well as to protect ourselves from the counterparty risk of our financial hedges, may be limited in the future.

Since the onset of the COVID-19 pandemic, we have timely serviced our debt and other obligations, and we have not implemented or requested any concessions or materially modified the terms of any agreements.

The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control and may adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets.

In addition, our plan to strengthen our balance sheet through significant absolute debt reduction depends upon our ability to identify and continue to successfully execute our previously announced $750 million to $1.0 billion asset sale program.

Instability in the financial markets and uncertainty in the general business environment resulting from the COVID-19 pandemic may impact our ability to further execute our asset sale program on the terms and the timeframe previously anticipated.

To the extent we are not able to execute additional components of our asset sale plan or access the capital markets, we may have to delay or reduce our planned capital expenditures in future years.

Conveyance of Overriding Royalty Interest

On June 15, 2020, we announced the consummation of a transaction with an affiliate of Sixth Street Partners, LLC (“Sixth Street”) relating to certain overriding royalty interests across our existing asset base (the “ORRIs”).

In connection with the transaction, we contributed the ORRIs to a newly formed subsidiary, Martica Holdings LLC (“Martica”), and Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production targets attributable to the ORRIs are achieved.

All cash contributed by Sixth Street was distributed to us.

The ORRIs include an overriding royalty interest of 1.25% of our working interest in all of its proved developed operated properties in West Virginia and Ohio, subject to certain excluded wells (the “Initial PDP Override”), and an overriding royalty interest of 3.75% of our working interest in all of its undeveloped properties in West Virginia and Ohio (the “Development Override”).

Wells turned to sales after April 1, 2020 and prior to the later of (a) the date on which we turn to sales 2.2 million lateral feet (net to our interest) of horizontal wells burdened by the Development Override and (b) the earlier of (i) April 1, 2023 and (ii) the date on which we turn to sales 3.82 million lateral feet (net to our interest) of horizontal wells are subject to the Development Override.

The ORRIs also include an additional overriding royalty interest of 2.00% of our working interest in the properties underlying the Initial PDP Override (the “Incremental Override”).

The Incremental Override (or a portion thereof, as applicable) may be re-conveyed to us (at our election) if certain production targets attributable to the ORRIs are achieved through March 31, 2023.

Any portion of the Incremental Override that may not be re-conveyed to us based on us achieving such production volumes through March 31, 2023 will remain with Martica.

Prior to Sixth Street achieving an internal rate of return of 13% and 1.5x cash-on-cash return (the “Hurdle”), Sixth Street will receive all distributions in respect of the Initial PDP Override and the Development Override, and we will receive all distributions in respect of the Incremental Override, unless certain production targets are not achieved, in which case Sixth Street will receive some or all of the distributions in respect of the Incremental Override.

Following Sixth Street achieving the Hurdle, we will receive 85% of the distributions in respect of the ORRIs to which Sixth Street was entitled immediately prior to the Hurdle being achieved.

Production and Financial Results

For the three months ended March 31, 2020, our net production totaled 306 Bcfe, or 3,366 MMcfe per day, a 9% increase in daily combined production compared to 279 Bcfe, or 3,099 MMcfe per day, for the three months ended March 31, 2019.

Three months ended June 30, 2020 .

For the three months ended June 30, 2020 our net production totaled 320 Bcfe, or 3,521 MMcfe per day, a 9% increase in daily gas equivalent production compared to 294 Bcfe, or 3,226 MMcfe per day, for the three months ended June 30, 2019.

Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity.

Our average price received for production, before the effects of gains on settled commodity derivatives for the three months ended March 31, 2020 was $2.30 per Mcfe compared to $3.65 per Mcfe for the three months ended March 31, 2019.

Our average realized price after the effects of gains on settled commodity derivatives was $2.99 per Mcfe for the three months ended March 31, 2020 compared to $4.00 per Mcfe for the three months ended March 31, 2019.

For the three months ended March 31, 2020, we generated consolidated cash flows from operations of $201 million, net loss attributable to Antero of $339 million, and Adjusted EBITDAX of $244 million.

This compares to consolidated cash flows from operations of $539 million, consolidated net income attributable to Antero Resources of $979 million, and Adjusted EBITDAX of $443 million for the three months ended March 31, 2019.

Our average price received for production, before the effects of gains on settled commodity derivatives for the three months ended June 30, 2020 was $1.83 per Mcfe compared to $3.09 per Mcfe for the three months ended June 30, 2019.

Our average realized price after the effects of gains on settled commodity derivatives was $2.81 per Mcfe for the three months ended June 30, 2020 compared to $3.24 per Mcfe for the three months ended June 30, 2019, a decrease of 13%.

We generated consolidated cash flows from operations of $116 million, net loss attributable to Antero of $463 million, and Adjusted EBITDAX of $186 million for the three months ended June 30, 2020.

This compares to consolidated cash flows from operations of $218 million, consolidated net income attributable to Antero Resources of $42 million, and Adjusted EBITDAX of $252 million for the three months ended June 30, 2019.

See “—Non-GAAP Financial Measures” for a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net cash provided by operating activities and net income (loss).

Cash flows from operations decreased by $338 million for the three months ended March 31, 2020 compared to the prior year period primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression and transportation costs.

Consolidated net loss attributable to Antero Resources of $339 million for the three months ended March 31, 2020 decreased from consolidated net income attributable to Antero Resources of $979 million for the three months ended March 31, 2019 primarily due to the gain on deconsolidation of Antero Midstream Partners in 2019 partially offset by commodity derivative realized and fair value gains in 2020.

The three months ended March 31, 2020 was also impacted by an Impairment of equity investment due to the decline in Antero Midstream Corporation’s fair value and Antero Midstream Corporation’s earnings changing from earnings to a loss.

Adjusted EBITDAX decreased from $443 million for the three months ended March 31, 2019 to $244 million for the three months ended March 31, 2020, a decrease of 45%, primarily due to the decrease in commodity prices of 37% per Mcfe before and

26% per Mcfe after the effects of settled commodity derivatives, and increased gathering, compression and transportation costs discussed above.

Cash flows from operations decreased by $102 million for the three months ended June 30, 2020 compared to the prior year period primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives, increases in processing and transportation costs, and changes in current assets and liabilities.

Consolidated net loss attributable to Antero Resources of $463 million for the three months ended June 30, 2020 decreased from consolidated net income attributable to Antero Resources of $42 million for the three months ended June 30, 2019 primarily due to decreases in commodity derivative fair value gains (losses) and commodity prices and expense increases in processing and transportation costs.

Adjusted EBITDAX decreased from $252 million for the three months ended June 30, 2019 to $186 million for the three months ended June 30, 2020, a decrease of 26%, primarily due to the decrease in commodity prices of 41% per Mcfe before and 13% per Mcfe after the effects of settled commodity derivatives, and increased compression and transportation costs.

Six months ended June 30, 2020.

For the six months ended June 30, 2020 our net production totaled 627 Bcfe, or 3,444 MMcfe per day, a 10% increase in daily combined production compared to 572 Bcfe, or 3,163 MMcfe per day, for the six months ended June 30, 2019.

Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity.

Our average price received for production, before the effects of gains on settled commodity derivatives for the

six months ended June 30, 2020 was $2.06 per Mcfe compared to $3.36 per Mcfe for the six months ended June 30, 2019.

Our average realized price after the effects of gains on settled commodity derivatives was $2.90 per Mcfe for the six months ended June 30, 2020 compared to $3.61 per Mcfe for the six months ended June 30, 2019, a decrease of 20%.

We generated consolidated cash flows from operations of $317 million, net loss attributable to Antero of $802 million, and Adjusted EBITDAX of $430 million for the six months ended June 30, 2020.

This compares to consolidated cash flows from operations of $757 million, consolidated net income attributable to Antero Resources of $1.0 billion, and Adjusted EBITDAX of $694 million for the six months ended June 30, 2019.

Cash flows from operations decreased by $440 million for the six months ended June 30, 2020 compared to the prior year period primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives, increases in gathering, compression, processing and transportation costs, and changes in current assets and liabilities.

Consolidated net loss attributable to Antero Resources of $802 million for the six months ended June 30, 2020 decreased from consolidated net income attributable to Antero Resources of $1.0 billion for the six months ended June 30, 2019 primarily due to the gain on deconsolidation of Antero Midstream Partners in 2019 partially offset by commodity derivative realized and fair value gains in 2020.

The six months ended June 30, 2020 was also impacted by an impairment of equity investment due to the decline in Antero Midstream Corporation’s fair value, Antero Midstream Corporation’s reporting a loss for such period, and the decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression, processing and transportation costs.

Adjusted EBITDAX decreased from $694 million for the six months ended June 30, 2019 to $430 million for the six months ended June 30, 2020, a decrease of 38%, primarily due to the decrease in commodity prices of 39% per Mcfe before and 20% per Mcfe after the effects of settled commodity derivatives, and increased gathering, compression, processing and transportation costs.

A portion of the cost increases are the result of the deconsolidation of Antero Midstream Partners as costs that were previously eliminated in consolidation are now expensed.

2020 Capital Budget and Capital Spending

Our drilling and completion capital budget for 2020 has been reduced to $750 million from $1.15 billion.

Reductions in the 2020 capital budget may impact production in 2021 and forward to the extent fewer wells will be brought online.

On April 20, 2020, we announced our revised 2020 drilling and completion capital budget of $750 million.

We do not include acquisitions in our capital budget.

We periodically review our capital expenditures and adjust our budget and its allocation based on commodity prices, takeaway constraints, operating cash flow and liquidity.

For the three months ended March 31, 2020, our capital expenditures were approximately $312 million, including drilling and completion costs of $300 million, leasehold acquisitions of $10 million, and other capital expenditures of $2 million.

Our capital expenditures for the three months ended March 31, 2019 of approximately $472 million included drilling and completion costs of $369 million, leasehold acquisitions of $27 million, and other capital expenditures of $3 million.

In addition, consolidated capital expenditures for the three months ended March 31, 2019, included gathering and compression expenditures of $48 million and water handling and treatment expenditures of $24 million.

Three months ended June 30, 2020.

For the three months ended June 30, 2020, our capital expenditures were approximately $264 million, including drilling and completion costs of $252 million, leasehold acquisitions of $11 million, and other capital expenditures of less than $1 million.

Our capital expenditures for the three months ended June 30, 2019 of approximately $342 million included drilling and completion costs of $311 million, leasehold acquisitions of $29 million, and other capital expenditures of $2 million.

This 23% reduction in capital costs was a result of our well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, as well as operational efficiency gains.

Six months ended June 30, 2020.

For the six months ended June 30, 2020, our capital expenditures were approximately $575 million, including drilling and completion costs of $552 million, leasehold acquisitions of $22 million, and other capital expenditures of $1 million.

Our exploration and production capital expenditures for the six months ended June 30, 2019 of approximately $742 million included drilling and completion costs of $680 million, leasehold acquisitions of $57 million, and other capital expenditures of $5 million.

This 22% reduction in capital costs was a result of our well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, as well as operational efficiency gains.

In addition, consolidated capital expenditures for the six months ended June 30, 2019 included gathering and compression expenditures of $48 million and water handling and treatment expenditures of $24 million.

Antero Midstream Partners also invested $25 million in a joint venture.

These expenditures relate to the period prior to deconsolidation of Antero Midstream Partners on March 12, 2019.

For the three months ended March 31, 2020, our exploration and production capital expenditures decreased by $87 million from the three month period ended March 31, 2019.

Hedge Position

At March 31, 2020, we had fixed price natural gas swap contracts on NYMEX Henry Hub for the period from April 2020 through December 2023 covering 1.8 Tcf of our projected natural gas production at a weighted average index price of $2.77 per MMBtu, including contracts for the remainder of 2020 of approximately 613 Bcf of natural gas at a weighted average index price of $2.87 per MMBtu.

At March 31, 2020, we also had basis swaps for the period from April 2020 through December 2024 for approximately 89.5 Bcf of our projected natural gas production with pricing differentials ranging from $0.35 to $0.53 per MMBtu that hedge the difference between TCO and the NYMEX Henry Hub.

In addition, we have a call option agreement, which entitles the holder, if exercised, to enter into a fixed price swap agreement for approximately 428 MMBtu per day at a price of $2.77 per MMBtu in 2024.

Hedge Position (Excluding Martica)

At June 30, 2020, we had fixed price natural gas swap contracts on NYMEX Henry Hub for the period from July 2020 through December 2023 covering 1.8 Tcf of our projected natural gas production at a weighted average index price of $2.71 per MMBtu, including contracts for the remainder of 2020 of approximately 410 Bcf of natural gas at a weighted average index price of $2.87 per MMBtu.

At June 30, 2020, we also had basis swaps for the period from July 2020 through December 2024 for approximately 84.1 Bcf of our projected natural gas production with pricing differentials ranging from $0.35 to $0.53 per MMBtu that hedge the difference between TCO and the NYMEX Henry Hub.

In addition, we have a call option agreement, which entitles the

holder, if exercised, to enter into a fixed price swap agreement for approximately 428 MMBtu per day at a price of $2.77 per MMBtu in 2024.

At June 30, 2020, we had fixed price oil swap contracts on NYMEX-WTI for the period from July 2020 through December 2021 covering approximately 5.9 million barrels of our projected oil production at a weighted average index price of $55.54 per barrel.

Additionally, we had fixed price propane swap contracts on ARA Propane for the period from July 2020 through December 2020 covering approximately 1.9 million barrels of our projected propane production at a weighted average index price of $0.65 per gallon.

We also had fixed price ethane swap contracts on OPIS Ethane Mt Belv for the period from July 2020 through March 2021 covering approximately 6.2 million barrels of our projected ethane production at a weighted average index price of $0.20 per gallon.

As a result of the ORRI transaction, we monetized 100,000 MMBtu/d of 2021 natural gas hedges in July 2020 for proceeds of approximately $29 million.

We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans.

As of March 31, 2020, the estimated fair value of our commodity derivative contracts was approximately $1.1 billion.

Credit Facility

Our borrowing base was reduced to $2.85 billion and lender commitments remained at $2.64 billion at the redetermination in April 2020.

The borrowing base under our Credit Facility is redetermined semi-annually and is based on the estimated future cash flows from our proved oil and gas reserves, the value of our ownership interest in Antero Midstream Corporation and our commodity derivative positions.

The next redetermination is scheduled to occur in October 2020.

The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of our senior notes then outstanding.

At March 31, 2020, we had an outstanding balance under the Credit Facility of $882 million, with a weighted average interest rate of 2.57%, and letters of credit of $730 million.

See “—Debt Agreements and Contractual Obligations—Senior Secured Revolving Credit Facility” for a description of the Credit Facility.

Share Repurchase Program

During the three months ended March 31, 2020, pursuant to our share repurchase program, we repurchased 27,193,237 shares of our common stock (approximately 9% of total shares outstanding at commencement of the program) at an average cost of $1.57 for a total cost of approximately $43 million.

During the term of this program, we repurchased an aggregate of approximately $215 million of our shares of common stock.

At March 31, 2020, Antero had 268,926,481 shares outstanding.

As of June 30, 2020, the estimated fair value of our commodity derivative contracts was approximately $619 million.

Results of Operations

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however, our disclosures include the segments of our unconsolidated affiliates due to their significance to our operations.

See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on our reportable segments.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 18—Segment Information to the unaudited condensed consolidated financial statements for disclosures on our reportable segments.

Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity.

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2020

The operating results of our reportable segments were as follows for the three months ended March 31, 2019 and 2020 (in thousands):

Three Months Ended June 30, 2019 Compared to Three Months Ended June 30, 2020

The operating results of our reportable segments were as follows for the three months ended June 30, 2019 and 2020 (in thousands):

Equity Method

3 unchanged sentences

unconsolidated

Three months ended March 31, 2019:

Three months ended June 30, 2019:

Revenue and other:

1 unchanged sentence

Natural gas liquids sales

Commodity derivative fair value losses

Gathering, compression, and water handling and treatment

Commodity derivative fair value gains

Gathering, compression, water handling and treatment

Operating expenses:

5 unchanged sentences

Impairment of midstream assets

Accretion of asset retirement obligations

Depletion, depreciation, and amortization

Loss on sale of assets

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

9 unchanged sentences

unconsolidated

Three months ended March 31, 2020:

Three months ended June 30, 2020:

Revenue and other:

1 unchanged sentence

Natural gas liquids sales

Commodity derivative fair value losses

Gathering, compression, water handling and treatment

Operating expenses:

Lease operating

Gathering and compression

Transportation

Production and ad valorem taxes

Impairment of oil and gas properties

Depletion, depreciation, and amortization

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

Equity-based compensation

Contract termination and rig stacking and other expenses

Operating income (loss)

Equity in earnings of unconsolidated affiliates

Exploration and Production Segment Results for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2020

The following table sets forth selected operating data of the exploration and production segment for the three months ended June 30, 2019 compared to the three months ended June 30, 2020:

Three months ended June 30,

Production data:

Natural gas (Bcf)

C2 Ethane (MBbl)

C3+ NGLs (MBbl)

Combined (Bcfe)

Daily combined production (MMcfe/d)

Average prices before effects of derivative settlements (1) :

Natural gas (per Mcf)

C2 Ethane (per Bbl)

C3+ NGLs (per Bbl)

Oil (per Bbl)

Weighted Average Combined (per Mcfe)

Average realized prices after effects of derivative settlements (1) :

Natural gas (per Mcf)

C2 Ethane (per Bbl)

C3+ NGLs (per Bbl)

Oil (per Bbl)

Weighted Average Combined (per Mcfe)

Average costs (per Mcfe):

Lease operating

Gathering and compression

Transportation

Production taxes

Marketing, net

Depletion, depreciation, amortization and accretion

General and administrative (excluding equity-based compensation)

(1) Average sales prices shown in the table reflect both the before and after effects of our settled commodity derivatives.

Our calculation of such after effects includes gains on settlements of commodity derivatives, which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.

Oil and NGLs production was converted at 6 Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts.

This ratio is an estimate of the equivalent energy content of the products and does not necessarily reflect their relative economic value.

Natural gas sales .

Revenues from production of natural gas decreased from $553 million for the three months ended June 30, 2019 to $367 million for the three months ended June 30, 2020, a decrease of $186 million, or 34% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Increased natural gas production volumes accounted for an approximate $18 million increase in year-over-year natural gas revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $204 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of NGLs decreased from $304 million for the three months ended June 30, 2019 to $212 million for the three months ended June 30, 2020, a decrease of $92 million, or 30% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Increased NGLs production volumes accounted for an approximate $75 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $167 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of oil decreased from $49 million for the three months ended June 30, 2019 to $8 million for the three months ended June 30, 2020, a decrease of $41 million, or 83% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Increased oil production volumes accounted for an approximate $3 million increase in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $44 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (losses).

To achieve more predictable cash flows, and to reduce our exposure to price fluctuations, we enter into fixed for variable price swap contracts, basis swap contracts and collar contracts when management believes that favorable future sales prices for our production can be secured.

Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment.

Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations.

The commodity derivative fair value gains (losses) included $45 million and $314 million of gains on cash settled derivatives for the three months ended June 30, 2019 and 2020, respectively.

For the three months ended June 30, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $328 million and losses of $168 million, respectively.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement.

Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement.

We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.

Other income .

Other income decreased from $2 million for the three months ended June 30, 2019 to $1 million for the three months ended June 30, 2020.

Lease operating expense .

Lease operating expense decreased from $41 million for the three months ended June 30, 2019 to $25 million for the three months ended June 30, 2020, a decrease of $16 million, or 39%.

On a per unit basis, lease operating expenses decreased from $0.14 for the three months ended June 30, 2019 to $0.08 for the three months ended June 30, 2020.

This decrease is primarily due to decreased water handling costs resulting from improved operating efficiencies including the reuse of produced and flowback water in completion operations.

Gathering, compression, processing, and transportation expense.

Gathering, compression, processing, and transportation expense increased from $567 million for the three months ended June 30, 2019 to $632 million for the three months ended June 30, 2020.

This is primarily a result of the 9% increase in production.

Gathering and compression costs decreased from $0.72 per Mcfe to $0.63 per Mcfe primarily as a result of decreased costs associated with fuel as a result of a decrease in natural gas prices and a $12 million incentive fee rebate from Antero Midstream Corporation.

Processing costs increased from $0.66 to $0.76 per Mcfe as a result of increased NGL production in our production mix.

Processing costs remained relatively unchanged per NGL barrel.

Our transportation costs increased from $0.56 per Mcfe to $0.58 per Mcfe due to increased rates on the Rockies Express pipeline.

Production and ad valorem tax expense.

Production and ad valorem taxes decreased from $31 million for the three months ended June 30, 2019 to $20 million for the three months ended June 30, 2020, a decrease of $11 million, or 35%.

This decrease is primarily as a result of decreases in commodity prices.

Production and ad valorem taxes as a percentage of natural gas revenues decreased slightly from 6% in the three months ended June 30, 2019, to 5% for the three months ended June 30, 2020.

Impairment of oil and gas properties .

Impairment of oil and gas properties decreased from $131 million for the three months ended June 30, 2019 to $37 million for the three months ended June 30, 2020, a decrease of $94 million, or 71%.

We recognized impairments primarily related to expiring leases and the design and initial costs related to pads we no longer plan to place into service.

We charge impairment expense for expiring leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, and future plans to develop the acreage.

Depletion, depreciation, and amortization expense (“DD&A”) .

DD&A expense decreased from $242 million for the three months ended June 30, 2019 to $214 million for the three months ended June 30, 2020, a decrease of $28 million, or 12%.

DD&A per Mcfe decreased from $0.83 per Mcfe during the three months ended June 30, 2019 to $0.67 per Mcfe during the three months ended June 30, 2020, as our depletable reserve volumes at June 30, 2020 increased slightly due to increased production and our depletable cost base decreased from June 30, 2019 due to an impairment in the value of our Utica properties of $881 million on September 30, 2019.

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) was $36 million for the three months ended June 30, 2019 and $30 million for the three months ended June 30, 2020, a decrease of $6 million, or 15%.

This decrease was primarily due to decreases in employee related expenses in the three months ended June 30, 2020 as a result of ongoing cost savings initiatives related to lower headcount in 2020.

We had 590 employees as of June 30, 2019 and 524 employees as of June 30, 2020.

On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 25%, from $0.12 per Mcfe during the three months ended June 30, 2019 to $0.09 per Mcfe during the three months ended June 30, 2020 as the expense decreased while production increased.

Equity-based compensation expense .

Noncash equity-based compensation expense remained relatively flat at $7 million for the three months ended June 30, 2019 and $8 million for the three months ended June 30, 2020.

See Note 10—Equity Based Compensation to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on equity-based compensation awards.

Contract termination and rig stacking.

We incurred contract termination and rig stacking costs of $6 million during the three months ended June 30, 2019 compared to $11 million for the three months ended June 30, 2020.

Contract termination and rig stacking costs represent fees incurred upon the delay or cancellation of drilling and completion contracts with third-party contractors in order to align our drilling and completion activity level with our capital budget.

Discussion of the Marketing Segment for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2020

We have entered into long-term firm transportation agreements for our current and expected future production to secure guaranteed capacity to favorable markets.

Where feasible, we purchase and sell third-party natural gas and NGLs to utilize our excess firm transportation capacity, or release capacity to third parties to conduct these activities on our behalf, to reduce our net costs related to the unused capacity under these transportation agreements.

Operating losses on our marketing activities, or our net marketing expense, decreased from $74 million, or $0.25 per Mcfe, for the three months ended June 30, 2019 to $49 million, or $0.15 per Mcfe, for the three months ended June 30, 2020.

The decrease was driven by higher volumes and the mitigation of some of our excess firm transportation expense.

Marketing revenues remained relatively flat at $63 million for the three months ended June 30, 2019 and $64 million for the three months ended June 30, 2020.

Marketing expenses decreased from $138 million for the three months ended June 30, 2019 to $113 million for the three months ended June 30, 2020, a decrease of $24 million, or 18%.

Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs.

Firm transportation costs included in the expenses above were $66 million and $41 million for the three months ended June 30, 2019 and 2020, respectively.

Discussion of Antero Midstream Corporation Segment for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2020

Antero Midstream Corporation.

Revenue from the Antero Midstream Corporation segment decreased from $256 million for the three months ended June 30, 2019 to $220 million for the three months ended June 30, 2020, a decrease of $36 million, or 14%, primarily due to a reduction in water handling revenues.

Total operating expenses related to the segment decreased from $138 million for the three months ended June 30, 2019 to $85 million for the three months ended June 30, 2020.

The decrease was primarily due to a reduction in operating expenses in the water handling segment including direct operating expense and depreciation.

Discussion of Items Not Allocated to Segments for the Three Months Ended June 30, 2019 Compared to the Three Months Ended June 30, 2020

Interest expense.

Our interest expense decreased from $54 million in the three months ended June 30, 2019 to $52 million in the three months ended June 30, 2020, a decrease of $2 million, or 4%.

This decrease was due to a decrease in total indebtedness resulting from repurchases of our unsecured senior notes at prices below their stated value.

Interest expense included approximately $2.6 million and $2.3 million of non-cash amortization of deferred financing costs for the three months ended June 30, 2019 and 2020, respectively.

Transaction expense.

We incurred transaction expense of $6 million in the three months ended June 30, 2020 and did not incur comparable costs in the three months ended June 30, 2019.

These expenses included legal and transaction fees associated with the sale of our overriding royalty interest and the creation of Martica.

See Note 4—Conveyance of Overriding Royalty Interest to the

unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on the transaction.

Income tax expense/benefit .

Income tax expense decreased from a deferred tax expense of $17 million, with an effective tax rate of 29%, for the three months ended June 30, 2019 to a deferred tax benefit of $142 million, with an effective tax rate of 23%, for the three months ended June 30, 2020.

The change was primarily a result of the decrease in book net income due to the reduction in revenue resulting from commodity price decreases.

Six Months Ended June 30, 2019 Compared to Six Months Ended June 30, 2020

The operating results of our reportable segments were as follows for the six months ended June 30, 2019 and 2020 (in thousands):

Equity Method

Elimination of

Investment in

transactions and

unconsolidated

Six months ended June 30, 2019:

Revenue and other:

Natural gas sales

Natural gas liquids sales

Commodity derivative fair value gains

8 unchanged sentences

Depletion, depreciation, and amortization

Loss on sale of assets

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

Equity-compensation

Equity-based compensation

Change in fair value of contingent acquisition consideration

Contract termination and rig stacking

Operating income (loss)

Equity in loss of unconsolidated affiliates

Exploration and Production Segment Results for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2020

The following table sets forth selected operating data of the exploration and production segment for the three months ended March 31, 2019 compared to the three months ended March 31, 2020:

Three months ended March 31,

Equity in earnings of unconsolidated affiliates

Equity Method

Elimination of

Investment in

transactions and

unconsolidated

Six months ended June 30, 2020:

Revenue and other:

Natural gas sales

Natural gas liquids sales

Commodity derivative fair value gains

Gathering, compression, water handling and treatment

Operating expenses:

Lease operating

Gathering and compression

Transportation

Production and ad valorem taxes

Impairment of oil and gas properties

Impairment of midstream assets

Depletion, depreciation, and amortization

Accretion of asset retirement obligations

General and administrative (excluding equity-based compensation)

Equity-based compensation

Contract termination and rig stacking and other expenses

Operating loss

Equity in earnings (loss) of unconsolidated affiliates

Exploration and Production Segment Results for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2020

The following table sets forth selected operating data of the exploration and production segment for the six months ended June 30, 2019 compared to the six months ended June 30, 2020:

Six months ended June 30,

Production data:

21 unchanged sentences

Production and ad valorem taxes

Marketing expense, net

Depletion, depreciation, amortization, and accretion

5 unchanged sentences

Natural gas sales .

Revenues from production of natural gas decreased from $657 million for the three months ended March 31, 2019 to $411 million for the three months ended March 31, 2020, a decrease of $246 million, or 37% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Revenues from production of natural gas decreased from $1.2 billion for the six months ended June 30, 2019 to $778 million for the six months ended June 30, 2020, a decrease of $432 million, or 36% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Increased natural gas production volumes accounted for an approximate $47 million increase in year-over-year natural gas revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $479 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of NGLs decreased from $314 million for the three months ended March 31, 2019 to $258 million for the three months ended March 31, 2020, a decrease of $56 million, or 18% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Increased NGLs production volumes accounted for an approximate $76 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $132 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of oil decreased from $48 million for the three months ended March 31, 2019 to $36 million for the three months ended March 31, 2020, a decrease of $12 million, or 26% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Revenues from production of NGLs decreased from $618 million for the six months ended June 30, 2019 to $470 million for the six months ended June 30, 2020, a decrease of $148 million, or 24% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Increased NGLs production volumes accounted for an approximate $150 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average

price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $298 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Revenues from production of oil decreased from $97 million for the six months ended June 30, 2019 to $44 million for the six months ended June 30, 2020, a decrease of $53 million, or 55% (calculated as the change in year-over-year volumes times the change in year-to-year average price).

Decreased oil production volumes accounted for an approximate $1 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate $52 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).

Commodity derivative fair value gains (lo sses) .

Commodity derivative fair value gains.

1 unchanged sentence

Consequently, all mark-to-market gains or losses, as well as cash receipts or payments on settled derivative instruments, are recognized in our statements of operations.

For the three months ended March 31, 2019 and 2020, our commodity hedges resulted in derivative fair value losses of $77 million and gains of $566 million, respectively.

The commodity derivative fair value gains (losses) included $97 million and $211 million of gains on cash settled derivatives for the three months ended March 31, 2019 and March 31, 2020, respectively.

The commodity derivative fair value gains included $143 million and $525 million of gains on cash settled derivatives for the six months ended June 30, 2019 and 2020, respectively.

For the six months ended June 30, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $251 million and $398 million, respectively.

Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement.

2 unchanged sentences

Other income .

Other income decreased from $2 million for the three months ended March 31, 2019 to $1 million for the three months ended March 31, 2020.

Other income remained relatively flat at $2 million for the six months ended June 30, 2019 and 2020.

Lease operating expense .

Lease operating expense decreased from $43 million for the three months ended March 31, 2019 to $26 million for the three months ended March 31, 2020, a decrease of $17 million, or 40%.

On a per unit basis, lease operating expenses decreased from $0.15 for the three months ended March 31, 2019 to $0.08 for the three months ended March 31, 2020.

This decrease is primarily due to decreased water handling costs resulting from improved operating efficiencies and cost reductions.

Lease operating expense decreased from $84 million for the six months ended June 30, 2019 to $50 million for the six months ended June 30, 2020, a decrease of $34 million, or 40%.

On a per unit basis, lease operating expenses decreased from $0.15 for the six months ended June 30, 2019 to $0.08 for the six months ended June 30, 2020.

This decrease is primarily due to decreased water handling costs resulting from improved operating efficiencies including the reuse of produced and flowback water in completion operations.

Gathering, compression, processing, and transportation expense.

Gathering, compression, processing, and transportation expense increased from $535 million for the three months ended March 31, 2019 to $589 million for the three months ended March 31, 2020.

Gathering, compression, processing, and transportation expense increased from $1.1 billion for the six months ended June 30, 2019 to $1.2 billion for the six months ended June 30, 2020.

This is primarily a result of the 9% increase in production.

Gathering and compression costs decreased from $0.76 per Mcfe to $0.63 per Mcfe primarily as a result of decreased costs associated with fuel as a result of a decrease in natural gas prices and a $12 million incentive fee rebate from Antero Midstream Corporation.

Processing costs increased from $0.61 to $0.69 per Mcfe as a result of increased NGL production.

Gathering and compression costs decreased from $0.74 per Mcfe for the six months ended June 30, 2019 to $0.63 per Mcfe for the six months ended June 30, 2020 primarily as a result of decreased costs associated with fuel as a result of a decrease in natural gas prices and $24 million in incentive fee rebates from Antero Midstream Corporation.

Processing costs increased from $0.63 per Mcfe to $0.72 per Mcfe for the six months ended June 30, 2019 and 2020, respectively, due to increased NGL production in our production mix.

Processing costs remained relatively unchanged per NGL barrel.

Our transportation costs increased from $0.55 per Mcfe to $0.61 per Mcfe due to increased demand charges for Mountaineer Xpress pipeline, which came on line in February 2019.

Transportation costs increased from $0.55 per Mcfe to $0.59 per Mcfe for the six months ended June 30, 2019 and 2020, respectively, primarily due to increased rates on the Rockies Express pipeline and demand charges for Mountaineer Xpress pipeline, which came on line in February 2019.

Production and ad valorem tax expense.

Production and ad valorem taxes decreased from $35 million for the three months ended March 31, 2019 to $26 million for the three months ended March 31, 2020, a decrease of $9 million, or 26%.

Production and ad valorem taxes decreased from $66 million for the six months ended June 30, 2019 to $46 million for the six months ended June 30, 2020, a decrease of $20 million, or 30%.

This decrease is primarily as a result of decreases in commodity prices.

Production and ad valorem taxes as a percentage of natural gas revenues increased slightly from 5% in the three months ended March 31, 2019, to 6% for the three months ended March 31, 2020.

Production and ad valorem taxes as a percentage of natural gas revenues remained flat at 5% for the six months ended June 30, 2019 and 2020.

Impairment of oil and gas properties .

Impairment of oil and gas properties increased from $81 million for the three months ended March 31, 2019 to $89 million for the three months ended March 31, 2020, an increase of $8 million, or 10%.

We recognized impairments primarily related to expiring leases and to design and initial costs related to pads we no longer plan to place into service.

Impairment of oil and gas properties decreased from $212 million for the six months ended June 30, 2019 to $127 million for the six months ended June 30, 2020, a decrease of $86 million, or 40%.

We recognized impairments primarily related to expiring leases and the design and initial costs related to pads we no longer plan to place into service.

Depletion, depreciation, and amortization expense (“DD&A”) .

DD&A expense decreased from $218 million for the three months ended March 31, 2019 to $200 million for the three months ended March 31, 2020, a decrease of $18 million, or 9%.

DD&A per Mcfe decreased from $0.78 per Mcfe during the three months ended March 31, 2019 to $0.66 per Mcfe during the three months ended March 31, 2020, as our depletable reserve volumes at March 31, 2020 increased slightly due to increased production and our depletable cost base decreased from March 31, 2019 due to an impairment in the value of our Utica properties of $881 million in the three months ended September 30, 2019.

Depletion, depreciation, and amortization expense .

DD&A expense decreased from $461 million for the six months ended June 30, 2019 to $414 million for the six months ended June 30, 2020, a decrease of $47 million, or 10%.

DD&A per Mcfe decreased from $0.81 per Mcfe during the six months ended June 30, 2019 to $0.66 per Mcfe during the six months ended June 30, 2020, as our

depletable reserve volumes at June 30, 2020 increased slightly due to increased production and our depletable cost base decreased from June 30, 2019 due to an impairment in the value of our Utica properties of $881 million on September 30, 2019.

General and administrative expense .

General and administrative expense (excluding equity-based compensation expense) related to the exploration and production segment decreased from $43 million for the three months ended March 31, 2019 to $28 million for the three months ended March 31, 2020, a decrease of $15 million, or 36%.

This decrease was primarily due to approximately $6.3 million in legal and other expenses related to the Transactions in the three months ended March 31, 2019 as well as decreases in employee related expenses in the three months ended March 31, 2020 as a result of ongoing cost savings initiatives.

We had 619 employees as of March 31, 2019 and 531 employees as of March 31, 2020.

On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 44%, from $0.16 per Mcfe during the three months ended March 31, 2019 to $0.09 per Mcfe during the three months ended March 31, 2020 as the expense decreased while production increased.

General and administrative expense (excluding equity-based compensation expense) related to the exploration and production segment decreased from $79 million for the six months ended June 30, 2019 to $58 million for the six months ended June 30, 2020, a decrease of $21 million, or 27%.

This decrease was primarily due to approximately $6.3 million in legal and other expenses related to the Transactions and the associated deconsolidation of Antero Midstream Partners transactions in the six months ended June 30, 2019 as well as decreases in employee related expenses in the six months ended June 30, 2020 as a result of ongoing cost savings initiatives related to lower headcount in 2020.

We had 590 employees as of June 30, 2019 and 524 employees as of June 30, 2020.

On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 36%, from $0.14 per Mcfe during the six months ended June 30, 2019 to $0.09 per Mcfe during the six months ended June 30, 2020 as the expense decreased while production increased.

Equity-based compensation expense .

Noncash equity-based compensation expense decreased from $6 million for the three months ended March 31, 2019 to $3 million for the three months ended March 31, 2020, a decrease of $3 million, or 48%.

Noncash equity-based compensation expense decreased from $13 million for the six months ended June 30, 2019 to $11 million for the six months ended June 30, 2020, a decrease of $2 million, or 15%.

This decrease was the result of equity award forfeitures, as well as a decrease in the total value of awards to officers and employees in 2019, which impacts future expense recognition.

When an equity award is forfeited, expense previously recognized for the award is reversed.

See Note 9 to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on equity-based compensation awards.

Contract termination and rig stacking.

We incurred contract termination and rig stacking costs of $8 million during the three months ended March 31, 2019 compared to no expense for the three months ended March 31, 2020.

We incurred contract termination and rig stacking costs of $14 million during the six months ended June 30, 2019 compared to $11 million for the six months ended June 30, 2020.

Discussion of the Marketing Segment for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2020

Discussion of the Marketing Segment for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2020

We have entered into long-term firm transportation agreements for our current and expected future production in order to secure guaranteed capacity to favorable markets.

Where feasible, we purchase and sell third-party natural gas and NGLs to utilize our excess firm transportation capacity, or release capacity to third parties to conduct these activities on our behalf, in order to reduce our net costs related to the unused capacity under these transportation agreements.

Operating losses on our marketing activities, or our net marketing expense, decreased from $72 million, or $0.26 per Mcfe, for the three months ended March 31, 2019 to $47 million, or $0.15 per Mcfe, for the three months ended March 31, 2020.

Our net marketing expense decreased from $146 million, or $0.26 per Mcfe, for the six months ended June 30, 2019 to $96 million, or $0.15 per Mcfe, for the six months ended June 30, 2020.

The decrease was driven by higher volumes and the mitigation of some of our excess firm transportation expense.

Marketing revenues decreased from $91 million for the three months ended March 31, 2019 to $46 million for the three months ended March 31, 2020, a decrease of $45 million, or 49%.

The decreases in revenues is due to lower excess firm transportation capacity and decreases in commodity prices in the three months ended March 31, 2020 compared to the three months ended March 31, 2019.

Marketing expenses decreased from $163 million for the three months ended March 31, 2019 to $93 million for the three months ended March 31, 2020, a decrease of $70 million, or 43%.

Marketing revenues decreased from $154 million for the six months ended June 30, 2019 to $110 million for the six months ended June 30, 2020, a decrease of $44 million, or 28%.

The decrease in revenues is due to lower excess firm transportation capacity and decreases in commodity prices in the six months ended June 30, 2020 compared to the six months ended June 30, 2019.

Marketing expenses decreased from $301 million for the six months ended June 30, 2019 to $206 million for the six months ended June 30, 2020, a decrease of $94 million, or 31%.

Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs.

Firm transportation costs included in the expenses above were $68 million and $47 million for the three months ended March 31, 2019 and 2020, respectively.

Discussion of Antero Midstream Corporation Segment for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2020

Firm transportation costs included in the expenses above were $127 million and $88 million for the six months ended June 30, 2019 and 2020, respectively.

Discussion of Antero Midstream Corporation Segment for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2020

Through March 12, 2019, the results of Antero Midstream Partners are included in our consolidated financial statements.

Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results.

As such, the three months ended March 31, 2019 include the results of Antero Midstream Partners through March 12, 2019.

See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

As such, the six months ended June 30, 2019 include the results of Antero Midstream Partners through March 12, 2019.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

Antero Midstream Corporation.

Revenue from the Antero Midstream Corporation segment increased from $54 million for the three months ended March 31, 2019 to $244 million for the three months ended March 31, 2020, an increase of $190 million, or 350%.

The increase in operating revenue was primarily due to the three months ended March 31, 2019 only including Antero Midstream Corporation’s results following the closing of the Transactions on March 12, 2019.

Total operating expenses related to the segment increased from $33 million for the three months ended March 31, 2019 to $763 million for the three months ended March 31,

Revenue from the Antero Midstream Corporation segment increased from $310 million for the six months ended June 30, 2019 to $463 million for the six months ended June 30, 2020, an increase of $153 million, or 49%.

The increase in operating revenue was primarily due to the six months ended June 30, 2019 only including Antero Midstream

Corporation’s results following the closing of the Transactions on March 12, 2019.

Total operating expenses related to the segment increased from $189 million for the six months ended June 30, 2019 to $848 million for the six months ended June 30, 2020.

The increase was primarily due to impairments by Antero Midstream Corporation of $89 million on its freshwater pipelines and equipment, and an impairment charge of $575 million on its goodwill.

Discussion of Items Not Allocated to Segments for the Three Months Ended March 31, 2019 Compared to the Three Months Ended March 31, 2020

Discussion of Items Not Allocated to Segments for the Six Months Ended June 30, 2019 Compared to the Six Months Ended June 30, 2020

Impairment of equity investment .

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Interest expense.

Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $55 million in the three months ended March 31, 2019 to $53 million in the three months ended March 31, 2020, a decrease of $2 million, or 3%.

This decrease is due to a decrease in total indebtedness resulting from repurchases of our unsecured senior notes at prices below their stated value.

Consolidated interest expense decreased from $72 million for the three months ended March 31, 2019 to $53 million for the three months ended March 31, 2020, a decrease of $19 million, or 26%.

During the three months ended March 31, 2019, interest related to Antero Midstream Partners’ debt through March 12, 2019 is included consolidated interest expense.

Interest expense includes approximately $3.1 million and $2.5 million of non-cash amortization of deferred financing costs for the three months ended March 31, 2019 and 2020, respectively.

Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $109 million for the six months ended June 30, 2019 to $105 million for the six months ended June 30, 2020 primarily due to the reduction in debt as a result of our debt repurchases.

Consolidated interest expense decreased from $126 million for the six months ended June 30, 2019 to $105 million for the six months ended June 30, 2020, a decrease of $21 million, or 17%.

During the six months ended June 30, 2019, interest related to Antero Midstream Partners’ debt through March 12, 2019 is included consolidated interest expense.

Interest expense includes approximately $5.7 million and $4.8 million of non-cash amortization of deferred financing costs for the six months ended June 30, 2019 and 2020, respectively.

Transaction expense.

We incurred transaction expense of $6 million in the six months ended June 30, 2020 and did not incur comparable costs in the six months ended June 30, 2019.

These expenses include legal and transaction fees associated with the sale of our overriding royalty interest and the creation of Martica.

See Note 4—Conveyance of Overriding Royalty Interest to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on this transaction.

Income tax expense/benefit .

Income tax expense decreased from a deferred tax expense of $288 million and $1 million of current tax expense, with an effective tax rate of 22%, for the three months ended March 31, 2019 to a deferred tax benefit of $110 million, with an effective tax rate of 25%, for the three months ended March 31, 2020.

The change was primarily a result of the increase in book income due to the Transactions and the associated deconsolidation of Antero Midstream Partners for the three months ended March 31, 2019, offset by the decrease in book income resulting from the impairment of our investment in Antero Midstream Corporation for the three months ended March 31, 2020.

Income tax expense decreased from a deferred tax expense of $305 million and $1 million of current tax expense, with an effective tax rate of 22%, for the six months ended June 30, 2019 to a deferred tax benefit of $252 million, with an effective tax rate of 24%, for the six months ended June 30, 2020.

The change was primarily a result of an increase in book income due to the Transactions and the associated deconsolidation of Antero Midstream Partners for the six months ended June 30, 2019, offset by a decrease in book income resulting from the impairment of our investment in Antero Midstream Corporation and reduced revenue due to commodity price decreases for the six months ended June 30, 2020.

Capital Resources and Liquidity

Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under the Credit Facility, issuances of debt and equity securities, and distributions/dividends from unconsolidated affiliates.

Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under the Credit Facility, issuances of debt and equity securities, distributions/dividends from unconsolidated affiliates and proceeds from our asset sale program, including the sale of the overriding royalty interest.

Our primary use of cash has been for the exploration, development, and acquisition of oil and natural gas properties.

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Our future success in growing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.

In addition, we may from time to time repurchase shares of our common stock.

Under our prior share repurchase program, we repurchased and retired 27,193,237 common shares at a weighted average price per share of $1.57 for approximately $43 million during the three months ended March 31, 2020.

During the term of this program, we repurchased approximately $215 million of our shares of common stock.

During the six months ended June 30, 2020, we repurchased shares of our common stock under our share repurchase program that expired March 31, 2020.

We repurchased and retired 28,193,237 common shares at a weighted average price per share of $1.54 for approximately $43 million during the six months ended June 30, 2020.

We may also seek to retire or purchase our outstanding debt securities from time to time through cash purchases, in open market purchases, privately negotiated transactions or otherwise.

Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors.

During the three months ended March 31, 2020, we repurchased $383 million principal amount of debt at a 21% weighted average discount, including a portion of both our 2021 notes and our 2022 notes.

During the six months ended June 30, 2020, we repurchased $619 million principal amount of debt at a 19% weighted average discount, including a portion of our 2021 notes, 2022 notes, 2023 notes and 2025 notes.

We recognized a gain of approximately $120 million on the early extinguishment of the debt repurchased.

These repurchases, at a discount, have resulted in a net reduction in total debt outstanding and interest expense.

As of March 31, 2020, we believe that funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under the Credit Facility, or capital market transactions will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

As of June 30, 2020, we believe that funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under the Credit Facility, or capital market transactions will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months.

Our 2021 notes are due November 1, 2021 and our Credit Facility will become due 91 days prior to that date, or on August 1, 2021, if the 2021 notes are not repaid prior to August 1, 2021.

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The classification of the Credit Facility as a current liability does not impact any of our financial covenants.

In addition, we believe we have the ability to address the maturity of the 2021 Notes with proceeds from potential asset sales, free cash flow from operations, and available borrowings under the Credit Facility.

For more information on our outstanding indebtedness, see Note 7 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.

In addition, we believe we have the ability to address the maturity of the 2021 notes with proceeds from our asset sales program, free cash flow from operations, and available borrowings under the Credit Facility.

For more information on our outstanding indebtedness, see Note 8—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q.

For information about the impacts of COVID-19 on our capital resources and liquidity, see “—COVID-19 Pandemic.”

The following table summarizes our cash flows for the three months ended March 31, 2019 and 2020:

Three Months Ended March 31,

The following table summarizes our cash flows for the six months ended June 30, 2019 and 2020:

Six Months Ended June 30,

(in thousands)

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Net cash used in investing activities

Net cash provided by (used in) financing activities

Net cash provided by financing activities

Effect of deconsolidation of Antero Midstream Partners LP

Net decrease in cash and cash equivalents

The Company's condensed consolidated cash flow statements for the three months ended March 31, 2019 includes the cash flows related to Antero Midstream Partners for periods prior to March 13, 2019.

Effective March 13, 2019, the Company's cash flows include only the operating, investing and financing activities related to Antero and;

therefore, the cash flows for the three months ended March 31, 2019 are not representative of our expected future cash flows.

See Note 3 to the unaudited condensed consolidated financial statements for more information.

The Company's condensed consolidated cash flow statements for the six months ended June 30, 2019 includes the cash flows related to Antero Midstream Partners for periods prior to March 13, 2019.

Effective March 13, 2019, the Company's cash flows include only the operating, investing and financing activities related to Antero.

Therefore, the cash flows for the six months ended June 30, 2019 may not be representative of our expected future cash flows.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for more information.

Cash Flows Provided by Operating Activities

Net cash provided by operating activities was $539 million and $201 million for the three months ended March 31, 2019 and 2020, respectively.

Cash flow from operations decreased primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression and transportation costs.

Net cash provided by operating activities was $757 million and $317 million for the six months ended June 30, 2019 and 2020, respectively.

Our net operating cash flows are sensitive to many variables, the most significant of which is the volatility of natural gas, NGLs, and oil prices, as well as volatility in the cash flows attributable to settlement of our commodity derivatives.

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Cash Flows Used in Investing Activities

During the three months ended March 31, 2019 and 2020, we used cash flows in investing activities of $205 million and $187 million, respectively, primarily as a result of our capital expenditures for drilling, development, and acquisitions.

In addition, cash flows in investing activities included expenditures of Antero Midstream Partners related to construction of midstream and water handling and treatment infrastructure and investments in joint ventures through March 12, 2019.

Effective March 13, 2019, these expenditures are no longer consolidated in our results.

Cash flows used in investing activities decreased from $205 million for the three months ended March 31, 2019 to $187 million for the three months ended March 31, 2020, primarily due to a decrease in capital expenditures of $160 million during the three months ended March 31, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the Transactions impacting the three months ended March 31, 2019 and $125 million in settlement of the water earnout impacting the three months ended March 31, 2020.

See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

Total capital expenditures for oil and gas properties decreased from $396 million during the three months ended March 31, 2019 to $311 million during the three months ended March 31, 2020 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation.

The three months ended March 31, 2019 included Antero Midstream Partners’ investments in joint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression systems of $73 million.

Due to the deconsolidation of Antero Midstream Partners on March 12, 2019, cash flows used in investing activities for the three months ended March 31, 2020 do not include costs attributable to Antero Midstream Partner’s investing activity.

Cash flows used in investing activities decreased from $546 million for the six months ended June 30, 2019 to $450 million for the six months ended June 30, 2020, primarily due to a decrease in capital expenditures of $239 million during the six months ended June 30, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the Transactions impacting the six months ended June 30, 2019 and $125 million in settlement of the water earnout impacting the six months ended June 30, 2020.

In addition, the six months ended June 30, 2019 included Antero Midstream Partners’ investments in joint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression systems of $73 million.

Due to the deconsolidation of Antero Midstream Partners on March 12, 2019, cash flows used in investing activities for the six months ended June 30, 2020 do not include costs attributable to Antero Midstream Partner’s investing activity.

See Note 3—Deconsolidation of Antero Midstream Partners LP to the unaudited condensed consolidated financial statements for further discussion on the Transactions.

Total capital expenditures for oil and gas properties decreased from $742 million during the six months ended June 30, 2019 to $575 million during the six months ended June 30, 2020 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation.

Our drilling and completion capital budget for 2020 has been reduced to $750 million from $1.15 billion.

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Cash Flows Provided by Financing Activities

During the three months ended March 31, 2019 and 2020, net cash flows provided by financing activities decreased from a source of $285 million to a use of $14 million primarily as a result of the issuance of senior notes by Antero Midstream Partners prior to the Transactions and the associated deconsolidation of Antero Midstream Partners, partially offset by net repayments on our Credit Facility and Antero Midstream Partners’ credit facility.

Net borrowings (repayments) on our Credit Facility and Antero Midstream Partners’ credit facility changed from net payments of $270 million during the three months ended March 31, 2019 to net borrowings of $330 million during the three months ended March 31, 2020.

Approximately $302 million of borrowings on our Credit Facility in the three months ended March 31, 2020 was used to repurchase a portion of our 2021 and 2022 unsecured notes.

In addition, we repurchased and retired 27,193,237 common shares for approximately $43 million during the three months ended March 31, 2020.

We did not repurchase any of our unsecured notes or shares during the three months ended March 31, 2019.

During the six months ended June 30, 2019 and 2020, net cash flows provided by financing activities decreased from $408 million to $133 million primarily as a result of the issuance of senior notes by Antero Midstream Partners prior to the Transactions and the associated deconsolidation of Antero Midstream Partners, partially offset by net repayments on our Credit Facility and Antero Midstream Partners’ credit facility.

Additionally, during the six months ended June 30, 2020, we received $300 million for the sale of a noncontrolling interest in Martica.

See Note 4—Conveyance of Overriding Royalty Interest for more information on this transaction.

Net borrowings (repayments) on our Credit Facility and Antero Midstream Partners’ credit facility changed from net repayments of $145 million during the six months ended June 30, 2019 to net borrowings of $374 million during the six months ended June 30, 2020.

In the six months ended June 30, 2020, approximately $497 million, partially funded with net borrowings on our Credit Facility, was used to repurchase a portion of our 2021 notes, 2022 notes, 2023 notes and 2025 notes.

In addition, we repurchased and retired 28,193,237 common shares for approximately $43 million during the six months ended June 30, 2020.

We did not repurchase any of our unsecured notes or shares during the six months ended June 30, 2019.

Debt Agreements and Contractual Obligations

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Our Credit Facility is with a consortium of bank lenders.

On April 29 , 2020, Antero Resources entered into a Third Amendment to the Credit Facility, pursuant to which certain terms of the Credit Facility were amended, as further described herein.

Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular redeterminations.

The borrowing base was adjusted to $2.85 billion and lender commitments were reaffirmed at $2.64 billion in the scheduled redetermination in April 2020.

The borrowing base is $2.85 billion and lender commitments are $2.64 billion.

The next redetermination of the borrowing base is scheduled to occur in October 2020.

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At December 31, 2019, we had $552 million of borrowings under the Credit Facility with a weighted average interest rate of 3.28% and $623 million of letters of credit outstanding.

At March 31, 2020, we had $882 million of borrowings and $730 million of letters of credit outstanding under the Credit Facility.

The average annualized interest rate incurred on the Credit Facility during the three months ended March 31, 2020 was approximately 3.28%.

At June 30, 2020, we had $926 million of borrowings and $730 million of letters of credit outstanding under the Credit Facility.

The average annualized interest rate incurred on the Credit Facility during the six months ended June 30, 2020 was approximately 3.22%.

Our Credit Facility provides for borrowing under either LIBOR or an Alternative Rate of Interest.

Under the Credit Facility, “Investment Grade Period” is a period that, as long as no event of default has occurred, commences when Antero elects to give notice to the Administrative Agent that Antero has received at least one of either (i) a BBB- or better rating from S&P or (ii) a Baa3 or better rating from Moody’s (an “Investment Grade Rating”).

An Investment Grade Period can end at Antero’s election.

During any period that is not an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following two financial ratios as of the end of each fiscal quarter:

● a current ratio, which is the ratio of our current assets (including any unused borrowing base under the facilities and excluding derivative assets) to our current liabilities (excluding derivative liabilities and lease liabilities), of not less than 1.0 to 1.0;

● an interest coverage ratio, which is the ratio of EBITDAX (as defined by the credit facility agreement) to interest expense over the most recent four quarters, of not less than 2.5 to 1.0.

During an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following three financial ratios as of the end of each fiscal quarter

● a ratio of total Indebtedness (as defined by the credit facility agreement) to EBITDAX (as defined by the credit facility agreement) of not more than 4.25 to 1.00;

● a ratio of PV-9 reflected in the most recently delivered reserve report to its total Indebtedness of not less than 1.50 to 1.00, but only if Antero does not have both (i) an unsecured rating from Moody’s of Baa3 or better and (ii) an unsecured rating from S&P of BBB- or better.

We were in compliance with the applicable covenants and ratios as of December 31, 2019 and March 31, 2020.

The actual borrowing capacity available to us may be limited by the financial ratio covenants.

At March 31, 2020, our current ratio was 2.28 to 1.0 and our interest coverage ratio was 5.06 to 1.0.

We were in compliance with the applicable covenants and ratios as of December 31, 2019 and June 30, 2020.

At June 30, 2020, our current ratio was 2.37 to 1.0 and our interest coverage ratio was 5.22 to 1.0.

For more information on the terms, conditions, and restrictions under the Credit Facility, please refer to our 2019 Form 10-K.

Senior Notes .

Please refer to Note 7 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7.

Please refer to Note 8—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to “Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Form 10-K for information on our senior notes.

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The amounts involved could be material.

During the three months ended March 31, 2020, we repurchased $383 million principal amount of debt at a 21% weighted average discount, including a portion of our 2021 notes and our 2022 notes.

Contractual Obligations .

A summary of our contractual obligations as of March 31, 2020 is provided in the table below.

A summary of our contractual obligations as of June 30, 2020 is provided in the table below.

Future capital contributions to unconsolidated affiliates are excluded from the table as neither the amounts nor the timing of the obligations can be determined in advance.

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Land payment obligations (7)

(1) Includes outstanding principal amounts at March 31, 2020.

(1) Includes outstanding principal amounts at June 30, 2020.

This table does not include future commitment fees, interest expense, or other fees on our Credit Facility because they are floating rate instruments and we cannot determine with accuracy the timing of future loan advances, repayments, or future interest rates to be charged.

The maturity date of the Credit Facility is the earlier of (i) October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption of any series of Antero’s senior notes then outstanding.

(2) Our senior notes include our 2021 notes, our 2022 notes, our 5.625% notes due 2023, and our 5.00% notes due 2025.

(2) Our senior notes include our 2021 notes, 2022 notes, 2023 notes, and 2025 notes.

(3) Includes contracts for services provided by drilling rigs and completion fleets, processing, gathering and compression services agreements and office and equipment leases accounted for as leases.

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however, we will record in our financial statements our proportionate share of costs based on our working interests.

See Note 12 to the unaudited condensed consolidated financial statements for more information on the Company’s operating and finance leases.

See Note 13—Leases to the unaudited condensed consolidated financial statements for more information on our operating and finance leases.

(4) Represents the present value of our estimated asset retirement obligations.

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Effective March 13, 2019, we no longer consolidate Antero Midstream Partners and account for our interest in Antero Midstream using the equity method of accounting.

See Note 5 to the unaudited condensed consolidated financial statements for more information on our equity investments.

See Note 6—Equity Method Investments to the unaudited condensed consolidated financial statements for more information on our equity investments.

Adjusted EBITDAX includes distributions received with respect to limited partner interests in Antero Midstream Partners common units through March 12, 2019.

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There are significant limitations to using Adjusted EBITDAX as a measure of performance, including the inability to analyze the effects of certain recurring and non-recurring items that materially affect our net income or loss, the lack of comparability of results of operations of different companies, and the different methods of calculating Adjusted EBITDAX reported by different companies.

The following table represents a reconciliation of our net income (loss), including noncontrolling interest, to Adjusted EBITDAX and a reconciliation of our Adjusted EBITDAX to net cash provided by operating activities per our unaudited condensed consolidated statements of cash flows, in each case, for the three months ended March 31, 2019 and 2020.

Adjusted EBITDAX also excludes the results of Antero Midstream Partners in order to provide comparability with the current structure of Antero Resources as effective March 13, 2019, we no longer consolidate Antero Midstream Partners results.

Adjusted EBITDAX excludes the results of Antero Midstream Partners in order to provide comparability with the current structure of Antero Resources as effective March 13, 2019, we no longer consolidate Antero Midstream Partners results.

These adjustments are disclosed in the table below as Antero Midstream Partners related adjustments.

Three months ended March 31,

Adjusted EBITDAX also excludes the noncontrolling interests in Martica and these adjustments are disclosed in the table below as Martica related adjustments.

Three months ended June 30,

Six months ended June 30,

(in thousands)

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

Net income and comprehensive income attributable to noncontrolling interests

Net loss and comprehensive loss attributable to noncontrolling interests

Depletion, depreciation, amortization, and accretion

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Exploration expense

Gain on sale of assets

(Gain) Loss on sale of assets

Contract termination and rig stacking

Simplification transaction fees

Net income and comprehensive income attributable to noncontrolling interests

Antero Midstream Partners interest expense, net (2)

Antero Midstream Partners depreciation, accretion of ARO and accretion of contingent consideration (2)

Antero Midstream Partners impairment

Antero Midstream Partners equity-based compensation expense (2)

Antero Midstream Partners equity in earnings of unconsolidated affiliates (2)

Antero Midstream Partners distributions from unconsolidated affiliates (2)

Equity in earnings of Antero Midstream Partners (2)

Distributions from Antero Midstream Partners (2)

Antero Midstream Partners Simplification transaction fees

Transaction expense

Antero Midstream Partners related adjustments (2)

Martica related adjustments (3)

Adjusted EBITDAX

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Antero Midstream Partners related adjustments (2)

Martica related adjustments (3)

Interest expense, net

Exploration expense

Gain on asset sale

Changes in current assets and liabilities

Simplification transaction fees

Other non-cash items

Transaction expense

Net cash provided by operating activities

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(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 the Closing).

Effective March 13, 2019, Antero accounts for its

unconsolidated investment in Antero Midstream Corporation using the equity method of accounting.

See Note 5 to the unaudited condensed consolidated financial statements for further discussion on equity method investments.

Effective March 13, 2019, Antero accounts for its unconsolidated investment in Antero Midstream Corporation using the equity method of accounting.

See Note 6—Equity Method Investments to the unaudited condensed consolidated financial statements for further discussion on equity method investments.

(3) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above.

Critical Accounting Policies and Estimates

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We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated financial statements.

Also, see Note 2 to the consolidated financial statements, included in our 2019 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

Also, see Note 2—Summary of Significant Accounting Policies to the consolidated financial statements, included in our 2019 Form 10-K, for a discussion of additional accounting policies and estimates made by management.

We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment for the Utica and Marcellus Shale properties, by property, when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.

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These events have caused, and continue to cause, significant volatility in future prices which are used in this evaluation.

Based on future prices at March 31, 2020, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required.

We have not recorded any impairment expenses associated with our proved properties during the three months ended March 31, 2019 and 2020.

We recorded an impairment charge of $881 million related to the Utica Shale properties during the three months ended September 30, 2019.

Based on future prices at June 30, 2020, the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required.

We have not recorded any impairment expenses associated with our proved properties during the six months ended June 30, 2019 and 2020.

We recorded an impairment charge of $881 million related to the Utica Shale properties on September 30, 2019.

Estimated undiscounted future net cash flows are very sensitive to commodity price swings at current commodity price levels and a relatively small decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future reporting period, which would require us to further evaluate if an impairment charge would be necessary.

If future prices decline further from March 31, 2020, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary.

If future prices decline further from June 30, 2020, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary.

We are unable, however, to predict future commodity prices with any reasonable certainty.

Off-Balance Sheet Arrangements

As of March 31, 2020, we did not have any off balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations.

As of June 30, 2020, we did not have any off balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations.

See “—Debt Agreements and Contractual Obligations—Contractual Obligations” for our commitments under these agreements.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-Q

Item 2. Management’s Discussion and Analysis