Item 2. Management’s Discussion and Analysis
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and related notes included elsewhere in this Quarterly Report on Form 10-Q. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. We caution that assumptions, expectations, projections, intentions, or beliefs about future events may, and often do, vary from actual results, and the differences can be material. Some of the key factors that could cause actual results to vary from our expectations include changes in natural gas, NGLs, and oil prices, the timing of planned capital expenditures, our ability to fund our development programs, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, impacts of world health events, including the COVID-19 pandemic, potential shut-ins of production due to lack of downstream demand or storage capacity, and uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, as well as those factors discussed below, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. See “Cautionary Statement Regarding Forward-Looking Statements.” Also, see the risk factors and other cautionary statements described under the heading “Item 1A. Risk Factors.” We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
In this section, references to “Antero,” the “Company,” “we,” “us,” and “our” refer to Antero Resources Corporation and its subsidiaries, unless otherwise indicated or the context otherwise requires.
Our Company
We are an independent oil and natural gas company engaged in the exploration, development and production of natural gas, NGLs, and oil properties located in the Appalachian Basin. We focus on unconventional reservoirs, which can generally be characterized as fractured shale formations. Our management team has worked together for many years and has a successful track record of reserve and production growth as well as significant expertise in unconventional resource plays. Our strategy is to leverage our team’s experience delineating and developing natural gas resource plays to profitably grow our reserves and production, primarily on our existing multi-year inventory of drilling locations.
We have assembled a portfolio of long-lived properties that are characterized by what we believe to be low geologic risk and repeatability. Our drilling opportunities are focused in the Marcellus Shale and Utica Shale of the Appalachian Basin. As of September 30, 2020, we held approximately 522,000 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.
We operate in the following industry segments: (i) the exploration, development, and production of natural gas, NGLs, and oil; (ii) marketing of excess firm transportation capacity; and (iii) our equity method investment in Antero Midstream Corporation. All of our operations are conducted in the United States. 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.
2020 Developments and Highlights
COVID-19 Pandemic
In March 2020, the World Health Organization declared the COVID-19 outbreak a pandemic. Governments have tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, which have caused a significant decrease in activity in the global economy and the demand for oil and, to a lesser extent, natural gas and NGLs. Also in March 2020, Saudi Arabia and Russia failed to agree to cut production of oil along with the Organization of the Petroleum Exporting Countries (“OPEC”), and Saudi Arabia significantly reduced the price at which it sells oil and announced plans to increase production, which contributed to a sharp drop in the price of oil. 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.
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. We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our employees and workers. 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
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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 4% of our total revenue for each of the nine months ended September 30, 2020 and the year ended December 31, 2019. While natural gas prices also declined during the first half of 2020, benchmark Henry Hub prices recovered during the third quarter and averaged $2.58/Mcf in September. Similarly, C3+ NGL prices also improved during the third quarter as gasoline demand increased, supporting prices for normal butane (nC4), isobutane (iC4), and pentane (C5), all of which are used for gasoline. The COVID-19 induced demand destruction on gasoline, which forced C5 prices below propane prices for much of April to under $0.40 per gallon, has since rebounded with benchmark C5 price in October in the range of $0.85 to $0.95 per gallon.
In addition, we have hedged through fixed price contracts the sale of 1.3 Bcf per day of natural gas at a weighted average price of $2.84 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 10,315 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. 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, 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. While we have seen a decrease in the overall demand for these products, demand for natural gas and NGLs has not declined as much as demand for oil, and there has not been as substantial an oversupply of natural gas and NGLs as there has been of oil. Furthermore, the decrease in demand for oil has significantly reduced the number of rigs drilling for oil in the continental U.S. and, as a result, estimates of future gas supply associated with oil production have declined. 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 third 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 were approximately $15/Bbl during the third quarter. Pre-hedge oil realizations were negatively impacted during the second quarter and beginning of the third 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 period 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 through this period. Antero expects its full year 2020 realized oil price differential to be at the high end of the $10.00/Bbl to $12.00/Bbl range, as the differential normalizes during the fourth quarter 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, and such capacity is still largely available to us.
During the third 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
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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 third quarter, our ongoing emphasis on completion efficiencies and drilling longer laterals resulted in material improvements in well costs. Well costs average $640 per lateral foot during the third quarter, benefiting from these efficiency improvements and lateral lengths that averaged over 15,000 feet. Well costs were $675 per foot when normalized for a 12,000 foot lateral length. We expect well costs to average $675 per foot during the fourth quarter of 2020, based on a 12,000 foot lateral. 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. 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 the end of the first quarter of 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 September 30, 2020, unresolved storage capacity restraints or other consequences caused by the COVID-19 pandemic.
In October 2020, the borrowing base supporting our Credit Facility was subject to its semi-annual redetermination and was re-affirmed our borrowing base at $2.85 billion. Lender commitments also remained unchanged at $2.64 billion, providing us with a consistent amount of available borrowings. Our next semi-annual borrowing base redetermination is in April 2021, which could impact our available borrowings and liquidity.
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. 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. We have announced $751 million in asset sales since December 2019, inclusive of up to $51 million of contingent consideration, with proceeds used for absolute debt reduction. Any additional asset sales or excess cash flows is expected to be used for further debt reduction. 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.
Volumetric Production Payment Transaction
On August 10, 2020, we completed a volumetric production payment transaction and received net proceeds of approximately $215 million (the "VPP"). In connection with the VPP, we entered into a purchase and sale agreement, together with a conveyance agreement and production and marketing agreement, with J.P. Morgan Ventures Energy Corporation ("JPM-VEC") to convey, effective July 1, 2020, an overriding royalty interest in dry gas producing properties in West Virginia (the "VPP Properties") equal to 136,589,000 MMBtu over the expected seven-year term of the VPP.
We accounted for the VPP as a conveyance under Accounting Standard Codifications (“ASC”) Topic 932, Extractive Industries—Oil and Gas , and the net proceeds were recognized as deferred revenue as of September 30, 2020. Deferred revenue is recognized as volumes are delivered using the units-of-production method over the term of the VPP. Under the production and marketing agreement, we and our affiliates provide certain marketing services as JPM-VEC’s agent, and any income or expenses related to these services will be recorded as marketing revenue or marketing expenses (as the case may be).
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Contemporaneously with the VPP transaction, we executed a call option related to the production volumes associated with our retained interest in the VPP properties, which is collateralized by a mortgage on the VPP properties. Additionally, the production and marketing agreement contains an embedded put option related to the production volumes for our retained interest in the VPP properties, which has been bifurcated from the production and marketing arrangement and accounted for as a derivative instrument recorded at fair value as of September 30, 2020. See Note 12—Derivative Instruments to the unaudited condensed consolidated financial statements for further discussion of such derivative instruments.
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 at the initial closing 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 in the third quarter of 2020 and first quarter of 2021. All cash contributed by Sixth Street was distributed to us. As of September 30, 2020, we determined we met the production threshold related to the third quarter of 2020 whereby we became entitled to receive a $51 million cash distribution that will be paid in the fourth quarter of 2020.
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
Three months ended September 30, 2020 . For the three months ended September 30, 2020 our net production totaled 347 Bcfe, or 3,772 MMcfe per day, a 12% increase in daily gas equivalent production compared to 310 Bcfe, or 3,367 MMcfe per day, for the three months ended September 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 for the three months ended September 30, 2020 was $2.30 per Mcfe compared to $2.74 per Mcfe for the three months ended September 30, 2019. These prices are before the effects of gains on settled commodity derivatives in both periods and included the proceeds related to a certain lawsuit in the three months ended September 30, 2019. Our average realized price after the effects of gains on settled commodity derivatives was $2.92 per Mcfe for the three months ended September 30, 2020 compared to $3.13 per Mcfe for the three months ended September 30, 2019, a decrease of 7%.
We generated consolidated cash flows from operations of $176 million, net loss attributable to Antero Resources of $536 million, and Adjusted EBITDAX of $272 million for the three months ended September 30, 2020. This compares to consolidated cash flows from operations of $198 million, consolidated net loss attributable to Antero Resources of $879 million, and Adjusted EBITDAX of $258 million for the three months ended September 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 $22 million for the three months ended September 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
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Antero Resources of $536 million for the three months ended September 30, 2020 decreased from consolidated net loss attributable to Antero Resources of $879 million for the three months ended September 30, 2019 primarily due to impairments of oil and gas properties in 2019, partially offset by decreases in commodity derivative fair value gains (losses) and commodity prices and expense increases in processing and transportation costs.
Adjusted EBITDAX increased from $258 million for the three months ended September 30, 2019 to $272 million for the three months ended September 30, 2020, an increase of 6%, primarily due to higher commodity derivative settlement gains and decreased operating expenses per Mcfe, partially offset by lower commodity prices between periods.
Nine months ended September 30, 2020. For the nine months ended September 30, 2020 our net production totaled 974 Bcfe, or 3,554 MMcfe per day, a 10% increase in daily combined production compared to 882 Bcfe, or 3,232 MMcfe per day, for the nine months ended September 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 nine months ended September 30, 2020 was $2.15 per Mcfe compared to $3.15 per Mcfe for the nine months ended September 30, 2019. Our average realized price, after the effects of gains on settled commodity derivatives in both periods and including the proceeds related to a certain lawsuit in the three months ended September 30, 2019, was $2.91 per Mcfe for the nine months ended September 30, 2020 compared to $3.44 per Mcfe for the nine months ended September 30, 2019, a decrease of 15%.
We generated consolidated cash flows from operations of $493 million, net loss attributable to Antero of $1.3 billion, and Adjusted EBITDAX of $703 million for the nine months ended September 30, 2020. This compares to consolidated cash flows from operations of $956 million, consolidated net income attributable to Antero Resources of $142 million, and Adjusted EBITDAX of $952 million for the nine months ended September 30, 2019.
Cash flows from operations decreased by $463 million for the nine months ended September 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 $1.3 billion for the nine months ended September 30, 2020 decreased from consolidated net income attributable to Antero Resources of $142 million for the nine months ended September 30, 2019 primarily due to lower commodity prices between periods as well as the gain on deconsolidation of Antero Midstream Partners in 2019 partially offset by impairment of oil and gas properties in 2019. The nine months ended September 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 $982 million for the nine months ended September 30, 2019 to $703 million for the nine months ended September 30, 2020, a decrease of 26%, primarily due to the decrease in commodity prices of 32% per Mcfe before and 15% per Mcfe after the effects of settled commodity derivatives, and increased processing and transportation costs per Mcfe. 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
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.
Three months ended September 30, 2020. For the three months ended September 30, 2020, our capital expenditures were approximately $151 million, including drilling and completion costs of $141 million, leasehold acquisitions of $9 million, and other capital expenditures of $1 million. Our capital expenditures for the three months ended September 30, 2019 of approximately $292 million included drilling and completion costs of $278 million, leasehold acquisitions of $13 million, and other capital expenditures of $1 million. This 48% reduction in capital costs was a result of our decreased activity levels during the third quarter of 2020 as well as well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, and operational efficiency gains.
Nine months ended September 30, 2020. For the nine months ended September 30, 2020, our capital expenditures were approximately $726 million, including drilling and completion costs of $694 million, leasehold acquisitions of $31 million, and other capital expenditures of $1 million. Our exploration and production capital expenditures for the nine months ended September 30, 2019 of approximately $1.1 billion included drilling and completion costs of $958 million, leasehold acquisitions of $70 million, and
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other capital expenditures of $6 million. This 30% reduction in capital costs was a result of our decreased activity levels during 2020 as well as our well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, and operational efficiency gains.
In addition, consolidated capital expenditures for the nine months ended September 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.
Hedge Position (Excluding Martica)
As of September 30, 2020, we had fixed price natural gas swap contracts on NYMEX Henry Hub for the period from October 2020 through December 2023 covering 1.3 Tcf of our projected natural gas production at a weighted average index price of $2.69 per MMBtu, including contracts for the remainder of 2020 of approximately 190 Bcf of natural gas at a weighted average index price of $2.84 per MMBtu. As of September 30, 2020, we also had basis swaps for the period from October 2020 through December 2024 for approximately 78.6 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.
As of September 30, 2020, we had fixed price oil swap contracts on NYMEX-WTI for the period from October 2020 through December 2021 covering approximately 3.5 million barrels of our projected oil production at a weighted average index price of $55.48 per barrel. Additionally, we had fixed price propane swap contracts on ARA Propane for the period from October 2020 through December 2020 covering approximately 0.9 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 October 2020 through March 2021 covering approximately 4.0 million barrels of our projected ethane production at a weighted average index price of $0.20 per gallon.
As of September 30, 2020, we also had an embedded put option tied to NYMEX pricing for the production volumes associated with our retained interest in the VPP properties of 120,667,000 MMBtu remaining through December 31, 2026 at a weighted average strike price of $2.60 per MMBtu.
We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As of September 30, 2020, the estimated fair value of our commodity derivative contracts was a net liability of approximately $130 million.
Results of Operations
We have three operating segments: (1) the exploration, development and production of natural gas, NGLs, and oil; (2) marketing and utilization of excess firm transportation capacity gathering and processing; and (3) equity method investment in Antero Midstream Corporation. Revenues from Antero Midstream Corporation’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream Partners. All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided by Antero Midstream Partners, which we capitalized as proved property development costs. Through March 12, 2019, the results of Antero Midstream Partners were included in our consolidated financial statements. Effective March 13, 2019, the results of Antero Midstream Partners are no longer included in our results; however, our disclosures include the segments of our unconsolidated affiliates due to their significance to our operations. See Note 3—Deconsolidation of Antero Midstream Partners LP and Note 18—Segment Information to the unaudited condensed consolidated financial statements. 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.
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Three Months Ended September 30, 2019 Compared to Three Months Ended September 30, 2020
The operating results of our reportable segments were as follows for the three months ended September 30, 2019 and 2020 (in thousands):
Equity Method
Elimination of
Investment in
intersegment
Exploration
Antero
transactions and
and
Midstream
unconsolidated
Consolidated
production
Marketing
Corporation
affiliates
total
Three months ended September 30, 2019:
Revenue and other:
Natural gas sales
$
524,448
—
—
—
524,448
Natural gas liquids sales
284,958
—
—
—
284,958
Oil sales
40,561
—
—
—
40,561
Commodity derivative fair value gains
220,788
—
—
—
220,788
Gathering, compression, water handling and treatment
—
—
272,658
(272,658)
—
Marketing
—
46,645
—
—
46,645
Other income (loss)
1,481
—
(28,863)
28,863
1,481
Total
$
1,072,236
46,645
243,795
(243,795)
1,118,881
Operating expenses:
Lease operating
$
35,928
—
49,050
(49,050)
35,928
Gathering and compression
209,752
—
13,091
(13,091)
209,752
Processing
230,377
—
—
—
230,377
Transportation
163,731
—
—
—
163,731
Production and ad valorem taxes
28,863
—
1,179
(1,179)
28,863
Marketing
—
108,216
—
—
108,216
Exploration
208
—
—
—
208
Impairment of oil and gas properties
1,041,469
—
—
—
1,041,469
Impairment of midstream assets
—
—
465,278
(457,478)
7,800
Depletion, depreciation, and amortization
241,503
—
24,460
(24,460)
241,503
Accretion of asset retirement obligations
927
—
54
(54)
927
General and administrative (excluding equity-based compensation)
32,048
—
10,466
(10,466)
32,048
Equity-based compensation
3,875
—
20,129
(20,129)
3,875
Change in fair value of contingent acquisition consideration
—
—
1,977
(1,977)
—
Contract termination and rig stacking
62
—
—
—
62
Total
1,988,743
108,216
585,684
(577,884)
2,104,759
Operating income (loss)
$
(916,507)
(61,571)
(341,889)
334,089
(985,878)
Equity in earnings of unconsolidated affiliates
$
(117,859)
—
18,478
(18,478)
(117,859)
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Equity Method
Elimination of
Investment in
intersegment
Exploration
Antero
transactions and
and
Midstream
unconsolidated
Consolidated
production
Marketing
Corporation
affiliates
total
Three months ended September 30, 2020:
Revenue and other:
Natural gas sales
$
436,304
—
—
—
436,304
Natural gas liquids sales
327,426
—
—
—
327,426
Oil sales
34,265
—
—
—
34,265
Commodity derivative fair value losses
(514,751)
—
—
—
(514,751)
Gathering, compression, water handling and treatment
—
—
251,215
(251,215)
—
Marketing
—
91,497
—
—
91,497
Amortization of deferred revenue, VPP
5,175
—
—
—
5,175
Other income
675
—
(17,800)
17,800
675
Total
$
289,094
91,497
233,415
(233,415)
380,591
Operating expenses:
Lease operating
$
21,450
—
—
—
21,450
Gathering and compression
221,004
—
38,052
(38,052)
221,004
Processing
244,888
—
—
—
244,888
Transportation
190,723
—
—
—
190,723
Production and ad valorem taxes
25,790
—
—
—
25,790
Marketing
—
128,580
—
—
128,580
Exploration
454
—
—
—
454
Impairment of oil and gas properties
29,392
—
—
—
29,392
Impairment of midstream assets
—
—
947
(947)
—
Depletion, depreciation, and amortization
238,418
—
26,801
(26,801)
238,418
Accretion of asset retirement obligations
1,115
—
39
(39)
1,115
General and administrative (excluding equity-based compensation)
25,941
—
9,554
(9,554)
25,941
Equity-based compensation
5,699
—
3,678
(3,678)
5,699
Contract termination and rig stacking and other expenses
1,246
—
2,527
(2,527)
1,246
Total
1,006,120
128,580
81,598
(81,598)
1,134,700
Operating income (loss)
$
(717,026)
(37,083)
151,817
(151,817)
(754,109)
Equity in earnings of unconsolidated affiliates
$
24,419
—
23,173
(23,173)
24,419
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Exploration and Production Segment Results for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020
The following table sets forth selected operating data of the exploration and production segment for the three months ended September 30, 2019 compared to the three months ended September 30, 2020:
Three months ended
Amount of
September 30,
Increase
Percent
2019
2020
(Decrease)
Change
Production data (1) :
Natural gas (Bcf)
210
226
16
8
%
C2 Ethane (MBbl)
4,307
5,459
1,152
27
%
C3+ NGLs (MBbl)
11,472
13,400
1,928
17
%
Oil (MBbl)
865
1,367
502
58
%
Combined (Bcfe)
310
347
37
12
%
Daily combined production (MMcfe/d)
3,367
3,772
405
12
%
Average prices before effects of derivative settlements (2) :
Natural gas (per Mcf)
$
2.50
$
1.93
$
(0.57)
(23)
%
C2 Ethane (per Bbl)
$
6.15
$
5.94
$
(0.21)
(3)
%
C3+ NGLs (per Bbl)
$
22.53
$
22.01
$
(0.52)
(2)
%
Oil (per Bbl)
$
46.86
$
25.07
$
(21.79)
(47)
%
Weighted Average Combined (per Mcfe)
$
2.74
$
2.30
$
(0.44)
(16)
%
Average realized prices after effects of derivative settlements (2) :
Natural gas (per Mcf)
$
3.05
$
2.73
$
(0.32)
(10)
%
C2 Ethane (per Bbl)
$
6.15
$
5.67
$
(0.48)
(8)
%
C3+ NGLs (per Bbl)
$
22.67
$
23.81
$
1.14
5
%
Oil (per Bbl)
$
50.00
$
34.96
$
(15.04)
(30)
%
Weighted Average Combined (per Mcfe)
$
3.13
$
2.92
$
(0.21)
(7)
%
Average costs (per Mcfe):
Lease operating
$
0.12
$
0.06
$
(0.06)
(50)
%
Gathering and compression
$
0.68
$
0.64
$
(0.04)
(6)
%
Processing
$
0.74
$
0.71
$
(0.03)
(4)
%
Transportation
$
0.53
$
0.55
$
0.02
4
%
Production taxes
$
0.09
$
0.07
$
(0.02)
(22)
%
Marketing, net
$
0.20
$
0.11
$
(0.09)
(45)
%
Depletion, depreciation, amortization and accretion
$
0.78
$
0.69
$
(0.09)
(12)
%
General and administrative (excluding equity-based compensation)
$
0.10
$
0.07
$
(0.03)
(30)
%
(1) Production data excludes volumes related to the VPP.
(2) 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 $524 million for the three months ended September 30, 2019 to $436 million for the three months ended September 30, 2020, a decrease of $88 million, or 17% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Higher natural gas production volumes during the three months ended September 30, 2020 accounted for an approximate $40 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 $128 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).
NGLs sales . Revenues from production of NGLs increased from $285 million for the three months ended September 30, 2019 to $327 million for the three months ended September 30, 2020, an increase of $42 million, or 15% (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 $50 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 $8
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million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).
Oil sales . Revenues from production of oil decreased from $41 million for the three months ended September 30, 2019 to $34 million for the three months ended September 30, 2020, a decrease of $7 million, or 16% (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 $23 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 $30 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 $120 million and $234 million gains on cash settled derivatives for the three months ended September 30, 2019 and 2020, respectively. For the three months ended September 30, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $221 million and losses of $515 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.
Amortization of deferred revenue, VPP. The three months ended September 30, 2020 include amortization of $5 million of deferred revenues associated with the VPP, which relate to the production volumes delivered under the terms of the agreement during such period at approximately $1.61 per MMBtu. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on this transaction.
Other income . Other income remained relatively consistent at $1 million for the three months ended September 30, 2019 and 2020.
Lease operating expense . Lease operating expense decreased from $36 million for the three months ended September 30, 2019 to $21 million for the three months ended September 30, 2020, a decrease of $15 million, or 40%. On a per unit basis, lease operating expenses decreased from $0.12 for the three months ended September 30, 2019 to $0.06 for the three months ended September 30, 2020, primarily due to lower 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 by $53 million, or 9%, from $604 million for the three months ended September 30, 2019 to $657 million for the three months ended September 30, 2020 primarily due to a 12% increase in production, partially offset by lower costs between periods. Gathering and compression costs decreased from $0.68 per Mcfe to $0.64 per Mcfe primarily as a result of lower fuel costs as a result of decreased natural gas prices and a $12 million incentive fee rebate from Antero Midstream Corporation. Processing costs primarily decreased from $0.74 to $0.71 per Mcfe as a result of decreased terminal fees at Mariner East 2. Our transportation costs increased from $0.53 per Mcfe to $0.55 per Mcfe due to increased rates on the Rockies Express pipeline.
Production and ad valorem tax expense. Production and ad valorem taxes decreased from $29 million for the three months ended September 30, 2019 to $26 million for the three months ended September 30, 2020, a decrease of $3 million, or 11%. This decrease is primarily as a result of decreases in commodity prices. Production and ad valorem taxes as a percentage of natural gas revenues was relatively consistent at 6% in the three months ended September 30, 2019 and 2020.
Impairment of oil and gas properties . During the three months ended September 30, 2019, we recognized an $881 million impairment to write-down our Utica Shale proved properties to fair value because the carrying value of such properties exceeded the estimated undiscounted cash flows based on future strip commodity prices as of September 30, 2019. We also recorded $160 million of impairments for the three months ended September 30, 2019 related to expiring leases and the design and initial costs related to pads we no longer plan to place into service. During the three months ended September 30, 2020, we recognized impairment of $29 million primarily related to expiring leases and the design and initial costs related to pads we no longer plan to place into service.
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Depletion, depreciation, and amortization expense (“DD&A”) . DD&A expense decreased from $242 million for the three months ended September 30, 2019 to $238 million for the three months ended September 30, 2020, a decrease of $4 million, or 1%. DD&A per Mcfe decreased from $0.78 per Mcfe during the three months ended September 30, 2019 to $0.69 per Mcfe during the three months ended September 30, 2020, primarily due to a lower depletable cost basis as a result of the Utica proved property impairment of $881 million in 2019, which was partially offset by downward reserve revisions that resulted from lower SEC prices between periods.
General and administrative expense . General and administrative expense (excluding equity-based compensation expense) was $32 million for the three months ended September 30, 2019 and $26 million for the three months ended September 30, 2020, a decrease of $6 million, or 19%. This decrease was primarily due to decreases in employee related expenses in the three months ended September 30, 2020 as a result of ongoing cost savings initiatives related to lower headcount in 2020. We had 569 employees as of September 30, 2019 and 520 employees as of September 30, 2020. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 30%, from $0.10 per Mcfe during the three months ended September 30, 2019 to $0.07 per Mcfe during the three months ended September 30, 2020 as a result of higher production volumes and lower overall costs between periods.
Equity-based compensation expense . Noncash equity-based compensation expense was $4 million for the three months ended September 30, 2019 and $6 million for the three months ended September 30, 2020, an increase of $2 million, or 47%. This increases was primarily due to new equity-based compensation awards granted in the three months ended September 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 less than $1 million during the three months ended September 30, 2019 compared to $1 million for the three months ended September 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 September 30, 2019 Compared to the Three Months Ended September 30, 2020
Marketing. 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 $62 million, or $0.20 per Mcfe, for the three months ended September 30, 2019 to $37 million, or $0.11 per Mcfe, for the three months ended September 30, 2020. The decrease was driven by higher volumes and the mitigation of some of our excess firm transportation expense.
Marketing revenues increased from $47 million for the three months ended September 30, 2019 to $92 million for the three months ended September 30, 2020, an increase of $45 million, or 96%. Marketing expenses increased from $108 million for the three months ended September 30, 2019 to $129 million for the three months ended September 30, 2020, an increase of $21 million, or 19%. 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 $62 million and $32 million for the three months ended September 30, 2019 and 2020, respectively.
Discussion of Antero Midstream Corporation Segment for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020
Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment decreased from $244 million for the three months ended September 30, 2019 to $235 million for the three months ended September 30, 2020, a decrease of $9 million, or 4%, primarily due to a reduction in water handling revenues. Total operating expenses related to the segment decreased from $586 million for the three months ended September 30, 2019 to $82 million for the three months ended September 30, 2020. The decrease was primarily due to impairment expense of $457 million on Antero Midstream Corporation’s wastewater treatment facility and related goodwill and customer relationships in the three months ended September 30, 2019.
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Table of Contents
Discussion of Items Not Allocated to Segments for the Three Months Ended September 30, 2019 Compared to the Three Months Ended September 30, 2020
Interest expense. Our interest expense was relatively flat at $48 million for each of the three months ended September 30, 2019 and 2020 due to lower total indebtedness resulting from repurchases of our unsecured senior notes at prices below their stated value, partially offset by the interest that accrued on the newly issued 2026 Convertible Notes (as defined below). Interest expense included approximately $2.6 million and $3.1 million of non-cash amortization of deferred financing costs for the three months ended September 30, 2019 and 2020, respectively.
Transaction expense. We incurred transaction expense of less than $1 million in the three months ended September 30, 2020 and did not incur comparable costs in the three months ended September 30, 2019. These expenses included legal and transaction fees associated with the ORRI transaction. See Note 4—Transactions 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 benefit . Income tax benefit decreased from a deferred tax benefit of $273 million, with an effective tax rate of 24%, for the three months ended September 30, 2019 to a deferred tax benefit of $169 million, with an effective tax rate of 23%, for the three months ended September 30, 2020. The change was primarily a result of an increase in book income due to the impairment of proved properties in the Utica Shale in the prior period.
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Table of Contents
Nine months ended September 30, 2019 Compared to Nine months ended September 30, 2020
The operating results of our reportable segments were as follows for the nine months ended September 30, 2019 and 2020 (in thousands):
Equity Method
Elimination of
Investment in
intersegment
Exploration
Antero
transactions and
and
Midstream
unconsolidated
Consolidated
production
Marketing
Corporation
affiliates
total
Nine months ended September 30, 2019:
Revenue and other:
Natural gas sales
$
1,735,086
—
—
—
1,735,086
Natural gas liquids sales
902,606
—
—
—
902,606
Oil sales
137,675
—
—
—
137,675
Commodity derivative fair value gains
471,847
—
—
—
471,847
Gathering, compression, water handling and treatment
—
—
592,699
(588,220)
4,479
Marketing
—
200,911
—
—
200,911
Other income
4,999
—
(39,178)
37,527
3,348
Total
$
3,252,213
200,911
553,521
(550,693)
3,455,952
Operating expenses:
Lease operating
119,754
—
111,427
(112,664)
118,517
Gathering and compression
632,733
—
28,324
(138,810)
522,247
Processing
593,394
—
—
—
593,394
Transportation
479,582
—
—
—
479,582
Production and ad valorem taxes
94,569
—
2,549
(1,609)
95,509
Marketing
—
408,839
—
—
408,839
Exploration
648
—
—
—
648
Impairment of oil and gas properties
1,253,712
—
—
—
1,253,712
Impairment of midstream assets
—
—
472,854
(458,072)
14,782
Depletion, depreciation, and amortization
702,299
—
68,557
(46,850)
724,006
Loss on sale of assets
951
—
—
—
951
Accretion of asset retirement obligations
2,758
133
(70)
2,821
General and administrative (excluding equity-based compensation)
111,363
—
31,931
(16,114)
127,180
Equity-based compensation
16,850
—
53,095
(50,618)
19,327
Change in fair value of contingent acquisition consideration
—
—
5,323
(5,323)
—
Contract termination and rig stacking
14,026
—
—
—
14,026
Total
4,022,639
408,839
774,193
(830,130)
4,375,541
Operating income (loss)
$
(770,426)
(207,928)
(220,672)
279,437
(919,589)
Equity in earnings of unconsolidated affiliates
$
(102,457)
—
34,981
(22,717)
(90,193)
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Table of Contents
Equity Method
Elimination of
Investment in
intersegment
Exploration
Antero
transactions and
and
Midstream
unconsolidated
Consolidated
production
Marketing
Corporation
affiliates
total
Nine months ended September 30, 2020:
Revenue and other:
Natural gas sales
$
1,214,801
—
—
—
1,214,801
Natural gas liquids sales
797,296
—
—
—
797,296
Oil sales
78,233
—
—
—
78,233
Commodity derivative fair value losses
(116,933)
—
—
—
(116,933)
Gathering, compression, water handling and treatment
—
—
749,870
(749,870)
—
Marketing
—
201,855
—
—
201,855
Amortization of deferred revenue, VPP
5,175
—
—
—
5,175
Other income
2,180
—
(53,011)
53,011
2,180
Total
$
1,980,752
201,855
696,859
(696,859)
2,182,607
Operating expenses:
Lease operating
$
71,836
—
—
—
71,836
Gathering and compression
616,785
—
128,847
(128,847)
616,785
Processing
697,716
—
—
—
697,716
Transportation
562,583
—
—
—
562,583
Production and ad valorem taxes
71,481
—
—
—
71,481
Marketing
—
334,906
—
—
334,906
Exploration
895
—
—
—
895
Impairment of oil and gas properties
155,962
—
—
—
155,962
Impairment of midstream assets
—
—
665,491
(665,491)
—
Depletion, depreciation, and amortization
652,130
—
81,889
(81,889)
652,130
Accretion of asset retirement obligations
3,330
—
142
(142)
3,330
General and administrative (excluding equity-based compensation)
84,263
—
29,478
(29,478)
84,263
Equity-based compensation
17,001
—
9,713
(9,713)
17,001
Contract termination and rig stacking and other expenses
12,317
—
13,920
(13,920)
12,317
Total
2,946,299
334,906
929,480
(929,480)
3,281,205
Operating loss
$
(965,547)
(133,051)
(232,621)
232,621
(1,098,598)
Equity in earnings (loss) of unconsolidated affiliates
$
(83,408)
—
63,197
(63,197)
(83,408)
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Table of Contents
Exploration and Production Segment Results for the Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020
The following table sets forth selected operating data of the exploration and production segment for the nine months ended September 30, 2019 compared to the nine months ended September 30, 2020:
Nine months ended
Amount of
September 30,
Increase
Percent
2019
2020
(Decrease)
Change
Production data (1) :
Natural gas (Bcf)
617
649
32
5
%
C2 Ethane (MBbl)
11,536
14,686
3,150
27
%
C3+ NGLs (MBbl)
29,842
36,167
6,325
21
%
Oil (MBbl)
2,823
3,308
485
17
%
Combined (Bcfe)
882
974
92
10
%
Daily combined production (MMcfe/d)
3,232
3,554
322
10
%
Average prices before effects of derivative settlements (2) :
Natural gas (per Mcf)
$
2.81
$
1.87
$
(0.94)
(33)
%
C2 Ethane (per Bbl)
$
8.01
$
5.85
$
(2.16)
(27)
%
C3+ NGLs (per Bbl)
$
27.15
$
19.67
$
(7.48)
(28)
%
Oil (per Bbl)
$
48.77
$
23.65
$
(25.12)
(52)
%
Weighted Average Combined (per Mcfe)
$
3.15
$
2.15
$
(1.00)
(32)
%
Average realized prices after effects of derivative settlements (2) :
Natural gas (per Mcf)
$
3.23
$
2.80
$
(0.43)
(13)
%
C2 Ethane (per Bbl)
$
8.01
$
5.72
$
(2.29)
(29)
%
C3+ NGLs (per Bbl)
$
27.24
$
22.25
$
(4.99)
(18)
%
Oil (per Bbl)
$
50.16
$
38.00
$
(12.16)
(24)
%
Weighted Average Combined (per Mcfe)
$
3.44
$
2.91
$
(0.53)
(15)
%
Average costs (per Mcfe):
Lease operating
$
0.14
$
0.07
$
(0.07)
(50)
%
Gathering and compression
$
0.72
$
0.63
$
(0.09)
(13)
%
Processing
$
0.67
$
0.72
$
0.05
7
%
Transportation
$
0.54
$
0.58
$
0.04
7
%
Production and ad valorem taxes
$
0.11
$
0.07
$
(0.04)
(36)
%
Marketing expense, net
$
0.24
$
0.14
$
(0.10)
(42)
%
Depletion, depreciation, amortization, and accretion
$
0.80
$
0.67
$
(0.13)
(16)
%
General and administrative (excluding equity-based compensation)
$
0.13
$
0.09
$
(0.04)
(31)
%
(1) Production data excludes volumes related to the VPP.
(2) 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 $1.7 billion for the nine months ended September 30, 2019 to $1.2 billion for the nine months ended September 30, 2020, a decrease of $520 million, or 30% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Higher natural gas production volumes during the nine months ended September 30, 2020 accounted for an approximate $90 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 $610 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).
NGLs sales . Revenues from production of NGLs decreased from $903 million for the nine months ended September 30, 2019 to $797 million for the nine months ended September 30, 2020, a decrease of $106 million, or 12% (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 $196 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 $302
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million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes).
Oil sales . Revenues from production of oil decreased from $138 million for the nine months ended September 30, 2019 to $78 million for the nine months ended September 30, 2020, a decrease of $59 million, or 43% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased oil production volumes accounted for a $24 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 $83 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 $262 million and $759 million of gains on cash settled derivatives for the nine months ended September 30, 2019 and 2020, respectively. For the nine months ended September 30, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $472 million and losses of $117 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.
Amortization of deferred revenue, VPP. The nine months ended September 30, 2020 include amortization of $5 million of deferred revenues associated with the VPP, which relate to the production volumes delivered under the terms of the agreement during such period at approximately $1.61 per MMBtu. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on this transaction.
Other income . Other income remained relatively consistent at $3 million and $2 million for the nine months ended September 30, 2019 and 2020, respectively.
Lease operating expense . Lease operating expense decreased from $119 million for the nine months ended September 30, 2019 to $72 million for the nine months ended September 30, 2020, a decrease of $47 million, or 39%. On a per unit basis, lease operating expenses decreased from $0.14 per Mcfe for the nine months ended September 30, 2019 to $0.07 per Mcfe for the nine months ended September 30, 2020 primarily due to lower 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 by $282 million, or 18%, from $1.6 billion for the nine months ended September 30, 2019 to $1.9 billion for the nine months ended September 30, 2020 primarily due to a 10% increase in production between periods as well as higher processing and transportation costs. Gathering and compression costs decreased from $0.72 per Mcfe for the nine months ended September 30, 2019 to $0.63 per Mcfe for the nine months ended September 30, 2020 primarily due to lower fuel costs as a result of decreased natural gas prices and $36 million in incentive fee rebates from Antero Midstream Corporation. Processing costs primarily increased from $0.67 per Mcfe to $0.72 per Mcfe for the nine months ended September 30, 2019 and 2020, respectively, due to increased NGL production in our production mix. Processing costs, however, remained relatively unchanged per NGL barrel. Transportation costs increased from $0.54 per Mcfe to $0.58 per Mcfe for the nine months ended September 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 $96 million for the nine months ended September 30, 2019 to $72 million for the nine months ended September 30, 2020, a decrease of $24 million, or 25% primarily due to lower in commodity prices between periods. Production and ad valorem taxes as a percentage of natural gas revenues was relatively consistent at 6% in each of the nine months ended September 30, 2019 and 2020.
Impairment of oil and gas properties . During the nine months ended September 30, 2019, we recognized an $881 million impairment to write-down our Utica Shale proved properties to fair value because the carrying value of such properties exceeded the
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estimated undiscounted cash flows based on future strip commodity prices as of September 30, 2019. We also recorded $373 million of impairments for the nine months ended September 30, 2019 related to expiring leases and the design and initial costs related to pads we no longer plan to place into service. During the nine months ended September 30, 2020 we recognized impairment of $156 million 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 expense decreased from $724 million for the nine months ended September 30, 2019 to $652 million for the nine months ended September 30, 2020, a decrease of $72 million, or 10%. DD&A per Mcfe decreased from $0.80 per Mcfe during the nine months ended September 30, 2019 to $0.67 per Mcfe during the nine months ended September 30, 2020, primarily due to a lower depletable cost basis as a result of the Utica proved property impairment of $881 million in 2019, partially offset by downward reserve revisions that resulted from lower SEC prices between periods.
General and administrative expense . General and administrative expense (excluding equity-based compensation expense) was $127 million for the nine months ended September 30, 2019 and $84 million for the nine months ended September 30, 2020, a decrease of $43 million, or 34%. This decrease was primarily due to decreases in employee related expenses in the nine months ended September 30, 2020 as a result of ongoing cost savings initiatives related to lower headcount in 2020. We had 569 employees as of September 30, 2019 and 520 employees as of September 30, 2020. On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 31%, from $0.13 per Mcfe during the nine months ended September 30, 2019 to $0.09 per Mcfe during the nine months ended September 30, 2020 as a result of higher production volumes and lower overall costs between periods.
Equity-based compensation expense . Noncash equity-based compensation expense decreased from $19 million for the nine months ended September 30, 2019 to $17 million for the nine months ended September 30, 2020, a decrease of $2 million, or 12%. 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 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 $14 million during the nine months ended September 30, 2019 compared to $12 million for the nine months ended September 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 Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020
Marketing. 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, in order to reduce our net costs related to the unused capacity under these transportation agreements.
Our net marketing expense decreased from $208 million, or $0.24 per Mcfe, for the nine months ended September 30, 2019 to $133 million, or $0.14 per Mcfe, for the nine months ended September 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 $201 million and $202 million for the nine months ended September 30, 2019 and 2020, respectively.
Marketing expenses decreased from $409 million for the nine months ended September 30, 2019 to $335 million for the nine months ended September 30, 2020, a decrease of $74 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 $127 million and $122 million for the nine months ended September 30, 2019 and 2020, respectively.
Discussion of Antero Midstream Corporation Segment for the Nine months ended September 30, 2019 Compared to the Nine months ended September 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 nine months
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ended September 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.
Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment increased from $554 million for the nine months ended September 30, 2019 to $697 million for the nine months ended September 30, 2020, an increase of $143 million, or 26%, primarily due to the nine months ended September 30, 2019 only including Antero Midstream Corporation’s results following the closing of the simplification transactions on March 12, 2019. Total operating expenses related to the segment increased from $774 million for the nine months ended September 30, 2019 to $929 million for the nine months ended September 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 expense of $575 million on its goodwill.
Discussion of Items Not Allocated to Segments for the Nine months ended September 30, 2019 Compared to the Nine months ended September 30, 2020
Impairment of equity investment . At March 31, 2020, we determined that events and circumstances indicated that the carrying value of our equity method investment in Antero Midstream Corporation had experienced an other-than-temporary decline and we recorded an impairment of $611 million. The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation at March 31, 2020.
Interest expense. Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $157 million for the nine months ended September 30, 2019 to $153 million for the nine months ended September 30, 2020 primarily due to the reduction in debt as a result of our debt repurchases of our unsecured senior notes at prices below their stated value, partially offset by interest that accrued on the newly issued 2026 Convertible Notes.
Consolidated interest expense decreased from $174 million for the nine months ended September 30, 2019 to $153 million for the nine months ended September 30, 2020, a decrease of $21 million, or 12%. During the nine months ended September 30, 2019, interest related to Antero Midstream Partners’ debt through March 12, 2019 is included in consolidated interest expense. Interest expense includes approximately $8.3 million and $8.0 million of non-cash amortization of deferred financing costs for the nine months ended September 30, 2019 and 2020, respectively.
Transaction expense. We incurred transaction expense of $7 million in the nine months ended September 30, 2020 and did not incur comparable costs in the nine months ended September 30, 2019. These expenses included legal and transaction fees associated with the sale of our ORRI and the creation of Martica, as well as the VPP transaction. See Note 4—Transactions to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on these transactions.
Income tax expense/benefit . Income tax expense decreased from a deferred tax expense of $33 million, with an effective tax rate of 15%, for the nine months ended September 30, 2019 to a deferred tax benefit of $421 million, with an effective tax rate of 24%, for the nine months ended September 30, 2020. The change was primarily a result of an increase in book income due to the simplification transactions and the associated deconsolidation of Antero Midstream Partners for the nine months ended September 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 nine months ended September 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, 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. As we develop our reserves, we continually monitor what capital resources, including equity and debt financings, are available to meet our future financial obligations, planned capital expenditure activities, and liquidity requirements. 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.
During the nine months ended September 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 nine months ended September 30, 2020.
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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 and nine months ended September 30, 2020, we repurchased $461 million and $1.1 billion, respectively, principal amount of debt at a weighted average discount of 13% and 17%, respectively, which purchases included a portion of the 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes. Repurchases of the principal amount of debt during the three and nine months ended September 30, 2020 include repurchases of $367 million on the 2021 Notes, 2022 Notes and 2023 Notes through previously disclosed tender offers at a weighted average discount of 10%. These repurchases, at a discount, have resulted in a net reduction in total debt outstanding and interest expense.
As of September 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. Under our business plan, we intend to extinguish the 2021 Notes prior to August 1, 2021 with proceeds from our asset sales program, cash flow from operations and available borrowings under the Credit Facility. Consequently, we have classified our Credit Facility as long-term debt. The classification of our Credit Facility does not impact any of our financial covenants.
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 nine months ended September 30, 2019 and 2020:
Nine Months Ended
September 30,
Increase
(in thousands)
2019
2020
(Decrease)
Net cash provided by operating activities
$
955,518
492,510
(463,008)
Net cash used in investing activities
(825,327)
(384,063)
441,264
Net cash provided by (used in) financing activities
489,341
(108,447)
(597,788)
Effect of deconsolidation of Antero Midstream Partners LP
(619,532)
—
619,532
Net increase (decrease) in cash and cash equivalents
$
—
—
—
The Company's condensed consolidated cash flow statements for the nine months ended September 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 nine months ended September 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 $956 million and $493 million for the nine months ended September 30, 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, processing, and transportation costs.
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. Prices for natural gas, NGLs, and oil are primarily determined by prevailing market conditions. Regional and worldwide economic activity, weather, infrastructure capacity to reach markets, storage capacity and other variables influence the market conditions for these products. For example, the impact of the COVID-19 outbreak has reduced domestic and international demand for natural gas, NGLs, and oil. These factors are beyond our control and are difficult to predict.
Cash Flows Used in Investing Activities
Cash flows used in investing activities decreased from $825 million for the nine months ended September 30, 2019 to $384 million for the nine months ended September 30, 2020, primarily due to a decrease in capital expenditures of $307 million during the
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nine months ended September 30, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the simplification transactions impacting the nine months ended September 30, 2019 and $125 million in settlement of the water earnout impacting the nine months ended September 30, 2020.
In addition, the nine months ended September 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 nine months ended September 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.
Total capital expenditures for oil and gas properties decreased from $1.0 billion during the nine months ended September 30, 2019 to $726 million during the nine months ended September 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. Our capital budget may be adjusted as business conditions warrant as the amount, timing, and allocation of capital expenditures is largely discretionary and within our control. If natural gas, NGLs, and oil prices decline to levels that do not generate an acceptable level of corporate returns, or costs increase to levels that do not generate an acceptable level of corporate returns, we may defer a significant portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity, and to prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flows. We routinely monitor and adjust our capital expenditures in response to changes in commodity prices, availability of financing, drilling and acquisition costs, industry conditions, the timing of regulatory approvals, the availability of rigs, the relative success in drilling activities, contractual obligations, internally generated cash flows, and other factors both within and outside our control.
Cash Flows Provided by (Used in) Financing Activities
Net cash flows provided by financing activities was $489 million for the nine months ended September 30, 2019, compared to net cash flows provided by financing activities of $108 million for the nine months ended September 30, 2020. This decrease was primarily due to the issuance of senior notes by Antero Midstream Partners prior to the simplification 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 nine months ended September 30, 2020, we received $300 million for the sale of a noncontrolling interest in Martica and issued $288 million principal amount of the 2026 Convertible Notes. See Note 4—Transactions and Note 8—Long-Term Debt for more information on these transactions, respectively.
Net borrowings (repayments) on our Credit Facility and Antero Midstream Partners’ credit facility changed from net repayments of $45 million during the nine months ended September 30, 2019 to net borrowings of $275 million during the nine months ended September 30, 2020. In the nine months ended September 30, 2020, approximately $900 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 nine months ended September 30, 2020 compared to repurchases of common stock of $18 million during the nine months ended September 30, 2019. We did not repurchase any of our unsecured notes during the nine months ended September 30, 2019.
Debt Agreements and Contractual Obligations
Senior Secured Revolving Credit Facility . Our Credit Facility is with a consortium of bank lenders. 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 re-affirmed in October 2020 at $2.85 billion and lender commitments are $2.64 billion. The next redetermination of the borrowing base is scheduled to occur in April 2021. 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 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. As of September 30, 2020, we had $827 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 nine months ended September 30, 2020 was approximately 3.28%. Our Credit Facility provides for borrowing under either LIBOR or an Alternative Rate of Interest.
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We were in compliance with the applicable covenants and ratios as of December 31, 2019 and September 30, 2020. As of September 30, 2020, our current ratio was 2.41 to 1.0 and our interest coverage ratio was 7.78 to 1.0.
For more information on the terms, conditions, and restrictions under the Credit Facility, please refer to the 2019 Form 10-K.
Senior Notes . 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 the 2019 Form 10-K for information on our senior notes.
We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, or otherwise. Such repurchases, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions, and other factors. The amounts involved could be material. During the nine months ended September 30, 2020, we repurchased $1.1 billion principal amount of debt at a 17% weighted average discount, including a portion of our 2021 Notes, 2022 Notes, 2023 Notes and 2025 Notes.
Convertible Senior Notes. On August 21, 2020, we issued $250 million in aggregate principal amount of 4.25% Convertible Senior Notes due September 1, 2026 (the “2026 Convertible Notes”). On September 2, 2020, we issued an additional $37.5 million aggregate principal amount of 2026 Convertible Notes pursuant to the partial exercise of the initial purchasers’ option to purchase additional 2026 Convertible Notes. The 2026 Convertible Notes were issued pursuant to an indenture and are senior, unsecured obligations of Antero Resources and were issued in a private offering to qualified institutional buyers pursuant to Rule 144A under the Securities Act of 1933, as amended. The 2026 Convertible Notes bear interest at a fixed rate of 4.25% per annum, payable semi-annually in arrears on March 1 and September 1 of each year, commencing on March 1, 2021. Proceeds from the issuance of the 2026 Convertible Notes totaled $278.6 million, net of initial purchasers’ fees and issuance costs of $8.9 million. We used the net proceeds from this issuance to repay a portion of the debt outstanding under its Credit Facility. Please refer to Note 8—Long Term Debt to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q for more information.
Contractual Obligations . A summary of our contractual obligations as of September 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.
Remainder
Year ended December 31,
(in millions)
of 2020
2021
2022
2023
2024
2025
Thereafter
Total
Recorded contractual obligations:
Credit Facility (1)
$
—
827
—
—
—
—
—
827
Antero senior notes—principal (2)
—
315
661
579
—
590
288
2,433
Antero senior notes—interest (2)
42
124
107
56
40
25
11
405
Operating leases (3)
66
247
267
301
335
307
1,139
2,662
Finance leases (3)
—
1
—
—
—
—
—
1
Imputed interest for leases (3)
91
344
312
274
232
187
419
1,859
Asset retirement obligations (4)
—
—
—
—
—
—
59
59
Unrecorded contractual obligations:
Firm transportation (5)
278
1,076
1,034
1,061
1,021
981
6,941
12,392
Processing, gathering, and compression services (6)
14
55
53
59
59
47
106
393
Drilling and completion
2
—
—
—
—
—
—
2
Land payment obligations (7)
2
3
—
—
—
—
—
5
Total
$
495
2,992
2,434
2,330
1,687
2,137
8,963
21,038
(1) Includes outstanding principal amounts as of September 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, which is August 1, 2021 if the 2021 Notes are not repaid prior to such date. Under our business plan, we intend to extinguish the 2021 Notes prior to August 1, 2021 with proceeds from our asset sales program, cash flow from operations and available borrowings under our Credit Facility. Consequently, we have classified our Credit Facility as long-term debt.
(2) Our senior notes include our 2021 Notes, 2022 Notes, 2023 Notes, 2025 notes and 2026 Convertible Notes.
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(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. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests. 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. Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance; however, we believe it is likely that a very small amount of these obligations will be settled within the next five years.
(5) Includes firm transportation agreements with various pipelines in order to facilitate the delivery of our production to market. These contracts commit us to transport minimum daily natural gas or NGLs volumes at negotiated rates, or pay for any deficiencies at specified reservation fee rates. The amounts in this table reflect our minimum daily volumes at the reservation fee rates. The values in the table represent the gross amounts that we are committed to pay; however, we will record in our financial statements our proportionate share of costs based on our working interests and net of any f ees for excess firm transportation marketed to third parties . None of these agreements were determined to be leases.
(6) Contractual commitments for processing, gathering, and compression services agreements represent minimum commitments under long-term agreements not accounted for as leases. The obligations determined to be leases are included within finance and operating leases in the table above.
(7) Includes contractual commitments for land acquisition agreements. The values in the table represent the minimum payments due under these arrangements. None of these agreements were determined to be leases.
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Non-GAAP Financial Measures
Adjusted EBITDAX is a non-GAAP financial measure that we define as net income (loss), including noncontrolling interests, before interest expense, interest income, gains or losses from commodity derivatives and marketing derivatives, amortization of deferred revenue, but including net cash receipts or payments on derivative instruments included in derivative gains or losses other than proceeds from derivative monetizations, income taxes, impairments, depletion, depreciation, amortization, and accretion, exploration expense, equity-based compensation, gain or loss on early extinguishment of debt, contract termination and rig stacking costs, loss on sale of equity investment shares, equity in earnings or loss of unconsolidated affiliates, water earnout, simplification transaction fees, gain or loss on sale of assets and Antero Midstream Partners related adjustments.
Through March 12, 2019, the financial results of Antero Midstream Partners were included in our consolidated results. 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 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.
Adjusted EBITDAX as used and defined by us, may not be comparable to similarly titled measures employed by other companies and is not a measure of performance calculated in accordance with GAAP. Adjusted EBITDAX should not be considered in isolation or as a substitute for operating income or loss, net income or loss, cash flows provided by operating, investing, and financing activities, or other income or cash flow statement data prepared in accordance with GAAP. Adjusted EBITDAX provides no information regarding our capital structure, borrowings, interest costs, capital expenditures, working capital movement, or tax position. Adjusted EBITDAX does not represent funds available for discretionary use because those funds may be required for debt service, capital expenditures, working capital, income taxes, exploration expenses, and other commitments and obligations. However, our management team believes Adjusted EBITDAX is useful to an investor in evaluating our financial performance because this measure:
● is widely used by investors in the oil and natural gas industry to measure operating performance without regard to items excluded from the calculation of such term, which may vary substantially from company to company depending upon accounting methods and the book value of assets, capital structure and the method by which assets were acquired, among other factors;
● helps investors to more meaningfully evaluate and compare the results of our operations from period to period by removing the effect of our capital and legal structure from our operating structure;
● is used by our management team for various purposes, including as a measure of our operating performance, in presentations to our Board of Directors, and as a basis for strategic planning and forecasting; and
● is used by our Board of Directors as a performance measure in determining executive compensation.
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 and nine months ended September 30, 2019 and 2020. 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
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in the table below as Antero Midstream Partners related adjustments. 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
Nine months ended
September 30,
September 30,
(in thousands)
2019
2020
2019
2020
Reconciliation of net income (loss) to Adjusted EBITDAX:
Net income (loss) and comprehensive income (loss) attributable to Antero Resources Corporation
$
(878,864)
(535,613)
$
142,067
(1,337,727)
Net income (loss) and comprehensive income (loss) attributable to noncontrolling interests
—
(18,233)
46,993
(17,997)
Depletion, depreciation, amortization, and accretion
242,430
239,533
726,827
655,460
Impairment of oil and gas properties
1,041,469
29,392
1,253,712
155,962
Impairment of midstream assets
7,800
—
14,782
—
Unrealized commodity derivative gains (losses)
(100,785)
748,791
(210,053)
875,811
Proceeds from derivative monetizations
—
(18,073)
—
(18,073)
Amortization of deferred revenue, VPP
—
(5,175)
—
(5,175)
Equity-based compensation expense
3,875
5,699
19,327
17,001
Provision for income tax expense (benefit)
(272,627)
(168,778)
33,332
(421,167)
Gain on early extinguishment of debt
—
(55,633)
—
(175,365)
Equity in (earnings) loss of unconsolidated affiliates
117,859
(24,419)
90,193
83,408
Impairment of equity investment
—
—
—
610,632
Gain on deconsolidation of Antero Midstream Partners LP
—
—
(1,406,042)
—
Distributions/dividends from unconsolidated affiliates
48,714
42,755
109,241
128,267
Interest expense, net
47,754
48,043
173,868
152,956
Exploration expense
208
454
648
895
Gain on sale of assets
—
—
951
—
Contract termination and rig stacking
62
1,246
14,026
12,317
Simplification transaction fees
—
—
15,482
—
Transaction expense
—
524
—
6,662
257,895
290,513
1,025,354
723,867
Antero Midstream Partners related adjustments (2)
—
—
(73,115)
—
Martica related adjustments (2)
—
(18,072)
—
(21,172)
Adjusted EBITDAX
$
257,895
272,441
$
952,239
702,695
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities:
Adjusted EBITDAX
$
257,895
272,441
$
952,239
702,695
Antero Midstream Partners related adjustments (1)
—
—
73,115
—
Martica related adjustments (2)
—
18,072
—
21,172
Interest expense, net
(47,754)
(48,043)
(173,868)
(152,956)
Exploration expense
(208)
(454)
(648)
(895)
Changes in current assets and liabilities
(13,653)
(86,618)
127,322
(78,891)
Simplification transaction fees
—
—
(15,482)
—
Transaction expense
—
(524)
—
(6,662)
Proceeds from derivative monetizations
—
18,073
—
18,073
Other items
2,130
2,923
(7,160)
(10,026)
Net cash provided by operating activities
$
198,410
175,870
$
955,518
492,510
(1) Amounts reflected are net of any elimination adjustments for intercompany activity and include activity related to Antero Midstream Partners through March 12, 2019. 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.
(2) Adjustments reflect noncontrolling interests in Martica not otherwise adjusted in amounts above.
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Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. Our more significant accounting policies and estimates include the successful efforts method of accounting for our production activities, estimates of natural gas, NGLs, and oil reserve quantities and standardized measures of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments in the 2019 Form 10-K. 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—Summary of Significant Accounting Policies to the consolidated financial statements, included in the 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. Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using future prices), we estimate the fair value of our proved properties and record an impairment charge for any excess of the carrying amount of the properties over the estimated fair value of the properties.
The estimated future net cash flows have been impacted by the COVID-19 pandemic and the decision in March 2020 by Saudi Arabia to reduce the price at which it sells oil and announcing plans to increase production. These events have caused, and continue to cause, significant volatility in future prices which are used in this evaluation. Based on future prices as of September 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 nine months ended September 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 September 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.
New Accounting Pronouncements
On August 5, 2020, the Financial Accounting Standards Board issued Accounting Standards Update No. 2020-06, Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity , which eliminates the cash conversion model in ASC 470-20 (defined below in Item 1A. Risk Factors) that require separate accounting for conversion features that is currently being applied to the 2026 Convertible Notes, and instead, allows the debt instrument and conversion features to be accounted for as a single debt instrument. The new standard becomes effective on January 1, 2022, and early adoption is permitted. We are evaluating our plans for adoption, including the adoption date and transition method.
Upon adoption of this new standard, we expect to reclassify $62 million, net of deferred income taxes and equity issuance costs, to long-term debt and deferred income tax liability, as applicable, from stockholders’ equity. Additionally, annual interest expense for the 2026 Convertible Notes will be based on an effective interest rate of 4.8% as compared to 11.7% for the three and nine months ended September 30, 2020 in the statement of operations and the weighted average diluted shares outstanding will increase from zero as of September 30, 2020 under the treasury-stock method to 66 million under the if-converted method. We do not believe that adoption of the standard will impact our operational strategies or growth prospects.
Off-Balance Sheet Arrangements
As of September 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.
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