ANTERO RESOURCES CORPORATION 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 toAntero 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 theAppalachian 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 theMarcellus Shale andUtica Shale of theAppalachian Basin . As ofMarch 31, 2020 , we held approximately 536,000 net acres of rich gas and dry gas properties located in theAppalachian Basin inWest Virginia andOhio . Our corporate headquarters are inDenver, 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 inthe United States . As described below and elsewhere in this Quarterly Report on Form 10-Q, effectiveMarch 13, 2019 , the results ofAntero Midstream Partners are no longer consolidated in Antero's results.
Address, Internet Website and Availability of Public Filings
Our principal executive offices are located at
We furnish or file with theSEC our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, and our Current Reports on Form 8-K. We make these documents available free of charge at www.anteroresources.com under the "Investors-SEC Filings" section as soon as reasonably practicable after they are furnished or filed with theSEC . Information on our website is not incorporated into this Quarterly Report on Form 10-Q or any of our other filings with theSEC . 40 Table of Contents
2020 Developments and Highlights
COVID-19 Pandemic
InMarch 2020 , theWorld 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 inMarch 2020 ,Saudi Arabia andRussia failed to agree to cut production of oil along with theOrganization of the Petroleum Exporting Countries ("OPEC"), andSaudi 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. WhileOPEC ,Russia and other allied producers reached an agreement inApril 2020 to reduce production, oil prices have remained low. The imbalance between the supply of and demand for oil, as well as the uncertainty around the extent and timing of an economic recovery, have caused extreme market volatility and a substantial adverse effect on commodity prices in March and April. As a producer of natural gas, NGLs and oil, we are recognized as an essential business under various federal, state and local regulations related to the COVID-19 pandemic. We have continued to operate as permitted under these regulations while taking steps to protect the health and safety of our 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 portion of our non-field level employees have transitioned temporarily to remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting. To date, we have had no confirmed cases of COVID-19 within our employee group at any of our locations. Our natural gas, NGLs and oil producing properties are located in the liquids-richAppalachian Basin . Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 3% and 4% of our total revenue for the three months endedMarch 31, 2020 and the year endedDecember 31, 2019 , respectively. While natural gas prices also declined during the first quarter of 2020, the decline in natural gas prices has been far less significant than the decline in oil prices. In addition, we have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of$2.87 per MMBtu for the remainder of 2020. Our hedges cover a substantial majority of our expected natural gas production in 2020. We also have fixed priced contracts for the sale of 10,352 barrels per day of propane at a weighted average price of$0.65 per gallon and 26,000 barrels per day of oil at a weighted average price of$55.63 per barrel for the remainder of 2020. These fixed price contracts resulted in total commodity derivative fair value gains of$566 million , including settled commodity derivative gains of$211 million , during the three months endedMarch 31, 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 or shut-ins, 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 continentalU.S. and, as a result, estimates of future gas supply associated with oil production have declined. Additionally, the restart of economic activity inAsia , coupled with lower refinery liquefied petroleum gas ("LPG") production in theU.S. ,Europe , and other markets such asIndia , has led to strengthening prices for international LPG. Our supply chain also has not thus far experienced any significant interruptions. The industry overall is experiencing storage capacity constraints with respect to oil and certain NGL products, and we may become subject to those constraints if we are not able to sell our production, or certain components of our production, or enter into additional storage arrangements. The lack of a market or available storage for any one NGL product or oil could result in us having to delay or discontinue well completions and commercial production or shut in production for other products as we cannot curtail the production of individual products in a meaningful way without reducing the production of other products. Potential impacts of these constraints may include partial shut-in of production, although we are not able to determine the extent of or for how long any shut-ins may occur. However, because some of our wells produce rich gas, which is processed, and some produce dry gas, which does not require processing, we have the ability to change the mix of products that we produce and wells that we complete to adjust our production to address takeaway capacity constraints for certain products better than if we had only rich gas or dry gas wells. We have the ability to shut-in rich gas wells and still produce from our dry gas wells if processing or storage capacity of NGL products becomes further limited or constrained. Also, prior to the COVID-19 pandemic, we had developed a diverse set of buyers and destinations, as well as in-field and off-site storage capacity for our condensate volumes. Since the outbreak of the pandemic, we have expanded our customer base and doubled our condensate storage capacity within the basin. 41 Table of Contents In addition, as discussed below in "-2020 Capital Budget and Capital Spending," we have reduced our drilling and completion capital budget for 2020 by approximately 34% since the beginning of the year. We will continue to monitor our five-year drilling plan throughout the year and will make further revisions if deemed necessary. Reductions in the 2020 capital budget may impact production levels in 2021 and forward to the extent fewer wells will be brought online. During the three months endedMarch 31, 2020 and during the two previous quarters, we have recognized various impairment charges related to the decline in commodity prices and the value of our investment in Antero Midstream Corporation. At this time, we do not anticipate any further impairment charges in our equity method investment in Antero Midstream Corporation, as the value of our equity method investment has increased sinceMarch 31, 2020 . Additional impairment charges related to our assets may occur if we experience disruptions in production, additional or sustained declines in the forward commodity price strip fromMarch 31, 2020 , unresolved storage capacity restraints or other consequences of the COVID-19 pandemic. InApril 2020 , the borrowing base supporting our Credit Facility was subject to its annual redetermination. The bank prices used in our redetermination were materially lower than the bank prices used in ourApril 2019 redetermination and were lower than strip prices as ofApril 27, 2020 . As a result, the lenders under our Credit Facility reduced our borrowing base from the previous level. Lender commitments remained unchanged at$2.64 billion , providing us with a consistent amount of available borrowings. Our borrowing base is now subject to a semi-annual redetermination and, therefore, our available borrowings and liquidity could be impacted by an additional redetermination in 2020. In addition, our borrowing capacity is directly impacted by the amount of financial assurance we are required to provide in the form of letters of credit to third parties, primarily pipeline capacity providers. Our ability to limit the financial assurance we are required to provide, while also protecting ourselves from the counterparty risk of our financial hedges, may be impacted by the ongoing effects of the COVID-19 pandemic. The COVID-19 pandemic, commodity market volatility and resulting financial market instability are variables beyond our control, which can adversely impact our generation of funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under our Credit Facility and our ability to access the capital markets. In addition, our plan to strengthen our balance sheet through significant absolute debt reduction depends upon our ability to identify and successfully execute our previously announced asset monetization program. Instability in the financial markets and uncertainty in the general business environment resulting from the COVID-19 pandemic may impact our ability to execute our asset monetization program on the terms and the timeframe previously anticipated. To the extent we are not able to execute our asset monetization plan or access the capital markets, we may have to delay or reduce our planned capital expenditures in order to address our upcoming debt obligations.
Production and Financial Results
For the three months endedMarch 31, 2020 , our net production totaled 306 Bcfe, or 3,366 MMcfe per day, a 9% increase in daily combined production compared to 279 Bcfe, or 3,099 MMcfe per day, for the three months endedMarch 31, 2019 . Production increases resulted from an increase in the number of producing wells as a result of our drilling and completion activity. Our average price received for production, before the effects of gains on settled commodity derivatives for the three months endedMarch 31, 2020 was$2.30 per Mcfe compared to$3.65 per Mcfe for the three months endedMarch 31, 2019 . Our average realized price after the effects of gains on settled commodity derivatives was$2.99 per Mcfe for the three months endedMarch 31, 2020 compared to$4.00 per Mcfe for the three months endedMarch 31, 2019 . For the three months endedMarch 31, 2020 , we generated consolidated cash flows from operations of$201 million , net loss attributable to Antero of$339 million , and Adjusted EBITDAX of$244 million . This compares to consolidated cash flows from operations of$539 million , consolidated net income attributable to Antero Resources of$979 million , and Adjusted EBITDAX of$443 million for the three months endedMarch 31, 2019 . See "-Non-GAAP Financial Measures" for a definition of Adjusted EBITDAX and a reconciliation of Adjusted EBITDAX to net cash provided by operating activities and net income (loss). Cash flows from operations decreased by$338 million for the three months endedMarch 31, 2020 compared to the prior year period primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression and transportation costs. Consolidated net loss attributable to Antero Resources of$339 million for the three months endedMarch 31, 2020 decreased from consolidated net income attributable to Antero Resources of$979 million for the three months endedMarch 31, 2019 primarily due to the gain on deconsolidation ofAntero Midstream Partners in 2019 partially offset by commodity derivative realized and fair value gains in 2020. The three months endedMarch 31, 2020 was also impacted by an Impairment of equity investment due to the decline in Antero Midstream Corporation's fair value and Antero Midstream Corporation's earnings changing from earnings to a loss.
Adjusted EBITDAX decreased from
42
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26% per Mcfe after the effects of settled commodity derivatives, and increased
gathering, compression and transportation costs discussed above. A portion of
the cost increases are the result of the deconsolidation of Antero Midstream
Partners as costs that were previously eliminated in consolidation are now
expensed.
2020 Capital Budget and Capital Spending
Our drilling and completion capital budget for 2020 has been reduced to$750 million from$1.15 billion . Reductions in the 2020 capital budget may impact production in 2021 and forward to the extent fewer wells will be brought online. We do not include acquisitions in our capital budget. We periodically review our capital expenditures and adjust our budget and its allocation based on commodity prices, takeaway constraints, operating cash flow and liquidity. For the three months endedMarch 31, 2020 , our capital expenditures were approximately$312 million , including drilling and completion costs of$300 million , leasehold acquisitions of$10 million , and other capital expenditures of$2 million . Our capital expenditures for the three months endedMarch 31, 2019 of approximately$472 million included drilling and completion costs of$369 million , leasehold acquisitions of$27 million , and other capital expenditures of$3 million . In addition, consolidated capital expenditures for the three months endedMarch 31, 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 ofAntero Midstream Partners onMarch 12 . 2019. For the three months endedMarch 31, 2020 , our exploration and production capital expenditures decreased by$87 million from the three month period endedMarch 31, 2019 . This 22% reduction in capital costs was a result of our well cost savings initiatives, which include savings resulting from service cost deflation, sand and water logistics optimization, as well as operational efficiency gains.
Hedge Position
AtMarch 31, 2020 , we had fixed price natural gas swap contracts on NYMEX Henry Hub for the period fromApril 2020 throughDecember 2023 covering 1.8 Tcf of our projected natural gas production at a weighted average index price of$2.77 per MMBtu, including contracts for the remainder of 2020 of approximately 613 Bcf of natural gas at a weighted average index price of$2.87 per MMBtu. AtMarch 31, 2020 , we also had basis swaps for the period fromApril 2020 throughDecember 2024 for approximately 89.5 Bcf of our projected natural gas production with pricing differentials ranging from$0.35 to$0.53 per MMBtu that hedge the difference between TCO and the NYMEX Henry Hub. In addition, we have a call option agreement, which entitles the holder, if exercised, to enter into a fixed price swap agreement for approximately 428 MMBtu per day at a price of$2.77 per MMBtu in 2024. We believe our hedge position provides some certainty to cash flows supporting our future operations and capital spending plans. As ofMarch 31, 2020 , the estimated fair value of our commodity derivative contracts was approximately$1.1 billion . Credit Facility Our borrowing base was reduced to$2.85 billion and lender commitments remained at$2.64 billion at the redetermination inApril 2020 . The borrowing base under our Credit Facility is redetermined semi-annually and is based on the estimated future cash flows from our proved oil and gas reserves, the value of our ownership interest in Antero Midstream Corporation and our commodity derivative positions. The next redetermination is scheduled to occur inOctober 2020 . The maturity date of the Credit Facility is the earlier of (i)October 26, 2022 and (ii) the date that is 91 days prior to the earliest stated redemption date of any series of our senior notes then outstanding. AtMarch 31, 2020 , we had an outstanding balance under the Credit Facility of$882 million , with a weighted average interest rate of 2.57%, and letters of credit of$730 million . See "-Debt Agreements and Contractual Obligations-Senior Secured Revolving Credit Facility" for a description of the Credit Facility.
Share Repurchase Program
During the three months endedMarch 31, 2020 , pursuant to our share repurchase program, we repurchased 27,193,237 shares of our common stock (approximately 9% of total shares outstanding at commencement of the program) at an average cost of$1.57 for a total cost of approximately$43 million . During the term of this program, we repurchased an aggregate of approximately$215 million of our shares of common stock. AtMarch 31, 2020 , Antero had 268,926,481 shares outstanding. 43 Table of Contents 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 byAntero Midstream Partners . All intersegment transactions were eliminated upon consolidation, including revenues from water handling and treatment services provided byAntero Midstream Partners , which we capitalized as proved property development costs. ThroughMarch 12, 2019 , the results ofAntero Midstream Partners were included in our consolidated financial statements. EffectiveMarch 13, 2019 , the results ofAntero 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 to the unaudited condensed consolidated financial statements for further discussion on the Transactions and Note 17 to the unaudited condensed consolidated financial statements for disclosures on our reportable segments. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market and utilize excess firm transportation capacity.
Three Months Ended
The operating results of our reportable segments were as follows for the three
months ended
Equity Method Elimination of
Investment in intersegment
Exploration Antero transactions and
and Midstream unconsolidated Consolidated
production Marketing Corporation affiliates total
Three months ended March 31, 2019 :
Revenue and other:
Natural gas sales $ 657,266 - - - 657,266
Natural gas liquids sales 313,685 - - - 313,685
Oil sales 48,052 - - - 48,052Commodity derivative fair value losses (77,368) - - - (77,368) Gathering, compression, and water handling and treatment - -
55,889 (51,410) 4,479
Marketing - 91,186 - - 91,186
Other income 1,758 - (1,781) 130 107
Total $ 943,393 91,186 54,108 (51,280) 1,037,407
Operating expenses:
Lease operating 42,969 - 11,815 (13,052) 41,732Gathering and compression 212,833 -
2,935 (113,421) 102,347
Processing 169,999 - - - 169,999
Transportation 152,183 - - - 152,183Production and ad valorem taxes 34,738 -
232 708 35,678
Marketing - 163,084 - - 163,084
Exploration 126 - - - 126Impairment of oil and gas properties 81,244 - - - 81,244 Impairment of midstream assets - - 6,982 - 6,982 Accretion of asset retirement obligations 913 - 10 53 976 Depletion, depreciation, and amortization 218,494 - 7,650 14,057 240,201 General and administrative (excluding equity-based compensation) 43,482 - 1,594 14,223 59,299 Equity-based compensation 6,426 - 590 1,887 8,903 Change in fair value of contingent acquisition consideration - - 1,049 (1,049) - Contract termination and rig stacking 8,360 - - - 8,360 Total 971,767 163,084 32,857 (96,594) 1,071,114 Operating income (loss)$ (28,374) (71,898) 21,251 45,314 (33,707) Equity in earnings of unconsolidated affiliates$ 1,817 - 2,880 9,384 14,081 44 Table of Contents Equity Method Elimination of Investment in intersegment Exploration Antero transactions and and Midstream unconsolidated Consolidated production Marketing Corporation affiliates total Three months endedMarch 31, 2020 : Revenue and other: Natural gas sales$ 411,082 - - - 411,082 Natural gas liquids sales 257,673 - - - 257,673 Oil sales 35,646 - - - 35,646
Commodity derivative fair value gains 565,833 - - - 565,833 Gathering, compression, water handling and treatment - - 261,314 (261,314) - Marketing - 46,073 - - 46,073 Other income 798 - (17,606) 17,606 798 Total$ 1,271,032 46,073 243,708 (243,708) 1,317,105 Operating expenses: Lease operating$ 25,644 - - - 25,644
Gathering and compression 193,008 -
55,908 (55,908) 193,008
Processing 210,236 - - - 210,236
Transportation 185,380 - - - 185,380Production and ad valorem taxes 25,699 -
1,498 (1,498) 25,699
Marketing - 93,273 - - 93,273
Exploration 210 - - - 210Impairment of oil and gas properties 89,220 - - - 89,220 Impairment of midstream assets - - 664,544 (664,544) - Depletion, depreciation, and amortization 199,677 - 27,343 (27,343) 199,677 Accretion of asset retirement obligations 1,104 - 42 (42) 1,104 General and administrative (excluding equity-based compensation) 27,892 -
10,199 (10,199) 27,892
Equity-compensation 3,329 - 3,338 (3,338) 3,329
Total 961,399 93,273 762,872 (762,872) 1,054,672Operating income (loss)$ 309,633 (47,200) (519,164) 519,164 262,433 Equity in loss of unconsolidated affiliates$ 128,055 -
- - 128,055
45
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Exploration and Production Segment Results for the Three Months Ended
The following table sets forth selected operating data of the exploration and production segment for the three months endedMarch 31, 2019 compared to the three months endedMarch 31, 2020 : Amount of Three months ended March 31, Increase Percent 2019 2020 (Decrease) Change Production data: Natural gas (Bcf) 199 208 9 5 % C2 Ethane (MBbl) 3,509 4,604 1,095 31 % C3+ NGLs (MBbl) 8,794 10,833 2,039 23 % Oil (MBbl) 1,017 938 (79) (8) % Combined (Bcfe) 279 306 27 10 %
Daily combined production (MMcfe/d) 3,099 3,366 267 9 % Average prices before effects of derivative settlements (1): Natural gas (per Mcf) (2)$ 3.30 $
1.98$ (1.32) (40) % C2 Ethane (per Bbl)$ 10.12 $ 5.82$ (4.30) (42) % C3+ NGLs (per Bbl)$ 31.63 $ 21.31$ (10.32) (33) % Oil (per Bbl)$ 47.23 $ 38.02$ (9.21) (20) %
Weighted Average Combined (per Mcfe)$ 3.65 $ 2.30$ (1.35) (37) % Average realized prices after effects of derivative settlements (1): Natural gas (per Mcf)$ 3.79 $ 2.88$ (0.91) (24) % C2 Ethane (per Bbl)$ 10.12 $ 5.82$ (4.30) (42) % C3+ NGLs (per Bbl)$ 31.59 $ 22.56$ (9.03) (29) % Oil (per Bbl)$ 47.23 $ 47.29$ 0.06 0 %
Weighted Average Combined (per Mcfe)$ 4.00 $ 2.99$ (1.01) (25) % Average costs (per Mcfe): Lease operating$ 0.15 $ 0.08$ (0.07) (47) % Gathering and compression$ 0.76 $
0.63$ (0.13) (17) % Processing$ 0.61 $ 0.69$ 0.08 13 % Transportation$ 0.55 $ 0.61$ 0.06 11 %
Production and ad valorem taxes$ 0.12 $ 0.08$ (0.04) (33) % Depletion, depreciation, amortization, and accretion$ 0.78 $ 0.66$ (0.12) (15) % General and administrative (excluding equity-based compensation)$ 0.16 $
0.09
(1) Average sales prices shown in the table reflect both the before and after
effects of our settled commodity derivatives. Our calculation of such after
effects includes gains on settlements of commodity derivatives, which do not
qualify for hedge accounting because we do not designate or document them as
hedges for accounting purposes. Oil and NGLs production was converted at 6
Mcf per Bbl to calculate total Bcfe production and per Mcfe amounts. This
ratio is an estimate of the equivalent energy content of the products and
does not necessarily reflect their relative economic value.
Natural gas sales. Revenues from production of natural gas decreased from$657 million for the three months endedMarch 31, 2019 to$411 million for the three months endedMarch 31, 2020 , a decrease of$246 million , or 37% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased natural gas production volumes accounted for an approximate$30 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$276 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$314 million for the three months endedMarch 31, 2019 to$258 million for the three months endedMarch 31, 2020 , a decrease of$56 million , or 18% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Increased NGLs production volumes accounted for an approximate$76 million increase in year-over-year NGL revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate$132 million decrease in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). 46 Table of Contents Oil sales. Revenues from production of oil decreased from$48 million for the three months endedMarch 31, 2019 to$36 million for the three months endedMarch 31, 2020 , a decrease of$12 million , or 26% (calculated as the change in year-over-year volumes times the change in year-to-year average price). Decreased oil production volumes accounted for an approximate$4 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price), and changes in our prices, excluding the effects of derivative settlements, accounted for an approximate$8 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. For the three months endedMarch 31, 2019 and 2020, our commodity hedges resulted in derivative fair value losses of$77 million and gains of$566 million , respectively. The commodity derivative fair value gains (losses) included$97 million and$211 million of gains on cash settled derivatives for the three months endedMarch 31, 2019 andMarch 31, 2020 , respectively. Commodity derivative fair value gains or losses vary based on future commodity prices and have no cash flow impact until the derivative contracts are settled or monetized prior to settlement. Derivative asset or liability positions at the end of any accounting period may reverse to the extent future commodity prices increase or decrease from their levels at the end of the accounting period, or as gains or losses are realized through settlement. We expect continued volatility in commodity prices and the related fair value of our derivative instruments in the future.
Other income. Other income decreased from
Lease operating expense. Lease operating expense decreased from$43 million for the three months endedMarch 31, 2019 to$26 million for the three months endedMarch 31, 2020 , a decrease of$17 million , or 40%. On a per unit basis, lease operating expenses decreased from$0.15 for the three months endedMarch 31, 2019 to$0.08 for the three months endedMarch 31, 2020 . This decrease is primarily due to decreased water handling costs resulting from improved operating efficiencies and cost reductions. Gathering, compression, processing, and transportation expense. Gathering, compression, processing, and transportation expense increased from$535 million for the three months endedMarch 31, 2019 to$589 million for the three months endedMarch 31, 2020 . This is primarily a result of the increase in production. Gathering and compression costs decreased from$0.76 per Mcfe to$0.63 per Mcfe primarily as a result of decreased costs associated with fuel as a result of a decrease in natural gas prices and a$12 million incentive fee rebate from Antero Midstream Corporation. Processing costs increased from$0.61 to$0.69 per Mcfe as a result of increased NGL production. Processing costs remained relatively unchanged per NGL barrel. Our transportation costs increased from$0.55 per Mcfe to$0.61 per Mcfe due to increased demand charges for Mountaineer Xpress pipeline, which came on line inFebruary 2019 . Production and ad valorem tax expense. Production and ad valorem taxes decreased from$35 million for the three months endedMarch 31, 2019 to$26 million for the three months endedMarch 31, 2020 , a decrease of$9 million , or 26%. This decrease is primarily as a result of decreases in commodity prices. Production and ad valorem taxes as a percentage of natural gas revenues increased slightly from 5% in the three months endedMarch 31, 2019 , to 6% for the three months endedMarch 31, 2020 . Impairment of oil and gas properties. Impairment of oil and gas properties increased from$81 million for the three months endedMarch 31, 2019 to$89 million for the three months endedMarch 31, 2020 , an increase of$8 million , or 10%. We recognized impairments primarily related to expiring leases and to design and initial costs related to pads we no longer plan to place into service. We charge impairment expense for expiring leases when we determine they are impaired based on factors such as remaining lease terms, reservoir performance, commodity price outlooks, and future plans to develop the acreage. Depletion, depreciation, and amortization expense ("DD&A"). DD&A expense decreased from$218 million for the three months endedMarch 31, 2019 to$200 million for the three months endedMarch 31, 2020 , a decrease of$18 million , or 9%. DD&A per Mcfe decreased from$0.78 per Mcfe during the three months endedMarch 31, 2019 to$0.66 per Mcfe during the three months endedMarch 31, 2020 , as our depletable reserve volumes atMarch 31, 2020 increased slightly due to increased production and our depletable cost base decreased fromMarch 31, 2019 due to an impairment in the value of ourUtica properties of$881 million in the three months endedSeptember 30, 2019 . 47
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General and administrative expense. General and administrative expense (excluding equity-based compensation expense) related to the exploration and production segment decreased from$43 million for the three months endedMarch 31, 2019 to$28 million for the three months endedMarch 31, 2020 , a decrease of$15 million , or 36%. This decrease was primarily due to approximately$6.3 million in legal and other expenses related to the Transactions in the three months endedMarch 31, 2019 as well as decreases in employee related expenses in the three months endedMarch 31, 2020 as a result of ongoing cost savings initiatives. We had 619 employees as ofMarch 31, 2019 and 531 employees as ofMarch 31, 2020 . On a per-unit basis, general and administrative expense excluding equity-based compensation decreased by 44%, from$0.16 per Mcfe during the three months endedMarch 31, 2019 to$0.09 per Mcfe during the three months endedMarch 31, 2020 as the expense decreased while production increased. Equity-based compensation expense. Noncash equity-based compensation expense decreased from$6 million for the three months endedMarch 31, 2019 to$3 million for the three months endedMarch 31, 2020 , a decrease of$3 million , or 48%. This decrease was the result of equity award forfeitures, as well as a decrease in the total value of awards to officers and employees in 2019, which impacts future expense recognition. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 9 to the unaudited condensed consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for more information on equity-based compensation awards. Contract termination and rig stacking. We incurred contract termination and rig stacking costs of$8 million during the three months endedMarch 31, 2019 compared to no expense for the three months endedMarch 31, 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
Marketing. We have entered into long-term firm transportation agreements for our current and expected future production in order to secure guaranteed capacity to favorable markets. Where feasible, we purchase and sell third-party natural gas and NGLs to utilize our excess firm transportation capacity, or release capacity to third parties to conduct these activities on our behalf, in order to reduce our net costs related to the unused capacity under these transportation agreements. Operating losses on our marketing activities, or our net marketing expense, decreased from$72 million , or$0.26 per Mcfe, for the three months endedMarch 31, 2019 to$47 million , or$0.15 per Mcfe, for the three months endedMarch 31, 2020 . The decrease was driven by higher volumes and the mitigation of some of our excess firm transportation expense. Marketing revenues decreased from$91 million for the three months endedMarch 31, 2019 to$46 million for the three months endedMarch 31, 2020 , a decrease of$45 million , or 49%. The decreases in revenues is due to lower excess firm transportation capacity and decreases in commodity prices in the three months endedMarch 31, 2020 compared to the three months endedMarch 31, 2019 . Marketing expenses decreased from$163 million for the three months endedMarch 31, 2019 to$93 million for the three months endedMarch 31, 2020 , a decrease of$70 million , or 43%. Marketing expenses include firm transportation costs related to current excess firm capacity as well as the cost of third-party purchased gas and NGLs. Firm transportation costs included in the expenses above were$68 million and$47 million for the three months endedMarch 31, 2019 and 2020, respectively.
Discussion of Antero Midstream Corporation Segment for the Three Months Ended
ThroughMarch 12, 2019 , the results ofAntero Midstream Partners are included in our consolidated financial statements. EffectiveMarch 13, 2019 , we no longer consolidate the results ofAntero Midstream Partners in our results. As such, the three months endedMarch 31, 2019 include the results ofAntero Midstream Partners throughMarch 12, 2019 . See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment increased from$54 million for the three months endedMarch 31, 2019 to$244 million for the three months endedMarch 31, 2020 , an increase of$190 million , or 350%. The increase in operating revenue was primarily due to the three months endedMarch 31, 2019 only including Antero Midstream Corporation's results following the closing of the Transactions onMarch 12, 2019 . Total operating expenses related to the segment increased from$33 million for the three months endedMarch 31, 2019 to$763 million for the three months endedMarch 31 , 48 Table of Contents
2020. The increase was primarily due to impairments by Antero Midstream
Corporation of
Discussion of Items Not Allocated to Segments for the Three Months Ended
Impairment of equity investment. AtMarch 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 atMarch 31, 2020 . Interest expense. Our interest expense exclusive of interest expense related toAntero Midstream Partners' indebtedness decreased from$55 million in the three months endedMarch 31, 2019 to$53 million in the three months endedMarch 31, 2020 , a decrease of$2 million , or 3%. This decrease is due to a decrease in total indebtedness resulting from repurchases of our unsecured senior notes at prices below their stated value. Consolidated interest expense decreased from$72 million for the three months endedMarch 31, 2019 to$53 million for the three months endedMarch 31, 2020 , a decrease of$19 million , or 26%. During the three months endedMarch 31, 2019 , interest related toAntero Midstream Partners' debt throughMarch 12, 2019 is included consolidated interest expense.
Interest expense includes approximately
Income tax expense/benefit. Income tax expense decreased from a deferred tax expense of$288 million and$1 million of current tax expense, with an effective tax rate of 22%, for the three months endedMarch 31, 2019 to a deferred tax benefit of$110 million , with an effective tax rate of 25%, for the three months endedMarch 31, 2020 . The change was primarily a result of the increase in book income due to the Transactions and the associated deconsolidation ofAntero Midstream Partners for the three months endedMarch 31, 2019 , offset by the decrease in book income resulting from the impairment of our investment in Antero Midstream Corporation for the three months endedMarch 31, 2020 .
Capital Resources and Liquidity
Our primary sources of liquidity have been through net cash provided by operating activities including proceeds from derivatives, borrowings under the Credit Facility, issuances of debt and equity securities, and distributions/dividends from unconsolidated affiliates. Our primary 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. In addition, we may from time to time repurchase shares of our common stock. Under our prior share repurchase program, we repurchased and retired 27,193,237 common shares at a weighted average price per share of$1.57 for approximately$43 million during the three months endedMarch 31, 2020 . During the term of this program, we repurchased approximately$215 million of our shares of common stock. We may also seek to retire or purchase our outstanding debt securities from time to time through cash purchases, in open market purchases, privately negotiated transactions or otherwise. Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. During the three months endedMarch 31, 2020 , we repurchased$383 million principal amount of debt at a 21% weighted average discount, including a portion of both our 2021 notes and our 2022 notes. We recognized a gain of approximately$81 million on the early extinguishment of the debt repurchased. These repurchases, at a discount, have resulted in a net reduction in total debt outstanding and interest expense. 49
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As ofMarch 31, 2020 , we believe that funds from operating cash flows, distributions from unconsolidated affiliates, available borrowings under the Credit Facility, or capital market transactions will be sufficient to meet our cash requirements, including normal operating needs, debt service obligations, capital expenditures, and commitments and contingencies for at least the next 12 months. Our 2021 notes are dueNovember 1, 2021 and our Credit Facility will become due 91 days prior to that date, or onAugust 1, 2021 , if the 2021 notes are not repaid prior toAugust 1, 2021 . If the 2021 notes remain outstanding as ofAugust 1, 2020 , the Credit Facility will be classified as a current liability as ofSeptember 30, 2020 and both the Credit Facility and the 2021 notes will be classified as current liabilities as ofDecember 31, 2020 if still outstanding at that time. The classification of the Credit Facility as a current liability does not impact any of our financial covenants. In addition, we believe we have the ability to address the maturity of the 2021 Notes with proceeds from potential asset sales, free cash flow from operations, and available borrowings under the Credit Facility.
For more information on our outstanding indebtedness, see Note 7 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q. For information about the impacts of COVID-19 on our capital resources and liquidity, see "-COVID-19 Pandemic."
The following table summarizes our cash flows for the three months endedMarch 31, 2019 and 2020: Three Months Ended March 31, Increase (in thousands) 2019 2020 (Decrease) Net cash provided by operating activities$ 539,004 200,677 (338,327) Net cash used in investing activities (204,817) (186,681) 18,136 Net cash provided by (used in) financing activities 285,345 (13,996) (299,341) Effect of deconsolidation of Antero Midstream Partners LP (619,532) - 619,532 Net decrease in cash and cash equivalents $ -
- - The Company's condensed consolidated cash flow statements for the three months endedMarch 31, 2019 includes the cash flows related toAntero Midstream Partners for periods prior toMarch 13, 2019 . EffectiveMarch 13, 2019 , the Company's cash flows include only the operating, investing and financing activities related to Antero and; therefore, the cash flows for the three months endedMarch 31, 2019 are not representative of our expected future cash flows. See Note 3 to the unaudited condensed consolidated financial statements for more information.
Cash Flows Provided by Operating Activities
Net cash provided by operating activities was$539 million and$201 million for the three months endedMarch 31, 2019 and 2020, respectively. Cash flow from operations decreased primarily due to decreases in commodity prices both before and after the effects of settled commodity derivatives and increases in gathering, compression and transportation costs. 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
During the three months endedMarch 31, 2019 and 2020, we used cash flows in investing activities of$205 million and$187 million , respectively, primarily as a result of our capital expenditures for drilling, development, and acquisitions. In addition, cash flows in investing activities included expenditures ofAntero Midstream Partners related to construction of midstream and water handling and treatment infrastructure and investments in joint ventures throughMarch 12, 2019 . EffectiveMarch 13, 2019 , these expenditures are no longer consolidated in our results. Cash flows used in investing activities decreased from$205 million for the three months endedMarch 31, 2019 to$187 million for the three months endedMarch 31, 2020 , primarily due to a decrease in capital expenditures of$160 million during the three months endedMarch 31, 2020 as compared to the same period in 2019,$297 million in proceeds received in connection with the Transactions impacting the three months endedMarch 31, 2019 and$125 million in settlement of the water earnout impacting the three months endedMarch 31, 2020 . See Note 3 to the unaudited condensed consolidated financial statements for further discussion on the Transactions. 50
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Total capital expenditures for oil and gas properties decreased from$396 million during the three months endedMarch 31, 2019 to$311 million during the three months endedMarch 31, 2020 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation. The three months endedMarch 31, 2019 includedAntero 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 ofAntero Midstream Partners onMarch 12, 2019 , cash flows used in investing activities for the three months endedMarch 31, 2020 do not include costs attributable to Antero Midstream Partner's investing activity. 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 Financing Activities
During the three months endedMarch 31, 2019 and 2020, net cash flows provided by financing activities decreased from a source of$285 million to a use of$14 million primarily as a result of the issuance of senior notes byAntero Midstream Partners prior to the Transactions and the associated deconsolidation ofAntero Midstream Partners , partially offset by net repayments on ourCredit Facility andAntero Midstream Partners' credit facility. Net borrowings (repayments) on ourCredit Facility andAntero Midstream Partners' credit facility changed from net payments of$270 million during the three months endedMarch 31, 2019 to net borrowings of$330 million during the three months endedMarch 31, 2020 . Approximately$302 million of borrowings on our Credit Facility in the three months endedMarch 31, 2020 was used to repurchase a portion of our 2021 and 2022 unsecured notes. In addition, we repurchased and retired 27,193,237 common shares for approximately$43 million during the three months endedMarch 31, 2020 . We did not repurchase any of our unsecured notes or shares during the three months endedMarch 31, 2019 .
Debt Agreements and Contractual Obligations
Senior Secured Revolving Credit Facility. Our Credit Facility is with a consortium of bank lenders. OnApril 29, 2020 , Antero Resources entered into a Third Amendment to the Credit Facility, pursuant to which certain terms of the Credit Facility were amended, as further described herein. Borrowings under the Credit Facility are subject to borrowing base limitations based on the collateral value of our assets and are subject to regular redeterminations. The borrowing base was adjusted to$2.85 billion and lender commitments were reaffirmed at$2.64 billion in the scheduled redetermination inApril 2020 .
The
next redetermination of the borrowing base is scheduled to occur in
AtDecember 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. AtMarch 31, 2020 , we had$882 million of borrowings and$730 million of letters of credit outstanding under the Credit Facility. The average annualized interest rate incurred on the Credit Facility during the three months endedMarch 31, 2020 was approximately 3.28%. Our Credit Facility provides for borrowing under either LIBOR or an Alternative Rate of Interest. Under the Credit Facility, "Investment Grade Period" is a period that, as long as no event of default has occurred, commences when Antero elects to give notice to the Administrative Agent that Antero has received at least one of either (i) a BBB- or better rating from S&P or (ii) a Baa3 or better rating from Moody's (an "Investment Grade Rating"). An Investment Grade Period can end at Antero's election. During any period that is not an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following two financial ratios as of the end of each fiscal quarter:
a current ratio, which is the ratio of our current assets (including any unused
? borrowing base under the facilities and excluding derivative assets) to our
current liabilities (excluding derivative liabilities and lease liabilities),
of not less than 1.0 to 1.0; and
51
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an interest coverage ratio, which is the ratio of EBITDAX (as defined by the
? credit facility agreement) to interest expense over the most recent four
quarters, of not less than 2.5 to 1.0.
During an Investment Grade Period, the Credit Facility requires Antero and its restricted subsidiaries to maintain the following three financial ratios as of the end of each fiscal quarter
a current ratio, which is the ratio of our current assets (including any unused
? borrowing base under the facilities and excluding derivative assets) to our
current liabilities (excluding derivative liabilities), of not less than 1.0 to
1.0;
a ratio of total Indebtedness (as defined by the credit facility agreement) to
? EBITDAX (as defined by the credit facility agreement) of not more than 4.25 to
1.00; and
a ratio of PV-9 reflected in the most recently delivered reserve report to its
? total Indebtedness of not less than 1.50 to 1.00, but only if Antero does not
have both (i) an unsecured rating from Moody's of Baa3 or better and (ii) an
unsecured rating from S&P of BBB- or better.
We were in compliance with the applicable covenants and ratios as of
For more information on the terms, conditions, and restrictions under the Credit Facility, please refer to our 2019 Form 10-K.
Senior Notes. Please refer to Note 7 to the unaudited condensed consolidated financial statements included in this Quarterly Report on Form 10-Q and to "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" included in our 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 three months endedMarch 31, 2020 , we repurchased$383 million principal amount of debt at a 21% weighted average discount, including a portion of our 2021 notes and our 2022 notes. 52 Table of Contents Contractual Obligations. A summary of our contractual obligations as ofMarch 31, 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) $ - 882 - - - - - 882 Antero senior notes-principal(2) - 730 761 750 - 600 - 2,841 Antero senior notes-interest(2) 135 151 111 51 30 15 - 493 Operating leases(3) 228 269 285 313 342 309 1,069 2,815 Finance leases(3) 1 1 - - - - - 2 Imputed interest for leases(3) 236 289 259 225 188 149 326 1,672 Asset retirement obligations(4) - - -
- - - 57 57 Unrecorded contractual obligations: Firm transportation(5) 833 1,077 1,034 1,057 1,017 978 6,931 12,927 Processing, gathering, and compression services(6) 42 56 54 59 59 47 105 422 Drilling and completion 19 - - - - - - 19 Land payment obligations(7) 2 3 - - - - - 5 Total$ 1,496 3,458 2,504 2,455 1,636 2,098 8,488 22,135
(1) Includes outstanding principal amounts at
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)
the earliest stated redemption of any series of Antero's senior notes then
outstanding.
(2) Our senior notes include our 2021 notes, our 2022 notes, our 5.625% notes due
2023, and our 5.00% notes due 2025.
(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 12 to the unaudited condensed consolidated
financial statements for more information on the Company's 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
fees 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.
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, 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 andAntero Midstream Partners related adjustments. 53
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ThroughMarch 12, 2019 , the financial results ofAntero Midstream Partners were included in our consolidated results. EffectiveMarch 13, 2019 , we no longer consolidateAntero Midstream Partners and account for our interest in Antero Midstream using the equity method of accounting. See Note 5 to the unaudited condensed consolidated financial statements for more information on our equity investments. Adjusted EBITDAX includes distributions received with respect to limited partner interests inAntero Midstream Partners common units throughMarch 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 months endedMarch 31, 2019 and 2020. Adjusted EBITDAX also excludes the results ofAntero Midstream Partners in order to provide comparability with the current structure of Antero Resources as effectiveMarch 13, 2019 , we no longer consolidateAntero Midstream Partners results. These adjustments are disclosed in the table below asAntero Midstream Partners related adjustments. 54 Table of Contents Three months ended March 31, (in thousands) 2019 2020
Reconciliation of net income (loss) to Adjusted EBITDAX:
Net income (loss) and comprehensive income (loss)
attributable to
$ 978,763
(338,810)
Net income and comprehensive income attributable to noncontrolling interests
46,993 -
Depletion, depreciation, amortization, and accretion 241,177200,781
Impairment of oil and gas properties 81,244
89,220
Impairment of midstream assets 6,982 - Commodity derivative fair value (gains) losses (1) 77,368
(565,833)
Gains on settled commodity derivatives (1) 97,092
210,926
Equity-based compensation expense 8,903
3,329
Provision for income tax expense (benefit) 288,710
(109,985)
Gain on early extinguishment of debt -
(80,561)
Equity in (earnings) loss of unconsolidated affiliates (14,081)
128,055
Impairment of equity investment -
610,632
Gain on deconsolidation of
-
Distributions/dividends from unconsolidated affiliates 12,605
42,756
Interest expense, net 71,950 53,102
Exploration expense 126 210
Gain on sale of assets - (31)
Contract termination and rig stacking 8,360 -
Simplification transaction fees 15,482 -
515,632 243,791
Net income and comprehensive income attributable to noncontrolling interests
(46,993) -
Antero Midstream Partners interest expense, net (2) (16,815) -
(21,770) -
Antero Midstream Partners impairment (6,982) -
Antero Midstream Partners equity-based compensation
expense (2) (2,477) -
Antero Midstream Partners equity in earnings of
unconsolidated affiliates (2) 12,264 -
Antero Midstream Partners distributions from
unconsolidated affiliates (2) (12,605) -
Equity in earnings of Antero Midstream Partners (2) (15,021) -
Distributions from Antero Midstream Partners (2) 46,469 -
Antero Midstream Partners Simplification transaction
fees (9,185) -
Antero Midstream Partners related adjustments (73,115) -
Adjusted EBITDAX $ 442,517 243,791
Reconciliation of our Adjusted EBITDAX to net cash provided by operating activities: Adjusted EBITDAX
$ 442,517
243,791
Antero Midstream Partners related adjustments 73,115
-
Interest expense, net (71,950) (53,102)
Exploration expense (126) (210)
Gain on asset sale - 31Changes in current assets and liabilities 109,065
7,727
Simplification transaction fees (15,482) - Other non-cash items 1,865
2,440
Net cash provided by operating activities$ 539,004
200,677
(1) The adjustments for the derivative fair value gains and losses and gains on
settled derivatives have the effect of adjusting net income (loss) from
operations for changes in the fair value of unsettled derivatives, which are
recognized at the end of each accounting period. As a result, derivative
gains included in the calculation Adjusted EBITDAX only reflect derivatives
that settled during the period.
(2) Amounts reflected are net of any elimination adjustments for intercompany
activity and include activity related to
March 12, 2019 (date of the Closing). EffectiveMarch 13, 2019 , Antero accounts for its 55 Table of Contents
unconsolidated investment in Antero Midstream Corporation using the equity
method of accounting. See Note 5 to the unaudited condensed consolidated
financial statements for further discussion on equity method investments.
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 our 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 to the consolidated financial statements, included in our 2019 Form 10-K, for a discussion of additional accounting policies and estimates made by management. We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment for theUtica andMarcellus 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 inMarch 2020 bySaudi 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 atMarch 31, 2020 , the estimated undiscounted future net cash flows exceeded the carrying amount and no further evaluation was required. We have not recorded any impairment expenses associated with our proved properties during the three months endedMarch 31, 2019 and 2020. We recorded an impairment charge of$881 million related to theUtica Shale properties during the three months endedSeptember 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 fromMarch 31, 2020 , the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. We are unable, however, to predict future commodity prices with any reasonable certainty.
Off-Balance Sheet Arrangements
As ofMarch 31, 2020 , we did not have any off balance sheet arrangements other than contractual commitments for firm transportation, gas processing and fractionation, gathering, and compression services and land payment obligations. See "-Debt Agreements and Contractual Obligations-Contractual Obligations" for our commitments under these agreements.
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