Item 7. Management’s Discussion and Analysis
ITEM 7. 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 consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. 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, 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 development, production, exploration and acquisition 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 develop 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 Appalachian Basin. As of December 31, 2020, we held approximately 515,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 174,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.
As of December 31, 2020, our estimated proved reserves were approximately 17.6 Tcfe, consisting of 10.0 Tcf of natural gas, 745 MMBbl of assumed recovered ethane, 491 MMBbl of C3+ NGLs, and 32 MMBbl of oil. This represents a 7% decrease in estimated proved reserves from December 31, 2019. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2020, we had approximately 2,133 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible.
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) midstream services through our equity method investment in Antero Midstream Corporation. As described below and elsewhere in this Annual Report on Form 10-K, effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners. All of our operations are conducted in the United States.
Recent 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
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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 contract 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 continue to operate in remote work from home arrangements, and we have been able to maintain a consistent level of effectiveness through these arrangements, including maintaining our day-to-day operations, our financial reporting systems and our internal control over financial reporting.
Our natural gas, NGLs and oil producing properties are located in the liquids-rich Appalachian Basin. Although the decline in oil prices has negatively impacted our oil revenue, oil sales represented approximately 3% of our total revenue for the year ended December 31, 2020. While natural gas prices also declined during the first half of 2020, benchmark Henry Hub prices recovered during the third quarter and averaged $2.32/Mcf in the last half of 2020. Similarly, C3+ NGL prices also improved during the second half of 2020 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 pandemic reduced gasoline demand, which forced C5 prices below propane prices for much of April 2020 to under $0.40 per gallon, has since rebounded with benchmark C5 price in January 2021 in the range of $1.05 to $1.25 per gallon.
In addition, we have hedged through fixed price contracts the sale of 2.2 Bcf per day of natural gas at a weighted average price of $2.77 per MMBtu in 2021. Our hedges cover a substantial majority of our expected natural gas production in 2021. We also have fixed priced contracts for the sale of 19,000 barrels per day of ethane at a weighted average price of $0.20 per gallon and 3,000 barrels per day of oil at a weighted average price of $55.16 per barrel for 2021. 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 into 2021.
During the fourth quarter of 2020, we shipped 43% of our total C3+ NGL net production on Mariner East 2 for export and realized a $0.11 per gallon premium to Mont Belvieu pricing on these volumes at Marcus Hook, PA. We sold the remaining 57% of C3+ NGL net production at a $0.06 per gallon discount to Mont Belvieu pricing at Hopedale, OH. We expect to sell at least 48% of our C3+ NGL full-year production in 2021 at Marcus Hook for export at a premium to Mont Belvieu.
Condensate differentials to WTI were approximately $12/Bbl during the fourth 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 2021 realized oil price differential to be at the high end of the $9.00/Bbl to $11.00/Bbl range, as the differential normalized during the fourth quarter of 2020.
Our supply chain also has not experienced any significant interruptions. 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.
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In addition, as discussed in “—Capital Resources and Liquidity—2020 Capital Spending and 2021 Capital Budget” below, we announced a 21% reduction in our drilling and completion capital budget for 2021 compared to 2020. During the fourth quarter, our ongoing emphasis on completion efficiencies and drilling longer laterals resulted in material improvements in well costs. Well costs averaged approximately $680 per lateral foot during the fourth quarter, benefiting from these efficiency improvements and lateral lengths that averaged over 15,000 feet. Well costs were approximately $690 per foot when normalized for a 12,000 foot lateral length. We expect well costs to average $660 per foot during the first quarter of 2021, based on a 12,000 foot lateral. We continue to monitor our five-year drilling plan and will make further revisions as appropriate.
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 because 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 December 31, 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 at $2.85 billion. Lender commitments 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.
Financing Highlights
Debt Repurchase Program
During the year ended December 31, 2020, we repurchased $1.4 billion principal amount of our senior notes through open market repurchases, tender offers and redemptions at a weighted average discount of 13%. We recognized a gain of $176 million for the year ended December 31, 2020 on the early extinguishment of the debt repurchased. As a result, our 5.375% senior notes due November 1, 2021 (the “2021 Notes”) were fully retired as of November 30, 2020. Additionally, we fully redeemed our 5.125% senior notes due December 1, 2022 (the “2022 Notes”) at par, plus accrued and unpaid interest in the first quarter of 2021. See Note 8—Long-Term Debt to the consolidated financial statements for more information.
Asset Sales Program
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”). At the initial closing, Sixth Street contributed $300 million in cash (subject to customary adjustments) and agreed to contribute up to an additional $102 million in cash if certain production thresholds 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. We met the production threshold related to the third quarter of 2020 and received a $51 million cash distribution during the year ended December 31, 2020. See Note 4—Transactions to the consolidated financial statements for more information.
On August 10, 2020, we completed a volumetric production payment transaction and received net proceeds of approximately $216 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
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136,589,000 MMBtu over the expected seven-year term of the VPP. See Note 4—Transactions to the consolidated financial statements for more information.
On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners. Under the terms of the arrangement, QL will fund 20% of total development capital spending in 2021 and is expected to fund between 15% and 20% of total development capital spending on an annual basis from 2022 through 2024. All of the wells spud during each calendar year period will be a separate annual tranche. Capital costs in excess of, and cost savings below, a specified percentage of budgeted amounts for each annual tranche will be for our account.
For each tranche other than 2021, we will propose a capital budget and estimated internal rate of return (“IRR”) for all wells to be spud during the year and, subject to the mutual agreement of the parties that the estimated IRR for each tranche exceeds a specified return, QL will be obligated to participate in such tranche. For each annual tranche in which QL participates, QL will receive a proportionate working interest percentage in each well spud in such tranche. If we present a capital budget for an annual tranche with an estimated IRR equal to or exceeding a specified return that QL in good faith believes is less than such specified return and QL elects not to participate, we will not be obligated to offer QL the opportunity to participate in subsequent tranches. No earlier than December 31 following the expiration of each tranche year, we will calculate the tranche IRR for such tranche year and, if the tranche IRR exceeds certain specified returns, we will receive a carry in the form of a one-time payment from QL for such annual tranche.
Issuance of Convertible Senior Notes and Senior Notes
On August 21, 2020, we issued $250 million in aggregate principal amount of 4.25% senior unsecured convertible notes (the “2026 Convertible Notes”). On September 2, 2020, we issued an additional $37.5 million of the 2026 Convertible Notes. The initial conversion rate is 230.2026 shares of our common stock per $1,000 principal amount of 2026 Convertible Notes, subject to adjustment upon the occurrence of specified events. Please see “—Debt Agreements and Contractual Obligations—Senior Unsecured Notes” below and Note 8—Long-Term Debt to the consolidated financial statements for more information.
On January 4, 2021, we issued $500 million of 8.375% senior notes due July 15, 2026 (the “2026 Notes”) at par. On January 26, 2021, we issued $700 million of 7.625% senior notes due February 1, 2029 (the “2029 Notes”) at par. The 2026 Notes and 2029 Notes are unsecured and effectively subordinated to the Credit Facility to the extent of the value of the collateral securing the Credit Facility. The 2026 Notes and 2029 Notes rank pari passu to our other outstanding senior notes. The 2026 Notes and 2029 Notes are guaranteed on a full and unconditional and joint and several senior unsecured basis by our wholly owned subsidiaries and certain of our future restricted subsidiaries. Please see “—Debt Agreements and Contractual Obligations—Senior Unsecured Notes” below and Note 8—Long-Term Debt to the consolidated financial statements for more information.
Convertible Notes Equitization
On January 12, 2021, we completed a registered direct offering (the “Share Offering”) of an aggregate of 31.4 million shares of our common stock at a price of $6.35 per share to certain holders of our 2026 Convertible Notes. We used the proceeds from the Share Offering and approximately $63 million of borrowings under the Credit Facility to repurchase from such holders $150 million aggregate principal amount of the 2026 Convertible Notes in privately negotiated transactions (the “Convertible Note Repurchase,” and, collectively with the Share Offering, the “Equitization Transactions”). See Note 8—Long-Term Debt to the consolidated financial statements for more information.
Share Repurchase Program
Our board-approved share repurchase program expired on March 31, 2020. Prior to the program’s expiration, 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 first quarter of 2020.
Sources of Our Revenues
● Natural gas, NGL and oil sale revenues. Our revenues are primarily derived from the sale of natural gas and oil production, as well as the sale of NGLs that are extracted from our natural gas during processing. Our production is entirely from within the continental United States; however, some of our production revenues are attributable to customers who export our products. During 2020, our production revenues were comprised of approximately 59% from the sale of natural gas and 41% from the sale of NGLs and oil. Natural gas, NGLs, and oil prices are inherently volatile and are influenced by many factors
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outside of our control. All of our production is derived from natural gas wells, some of which also produce NGLs which are extracted through processing, and oil.
● Commodity derivatives. To achieve more predictable cash flows and to reduce our exposure to downward price fluctuations, we utilize derivative instruments to hedge future sales prices on a significant portion of our production. We enter into primarily fixed price natural gas, NGLs, and oil swap contracts for natural gas in which we receive or pay the difference between a fixed price and the variable market price received, as well as basis swap contracts that hedge the difference between the New York Mercantile Exchange (“NYMEX”) index price and a local index price. At the end of each accounting period, we estimate the fair value of these swaps and, because we have not elected hedge accounting, we recognize changes in the fair value of these derivative instruments in earnings. We expect continued volatility in the prices we receive for our production and the fair value of our derivative instruments.
● Marketing revenues. Marketing revenues are primarily derived from activities to purchase and sell third-party natural gas and NGLs and to market excess firm transportation capacity to third parties.
● Gathering, compression, water handling and treatment revenues. Gathering, compression, water handling and treatment revenues are derived from our ownership interest in Antero Midstream Partners through March 12, 2019 and Antero Midstream thereafter.
Principal Components of Our Cost Structure
● Lease operating expenses. These are the operating costs incurred to maintain our production. Such costs include produced water hauling, water handling, water disposal, labor-related costs to monitor producing wells, maintenance, repairs, and workover expenses. Cost levels for these expenses can vary based on the volume of water produced, supply and demand for oilfield services, activity levels, and other factors.
● Gathering, compression, processing and transportation. These costs include the costs to purchase services from Antero Midstream and fees paid to other third parties who operate low- and high- pressure gathering systems that transport our gas. They also include costs to process and extract NGLs from our produced gas and to transport our natural gas, NGLs, and oil to market. We often enter into fixed price long- term contracts that secure transportation and processing capacity, which may include minimum volume commitments, the cost for which is included in these expenses to the extent that they are not associated with excess capacity. Costs associated with excess capacity are included in marketing expenses.
● Production and ad valorem taxes. Production and ad valorem taxes consist of severance and ad valorem taxes. Severance taxes are paid on produced natural gas and oil based on a percentage of sales prices (not hedged prices) or at fixed per-unit rates established by state authorities. Ad valorem taxes are paid based on the value of our reserves as well as the value of property and equipment.
● Marketing expenses . We purchase and sell third-party natural gas and NGLs and market our excess capacity under long-term contracts. Marketing costs include the cost of purchased third-party natural gas and NGLs. We also classify firm transportation costs related to capacity contracted for in advance of having sufficient production and infrastructure to fully utilize this excess capacity as marketing expenses, because we market this excess capacity to third parties. We enter into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure capacity on major pipelines.
● Exploration expense. These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, and costs of unsuccessful exploratory dry holes.
● Impairment of oil and gas properties. These costs include impairment and costs associated with leases expirations, impairment of design and initial costs related to pads that are no longer planned to be placed into service, and impairment of proved properties due to lower future commodity prices. We charge impairment expense for expired or soon-to-be expired 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. We also record impairment charges for proved properties on a geological reservoir basis when events or changes in circumstances indicate that a property’s carrying amount may not be recoverable.
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● Depletion, depreciation, and amortization. Depletion, depreciation, and amortization (“DD&A”), includes the systematic expensing of the capitalized costs incurred to acquire, explore and develop natural gas, NGLs, and oil. As a successful efforts company, we capitalize all costs associated with our acquisition and development efforts and all successful exploration efforts, and allocate these costs using the units of production method. Depreciation is computed over an asset’s estimated useful life using the straight-line basis.
● General and administrative expense. These costs include overhead, including payroll and benefits for our staff, costs of maintaining our headquarters, costs of managing our production and development operations, audit and other professional fees, insurance, legal expenses, and other administrative expenses. General and administrative expense also includes noncash equity-based compensation expense. See Note 10—Equity-Based Compensation and Retention Awards to the consolidated financial statements for more information.
● Interest expense. We finance a portion of our capital expenditures, working capital requirements, and acquisitions with borrowings under the Credit Facility, which has a variable rate of interest based on LIBOR or the prime rate. As a result, we incur substantial interest expense that is affected by both fluctuations in interest rates and our financing decisions. As of December 31, 2020, we had a fixed interest rate of 5.125% on our 2022 Notes having a principal balance of $661 million, a fixed interest rate of 5.625% on our 2023 Notes having a principal balance of $574 million, a fixed interest rate of 5.00% on our 2025 Notes having a principal balance of $590 million, and a fixed interest rate of 4.25% on our 2026 Convertible Notes having a principal balance of $287.5 million. See Note 8—Long-Term Debt to the consolidated financial statements for more information.
● Income tax expense. We are subject to state and federal income taxes but are currently not in a cash tax paying position with respect to federal income taxes. The difference between our financial statement income tax expense and our federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties, the effects of noncontrolling interests and the deferral of unsettled commodity derivative gains for tax purposes until they are settled. We do pay some state income or franchise taxes where state income or franchise taxes are determined on a basis other than income. We have recorded deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets. See Note 14—Income Taxes to the consolidated financial statements for more information.
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) midstream services through our equity method investment in Antero Midstream Corporation. Revenues from Antero Midstream’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, we included the results of Antero Midstream Partners in our consolidated financial statements. Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results; however, our segment disclosures include the segments of our unconsolidated affiliates, due to their significance to our operations. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the simplification transactions and Note 18—Segment Information to the 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.
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Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
The operating results of our reportable segments were as follows for the years ended December 31, 2019 and 2020 (in thousands):
Equity Method
Elimination of
Investment in
Intersegment
Exploration
Antero
Transactions and
and
Midstream
Unconsolidated
Consolidated
Production
Marketing
Corporation (1)
Affiliates
Total
Year Ended December 31, 2019
Revenue and other:
Natural gas sales
$
2,247,162
—
—
—
2,247,162
Natural gas liquids sales
1,219,162
—
—
—
1,219,162
Oil sales
177,549
—
—
—
177,549
Commodity derivative fair value gains
463,972
—
—
—
463,972
Gathering, compression, water handling and treatment
—
—
849,598
(845,120)
4,478
Marketing
—
292,207
—
—
292,207
Other income (loss)
5,812
—
(57,010)
55,358
4,160
Total
$
4,113,657
292,207
792,588
(789,762)
4,408,690
Operating expenses:
Lease operating
146,990
—
162,376
(163,646)
145,720
Gathering and compression
825,777
—
41,013
(151,465)
715,325
Processing
774,280
—
—
—
774,280
Transportation
657,042
—
—
—
657,042
Production and ad valorem taxes
124,202
—
3,830
(2,890)
125,142
Marketing
—
549,814
—
—
549,814
Exploration
884
—
—
—
884
Impairment of oil and gas properties
1,300,444
—
—
—
1,300,444
Impairment of midstream assets
—
—
776,832
(762,050)
14,782
Depletion, depreciation, and amortization
893,161
—
95,526
(73,820)
914,867
Accretion of asset retirement obligations
3,699
—
187
(124)
3,762
General and administrative (excluding equity-based compensation)
139,320
—
44,596
(28,779)
155,137
Equity-based compensation
21,082
—
73,517
(71,040)
23,559
Change in fair value of contingent acquisition consideration
—
—
8,076
(8,076)
—
Contract termination and rig stacking
14,026
—
—
—
14,026
Loss on sale of assets
951
—
—
—
951
Total
4,901,858
549,814
1,205,953
(1,261,890)
5,395,735
Operating income (loss)
$
(788,201)
(257,607)
(413,365)
472,128
(987,045)
Equity in earnings of unconsolidated affiliates
$
—
—
51,315
(194,531)
(143,216)
(1) Includes the consolidated results of Antero Midstream Partners through March 12, 2019 and results of the Company’s equity method investment in Antero Midstream Corporation effective March 13, 2019.
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Equity Method
Elimination of
Investment in
Intersegment
Exploration
Antero
Transactions and
and
Midstream
Unconsolidated
Consolidated
Production
Marketing
Corporation
Affiliates
Total
Year Ended December 31, 2020
Revenue and other:
Natural gas sales
$
1,809,952
—
—
—
1,809,952
Natural gas liquids sales
1,161,683
—
—
—
1,161,683
Oil sales
112,270
—
—
—
112,270
Commodity derivative fair value gains
79,918
—
—
—
79,918
Gathering, compression, water handling and treatment
—
—
971,391
(971,391)
—
Marketing
—
310,572
—
—
310,572
Amortization of deferred revenue, VPP
14,507
—
—
—
14,507
Other income
2,797
—
(70,672)
70,672
2,797
Total
$
3,181,127
310,572
900,719
(900,719)
3,491,699
Operating expenses:
Lease operating
$
98,865
—
—
—
98,865
Gathering and compression
834,758
—
165,386
(165,386)
834,758
Processing
909,038
—
—
—
909,038
Transportation
787,042
—
—
—
787,042
Production and ad valorem taxes
106,775
—
—
—
106,775
Marketing
—
469,404
—
—
469,404
Exploration
1,083
—
—
—
1,083
Impairment of oil and gas properties
223,770
—
—
—
223,770
Impairment of midstream assets
—
—
673,640
(673,640)
—
Depletion, depreciation, and amortization
861,870
—
108,790
(108,790)
861,870
Accretion of asset retirement obligations
3,421
—
180
(180)
3,421
General and administrative (excluding equity-based compensation)
111,165
—
39,435
(39,435)
111,165
Equity-based compensation
23,317
—
12,778
(12,778)
23,317
Contract termination and rig stacking and other expenses
14,290
—
15,219
(15,219)
14,290
Loss on sale of assets
348
—
2,929
(2,929)
348
Total
3,975,742
469,404
1,018,357
(1,018,357)
4,445,146
Operating loss
$
(794,615)
(158,832)
(117,638)
117,638
(953,447)
Equity in earnings (loss) of unconsolidated affiliates
$
(62,660)
—
86,430
(86,430)
(62,660)
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Exploration and Production Segment Results for the Year Ended December 31, 2019 Compared to the Year Ended December 31, 2020
The following table sets forth selected operating data of the exploration and production segment for the year ended December 31, 2019 compared to the year ended December 31, 2020:
Years Ended
Amount of
December 31,
Increase
Percent
2019
2020
(Decrease)
Change
Production data (1) (2) :
Natural gas (Bcf)
822
875
53
6
%
C2 Ethane (MBbl)
15,861
19,709
3,848
24
%
C3+ NGLs (MBbl)
39,445
48,341
8,896
23
%
Oil (MBbl)
3,632
4,412
780
21
%
Combined (Bcfe)
1,175
1,310
135
11
%
Daily combined production (MMcfe/d)
3,220
3,578
358
11
%
Average prices before effects of derivative settlements (3) :
Natural gas (per Mcf)
$
2.74
2.07
(0.67)
(24)
%
C2 Ethane (per Bbl)
$
7.85
5.77
(2.08)
(26)
%
C3+ NGLs (per Bbl)
$
27.75
21.68
(6.07)
(22)
%
Oil (per Bbl)
$
48.88
25.45
(23.43)
(48)
%
Weighted Average Combined (per Mcfe)
$
3.10
2.35
(0.75)
(24)
%
Average realized prices after effects of derivative settlements (3) :
Natural gas (per Mcf)
$
3.14
2.79
(0.35)
(11)
%
C2 Ethane (per Bbl)
$
7.85
5.65
(2.20)
(28)
%
C3+ NGLs (per Bbl)
$
27.41
23.91
(3.50)
(13)
%
Oil (per Bbl)
$
50.92
38.91
(12.01)
(24)
%
Weighted Average Combined (per Mcfe)
$
3.38
2.96
(0.42)
(12)
%
Average costs (per Mcfe):
Lease operating
$
0.13
0.08
(0.05)
(38)
%
Gathering and compression
$
0.70
0.64
(0.06)
(9)
%
Processing
$
0.66
0.69
0.03
5
%
Transportation
$
0.56
0.60
0.04
7
%
Production and ad valorem taxes
$
0.11
0.08
(0.03)
(27)
%
Marketing expense, net
$
0.22
0.12
(0.10)
(45)
%
Depletion, depreciation, amortization, and accretion
$
0.76
0.66
(0.10)
(13)
%
General and administrative (excluding equity-based compensation)
$
0.12
0.08
(0.04)
(33)
%
(1) Production data excludes volumes related to the VPP.
(2) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains on settlements of commodity derivatives (but does not include proceeds from the derivative monetizations in 2018 and 2020), 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.
(3) The average realized price for 2019 includes $54 million of the proceeds related to the South Jersey Litigation. See Note 16—Contingencies to the consolidated financial statements for further discussion on the South Jersey Litigation. Excluding the effect of the proceeds of the South Jersey Litigation settlement, the average realized price would have been $2.67 per Mcf.
Natural gas sales . Revenues from sales of natural gas decreased from $2.2 billion, which included litigation proceeds of $54 million, for the year ended December 31, 2019 to $1.8 billion for the year ended December 31, 2020, a decrease of $437 million. Please see Note 16— Contingencies to the consolidated financial statements for more information.
Excluding litigation proceeds, higher natural gas production volumes during the year ended December 31, 2020 accounted for an approximate $143 million increase in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price excluding the proceeds from the South Jersey Litigation), and decreases in our prices (excluding the effects of derivative settlements and proceeds from the South Jersey Litigation) accounted for an approximate $526 million decrease in year-over-year gas sales revenue (calculated as the change in the year-to-year average price excluding the proceeds from the South Jersey Litigation times current year production volumes).
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NGLs sales . Revenues from sales of NGLs decreased from $1.22 billion for the year ended December 31, 2019 to $1.16 billion for the year ended December 31, 2020, a decrease of $57 million, or 5%. Higher NGLs production volumes accounted for an approximate $277 million increase in year-over-year NGLs sales 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 $334 million decrease in year-over-year NGL sales 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 $178 million for the year ended December 31, 2019 to $112 million for the year ended December 31, 2020, a decrease of $66 million. Increased oil production volumes accounted for a $38 million increase in year-over-year oil sales 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 $104 million decrease in year-over-year oil sales 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 years ended December 31, 2019 and 2020, our commodity hedges resulted in derivative fair value gains of $464 million and $80 million, respectively. The commodity derivative fair value gains included $325 million and $795 million of cash proceeds on gains on settled derivatives for the years ended December 31, 2019 and 2020, respectively. Commodity derivative fair value gains (losses) for the year ended December 31, 2020 also include cash proceeds of $9 million related to derivatives that were monetized prior to their contractual settlement dates.
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 year ended December 31, 2020 includes amortization of $15 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 consolidated financial statements for more information on this transaction.
Other income . Other income remained relatively consistent at $4 million and $3 million for the years ended December 31, 2019 and 2020, respectively.
Lease operating expense . Lease operating expense for the exploration and production segment decreased from $146 million for the year ended December 31, 2019 to $99 million for the year ended December 31, 2020, a decrease of $47 million or 32%. On a per unit basis, lease operating expenses decreased from $0.13 per Mcfe for the year ended December 31, 2019 to $0.08 per Mcfe for the year ended December 31, 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 from $2.2 billion for the year ended December 31, 2019 to $2.5 billion for the year ended December 31, 2020. This is primarily a result of the 11% increase in production. Gathering and compression costs decreased from $0.70 per Mcfe for the year ended December 31, 2019 to $0.64 per Mcfe for the year ended December 31, 2020 primarily due to lower fuel costs as a result of decreased natural gas prices and $48 million in incentive fee rebates from Antero Midstream Corporation. Processing costs increased from $0.66 per Mcfe to $0.69 per Mcfe for the years ended December 31, 2019 and 2020, respectively, primarily due to increased NGL production in our production mix. Processing costs, however, decreased per NGL barrel year-over-year. Transportation costs increased from $0.56 per Mcfe to $0.60 per Mcfe for the years ended December 31, 2019 and 2020, respectively, primarily due to increased rates on the Rockies Express pipeline, which were effective October 2019 and demand charges for Mountaineer Xpress pipeline.
Production and ad valorem tax expense. Total production and ad valorem taxes decreased from $125 million for the year ended December 31, 2019 to $107 million for the year ended December 31, 2020, a decrease of $18 million or 15%, primarily due to lower commodity prices between periods. On a per Mcfe basis, production and ad valorem taxes decreased from $0.11 per Mcfe for
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the year ended December 31, 2019 to $0.08 per Mcfe for the year ended December 31, 2020. Production and ad valorem taxes as a percentage of natural gas revenues remained at 6% in each of the years ended December 31, 2019 and 2020.
Exploration expense . Exploration expense representing expenses incurred for unsuccessful lease acquisition efforts remained relatively flat at $1 million for each of the years ended December 31, 2019 and 2020.
Impairment of oil and gas properties . During the year ended December 31, 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 $419 million and $224 million of impairments for the years ended December 31, 2019 and 2020, respectively, 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 $893 million for the year ended December 31, 2019 to $862 million for the year ended December 31, 2020 for the exploration and production segment, a decrease of $31 million or 4%. DD&A per Mcfe decreased from $0.76 per Mcfe during the year ended December 31, 2019 to $0.66 per Mcfe during the year ended December 31, 2020 due to a reduction in the cost basis of producing properties as a result of the impairments discussed above as well as due to increases in proved reserves between periods.
General and administrative expense. General and administrative expense (excluding equity-based compensation expense) decreased from $139 million for the year ended December 31, 2019 to $111 million for the year ended December 31, 2020, a decrease of $28 million or 20%, primarily due to decreases in employee related expenses in the year ended December 31, 2020 as a result of ongoing cost savings initiatives including lower headcount between periods. We had 547 employees as of December 31, 2019 and 522 employees as of December 31, 2020. On a per unit basis, general and administrative expense excluding equity-based compensation decreased by 33%, from $0.12 per Mcfe during the year ended December 31, 2019 to $0.08 per Mcfe during the year ended December 31, 2020 as a result of higher production volumes and lower overall costs between periods.
Equity-based compensation expense . Noncash equity-based compensation expense increased from $21 million for the year ended December 31, 2019 to $23 million for the year ended December 31, 2020, an increase of $2 million or 8%, primarily due to new awards granted to officers and employees in 2020 partially offset by equity award forfeitures during 2020. When an equity award is forfeited, expense previously recognized for the award is reversed. See Note 10—Equity-Based Compensation and Retention Awards to the consolidated financial statements 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 each of the years ended December 31, 2019 and 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.
Marketing Segment Results for the Year Ended December 31, 2019 Compared to the Year Ended December 31, 2020
Marketing. Where feasible, we purchase and sell third-party natural gas and NGLs and market our excess firm transportation capacity, or engage third parties to conduct these activities on our behalf, in order to optimize the revenues from these transportation agreements. We have entered into long-term firm transportation agreements for a significant portion of our current and expected future production in order to secure guaranteed capacity to favorable markets.
Our net marketing expense decreased from $258 million, or $0.22 per Mcfe, for the year ended December 31, 2019 to $159 million, or $0.12 per Mcfe, for the year ended December 31, 2020. The decrease was driven by higher marketing volumes and the mitigation of some of our excess firm transportation expense.
Marketing revenues increased from $292 million for the year ended December 31, 2019 to $311 million for the year ended December 31, 2020, an increase of $19 million, or 6%, primarily due to increased marketing volumes.
Marketing expenses decreased from $550 million for the year ended December 31, 2019 to $469 million for the year ended December 31, 2020, a decrease of $81 million, or 15%. 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 $250 million and $146 million for the years ended December 31, 2019 and 2020, respectively.
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Antero Midstream Corporation Segment Results for the Year Ended December 31, 2019 Compared to the Year Ended December 31, 2020
During the period from January 1, 2019 through March 12, 2019, we included the results of Antero Midstream Partners in our consolidated financial statements. Effective March 13, 2019, we no longer consolidate the results of Antero Midstream Partners in our results. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions. We now account for our interest in Antero Midstream Corporation as an equity method investment.
Antero Midstream Corporation. Revenue from the Antero Midstream Corporation segment increased from $793 million, which included amortization of customer relationships of $57 million, for the year ended December 31, 2019 to $901 million, which included amortization of customer relationships of $71 million, for the year ended December 31, 2020, an increase of $108 million, or 14%. The increase in operating revenue was primarily due to an increase in gathering and compression volumes partially offset by a decrease in fresh water delivery volumes for the year ended December 31, 2020. Total operating expenses related to the segment decreased from $1.2 billion for the year ended December 31, 2019 to $1.0 billion for the year ended December 31, 2020 primarily due to a decrease in total impairments of $88 million period over period.
In addition, Antero Midstream Partners had equity in earnings of unconsolidated affiliates of $51 million and $86 million for the years ended December 31, 2019 and 2020, respectively.
Discussion of Items Not Allocated to Segments for the Year Ended December 31, 2019 Compared to the Year Ended December 31, 2020
Water earnout. In conjunction with the acquisition of the water handling and treatment assets, Antero Midstream agreed to pay us (a) $125 million in cash if Antero Midstream delivered 176 million barrels or more of fresh water during the period between January 1, 2017 and December 31, 2019 and (b) an additional $125 million in cash if Antero Midstream delivered 219 million barrels or more of fresh water during the period between January 1, 2018 and December 31, 2020. As of December 31, 2019, Antero Midstream had delivered more than the 176 million barrels, which entitled us to $125 million pursuant to clause (a) above, and, as a result, we recognized other income associated with the settlement on the water earnout. The cash proceeds were received in January 2020. As of December 31, 2020, Antero Midstream did not deliver more than 219 million barrels, and, as a result, no additional proceeds were earned with respect to the water earnout.
Impairment of equity method investment . In 2019 and 2020, we determined that events and circumstances indicated that the carrying value of our investment in Antero Midstream Corporation had experienced an other-than-temporary decline and we recorded impairments of $468 million and $611 million, respectively. The fair value of the equity method investment in Antero Midstream Corporation was based on the quoted market share price of Antero Midstream Corporation as of December 31, 2019 and March 31, 2020, respectively.
Interest expense. Our interest expense exclusive of interest expense related to Antero Midstream Partners’ indebtedness decreased from $228 million for the year ended December 31, 2019 to $200 million for the year ended December 31, 2020, a decrease of $28 million, or 12%, primarily due to the reduction in debt as a result of our debt repurchases of unsecured senior notes at prices below their stated value, partially offset by interest that accrued on the newly issued 2026 Convertible Notes and higher borrowings on our Credit Facility between periods. Interest expense includes approximately $11 million and $12 million of non-cash amortization of debt issuance costs and debt discounts and premiums for the years ended December 31, 2019 and 2020, respectively.
Income tax benefit. Income tax benefit increased from $74 million, with an effective tax rate of 20%, for the year ended December 31, 2019 to $397 million, with an effective tax rate of 24%, for the year ended December 31, 2020 primarily due to an increased book loss year over year. For the year ended December 31, 2020, our overall effective tax rate was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction and non-deductible equity-based compensation expenses. See Note 14—Income Taxes to our consolidated financial statements more for information regarding our income tax provision for the years ended December 31, 2019 and 2020.
As of December 31, 2019 and 2020, we had U.S. federal and state NOL carryforwards of approximately $2.3 billion and $2.0 billion, respectively. Many of these NOLs expire at various dates between 2032 and 2040 while others have no expiration date. Potential future legislation or the imposition of new or increased taxes may have a significant effect on our future taxable position.
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The impact of any such change would be recorded in the period in which such interpretation is received or legislation is enacted.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2019
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations —Results of Operations” in our Annual Report on Form 10-K for the year ended December 31, 2019 for a discussion of the results of operations for the year ended December 31, 2018 compared to the year ended December 31, 2019.
Capital Resources and Liquidity
Overview
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. 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.
The Credit Facility has a borrowing base of $2.85 billion and current lender commitments of $2.64 billion. The borrowing base is redetermined semi-annually based on certain factors including our reserves, natural gas, NGLs, and oil commodity prices, and the value of our hedge portfolio. The next redetermination of the borrowing base is scheduled to occur in April 2021. For a discussion of the risks of a decrease in the borrowing base under the Credit Facility, see “Item 1A. Risk Factors—The borrowing base under the Credit Facility may be reduced if commodity prices decline, which could hinder or prevent us from meeting our future capital needs. We may also be required to post additional collateral as financial assurance of our performance under certain contractual arrangements, which could adversely impact available liquidity under our Credit Facility.”
Our commodity hedge position provides us with additional liquidity because it provides us with the relative certainty of receiving a significant portion of our future expected revenues from operations despite potential declines in the price of natural gas. Our ability to make significant additional acquisitions for cash would require us to utilize borrowings on the Credit Facility or obtain additional equity or debt financing, which we may not be able to obtain on terms acceptable to us, or at all. The Credit Facility is funded by a syndicate of 25 banks. We believe that the participants in the syndicate have the capability to fund up to their current commitment. If one or more banks should not be able to do so, we may not have the full availability of the Credit Facility.
2020 Capital Spending and 2021 Capital Budget
For the year ended December 31, 2020, our total consolidated capital expenditures were approximately $785 million, including drilling and completion expenditures of $735 million, leasehold additions of $48 million, and other capital expenditures of $2 million. Our net capital budget for 2021 is $635 million. Our budget includes $590 million for drilling and completions and $45 million for leasehold expenditures. We do not budget for acquisitions. During 2021, we plan to operate an average of three drilling rigs and two completion crews and we plan to complete 65 to 70 horizontal wells in the Appalachian Basin in 2021. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities, and commodity prices.
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, 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.
Based on strip prices as of December 31, 2020, we believe that net cash provided from operating activities, available borrowings under the Credit Facility and 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. For more information on our outstanding indebtedness, see “—Debt Agreements and Contractual Obligations.”
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Cash Flows
The following table summarizes our cash flows for the years ended December 31, 2018, 2019 and 2020:
Year Ended December 31,
(in thousands)
2018
2019
2020
Net cash provided by operating activities
$
2,081,987
1,103,458
735,640
Net cash used in investing activities
(2,350,724)
(1,041,490)
(530,061)
Net cash provided by (used in) financing activities
240,296
557,564
(205,579)
Effect of deconsolidation of Antero Midstream Partners LP
—
(619,532)
—
Net increase (decrease) in cash and cash equivalents
$
(28,441)
—
—
Our consolidated cash flow statements for the years ended December 31, 2018 and 2019 include the cash flows related to Antero Midstream Partners for periods prior to March 13, 2019. Effective March 13, 2019, the Company's cash flows include only the operating, investing and financing activities related to Antero and therefore, the cash flows for the years ended December 31, 2018 and 2019 may not be representative of our expected future cash flows. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for more information.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2020
Operating Activities. Net cash provided by operating activities was $1.1 billion and $736 million for the years ended December 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, 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 global demand for natural gas, NGLs, and oil. These factors are beyond our control and are difficult to predict. For additional information on the impact of changing prices on our financial position, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
Investing Activities. Cash flows used in investing activities decreased from $1.0 billion for the year ended December 31, 2019 to $530 million for the year ended December 31, 2020, primarily due to a decrease in capital expenditures of $548 million during the year ended December 31, 2020 as compared to the same period in 2019, $297 million in proceeds received in connection with the Transactions in the year ended December 31, 2019, $100 million in proceeds received in connection with the sale of shares of Antero Midstream Corporation common stock in the year ended December 31, 2019, $125 million in settlement of the water earnout impacting the year ended December 31, 2020 and $216 million in proceeds received from the VPP in the year ended December 31, 2020. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements for further discussion on the Transactions.
In addition, the year ended December 31, 2019 included Antero Midstream Partners’ investments in joint ventures of $25 million and capital expenditures for water handling and treatment systems and gas gathering and compression systems of $73 million. Due to the deconsolidation of Antero Midstream Partners on March 12, 2019, cash flows used in investing activities for the year ended December 31, 2020 do not include costs attributable to Antero Midstream Partner’s investing activity. See Note 3—Deconsolidation of Antero Midstream Partners LP to the consolidated financial statements. Excluding Antero Midstream Partners, capital expenditures were $1.3 billion and $874 million for the years ended December 31, 2019 and 2020, respectively.
Total additions to unproved properties and drilling and completion costs decreased from $1.3 billion during the year ended December 31, 2019 to $826 million during the year ended December 31, 2020 primarily due to a decrease in drilling and completion activity, increased drilling and completion efficiencies and service cost deflation.
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Financing Activities. Net cash flows provided by financing activities was $558 million for the year ended December 31, 2019, compared to net cash flows used in financing activities of $206 million for the year ended December 31, 2020. Net borrowings on our Credit Facility and Antero Midstream Partners’ credit facility increased from $232 million during the year ended December 31, 2019 to $465 million during the year ended December 31, 2020. During the year ended December 31, 2020, approximately $1.2 billion was used to repurchase all of our 2021 Notes and repurchase a portion of our 2022 Notes, 2023 Notes and 2025 Notes, which were partially funded with borrowings on our Credit Facility, compared to $191 million used to repurchase senior notes in the year ended December 31, 2019. In addition, we repurchased and retired 28,193,237 shares of common stock for approximately $43 million during the year ended December 31, 2020 compared to repurchases of 13,390,617 shares of common stock for approximately $39 million during the year ended December 31, 2019.
During the year ended December 31, 2019, Antero Midstream Partners issued $650 million of senior notes prior to the Transactions and during the year ended December 31, 2020, we issued $288 million principal amount of 2026 Convertible Notes. Additionally, we also received $351 million for the sale of a noncontrolling interest in Martica during the year ended December 31, 2020. See Note 4—Transactions and Note 8—Long-Term Debt for more information on these transactions, respectively.
Year Ended December 31, 2018 Compared to Year Ended December 31, 2019
Refer to “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity” in our Annual Report on Form 10-K for the year ended December 31, 2019 for a discussion of the cash flows for the year ended December 31, 2018 compared to the year ended December 31, 2019.
Debt Agreements and Contractual Obligations
Debt Agreements
Senior Secured Revolving Credit Facility
The 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 semi-annual redeterminations. As of December 31, 2020, the borrowing base was $2.85 billion and lender commitments were $2.64 billion. The next redetermination of the borrowing base is scheduled to occur by the end of April 2021. The Credit Facility is scheduled to mature on October 26, 2022.
As of December 31, 2020, we had $1.0 billion of borrowings with a weighted average interest rate of 3.26% and $730 million of letters of credit outstanding under the Credit Facility. As of December 31, 2019, we had $552 million of borrowings, with a weighted average interest rate of 3.28%, and $623 million of letters of credit outstanding under the Credit Facility. The Credit Facility provides for borrowing under either an Adjusted LIBO Rate or an Alternate Base Rate (each as defined in the Credit Facility).
The Credit Facility contains restrictive covenants that may limit our ability to, among other things:
● incur additional indebtedness;
● sell assets;
● make loans to others;
● make investments;
● enter into mergers;
● pay dividends;
● hedge future production;
● incur liens; and
● engage in certain other transactions without the prior consent of the lenders.
However, many of these covenants will terminate during any Investment Grade Period (as defined in the Credit Facility).
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We were in compliance with the applicable covenants and ratios as of December 31, 2019 and 2020. The actual borrowing capacity available to us may be limited by the financial ratio covenants. As of December 31, 2020, our current ratio was 2.25 to 1.0 (based on the $2.85 billion borrowing base under the Credit Facility) and our interest coverage ratio was 7.30 to 1.0.
Senior Unsecured Notes
The following table summarizes certain material terms of our senior unsecured notes and convertible notes outstanding as of December 31, 2020:
2026
2022 Notes
2023 Notes
2025 Notes
Convertible Notes
Outstanding principal (in thousands)
$
660,516
$
574,182
$
590,000
$
287,500
Interest rate
5.125
%
5.625
%
5.00
%
4.25
%
Maturity date
December 1, 2022
June 1, 2023
March 1, 2025
September 1, 2026
Interest payment dates
June 1, Dec. 1
June 1, Dec. 1
Mar. 1, Sept. 1
Mar. 1, Sept. 1
Make-whole redemption date (1)
June 1, 2020
June 1, 2021
March 1, 2023
N/A (2)
(1) On or after these dates, we may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, we may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.
(2) The indenture governing the 2026 Convertible Notes does not allow us to optionally redeem the 2026 Convertible Notes prior to the maturity date.
On January 4, 2021 and January 26, 2021, we issued the 2026 Notes and 2029 Notes, respectively, at par. We used the proceeds from the issuances of the senior notes to repay borrowings outstanding under the Credit Facility and redeem previously issued senior notes. The following table summarizes certain material terms of the 2026 Notes and 2029 Notes:
2026 Notes
2029 Notes
Outstanding principal (in thousands)
$
500,000
$
700,000
Interest rate
8.375
%
7.625
%
Maturity date
July 15, 2026
February 1, 2029
Interest payment dates
Jan. 15, July 15
Feb. 1, Aug. 1
Make-whole redemption date (1)
January 15, 2026
February 1, 2027
(1) On or after these dates, we may redeem the applicable series of notes, in whole or in part, at a redemption price equal to 100% of the principal amount redeemed, together with accrued and unpaid interest up to the redemption date. At any time prior to these dates, we may redeem the notes at a redemption price that includes an applicable premium as defined in the indentures to such notes.
Please refer to Note 8—Long Term Debt to the consolidated financial statements for more 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. Any such repurchases will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved could be material. During the year ended December 31, 2020, we repurchased $1.4 billion principal amount of debt at a 13% weighted average discount, including all of our 2021 Notes and a portion of our 2022 Notes, 2023 Notes and 2025 Notes.
The senior notes indentures each contain restrictive covenants and restrict our ability to incur additional debt unless a pro forma minimum interest coverage ratio requirement of 2.25:1 is maintained. We were in compliance with such covenants as of December 31, 2019 and 2020.
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Contractual Obligations
A summary of our contractual obligations as of December 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.
Year Ended December 31,
(in millions)
2021
2022
2023
2024
2025
Thereafter
Total
Recorded contractual obligations:
Credit Facility (1)
$
—
1,017
—
—
—
—
1,017
Antero senior notes—principal (2)
—
661
574
—
590
287
2,112
Antero senior notes—interest (2)
108
108
58
42
27
12
355
Operating leases (3)
265
268
301
335
307
1,139
2,615
Finance leases (3)
1
—
—
—
—
—
1
Imputed interest for leases (3)
346
312
274
232
187
420
1,771
Asset retirement obligations (4)
—
—
—
—
—
54
54
Unrecorded contractual obligations:
Firm transportation (5)
1,080
1,037
1,065
1,025
985
6,948
12,140
Processing, gathering, and compression services (6)
55
52
59
59
48
114
387
Land payment obligations (7)
3
—
—
—
—
—
3
Total
$
1,858
3,455
2,331
1,693
2,144
8,974
20,455
(1) Includes outstanding principal amounts as of December 31, 2020. This table does not include future commitment fees, interest expense, or other fees on the 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 Credit Facility is scheduled to mature on October 26, 2022.
(2) Our senior notes include the 2022 Notes, 2023 Notes, 2025 Notes and 2026 Convertible Notes but does not include the 2026 Notes (aggregate principal amount of $500 million) or the 2029 Notes (aggregate principal amount of $700 million). After December 31, 2020, we redeemed all of our 2022 Notes and equitized a portion of our 2026 Convertible Notes. See Note 8—Long-Term Debt to the consolidated financial statements for more information on these transactions.
(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 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 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.
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 measure of future cash flows, and impairment of proved properties. We provide an expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in the preparation of our consolidated
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financial statements. See Note 2—Summary of Significant Accounting Policies to the consolidated financial statements for a discussion of additional accounting policies and estimates made by management.
Successful Efforts Method
The Company accounts for its natural gas, NGLs, and oil exploration and development activities under the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete productive wells, development wells, and undeveloped leases are capitalized. Oil and gas lease acquisition costs are also capitalized. Exploration costs, including personnel and other internal costs, geological and geophysical expenses, delay rentals for gas and oil leases, and costs associated with unsuccessful lease acquisitions are charged to expense as incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when we determine that the well does not contain reserves in commercially viable quantities. The Company reviews exploration costs related to wells in progress at the end of each quarter and makes a determination, based on known results of drilling at that time, whether the costs should continue to be capitalized pending further well testing and results, or charged to expense. We have not incurred any such charges in the years ended December 31, 2018, 2019 and 2020. The sale of a partial interest in a proved property is accounted for as a cost recovery, and no gain or loss is recognized as long as this treatment does not significantly affect the units of production amortization rate. A gain or loss is recognized for all other sales of producing properties.
Unproved properties with significant acquisition costs are assessed for impairment on a property by property basis, and any impairment in value is charged to expense. Impairment is assessed based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, and future plans to develop acreage. Unproved properties and the related costs are transferred to proved properties when reserves are discovered on, or otherwise attributed to, the property. Proceeds from sales of partial interests in unproved properties are accounted for as a recovery of cost without recognition of any gain or loss until the cost has been recovered. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $549 million, $393 million, and $224 million for the years ended December 31, 2018, 2019 and 2020, respectively.
The successful efforts method of accounting can have a significant impact on our operational results when we are entering a new exploratory area in anticipation of finding a gas and oil field that will be the focus of future development drilling activities. The initial exploratory wells may be unsuccessful and would be expensed if reserves are not found in economic quantities. Seismic costs can be substantial, which will result in additional exploration expenses when incurred. Additionally, the application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred.
Natural Gas, NGLs, and Oil Reserve Quantities and Standardized Measure of Future Cash Flows
Our internal technical staff prepares the estimates of natural gas, NGLs, and oil reserves and associated future net cash flows, which are audited by our independent reserve engineers. Current accounting guidance allows only proved natural gas, NGLs, and oil reserves to be included in our financial statement disclosures. The SEC has defined proved reserves as the estimated quantities of natural gas, NGLs, and oil which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Proved undeveloped reserves include reserves that are expected to be drilled and developed within five years; wells that are not drilled within five years from booking are reclassified from proved reserves to probable reserves. Reserves are used in our depletion calculation and in assessing the carrying value of our oil and gas properties.
Our independent reserve engineers and internal technical staff must make a number of subjective assumptions based on their professional judgment in developing reserve estimates. Reserve estimates consider recent production levels and other technical information about each field. Natural gas, NGLs, and oil reserve engineering is a subjective process of estimating underground accumulations of natural gas, NGLs, and oil that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, natural gas, NGLs, and oil prices, cost changes, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates are generally different from the quantities of natural gas, NGLs, and oil that are ultimately recovered. We cannot predict the amounts or timing of future reserve revisions. Any significant revisions could affect the future amortization rates of capitalized costs and result in a material asset impairment.
Impairment of Proved Properties
We evaluate the carrying amount of our proved natural gas, NGLs, and oil properties for impairment on a geological reservoir basis whenever events or changes in circumstances indicate that a property’s carrying amount may not be
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recoverable. Under GAAP for successful efforts accounting, if the carrying amount exceeds the estimated undiscounted future net cash flows (measured using futures prices at the end of a quarter), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeded the estimated fair value of the properties.
We did not record any impairments for proved properties during the years ended December 31, 2018 and 2020. During the year ended December 31, 2019 the Utica Shale carrying value exceeded the estimated fair value of the Utica Shale assets based on sales of other properties. As a result, we recorded an impairment of $881 million related to proved oil and gas properties in the Utica Shale during the year ended December 31, 2019.
Based on current future commodity prices, we currently do not anticipate having to record any impairment charge for our proved properties in the near future. We estimate that if strip prices were to decline by approximately 2.5% from future pricing levels as of December 31, 2020, estimated future net revenues for our Utica properties would approximate the carrying amount of the properties and further evaluation of the fair value of those properties would be required in order to determine if an impairment charge would be necessary under GAAP. For our Marcellus properties, strip pricing would have to decline by more than approximately 10% from year-end 2020 levels before further evaluation of those properties would be required in order to determine if an impairment charge would be necessary under GAAP. We are unable, however, to predict commodity prices with any greater precision than the futures market.
Fair Value Measurement
The FASB ASC Topic 820, Fair Value Measurements and Disclosures , clarifies the definition of fair value, establishes a framework for measuring fair value, and sets forth disclosure requirements about fair value measurements. This guidance also relates to all nonfinancial assets and liabilities that are not recognized or disclosed on a recurring basis (e.g., the initial recognition of asset retirement obligations and impairments of long- lived assets). The fair value is the price that we estimate would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. A fair value hierarchy is used to prioritize inputs to valuation techniques used to estimate fair value. An asset or liability subject to the fair value requirements is categorized within the hierarchy based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the asset or liability. The highest priority (Level 1) is given to unadjusted quoted market prices in active markets for identical assets or liabilities, and the lowest priority (Level 3) is given to unobservable inputs. Level 2 inputs are data, other than quoted prices included within Level 1, that are observable for the asset or liability, either directly or indirectly.
We account for our investment in Antero Midstream under the equity method of accounting. We evaluate our equity method investment for impairment when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the fair value of the investment to the carrying value of the investment to determine whether potential impairment has occurred. If the fair value is less than the carrying value and management considers the decline in value to be other-than-temporary, the excess of the carrying value over the fair value is recognized in the financial statements as an impairment loss. See Note 10—Equity-Based Compensation and Retention Awards to the consolidated financial statements for further discussion on our equity method investments.
As of December 31, 2019 and March 31, 2020, we determined that events and circumstances indicated that the carrying value had experienced an other-than-temporary decline and we recorded impairment expense of $468 million and $611 million, respectively. The fair value of the equity method investment in Antero Midstream was based on the quoted market common stock price of Antero Midstream as of December 31, 2019 (Level 1).
Income Taxes
We are subject to state and federal income taxes, but are currently not in a cash tax paying position with respect to federal income taxes. The difference between our financial statement income tax expense and our federal income tax liability is primarily due to the differences in the tax and financial statement treatment of oil and gas properties and derivative instruments. Our deferred tax assets and liabilities result from temporary differences between tax and financial statement income, primarily from derivative instruments, oil and gas properties and net operating loss (“NOL”) carryforwards. As of December 31, 2020, we have U.S. federal and state NOLs expiring at various dates from 2032 to 2040 while others have no expiration date, which resulted in the recognition of significant deferred tax assets. We record deferred income tax expense to the extent our deferred tax liabilities exceed our deferred tax assets. We record a deferred income tax benefit to the extent our deferred tax assets exceed our deferred tax liabilities.
We record a valuation allowance when we believe all or a portion of our deferred tax assets will not be realized. In assessing
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the realizability of our deferred tax assets, management considers whether some portion or all of the deferred tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred tax assets are deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment, estimates of which may be imprecise due to unforeseen future events or conditions outside of our control, including changes in commodity prices or changes to tax laws and regulations. The amount of deferred tax assets considered realizable could change based upon the amounts of taxable income actually generated, or as estimates of future taxable income change. As of December 31, 2020, we have recognized a valuation allowance of $46 million for NOLs we do not expect to realize that are primarily attributable to states in which we no longer operate.
The calculation of deferred tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations. We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the Internal Revenue Service or state revenue authorities.
New Accounting Pronouncements
On August 5, 2020, the FASB 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, Debt with Conversion and Other Options , that require separate accounting for conversion features, 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 $85 million, net of deferred income taxes and equity issuance costs, to long-term debt and deferred income tax liability, as applicable, from stockholders’ equity as of December 31, 2020, which amount is subject to adjustment for any conversions until adoption of this new standard. Additionally, annual interest expense for the 2026 Convertible Notes will be based on an effective interest rate of 4.8% as compared to 15.1% for the year ended December 31, 2020. We do not believe that adoption of the standard will impact our operational strategies or development prospects.
Off-Balance Sheet Arrangements
As of December 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.