EDGAR 10-K Filing

Company CIK: 1433270
Filing Year: 2025
Filename: 1433270_10-K_2025_0001558370-25-000864.json

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ITEM 1. BUSINESS
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Our Company and Organizational Structure
Antero Resources Corporation (individually referred to as “Antero”) and its consolidated subsidiaries (collectively referred to as “Antero Resources,” the “Company,” “we,” “us” or “our”) are engaged in the development, production, exploration and acquisition of natural gas, NGLs and oil properties located in the Appalachian Basin. The Company targets large, repeatable resource plays where horizontal drilling and advanced fracture stimulation technologies provide the means to economically develop and produce natural gas, NGLs and oil from unconventional formations. As of December 31, 2024, we held approximately 521,000 net acres of natural gas, NGLs and oil properties located in the Appalachian Basin primarily in West Virginia and Ohio. Our corporate headquarters is in Denver, Colorado.
Ownership in Antero Midstream
Antero Midstream is a growth-oriented midstream energy company formed to own, operate and develop midstream energy assets that primarily service our completion and production activity in the Appalachian Basin. Antero Midstream’s assets consist of gathering systems and compression facilities, water handling and blending facilities, and interests in processing and fractionation plants, through which it provides services to us under long-term contracts.
We have an interest in Antero Midstream that provides significant influence, but not control, over Antero Midstream. As a result, we account for our interest in Antero Midstream using the equity method of accounting. As of December 31, 2024, we owned 29% of Antero Midstream’s common stock.
General
The following table provides a summary of selected data for our Appalachian Basin natural gas, NGLs and oil assets as of the date and for the period indicated.
Three Months Ended
As of December 31, 2024
December 31, 2024
Gross
Average
Proved
Net Proved
Potential
Net Daily
Reserves (1) (2)
PV-10 (3)
Developed
Total
Drilling
Production
(Bcfe)
(in millions)
Wells (4)
Net Acres
Locations (5)
(MMcfe/d)
Appalachian Basin
17,903
$
3,830
1,443
521,038
1,137
3,431
Discounted future income taxes
(335)
Standardized Measure (6)
$
3,495
(1) Estimated proved reserve volumes and values were calculated assuming partial ethane recovery, with rejection of the remaining ethane and using the unweighted 12 month average of the first-day-of-the-month prices (“SEC reserves prices”) for the year ended December 31, 2024, which were $2.12 per Mcf for natural gas, $10.51 per Bbl for ethane, $42.34 per Bbl for C3+ NGLs and $61.60 per Bbl for oil for the Appalachian Basin based on Henry Hub and WTI reference prices of $2.13 per MMBtu and $75.54 per Bbl, respectively.
(2) Proved reserves for the noncontrolling interests in Martica as of December 31, 2024 were 57 Bcfe.
(3) PV-10 is a non-GAAP financial measure. We believe that the presentation of PV-10 is relevant and useful to our investors as supplemental disclosure to the standardized measure of future net cash flows, or after-tax amount, because it presents the discounted future net cash flows attributable to our proved reserves prior to taking into account future corporate income taxes and our current tax structure. While the standardized measure is dependent on the unique tax situation of each company, PV-10 is based on a pricing methodology and discount factors that are consistent for all companies. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. The difference between the standardized measure and the PV-10 amount is the discounted amount of estimated future income taxes. Future income taxes are not basin specific, and therefore, the standardized measure is only at a company level. See Note 20-Supplemental Information on Oil and Gas Producing Activities to our consolidated financial statements for additional information about the calculation of standardized measure.
(4) Excludes certain vertical wells with no proved reserves booked that were primarily acquired in conjunction with leasehold acreage acquisitions.
(5) Gross potential drilling locations are comprised of 186 locations classified as proved undeveloped and 951 locations classified as probable and possible and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024. See “Item 1A. Risk Factors” for risks and uncertainties related to developing our potential well locations contained in our proved, probable and possible reserve categories.
(6) Standardized measure of discounted future net cash flows for the noncontrolling interests in Martica as of December 31, 2024 was $101 million.
For the year ended December 31, 2024, our total consolidated capital expenditures were $721 million, including drilling and completion expenditures of $620 million, leasehold additions of $91 million and other capital expenditures of $10 million. We completed 41 net horizontal wells during the year ended December 31, 2024. Our net capital budget for 2025 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions other than leasehold acquisitions. During 2025, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. We periodically review our capital expenditures and adjust our budget and its allocation based on liquidity, drilling results, leasehold acquisition opportunities and commodity prices.
Business Strategy and Competitive Strengths
Experienced Management Team
Our management team has worked together for many years and has established a successful track record of executing in unconventional resource plays. We intend to leverage our team’s experience delineating and developing natural gas resource plays to continue developing our reserves and production, primarily on our existing multi-year project inventory.
Strong Balance Sheet and Sustainable Leverage Profile
We are focused on maintaining a strong balance sheet, which includes maintaining a sustainable leverage profile. As of December 31, 2023 and 2024, we had total debt of $1.5 billion. See Note 7-Long-Term Debt to our consolidated financial statements for additional information.
Focused, Long-Lived Asset Base with Sufficient Takeaway Capacity
We have assembled a portfolio of long-lived properties that are characterized by what we believe to be high repeatability and low geologic risk. Our drilling opportunities are focused in the Appalachian Basin where we have a substantial inventory of liquids-rich locations. Additionally, we have secured sufficient long-term firm takeaway capacity on major pipelines in our core operating area to accommodate our current development plans and move our production to various markets.
Integrated Business Platform
We operate in the following reportable 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. See Note 17-Reportable Segments to our consolidated financial statements for additional information on our industry segment operations.
Culture of Continuous Improvement and Responsible Stewardship
We are committed to a culture of continuous improvement, which serves as our foundation to develop and achieve our ESG goals as well as further our goal of environmental stewardship. Innovation, collaboration, technology and establishing meaningful goals have enabled us to improve our safety record, partner with Antero Midstream to recycle or reuse a substantial majority of our flowback and produced water and further our commitment to lowering GHG emission intensity across our operations. Our 2023 ESG Report, available on our website at www.anteroresources.com/esg, includes more information on our ESG goals, as well as specific initiatives we have in place to help achieve these goals. Our 2023 ESG Report and other information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them. Additionally, see “-Regulation of Environmental and Occupational Safety and Health Matters” for more information on GHG emissions and “Item 1A. Risk Factors” for risks and uncertainties related to our business operations.
Hedge Program
We may utilize a hedging program to mitigate volatility in commodity prices and to protect certain of our expected future cash flows when circumstances warrant. However, due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased substantially. Our hedging program may include commodity fixed price swaps, basis swaps, collars or other similar instruments related to the price risk associated with our production. Additionally, our consolidated VIE, Martica, also enters into hedging contracts for natural gas, NGLs and oil, and the gains and losses from such contracts are fully attributable to the noncontrolling interests in Martica. As of December 31, 2024, the estimated fair value of our commodity net derivative contracts was a liability of $47 million. See Note 11-Derivative Instruments to the consolidated financial statements for additional information.
Drilling Partnerships
2021-2024 Drilling Partnership
On February 17, 2021, we announced the formation of a drilling partnership with QL Capital Partners (“QL”), an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program. Under the terms of the arrangement, each year in which QL participates represents an annual tranche, and QL will be conveyed a working interest in any wells spud by us during such tranche year. For 2021 through 2024, we agreed to the estimated internal rate of return (“IRR”) of our capital budget for each annual tranche, and QL agreed to participate in all four annual tranches. We develop and manage the drilling program associated with each tranche, including the selection of wells. Additionally, for each annual tranche, we will enter into assignments, bills of sale and conveyances pursuant to which QL will be conveyed a proportionate working interest percentage in each well spud in that year, which conveyances will not be subject to any reversion.
Under the terms of the arrangement, QL funded development capital of 20% for wells spud in 2021 and 2024 and 15% for wells spud in 2022 and 2023, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, we may receive a carry in the form of a one-time payment from QL for each annual tranche if the IRR for such tranche exceeds certain specified returns, which will be determined no earlier than October 31 and no later than December 1 following the end of each tranche year. We received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023 and a carry of $32 million for the 2023 tranche during the year ended December 31, 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. Subject to the preceding sentence, for any wells included in a tranche, QL is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. See Note 3-Transactions to our consolidated financial statements for additional information.
2025 Drilling Partnership
On December 11, 2024, we entered into a drilling partnership with an unaffiliated third-party (“the 2025 Drilling Partnership”). Under the terms of the arrangement, the third-party will participate in and fund a share of total development capital expenses for wells spud by Antero during the 2025 calendar year. For each well spud during the 2025 calendar year, the third-party will receive a 15% working interest in such wells and will fund greater than 15% of total development capital expenses for such wells. Subject to the preceding sentence, for any wells spud in the calendar year 2025, the third-party is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. Additionally, for each well in the partnership, we will enter into an assignment, bill of sale and conveyance pursuant to which the third-party will be conveyed a proportionate working interest percentage in such well, which conveyances will not be subject to any reversion. See Note 3-Transactions to our consolidated financial statements for additional information.
Our Properties and Operations
Reserves
The table below summarizes our estimated proved reserves as of December 31, 2023 and 2024, which were prepared assuming partial ethane recovery, and rejection of the remaining ethane. When ethane is rejected at the processing plant, it is left in the gas stream and sold with the methane gas.
Oil and
Percentage
Natural Gas
NGLs
Condensate
Equivalents
of Proved
(Bcf)
(MMBbl)
(MMBbl)
(Bcfe)
Reserves
As of December 31, 2023 (1)
Proved developed reserves (2)
7,912
13,783
%
Proved undeveloped reserves (3)
2,702
4,338
%
Total
10,614
1,222
18,121
%
As of December 31, 2024 (1)
Proved developed reserves (2)
7,876
13,747
%
Proved undeveloped reserves (3)
2,727
4,156
%
Total
10,603
1,193
17,903
%
(1) The SEC reserves prices for the year ended December 31, 2023 were $2.63 per Mcf for natural gas, $11.75 per Bbl for ethane, $38.01 per Bbl for C3+ NGLs and $64.97 per Bbl for oil for the Appalachian Basin based on Henry Hub and WTI reference prices of $2.64 per MMBtu and $78.21 per Bbl, respectively. The SEC
reserves prices for the year ended December 31, 2024 were $2.12 per Mcf for natural gas, $10.51 per Bbl for ethane, $42.34 per Bbl for C3+ NGLs and $61.60 per Bbl for oil for the Appalachian Basin based on Henry Hub and WTI reference prices of $2.13 per MMBtu and $75.54 per Bbl, respectively.
(2) Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2024 were 57 Bcfe, which consisted of 44 Bcf of natural gas and 2 MMBbl of NGLs.
(3) There were no proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2023 and 2024.
Proved Reserves
The following table summarizes the changes in our estimated proved reserves (in Bcfe):
Proved reserves, December 31, 2023
18,121
Extensions, discoveries and other additions
Revisions of previous estimates
Revisions to five-year development plan
Price revisions
(77)
Sales of reserves in place
(184)
Production
(1,252)
Proved reserves, December 31, 2024
17,903
Extensions and discoveries of 783 Bcfe of proved reserves resulted from delineation and developmental drilling in the Appalachian Basin. Revisions of previous estimates of 305 Bcfe primarily relates to increases in our ownership interests. Revisions to the five-year development plan of 207 Bcfe includes an upward revision of 416 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, partially offset by a downward revision of 209 Bcfe for locations that were not developed within five years of initial booking as proved reserves. Price revisions of 77 Bcfe are due to decreases in prices for natural gas, and oil between periods, partially offset by increases in prices for NGLs for the year ended December 31, 2024. Sales of reserves in place of 184 Bcfe are related to the 2025 Drilling Partnership. Estimated proved reserves as of December 31, 2024 totaled 17.9 Bcfe, a decrease of 1% from December 31, 2023.
Proved Undeveloped Reserves
Proved undeveloped reserves are included in the previous table of total proved reserves. The following table summarizes the changes in our estimated proved undeveloped reserves (in Bcfe):
Proved undeveloped reserves, December 31, 2023
4,338
Extensions, discoveries and other additions
Revisions of previous estimates
Revisions to five-year development plan
Reclassifications to proved developed reserves
(1,416)
Sales of reserves in place
(184)
Proved undeveloped reserves, December 31, 2024
4,156
Extensions and discoveries of 783 Bcfe of proved undeveloped reserves resulted from delineation and developmental drilling in the Appalachian Basin. Revisions of previous estimates of 389 Bcfe includes an upward revision of 496 Bcfe for increases in our ownership interests, partially offset by downward revisions of 107 Bcfe primarily related to ethane recovery. Revisions to the five-year development plan of 246 Bcfe includes an upward revision of 434 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, partially offset by a downward revision of 188 Bcfe for locations that were not developed within five years of initial booking as proved reserves. Sales of reserves in place of 184 Bcfe are related to the 2025 Drilling Partnership. Estimated proved undeveloped reserves as of December 31, 2024 totaled 4.2 Bcfe, a decrease of 4% from December 31, 2023.
During the year ended December 31, 2024, we converted 1,416 Bcfe, or 33% of our proved undeveloped reserves to proved developed reserves and incurred drilling and completion costs of $429 million. We spent an additional $186 million on development costs related primarily to drilled and uncompleted wells and properties in the proved undeveloped classification as of December 31, 2024, resulting in total development costs incurred of $615 million, as disclosed in Note 20-Supplemental Information on Oil and Gas Producing Activities to the consolidated financial statements. Estimated future development costs relating to the development of our proved undeveloped reserves as of December 31, 2024 are $1.8 billion, or $0.44 per Mcfe, over the next five years. We maintain a five-year development plan, which is reviewed by our Board of Directors, which supports our maintenance capital program. The development plan is reviewed annually to ensure capital is allocated to the wells that have the highest risk-adjusted rates of return within our inventory of undrilled well locations. Based on strip pricing as of December 31, 2024, we believe that net cash provided by
operating activities will be sufficient to finance such future development costs. While our development program is primarily focused on drilling our proved undeveloped reserves, we will also continue to drill leasehold delineation wells and build on our current leasehold position. See “Item 1A. Risk Factors-The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.”
As of December 31, 2024, an estimated 5,617 of our net leasehold acres, containing 177 gross wells (14 net wells) associated with proved undeveloped reserves, are subject to renewal prior to scheduled drilling. Some of these leases have contract renewal options and some will need to be renegotiated. We estimate a potential cost of $16 million to renew the 5,617 acres based upon current leasing authorizations and option to extend payments. Proved undeveloped reserves of 366 Bcfe are related to these leases. Historically, we have had a high success rate in renewing leases, and we expect that we will be able to renew substantially all of the leases underlying this acreage prior to the scheduled drilling dates. Based on our historical success rate in renewing leases, we estimate that we may not be able to renew leases covering 37 Bcfe of these proved undeveloped reserves.
If we are not able to renew these leases prior to the scheduled drilling dates, our quantities of net proved undeveloped reserves will be somewhat reduced on those locations.
Preparation of Reserve Estimates
Our proved reserve estimates as of December 31, 2022, 2023 and 2024 included in this Annual Report on Form 10-K were prepared by our internal reserve engineers in accordance with petroleum engineering and evaluation standards published by the Society of Petroleum Evaluation Engineers and definitions and guidelines established by the SEC. These proved reserve estimates have been audited by our independent engineers, DeGolyer and MacNaughton (“D&M”). A copy of the summary report of D&M with respect to our reserves as of December 31, 2024 is filed as Exhibit 99.1 to this Annual Report on Form 10-K. The technical person at D&M primarily responsible for reviewing our reserves estimates was Dilhan Ilk, P.E. Mr. Ilk is a Registered Professional Engineer in the State of Texas (License No. 139334), is a member of the Society of Petroleum Engineers, and has in excess of 10 years of experience in oil and gas reservoir studies and reserves evaluations. Mr. Ilk graduated from the Istanbul Technical University in 2003 with a Bachelor of Science degree in Petroleum Engineering, a Master of Science degree in Petroleum Engineering from Texas A&M University in 2005 and a Doctor of Philosophy degree in Petroleum Engineering from Texas A&M University in 2010. The technical persons responsible for overseeing the audit of our reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.
Our internal staff of petroleum engineers and geoscience professionals works closely with D&M to ensure the integrity, accuracy and timeliness of data furnished to our independent reserve engineers in their reserve auditing process. Periodically, our technical team meets with D&M to review properties and discuss methods and assumptions used by us to prepare reserve estimates. Our internally prepared reserve estimates and related reports are reviewed and approved by our Senior Vice President - Reserves, Planning and Midstream, W. Patrick Ash. Mr. Ash has served as Senior Vice President - Reserves, Planning and Midstream since June 2019. Previously, he served as Vice President - Reservoir Engineering and Planning from December 2017 to June 2019. Prior to December 2017, Mr. Ash was at Ultra Petroleum for six years in management positions of increasing responsibility, most recently serving as Vice President, Development. In this position he led the reservoir engineering, geoscience, and corporate engineering groups. From 2001 to 2011, Mr. Ash served in engineering roles at Devon Energy, NFR Energy and Encana Corporation. Mr. Ash holds a B.S. in Petroleum Engineering from Texas A&M University and an MBA from Washington University in St. Louis.
Our senior management and Board of Directors also reviews our reserve estimates and related reports with Mr. Ash and other members of our technical staff. Additionally, our senior management reviews and approves any significant changes to our proved reserves on a quarterly basis.
Identification of Potential Well Locations
Our identified potential well locations represent locations to which proved, probable or possible reserves were attributable based on SEC reserves prices as of December 31, 2024.
Production, Price and Cost History
Natural gas, NGLs and oil are commodities, and the prices that we receive for our production are largely a function of market supply and demand. Demand for our products is impacted by general economic conditions, weather and other seasonal conditions. Over or under supply of natural gas, NGLs or oil can result in substantial price volatility. A substantial or extended decline in commodity prices, or poor drilling results, could have a material adverse effect on our financial position, results of operations, cash flows, quantities of reserves that may be economically produced and our ability to access capital markets. See “Item 1A. Risk
Factors- Natural gas, NGLs and oil price volatility, or a substantial or prolonged period of low natural gas, NGLs and oil prices, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.”
Exploration and Production and Marketing Segments
The following table sets forth information regarding our production, realized prices and production costs for the years ended December 31, 2022, 2023 and 2024. For additional information on price calculations, see information set forth in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.”
Year Ended December 31,
Production data (1) (2):
Natural gas (Bcf)
C2 Ethane (MBbl)
18,818
24,657
30,391
C3+ NGLs (MBbl)
39,914
41,927
42,434
Oil (MBbl)
3,223
3,874
3,693
Combined (Bcfe)
1,170
1,238
1,252
Daily combined production (MMcfe/d)
3,204
3,392
3,421
Average prices before effects of derivative settlements (3):
Natural gas (per Mcf)
$
6.92
2.69
2.29
C2 Ethane (per Bbl) (4)
$
20.41
10.14
9.05
C3+ NGLs (per Bbl)
$
52.98
37.85
42.23
Oil (per Bbl)
$
85.53
63.80
62.29
Combined average sales prices before effects of derivative settlements (per Mcfe) (1)
$
7.09
3.45
3.29
Combined average sales prices after effects of derivative settlements (per Mcfe) (1)
$
5.46
3.43
3.30
Average Costs (per Mcfe):
Lease operating
$
0.09
0.10
0.09
Gathering, compression, processing and transportation
$
2.23
2.13
2.16
Production and ad valorem taxes
$
0.25
0.13
0.17
Marketing, net
$
0.10
0.06
0.05
General and administrative (excluding equity-based compensation)
$
0.12
0.13
0.13
Depletion, depreciation, amortization and accretion
$
0.62
0.61
0.61
(1) Production data excludes volumes related to the volumetric production payment transaction (“VPP”).
(2) 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 may not reflect their relative economic value.
(3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains or losses on settlements of commodity derivatives (but does not include payments for the derivative monetizations in 2023 and 2024). These commodity derivatives do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.
(4) The average realized price for the years ended December 31, 2022, 2023 and 2024 includes $10 million, $15 million and $2 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before the effects of derivatives for the years ended December 31, 2022, 2023 and 2024 would have been $19.88 per Bbl, $9.55 per Bbl and $8.99 per Bbl, respectively.
Acreage
The following table sets forth certain information regarding the total developed and undeveloped acreage in which we own an interest as of December 31, 2024. Approximately 86% of our net Appalachian Basin acreage is held by production. Acreage related to royalty, overriding royalty, and other similar interests is excluded from this table.
Developed Acres
Undeveloped Acres (2)
Total Acres (2)
Gross
Net
Gross
Net
Gross
Net
Appalachian Basin (1)
290,133
272,956
277,178
248,082
567,311
521,038
(1) Our acreage is located in West Virginia, Ohio and Pennsylvania.
(2) There are 12,839 gross (11,799 net), 9,303 gross (8,014 net) and 24,342 gross (22,508 net) acres subject to expiration during the years ending December 31, 2025, 2026 and 2027, respectively, if production is not established within the spacing units covering the acreage prior to the expiration dates and they are not otherwise extended or renewed.
Productive Wells
As of December 31, 2024, we had 1,859 gross and 1,687 net productive wells, all of which are natural gas wells located in the Appalachian Basin. Net wells reflect the sum of our percentage ownership in gross wells.
Drilling Activity
The following table sets forth the results of our drilling activity for wells drilled and completed during the years ended December 31, 2022, 2023 and 2024. Gross wells reflect the number of wells in which we own an interest and include historical drilling activity in the Appalachian Basin. Net wells reflect the sum of our working interests in gross wells.
Year Ended December 31,
2024 (1)
Gross
Net
Gross
Net
Gross
Net
Development wells:
Productive
Dry
-
-
-
-
-
-
Total development wells
Exploratory wells:
Productive
-
-
-
-
Dry
-
-
-
-
-
-
Total exploratory wells
-
-
-
-
(1) Well counts exclude 23 gross wells (17 net wells) that were in the process of being completed as of December 31, 2024.
Gathering and Compression
The substantial majority of our exploration and development activities are supported by the natural gas gathering and compression assets of Antero Midstream. As a result, our agreements with Antero Midstream allow us to obtain the necessary gathering and compression capacity for our production, and we have leveraged our relationship with Antero Midstream to support our development. Antero Midstream’s capital expenditures for gas gathering and compression infrastructure that services our production were $132 million for the years ended December 31, 2023 and 2024. Subject to pre-existing dedications and other third-party commitments, we have dedicated to Antero Midstream substantially all of our current and future acreage in West Virginia and Ohio for gathering and compression services.
As of December 31, 2024, Antero Midstream’s gathering and compression systems included 708 miles of gas gathering pipelines and 4.6 Bcf/d of compression capacity in the Appalachian Basin. We also have access to additional third-party gas gathering pipelines. The gathering, compression and dehydration services provided by third parties are contracted on a fixed-fee basis.
Natural Gas Processing
Many of our wells in the Appalachian Basin allow us to produce liquids-rich natural gas that contains a significant amount of NGLs. Liquids-rich natural gas is processed, which involves the removal and separation of NGLs from the wellhead natural gas.
NGLs are valuable commodities once removed from the natural gas stream in a cryogenic processing facility yielding y-grade liquids. Y-grade liquids are then fractionated, thereby breaking up the y-grade liquid into its key components. Fractionation refers to the process by which a y-grade stream is separated into individual products such as ethane, propane, normal butane, isobutane and natural gasoline. Fractionation occurs by heating the y-grade liquids to allow for the separation of the component parts based on the specific boiling points of each product. Each of the individual products has its own market price.
The combination of infrastructure constraints in the Appalachian Basin and low ethane prices has resulted in many producers “rejecting” rather than “recovering” ethane. Ethane rejection occurs when ethane is left in the wellhead gas stream when the gas is processed, rather than being extracted and sold as a liquid after fractionation. When ethane is left in the gas stream, the Btu content of the residue gas at the tailgate of the processing plant is higher. Producers generally elect to “reject” ethane when the price received for the ethane in the gas stream is greater than the net price received for the ethane being sold as a liquid after fractionation. When ethane is recovered, the Btu content of the residue gas is lower, but a producer is then able to recover the value of the ethane sold as a separate product.
Given the existing commodity price environment and the current limited ethane market in the northeast, we are currently rejecting the majority of the ethane obtained in the natural gas stream when processing our liquids-rich gas. However, we realize a pricing upgrade when selling the remaining NGLs product stream at current prices. We may elect to recover more ethane when ethane prices result in a value for the ethane that is greater than the Btu equivalent residue gas and incremental recovery costs.
We contract with MarkWest to provide cryogenic processing capacity for our Appalachian Basin production. Antero Midstream owns a 50% interest in the Joint Venture to develop processing and fractionation assets in Appalachia. Below is a summary of the nameplate capacity of the processing plants owned by MarkWest and the Joint Venture, our contracted capacity at these plants and their completion status.
Plant
Processing
Contracted
Nameplate
Processing
Capacity
Capacity
Completion
(MMcf/d)
(MMcf/d)
Status
Sherwood 1 through 13 (1)
2,600
2,600
In service
Smithburg 1 (1)
In service
Seneca 1 through 4 (1)
In service
Total
3,600
3,400
(1) MarkWest owns the gas processing plants referred to as Sherwood 1 through 6 and Seneca 1 through 4 and the Joint Venture owns the gas processing plants referred to as Sherwood 7 through 13 and Smithburg 1. The Joint Venture also owns a 33 1/3% interest in two fractionation facilities located at MarkWest’s Hopedale complex.
Transportation and Takeaway Capacity
We have entered into firm transportation agreements with various pipelines that enable us to deliver natural gas to the Midwest, Gulf Coast, Eastern Regional, and Mid-Atlantic markets. Our primary firm transportation commitments include the following:
Midwest-Chicago Regional Markets
We have several firm transportation contracts with pipelines that have capacity to deliver natural gas to the Chicago and Michigan markets. The Chicago directed pipelines include the Rockies Express Pipeline (“REX”), the Midwestern Gas Transmission pipeline (“MGT”), the Natural Gas Pipeline Company of America pipeline (“NGPL”), and the ANR Pipeline Company pipeline (“ANR Chicago”). The firm transportation contract on REX provides firm capacity for 400,000 MMBtu/d and delivers gas to downstream contracts on MGT, NGPL and ANR Chicago.
We have 125,000, 75,000 and 200,000 MMBtu/d of firm transportation on MGT, NGPL and ANR Chicago, respectively. The MGT and NGPL contracts deliver gas to the Chicago city gate area and the ANR Chicago contract delivers natural gas to Chicago in the summer and Michigan in the winter. The Chicago and Michigan contracts expire at various dates from 2029 through 2033.
Gulf Coast, Atlantic Seaboard and International Markets
We have firm transportation contracts with various pipelines to access the Gulf Coast, Atlantic Seaboard and international markets. These contracts include firm capacity on the following pipelines: (i) Columbia Gas Transmission Pipeline (“TCO”), (ii) Columbia Gulf Transmission Pipeline (“Columbia Gulf”), (iii) Stonewall Gas Gathering (“SGG”), (iv) Eastern Gas Transmission and Storage Pipeline (“EGTS”), (v) Tennessee Gas Pipeline (“Tennessee”), (vi) ANR Pipeline (“ANR Gulf”), (vii) Rover Pipeline (“Rover”), (viii) Mountaineer Xpress Pipeline (“MXP”), (ix) Columbia Gas Transmission IPP Pool (“TCO IPP”), (x) Gulf Xpress Pipeline (“GXP”), (xi) Enterprise Products Partners ATEX Pipeline (“ATEX”) and (xii) Sunoco Pipeline (“Mariner East 2”). Our diverse portfolio of firm capacity gives us the flexibility to move natural gas to the local Appalachia market or other preferred markets with more favorable pricing. These firm capacity contracts include:
● TCO and TCO west bound (“TCO WB”) firm capacity of approximately 433,000 MMBtu/d and 746,000 MMBtu/d respectively, and our TCO WB increases to approximately 800,000 MMBtu/d in 2027. This firm transportation provide us with access to the local Appalachia and the Gulf Coast markets via the Tennessee and Columbia Gulf pipelines. We have 430,000 MMBtu/d of firm transportation on Columbia Gulf. These contracts expire at various dates from 2027 through 2058.
● TCO east bound firm capacity of approximately 356,000 MMBtu/d that delivers (i) 330,000 MMBtu/d of natural gas to the Cove Point LNG facility and (ii) approximately 26,000 MMBtu/d to the Atlantic Seaboard. These contracts expire at various dates from 2029 to 2038.
● SGG firm capacity of 900,000 MMBtu/d that transports gas from various gathering system interconnection points and the MarkWest Sherwood plant complex to the TCO WB System through 2030. However, our SGG minimum volume commitment decreases to 600,000 MMBtu/d in 2027.
● MXP firm capacity of 700,000 MMBtu/d that transports gas from the MarkWest Sherwood plant complex to Tennessee or Leach, Kentucky. We have approximately 183,000 MMBtu/d on GXP, which continues from Leach, Kentucky to the Gulf Coast. These contracts expire in 2034.
● Rover Pipeline firm capacity of 870,000 MMBtu/d, which decreases to 840,000 MMBtu/d in 2026, that connects the Appalachian Basin to Midwest and Gulf Coast markets via the ANR Chicago and ANR Gulf segments. These contracts expire at various dates from 2025 to 2033.
● EGTS firm capacity of 1,000 MMBtu/d through 2027 from the MarkWest Sherwood plant complex to the Texas Eastern Transmission Corporation Pipeline.
● Tennessee firm capacity of 790,000 MMBtu/d, which decreases to 200,000 MMBtu/d in 2030, to deliver natural gas from the Broad Run interconnect on TCO WB to the Gulf Coast market. These contracts expire at various dates from 2030 to 2033.
● ANR Gulf firm capacity of 600,000 MMBtu/d to deliver natural gas from West Virginia and Ohio to the Gulf Coast market. This contract expires in 2045.
● ATEX firm capacity of 20,000 Bbl/d to deliver ethane to Mont Belvieu, Texas. This contract expires in 2028.
● Mariner East 2 firm capacity for ethane of 11,500 Bbl/d and propane and butane of 65,000 Bbl/d to deliver to Marcus Hook, Pennsylvania. These contracts expire in 2028 and 2029, respectively. Mariner East 2 provides access to international markets via trans-ocean LPG carriers.
Under firm transportation contracts, we are obligated to deliver minimum daily volumes or pay fees for any deficiencies in deliveries. See Note 14-Commitments to our consolidated financial statements for information on our minimum fees for such contracts. Based on current projected 2025 annual production guidance, we estimate that we could incur annual net marketing costs of $0.04 per Mcfe to $0.06 per Mcfe in 2025 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third-party gas and capture positive basis differentials. Where permitted, we continue to actively market any excess capacity in order to offset minimum commitment fees and those activities are recorded in our net marketing expense.
Delivery Commitments
We have entered into various firm sales contracts to deliver and sell gas and NGLs. We believe we will have sufficient production quantities to meet substantially all of such commitments. We may purchase gas from third parties to satisfy shortfalls should they occur.
As of December 31, 2024, our firm sales commitments through 2029 included:
Natural Gas
Ethane
C3+ NGLs
Year Ending December 31,
(MMBtu/d)
(Bbl/d)
(Bbl/d)
602,618
85,500
10,126
600,000
85,500
-
600,000
86,500
-
600,000
85,000
-
530,000
75,000
-
We utilize a part of our firm transportation capacity to deliver gas and NGLs under the majority of these firm sales contracts. We have firm transportation contracts that require us to either ship products on said pipelines or pay demand charges for shortfalls. The minimum demand fees are reflected in our table of contractual obligations. See Note 14-Commitments to our consolidated financial statements.
Water Handling Operations
Our agreements with Antero Midstream allow us to obtain fresh water for use in our drilling and completion operations, as well as services to dispose of flowback and produced water resulting from our operations.
Antero Midstream owns two independent fresh water distribution systems that distribute fresh water from the Ohio River and several regional water sources, for well completion operations in the Appalachian Basin. These systems consist of permanent buried pipelines, portable surface pipelines and water storage facilities, as well as pumping stations to transport the water throughout the pipeline networks. The surface pipelines are moved to well pads to service completion operations to the extent necessary and feasible. Through Antero Midstream, we also recycle and reuse the majority of our flowback and produced water through blending.
As of December 31, 2024, Antero Midstream owned and operated 233 miles of buried water pipelines and 163 miles of portable surface water pipelines in the Appalachian Basin. Additionally, as of December 31, 2024, Antero Midstream had the ability to store approximately 5 million barrels of fresh water in 34 impoundments equipped with transfer pumps located throughout our leasehold acreage.
Major Customers
No customer accounted for more than 10% of our sales for the years ended December 31, 2023 and 2024.
Title to Properties
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. As is customary in the industry, often in the case of undeveloped properties and acquisitions of producing properties, cursory investigation of record title is made at the time of such acquisitions. Further investigations may be made before commencement of drilling operations on undeveloped properties. Individual properties may be subject to burdens that we believe do not materially interfere with the use, or affect the value of, the properties. Burdens on properties may include:
● customary royalty interests;
● liens incident to operating agreements and for current taxes;
● obligations or duties under applicable laws;
● development obligations under natural gas leases; or
● net profits interests.
Seasonality
Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, cold winters, hot summers or severe weather events can significantly increase demand and price fluctuations, while seasonal anomalies, such as mild winters, mild summers or severe weather events can sometimes lessen the impact of these fluctuations. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the spring, summer and fall. This can also reduce seasonal demand fluctuations. Seasonal anomalies can also increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay our operations.
Competition
The oil and natural gas industry is intensely competitive, and we compete with other companies in our industry that have greater resources than we do. Many of these companies not only explore for and produce natural gas, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive natural gas properties and exploratory prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit, and may be able to expend greater resources to attract and maintain industry personnel. In addition, these companies may have a greater ability to continue exploration activities during periods of low natural gas market prices. Our larger competitors may be able to absorb the burden of existing, and any changes to, federal, state, and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
Regulation of the Oil and Natural Gas Industry
General
We operate on private or state-owned lands, and we have no production from federal mineral interests. Our oil and natural gas operations are subject to extensive, and frequently changing, laws and regulations related to well permitting, drilling and completion, and to the production, transportation and sale of natural gas, NGLs and oil. We believe compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, such laws and regulations are frequently amended or reinterpreted. Additional proposals and proceedings that affect the oil and natural gas industry are regularly considered by Congress, federal agencies, state and local governments and the courts. We cannot predict when or whether any such proposals may become effective. Therefore, we are unable to predict the future costs or impact of compliance. The regulatory burden on the industry increases the cost of doing business and affects profitability. We do not believe that any regulatory changes will affect us materially differently from the way they will affect our competitors.
Regulation of Production of Natural Gas and Oil
We own interests in properties located onshore in West Virginia, Ohio and Pennsylvania, and our production activities on these properties are subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. These statutes and regulations address requirements related to permits for drilling of wells, bonding to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, the plugging and abandonment of wells, venting or flaring of natural gas and the ratability or fair apportionment of production from fields and individual wells. In addition, all of the states in which we own and operate properties have regulations governing environmental and conservation matters, including provisions for the handling and disposing or discharge of waste materials, the unitization or pooling of natural gas and oil properties, the establishment of maximum allowable rates of production from natural gas and oil wells, and the size of drilling and spacing units or proration units and the density of wells that may be drilled. Some states also have granted their oil and gas regulators the power to prorate production to the market demand for oil and gas, and other states may elect to do so in the future. The effect of these regulations is to limit the amount of natural gas and oil that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of natural gas, NGLs and oil within its jurisdiction.
The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Regulation of Transportation of Natural Gas
The transportation and sale, or resale, of natural gas in interstate commerce are regulated by the FERC, under the Natural Gas Act of 1938 (“NGA”), the Natural Gas Policy Act of 1978 (“NGPA”), and regulations issued under those statutes. FERC regulates interstate natural gas transportation rates and service conditions, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Since 1985, FERC has endeavored to make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis. Although FERC’s orders do not directly regulate natural gas producers, they are intended to foster increased competition within all phases of the natural gas industry.
Gathering services, which occurs upstream of jurisdictional transmission services, are regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC. Although FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material
difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Regulation of Sales of Natural Gas, NGLs and Oil
The prices at which we sell natural gas, NGLs and oil are not currently subject to federal regulation and, for the most part, are not subject to state regulation. FERC, however, regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Similarly, the price we receive from the sale of oil and NGLs is affected by the cost of transporting those products to market. FERC regulates the transportation of oil and liquids on interstate pipelines under the provision of the Interstate Commerce Act, the Energy Policy Act of 1992 and regulations issued under those statutes. Intrastate pipeline transportation of oil, NGLs and other products, is dependent on pipelines whose rates, terms and conditions of service are subject to regulation by state regulatory bodies under state statutes. In addition, while sales by producers of natural gas and all sales of crude oil, condensate and NGLs can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.
With regard to our physical sales of these energy commodities and any related hedging activities that we undertake, we are required to observe anti-market manipulation laws and related regulations enforced by the FERC as described below, the U.S. Commodity Futures Trading Commission under the Commodity Exchange Act (“CEA”) and the Federal Trade Commission (“FTC”). We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Should we violate the anti-market manipulation laws and regulations, we could be subject to fines and penalties as well as related third-party damage claims by, among others, market participants, sellers, royalty owners and taxing authorities.
The Domenici Barton Energy Policy Act of 2005 (“EPAct of 2005”) amended the NGA to add an anti-market manipulation provision, which makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore, provided FERC with additional civil penalty authority. In Order No. 670, FERC promulgated rules implementing the anti-market manipulation provision of the EPAct of 2005, which make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (ii) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rules do not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but do apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting requirements under Order No. 704 described below. Under the EPAct of 2005, FERC has the power to assess civil penalties of up to $1,000,000 (adjusted annually for inflation) per day for each violation of the NGA and the NGPA. In January 2025, FERC issued an order (Order No. 906) increasing the maximum civil penalty amounts under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of up to $1,584,648 per violation per day.
Under Order No. 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors, natural gas marketers and natural gas producers are required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 also requires market participants to indicate whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.
The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. In November 2009, the FTC issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to approximately $1.5 million (adjusted annually for inflation) per violation per day. Together with FERC, these agencies have imposed broad rules and regulations prohibiting fraud and manipulation in oil and gas markets and energy futures markets.
Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action FERC will take. We do not believe that any regulatory changes will affect us materially differently from the way they will affect our competitors.
Regulation of Environmental and Occupational Safety and Health Matters
General
Our operations are subject to numerous stringent federal, regional, state and local statutes and regulations governing occupational safety and health and the discharge of materials into the environment or otherwise relating to environmental protection. Violations of these laws can result in substantial administrative, civil and criminal penalties. These laws and regulations may require the acquisition of permits before drilling or other regulated activity commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling, completing, producing and transporting through pipelines, govern the sourcing and disposal of water used in the drilling and completion process, limit or prohibit activities in certain areas and on certain lands lying within wilderness, wetlands, frontier and other protected areas or areas with endangered or threatened species restrictions, require some form of remedial action to prevent or mitigate pollution from former operations such as plugging abandoned wells or closing earthen pits, establish specific safety and health criteria addressing worker protection and impose substantial liabilities for pollution resulting from operations or failure to comply with applicable laws and regulations. In addition, these laws and regulations may restrict the rate of production.
The following is a summary of the more significant existing environmental and occupational health and workplace safety laws and regulations, as amended from time to time, to which our business operations are subject and for which compliance may have a material adverse impact on our financial position, results of operations or cash flows.
Hazardous Substances and Waste Handling
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. In addition, despite the “petroleum exclusion” of Section 101(14) of CERCLA, which currently encompasses crude oil and natural gas, we generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics; however, we are unaware of any liabilities arising under CERCLA for which we may be held responsible that would materially and adversely affect us.
The Resource Conservation and Recovery Act (“RCRA”), and analogous state laws, establish detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, these wastes may be regulated by the EPA, or state agencies under RCRA’s less stringent nonhazardous solid waste provisions, or under state laws or other federal laws. Moreover, it is possible that these particular oil and natural gas exploration, development and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. In addition, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as waste solvents, laboratory wastes and waste compressor oils that may become regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
We currently own, lease or operate numerous properties that have been used for oil and natural gas exploration and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including offsite locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. We are able to control directly the operation of only those wells with respect to which we act or have acted as operator. The failure of a prior owner or operator to comply with applicable environmental regulations may, in certain circumstances, be attributed to us as current owners or operators under CERCLA. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, regardless of fault, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or waste pit closure operations to prevent future contamination.
Water Discharges
The Federal Water Pollution Control Act, or the Clean Water Act (the “CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States (“WOTUS”). The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”). The scope of these regulated waters has been subject to substantial controversy and uncertainty, with the Corps and EPA pursuing several rulemakings since 2015 to attempt to define the scope of WOTUS. Most recently, EPA issued a WOTUS rule in September 2023 that is currently only implemented in 24 states due to ongoing litigation. Thus, the operative definition of WOTUS varies by state. To the extent the implementation of this rule, results of the litigation, or any action further expands the scope of the CWA’s jurisdiction in areas where we operate, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could delay the development of our natural gas and oil projects. Similarly, any increased costs or delays for such permits may impact the development of pipeline infrastructure, which may impact our ability to transport our products. Also, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” in connection with on-site storage of significant quantities of oil. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of oil and other substances in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages. However, we cannot predict what, when or how the Trump administration may take action with respect to any of these regulations. As a result, there is significant uncertainty with respect to wetlands regulations under the CWA at this time.
Air Emissions
The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as compressor stations, through air emissions standards, construction and operating permitting programs, and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants, the costs of which could be significant. The need to obtain permits has the potential to delay the development of our oil and natural gas projects. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. Most recently, in 2020, the Trump administration maintained the National Ambient Air Quality Standard (“NAAQS”) for ozone at 70 parts per billion for both the 8-hour primary and secondary standards. The EPA’s reconsideration of this standard remains ongoing. These decisions are subject to legal challenge. Additionally, we cannot predict what actions, if any, and on what timeline, the Trump administration may take with respect to these regulations. The EPA has also issued final rules under the Clean Air Act that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants programs. These final rules require, among other things, capturing or combustion of certain emissions, as well as emission leak detection and repair programs. These regulations also establish specific new requirements regarding emissions from production related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of natural gas and oil projects and increase our costs of development and production, which costs could be significant. However, we do not believe that compliance with such current requirements will have a material adverse effect on our operations.
Regulation of “Greenhouse Gas” Emissions
In response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration (“PSD”), construction and Title V operating permit reviews for certain large stationary sources that are already major sources of criteria pollutant emissions regulated under the statute. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.
The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and volatile organic compounds (“VOCs”) from new and modified oil and natural gas production and natural gas processing and transmission facilities. Most recently, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities,
known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources. The requirements include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems and zero-emission requirements for certain devices. The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. These rules are currently subject to legal challenges, and we cannot predict the ultimate outcome. However, the OOOOb rules are currently in effect.
Moreover, compliance with the new rules may affect the amount we owe under the methane fee imposed under the recently passed Inflation Reduction Act (“IRA 2022”) because compliance with EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states have separately imposed their own regulations on methane emissions from oil and gas production activities. The Trump administration may seek to challenge, repeal, or revise EPA’s methane rules; however, we cannot predict what, when, or how the new administration may take actions to rollback or otherwise revise existing methane-related regulations. Existing climate change-related regulation has already become a focus of the new Trump Administration. On his first day in office, President Trump signed several Executive Orders rescinding many of the previous administration’s climate-related Executive Orders and associated initiatives. President Trump’s directives included, amongst others, directing the EPA to reconsider its 2009 endangerment findings relating to GHGs, which provides regulatory justification for federal GHG permitting and methane emission control requirements, and directing the EPA to reconsider its use of Social Cost of GHG estimates in federal permitting decisions. We cannot predict the ultimate impact of these Executive Orders or any similar future changes on our business or results of operations.
We have developed a program to reduce and manage our methane and other air emissions that is guided by the following principles: (i) monitoring the science of climate risks and air quality, (ii) addressing stakeholder inquiries regarding our position on climate risks, methane emissions and air quality matters, (iii) monitoring our measures to reduce methane and air emissions and (iv) overseeing development of methane and air emission reductions from activities, including implementation of best-management practices and new technology.
We have taken several steps to manage methane and other emissions from our operations. For example, Antero incorporated a balanced drill out technique as the final step in the completions process where the majority of gas from the wellbore is maintained downhole. This is followed by a controlled emission flowback process that captures gas and sends it to sales. We have a sustained history of managing methane emissions from our operations, as demonstrated by our continued use of emission reduction techniques and equipment.
When we permit a facility, we install air pollution control equipment to comply with federal Clean Air Act NSPS and applicable Best Available Control Technology standards. The control equipment includes Vapor Recovery Towers and Vapor Recovery Units, which capture methane emissions and direct them to a sales line. This technology allows us to recover a valuable product and reduce emissions. Additionally, residual storage tank emissions are controlled with vapor combustors that reduce methane emissions by 98%. We continue to transition away from intermittent and low bleed natural gas supplied pneumatic devices to air supplied pneumatics at all new production facilities along with limiting natural gas pneumatic releases by routing to a process, sales line or combustion device. In 2024, we eliminated or replaced approximately 267 natural gas driven pneumatic devices, which brings the total number of pneumatic devices eliminated or replaced in our operations to approximately 7,000 since this initiative began in 2021.
Our methane and air emission control program also includes a Leak Detection and Repair (“LDAR”) program. Periodic inspections are conducted to minimize emissions by detecting leaks and repairing them promptly. The LDAR program inspections utilize a state-of-the-art Optical Gas Imaging, Forward Looking Infrared Radar camera to identify equipment leaks. In addition, our Operations group has a maintenance program in place, which includes cleaning and replacing thief hatch seals and worn equipment to prevent leaks from occurring. Our efforts to date have resulted in a declining volume of methane emissions based on the decreasing number of leaks detected by our LDAR program.
We participate in the EPA’s Natural Gas STAR Program, which provides a framework for companies with U.S. oil and gas operations to implement methane reduction technologies and practices and document their emission reduction activities. We are also members of ONE Future, a voluntary industry collective that seeks to reduce methane emission intensity across the natural gas supply chain, as well as The Environmental Partnership, which focuses on voluntary measures that the oil and gas industry can take to reduce
emissions of methane and VOCs through the implementation of LDAR, equipment emission monitoring and maintenance and repair programs. By joining these programs, we committed to: (i) evaluate our methane emission reduction opportunities, (ii) implement methane reduction projects where feasible and (iii) annually report our methane emissions and/or our methane reduction activities.
Since 2017, we have published an annual ESG report, which highlights our most significant environmental program improvements and initiatives. As highlighted in our ESG report, our methane leak loss rate in 2023 was 0.011%, calculated in accordance with ONE Future, well below the ONE Future voluntary industry target of 1%.
During 2024, our GHG/methane emission reduction efforts included the following activities:
● Continued our responsibly sourced gas certification effort and expanded the number of wells and production that is Trustwell certified by Project Canary.
● Conducted quarterly aerial flyovers of the majority of our well pad locations as part of our emissions monitoring initiatives.
● Eliminated or replaced approximately 267 intermittent and low-bleed natural gas-controlled pneumatics.
● Plugged and abandoned certain older vertical wells that were acquired in conjunction with property acquisitions. Plugging and abandoning older, low producing wells can reduce methane emissions.
● Preventatively replaced and/or repaired aging storage tank vapor control system equipment to reduce potential for fugitive methane and GHG emissions.
● Developed a marginal abatement cost curve (“MACC”) to effectively and systematically model emission reduction projects across our operations. Our MACC process is instrumental in evaluating the capital improvements required to achieve our net zero scope 1 and scope 2 emissions targets.
● Continued utilization of the following procedures or equipment in our operations:
o Quarterly facility LDAR inspections, which in most cases is twice the frequency required by current federal regulation.
o Lockdown thief hatches and isolation valves on storage tanks at all new production facilities to reduce unnecessary potential emissions during daily operations and maintenance activity.
o Operated burner management systems with two stages of pressure control, which are certified by the manufacturer to meet EPA performance standards, to optimize combustor efficiency.
o Vapor recovery systems that incorporate up to three stages of vapor recovery in our process.
o Low pressure separators as part of our completions process to recover methane that would otherwise be flared during flowback operations and allows such methane to become a salable product.
o Periodic pressure relief valve testing and repair.
o Balanced-pressure well drill outs, which minimize the potential for venting and/or flaring of gas from our wells during the well completion process.
o Mobile gas lift units, which reduces emissions that would otherwise be emitted by well swabbing and liquids unloading.
o Utilized our ESG Advisory Council together with our GHG/Methane Reduction Team to manage the identification, evaluation, monitoring, mitigation and adaptation, as applicable, of risks and opportunities related to the environment.
We continue to assess various opportunities for emission reductions. However, we cannot guarantee that we will be able to implement any of the opportunities that we may review or explore. For any such opportunities that we do choose to implement, we cannot guarantee that we will be able to implement them within a specific timeframe or across all operational assets. For risks and uncertainties related to ESG matters, see “Item 1A. Risk Factors-Business Operations-ESG matters and conservation measures may adversely impact our business.”
Increasingly, oil and natural gas companies are exposed to litigation risks related to climate risks. We are not currently party to any such litigation, but could be named in future actions making similar claims of liability and, depending on the nature of the claims asserted and other factors, such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
In the United States, no comprehensive climate legislation has been implemented at the federal level. In August 2022, the IRA 2022 was signed into law, appropriating significant federal funding for renewable energy initiatives and, for the first time ever, imposing a federal fee on excess methane emissions from certain oil and gas facilities. On November 12, 2024, the EPA finalized a rule requiring oil and gas facilities that emit more than 25,000 metric tons of CO2 per year to pay a set fee per metric ton of methane emissions that exceed statutory thresholds. Congress may seek to revise the IRA 2022 to remove this rule, but we cannot predict whether, when, or how Congress might seek to do so. Unless repealed or modified, the emissions fee and renewable and low-carbon energy funding provisions of the law could increase our operating costs and reduce demand for oil and natural gas, which could in turn adversely affect our business and results of operations, as well as those of our customers. The Trump administration may seek to challenge, repeal, or revise the methane fee rule or the IRA 2022; however, we cannot predict when or whether the new administration may take these actions, if at all, or the resulting impact on our business operations.
Internationally, the Paris Agreement requires member states to individually determine and submit non-binding emissions reduction targets every five years beginning in 2020. President Biden recommitted the United States to the Paris Agreement in February 2021, and in April 2021, established a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. However, on January 20, 2025, President Trump signed an Executive Order once again withdrawing the United States from the Paris Agreement. The United States’ participation in future United Nations climate-related conferences and the impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, any Conference of the Parties, or other international conventions cannot be predicted at this time.
Additionally, our access to capital may be impacted by climate risk policies. Financial institutions may adopt policies that have the effect of reducing the funding provided to the oil and natural gas industry. To the extent implemented or pursued, such policies and commitments could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. While we cannot predict how or to what extent sustainable lending and investment practices may impact our operations, a material reduction in the capital available to the oil and natural gas industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could impact our business and operations.
In addition, in March of 2024, the SEC finalized a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and periodic reports. However, this rule is currently paused pending litigation and is expected to be repealed. The timeline for any repeal, if at all, is subject to a number of uncertainties and likely could face legal challenges that would further delay the implementation of any repeal, and we cannot predict the ultimate outcome. Further, in October 2023, the Governor of California signed the Climate Corporate Data Accountability Act (“CCDAA”) and Climate-Related Financial Risk Act (“CRFRA”) into law. The CCDAA requires both public and private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2 and 3 GHG emissions. The CRFRA requires the disclosure of a climate-related financial risk report (in line with the Task Force on the Climate-Related Financial Disclosures (“TCFD”) recommendations or equivalent disclosure requirements under the International Sustainability Standards Board’s (“ISSB”) climate-relate disclosure standards) every other year for public and private companies that are “doing business in California” and have total annual revenue of at least $500 million. Reporting under both laws would begin in 2026. These laws are currently subject to legal challenges, but the outcome of such challenges is uncertain at this time. Additionally, New York and other jurisdictions are considering adopting similar climate disclosure laws. Currently, the ultimate impact of these laws on our business is uncertain. The Governor of California has directed further consideration of the implementation deadlines for each of the laws, and there is potential for legal challenges to be filed with respect to the scope of the law, but, absent clarification or revisions to the law, alongside the SEC rule, implementation may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate-related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. Separately, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, and there is the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures to be misleading or deficient.
Moreover, climate risks may also result in various physical risks, such as the increased frequency or intensity of extreme weather events or changes in meteorological and hydrological patterns, that could adversely impact our financial condition and
operations, as well as those or our suppliers and customers. Such physical risks may result in damage to our facilities or otherwise adversely impact our operations, such as if we become subject to water use curtailments in response to drought, or demand for our products, such as to the extent warmer winters reduce the demand for energy for heating purposes. Such physical risks may also impact the infrastructure we rely on to produce or transport our products. One or more of these developments could have a material adverse effect on our business, financial condition, and operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (“SDWA”), over certain hydraulic fracturing activities. For example, although we do not use diesel fuel down hole in our hydraulic fracturing operations, in February 2014, the EPA issued permitting guidance for the industry regarding such activities. In addition, the EPA finalized rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. New legislation regulating hydraulic fracturing may be considered again in future, though we cannot predict when or the scope of any such legislation at this time. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the Ohio Legislature has adopted a law requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drill baseline water quality sampling of certain water wells near a proposed horizontal well. Local government also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have banned and others seek to ban hydraulic fracturing altogether. We believe that we are in compliance with the applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Occupational Safety and Health Act
We are also subject to the requirements of the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities, and citizens. We do not believe that any noncompliance with worker health and safety requirements has occurred or will have a material adverse effect on our business or operations.
Endangered Species Act
The federal Endangered Species Act (“ESA”), provides for the protection of endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on natural gas and oil leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. The U.S. Fish and Wildlife Service (“USFWS”), may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit access to protected areas for natural gas and oil development. Moreover, as a result of a settlement, the USFWS was required to make a determination as to whether more than 250 species classified as endangered or threatened should be listed under the ESA by the completion of the agency’s 2017 fiscal year. For example, in November 2022, the USFWS listed the northern long-eared bat, whose habitat includes the areas in which we operate, as an endangered species under the ESA, which became effective on March 31, 2023. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could
have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
Although we have not experienced any material adverse effect from compliance with environmental requirements, there is no assurance that this will continue. We did not have any material capital or other non-recurring expenditures in connection with complying with environmental laws or environmental remediation matters in 2024, nor do we anticipate that such expenditures will be material in 2025.
Human Capital
We believe that our employees and contractors are significant contributors to our success and the future success of our Company, which depends on our ability to attract, retain and motivate qualified personnel. The skills, experience and industry knowledge of key employees significantly benefit our operations and performance.
As of December 31, 2024, we had 616 full-time employees, including 46 in executive, finance, treasury, legal and administration, 27 in information technology, 17 in geology, 240 in production and operations, 183 in midstream and water, 52 in land and 51 in accounting and internal audit. Additionally, we utilize the services of independent contractors to perform various field and other services. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be generally good.
Total Rewards
We have demonstrated a history of investing in our workforce by offering competitive salaries, fair living wages and comprehensive benefits. To foster a stronger sense of ownership and align the interests of our personnel with shareholders, we provide long-term incentive programs that include restricted stock units, performance share units and cash awards. Additionally, we offer short-term cash incentive programs, which are discretionary and are based on individual and company performance factors, among others. Furthermore, we offer comprehensive benefits to our full-time employees working 30 hours or more per week. To be an employer of choice and maintain the strength of our workforce, we consistently assess the current business environment and labor market to refine our compensation and benefits programs and other resources available to our personnel. Among other benefits, these include:
● comprehensive health insurance, including vision and dental; we have not increased employee premiums in over 17 years;
● employee Health Savings Accounts, including contributions to these accounts by us;
● 401(k) retirement savings plan with discretionary contribution matching opportunities;
● competitive paid time off and sick leave programs;
● paid parental leave;
● student loan repayment matching opportunities; and
● wellness support benefits including an employee assistance program, short-term and long-term disability coverage and gym memberships and/or fitness subscription reimbursement, among others.
Role Based Support
We support our employees’ professional development. To help our personnel succeed in their roles, we emphasize continuous formal and informal training, developmental and educational opportunities. We also assist employees with the cost of educational pursuits through our student loan repayment matching program. Additionally, we have a robust performance evaluation program, which includes tools to facilitate goals and career progression.
Workforce Health and Safety
The safety of our employees is a core tenet of our values, and our safety goal is zero incidents and zero injuries. A strong safety culture reduces risk, enhances productivity and builds a strong reputation in the communities in which we operate. We have earned a reputation as a safe and an environmentally responsible operator through continuous improvement in our safety performance. This makes us more attractive for current and new employees.
We invest in safety training and coaching, promote risk assessments and encourage visible safety leadership. Employees are empowered and expected to stop or refuse to perform a job if it is not safe or cannot be performed safely. We sponsor emergency preparedness programs, conduct regular audits to assess our performance and celebrate our successes in which we acknowledge employees and contractors alike who have exhibited strong safety leadership during the course of the year. These many efforts combine to create a culture of safety throughout the company and provide a positive influence on our contractor community.
Equal Employment Opportunity and Workplace Culture
We are committed to building a culture where equal employment opportunity and a strong workplace culture are core philosophies across our operations. We prohibit all forms of unlawful discrimination and are committed to making opportunities for development and progress available to all employees so their talents can be fully developed to maximize our and their success. We believe that creating an environment that cultivates a sense of belonging requires encouraging employees to continue to educate themselves about each other’s experiences, and we strive to promote the respect and dignity of all persons. We also believe it is important that we foster education, communication and understanding about diverse backgrounds and perspectives as well as belonging. Finally, in line with these beliefs and our commitment to equal employment opportunity, we expect recruiters operating on our behalf to provide us with a diverse pool of candidates.
Address, Internet Website and Availability of Public Filings
Our principal executive offices are located at 1615 Wynkoop Street, Denver, Colorado 80202 and our telephone number is (303) 357-7310. Our website is located at www.anteroresources.com.
We furnish or file our Annual Reports on Form 10-K, our Quarterly Reports on Form 10-Q, our Current Reports on Form 8-K and amendments to such reports and other documents with the SEC under the Exchange Act. The SEC also maintains an internet website at www.sec.gov that contains reports, proxy and information statements and other information regarding issuers, including us, that file electronically with the SEC.
We also make these documents available free of charge at www.anteroresources.com under the “Investors” link as soon as reasonably practicable after they are filed or furnished with the SEC.
Information on our website is not incorporated into this Annual Report on Form 10-K or our other filings with the SEC and is not a part of them.

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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS
We are subject to certain risks and hazards due to the nature of the business activities we conduct. The risks described in this Annual Report on Form 10-K could materially and adversely affect our business, financial condition, cash flows and results of operations. We may experience additional risks and uncertainties not currently known to us. Furthermore, as a result of developments occurring in the future, conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations.
Commodity Prices
Natural gas, NGLs and oil price volatility, or a substantial or prolonged period of low natural gas, NGLs and oil prices, may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and financial commitments.
The prices we receive for our natural gas, NGLs and oil production heavily influence our revenue, profitability, access to capital and future rate of growth. Natural gas, NGLs and oil are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:
● worldwide and regional economic conditions impacting the global supply and demand for natural gas, NGLs and oil;
● the price and quantity of imports of foreign, and exports of domestic, oil, natural gas and NGLs including liquefied natural gas;
● political conditions in or affecting other producing countries, including conflicts in or among the Middle East, Africa, South America and Russia;
● the level of global exploration and production;
● the level of global inventories;
● events that impact global market demand;
● prevailing prices on local price indexes in the areas in which we operate;
● localized and global supply and demand fundamentals and transportation availability;
● weather conditions;
● technological advances affecting energy consumption;
● the price and availability of alternative fuels; and
● domestic, local and foreign governmental regulation and taxes.
The first of month prices for NYMEX Henry Hub natural gas ranged from a high of $3.43 per MMBtu to a low of $1.58 per MMBtu in 2024, and the calendar month average prices for NYMEX West Texas Intermediate crude oil ranged from a high of $84.39 per barrel to a low of $69.37 per barrel during the same period. Natural gas prices were substantially lower in 2024 than they were in 2023, while oil prices were relatively consistent in 2024 and 2023. The markets for these commodities have historically been volatile, and these markets will likely continue to be volatile in the future. In addition, the market price for natural gas in the Appalachian Basin continues to be lower relative to NYMEX Henry Hub as a result of the significant increases in the supply of natural gas in the Northeast region in recent years. NGLs are made up of ethane, propane, isobutane, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, which adds further volatility to the pricing of NGLs. Due to the volatility of commodity prices, we are unable to predict future potential movements in the market prices for natural gas, oil and NGLs at our ultimate sales points and, thus, cannot predict the ultimate impact of prices on our operations.
Prolonged low, and/or significant or extended declines in, natural gas, NGLs and oil prices may adversely affect our revenues, operating income, cash flows and financial position, particularly if we are unable to control our development costs during periods of lower natural gas, NGLs and oil prices. Declines in prices could also adversely affect our drilling activities and the amount of natural gas, NGLs and oil that we can produce economically, which may result in our having to make significant downward adjustments to the value of our assets and could cause us to incur non-cash impairment charges to earnings in future periods. Reductions in cash flows from lower commodity prices have required us to reduce our capital spending and could reduce our production and our reserves, negatively affecting our future rate of growth. Lower prices for natural gas, NGLs and oil may also adversely affect our credit ratings and result in a reduction in our borrowing capacity and access to other capital. We are also exposed to the risk of non-performance by our hedge counterparties in the event that changes, positive or negative, in natural gas prices result in our derivative contracts having a positive fair value in our favor. Further, adverse economic and market conditions could negatively affect the collectability of our trade receivables and cause our hedge counterparties to be unable to perform their obligations or to seek bankruptcy protection.
Increases in natural gas, NGLs and oil prices may be accompanied by or result in increased well drilling costs, increased production taxes, increased lease operating expenses, increased volatility in seasonal gas price spreads and increased end-user conservation or conversion to alternative fuels. In addition, to the extent we have hedged our current production at prices below the current market price, we are unable to benefit fully from an increase in the price of natural gas, NGLs and oil.
Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.
To achieve more predictable cash flows and reduce our exposure to downward price fluctuations, we have historically entered into fixed swap hedging contracts for a significant percentage of our expected production volumes. For example, in 2021 we hedged 91%, 36% and 29% of our natural gas, NGLs and oil production, respectively. Additionally, in 2022 we hedged 49% of our natural gas production, and our NGLs and oil production was unhedged. Due to our improved liquidity and leverage position as compared to past levels, the percentage of our expected production that we hedge has decreased. For example, in 2023 and 2024, substantially all of our production was unhedged, and as of December 31, 2024, we had fixed swap and collar contracts in place for a nominal portion of our natural gas production in 2025 and 2026. To the extent that we engage in hedging activity in the future, we may be prevented from realizing the near-term benefits of price increases above the levels of the hedges. If we choose not to engage in, or otherwise reduce our future use of, hedging arrangements or are unable to engage in hedging arrangements due to lack of acceptable counterparties, we may be more adversely affected by changes in commodity prices than our competitors who engage in hedging arrangements to a greater extent than we do. Conversely, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:
● production volumes are less than expected;
● commodity prices rise significantly in excess of our hedged price, resulting in significant cash payments to our hedge counterparties;
● we are unable to find available counterparties in the future;
● the creditworthiness of our hedge counterparties or their guarantors is substantially impaired; or
● counterparties have credit limits that may constrain our ability to hedge additional volumes.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment if the estimated future undiscounted cash flows are less than the carrying value of our properties. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We may incur significant impairment charges in the future, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Imbalances between the supply of and demand for oil, natural gas and NGLs could cause extreme market volatility, increased costs and decreased availability of storage capacity.
The marketing of our natural gas, NGLs and oil production is substantially dependent upon the existence of adequate markets for our products. Imbalances between the supply of and demand for these products could cause extreme market volatility and a substantial adverse effect on commodity prices during such time. Such imbalances could also result in the industry experiencing storage capacity constraints with respect to certain NGLs and oil. Without sufficient transportation and storage capacity, many producers may be forced to temporarily shut in portions of their production or sell portions of their production at below-market prices.
For example, in response to the coronavirus pandemic, governments tried to slow the spread of the virus by imposing social distancing guidelines, travel restrictions and stay-at-home orders, among other actions, which caused a significant decrease in the demand for oil and to a lesser extent, natural gas and NGLs. We are unable to predict the extent to which another world health event could impact our business results and operations, but such events could give rise to an imbalance between the supply of and demand for our products that could adversely affect our financial condition and results of operations.
Reserves
The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.
As of December 31, 2024, 23% of our total estimated proved reserves were classified as proved undeveloped. Our 4.2 Tcfe of estimated proved undeveloped reserves will require an estimated $1.8 billion of development capital over the next five years. Moreover, the development of probable and possible reserves will require additional capital expenditures and such reserves are less certain to be recovered than proved reserves. Development of these undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could require us to reclassify our proved undeveloped reserves as unproved reserves.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves.
To prepare our estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary.
The process also requires economic assumptions about matters such as realized prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, realized prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may adjust our reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.
Investors should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from our reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate.
The standardized measure of discounted future net cash flows from our proved reserves is not the same as the current market value of our estimated oil and gas reserves.
Investors should not assume that the standardized measure of discounted future net cash flows from our proved reserves is the current market value of our estimated oil and gas reserves. In accordance with SEC requirements, we based the discounted future net cash flows from our proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. Actual future net cash flows from our properties will be affected by factors such as the actual prices we receive for natural gas, NGLs and oil, the amount, timing and cost of actual production and changes in governmental regulations or taxation. In addition, the 10% discount factor we use when calculating the standardized measure is based on SEC guidelines, and may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and, eventually, production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore, our future cash flow and results of operations are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production, and any such acquisition and development may be offset by any asset disposition. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.
Approximately 48% of our net leasehold acreage is undeveloped, and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.
Approximately 48% of our net leasehold acreage is undeveloped, or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. We have proved undeveloped reserves of 366 Bcfe related to such acreage that is subject to renewal prior to drilling. In addition, 14% of our natural gas leases related to our Appalachian Basin acreage require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Our future oil and gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage. For more information on our future potential acreage expirations, see “Item 1. Business and Properties-Our Properties and Operations-Undeveloped Acreage Expirations.”
Business Operations
Drilling for and producing oil and gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Our future financial condition and results of operations will depend on the success of our exploration, development and acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable hydrocarbons. Our decisions to purchase, explore or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. For a discussion of the uncertainty involved in these processes, see “-Reserves-Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in our
reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing and operating wells is subject to operational uncertainties.
Further, many factors may curtail, delay or cancel our scheduled drilling projects, including the following:
● prolonged declines in natural gas, NGLs and oil prices;
● limitations in the market for natural gas, NGLs and oil;
● delays imposed by, or resulting from, compliance with regulatory requirements;
● pressure or irregularities in geological formations;
● shortages of, or delays in, obtaining equipment, qualified personnel or water for hydraulic fracturing activities;
● equipment failures or accidents;
● adverse weather conditions, such as blizzards, tornadoes, hurricanes and ice storms;
● issues related to compliance with environmental regulations;
● environmental hazards, such as natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
● limited availability of financing at acceptable terms; and
● mineral interest or other title problems.
Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.
Properties that we decide to drill may not yield natural gas, NGLs or oil in commercially viable quantities, which may adversely affect our financial condition, results of operations and cash flows.
Prior to drilling and testing a prospect, we are unable to predict with certainty whether any particular prospect will yield natural gas, NGLs or oil in sufficient quantities to recover drilling or completion costs or to be economically viable. Seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether natural gas or oil will be present or, if present, whether natural gas or oil will be present in commercial quantities. We cannot make any assurances that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:
● unexpected drilling conditions;
● mineral interest or other title problems;
● pressure or lost circulation in formations;
● equipment failure or accidents;
● adverse weather conditions;
● compliance with environmental and other governmental or contractual requirements; and
● increase in the cost of, or shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.
Market conditions or operational impediments, such as the unavailability of satisfactory transportation arrangements or necessary infrastructure, may hinder our access to natural gas, NGLs and oil markets or delay our production.
The availability of a ready market for our natural gas, NGLs and oil production depends on a number of factors, including the demand for and supply of natural gas, NGLs and oil and the proximity of reserves to, and capacity of, pipelines, other transportation facilities, gathering and processing, fractionation facilities and the availability of other third-party transportation services. The capacity of transmission, gathering and processing and fractionation facilities and the availability of third-party transportation services may be insufficient to accommodate potential production from existing and new wells, which may result in substantial discounts in the prices we receive for our natural gas, NGLs and oil. While our investment in midstream infrastructure through Antero Midstream is intended to address access to and potential curtailments on existing midstream infrastructure, we also deliver to and are serviced by third-party natural gas, NGLs and oil transmission, gathering, processing, storage and fractionation facilities and transportation services that are limited in number, geographically concentrated and subject to significant risks. These risks include the availability of capital, materials and qualified contractors and work force, as well as weather conditions, natural gas, NGLs and oil price volatility, delays in obtaining permits and other government approvals, title and property access problems, geology, public opposition to infrastructure development, compliance by Antero Midstream and/or third parties with their contractual obligations to us and other factors.
An extended interruption of access to or service from pipelines and facilities operated by Antero Midstream and/or third parties, or of transportation services provided by Antero Midstream and/or third parties for any reason, including our failure to obtain such services on acceptable terms, cyberattacks on such pipelines and facilities or service interruptions due to gas quality, could materially harm our business by causing delays in producing and selling our natural gas, NGLs and oil. In such an event, we might have to shut in our wells awaiting a pipeline connection or capacity and/or sell our production at prices lower than market prices or at prices lower than we currently project, all of which could adversely affect our business, financial condition and results of operations. If we shut-in or curtail production for any of these or other reasons, we would be unable to realize revenue from those wells until other arrangements were made to deliver the products to market.
Our ability to produce natural gas, NGLs and oil economically and in commercial quantities is dependent on the availability of adequate supplies of water for drilling and completion operations and access to water and waste disposal or recycling facilities and services at a reasonable cost. Restrictions on our ability to obtain water or dispose of produced water and other waste may have an adverse effect on our financial condition, results of operations and cash flows.
The hydraulic fracture stimulation process on which we depend to produce commercial quantities of natural gas, NGLs and oil requires the use and disposal of significant quantities of water. The availability of water recycling facilities and other disposal alternatives to receive all of the water produced from our wells may affect our production. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, or to timely obtain water sourcing permits or other rights, could adversely impact our operations. The availability of water may change over time in ways that we cannot control, including as a result of climate related effects such as shifting weather patterns. Additionally, the imposition of new environmental initiatives and regulations could include restrictions on our ability to obtain water or dispose of waste and adversely affect our business and operating results.
Our identified potential well locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to obtain the substantial amount of capital necessary to drill our potential well locations.
Our management team has specifically identified and scheduled certain well locations as an estimation of our future multi-year drilling activities on our existing acreage. These well locations represent a significant part of our development strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including natural gas, NGLs and oil prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, unitization agreements, lease acquisitions, surface agreements, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertainties, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas, NGLs or oil from these or any other potential well locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified. For more information on our future potential acreage expirations, see “Item 1. Business and Properties-Our Properties and Operations-Undeveloped Acreage Expirations.”
As of December 31, 2024, we had 1,137 identified potential horizontal well locations in our proved, probable and possible reserve base and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024. As a result of the limitations described above, we may be unable to drill many of our potential well locations. In
addition, we will require significant additional capital over a prolonged period to pursue the development of these locations, and we may not be able to obtain or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves, or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations. For more information on our identified potential well locations, see “Item 1. Business and Properties-Our Properties and Operations-Estimated Proved Reserves-Identification of Potential Well Locations.”
We may incur losses as a result of title defects or other matters affecting the unitization of interests.
When we acquire oil and gas leases or interests, we typically do not incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, before attempting to acquire a lease in a specific mineral interest, we rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office. Leases in the Appalachian Basin are particularly vulnerable to title deficiencies due to the long history of private land ownership, severed mineral estates and inadequate records of death and heirships regarding mineral and surface land ownership in the area, resulting in extensive and complex chains of title. The existence of a material title deficiency can render a lease worthless and can adversely affect our financial condition, results of operations and cash flows. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title or the right to include certain interests in a unit may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property, which may adversely impact our business, financial condition or results of operations.
Legal proceedings brought against us could result in substantial liabilities and materially and adversely impact our financial condition.
Like many oil and gas companies, we are involved in various legal proceedings, including threatened claims, such as contractual, title and royalty disputes. For example, we are party to class action litigation that involves claimants’ alleged entitlements to, and accounting for, natural gas royalties, and that could have an impact on the methods for determining the amount of permitted post-production costs and types of cost that may be deducted from royalty payments, among other things. The cost to settle legal proceedings (asserted or unasserted) or satisfy any resulting unfavorable judgment against us in such proceedings could result in a substantial liability or the loss of interests, which could materially and adversely impact our cash flows, operating results and financial condition for the period in which any such effect becomes reasonably estimable. Judgments and estimates to determine accruals or range of losses related to legal proceedings are difficult to predict and could change from one period to the next, and such changes could be material. Current accruals may be insufficient to satisfy any such judgments. Legal proceedings could also result in negative publicity about the Company. Defending these actions, especially purported class actions, can be costly and can distract management and other personnel from their primary responsibilities. In addition, many of our proceedings are in their early stages. Where this is the case, the allegations and damage theories have not been fully developed, and are all subject to inherent uncertainties. As a result, management’s view of the likelihood of a material and adverse financial impact from any such proceeding may change in the future. See Note 15-Contingencies to the consolidated financial statements for additional information on legal proceedings.
ESG matters and conservation measures may adversely impact our business.
Stakeholder attention to climate risks, societal expectations on companies related to climate risks, investor, regulatory and societal expectations regarding voluntary and mandatory ESG disclosures and consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, negative impacts on our stock price and reduced access to capital markets. Any increased attention to climate risks and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us and, depending on the nature of the claims asserted and other factors, such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Moreover, while we create and publish voluntary disclosures regarding ESG matters from time to time, many of the statements in those voluntary disclosures are based on hypothetical expectations and assumptions that may or may not be representative of current or actual risks or events or forecasts of expected risks or events, including the costs associated therewith. Mandatory ESG-related disclosure is also emerging as an area where we may be, or may become, subject to required disclosures in certain jurisdictions, depending on our purported nexus to such jurisdictions and any such mandatory disclosures may similarly necessitate the use of hypothetical, projected or estimated data, some of which is not controlled by us and is inherently subject to imprecision. Disclosures reliant upon such expectations and assumptions are necessarily uncertain and may be prone to error or subject to misinterpretation given the long timelines involved and the lack of an established single approach to identifying, measuring and reporting on many ESG matters. In addition, we have established a net zero goal by 2025 with respect to our Scope 1 (direct) and Scope 2 (indirect from the purchase of energy) GHG emissions, and we could face unexpected material costs as a result of our efforts to meet this goal and any future revisions to it. We continue to evaluate a range of technology and other measures, such as carbon offsets, that could assist with meeting this goal. Given uncertainties related to the use of emerging technologies, the state of markets
for and the availability of verified carbon offsets, we cannot predict whether or not we will be able to timely meet these goals, if at all. In addition, while we may seek to only purchase carbon offsets verified by reputable third parties, we cannot guarantee that any carbon offsets we purchase will achieve the GHG emission reductions represented, and we could face increased costs to purchase additional carbon offsets to cover any gap or loss, particularly if carbon offset markets face capacity constraints as a result of increased demand. Moreover, certain stakeholders may object to the use of offsets generally or with respect to specific transactions we engage in as to any carbon reduction benefits we may claim resulting from such offsets. Furthermore, certain jurisdictions, including California, are instituting new laws that require disclosures related to voluntary carbon offsets and similar constructs. Disclosures under these regimes are novel and it is uncertain whether any disclosures we may make in connection therewith will satisfy the laws and may lead to uncertain consequences, such as private parties criticizing such projects, whether via litigation or otherwise. While we may participate in various voluntary frameworks and certification programs to improve the ESG profile of our operations and products, we cannot guarantee that such participation or certification will have the intended results on our or our products’ ESG profile. Also, despite any aspirational goals, we may receive pressure from investors, lenders or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
Furthermore, our reputation, as well as our stakeholder relationships, could be adversely impacted as a result of, among other things, any failure to meet our ESG plans or goals or stakeholder perceptions of statements made by us, our employees and executives, agents, or other third parties or public pressure from investors or policy groups to change our policies. Such statements with respect to ESG matters are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits. As a result, we may face increased litigation risks from private parties and governmental authorities related to our ESG efforts. Moreover, any alleged claims of greenwashing against us or others in our industry may lead to negative sentiment towards our company or industry. To the extent that the Company is unable to respond timely and appropriately to any negative publicity, our reputation could be harmed. Damage to our overall reputation could have a negative impact on our financial results and require additional resources for the Company to rebuild its reputation. In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings may be used by some investors to inform their investment and voting decisions. Unfavorable ESG ratings and recent activism directed at shifting funding away from companies with energy-related assets could lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital. Also, certain institutional lenders may decide not to provide funding for oil and natural gas companies or the corresponding infrastructure projects based on climate related concerns, which could affect our access to capital for potential growth projects. Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact Antero Midstream and our customers, which may adversely impact our business, financial condition or results of operations.
We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition, results of operations and cash flows.
Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the possibility of:
● environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater, air and shoreline contamination;
● abnormally pressured formations;
● mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
● fires, explosions and ruptures of pipelines;
● personal injuries and death;
● natural disasters; and
● terrorist attacks targeting natural gas and oil related facilities and infrastructure.
Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:
● injury or loss of life;
● damage to and destruction of property, natural resources and equipment;
● pollution and other environmental damage;
● regulatory investigations and penalties;
● suspension of our operations; and
● repair and remediation costs.
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Competition in the oil and gas industry is intense, making it more difficult for us to acquire properties, market products and secure trained personnel.
Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing products and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be successful in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.
Strategic determinations, including the allocation of capital and other resources to strategic opportunities and repayment of indebtedness, are challenging, and our failure to appropriately allocate capital and resources among our various initiatives may adversely affect our financial condition.
Our future success depends on whether we can identify optimal strategies for our business. In developing our 2025 business plan, we considered allocating capital and other resources to various aspects of our businesses, including well development, exploratory activities, corporate items, repayment of indebtedness and other alternatives. Notwithstanding the determinations made in the development of our 2025 plan, business opportunities not previously identified periodically come to our attention, including possible acquisitions and dispositions. If we fail to identify optimal business strategies, including the appropriate corporate structure or the appropriate rate of reserve development, or fail to optimize our capital investment and capital raising opportunities and to use our other resources to further our business strategies, our financial condition may be adversely affected. Moreover, economic or other circumstances may change from those contemplated by our 2025 plan, and our failure to recognize or respond to those changes may limit our ability to achieve our objectives.
We periodically engage in acquisitions, dispositions and other strategic transactions, including joint ventures. These transactions involve various inherent risks, such as our ability to obtain the necessary regulatory approvals; the timing of and conditions imposed upon us by regulators in connection with such approvals; the assumption of potential environmental or other liabilities; and our ability to realize the benefits expected from the transactions. In addition, prevailing market conditions and other factors could negatively impact the benefits we receive from transactions. Competition for acquisition opportunities in our industry is intense and may increase the cost of, or cause us to refrain from, completing acquisitions. Our inability to complete a transaction or to achieve our strategic or financial goals in any transaction could have significant adverse effects on our financial position, results of operations and cash flows.
World health events may materially adversely affect our business.
World health events may cause disruptions to our business and operational plans, which may include (i) shortages of employees, (ii) unavailability of contractors and subcontractors, (iii) interruption of supplies from third parties upon which we rely, (iv) recommendations of, or restrictions imposed by, government and health authorities, including quarantines, and (v) restrictions that we and our contractors and subcontractors impose, including facility shutdowns, to ensure the safety of employees and others. While it is not possible to predict their extent or duration, these disruptions may have a material adverse effect on our business, financial condition and results of operations.
Further, the effects of a world health event could negatively impact global demand for crude oil and natural gas, which may contribute to price volatility that could impact the price we receive for natural gas, NGLs and oil and materially and adversely affect the demand for and marketability of our production, as well as lead to temporary curtailment or shut-ins of production due to lack of downstream demand or storage capacity. Additionally, to the extent a pandemic, epidemic or outbreak of an infectious disease adversely affects our business and financial results, it may also have the effect of heightening many of the other risks set forth in this “Item 1A. Risk Factors.”
Terrorist attacks, cyberattacks and threats could have a material adverse effect on our business, financial condition and results of operations.
Terrorist attacks or cyberattacks may significantly affect the energy industry, including our operations and those of our suppliers and customers, as well as general economic conditions, consumer confidence and spending and market liquidity. Cyber incidents, including deliberate attacks, have increased in frequency globally. Strategic targets, such as energy related assets, may be at greater risk of future attacks than other targets in the United States. We depend on digital technology in many areas of our business and operations, including, but not limited to, estimating quantities of oil and natural gas reserves, processing and recording financial and operating data, oversight and analysis of our drilling, completion and production operations and communications with our employees and third-party customers or service providers. We also collect and store sensitive data in the ordinary course of our business, including personally identifiable information as well as our proprietary business information and that of our customers, suppliers, investors and other stakeholders. The growing regulatory landscape around data protection adds additional complexity to safeguarding this information. The secure processing, maintenance and transmission of information is critical to our operations, and we monitor our key information technology systems in an effort to detect and prevent cyberattacks, security breaches or unauthorized access. Despite our security measures, our information technology systems may undergo cyberattacks or security breaches including as a result of employee error, malfeasance or other threat vectors, which could lead to the corruption, loss, or disclosure of proprietary and sensitive data, misdirected wire transfers, and an inability to: perform services for our customers; complete or settle transactions; maintain our books and records; prevent environmental damage; and maintain communications or operations. Significant liability to the Company or third parties may result. We are not able to anticipate, detect or prevent all cyberattacks, particularly because the methodologies used by attackers change frequently or may not be recognized until an attack is already underway or significantly thereafter, and because attackers are increasingly using technologies specifically designed to circumvent cybersecurity measures and avoid detection. Cybersecurity attacks are also becoming more sophisticated and include, but are not limited to, ransomware, credential stuffing, spear phishing, social engineering, use of deepfakes (e.g., highly realistic synthetic media generated by artificial intelligence) and other attempts to gain unauthorized access to data for purposes of extortion or other malfeasance.
Our information and operational technologies, systems and networks, and those of our vendors, suppliers, customers and other business partners, may become the target of cyberattacks or information security breaches that result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or adversely disrupt our business operations. The interconnected nature of our industry heightens the risk that a cybersecurity incident affecting one of our vendors, suppliers, customers or other business partners could propagate across the supply chain, potentially causing widespread operational or financial disruptions. Although we have written policies and procedures for monitoring cybersecurity risk and identifying and reporting incidents, there can be no guarantee they will be effective at preventing cyberattacks or ensuring incidents are timely identified or reported. Some cyber incidents, such as surveillance, ransomware, or deepfake-based social engineering attacks, may remain undetected for some period of time. Advances in computer capabilities, discoveries in the field of artificial intelligence, cryptography, or other developments may result in a compromise or breach of the technology we use to safeguard confidential, personal or other information. As cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our personnel, information, facilities and infrastructure may result in increased capital and operating costs. While we maintain cyber insurance coverage to help mitigate financial risks associated with cyber incidents, such policies have limitations and do not cover all potential losses, such as reputational harm or regulatory fines. Accordingly, our cyber insurance may not provide coverage for all potential risks arising from cyber incidents. As cyberattacks increase globally in frequency and severity, coverage availability and affordability may further decline. A successful cyberattack or security breach could result in liability resulting from data privacy or cybersecurity
claims, liability under data privacy laws, regulatory penalties, damage to our reputation, long-lasting loss of confidence in us, or additional costs for remediation and modification or enhancement of our information systems to prevent future occurrences, all of which could have a material and adverse effect on our business, financial condition or results of operations. To date, we have not experienced any material losses relating to cyberattacks; however, there can be no assurance that we will not suffer such losses in the future. No security measure is infallible. Consequently, it is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations.
Our producing properties are concentrated in the Appalachian Basin, making us vulnerable to risks associated with operating in one major geographic area.
Our producing properties are geographically concentrated in the Appalachian Basin in West Virginia and Ohio. As of December 31, 2024, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by, and costs associated with, governmental regulation, state and local political activities, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of natural gas, NGLs or oil.
In addition, a number of areas within the Appalachian Basin have historically been subject to mining operations. For example, third parties may engage in subsurface coal and other mining operations near or under our properties, which could cause subsidence or other damage to our properties, adversely impact our drilling operations or adversely impact third-party midstream activities on which we rely. In such event, our operations may be impaired or interrupted, and we may not be able to recover the costs incurred as a result of temporary shut-ins or the plugging and abandonment of any of our wells. Furthermore, the existence of mining operations near our properties could require coordination to avoid adverse impacts as a result of drilling and mining in close proximity. These restrictions on our operations, and any similar restrictions, could cause delays or interruptions or prevent us from executing our business strategy, which could materially adversely affect our results of operations and financial position.
Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
Opposition toward oil and natural gas drilling and development activities generally has been growing globally and is particularly pronounced in the U.S., and companies in our industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability and business practices. Negative public perception regarding us and/or our industry may lead to increased litigation and regulatory, legislative and judicial scrutiny, which may, in turn, lead to new local, state and federal laws, regulations, guidelines and enforcement interpretations in safety, environmental, royalty and surface use areas. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, challenged or burdened by requirements that restrict our ability to profitably conduct our business. In addition, anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations, such as drilling and development. If activism against oil and natural gas exploration and development persists or increases, there could be a material adverse effect on our business, financial condition and results of operations.
Customer Concentration and Credit Risk
The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
Our principal exposures to credit risk are through receivables resulting from the sale of our natural gas, NGLs and oil production that we market to energy companies, end users, and refineries ($453 million as of December 31, 2024). We are also subject to credit risk due to concentration of receivables with several significant customers. The largest purchaser of our products during the year ended December 31, 2024 accounted for 7% of our product revenues. We do not require all of our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Hedging transactions may become more costly or unavailable to us and expose us to counterparty credit risk.
To the extent that we engage in hedging activity in the future, derivative arrangements could limit the benefit we would receive from increases in the prices for natural gas, NGLs and oil, which could also have an adverse effect on our financial condition. If natural gas, NGLs or oil prices upon settlement of our derivative contracts exceed the price at which we have hedged our commodities, we will be obligated to make cash payments to our hedge counterparties, which could, in certain circumstances, be significant.
In addition, U.S. regulators adopted a final rule in November 2019 implementing a new approach for calculating the exposure amount of derivative contracts under the applicable agencies’ regulatory capital rules, referred to as the standardized approach for counterparty credit risk (“SA-CCR”). As adopted, certain financial institutions are required to comply with the new SA-CCR rules beginning on January 1, 2022. These rules could significantly increase the capital requirements for certain participants in the over-the-counter derivatives market in which we participate. These increased capital requirements could result in significant additional costs being passed through to end-users like us or reduce the number of participants or products available to us in the over-the-counter derivatives market. The effects of these regulations could reduce our hedging opportunities, or substantially increase the cost of hedging, which could adversely affect our business, financial condition and results of operations.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, NGLs and natural gas prices and interest rates.
As described above, we enter into certain derivative instruments in the ordinary course operations of our business. Derivative instruments expose us to the risk of financial loss in some circumstances, including when there is an increase in the differential between the underlying price in the derivative instrument and actual prices received or when there are issues with regard to legal enforceability of such instruments. As of December 31, 2024, the estimated fair value of our total derivative assets was $2 million. Also, our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.
Vendor Risks
We are required to pay fees to our service providers based on minimum volumes under long-term contracts regardless of actual volume throughput.
We have various firm transportation and gas processing, gathering and compression service agreements in place, each with minimum volume delivery commitments. Lower commodity prices may lead to reductions in our drilling and completion program, which may result in insufficient production to fully utilize our firm transportation and processing capacity. Our firm transportation agreements expire at various dates from 2025 to 2058 and our gas processing, gathering, and compression services agreements expire at various dates from 2025 to 2038. We are obligated to pay fees on minimum volumes to certain of our service providers regardless of actual volume throughput. In addition, FERC regulates interstate natural gas transportation rates, and terms and conditions of transportation service, which affects the marketing of the natural gas we produce, as well as the prices we receive for sales of our natural gas. Transportation rates on FERC-regulated pipelines are subject to change, and depending on the amount of any increase, such an increase in rates could have an adverse effect on our results of operations. As of December 31, 2024, our long-term contractual obligations under agreements with minimum volume commitments totaled $9.4 billion over the term of the contracts. If we have insufficient production to meet the minimum volumes or are otherwise unable to fulfill all or a portion of our volume commitments, our cash flow from operations will be reduced, which may require us to reduce or delay our planned investments and capital expenditures or seek alternative means of financing, all of which may have a material adverse effect on our results of operations.
Assuming 2025 production is unchanged from 2024 production, we estimate that we will incur annual net marketing costs of $0.04 per Mcfe to $0.06 per Mcfe in 2025 for unutilized transportation capacity depending on the amount of unutilized capacity that can be marketed to third parties or utilized to transport third-party gas and capture positive basis differentials. Additionally, our net marketing expense could increase depending on utilization of our transportation capacity based on future production and how much, if any, future excess transportation can be marketed to third parties.
We may be limited in our ability to choose gathering operators, processing and fractionation services providers and water services providers in our areas of operations pursuant to our agreements with Antero Midstream.
Pursuant to our gathering and compression agreements with Antero Midstream, we have dedicated the gathering and compression of all of our current and future natural gas production in West Virginia, Ohio and Pennsylvania to Antero Midstream, so long as such production is not otherwise subject to a pre-existing dedication. Further, pursuant to the right of first offer agreement that we have entered into with Antero Midstream, Antero Midstream has a right to bid to provide certain processing and fractionation services in respect of all of our current and future gas production (as long as it is not subject to a pre-existing dedication) and will be entitled to provide such services if its bid matches or is more favorable to us than terms proposed by other parties. As a result, we will be limited in our ability to use other gathering and compression operators in West Virginia, Ohio and Pennsylvania, even if such operators can offer us more efficient service. We will also be limited in our ability to use other processing and fractionation services providers in any area to the extent Antero Midstream is able to offer a competitive bid.
Pursuant to the Water Services Agreement that we have entered into with Antero Midstream, we have dedicated the provision of fresh water and wastewater services in defined service areas in Ohio and West Virginia to Antero Midstream. Additionally, the Water Services Agreement provides Antero Midstream with a right of first offer on any future areas of operation outside of those defined areas. As a result, we will be limited in our ability to use other water services providers in the dedication areas of Ohio and West Virginia or other future areas of operation, even if such providers can offer us more favorable pricing or more efficient service.
The unavailability or high cost of additional drilling rigs, completion services, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our exploration and development plans within our budget and on a timely basis.
The demand for qualified and experienced field personnel to drill and complete wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, as the rate of inflation has increased in the U.S., the cost of the good and services and labor we use in our operations has also increased, increasing our operating costs.
Interruptions in operations at facilities that process and fractionate our gas, or with pipelines or other facilities that transport or handle our gas, may adversely affect our business, financial condition and results of operations.
We have agreements with processing and fractionation facilities, including those owned by MPLX, LP and the Joint Venture, to accommodate our current operations as well as future development plans. In addition, we have gathering, compression, transportation and similar agreements with third parties to accommodate our current operations as well as future development plans. Any significant interruptions at these facilities or pipelines could cause us to curtail our future development and production plans, which could adversely affect our business, financial condition and results of operations.
The operations of the processing facilities or pipelines could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within the operator’s nor our control, such as:
● unscheduled maintenance or catastrophic events, including damages to facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters;
● restrictions imposed by governmental authorities or court proceedings;
● labor difficulties that result in a work stoppage or slowdown;
● disruption in the supply of power, water and other resources necessary to operate the facilities;
● damage to the facilities resulting from NGLs that do not comply with applicable specifications;
● inadequate fractionation capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGLs; and
● terrorist attacks or cyberattacks.
While such interruptions are outside of our control, we cannot predict if our counterparties will, in any such cases, attempt to recover certain damages, whether or not they are entitled to them, which could be substantial.
Acquisitions, Divestitures and Takeovers
We may be subject to risks in connection with acquisitions of properties.
The successful acquisition of producing properties requires an assessment of several factors, including:
● recoverable reserves;
● future natural gas, NGLs and oil prices and their applicable differentials;
● operating costs; and
● potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we are able to obtain contractual indemnification rights, there is no assurance that the seller will be capable of performing under any indemnification obligation.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business.
In the future, we may acquire businesses that complement or expand our current business. We may not be able to identify attractive acquisition opportunities. Even if we do identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.
The success of any completed acquisition will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition and results of operations.
In addition, the agreements governing our debt impose certain limitations on our ability to enter into mergers or combination transactions. Such agreements also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Certain provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders. Among other things, our certificate of incorporation and bylaws:
● provide advance notice procedures with regard to stockholder nominations of candidates for election as directors or other stockholder proposals to be brought before meetings of our stockholders, which may preclude our stockholders from bringing certain matters before our stockholders at an annual or special meeting;
● provide our Board of Directors the ability to authorize issuance of preferred stock in one or more series, which makes it possible for our Board of Directors to issue, without stockholder approval, preferred stock with voting or other rights or preferences that could impede the success of any attempt to change control of us and which may have the effect of deterring hostile takeovers or delaying changes in control or management of us;
● provide that the authorized number of directors may be changed only by resolution of our Board of Directors;
● provide that, subject to the rights of holders of any series of preferred stock to elect directors or fill vacancies in respect of such directors as specified in the related preferred stock designation, all vacancies, including newly created directorships be filled by the affirmative vote of holders of a majority of directors then in office, even if less than a quorum, or by the sole remaining director, and will not be filled by our stockholders;
● provide that, subject to the rights of the holders of any series of preferred stock to elect directors under specified circumstances, if any, any action required or permitted to be taken by our stockholders must be effected at a duly called annual or special meeting of our stockholders and may not be effected by any consent in writing in lieu of a meeting of such stockholders;
● provide for our Board of Directors to be divided into three classes of directors, with each class as nearly equal in number as possible, serving staggered three-year terms;
● provide that, subject to the rights of the holders of shares of any series of preferred stock, if any, to remove directors elected by such series of preferred stock pursuant to our certificate of incorporation (including any preferred stock designation thereunder), directors may be removed from office at any time, only for cause and by the holders of a majority of the voting power of all outstanding voting shares entitled to vote generally in the election of directors;
● provide that special meetings of our stockholders may only be called by the Chief Executive Officer, the Chairman of our Board of Directors or our Board of Directors pursuant to a resolution adopted by a majority of the total number of directors that we would have if there were no vacancies;
● provide that (i) Yorktown Partners LLC (“Yorktown”) and their affiliates are permitted to participate (directly or indirectly) in venture capital and other direct investments in corporations, joint ventures, limited liability companies and other entities conducting business of any kind, nature or description, (ii) Yorktown and their affiliates are permitted to have interests in, participate with, aid and maintain seats on the boards of directors or similar governing bodies of any such investments, in each case that may, are or will be competitive with our business and the business of our subsidiaries or in the same or similar lines of business as us and our subsidiaries, or that could be suitable for us or our subsidiaries and (iii) we have, subject to limited exceptions, renounced, to the fullest extent permitted by law, any interest or expectancy in, or in being offered an opportunity to participate in, such corporate opportunities;
● provide that the provisions of our certificate of incorporation can only be amended or repealed by the affirmative vote of the holders of at least 66 2/3% in voting power of the outstanding shares of our common stock entitled to vote thereon, voting together as a single class; and
● provide that our bylaws can be altered or repealed by (a) our Board of Directors or (b) our stockholders upon the affirmative vote of holders of at least 66 2/3% of the voting power of our common stock outstanding and entitled to vote thereon, voting together as a single class.
We have elected not to be subject to the provisions of Section 203 of the Delaware General Corporation Law (the “DGCL”), regulating corporate takeovers.
In general, the provisions of Section 203 of the DGCL prohibit a Delaware corporation, including those whose securities are listed for trading on the New York Stock Exchange, from engaging in any business combination with any interested stockholder for a period of three years following the date that the stockholder became an interested stockholder, unless:
● prior to such time, the business combination or the transaction which resulted in the stockholder becoming an interested stockholder is approved by our Board of Directors;
● upon consummation of the transaction that resulted in the stockholder becoming an interested stockholder, the interested stockholder owned at least 85% of the voting stock of the corporation outstanding at the time the transaction commenced (excluding certain specified shares); or
● on or after such time the business combination is approved by our Board of Directors and authorized at a meeting of stockholders by the holders of at least two-thirds of the outstanding voting stock that is not owned by the interested stockholder.
Section 203 of the DGCL permits a Delaware corporation to elect not to be governed by the provisions of Section 203. Pursuant to our certificate of incorporation, we expressly elected not to be governed by Section 203. Accordingly, we are not subject to any anti-takeover effects or protections of Section 203 of the DGCL, although no assurance can be given that we will not elect to be governed by Section 203 of the DGCL pursuant to an amendment to our certificate of incorporation in the future.
Certain of our stockholders have investments in our affiliates that may conflict with the interests of other stockholders.
Paul M. Rady and an individual affiliated with Yorktown serve as members of our Board of Directors and the Board of Directors of Antero Midstream. Mr. Rady and Yorktown also own a significant portion of the shares of our common stock. Mr. Rady and Yorktown may have conflicting interests with other stockholders. Conflicts of interest could arise in the future between us, on the one hand, and Mr. Rady and Yorktown, on the other hand, regarding, among other things, decisions related to our financing, capital expenditures and business plans, the terms of our agreements with Antero Midstream and its subsidiaries and the pursuit of potentially competitive business activities or business opportunities.
We may be unable to dispose of assets on attractive terms and may be required to retain liabilities for certain matters.
Our business and financing plans may periodically include divesting certain assets. However, we do not completely control the timing of divestitures, and delays in completing divestitures may reduce the benefits we may receive from them, such as reducing management distractions by selling non-core assets and the receipt of cash proceeds that reduce debt and contribute to our liquidity. Various factors could materially affect our ability to dispose of assets if and when we decide to do so, including the availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile commodity prices. In connection with certain dispositions, we may be required to contractually indemnify the purchaser or retain liabilities for certain matters.
Capital Structure and Access to Capital
Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our oil and gas reserves.
The oil and gas industry is capital intensive. We make, and expect to continue to make, substantial capital expenditures for the exploration, development, production, and acquisition of oil and gas reserves. Our cash flow used in investing activities for 2024 included drilling and completion costs of $615 million and leasehold expenditures of $91 million. Our net capital budget for 2025 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. Our capital budget excludes acquisitions, except for leasehold acquisitions. We expect to fund these capital expenditures with cash generated by operations, and dividends from Antero Midstream, which we do not control the timing or amount of, if any; however, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. The actual amount and timing of our future capital expenditures may differ materially from our capital budget as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological, and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to maintain production.
The issuance of additional indebtedness would require that a portion of our cash flow from operations be used for the payment of interest and principal on our indebtedness, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions.
Our cash flows from operations and access to capital are subject to a number of variables, including:
● our proved reserves;
● the level of hydrocarbons we are able to produce from existing wells;
● the prices at which our production is sold;
● our ability to acquire, locate and produce new reserves;
● the value of our commodity derivative portfolio; and
● availability under the Credit Facility.
If our revenues decrease as a result of sustained periods of low natural gas, NGLs and oil prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flows generated by our operations or available borrowings under the Credit Facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and could adversely affect our business, financial condition and results of operations.
We may not be able to generate sufficient cash flows to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.
Our ability to make scheduled payments on, or to refinance, our indebtedness, including the Credit Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the Senior Notes.
If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness, including the Credit Facility or the Senior Notes. For example, the proceeds of our asset sale program were used to retire a portion of our indebtedness. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital and credit markets, including the markets for debt securities and credit facilities, and our financial condition at such time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including the Credit Facility and the indentures governing our Senior Notes, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness, could result in more onerous restrictions in our debt securities and facilities and may result in us having to post collateral with, or provide letters of credit to, certain transactional counterparties. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt documents place certain restrictions on our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.
We may be unable to access the equity or debt capital markets to meet our obligations.
Declines in commodity prices may cause the financial markets to exert downward pressure on stock prices and credit capacity for companies throughout the energy industry. For example, for portions of 2020, the market for senior unsecured notes was unfavorable for senior note issuers. Our development plan may require access to the capital and credit markets. Although the market for senior note debt securities has improved compared to 2020, if the senior note market deteriorates, or if we are unable to access alternative means of debt or equity financing on acceptable terms or at all, we may be unable to implement our development plan or otherwise carry out our business plan, which could have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.
Restrictions in our existing and future debt agreements could limit our growth and our ability to engage in certain activities.
The Credit Facility contains a number of significant covenants (in addition to covenants restricting the incurrence of additional indebtedness), including restrictive covenants that may limit our ability to, among other things:
● merge, consolidate, liquidate or dissolve;
● grant liens on our property;
● incur certain indebtedness;
● make dividend payments, distributions or equity repurchases; and
● enter into material non-arms’-length transactions with our affiliates.
The indentures governing our Senior Notes contain similar restrictive covenants as well as restrictive covenants that may limit our ability to sell assets and make investments. In addition, the Credit Facility requires us to maintain a ratio of total indebtedness to capitalization of 65% or less. These restrictions, together with those in the indentures governing our Senior Notes may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing our Senior Notes and the Credit Facility impose on us.
A breach of any covenant in the Credit Facility would result in a default under that agreement after any applicable grace periods. A default, if not waived, could result in our inability to access loans under the Credit Facility or acceleration of the indebtedness outstanding under the Credit Facility and in a default with respect to, and an acceleration of, the indebtedness outstanding under other debt agreements. The accelerated indebtedness would become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. For example, during 2024, we had average outstanding borrowings under the Credit Facility of $440 million, and the impact of a 1.0% increase in interest rates on this amount of indebtedness would result in increased interest expense for that period of $4 million and a corresponding decrease in our cash flows and net income before the effects of income taxes. Furthermore, a downgrade to our credit rating would trigger certain obligations to deliver letters of credit to certain transactional counterparties, which would adversely impact our available liquidity, and likely result in more restrictive covenants being placed on our future indebtedness. Disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. A significant reduction in net cash provided by operating activities or the availability of credit could materially and adversely affect our ability to achieve our development plan and operating results.
Compliance with Regulations
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from low permeability subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure through a cased and cemented wellbore into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations, as does most of the domestic oil and natural gas industry. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel fuels and issued permitting guidance in February 2014 regarding such activities. In addition, the EPA finalized rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. New legislation regulating hydraulic fracturing may be considered again in future, though we cannot predict when or the scope of any such legislation at this time. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, the Ohio legislature has adopted a law requiring oil and natural gas operators to disclose chemical ingredients used to hydraulically fracture wells and to conduct pre-drill baseline water quality sampling of certain water wells near a proposed horizontal well. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Some states and municipalities have banned and others seek to ban hydraulic fracturing altogether. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development or production activities, and perhaps even be precluded from drilling wells.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
We may incur significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our exploration, development and production activities. These delays, costs and liabilities could arise under a wide range of federal, regional, state and local laws and regulations relating to protection of the environment and occupational health and workplace safety, including regulations and enforcement policies that have tended to become increasingly strict over time resulting in longer waiting periods to receive permits and other regulatory approvals. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations.
Strict, joint and several liabilities may be imposed under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental and occupational health and workplace safety impacts of our operations. We have been named from time to time as a defendant in litigation related to such matters. For example, we have been named as the defendant in separate lawsuits in West Virginia in which the plaintiffs have alleged that our oil and natural gas activities exposed them to hazardous substances and damaged their properties. Also, new laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. If we were not able to recover the resulting costs through insurance or increased revenues, our business, financial condition or results of operations could be adversely affected.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Our oil and gas exploration, production, processing and transportation operations are subject to complex and stringent laws and regulations. To conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. We may incur substantial costs to maintain compliance with these existing laws and regulations. In addition, our costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. For instance, in January 2023, the White House’s Council on Environmental Quality (“CEQ”) released guidance to assist federal agencies in assessing the GHG emissions and climate change effects of their proposed actions under the National Environmental Policy Act (“NEPA”). In May 2024, the CEQ published a final rule which, in the second and final “phase” of updates, revised the implementing regulations of procedural provisions of NEPA and implements NEPA amendments included in the Financial Responsibility Act of 2023. The final rule was challenged by various states. In the U.S. District Court for the District of North Dakota in February 2025, the court issued an order vacating the May 2024 rule citing a November 2024 opinion of the U.S. Court of Appeals for the D.C. Circuit, which held that the CEQ lacks authority to issue NEPA regulations. As a result of these rulings and the recent change in presidential administration, there is significant uncertainty with respect to current and future NEPA regulations. For example, on January 20, 2025, President Trump issued an Executive Order directing the CEQ to issue guidance and propose rescinding existing NEPA regulations to “expedite and simplify the permitting process.” While the impact of these developments is unclear at this time, any disruption in our ability to obtain permits could result in costs that could have a material adverse effect on our business, financial condition and results of operations.
Our business is subject to federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration for, and the production, processing and transportation of natural gas, NGLs and oil. While the Trump administration may make changes to President Biden’s environmental and climate change initiatives, we cannot predict what, when, or how the new administration may take actions to revise existing environmental laws or regulations, if at all, or the ultimate impact such changes may have on our business. For more information on these matters, see “Item 1. Business and Properties-Regulation of the Oil and Natural Gas Industry-Regulation of Environmental and Occupational Safety and Health Matters.” Failure to comply with such laws and regulations, including any evolving interpretation and enforcement by governmental authorities, could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Changes to existing or new regulations may unfavorably impact us. Such potential regulations could increase our operating costs, reduce our liquidity, delay or halt our operations or otherwise alter the way we conduct our business, which could in turn have a material adverse effect on our financial condition, results of operations and cash flows.
A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our assets, which may cause our revenues to decline and operating expenses to increase.
Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by the FERC as a natural gas company under the NGA. Although the FERC has not made any formal determinations with respect to any of our facilities, we believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis. Therefore, the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts or Congress, and such increased regulation could cause our revenues to decline and operating expenses to increase, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Should we fail to comply with all applicable FERC administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.
Under the EPAct of 2005, FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1,584,648 per day for each violation and disgorgement of profits associated with any violation. While our systems have not been regulated by FERC under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. Additional rules and legislation pertaining to those and other matters may be considered or adopted by FERC from time to time. Failure to comply with those regulations in the future could subject us to civil penalty liability, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The Inflation Reduction Act could adversely impact demand for oil and gas and could impose new costs on our operations.
In August 2022, President Biden signed the IRA 2022 into law. The IRA 2022 contains hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles and supporting infrastructure and carbon capture and sequestration, amongst other provisions. However, on January 20, 2025, President Trump issued an Executive Order directing agencies to immediately pause the disbursement of funds appropriated through the IRA 2022. The full impact of this Executive Order and related administrative actions is uncertain at this time. In addition, the IRA 2022 imposes the first ever federal fee on the emission of greenhouse gases through a methane emissions charge. The IRA 2022 amends the federal Clean Air Act to impose a fee on the emission of methane from sources required to report their GHG emissions to the EPA, including those sources in the onshore petroleum and natural gas production and gathering and boosting source categories. On November 12, 2024, the EPA finalized the methane emissions charge rule, which applies to oil and gas facilities emitting more than 25,000 metric tons of CO2 per year. The charge is set to start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025, and be set at $1,500 for 2026 and each year after. Calculation of the fee is based on certain thresholds established in the IRA 2022. The methane charge and the incentives for renewable energy infrastructure development could impose additional costs on our operations and further reduce demand for oil and natural gas. This could decrease demand for oil and gas and consequently adversely affect our business and results of operations. Congress may seek to revise the IRA 2022 to remove this rule, but we cannot predict whether, when, or how Congress might seek to do so. The Trump administration may also seek to challenge, repeal, or revise this rule, and Congress may attempt to repeal or amend the IRA 2022, including with respect to the methane emissions charge; however, we cannot predict what, when, or how the new administration or Congress may take actions to rollback or otherwise revise existing laws, rules, or regulations or the ultimate impact such changes may have on our business or results of operations.
Our operations are subject to a series of risks related to climate that could result in increased operating costs, limit the areas in which we may conduct oil and natural gas exploration and production activities, and reduce demand for our products.
Climate risks continue to attract considerable attention in the United States and in foreign countries. In the United States, no comprehensive climate legislation has been implemented at the federal level. Federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. The EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA for those emissions. These EPA rules could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and gas production sources in the United States on an annual basis, which include certain of our operations.
The federal regulation of methane from oil and gas facilities has been subject to substantial uncertainty in recent years. In June 2016, the EPA finalized NSPS, known as Subpart OOOOa, that establish emission standards for methane and VOCs from new and modified oil and natural gas production and natural gas processing and transmission facilities. Most recently, in December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as OOOOb, as well as standards for existing sources for the first time ever, known as OOOOc. Under the final rules, states have two years to prepare and submit their plans to impose methane emission controls on existing sources. The presumptive standards established under the final rule are generally the same for both new and existing sources. The requirements include enhanced leak detection survey requirements using optical gas imaging and other advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions, reduction of emissions by 95% through capture and control systems and zero-emission requirements for certain devices. The rule also establishes a “super emitter” response program that would allow third parties to make reports to EPA of large methane emission events, triggering certain investigation and repair requirements. Fines and penalties for violations of these rules can be substantial. The rules are currently subject to legal challenges, and the Trump administration may seek to revise or repeal these rules; however, we cannot predict what actions the new administration may take or how they might affect our business or results of operations. Moreover, compliance with the new rules may affect the amount we owe under the IRA 2022’s methane fee described above because compliance with EPA’s methane rules would exempt an otherwise covered facility from the requirement to pay the methane fee. The requirements of the EPA’s final methane rules have the potential to increase our operating costs and thus may adversely affect our financial results and cash flows. Moreover, failure to comply with these CAA requirements can result in the imposition of substantial fines and penalties as well as costly injunctive relief. Given the long-term trend toward increasing regulation, future federal GHG regulations of the oil and gas industry remain a possibility, and several states, including West Virginia and Ohio, have separately imposed or are considering imposing their own regulations on methane emissions from oil and gas production activities.
Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. However, on January 20, 2025, President Trump signed an Executive Order once again withdrawing the United States from the Paris Agreement. The United States’ participation in future United Nations climate-related conferences and the impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement or other international conventions cannot be predicted at this time.
Concern over climate risks has also from time to time resulted in increasing political risks in the United States, including climate-change related pledges made by President Biden and other public office representatives. For example, the Biden administration previously issued a pause on approvals for LNG export facilities, which was subsequently struck down in federal court. Following the legal challenges, the Biden administration released a study on the economic and environmental impacts of LNG exports, finding, based on a range of scenarios that vary in assumptions about global climate policies and technology availability, that increased U.S. LNG exports are associated with higher global GHG emissions. While President Trump has issued an Executive Order directing the Department of Energy to restart reviews of LNG export applications, we cannot predict what impact the study released by the prior administration may ultimately have.
Increasingly, oil and natural gas companies are exposed to litigation risks related to climate risks. We are not currently party to any such litigation, but could be named in future actions making similar claims of liability and, depending on the nature of the claims alleged and other factors, such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Additionally, companies in the oil and natural gas industry may be exposed to increasing financial risks. Financial institutions, including investment advisors and certain sovereign wealth, pension and endowment funds, may elect in the future to shift some or all of their investment into non-oil and natural gas related sectors. Certain institutional lenders who provide financing to fossil-fuel energy companies have also become more attentive to lending practices, and some of them may elect in future not to provide funding for oil and natural gas companies. To the extent implemented or pursued, such policies and commitments could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. While we cannot predict how or to what extent sustainable lending and investment practices may impact our operations, a material reduction in the capital available to the oil and natural gas industry could make it more difficult to secure funding for exploration, development, production, transportation and processing activities, which could result in decreased demand for our products or otherwise adversely impact our financial performance.
In addition, in March 2024, the SEC finalized a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related financial statement metrics, in registration statements and periodic reports. However, this rule is currently paused pending litigation and is expected to be repealed. The timeline for any repeal, if at all, is subject to a number of uncertainties and likely could face legal challenges that would further delay the implementation of any repeal, and we cannot predict the ultimate outcome. Similarly, in October 2023, the Governor of California signed the CCDAA and CRFRA into law. The CCDAA requires both public and private U.S. companies that are “doing business in California” and that have a total annual revenue of $1 billion to publicly disclose and verify, on an annual basis, Scope 1, 2 and 3 GHG emissions. The CRFRA requires the disclosure of a climate-related financial risk report (in line with the TCFD recommendations or equivalent disclosure requirements under the ISSB climate-relate disclosure standards) every other year for public and private companies that are “doing business in California” and have total annual revenue of at least $500 million. Reporting under both laws would begin in 2026. These laws are currently subject to legal challenges, but the outcome of such challenge is uncertain at this time. Additionally, New York and other jurisdictions are considering adopting similar climate disclosure laws. Currently, the ultimate impact of these laws on our business is uncertain. The Governor of California has directed further consideration of the implementation deadlines for each of the laws, and there is potential for legal challenges to be filed with respect to the scope of the law, but, absent clarification or revisions to the law, alongside the SEC final rule, if implemented, may result in additional costs to comply with these disclosure requirements as well as increased costs of and restrictions on access to capital. Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions. Separately, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, and there is the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives related to climate risks or GHG emissions from oil and natural gas facilities could result in increased costs of compliance or costs of consumption, thereby reducing demand for our products. Additionally, political, litigation, and financial risks may result in (i) restriction or cancellation of certain oil and natural gas production activities, (ii) incurrence of obligations for alleged damages, or (iii) impairment of our ability to continue operating in an economic manner. One or more of these developments could have a material adverse effect on our business, financial condition and results of operation.
Regulations related to the protection of wildlife could adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Oil and gas operations in our operating areas can be adversely affected by regulations designed to protect various wildlife. For example, following a 2020 court order to reconsider its decision to list the northern long-eared bat as threatened instead of endangered, the USFWS redesignated the bat as endangered in November 2022. The designation of previously unprotected species as threatened or endangered, or redesignation of a threatened species as endangered, in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in constraints on our exploration and production activities. This limits our ability to operate in those areas and can intensify competition during those months for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages. These constraints and the resulting shortages or high costs could delay our operations and materially increase our operating and capital costs.
Human Capital
The loss of senior management or technical personnel could adversely affect operations.
We depend on the services of our senior management and technical personnel. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of our senior management or technical personnel, including Paul M. Rady, our Chairman, President and Chief Executive Officer, could have a material adverse effect on our business, financial condition and results of operations.
Our officers and employees provide services to both us and Antero Midstream.
All of our executive officers and certain other personnel provide corporate, general and administrative services to Antero Midstream and, when providing services to Antero Midstream, are concurrently employed by us and Antero Midstream pursuant to the terms of a services agreement. In addition, certain of our operational personnel are seconded to Antero Midstream pursuant to the terms of a secondment agreement and are concurrently employed by us and Antero Midstream during such secondment. As a result, there could be material competition for the time and effort of the officers and employees who provide services to us and Antero Midstream. If such officers and employees do not devote sufficient attention to the management and operation of our business, our financial results may suffer.
Related Parties
Conflicts of interest will arise from time to time between Antero Midstream and us, and Antero Midstream may favor its own interests to the detriment of us and our stockholders.
All of our officers and certain of our directors are also officers or directors of Antero Midstream. Conflicts of interest will arise between Antero Midstream and us. Our directors and officers who are also directors and officers of Antero Midstream have a fiduciary duty to manage Antero Midstream in a manner that is beneficial to Antero Midstream. In resolving these actual or apparent conflicts of interest, these directors and officers may choose strategies that favor Antero Midstream over our interests and the interests of our stockholders. The resolution of any conflicts of interest between Antero Midstream and its subsidiaries, on one hand, and us and our subsidiaries, on the other, to the extent we can resolve them, may be costly and reduce the amount of time and attention that our directors and officers may spend in operating our business, which, in each case, may adversely affect our business.
Taxes
Our future tax liabilities may be greater than expected if our net operating loss (“NOL”) and tax credit carryforwards are limited, we do not generate expected deductions, or tax authorities challenge our tax positions.
As of December 31, 2024, we have U.S. federal and state NOL carryforwards of $0.6 billion and $1.9 billion, respectively, and U.S. federal tax credit carryforwards of $148 million. We have recorded a reserve for uncertain tax positions related to our U.S. federal tax credits of $54 million as of December 31, 2024. Some of the U.S. federal NOL carryforwards expire in 2037 while others have no expiration date. We expect to fully utilize our U.S. federal NOL carryforwards and U.S. federal tax credit carryforwards prior to expiration. The state NOL carryforwards expire at various dates from 2025 to 2044 while others have no expiration date. We do not expect to utilize certain of these NOL carryforwards due to changes in state tax law. Therefore, we have placed a valuation allowance against $1.2 billion of these state NOL carryforwards. These expectations are based upon assumptions we have made regarding, among other things, our income, capital expenditures and net working capital, and upon our NOL carryforwards not becoming subject to future limitation under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), or otherwise.
Section 382 and Section 383 of the Code generally impose an annual limitation on the amount of NOL carryforwards and tax credit carryforwards that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least 5% of such corporation’s stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that we were to undergo an ownership change, utilization of our NOL carryforwards and tax credit carryforwards would be subject to an annual limitation under Section 382 and Section 383 of the Code. Any unused annual limitation may be carried over to later years. Any limitation on our ability to utilize our NOL carryforwards or tax credit carryforwards against income or gain we generate in the future could increase our future tax liabilities and adversely affect our operating results and cash flows.
Furthermore, we are subject to various complex and evolving U.S. federal, state and local tax laws. U.S. federal, state and local tax laws, policies, statutes, rules, regulations or ordinances could be interpreted, changed, modified or applied adversely to us, in each case, possibly with retroactive effect. Any significant variance in our interpretation of current tax laws, including as result of the release of final Treasury Regulations or other interpretive guidance, or a successful challenge of one or more of our tax positions by the IRS or other state or local tax authorities could increase our future tax liabilities and adversely affect our operating results and cash flows.
While we expect to be able to (i) utilize all of our U.S. federal NOL and tax credit carryforwards, (ii) utilize a portion of our state NOL carryforwards and (iii) generate deductions to offset a portion of our future taxable income, in the event that our NOL or tax credit carryforwards are subject to future limitation (including due to an ownership change under Section 382 of the Code), deductions are not generated as expected, or if one or more of our tax positions are successfully challenged by the IRS or other tax authorities (in a tax audit or otherwise), our future tax liabilities may be greater than expected, which could adversely affect our operating results and cash flows.
Changes in tax laws or the interpretation thereof or the imposition of new or increased taxes or fees may increase our future tax liabilities and adversely affect our operating results and cash flows.
From time to time, U.S. federal and state level legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S. federal and state income tax provisions currently applicable to natural gas and oil exploration and development companies. Such proposed legislative changes include, but are not limited to, (i) the elimination of the
percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies and (v) an increase in the U.S. federal income tax rate applicable to corporations. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on natural gas and oil extraction. The passage of any legislation as a result of these proposals and other changes in tax laws or the imposition of new or increased taxes or fees on natural gas and oil extraction could increase our future tax liabilities and adversely affect our operating results and cash flows.
In addition, the IRA 2022 includes, among other things, a corporate alternative minimum tax (the “CAMT”). Under the CAMT, a 15% minimum tax will be imposed on certain financial statement income of “applicable corporations” in taxable years beginning after December 31, 2022. A corporation is generally an applicable corporation subject to CAMT in any taxable year following a taxable year in which the “average annual adjusted financial statement income” of the corporation and certain of its subsidiaries and affiliates exceeds $1 billion for a specified three taxable year period. We were not an applicable corporation subject to CAMT in 2024. Based on current commodity pricing, our interpretation of the CAMT and the IRA 2022 and a number of operational, economic, accounting and regulatory assumptions, we do not expect to become an applicable corporation subject to CAMT in the next three years. If we become an applicable corporation and our CAMT liability is greater than our regular U.S. federal income tax liability for any particular tax year, the CAMT liability would effectively accelerate our future U.S. federal income tax obligations, reducing our cash flows in that year, but provide an offsetting credit against our regular U.S. federal income tax liability in future tax years. As a result, our current expectation is that the impact of the CAMT is limited to potential timing differences in future tax years.
The IRA 2022 also imposes a 1% non-deductible excise tax on the fair market value of any stock repurchased by a publicly traded domestic corporation during any taxable year, with the fair market value of such repurchased stock reduced by the fair market value of certain stock issued by such corporation during such taxable year (such excise tax, the “Stock Buyback Tax”). In the past, there have been proposals to increase the amount of the Stock Buyback Tax from 1% to 4%; however, it is unclear whether such a change in the amount of the excise tax will be enacted and, if enacted, how soon any such change could take effect. The Stock Buyback Tax first applied to our authorized share repurchase program in the year ended December 31, 2023, and will continue to apply in subsequent taxable years.
The U.S. Department of the Treasury and the Internal Revenue Service have released proposed and final regulations and other interpretive guidance relating to the CAMT and the Stock Buyback Tax. Any significant variance from our current interpretation of such regulations and interpretive guidance could result in a change in our analysis of the application of the CAMT and the Stock Buyback Tax to us and its impact on our operations and cash flows.
General Risks
The price of our common stock may be volatile, and you could lose a significant portion of your investment.
The market price of the common stock could be volatile, and holders of common stock may not be able to resell their common stock at or above the price at which they acquired such securities due to fluctuations in the market price of common stock.
Specific factors that may have a significant effect on the market price for our common stock include:
● our operating and financial performance and prospects and the trading price of our common stock;
● the level of any dividends we may declare;
● quarterly variations in the rate of growth of our financial indicators, such as net income and revenues;
● levels of indebtedness;
● changes in revenue or earnings estimates or publication of research reports by analysts;
● speculation by the press or investment community;
● sales of our common stock by other stockholders;
● announcements by us or our competitors of significant contracts, acquisitions, strategic partnerships, joint ventures, securities offerings or capital commitments;
● general market conditions;
● changes in accounting standards, policies, guidance, interpretations or principles;
● adverse changes in tax laws or regulations; and
● domestic and international economic, legal and regulatory factors related to our performance.
Sales of a substantial amount of shares of our common stock in the public market could adversely affect the market price of our shares.
Sales of a substantial amount of shares of our common stock in the public market or grants to our directors and officers under the Amended and Restated Antero Resources Corporation 2020 Long Term Incentive Plan (the “Amended AR LTIP”), or the perception that these sales or grants may occur, could reduce the market price of shares of our common stock. All of the shares of our common stock are freely tradable without restriction or further registration under the Securities Act, unless the shares are held by any of our “affiliates” as such term is defined in Rule 144 under the Securities Act. We cannot predict the size of future issuances of our common stock or securities convertible into our common stock or the effect, if any, that future issuances and sales of shares of our common stock will have on the market price of our common stock.
There may be future dilution of our common stock, which could adversely affect the market price of shares of our common stock.
We are not restricted from issuing additional shares of our common stock out of our authorized capital. In the future, we may issue shares of our common stock to raise cash for future activities, acquisitions or other purposes. We may also acquire interests in other companies by using a combination of cash and shares of our common stock or only shares. We have issued or may issue securities convertible into, or exchangeable for, or that represent the right to receive, shares of our common stock. Any sales in the public market of the common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. Any of these events may dilute the ownership interests of our stockholders, reduce our net income per share or have an adverse effect on the price of shares of our common stock.
Our certificate of incorporation designates the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders, which could limit our stockholders' ability to obtain a favorable judicial forum for disputes with us or our directors, officers, employees or agents.
Our certificate of incorporation provides that, unless we consent in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware (the “Court of Chancery”) will, to the fullest extent permitted by applicable law, be the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action asserting a claim of breach of a fiduciary duty owed by any of our directors, officers, employees or agents to us or our stockholders, (iii) any action asserting a claim arising pursuant to any provision of the DGCL, our certificate of incorporation or our bylaws as to which the DGCL confers jurisdiction on the Court of Chancery or (iv) any action asserting a claim against us governed by the internal affairs doctrine, in each such case subject to the Court of Chancery having personal jurisdiction over the indispensable parties named as defendants therein. The foregoing provision does not apply to claims under the Securities Act, the Exchange Act or any claim for which the U.S. federal courts have exclusive jurisdiction. Any person or entity purchasing or otherwise acquiring or holding any interest in shares of our capital stock will be deemed to have notice of, and consented to, the provisions of certificate of incorporation described in the preceding sentence. This choice of forum provision may limit our stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with it or its directors, officers, employees or agents, which may discourage such lawsuits against us and such persons. Alternatively, if a court were to find these provisions of our certificate of incorporation inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our business, financial condition and results of operations.
We may issue preferred stock, which may have terms that could adversely affect the voting power or value of our common stock.
Our certificate of incorporation authorizes our Board of Directors to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our Board of Directors may determine. The terms of one or more classes or series of our preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of a class or series of our preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we might assign to holders of our preferred stock could affect the residual value of our common stock.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS
Not applicable.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. LEGAL PROCEEDINGS
The information required by this item is included in Note 15-Contingencies to our consolidated financial statements and is incorporated herein.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
We have one class of common equity outstanding, our common stock, par value $0.01 per share. Our common stock is listed on the New York Stock Exchange and traded under the symbol “AR.” On February 7, 2025, our common stock was held by 99 holders of record. The number of holders does not include the shareholders for whom shares of our common stock are held in a “nominee” or “street” name.
Issuer Purchases of Equity Securities
The following table sets forth our share purchase activity for each period presented:
Total Number
Approximate
of Shares
Dollar Value
Repurchased
of Shares
as Part of
that May
Total Number
Publicly
Yet be Purchased
of Shares
Average Price
Announced
Under the Plan
Period
Purchased (1)
Paid Per Share
Plans
($ in thousands)
October 1, 2024 - October 31, 2024
93,760
$
27.35
-
$
1,050,901
November 1, 2024 - November 30, 2024
26.69
-
1,050,901
December 1, 2024 - December 31, 2024
-
-
-
1,050,901
Total
94,358
$
27.35
-
(1) The total number of shares purchased includes shares of our common stock transferred to us in order to satisfy tax withholding obligations incurred upon the vesting of equity awards held by our employees.
Share Repurchase Program
On February 15, 2022, our Board of Directors authorized a share repurchase program to opportunistically repurchase up to $1.0 billion of shares of our outstanding common stock. On October 25, 2022, our Board of Directors authorized a $1.0 billion increase to our share repurchase program to allow us to repurchase up to an aggregate of $2.0 billion of our outstanding common stock. Through December 31, 2024, we have repurchased 28 million shares of our common stock through our share repurchase program at a total cost of $949 million. The shares may be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will be determined by us at our discretion and will depend on a variety of factors, including the market price of our common stock, general market and economic conditions and applicable legal requirements.
Dividend Restrictions
Our ability to pay dividends is governed by (i) the provisions of Delaware general corporation law, (ii) our Certificate of Incorporation and Bylaws, (iii) the indentures relating to our Senior Notes and (iv) the Credit Facility. We have not paid or declared any dividends on our common stock. The amount and timing of future payment of cash dividends on our common stock, if any, is within the discretion of the Board of Directors and will depend on our earnings, capital requirements, financial condition and other relevant factors. There is no assurance that we will pay any cash dividends on our common stock.
Stock Performance Graph
The graph below shows the cumulative total shareholder return assuming the investment of $100 on December 31, 2019 in each of our common stock, the Standard & Poor’s 500 (“S&P 500”) Index, and the Dow Jones U.S. Oil & Gas Index. We believe the Dow Jones U.S. Oil & Gas Index is meaningful because it is an independent, objective view of the performance of similarly-sized energy companies.
The information in this Form 10-K appearing under the heading “Stock Performance Graph” is being “furnished” pursuant to Item 2.01(e) of Regulation S-K under the Securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 2.01(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act of the Exchange Act except to the extent that we specifically request that it be treated as such.

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. RESERVED

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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 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.
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 high repeatability and low geologic risk. Our drilling opportunities are focused in the Appalachian Basin. As of December 31, 2024, we held approximately 521,000 net acres in the Appalachian Basin. In addition, we estimate that approximately 170,000 net acres of our leasehold may be prospective for the slightly shallower Upper Devonian Shale.
As of December 31, 2024, our estimated proved reserves were 17.9 Tcfe, consisting of 10.6 Tcf of natural gas, 674 MMBbl of assumed recovered ethane, 519 MMBbl of C3+ NGLs and 23 MMBbl of oil. These reserve estimates have been prepared by our internal reserve engineers and management and audited by our independent reserve engineers. As of December 31, 2024, we had 1,137 potential horizontal well locations on our existing leasehold acreage that were classified as proved, probable and possible and excludes 339 locations based on such locations being uneconomic at the SEC reserves prices for the year ended December 31, 2024.
We have three reportable 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. All of our operations are conducted in the United States. See Note 17-Reportable Segments to our consolidated financial statements for additional information.
Financing Highlights
Unsecured Credit Facility
During 2024, we achieved an investment grade credit rating from S&P Global Inc. in addition to our investment grade credit rating from Fitch Ratings, Inc. As a result of this investment grade credit rating, on July 30, 2024, we entered into an amended and restated senior revolving credit facility with lender commitments of $1.65 billion that matures on July 30, 2029, subject to certain extension terms and conditions (the “Unsecured Credit Facility”). Borrowings under the amended and restated facility are unsecured and are not guaranteed by any of our subsidiaries. See Note 7-Long-Term Debt to our consolidated financial statements for additional information.
Drilling Partnerships
2021-2024 Drilling Partnership
On February 17, 2021, we announced the formation of a drilling partnership with QL, an affiliate of Quantum Energy Partners, for our 2021 through 2024 drilling program. Under the terms of the arrangement, QL funded development capital of 20% for wells spud in 2021 and 2024 and 15% for wells spud in 2022 and 2023, which funding amounts represent QL’s proportionate working interest in such wells. Additionally, we received a carry of $29 million for each of the 2021 and 2022 tranches during the years ended December 31, 2022 and 2023 and a carry of $32 million for the 2023 tranche during the year ended December 31, 2024. See Note 3-Transactions to our consolidated financial statements for additional information.
2025 Drilling Partnership
On December 11, 2024, we entered into a drilling partnership with an unaffiliated third-party. Under the terms of the arrangement, the third-party will participate in and fund a share of total development capital expenses for wells spud by Antero during the 2025 calendar year. For each well spud during the 2025 calendar year, the third-party will receive a 15% working interest in such wells and will fund greater than 15% of total development capital expenses for such wells. Subject to the preceding sentence, for any wells spud in the calendar year 2025, the third-party is obligated and responsible for its working interest share of costs and liabilities, and is entitled to its working interest share of revenues, associated with such wells for the life of such wells. Additionally, for each well in the partnership, we will enter into an assignment, bill of sale and conveyance pursuant to which the third-party will be conveyed a proportionate working interest percentage in such well, which conveyances will not be subject to any reversion. See Note 3-Transactions to our consolidated financial statements for additional information.
Market Conditions and Business Trends
Commodity Markets
Prices for natural gas, NGLs and oil that we produce significantly impact our revenues and cash flows. Benchmark prices for natural gas and ethane decreased significantly, while benchmark prices for oil remained consistent and benchmark prices for C3+ NGLs increased during the year ended December 31, 2024 as compared to the year ended December 31, 2023. As a result of the lower benchmark natural gas and ethane prices and higher benchmark C3+ NGLs prices during the year ended December 31, 2024, we experienced a decrease in price realizations for natural gas and ethane products and an increase in price realization for C3+ NGLs products during the same period. We monitor the economic factors that impact natural gas, NGLs and oil prices, including domestic and foreign supply and demand indicators, domestic and foreign commodity inventories, the actions of Organization of Petroleum Exporting Countries and other large producing nations and the current conflicts in Ukraine and in the Middle East, among others. In the current economic environment, we expect that commodity prices for some or all of the commodities we produce could remain volatile. This volatility is beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
The following table details the average benchmark natural gas, NGLs and oil prices:
Year Ended December 31,
Henry Hub ($/Mcf) (1)
$
2.74
2.27
Mont Belvieu Ethane ($/Bbl) (2)
10.32
8.00
Mont Belvieu C3+ NGLs ($/Bbl) (3)
38.31
40.82
West Texas Intermediate ($/Bbl) (4)
77.62
75.72
(1) NYMEX first of month average natural gas price.
(2) ICE settlement ethane OPIS futures average price for the front month contract as published on the last trading day of the month.
(3) ICE settlement propane, isobutane, normal butane and natural gasoline OPIS futures average price for the front month contract as published on the last trading day of the month. Propane and isobutane reflect TET prices, and normal butane and natural gasoline reflect non-TET prices. Propane, isobutane, normal butane and natural gasoline futures prices are weighted to approximate Antero Resources’ average C3+ NGLs composition.
(4) NYMEX calendar month average settled futures price.
Hedge Position
Antero Resources (Excluding Martica)
We are exposed to certain commodity price risks relating to our ongoing business operations, and we use derivative instruments when circumstances warrant to manage such risks. In addition, we periodically enter into contracts that contain embedded features that are required to be bifurcated and accounted for separately as derivatives. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For 2023 and 2024, substantially all of our production was unhedged. Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps. As of December 31, 2024, the estimated fair value of our commodity derivative contracts, excluding Martica, was a net liability of $45 million. See Note 11-Derivative Instruments to our consolidated financial statements for additional information.
Martica
Our consolidated VIE, Martica, also maintains a portfolio of fixed price swap derivatives for the benefit of the noncontrolling interests in Martica. As such, all gains and losses attributable to Martica’s derivative portfolio are fully attributable to the noncontrolling interests in Martica. As of December 31, 2024, the estimated fair value of Martica’s commodity derivative contracts was a net liability of $2 million. See Note 11-Derivative Instruments to our consolidated financial statements for additional information.
Economic Indicators
The economy experienced elevated inflation levels as a result of global supply and demand imbalances, where global demand outpaced supplies beginning in 2021 and continuing through 2024. For example, CPI for all urban consumers increased 4.1% from December 2022 to December 2023 and an additional 2.9% from December 2023 to December 2024. In order to manage the inflation risk present in the United States’ economy, the Federal Reserve utilized monetary policy in the form of interest rate increases beginning in March 2022 in an effort to bring the inflation rate in line with its stated goal of 2% on a long-term basis. Between March 2022 and July 2023, the Federal Reserve increased the federal funds interest rate by 5.25%. During the second half of 2024, inflation rates began to approach the Federal Reserve’s stated goal of 2%, and the Federal Reserve decreased the federal funds rate by 1.0% between September and December 2024. While inflationary pressures in the United States’ economy have begun to subside, we continue to be impacted by the increased federal funds interest rate. See “-Results of Operations” for additional information.
The economy also continues to be impacted by the effects of global events. These events have often caused global supply chain disruptions with additional pressure due to trade sanctions on Russia and other global trade restrictions, among others. However, our supply chain has not experienced any significant interruptions as a result of such events.
Inflationary pressures, particularly as they relate to certain of our long-term contracts with CPI-based adjustments, and supply chain disruptions have and could continue to result in increases to our operating and capital costs that are not fixed. These economic variables are beyond our control and may adversely impact our business, financial condition, results of operations and future cash flows.
Sources of Our Revenues
● Natural gas, NGLs 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 2023 and 2024, our production revenues were comprised of 51% and 44%, respectively, from the sale of natural gas and 49% and 56%, respectively, from the sale of NGLs and oil. Natural gas, NGLs and oil prices are inherently volatile and are influenced by many factors 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. We utilize derivative instruments to hedge future sales prices for our production when circumstances warrant. We currently utilize call and embedded put options, collar contracts and fixed price contracts for a nominal portion of our natural gas in which we receive or pay the difference between a fixed price and the variable market price received. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps. See Note 11-Derivative Instruments to our consolidated financial statements for additional information. At the end of each accounting period, we estimate the fair value of these derivative instruments, 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 and water handling revenues. Gathering, compression and water handling revenues are derived from our ownership interest in Antero Midstream.
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, and 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 fees paid to Antero Midstream and other third parties who operate low and high pressure gathering and compression systems that transport our gas. They also include costs to process and extract NGLs from our liquids-rich 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.
● Water handling. Water handling expenses relate to the direct operating costs attributable to fresh water and other fluid handling services.
● 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, which exclude the effects of our derivative instruments, 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 and mine expenses. These are primarily costs related to unsuccessful leasing efforts, as well as geological and geophysical costs, including seismic costs, costs of unsuccessful exploratory dry holes and costs of other exploratory activities, including costs associated with our sand mine.
● Impairment of property and equipment. These costs include impairment and costs associated with lease 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 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. We also record impairment charges for other property and equipment when events or changes in circumstances indicate that the carrying amount of such property and/or equipment may not be recoverable.
● 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 9-Equity-Based Compensation to our consolidated financial statements for additional information.
● Interest expense. We finance a portion of our capital expenditures, working capital requirements and acquisitions with borrowings under our Credit Facility, which has a variable rate of interest based on the Adjusted Term SOFR Rate, the Adjusted Daily Simple SOFR (collectively, “SOFR”) or the Alternate Base Rate, in each case, plus an Applicable Rate (each term as defined in the Credit Facility). As of December 31, 2023 and 2024, we had an outstanding balance on the Credit Facility of $417 million and $393 million, respectively, with a weighted average interest rate of 7.7% and 5.9%, respectively. 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, 2023 and 2024, we had fixed interest rates ranging from 5.375% to 8.375% on our Senior Notes with an aggregate principal balance of $1.1 billion. See Note 7-Long-Term Debt to our consolidated financial statements for additional information.
● Income tax (expense) benefit. We are subject to U.S. federal and state income taxes, but we are currently not in a cash tax paying position with respect to U.S. federal income taxes. The difference between our financial statement income tax (expense) benefit and our current U.S. 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, the deferral of unsettled commodity derivative gains and losses for tax purposes until they are settled and research and development (“R&D”) tax credits. We have recorded deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities. See Note 13-Income Taxes to our consolidated financial statements for additional information.
Results of Operations
We have three reportable segments: (i) the exploration, development and production of natural gas, NGLs and oil; (ii) marketing and utilization of excess firm transportation capacity; and (iii) midstream services through our equity method investment in Antero Midstream. Revenues from Antero Midstream’s operations were primarily derived from intersegment transactions for services provided to our exploration and production operations by Antero Midstream. All intersegment transactions were eliminated upon consolidation, including revenues from water handling services provided by Antero Midstream, which we capitalized as proved property development costs. 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. See Note 17-Reportable Segments to our consolidated financial statements for additional information.
Year Ended December 31, 2023 Compared to Year Ended December 31, 2024
The operating results of our reportable segments were as follows (in thousands):
Year Ended December 31, 2023
Equity Method
Exploration
Investment in
Elimination of
and
Antero
Unconsolidated
Consolidated
Production
Marketing
Midstream (1)
Affiliate
Total
Revenue and other:
Natural gas sales
$
2,192,349
-
-
-
2,192,349
Natural gas liquids sales
1,836,950
-
-
-
1,836,950
Oil sales
247,146
-
-
-
247,146
Commodity derivative fair value gains
166,324
-
-
-
166,324
Gathering, compression and water handling
-
-
1,041,771
(1,041,771)
-
Marketing
-
206,122
-
-
206,122
Amortization of deferred revenue, VPP
30,552
-
-
-
30,552
Other revenue and income
2,529
-
-
-
2,529
Total revenue
4,475,850
206,122
1,041,771
(1,041,771)
4,681,972
Operating expenses:
Lease operating
118,441
-
-
-
118,441
Gathering and compression
858,462
-
95,507
(95,507)
858,462
Processing
1,014,181
-
-
-
1,014,181
Transportation
769,715
-
-
-
769,715
Water handling
-
-
117,658
(117,658)
-
Production and ad valorem taxes
158,855
-
-
-
158,855
Marketing
-
284,965
-
-
284,965
Exploration and mine expenses
2,700
-
-
-
2,700
General and administrative (excluding equity-based compensation)
164,997
-
39,462
(39,462)
164,997
Equity-based compensation
59,519
-
31,606
(31,606)
59,519
Depletion, depreciation and amortization
746,849
-
136,059
(136,059)
746,849
Impairment of property and equipment
51,302
-
(146)
51,302
Accretion of asset retirement obligations
3,244
-
(177)
3,244
Loss (gain) on sale of assets
(447)
-
6,030
(6,030)
(447)
Contract termination, loss contingency, settlements and other operating expenses
29,179
23,763
3,264
(3,264)
52,942
Total operating expenses
3,976,997
308,728
429,909
(429,909)
4,285,725
Operating income (loss)
$
498,853
(102,606)
611,862
(611,862)
396,247
Equity in earnings of unconsolidated affiliates
$
82,952
-
105,456
(105,456)
82,952
(1) Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements.
Year Ended December 31, 2024
Equity Method
Exploration
Investment in
Elimination of
and
Antero
Unconsolidated
Consolidated
Production
Marketing
Midstream (1)
Affiliate
Total
Revenue and other:
Natural gas sales
$
1,818,297
-
-
-
1,818,297
Natural gas liquids sales
2,066,975
-
-
-
2,066,975
Oil sales
230,027
-
-
-
230,027
Commodity derivative fair value gains
-
-
-
Gathering, compression and water handling
-
-
1,106,193
(1,106,193)
-
Marketing
-
179,069
-
-
179,069
Amortization of deferred revenue, VPP
27,101
-
-
-
27,101
Other revenue and income
3,396
-
-
-
3,396
Total revenue
4,146,527
179,069
1,106,193
(1,106,193)
4,325,596
Operating expenses:
Lease operating
118,693
-
-
-
118,693
Gathering and compression
897,160
-
103,053
(103,053)
897,160
Processing
1,069,887
-
-
-
1,069,887
Transportation
735,883
-
-
-
735,883
Water handling
-
-
114,923
(114,923)
-
Production and ad valorem taxes
207,671
-
-
-
207,671
Marketing
-
244,906
-
-
244,906
Exploration
2,618
-
-
-
2,618
General and administrative (excluding equity-based compensation)
162,876
-
41,754
(41,754)
162,876
Equity-based compensation
66,462
-
44,332
(44,332)
66,462
Depletion, depreciation and amortization
762,068
-
140,000
(140,000)
762,068
Impairment of property and equipment
47,433
-
(332)
47,433
Accretion of asset retirement obligations
3,759
-
(189)
3,759
Loss on sale of assets
-
(723)
Contract termination, loss contingency, settlements and other operating expenses
4,858
-
1,721
(1,721)
4,858
Total operating expenses
4,080,230
244,906
447,027
(447,027)
4,325,136
Operating income (loss)
$
66,297
(65,837)
659,166
(659,166)
Equity in earnings of unconsolidated affiliates
$
93,787
-
110,573
(110,573)
93,787
(1) Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements.
Exploration and Production Segment
The following table sets forth selected operating data of the exploration and production segment:
Year Ended
Amount of
December 31,
Increase
Percent
(Decrease)
Change
Production data (1) (2):
Natural gas (Bcf)
(22)
(3)
%
C2 Ethane (MBbl)
24,657
30,391
5,734
%
C3+ NGLs (MBbl)
41,927
42,434
%
Oil (MBbl)
3,874
3,693
(181)
(5)
%
Combined (Bcfe)
1,238
1,252
%
Daily combined production (MMcfe/d)
3,392
3,421
%
Average prices before effects of derivative settlements (3):
Natural gas (per Mcf)
$
2.69
2.29
(0.40)
(15)
%
C2 Ethane (per Bbl) (4)
$
10.14
9.05
(1.09)
(11)
%
C3+ NGLs (per Bbl)
$
37.85
42.23
4.38
%
Oil (per Bbl)
$
63.80
62.29
(1.51)
(2)
%
Weighted Average Combined (per Mcfe)
$
3.45
3.29
(0.16)
(5)
%
Average realized prices after effects of derivative settlements (3):
Natural gas (per Mcf)
$
2.66
2.30
(0.36)
(14)
%
C2 Ethane (per Bbl) (4)
$
10.14
9.05
(1.09)
(11)
%
C3+ NGLs (per Bbl)
$
37.80
42.36
4.56
%
Oil (per Bbl)
$
63.50
62.15
(1.35)
(2)
%
Weighted Average Combined (per Mcfe)
$
3.43
3.30
(0.13)
(4)
%
Average costs (per Mcfe):
Lease operating
$
0.10
0.09
(0.01)
(10)
%
Gathering and compression
$
0.69
0.72
0.03
%
Processing
$
0.82
0.85
0.03
%
Transportation
$
0.62
0.59
(0.03)
(5)
%
Production and ad valorem taxes
$
0.13
0.17
0.04
%
Marketing expense, net
$
0.06
0.05
(0.01)
(17)
%
General and administrative (excluding equity-based compensation)
$
0.13
0.13
-
*
Depletion, depreciation, amortization and accretion
$
0.61
0.61
-
*
*Not meaningful
(1) Production data excludes volumes related to the VPP.
(2) 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 may not reflect their relative economic value.
(3) Average prices reflect the before and after effects of our settled commodity derivatives. Our calculation of such after effects includes gains (losses) on settlements of commodity derivatives (but do not include payments for the derivative monetizations in 2023), which do not qualify for hedge accounting because we do not designate or document them as hedges for accounting purposes.
(4) The average realized price for the years ended December 31, 2023 and 2024 includes $15 million and $2 million, respectively, of proceeds related to a take-or-pay contract. Excluding the effect of these proceeds, the average realized price for ethane before and after the effects of derivatives for the years ended December 31, 2023 and 2024 would have been $9.55 per Bbl and $8.99 per Bbl, respectively.
Natural gas sales. Revenues from sales of natural gas decreased from $2.2 billion for the year ended December 31, 2023 to $1.8 billion for the year ended December 31, 2024, a decrease of $0.4 billion, or 17%. Lower commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $313 million decrease in year-over-year natural gas sales revenue (calculated as the change in the year-to-year average price times current year production volumes). Lower natural gas production volumes accounted for an approximate $61 million decrease in year-over-year natural gas sales revenue (calculated as the change in year-to-year volumes times the prior year average price).
NGLs sales. Revenues from sales of NGLs increased from $1.8 billion for the year ended December 31, 2023 to $2.1 billion for the year ended December 31, 2024, an increase of $0.3 billion, or 13%. Higher commodity prices (excluding the effects of derivative settlements) during the year ended December 31, 2024 accounted for an approximate $153 million increase in year-over-year revenues (calculated as the change in the year-to-year average price times current year production volumes). Higher NGLs production volumes during the year ended December 31, 2024 accounted for an approximate $77 million increase in year-over-year NGLs revenues (calculated as the change in year-to-year volumes times the prior year average price).
Oil sales. Revenues from sale of oil decreased from $247 million for the year ended December 31, 2023 to $230 million for the year ended December 31, 2024, a decrease of $17 million, or 7%. Lower oil production volumes during the year ended December 31, 2024 accounted for an approximate $11 million decrease in year-over-year oil revenues (calculated as the change in year-to-year volumes times the prior year average price). Lower oil prices for the year ended December 31, 2024 (excluding the effects of derivative settlements) accounted for an approximate $6 million decrease in year-over-year oil revenues (calculated as the change in the year-to-year average price times current year production volumes).
Commodity derivative fair value gains. Our commodity derivatives included fixed price swap contracts, swaptions, basis swap contracts, call options and embedded put options. 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 and comprehensive income. For the years ended December 31, 2023 and 2024, our commodity hedges resulted in derivative fair value gains of $166 million and $1 million, respectively. For the year ended December 31, 2023, commodity derivative fair value gains included $25 million of net cash payments for settled derivative losses, as well as $202 million for payments on derivatives that were settled prior to their contractual settlement dates. For the year ended December 31, 2024, commodity derivative fair value gains included $10 million of net cash proceeds for settled derivative gains.
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, monetized or terminated 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. Additionally, substantially all of our production is currently unhedged for 2025 and beyond, which limits our exposure to volatility in the fair value of our derivative instruments related to commodity price changes in the future.
Amortization of deferred revenue, VPP. Amortization of deferred revenues associated with the VPP decreased from $31 million for the year ended December 31, 2023 to $27 million for the year ended December 31, 2024, a decrease of $4 million or 11%, primarily due to lower production volumes attributable to the VPP properties between periods. Amortization of the deferred revenues associated with the VPP are recognized as the production volumes are delivered at $1.61 per MMBtu over the contractual term.
Lease operating expense. Lease operating expense remained relatively consistent for the years ended December 31, 2023 and 2024 at $118 million and $119 million, respectively. On a per-unit basis, lease operating expense decreased from $0.10 per Mcfe for the year ended December 31, 2023 to $0.09 per Mcfe for the year ended December 31, 2024 primarily due to lower water disposal costs and workover expense between periods.
Gathering, compression, processing and transportation expense. Gathering, compression, processing and transportation expense remained relatively consistent at $2.6 billion and $2.7 billion for the years ended December 31, 2023 and 2024, respectively. This was primarily a result of the following:
● Gathering and compression costs on a per unit basis increased from $0.69 per Mcfe for the year ended December 31, 2023 to $0.72 per Mcfe for the year ended December 31, 2024, primarily due to the expiration of the growth incentive fee rebate program on December 31, 2023 and annual CPI-based adjustments between periods. During the year ended December 31, 2023, we earned growth incentive fee rebates of $52 million.
● Processing costs on a per unit basis increased from $0.82 per Mcfe for the year ended December 31, 2023 to $0.85 per Mcfe for the year ended December 31, 2024, primarily due to increased costs for NGLs processing, which includes an annual CPI-based adjustment during the first quarter of 2024 and higher NGLs transportation fees.
● Transportation costs on a per unit basis decreased from $0.62 per Mcfe for the year ended December 31, 2023 to $0.59 per Mcfe and for the year ended December 31, 2024, primarily due to lower fuel costs as a result of lower natural gas prices and lower demand fees between periods.
Production and ad valorem tax expense. Production and ad valorem taxes increased from $159 million for the year ended December 31, 2023 to $208 million for the year ended December 31, 2024, an increase of $49 million or 31%, primarily due to higher ad valorem taxes, partially offset by lower natural gas and oil prices during the year ended December 31, 2024. Production and ad valorem taxes as a percentage of natural gas revenues increased from 7% for the year ended December 31, 2023 to 11% for the year ended December 31, 2024, primarily as a result of higher ad valorem taxes, which 2024 West Virginia ad valorem taxes are based on commodity prices during 2022.
General and administrative expense. General and administrative expense (excluding equity-based compensation expense) remained relatively consistent at $165 million, or $0.13 per Mcfe and $163 million, or $0.13 per Mcfe, for the years ended December 31, 2023 and 2024, respectively.
Equity-based compensation expense. Non-cash equity-based compensation expense increased from $60 million for the year ended December 31, 2023 to $66 million for the year ended December 31, 2024, an increase of $6 million or 12%. This increase was primarily due to higher restricted stock unit (“RSU”) award expense of $9 million between periods, partially offset by lower performance share unit (“PSU”) award expense of $3 million between periods. See Note 9-Equity-Based Compensation to our consolidated financial statements for additional information.
Depletion, depreciation and amortization expense. DD&A expense increased from $747 million for the year ended December 31, 2023 to $762 million for the year ended December 31, 2024, an increase of $15 million or 2%, primarily due to higher production volumes between periods. On a per-unit basis, DD&A expense remained consistent at $0.61 per Mcfe for the years ended December 31, 2023 and 2024.
Impairment of property and equipment. Impairment of property and equipment decreased from $51 million for the year ended December 31, 2023 to $47 million for the year ended December 31, 2024, a decrease of $4 million, or 8%, primarily due to lower impairments of expiring leases between periods. During both periods, we recognized impairments primarily related to expiring leases as well as design and initial costs related to pads we no longer plan to utilize.
Contract termination, loss contingency, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses attributable to our exploration and production segment decreased from $29 million for the year ended December 31, 2023 to $5 million for the year ended December 31, 2024. This decrease was primarily due to a loss contingency recorded during the year ended December 31, 2023 and lower expense associated with the early termination of certain drilling and completion contracts between periods.
Marketing Segment
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.
Net marketing expense decreased from $79 million, or $0.06 per Mcfe, for the year ended December 31, 2023 to $66 million, or $0.05 per Mcfe, for the year ended December 31, 2024, primarily due to lower firm transportation commitments between periods.
Marketing revenue. Marketing revenue decreased from $206 million for the year ended December 31, 2023 to $179 million for the year ended December 31, 2024, a decrease of $27 million, or 13%. This fluctuation primarily resulted from the following:
● Natural gas marketing revenue decreased by $77 million between periods primarily due to lower natural gas marketing volumes and prices. Lower natural gas marketing volumes accounted for a $68 million decrease in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and lower natural gas prices accounted for a $9 million decrease in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).
● Oil marketing revenue increased by $46 million between periods primarily due to higher oil marketing volumes and prices. Higher oil marketing volumes accounted for a $39 million increase in year-over-year marketing revenues (calculated as the change in year-to-year volumes times the prior year average price), and higher oil prices accounted for an approximate $7 million increase in year-over-year marketing revenues (calculated as the change in the year-to-year average price times current year marketing volumes).
● NGLs marketing revenues were $4 million for the year ended December 31, 2024. There were no NGLs marketing revenues for the year ended December 31, 2023.
Marketing expense. Marketing expense decreased from $285 million for the year ended December 31, 2023 to $245 million for the year ended December 31, 2024, a decrease of $40 million, or 14%. Marketing expense includes the cost of third-party purchased natural gas, NGLs and oil as well as firm transportation costs, including costs related to current excess firm capacity. The cost of third-party natural gas purchases decreased $62 million between periods, partially offset by increased oil and NGLs purchases of $37 million and $4 million, respectively. The total cost of third-party commodity purchases decreased primarily due to lower natural gas marketing volumes and prices between periods, partially offset by higher oil and NGLs marketing volumes during the year ended December 31, 2024. Firm transportation costs decreased $19 million from $105 million for the year ended December 31, 2023 to $86 million for the year ended December 31, 2024, primarily due to the reduction in firm transportation commitments between periods.
Contract termination, loss contingency, settlements and other operating expenses. Contract termination, loss contingency, settlements and other operating expenses attributable to our marketing segment for the year ended December 31, 2023 relate to a $24 million payment for the early termination of our firm transportation commitment of 200,000 MMBtu/d on the Equitrans pipeline. Our marketing segment did not incur any contract termination, loss contingency, settlements and other operating expenses for the year ended December 31, 2024.
Antero Midstream Segment
Antero Midstream revenue. Revenue from the Antero Midstream segment increased from $1.0 billion for the year ended December 31, 2023 to $1.1 billion for the year ended December 31, 2024, an increase of $0.1 billion, or 6%. This increase is primarily due to higher gathering and compression revenues of $84 million, partially offset by lower water handling revenues of $20 million. The increased gathering and compression revenues between periods is primarily a result of the expiration of the growth incentive fee rebate program on December 31, 2023, increased throughput and annual CPI-based gathering and compression rate adjustments between periods. The decreased water handling revenues between periods is primarily due to lower fresh water delivery and other fluid handling volumes, partially offset by an increased fresh water delivery rate due to an annual CPI-based adjustment during the year ended December 31, 2024.
Antero Midstream operating expense. Total operating expense related to the Antero Midstream segment increased from $430 million for the year ended December 31, 2023 to $447 million for the year ended December 31, 2024, an increase of $17 million, or 4%. This increase is primarily due to higher gathering and compression expense as a result of increased throughput during the year ended December 31, 2024, as well as higher general and administrative expense, including equity-based compensation expense, and depreciation expense between periods, partially offset by lower gains on asset sale during the year ended December 31, 2024.
Items Not Allocated to Segments
Interest expense. Interest expense remained consistent at $118 million for the years ended December 31, 2023 and 2024. See Note 7-Long-Term Debt to our consolidated financial statements for additional information.
Income tax (expense) benefit. For the year ended December 31, 2023, we had income tax expense of $64 million, with an effective tax rate of 17.6%, due to income before income taxes of $361 million. Our effective tax rate for the year ended December 31, 2023 was different than the statutory rate of 21% primarily due to the effects of state income taxes, the dividends received deduction, equity-based compensation expenses, noncontrolling interests, the effects of a West Virginia apportionment tax law change enacted in 2021 and changes in Pennsylvania’s corporate income tax rate. For the year ended December 31, 2024, we had an income tax benefit of $118 million primarily due to R&D tax credits of $95 million, loss before income taxes of $24 million and a reduction to our state NOL carryforward valuation allowance of $12 million. See Note 13-Income Taxes to our consolidated financial statements for additional information.
As of December 31, 2024, we had U.S. federal and state NOL carryforwards of $0.6 billion and $1.9 billion, respectively. Many of these NOL carryforwards expire at various dates between 2025 and 2044 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. 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, 2022 Compared to Year Ended December 31, 2023
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, 2023 for a discussion of the results of operations for the year ended December 31, 2022 compared to the year ended December 31, 2023.
Capital Resources and Liquidity
Overview
Our primary sources of liquidity have been through net cash provided by operating activities, borrowings under our Credit Facility, issuances of debt and equity securities and additional contributions from our asset sales, including our drilling partnerships. 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 developing our proved reserves and production will be highly dependent on net cash provided by operating activities and the capital resources available to us.
Our commodity hedge position can provide us with liquidity for the portion of our production that is hedged because it provides us with the relative certainty of our future expected revenues for such production despite potential declines in the price of natural gas. However, due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. Assuming our 2025 production is the same as our production in 2024, approximately 3% of our total production for 2025 is hedged through fixed price commodity swaps. Our ability to make significant 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 13 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.
Capital Spending and 2025 Capital Budget
For the year ended December 31, 2024, our total consolidated capital expenditures were $721 million, including drilling and completion expenditures of $620 million, leasehold additions of $91 million and other capital expenditures of $10 million. We completed 41 net horizontal wells during the year ended December 31, 2024. Our net capital budget for 2025 is $725 million to $800 million. Our budget includes: a range of $650 million to $700 million for drilling and completion and $75 million to $100 million for leasehold expenditures. We do not budget for acquisitions. During 2025, we plan to complete 60 to 65 net horizontal wells in the Appalachian Basin. 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, 2024, we believe that net cash provided from operating activities and available borrowings under the Credit Facility 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 Note 7-Long-Term Debt to our consolidated financial statements.
See Note 14-Commitments to our consolidated financial statements for information on our off-balance sheet arrangements.
Cash Flows
The following table summarizes our cash flows (in thousands):
Year Ended December 31,
Net cash provided by operating activities
$
994,721
849,288
Net cash used in investing activities
(1,140,767)
(714,153)
Net cash provided by (used in) financing activities
146,046
(135,135)
Net increase in cash and cash equivalents
$
-
-
Year Ended December 31, 2023 Compared to Year Ended December 31, 2024
Operating activities. Net cash provided by operating activities was $995 million and $849 million for the years ended December 31, 2023 and 2024, respectively. Net cash provided by operating activities decreased primarily due to lower natural gas prices and changes in working capital, partially offset by increased NGLs revenue due to higher C3+ NGLs prices, lower contract termination, loss contingency and settlements expense and lower net marketing expense between periods and a $202 million payment for early settlement of our swaption agreement in the year ended December 31, 2023.
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. 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. Net cash used in investing activities decreased from $1.1 billion for the year ended December 31, 2023 to $0.7 billion for the year ended December 31, 2024, primarily due to lower well completions between periods, decreased drilling activity as a result of a lower rig count between periods and decreased leasing activity during the year ended December 31, 2024. During the years ended December 31, 2023 and 2024, we completed 70 wells and 41 wells, respectively.
Financing activities. Net cash provided by financing activities was $146 million for the year ended December 31, 2023. Net cash used in financing activities was $135 million for the year ended December 31, 2024. This decrease in cash provided by financing activities between periods is primarily due lower net borrowings on our Credit Facility of $406 million, partially offset by decreased share repurchases of $75 million and lower distributions to the noncontrolling interests in Martica of $55 million between periods.
Year Ended December 31, 2022 Compared to Year Ended December 31, 2023
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, 2023 for a discussion of the cash flows for the year ended December 31, 2022 compared to the year ended December 31, 2023.
Debt Agreements
We may, from time to time, seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, 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. We were in compliance with all covenants and ratios applicable to our debt agreements as of December 31, 2023 and 2024. See Note 7-Long-Term Debt to our consolidated financial statements for additional information.
Critical Accounting 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. Any new accounting policies or updates to existing accounting policies as a result of new accounting pronouncements have been included in Note 2-Summary of Significant Accounting Policies to our consolidated financial statements. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosure of contingent liabilities. Accounting estimates and assumptions are considered to be critical if 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 reported amounts in our consolidated financial statements 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.
Successful Efforts Method
We account for our 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 oil and gas leases are capitalized. Items charged to expense generally include 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.
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. Impairment of oil and gas properties related to unproved properties for leases that have expired, or are expected to expire, was $98 million, $51 million and $47 million for the years ended December 31, 2022, 2023 and 2024, respectively.
We believe that the application of the successful efforts method of accounting requires judgment to determine the proper classification of wells designated as developmental or exploratory, which designation determines the proper accounting treatment of the costs incurred. In addition, evaluating our unproved properties for impairment involves significant judgments about future development plans, which include future sales prices of natural gas, NGLs and oil and future development and production costs, as well as the amount of natural gas, NGLs and oil recoveries.
Natural Gas, NGLs and Oil Reserve Quantities
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. 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 proved properties 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 reservoir. 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.
We believe that the estimates and assumptions related to reserve quantities is critical because any significant revisions or changes to these estimates and assumptions could affect the future amortization rates of capitalized proved property 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 recoverable. If the carrying amount of our proved properties exceeds the estimated undiscounted future net cash flows (measured using futures prices at the balance sheet date), we further evaluate our proved properties and record an impairment charge if the carrying amount of our proved properties exceeds the estimated fair value of the properties. We did not record any impairments for proved properties during the years ended December 31, 2022, 2023 and 2024.
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. Estimated undiscounted future net cash flows are sensitive to commodity price swings and a decline in prices could result in the carrying amount exceeding the estimated undiscounted future net cash flows at the end of a future
reporting period, which would require us to further evaluate if an impairment charge would be necessary. For our Utica and Marcellus properties, strip pricing would have to decline by more than 7% and 25%, respectively, from year end 2024 levels before further evaluation of those properties would be required in order to determine if an impairment charge is necessary. If future prices decline from December 31, 2024, the fair value of our properties may be below their carrying amounts and an impairment charge may be necessary. However, we are unable to predict commodity prices with any greater precision than the futures market.
We believe that the estimates and assumptions related to our undiscounted future net cash flows and the fair value of our proved properties is critical because different natural gas, NGLs and oil pricing, cost assumptions or discount rates, as applicable, may affect the recognition, timing and amount of an impairment and, if changed, could have a material effect on the Company's financial position and results of operations.
Derivative Instruments
In order to manage our exposure to natural gas, NGLs and oil price volatility, we may enter into derivative transactions from time to time, which agreements could include commodity fixed price swaps, basis swaps, collars or other similar instruments related to the price risk associated with our production. We record derivative instruments on the consolidated balance sheet as either assets or liabilities measured at fair value and record changes in the fair value of derivatives in current earnings as they occur. Our derivatives have not been designated as hedges for accounting purposes. Fair value measurements for our commodity derivatives require the use of assumptions and judgements including valuation techniques, future pricing, volatility, time to maturity and credit risk, among others. We regularly assess the reasonableness of these assumptions and judgements through the review of counterparty statements. However, changes to these assumptions and judgements could have a material effect on the Company's financial position and results of operations.
Income Taxes
Income taxes are accounted for using the asset and liability approach. Under this approach, deferred income tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis. We record deferred income tax expense to the extent our deferred income tax liabilities exceed our deferred income tax assets. We record a deferred income tax benefit to the extent our deferred income tax assets exceed our deferred income tax liabilities. 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.
We record a valuation allowance or reserve for an uncertain tax position when we believe all or a portion of our deferred income tax assets will not be realized. In assessing the realizability of our deferred income tax assets, management considers whether some portion or all of the deferred income tax assets will be realized based on a more-likely-than-not standard of judgment. The ultimate realization of deferred income tax assets is dependent upon our ability to generate future taxable income during the periods in which our deferred income tax assets are deductible or our tax credits can be utilized. Management considers the scheduled reversal of deferred income 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 income 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, 2024, we have recognized a valuation allowance of $43 million related to Colorado, Oklahoma and West Virginia state NOL carryforwards that we do not expect to realize due to expected future reduced income tax apportionment in those states. In addition, as of December 31, 2024, we have recorded a reserve for uncertain tax positions of $54 million related to our R&D tax credits.
The calculation of deferred income tax assets and liabilities involves uncertainties in the application of complex tax laws and regulations, as well as judgement on the amount of financial statement benefit recorded for uncertain tax positions. We recognize in our financial statements those tax positions which we believe are more-likely-than-not to be sustained upon examination by the IRS or state revenue authorities. We believe that the estimates and assumptions related to income taxes are critical because of the assumptions and estimates required to assess the likelihood that our deferred income tax assets will be recovered from future taxable income, as well as the judgement required to determine the amount and timing of a valuation allowance on our deferred income tax assets and reserve for uncertain tax positions. These assumptions affect deferred income tax liability and income tax (expense) benefit and, if changed, could have a material effect on the Company's financial position and results of operations.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in natural gas, NGLs and oil prices, as well as interest rates. These disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures.
Commodity Hedging Activities
Our primary market risk exposure is in the price we receive for our natural gas, NGLs and oil production. Pricing is primarily driven by spot regional market prices applicable to our U.S. natural gas production and the prevailing worldwide price for oil. Pricing for natural gas, NGLs and oil has, historically, been volatile and unpredictable, and we expect this volatility to continue in the future. The prices we receive for our production depend on many factors outside of our control, including volatility in the differences between commodity prices at sales points and the applicable index price.
We may enter into financial derivative instruments for a portion of our natural gas, NGLs and oil production when circumstances warrant and management believes that favorable future prices can be secured in order to mitigate some of the potential negative impact on our cash flows caused by changes in commodity prices. Due to our improved liquidity and leverage position as compared to historical levels, the percentage of our expected production that we hedge has decreased. For the years ended December 31, 2023 and 2024, substantially all of our production was unhedged.
Our financial hedging activities may include commodity derivative instruments that are intended to support natural gas, NGLs and oil prices at targeted levels and to manage our exposure to price risk associated with our production. These contracts may include commodity price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty, collars that set a floor and ceiling price for the hedged production, basis differential swaps or call or embedded put options, among others. These contracts are financial instruments and do not require or allow for physical delivery of the hedged commodity. As of December 31, 2024, our commodity derivatives included fixed swaps, collars, call options and embedded put options at index-based pricing for a nominal portion of our production. See Note 11-Derivative Instruments to our consolidated financial statements for additional information.
Based on our production and our derivative instruments that settled during the year ended December 31, 2024, our revenues would have decreased by $151 million for each $0.10 decrease per MMBtu in natural gas prices and $1.00 decrease per Bbl in oil and NGLs prices, excluding the effects of changes in the fair value of our derivative positions which remain open as of December 31, 2024.
All derivative instruments, other than those that meet the normal purchase and normal sale scope exception or other derivative scope exceptions, are recorded at fair market value in accordance with GAAP and are included in our consolidated balance sheets as assets or liabilities. The fair values of our derivative instruments are adjusted for non-performance risk. Because we do not designate these derivatives as accounting hedges, they do not receive hedge accounting treatment; therefore, 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 and comprehensive income. We present total gains or losses on commodity derivatives (for both settled derivatives and derivative positions which remain open) within operating revenues as commodity derivative fair value gains (losses) in the consolidated statements of operations and comprehensive income.
Mark-to-market adjustments of derivative instruments cause earnings volatility but have no cash flow impact relative to changes in market prices until the derivative contracts are settled or monetized prior to settlement. We expect continued volatility in the fair value of our derivative instruments. Our cash flows are impacted when the associated derivative contracts are settled or monetized by making or receiving payments to or from the counterparty. As of December 31, 2023 and 2024, the estimated fair value of our commodity derivative instruments was a net liability $37 million and $47 million, respectively, comprised of current and noncurrent assets and liabilities.
Counterparty and Customer Credit Risk
Our principal exposures to credit risk are through receivables resulting from the following: the sale of our natural gas, NGLs and oil production ($453 million as of December 31, 2024), which we market to energy companies, end users and refineries, and commodity derivative contracts ($2 million as of December 31, 2024).
We are subject to credit risk due to the concentration of our receivables from several significant customers for sales of natural gas, NGLs and oil. While we do at times require customers to post letters of credit or other credit support in connection with their obligations, we generally do not require our customers to post collateral. The inability or failure of our significant customers to meet their obligations to us, or their insolvency or liquidation, may adversely affect our financial results.
In addition, we are exposed to the credit risk of our counterparties for our derivative instruments. Credit risk is the potential failure of a counterparty to perform under the terms of a derivative contract. When the fair value of a derivative contract is positive, the counterparty is expected to owe us, which creates credit risk. To minimize the credit risk in derivative instruments, it is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions that management deems to be competent and competitive market makers. The creditworthiness of our counterparties is subject to periodic review. As of December 31, 2024, we have commodity hedges in place with four different counterparties, three of which are lenders under the Unsecured Credit Facility. As of December 31, 2024, we did not have any commodity derivative assets with bank counterparties under our Unsecured Credit Facility. The estimated fair value of our commodity derivative assets has been risk-adjusted using a discount rate based upon the counterparties’ respective published credit default swap rates (if available, or if not available, a discount rate based on the applicable Reuters bond rating) as of December 31, 2024. We believe that all of the counterparties to our derivative instruments are acceptable credit risks as of December 31, 2024. We are not required to provide credit support or collateral to any of our counterparties under our derivative contracts, nor are they required to provide credit support to us. As of December 31, 2024, we did not have any past-due receivables from, or payables to, any of the counterparties to our derivative contracts.
Interest Rate Risks
Our primary exposure to interest rate risk results from outstanding borrowings under the Credit Facility, which has a floating interest rate. The average annualized interest rate incurred on the Credit Facility for borrowings during the year ended December 31, 2024 was 7.4%. We estimate that a 1.0% increase in the applicable average interest rates for the year ended December 31, 2024 would have resulted in an estimated $4 million increase in interest expense.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The Reports of Independent Registered Public Accounting Firm, Consolidated Financial Statements and supplementary financial data required for this Item are set forth beginning on page of this Annual Report on Form 10-K and are incorporated herein by reference.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Not applicable.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Annual Report on Form 10-K. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosures and is recorded, processed, summarized and reported, within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2024 at a level of reasonable assurance.
Changes in Internal Control Over Financial Reporting
There have been no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Annual Report on Internal Control Over Financial Reporting
The management of Antero Resources Corporation is responsible for establishing and maintaining adequate internal control over financial reporting for us as defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act. This system is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
Our internal control over financial reporting includes those policies and procedures that:
(i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect our transactions and dispositions of the assets;
(ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and Directors; and
(iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on the financial statements.
Because of its inherent limitations, a system of internal control over financial reporting can provide only reasonable assurance and may not prevent or detect all misstatements. Further, because of changes in conditions, effectiveness of internal controls over financial reporting may vary over time.
Under the supervision of, and with the participation of, our management, including the Chief Executive Officer and Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework and criteria established in Internal Control-Integrated Framework in 2013, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management of Antero Resources Corporation concluded that our internal control over financial reporting was effective as of December 31, 2024.
The effectiveness of our internal control over financial reporting as of December 31, 2024 has been audited by KPMG LLP, an independent registered public accounting firm, as stated in their report which appears beginning on page in this Annual Report on Form 10-K.

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2025 Annual Meeting of Stockholders.
Code of Ethics
We intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K relating to amendments to or waivers from any provision of our Corporate Code of Business Conduct and Ethics applicable to our principal executive officer, principal financial officer, principal accounting officer and other persons performing similar functions by posting such information in the “Governance” subsection of our website at www.anteroresources.com.

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2025 Annual Meeting of Stockholders.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2025 Annual Meeting of Stockholders.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2025 Annual Meeting of Stockholders.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered accounting firm is KPMG LLP, Denver, CO, Auditor Firm ID: 185.
Pursuant to General Instruction G(3) to Form 10-K, we incorporate by reference into this Item the information to be disclosed in our definitive proxy statement for our 2025 Annual Meeting of Stockholders.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBIT AND FINANCIAL STATEMENT SCHEDULES
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules
The consolidated financial statements are listed on the Index to Financial Statements to this Annual Report on Form 10-K beginning on page.
(a)(3) Exhibits.
Exhibit
Number
Description of Exhibit
2.1
Simplification Agreement, dated as of October 9, 2018, by and among AMGP GP LLC, Antero Midstream GP LP, Antero IDR Holdings LLC, Arkrose Midstream Preferred Co LLC, Arkrose Midstream NewCo Inc., Arkrose Midstream Merger Sub LLC, Antero Midstream Partners GP LLC and Antero Midstream Partners LP (incorporated by reference to Exhibit 2.1 to Antero Midstream GP LP’s Current Report on Form 8-K (Commission File No. 001-38075) filed on October 10, 2018).
3.1
Amended and Restated Certificate of Incorporation of Antero Resources Corporation (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
3.2
Certificate of Amendment to Second Amended and Restated Certificate of Incorporation of Antero Resources Corporation, dated June 8, 2023 (incorporated by reference to Exhibit 3.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 8, 2023).
3.3
Second Amended and Restated Bylaws of Antero Resources Corporation, dated February 14, 2023 (incorporated by reference to Exhibit 3.2 to the Company’s Annual Report on Form 10-K (Commission File No. 0001-36120) filed on February 15, 2023).
4.1
Indenture related to the 4.25% Convertible Senior Notes due 2026, dated as of August 21, 2020, by and among Antero Resources Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K (Commission File No. 001-36120) filed on August 21, 2020).
4.2
Form of 4.25% Convertible Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K (Commission File No. 001-36120) filed on August 21,2020).
4.3
Indenture related to the 8.375% Senior Notes due 2026, dated as of January 4, 2021, by and among Antero Resources Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on January 4, 2021).
4.4
Form of 8.375% Senior Note due 2026 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on January 4, 2021).
4.5
Registration Rights Agreement, dated as of October 16, 2013, by and among Antero Resources Corporation and the owners of the membership interests in Antero Resources Investment LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
4.6*
Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended.
4.7
Indenture related to the 7.625% Senior Notes due 2029, dated as of January 26, 2021, by and among Antero Resources Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on February 1, 2021).
4.8
Form of 7.625% Senior Note due 2029 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on February 1, 2021).
4.9
Indenture related to the 5.375% Senior Notes due 2030, dated as of June 1, 2021, by and among Antero Resources Corporation, the several guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 1, 2021).
4.10
Form of 5.375% Senior Note due 2030 (incorporated by reference to Exhibit 4.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 1, 2021).
10.1
Contribution Agreement, dated as of October 16, 2013, by and between Antero Resources Corporation and Antero
Exhibit
Number
Description of Exhibit
Resources Midstream LLC (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 17, 2013).
10.2
Amended and Restated Contribution Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.1 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.3
Agreement and Plan of Merger, dated as of October 1, 2013, by and among Antero Resources Corporation, Antero Resources LLC and Antero Resources Investment LLC (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K (Commission File No. 333-164876) filed on October 11, 2013).
10.4
Second Amended and Restated Gathering and Compression Agreement, dated as of December 8, 2019, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 12, 2020).
10.5
Second Amended and Restated Right of First Offer Agreement, dated as of February 13, 2018, by and between Antero Resources Corporation and Antero Midstream LLC (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q (Commission File No. 001-36120) filed on April 25, 2018).
10.6
License Agreement, dated as of November 10, 2014, by and between Antero Resources Corporation and Antero Midstream Partners LP (incorporated by reference to Exhibit 10.4 to Antero Midstream Partners LP’s Current Report on Form 8-K (Commission File No. 001-36719) filed on November 17, 2014).
10.7
Amended and Restated Secondment Agreement, effective as of March 13, 2019, by and between Antero Midstream Corporation, Antero Midstream Partners LP, Antero Midstream Partners GP LLC, Antero Midstream LLC, Antero Water LLC, Antero Treatment LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.7 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 12, 2020).
10.8
Second Amended and Restated Services Agreement, effective as of March 13, 2019, by and among Antero Midstream Partners LP, Antero Midstream Corporation, Antero Midstream Partners GP LLC and Antero Resources Corporation (incorporated by reference to Exhibit 10.8 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 12, 2020).
10.9**
Amended and Restated Water Services Agreement dated as of February 12, 2019, by and between Antero Resources Corporation and Antero Water LLC (incorporated by reference to Exhibit 10.9 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 13, 2019).
10.10
Lender Certificate, dated October 29, 2019, delivered by Royal Bank of Canada, and agreed to and accepted by JPMorgan Chase Bank, N.A., as Administrative Agent, and Antero Resources Corporation (incorporated by reference to Exhibit 10.12 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 12, 2020).
10.11
Sixth Amended and Restated Credit Agreement, dated as of October 26, 2021, by and among Antero Resources Corporation, as Borrower, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-36120) filed on October 27, 2021).
10.12†
Form of Amended and Restated Indemnification Agreement (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on April 17, 2018).
10.13†
Antero Resources Corporation Long-Term Incentive Plan, effective as of October 1, 2013 (incorporated by reference to Exhibit 4.3 to the Company’s Registration Statement on Form S-8 (Commission File No. 001-36120) filed on October 11, 2013).
10.14†
Form of Stock Award Grant Notice and Stock Award Agreement (Form for Non-Employee Directors) under the Antero Resources Corporation 2020 Long-Term Incentive Plan (incorporated by reference to Exhibit 4.4 to the Company’s Current Report on Form S-8 (Commission File No. 001-36120) filed on July 9, 2020).
10.15
Stockholders’ Agreement, dated as of October 9, 2018, by and among Antero Midstream GP LP, Arkrose Subsidiary Holdings LLC, Warburg Pincus Private Equity X O&G, L.P., Warburg Pincus X Partners, L.P., Warburg Pincus Private Equity VIII, LP, Warburg Pincus Netherlands Private Equity VIII C.V.I. WP-WPVIII Investors, L.P., Yorktown Energy Partners V, L.P., Yorktown Energy Partners VI, L.P., Yorktown Energy Partners VII, L.P., Yorktown Energy Partners VIII, L.P., Paul M. Rady, Mockingbird Investment, LLC, Glen C. Warren, Jr. and Canton Investment Holdings LLC (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K (Commission File No. 001-36120) filed on October 10, 2018).
10.16
Registration Rights Agreement, dated March 12, 2019, by and among Antero Midstream Corporation, the Company, Arkrose Subsidiary Holdings LLC, Glen C. Warren, Jr., Canton Investment Holdings LLC, Paul M. Rady, Mockingbird Investments, LLC and other holders named therein (incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on March 13, 2019).
10.17†
Form of Restricted Stock Unit Grant Notice and Restricted Stock Unit Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly
Exhibit
Number
Description of Exhibit
Report on Form 10-Q (Commission File No. 001-36120) filed on October 28, 2020).
10.18†
Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-36120) filed on July 28, 2021).
10.19†
Form of Performance Share Unit Grant Notice and Performance Share Unit Agreement under the Antero Resources Corporation 2020 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-36120) filed on July 27, 2022).
10.20†
Amended and Restated Antero Resources Corporation 2020 Long Term Incentive Plan, dated June 5, 2024 (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K (Commission File No. 001-36120) filed on June 6, 2024).
10.21
Amended and Restated Credit Agreement, dated as of July 30, 2024, among Antero Resources Corporation, as Borrower, the Lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (incorporated by reference to Exhibit 10.2 to the Company’s Quarterly Report on Form 10-Q (Commission File No. 001-36120) filed on July 31, 2024).
19.1*
Antero Resources Corporation Insider Trading Policies.
21.1*
Subsidiaries of Antero Resources Corporation.
23.1*
Consent of KPMG LLP.
23.2*
Consent of DeGolyer and MacNaughton.
31.1*
Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
31.2*
Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 7241).
32.1*
Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
32.2*
Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes Oxley Act of 2002 (18 U.S.C. Section 1350).
97.1
Antero Resources Corporation Incentive Compensation Recovery Policy (incorporated by reference to Exhibit 97.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 14, 2024.
99.1*
Report of DeGolyer and MacNaughton, dated as of January 20, 2025, for proved reserves as of December 31, 2024.
99.2
Report of DeGolyer and MacNaughton, dated as of January 17, 2024, for proved reserves as of December 31, 2023 (incorporated by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 14, 2024).
99.3
Report of DeGolyer and MacNaughton, dated as of January 17, 2023, for proved reserves as of December 31, 2022 (incorporated by reference to Exhibit 99.1 to the Company’s Annual Report on Form 10-K (Commission File No. 001-36120) filed on February 15, 2023).
101*
The following financial information from this Form 10-K of Antero Resources Corporation for the year ended December 31, 2024, formatted in iXBRL (Inline eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations and Comprehensive Income, (iii) Consolidated Statements of Equity, (iv) Consolidated Statements of Cash Flows, and (v) Notes to the Consolidated Financial Statements, tagged as blocks of text.
104*
Cover Page Interactive Data File (embedded within the Inline XBRL document).
The exhibits marked with the asterisk symbol (*) are filed or furnished with this Annual Report on Form 10-K.
** Portions of this exhibit have been omitted pursuant to a request for confidential treatment.
† Management contract or compensatory plan or arrangement.