ANTERO RESOURCES Corp (AR) FY 2024 MD&A
This page reproduces the company's own Item 7 MD&A text from the linked SEC filing. It is filer text, not grepcent analysis, scoring, or investment advice.
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.
49
Table of Contents
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, | | ||||
| | 2023 | 2024 | | ||||
| 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 | |
| Column 1 | Column 2 |
|---|---|
| (1) | NYMEX first of month average natural gas price. |
| Column 1 | Column 2 |
|---|---|
| (2) | ICE settlement ethane OPIS futures average price for the front month contract as published on the last trading day of the month. |
| Column 1 | Column 2 |
|---|---|
| (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. |
| Column 1 | Column 2 |
|---|---|
| (4) | NYMEX calendar month average settled futures price. |
50
Table of Contents
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.
| Column 1 | Column 2 | Column 3 | Column 4 | Column 5 | Column 6 | Column 7 | Column 8 | Column 9 | Column 10 | Column 11 |
|---|---|---|---|---|---|---|---|---|---|---|
| | | | | | | | | | | |
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.
51
Table of Contents
Sources of Our Revenues
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | Water handling. Water handling expenses relate to the direct operating costs attributable to fresh water and other fluid handling services. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
52
Table of Contents
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
53
Table of Contents
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 | | | (146) | | | 51,302 | |
| Accretion of asset retirement obligations | | | 3,244 | | | — | | | 177 | | | (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 | |
| Column 1 | Column 2 |
|---|---|
| (1) | Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements. |
54
Table of Contents
| | | | | | | | | | | | | | | | | |
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | | 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 | | | 731 | | | — | | | — | | | — | | | 731 | |
| 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 | | | (332) | | | 47,433 | |
| Accretion of asset retirement obligations | | | 3,759 | | | — | | | 189 | | | (189) | | | 3,759 | |
| Loss on sale of assets | | | 862 | | | — | | | 723 | | | (723) | | | 862 | |
| 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) | | | 460 | |
| | | | | | | | | | | | | | | | | |
| Equity in earnings of unconsolidated affiliates | | $ | 93,787 | | | — | | | 110,573 | | | (110,573) | | | 93,787 | |
| Column 1 | Column 2 |
|---|---|
| (1) | Amounts reflect those recorded in Antero Midstream Corporation’s consolidated financial statements. |
55
Table of Contents
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 | | | |||||
| | 2023 | 2024 | (Decrease) | Change | | | |||||||
| Production data (1) (2): | | | | | | | | | | | | | |
| Natural gas (Bcf) | | | 815 | | | 793 | | | (22) | | (3) | % | |
| C2 Ethane (MBbl) | | | 24,657 | | | 30,391 | | | 5,734 | | 23 | % | |
| C3+ NGLs (MBbl) | | | 41,927 | | | 42,434 | | | 507 | | 1 | % | |
| Oil (MBbl) | | | 3,874 | | | 3,693 | | | (181) | | (5) | % | |
| Combined (Bcfe) | | | 1,238 | | | 1,252 | | | 14 | | 1 | % | |
| Daily combined production (MMcfe/d) | | | 3,392 | | | 3,421 | | | 29 | | 1 | % | |
| 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 | | 12 | % | |
| 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 | | 12 | % | |
| 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 | | 4 | % | |
| Processing | | $ | 0.82 | | | 0.85 | | | 0.03 | | 4 | % | |
| Transportation | | $ | 0.62 | | | 0.59 | | | (0.03) | | (5) | % | |
| Production and ad valorem taxes | | $ | 0.13 | | | 0.17 | | | 0.04 | | 31 | % | |
| 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
| Column 1 | Column 2 |
|---|---|
| (1) | Production data excludes volumes related to the VPP. |
| Column 1 | Column 2 |
|---|---|
| (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. |
| Column 1 | Column 2 |
|---|---|
| (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. |
| Column 1 | Column 2 |
|---|---|
| (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).
56
Table of Contents
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:
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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.
57
Table of Contents
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:
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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). |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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). |
| Column 1 | Column 2 | Column 3 |
|---|---|---|
| ● | 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. |
58
Table of Contents
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.
59
Table of Contents
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.
60
Table of Contents
Cash Flows
The following table summarizes our cash flows (in thousands):
| | | | | | | | |
|---|---|---|---|---|---|---|---|
| | | Year Ended December 31, | | ||||
| | | 2023 | 2024 | ||||
| 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
61
Table of Contents
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
62
Table of Contents
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.
63
Table of Contents