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Natural Gas Producing Activities (Unaudited) (Tables) | 12 Months Ended
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Dec. 31, 2024
Extractive Industries [Abstract] |
Schedule of Cost Incurred Relating to Property Acquisition, Exploration and Development | The following tables present total aggregate capitalized costs and costs incurred related to natural gas, NGLs and oil production activities.
| December 31,
| 2024 |  | 2023
| (Thousands)
Capitalized costs |  |  |
Proved properties | $ | 31,986,473 |  |  | $ | 30,471,164 |
Unproved properties | 1,563,440 |  |  | 2,039,431 |
Total capitalized costs | 33,549,913 |  |  | 32,510,595 |
Less: Accumulated depreciation and depletion | 12,489,317 |  |  | 10,734,099 |
Net capitalized costs | $ | 21,060,596 |  |  | $ | 21,776,496 |
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (Thousands)
Costs incurred (a) |  |  |  |  |
Property acquisition: |  |  |  |  |
Proved properties (b) | $ | 410,805 |  |  | $ | 4,142,621 |  |  | $ | 82,276 |
Unproved properties (c) | 98,007 |  |  | 575,130 |  |  | 113,523 |
Exploration | 2,735 |  |  | 3,330 |  |  | 3,438 |
Development | 1,848,000 |  |  | 1,782,428 |  |  | 1,298,665 |
(a)Amounts for all years presented exclude costs for facilities, information technology and other corporate items. In addition, amounts for 2024 exclude midstream assets. Amounts for 2023 and 2022 include costs for midstream assets. (b)Amounts in 2024 include $267.7 million and $74.7 million for wells and leases, respectively, received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $2,522.3 million, $757.6 million and $719.6 million for wells, midstream assets and leases, respectively, acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $40.5 million for leases acquired in the 2022 Asset Acquisition. See Note 6. (c)Amounts in 2024 include $10.8 million for unproved properties received as consideration for the First NEPA Non-Operated Asset Divestiture. See Note 7. Amounts in 2023 include $523.0 million for unproved properties acquired in the Tug Hill and XcL Midstream Acquisition. Amounts in 2022 include $17.1 million for unproved properties acquired in the 2022 Asset Acquisition. See Note 6.
Results of Operations Related to Natural Gas, NGL and Oil Producing Activities | The following table presents the results of operations related to natural gas, NGLs and oil production.
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (Thousands)
Sales of natural gas, NGLs and oil | $ | 4,934,366 |  |  | $ | 5,044,768 |  |  | $ | 12,114,168 |
Transportation and processing | 1,915,616 |  |  | 2,157,260 |  |  | 2,116,976 |
Production | 377,007 |  |  | 254,700 |  |  | 300,985 |
Operating and maintenance | 37,951 |  |  | — |  |  | — |
Exploration | 2,735 |  |  | 3,330 |  |  | 3,438 |
Depreciation and depletion | 2,016,670 |  |  | 1,732,142 |  |  | 1,665,962 |
(Gain) loss on sale/exchange of long-lived assets | (764,431) |  |  | 17,445 |  |  | (8,446) |
Impairment and expiration of leases | 97,368 |  |  | 109,421 |  |  | 176,606 |
Income tax expense | 316,377 |  |  | 187,463 |  |  | 1,987,323 |
Results of operations from producing activities, excluding corporate overhead | $ | 935,073 |  |  | $ | 583,007 |  |  | $ | 5,871,324 |
Schedule of the Entity's Proved Reserves | For all tables presented, NGLs and oil were converted at a rate of one Mbbl to approximately six million cubic feet (MMcf).
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (MMcfe)
Natural gas, NGLs and oil |  |  |  |  |
Proved developed and undeveloped reserves: |  |  |  |  |
Balance at January 1 | 27,596,694 |  |  | 25,002,589 |  |  | 24,961,499 |
Revision of previous estimates | (1,079,677) |  |  | (1,402,039) |  |  | (654,618) |
Purchase of hydrocarbons in place | 413,040 |  |  | 2,600,667 |  |  | 141,038 |
Sale of natural gas in place | (1,562,849) |  |  | — |  |  | — |
Extensions, discoveries and other additions | 3,125,620 |  |  | 3,411,750 |  |  | 2,494,713 |
Production | (2,228,159) |  |  | (2,016,273) |  |  | (1,940,043) |
Balance at December 31 | 26,264,669 |  |  | 27,596,694 |  |  | 25,002,589 |
Proved developed reserves: |  |  |  |  |
Balance at January 1 | 19,558,176 |  |  | 17,513,645 |  |  | 17,218,655 |
Balance at December 31 | 18,804,929 |  |  | 19,558,176 |  |  | 17,513,645 |
Proved undeveloped reserves: |  |  |  |  |
Balance at January 1 | 8,038,518 |  |  | 7,488,944 |  |  | 7,742,844 |
Balance at December 31 | 7,459,740 |  |  | 8,038,518 |  |  | 7,488,944 |
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (MMcf)
Natural gas |  |  |  |  |
Proved developed and undeveloped reserves: |  |  |  |  |
Balance at January 1 | 25,795,134 |  |  | 23,824,887 |  |  | 23,523,665 |
Revision of previous estimates | (917,676) |  |  | (1,461,305) |  |  | (432,315) |
Purchase of natural gas in place | 395,423 |  |  | 2,012,159 |  |  | 141,038 |
Sale of natural gas in place | (1,562,849) |  |  | — |  |  | — |
Extensions, discoveries and other additions | 2,921,638 |  |  | 3,326,736 |  |  | 2,434,543 |
Production | (2,086,441) |  |  | (1,907,343) |  |  | (1,842,044) |
Balance at December 31 | 24,545,229 |  |  | 25,795,134 |  |  | 23,824,887 |
Proved developed reserves: |  |  |  |  |
Balance at January 1 | 18,186,432 |  |  | 16,541,017 |  |  | 16,152,083 |
Balance at December 31 | 17,440,191 |  |  | 18,186,432 |  |  | 16,541,017 |
Proved undeveloped reserves: |  |  |  |  |
Balance at January 1 | 7,608,702 |  |  | 7,283,870 |  |  | 7,371,582 |
Balance at December 31 | 7,105,038 |  |  | 7,608,702 |  |  | 7,283,870 |
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (Mbbl)
NGLs |  |  |  |  |
Proved developed and undeveloped reserves: |  |  |  |  |
Balance at January 1 | 285,345 |  |  | 186,141 |  |  | 225,792 |
Revision of previous estimates | (24,332) |  |  | 11,558 |  |  | (33,955) |
Purchase of NGLs in place | 2,529 |  |  | 90,604 |  |  | — |
Extensions, discoveries and other additions | 30,391 |  |  | 13,592 |  |  | 9,610 |
Production | (22,025) |  |  | (16,550) |  |  | (15,306) |
Balance at December 31 | 271,908 |  |  | 285,345 |  |  | 186,141 |
Proved developed reserves: |  |  |  |  |
Balance at January 1 | 218,523 |  |  | 154,921 |  |  | 169,781 |
Balance at December 31 | 217,786 |  |  | 218,523 |  |  | 154,921 |
Proved undeveloped reserves: |  |  |  |  |
Balance at January 1 | 66,822 |  |  | 31,220 |  |  | 56,011 |
Balance at December 31 | 54,122 |  |  | 66,822 |  |  | 31,220 |
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (Mbbl)
Oil |  |  |  |  |
Proved developed and undeveloped reserves: |  |  |  |  |
Balance at January 1 | 14,915 |  |  | 10,142 |  |  | 13,846 |
Revision of previous estimates | (2,669) |  |  | (1,680) |  |  | (3,095) |
Purchase of oil in place | 407 |  |  | 7,481 |  |  | — |
Extensions, discoveries and other additions | 3,606 |  |  | 577 |  |  | 418 |
Production | (1,595) |  |  | (1,605) |  |  | (1,027) |
Balance at December 31 | 14,664 |  |  | 14,915 |  |  | 10,142 |
Proved developed reserves: |  |  |  |  |
Balance at January 1 | 10,101 |  |  | 7,183 |  |  | 7,981 |
Balance at December 31 | 9,669 |  |  | 10,101 |  |  | 7,183 |
Proved undeveloped reserves: |  |  |  |  |
Balance at January 1 | 4,814 |  |  | 2,959 |  |  | 5,865 |
Balance at December 31 | 4,995 |  |  | 4,814 |  |  | 2,959 |
Schedule of Estimated Future Net Cash Flows From Natural Gas and Oil Reserves | The following table summarizes estimated future net cash flows from natural gas and oil reserves.
| December 31,
| 2024 |  | 2023 |  | 2022
| (Thousands)
Future cash inflows (a) | $ | 44,871,509 |  |  | $ | 52,916,665 |  |  | $ | 140,032,653 |
Future production costs (b) | (18,979,056) |  |  | (24,357,033) |  |  | (22,801,652) |
Future development costs | (4,352,890) |  |  | (4,298,372) |  |  | (3,244,211) |
Future income tax expenses | (4,445,354) |  |  | (5,230,629) |  |  | (26,375,241) |
Future net cash flow | 17,094,209 |  |  | 19,030,631 |  |  | 87,611,549 |
10% annual discount for estimated timing of cash flows | (9,095,069) |  |  | (9,768,282) |  |  | (47,547,025) |
Standardized measure of discounted future net cash flows | $ | 7,999,140 |  |  | $ | 9,262,349 |  |  | $ | 40,064,524 |
(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines. Reserves were computed using average first-day-of-the-month closing prices for the prior twelve months less regional adjustments. Regional adjustments were calculated using historical average realized prices received in the Appalachian Basin. NGLs pricing was calculated using average first-day-of-the-month closing prices for the prior twelve months for NGLs components, adjusted using the regional component makeup of proved NGLs.
| December 31,
| 2024 |  | 2023 |  | 2022
Natural gas for NYMEX ($/MMBtu) | $ | 2.130 |  |  | $ | 2.637 |  |  | $ | 6.357 |
Less regional adjustments ($/MMBtu) | 0.741 |  |  | 1.029 |  |  | 1.094 |
Natural gas price ($/Mcf) | 1.468 |  |  | 1.700 |  |  | 5.543 |
NGLs price ($/Bbl) | 29.28 |  |  | 28.44 |  |  | 38.66 |
Oil for West Texas Intermediate (WTI) ($/Bbl) | 76.32 |  |  | 78.21 |  |  | 94.14 |
Less regional adjustments ($/Bbl) | 16.87 |  |  | 14.35 |  |  | 17.31 |
Oil price ($/Bbl) | 59.45 |  |  | 63.86 |  |  | 76.83 |
(b)Includes approximately $2,553 million, $2,443 million and $2,098 million for future plugging and abandonment costs as of December 31, 2024, 2023 and 2022, respectively.
Schedule of Changes in The Standardized Measure of Discounted Net Cash Flows From Natural Gas and Oil Reserves | The following table summarizes the changes in the standardized measure of discounted future net cash flows.
| Years Ended December 31,
| 2024 |  | 2023 |  | 2022
| (Thousands)
Net sales and transfers of natural gas and oil produced | $ | (2,603,792) |  |  | $ | (2,632,808) |  |  | $ | (9,696,207) |
Net changes in prices, production and development costs | (1,237,271) |  |  | (48,739,248) |  |  | 35,353,172 |
Extensions, discoveries and improved recovery, net of related costs | 464,496 |  |  | 6,347,387 |  |  | 1,798,851 |
Development costs incurred | 1,432,315 |  |  | 1,296,380 |  |  | 902,925 |
Net purchase of minerals in place | 269,453 |  |  | 2,131,567 |  |  | 280,233 |
Net sale of minerals in place | (692,019) |  |  | — |  |  | — |
Revision of previous estimates | (263,191) |  |  | (2,768,922) |  |  | (299,423) |
Accretion of discount | 926,235 |  |  | 4,006,452 |  |  | 1,728,112 |
Net change in income taxes | 411,999 |  |  | 9,190,460 |  |  | (7,233,051) |
Timing and other | 28,566 |  |  | 366,557 |  |  | (51,212) |
Net (decrease) increase | (1,263,209) |  |  | (30,802,175) |  |  | 22,783,400 |
Balance at January 1 | 9,262,349 |  |  | 40,064,524 |  |  | 17,281,124 |
Balance at December 31 | $ | 7,999,140 |  |  | $ | 9,262,349 |  |  | $ | 40,064,524 |
Following the completion of the Equitrans Midstream Merger as described in Note 6, the Company updated certain of its cost assumptions for estimating its proved reserves to reflect the Company's ownership of the assets acquired in the Equitrans Midstream Merger and the elimination of the gathering, transportation and water service costs from the pre-existing contractual relationships between the Company and Equitrans Midstream, which are treated as intercompany transactions on a consolidated basis. Similarly, the Company updated certain of its future cost assumptions to include the additional expenses required to build and maintain the acquired midstream assets, which are needed to transport the Company's produced gas to the first liquid sales point. Lastly, following the completion of the Midstream Joint Venture Transaction as discussed in Note 8, the Company updated certain of its future cost assumptions to account for changes in the noncontrolling interest ownership of the assets owned by the Midstream Joint Venture. The Company believes that the methodology used in developing these assumptions best reflects the current economic conditions affecting the Company's reserves and gives consideration to the Company's ownership interest in its midstream assets.

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