Natural Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2024

Extractive Industries [Abstract]

Natural Gas Producing Activities (Unaudited)

Natural Gas Producing Activities (Unaudited)

The following supplementary information presents a summary of the results of natural gas and oil activities in accordance with the successful efforts method of accounting for production activities.

Production Costs

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 for 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

Reserve Information

Proved developed reserves represent only those reserves expected to be recovered from existing wells and support equipment. Proved undeveloped reserves represent proved reserves expected to be recovered from new wells after substantial development costs are incurred.

The Company's estimate of proved natural gas, NGLs and oil reserves was prepared by Company engineers. The engineer primarily responsible for overseeing the preparation of the reserves estimate has 22 years of experience in the oil and gas industry and holds a bachelor's degree in petroleum engineering from the University of Oklahoma, a master's degree in business administration from Oklahoma City University and a Juris Doctor from the Oklahoma City University School of Law. To support the accurate and timely preparation and disclosure of its reserve estimates, the Company established internal controls over its reserve estimation processes and procedures, including the following: the price, heat content conversion rate and cost assumptions used in the economic model to determine the reserves are reviewed by management; division of interest and production volume are reconciled between the system used to calculate the reserves and other accounting/measurement systems; the reserves reconciliation between prior year reserves and current year reserves is reviewed by senior management; and the estimates of proved natural gas, NGLs and oil reserves are audited by Netherland, Sewell & Associates, Inc. (NSAI), an independent consulting firm hired by management. Since 1961, NSAI has evaluated oil and gas properties and independently certified petroleum reserves quantities in the United States and internationally.

In the course of its audit, NSAI conducted a detailed review of 100% of the total net natural gas, NGLs and oil proved reserves attributable to the Company's interests as of December 31, 2024. NSAI conducted a detailed, well-by-well audit of all the Company's properties. The estimates prepared by the Company and audited by NSAI were within the recommended 10% tolerance threshold set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, analogy and material balance were utilized in the evaluation of reserves. All of the Company's proved reserves are located in the United States.

The Company utilizes reliable technologies in the calculation of its proved undeveloped reserves. The technologies used in the estimation of the Company's proved undeveloped reserves include, but are not limited to, empirical evidence through drilling results and well performance, production data, decline curve analysis, well logs, geologic maps, core data, seismic data, demonstrated relationship between geologic parameters and performance, and the implementation and application of statistical analysis.

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

The change in reserves during the year ended December 31, 2024 resulted from the following:

•Conversions of 2,637 billion cubic feet equivalent (Bcfe) of proved undeveloped reserves to proved developed reserves.

•Extensions, discoveries and other additions of 3,126 Bcfe, which exceeded 2024 production of 2,228 Bcfe. Extensions, discoveries and other additions included an increase of 2,414 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2024 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan, 498 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to the Company's five-year development plan, positive revisions of 157 Bcfe from the extension of lateral lengths of proved undeveloped reserves and 57 Bcfe from converting unproved reserves to proved developed reserves.

•Negative revisions of 925 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking primarily as a result of development schedule changes.

•Negative revisions of 87 Bcfe to proved undeveloped locations primarily related to revisions to lateral lengths and type curves.

•Positive revisions to proved undeveloped locations of 189 Bcfe due primarily to changes in ownership interests.

•Negative revisions of 65 Bcfe primarily from proved developed locations as a result of negative curve revisions.

•Negative revisions of 192 Bcfe from proved developed locations as a result of lower pricing, impacting well economics.

•Purchase of hydrocarbons in place of 413 Bcfe in connection with the First NEPA Non-Operated Asset Divestiture described in Note 7.

•Sale of natural gas in place of 1,563 Bcfe in the NEPA Non-Operated Asset Divestitures described in Note 7.

The change in reserves during the year ended December 31, 2023 resulted from the following:

•Conversions of 2,561 Bcfe of proved undeveloped reserves to proved developed reserves.

•Extensions, discoveries and other additions of 3,412 Bcfe, which exceeded 2023 production of 2,016 Bcfe. Extensions, discoveries and other additions included an increase of 1,670 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2023 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan, 1,341 Bcfe of proved undeveloped additions for previously proved undeveloped properties reclassified from unproved properties due to their addition to the Company's five-year development plan, positive revisions of 92 Bcfe from the extension of lateral lengths of proved undeveloped reserves and 309 Bcfe from converting unproved reserves to proved developed reserves.

•Negative revisions of 755 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking as a result of development schedule changes.

•Negative revisions of 367 Bcfe primarily from proved undeveloped locations as a result of revisions to type curves.

•Positive revisions to proved undeveloped locations of 290 Bcfe due primarily to changes in ownership interests.

•Negative revisions of 208 Bcfe primarily from proved developed locations as a result of negative curve revisions.

•Negative revisions of 362 Bcfe from lower pricing that impacted well economics.

•Purchase of hydrocarbons in place of 2,600 Bcfe from the Tug Hill and XcL Midstream Acquisition described in Note 6.

The change in reserves during the year ended December 31, 2022 resulted from the following:

•Conversions of 1,365 Bcfe of proved undeveloped reserves to proved developed reserves.

•Extensions, discoveries and other additions of 2,495 Bcfe, which exceeded 2022 production of 1,940 Bcfe. Extensions, discoveries and other additions included an increase of 2,077 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2022 reserve development that expanded the number of the Company's proven locations and additions to the Company's five-year drilling plan and 418 Bcfe from converting unproved reserves to proved developed reserves.

•Negative revisions of 1,625 Bcfe related to proved undeveloped locations that are no longer expected to be developed as proved reserves within five years of initial booking as a result of development schedule changes, driven largely by third-party impacts, which have pushed planned completion dates into a future period from when originally planned.

•Positive revisions to proved undeveloped locations of 518 Bcfe due primarily to changes in ownership interests.

•Positive revisions of 356 Bcfe primarily from proved developed locations as a result of positive curve revisions.

•Positive revisions of 96 Bcfe from higher pricing that impacted well economics.

•Purchase of hydrocarbons in place of 141 Bcfe from the 2022 Asset Acquisition described in Note 6.

Standardized Measure of Discounted Future Cash Flow

Management cautions that the standardized measure of discounted future net cash flows should not be viewed as an indication of the fair market value of natural gas and oil producing properties, nor of the future cash flows expected to be generated therefrom. The information presented does not give recognition to future changes in estimated reserves, selling prices or costs and has been discounted at a rate of 10%.

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.

Holding production and development costs constant, an increase in NYMEX price of $0.10 per Dth for natural gas, an increase in WTI price of $10 per barrel for NGLs and an increase in WTI price of $10 per barrel for oil would result in a change in the December 31, 2024 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,184 million, $1,128 million and $73 million, respectively.

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.