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Natural Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2023

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,
	2023		2022

	(Thousands)
Capitalized costs
Proved properties	$	30,471,164	$	25,142,857
Unproved properties	2,039,431		1,747,705
Total capitalized costs	32,510,595		26,890,562
Less: Accumulated depreciation and depletion	10,734,099		9,119,553
Net capitalized costs	$	21,776,496	$	17,771,009


	Years Ended December 31,
	2023		2022		2021

	(Thousands)
Costs incurred (a)
Property acquisition:
Proved properties (b)	$	4,142,621	$	82,276	$	2,544,316
Unproved properties (c)	575,130		113,523		805,942
Exploration	3,330		3,438		24,403
Development	1,782,428		1,298,665		954,580

(a)Amounts exclude costs for facilities, information technology and other corporate items and include costs for midstream assets.

(b)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 described in Note 6. Amounts in 2022 include $40.5 million for leases acquired in the 2022 Asset Acquisition. Amounts in 2021 include $1,754.7 million, $257.9 million and $450.0 million for wells, midstream assets and leases, respectively, acquired in the Alta Acquisition and Reliance Asset Acquisition described in Note 6.

(c)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. Amounts in 2021 include $743.3 million for unproved properties acquired in the Alta Acquisition.

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,
	2023		2022		2021

	(Thousands)
Sales of natural gas, NGLs and oil	$	5,044,768	$	12,114,168	$	6,804,020
Transportation and processing	2,157,260		2,116,976		1,942,165
Production	254,700		300,985		225,279
Exploration	3,330		3,438		24,403
Depreciation and depletion	1,732,142		1,665,962		1,676,702
Loss (gain) on sale/exchange of long-lived assets	17,445		(8,446)		(21,124)
Impairment and expiration of leases	109,421		176,606		311,835
Income tax expense	187,463		1,987,323		667,435
Results of operations from producing activities, excluding corporate overhead	$	583,007	$	5,871,324	$	1,977,325

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 holds a bachelor's degree in chemical engineering from Michigan Technological University, a master's degree in chemical engineering from Colorado State University, an Executive Master of Business Administration in energy from the University of Oklahoma and is a licensed professional engineer with 24 years of experience in the oil and gas industry. 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, 2023. 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,
	2023	2022	2021

	(MMcf)
Natural gas, NGLs and oil
Proved developed and undeveloped reserves:
Balance at January 1	25,002,589	24,961,499	19,802,092
Revision of previous estimates	(1,402,039)	(654,618)	(274,111)
Purchase of hydrocarbons in place	2,600,667	141,038	4,186,933
Extensions, discoveries and other additions	3,411,750	2,494,713	3,104,402
Production	(2,016,273)	(1,940,043)	(1,857,817)
Balance at December 31	27,596,694	25,002,589	24,961,499
Proved developed reserves:
Balance at January 1	17,513,645	17,218,655	13,641,345
Balance at December 31	19,558,176	17,513,645	17,218,655
Proved undeveloped reserves:
Balance at January 1	7,488,944	7,742,844	6,160,747
Balance at December 31	8,038,518	7,488,944	7,742,844


	Years Ended December 31,
	2023	2022	2021

	(MMcf)
Natural gas
Proved developed and undeveloped reserves:
Balance at January 1	23,824,887	23,523,665	18,865,013
Revision of previous estimates	(1,461,305)	(432,315)	(568,814)
Purchase of natural gas in place	2,012,159	141,038	4,186,933
Extensions, discoveries and other additions	3,326,736	2,434,543	2,786,850
Production	(1,907,343)	(1,842,044)	(1,746,317)
Balance at December 31	25,795,134	23,824,887	23,523,665
Proved developed reserves:
Balance at January 1	16,541,017	16,152,083	12,750,312
Balance at December 31	18,186,432	16,541,017	16,152,083
Proved undeveloped reserves:
Balance at January 1	7,283,870	7,371,582	6,114,701
Balance at December 31	7,608,702	7,283,870	7,371,582


	Years Ended December 31,
	2023	2022	2021

	(Mbbl)
NGLs
Proved developed and undeveloped reserves:
Balance at January 1	186,141	225,792	148,762
Revision of previous estimates	11,558	(33,955)	46,868
Purchase of NGLs in place	90,604	—	—

Extensions, discoveries and other additions	13,592	9,610	47,120
Production	(16,550)	(15,306)	(16,958)
Balance at December 31	285,345	186,141	225,792
Proved developed reserves:
Balance at January 1	154,921	169,781	141,489
Balance at December 31	218,523	154,921	169,781
Proved undeveloped reserves:
Balance at January 1	31,220	56,011	7,273
Balance at December 31	66,822	31,220	56,011


	Years Ended December 31,
	2023	2022	2021

	(Mbbl)
Oil
Proved developed and undeveloped reserves:
Balance at January 1	10,142	13,846	7,417
Revision of previous estimates	(1,680)	(3,095)	2,249
Purchase of oil in place	7,481	—	—

Extensions, discoveries and other additions	577	418	5,805
Production	(1,605)	(1,027)	(1,625)
Balance at December 31	14,915	10,142	13,846
Proved developed reserves:
Balance at January 1	7,183	7,981	7,016
Balance at December 31	10,101	7,183	7,981
Proved undeveloped reserves:
Balance at January 1	2,959	5,865	401
Balance at December 31	4,814	2,959	5,865

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.

The change in reserves during the year ended December 31, 2021 resulted from the following:

•Conversions of 1,634 Bcfe of proved undeveloped reserves to proved developed reserves.

•Extensions, discoveries and other additions of 3,104 Bcfe, which exceeded 2021 production of 1,858 Bcfe. Extensions, discoveries and other additions included an increase of 2,828 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved due to 2021 reserve development that expanded the number of the Company's proven locations, implementation of, and alignment with, the Company's combo-development strategy and additions to the Company's five-year drilling plan, 52 Bcfe from extension of proved undeveloped reserves lateral lengths and 224 Bcfe from converting unproved reserves to proved developed reserves.

•Negative revisions of 819 Bcfe from proved undeveloped locations that are no longer expected to be developed within five years of initial booking as proved reserves as a result of revisions to the Company’s five-year drilling plan allowing for continued alignment with the Company’s combo-development strategy.

•Negative revisions to proved undeveloped locations of 62 Bcfe due primarily to changes in working interests and net revenue interest.

•Negative revisions of 31 Bcfe primarily from proved developed locations as a result of negative curve revisions.

•Positive revisions of 638 Bcfe from higher pricing that impacted well economics.

•Purchase of hydrocarbons in place of 4,187 Bcfe from the Alta Acquisition and Reliance Asset Acquisition described in Note 6.

Standard Measure of Discounted Future Cash Flow

Management cautions that the standard measure of discounted future 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,
	2023		2022		2021

	(Thousands)
Future cash inflows (a)	$	52,916,665	$	140,032,653	$	70,844,136
Future production costs (b)	(24,357,033)		(22,801,652)		(20,961,576)
Future development costs	(4,298,372)		(3,244,211)		(2,882,921)
Future income tax expenses	(5,230,629)		(26,375,241)		(10,433,091)
Future net cash flow	19,030,631		87,611,549		36,566,548
10% annual discount for estimated timing of cash flows	(9,768,282)		(47,547,025)		(19,285,424)
Standardized measure of discounted future net cash flows	$	9,262,349	$	40,064,524	$	17,281,124

(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,
	2023		2022		2021
Oil for West Texas Intermediate (WTI) ($/Bbl)	$	78.21	$	94.14	$	66.55
Less regional adjustments ($/Bbl)	14.35		17.31		14.98
Oil price ($/Bbl)	63.86		76.83		51.57
Natural gas for NYMEX ($/MMBtu)	2.637		6.357		3.598
Less regional adjustments ($/MMBtu)	1.029		1.094		1.040
Natural gas price ($/Mcf)	1.700		5.543		2.694
NGLs price ($/Bbl)	28.44		38.66		29.95

(b)Includes approximately $2,443 million, $2,098 million and $1,937 million for future plugging and abandonment costs as of December 31, 2023, 2022 and 2021, 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, 2023 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,260 million, $1,214 million and $77 million, respectively.

The following table summarizes the changes in the standardized measure of discounted future net cash flows.


	Years Ended December 31,
	2023		2022		2021

	(Thousands)
Net sales and transfers of natural gas and oil produced	$	(2,632,808)	$	(9,696,207)	$	(4,636,576)
Net changes in prices, production and development costs	(48,739,248)		35,353,172		17,290,913
Extensions, discoveries and improved recovery, net of related costs	6,347,387		1,798,851		46,078
Development costs incurred	1,296,380		902,925		764,002
Net purchase of minerals in place	2,131,567		280,233		3,491,441

Revisions of previous quantity estimates	(2,768,922)		(299,423)		184,552
Accretion of discount	4,006,452		1,728,112		336,646
Net change in income taxes	9,190,460		(7,233,051)		(3,614,029)
Timing and other	366,557		(51,212)		51,639
Net (decrease) increase	(30,802,175)		22,783,400		13,914,666
Balance at January 1	40,064,524		17,281,124		3,366,458
Balance at December 31	$	9,262,349	$	40,064,524	$	17,281,124