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Natural Gas Producing Activities (Unaudited)
 12 Months Ended
Dec. 31, 2022
Extractive Industries [Abstract]  
Natural Gas Producing Activities (Unaudited) Natural Gas Producing Activities (Unaudited)The following supplementary information summarized presents 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,
 20222021
 (Thousands)
Capitalized costs
Proved properties$25,142,857 $23,117,987 
Unproved properties1,747,705 2,405,867 
Total capitalized costs26,890,562 25,523,854 
Less: Accumulated depreciation and depletion9,119,553 7,508,178 
Net capitalized costs$17,771,009 $18,015,676 

Years Ended December 31,
202220212020
(Thousands)
Costs incurred (a)
Property acquisition:   
Proved properties (b)$82,276 $2,286,386 $761,940 
Unproved properties (c)113,523 805,942 78,404 
Exploration3,438 24,403 5,484 
Development1,292,509 950,531 947,233 

(a)Amounts exclude capital expenditures for facilities, information technology and other corporate items as well as the acquired midstream assets described in Note 6.
(b)Amounts in 2022 include $40.5 million for Marcellus leases acquired in the 2022 Asset Acquisition. Amounts in 2021 include $1,754.7 million and $450.0 million for Marcellus wells and leases, respectively, acquired in the Alta Acquisition and Reliance Asset Acquisition described in Note 6. Amounts in 2020 include $674.0 million and $6.5 million for Marcellus and Utica wells, respectively, acquired in the Chevron Acquisition.
(c)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. Amounts in 2020 include $38.9 million for unproved properties acquired in the Chevron 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,
 202220212020
 (Thousands)
Sales of natural gas, NGLs and oil$12,114,168 $6,804,020 $2,650,299 
Transportation and processing2,116,976 1,942,165 1,710,734 
Production300,985 225,279 155,403 
Exploration3,438 24,403 5,484 
Depreciation and depletion1,665,962 1,676,702 1,393,465 
(Gain) loss/impairment on sale/exchange of long-lived assets(8,446)(21,124)100,729 
Impairment and expiration of leases176,606 311,835 306,688 
Income tax expense (benefit)1,987,323 667,435 (254,671)
Results of operations from producing activities, excluding corporate overhead$5,871,324 $1,977,325 $(767,533)
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 crude 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's of business administration in energy from the University of Oklahoma and is a licensed professional engineer with 23 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 crude 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, 2022. 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,
 202220212020
 (MMcf)
Natural gas, NGLs and oil   
Proved developed and undeveloped reserves:   
Balance at January 124,961,499 19,802,092 17,469,394 
Revision of previous estimates(654,618)(274,111)(739,213)
Purchase of hydrocarbons in place141,038 4,186,933 1,380,564 
Sale of hydrocarbons in place— — (256,663)
Extensions, discoveries and other additions2,494,713 3,104,402 3,445,802 
Production(1,940,043)(1,857,817)(1,497,792)
Balance at December 3125,002,589 24,961,499 19,802,092 
Proved developed reserves:
Balance at January 117,218,655 13,641,345 12,443,987 
Balance at December 3117,513,645 17,218,655 13,641,345 
Proved undeveloped reserves:
Balance at January 17,742,844 6,160,747 5,025,407 
Balance at December 317,488,944 7,742,844 6,160,747 
 Years Ended December 31,
 202220212020
 (MMcf)
Natural gas   
Proved developed and undeveloped reserves:   
Balance at January 123,523,665 18,865,013 16,677,202 
Revision of previous estimates(432,315)(568,814)(781,668)
Purchase of natural gas in place141,038 4,186,933 1,209,326 
Sale of natural gas in place— — (254,930)
Extensions, discoveries and other additions2,434,543 2,786,850 3,433,857 
Production(1,842,044)(1,746,317)(1,418,774)
Balance at December 3123,824,887 23,523,665 18,865,013 
Proved developed reserves:   
Balance at January 116,152,083 12,750,312 11,811,521 
Balance at December 3116,541,017 16,152,083 12,750,312 
Proved undeveloped reserves:
Balance at January 17,371,582 6,114,701 4,865,681 
Balance at December 317,283,870 7,371,582 6,114,701 

 Years Ended December 31,
202220212020
(Mbbl)
NGLs   
Proved developed and undeveloped reserves:   
Balance at January 1225,792 148,762 126,955 
Revision of previous estimates(33,955)46,868 6,825 
Purchase of NGLs in place— — 25,879 
Sale of NGLs in place— — (289)
Extensions, discoveries and other additions9,610 47,120 1,757 
Production(15,306)(16,958)(12,365)
Balance at December 31186,141 225,792 148,762 
Proved developed reserves:  
Balance at January 1169,781 141,489 100,945 
Balance at December 31154,921 169,781 141,489 
Proved undeveloped reserves:
Balance at January 156,011 7,273 26,010 
Balance at December 3131,220 56,011 7,273 
 Years Ended December 31,
 202220212020
 (Mbbl)
Oil   
Proved developed and undeveloped reserves:   
Balance at January 113,846 7,417 5,077 
Revision of previous estimates(3,095)2,249 250 
Purchase of oil in place— — 2,660 
Sale of oil in place— — — 
Extensions, discoveries and other additions418 5,805 234 
Production(1,027)(1,625)(804)
Balance at December 3110,142 13,846 7,417 
Proved developed reserves:   
Balance at January 17,981 7,016 4,466 
Balance at December 317,183 7,981 7,016 
Proved undeveloped reserves:
Balance at January 15,865 401 611 
Balance at December 312,959 5,865 401 

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 has 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.

The change in reserves during the year ended December 31, 2020 resulted from the following:
•Conversions of 2,102 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 3,446 Bcfe, which exceeded 2020 production of 1,498 Bcfe. Extensions, discoveries and other additions included an increase of 2,096 Bcfe of proved undeveloped additions associated with acreage that was previously unproved but became proved using reliable technologies which expanded the number of the Company's technically proven locations, 1,295 Bcfe due to additions associated with directly offsetting development, 31 Bcfe from extension of proved undeveloped reserves lateral lengths and 24 Bcfe from converting unproved reserves to proved developed reserves.
•Negative revisions of 510 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. This includes 245 Bcfe from lower pricing that impacted well economics, shifting capital from the Ohio Utica, to Pennsylvania and West Virginia Marcellus, and 265 Bcfe as a result of continued implementation of the Company's combo-development strategy.
•Negative revisions of 384 Bcfe primarily from proved developed locations as a result of negative curve revisions in the Ohio Utica.
•Positive revisions to proved undeveloped locations of 155 Bcfe due primarily to changes in working interests and net revenue interests as well as type curve updates.
•Purchase of hydrocarbons in place of 1,381 Bcfe from the Chevron Acquisition described in Note 6.
•Sale of hydrocarbons in place of 257 Bcfe due to the 2020 Divestiture described in Note 8.

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 crude oil reserves.
December 31,
 202220212020
 (Thousands)
Future cash inflows (a)$140,032,653 $70,844,136 $27,976,557 
Future production costs (b)(22,801,652)(20,961,576)(16,344,965)
Future development costs(3,244,211)(2,882,921)(2,268,109)
Future income tax expenses(26,375,241)(10,433,091)(1,820,341)
Future net cash flow87,611,549 36,566,548 7,543,142 
10% annual discount for estimated timing of cash flows(47,547,025)(19,285,424)(4,176,684)
Standardized measure of discounted future net cash flows$40,064,524 $17,281,124 $3,366,458 

(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,
202220212020
Oil for West Texas Intermediate (WTI) ($/Bbl)$94.14 $66.55 $39.54 
Less regional adjustments ($/Bbl)$17.31 $14.98 $18.60 
Oil price ($/Bbl)$76.83 $51.57 $20.94 
Natural gas for NYMEX ($/MMBtu)$6.357 $3.598 $1.985 
Less regional adjustments ($/MMBtu)$1.094 $1.040 $0.680 
Natural gas price ($/Mcf)$5.543 $2.694 $1.380 
NGLs price ($/Bbl)$38.66 $29.95 $11.97 

(b)Includes approximately $2,098 million, $1,937 million and $1,554 million for future plugging and abandonment costs as of December 31, 2022, 2021 and 2020, respectively.
Holding production and development costs constant, an increase in NYMEX price of $0.10 per Dth for natural gas, an increase in WTI of $10 per barrel for NGLs and an increase in WTI of $10 per barrel for oil would result in a change in the December 31, 2022 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,123 million, $764 million and $50 million, respectively.

The following table summarizes the changes in the standardized measure of discounted future net cash flows.    
Years Ended December 31,
 202220212020
 (Thousands)
Net sales and transfers of natural gas and oil produced$(9,696,207)$(4,636,576)$(784,163)
Net changes in prices, production and development costs35,353,172 17,290,913 (6,761,447)
Extensions, discoveries and improved recovery, net of related costs1,798,851 46,078 714,808 
Development costs incurred902,925 764,002 797,796 
Net purchase of minerals in place280,233 3,491,441 350,075 
Net sale of minerals in place— — (226,497)
Revisions of previous quantity estimates(299,423)184,552 (324,415)
Accretion of discount1,728,112 336,646 849,267 
Net change in income taxes(7,233,051)(3,614,029)152,978 
Timing and other(51,212)51,639 105,383 
Net increase (decrease)22,783,400 13,914,666 (5,126,215)
Balance at January 117,281,124 3,366,458 8,492,673 
Balance at December 31$40,064,524 $17,281,124 $3,366,458