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Natural Gas Producing Activities (Unaudited)
 12 Months Ended
Dec. 31, 2021
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,
 20212020
 (Thousands)
Capitalized costs
Proved properties$23,117,987 $19,479,211 
Unproved properties2,405,867 2,291,814 
Total capitalized costs25,523,854 21,771,025 
Less: Accumulated depreciation and depletion7,508,178 5,866,418 
Net capitalized costs$18,015,676 $15,904,607 

Years Ended December 31,
202120202019
(Thousands)
Costs incurred (a)
Property acquisition:   
Proved properties (b)$2,286,386 $761,940 $40,316 
Unproved properties (c)805,942 78,404 154,128 
Exploration24,403 5,484 7,223 
Development950,531 947,233 1,560,346 

(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 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 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,
 202120202019
 (Thousands)
Sales of natural gas, NGLs and oil$6,804,020 $2,650,299 $3,791,414 
Transportation and processing1,942,165 1,710,734 1,752,752 
Production225,279 155,403 153,785 
Exploration24,403 5,484 7,223 
Depreciation and depletion1,676,702 1,393,465 1,538,745 
(Gain) loss/impairment on sale/exchange of long-lived assets(21,124)100,729 1,138,287 
Impairment and expiration of leases311,835 306,688 556,424 
Income tax expense (benefit)667,435 (254,671)(340,843)
Results of operations from producing activities, excluding corporate overhead$1,977,325 $(767,533)$(1,014,959)

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 and an executive master of business administration in energy from the University of Oklahoma and has 21 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, 2021. 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.

During 2020, the Company conducted a study of its reserves areas to determine the reliability of the technology used in calculating the Company's reserves. This study demonstrated that technologies used in the course of the Company's reserves determination are reliable, provide reasonable certainty of future performance and economics of the Company's wells, and conform to booking practices when using reliable technologies. The technologies used in the estimation of the Company's proved 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,
 202120202019
 (MMcf)
Natural gas, NGLs and oil   
Proved developed and undeveloped reserves:   
Balance at January 119,802,092 17,469,394 21,816,776 
Revision of previous estimates(274,111)(739,213)(4,907,239)
Purchase of hydrocarbons in place4,186,933 1,380,564 — 
Sale of hydrocarbons in place— (256,663)— 
Extensions, discoveries and other additions3,104,402 3,445,802 2,067,753 
Production(1,857,817)(1,497,792)(1,507,896)
Balance at December 3124,961,499 19,802,092 17,469,394 
Proved developed reserves:
Balance at January 113,641,345 12,443,987 11,550,161 
Balance at December 3117,218,655 13,641,345 12,443,987 
Proved undeveloped reserves:
Balance at January 16,160,747 5,025,407 10,266,615 
Balance at December 317,742,844 6,160,747 5,025,407 
 Years Ended December 31,
 202120202019
 (MMcf)
Natural gas   
Proved developed and undeveloped reserves:   
Balance at January 118,865,013 16,677,202 20,805,452 
Revision of previous estimates(568,814)(781,668)(4,722,799)
Purchase of natural gas in place4,186,933 1,209,326 — 
Sale of natural gas in place— (254,930)— 
Extensions, discoveries and other additions2,786,850 3,433,857 2,029,683 
Production(1,746,317)(1,418,774)(1,435,134)
Balance at December 3123,523,665 18,865,013 16,677,202 
Proved developed reserves:   
Balance at January 112,750,312 11,811,521 10,887,953 
Balance at December 3116,152,083 12,750,312 11,811,521 
Proved undeveloped reserves:
Balance at January 16,114,701 4,865,681 9,917,499 
Balance at December 317,371,582 6,114,701 4,865,681 
 Years Ended December 31,
202120202019
(Mbbl)
NGLs   
Proved developed and undeveloped reserves:   
Balance at January 1148,762 126,955 162,395 
Revision of previous estimates46,868 6,825 (30,312)
Purchase of NGLs in place— 25,879 — 
Sale of NGLs in place— (289)— 
Extensions, discoveries and other additions47,120 1,757 6,177 
Production(16,958)(12,365)(11,305)
Balance at December 31225,792 148,762 126,955 
Proved developed reserves:  
Balance at January 1141,489 100,945 106,879 
Balance at December 31169,781 141,489 100,945 
Proved undeveloped reserves:
Balance at January 17,273 26,010 55,516 
Balance at December 3156,011 7,273 26,010 
 Years Ended December 31,
 202120202019
 (Mbbl)
Oil   
Proved developed and undeveloped reserves:   
Balance at January 17,417 5,077 6,159 
Revision of previous estimates2,249 250 (428)
Purchase of oil in place— 2,660 — 
Sale of oil in place— — — 
Extensions, discoveries and other additions5,805 234 168 
Production(1,625)(804)(822)
Balance at December 3113,846 7,417 5,077 
Proved developed reserves:   
Balance at January 17,016 4,466 3,489 
Balance at December 317,981 7,016 4,466 
Proved undeveloped reserves:
Balance at January 1401 611 2,670 
Balance at December 315,865 401 611 
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.

The change in reserves during the year ended December 31, 2019 resulted from the following:

•Conversions of 2,646 Bcfe of proved undeveloped reserves to proved developed reserves.
•Extensions, discoveries and other additions of 2,068 Bcfe, which exceeded 2019 production of 1,508 Bcfe. Extensions, discoveries and other additions included an increase of 1,796 Bcfe from proved undeveloped additions associated with acreage that was previously unproved, but became proved due to 2019 reserve development that expanded the number of the Company's technically proven locations, implementation of, and alignment with, the Company's combo-development strategy and revisions to the Company's five-year drilling plan; 156 Bcfe from converting unproved reserves to proved developed reserves; and 116 Bcfe from extension of proved undeveloped reserves lateral lengths.
•Negative revisions of 4,508 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 implementation of the Company's combo-development strategy, which has refocused operations in the Company's core assets and driven execution of new development sequencing processes that emphasize productivity. While these efforts are expected to result in decreased well costs, they negatively impact proved undeveloped reserves as a result of (i) derecognizing previously-recorded proved undeveloped reserves that are now outside the Company's substantially revised five-year capital allocation program for purposes of the Company's reserves calculations and (ii) executing new development sequencing processes that will result in increased probable-to-proved developed conversion.
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,
 202120202019
 (Thousands)
Future cash inflows (a)$70,844,136 $27,976,557 $42,499,686 
Future production costs (b)(20,961,576)(16,344,965)(19,114,076)
Future development costs(2,882,921)(2,268,109)(2,617,731)
Future income tax expenses(10,433,091)(1,820,341)(3,013,667)
Future net cash flow36,566,548 7,543,142 17,754,212 
10% annual discount for estimated timing of cash flows(19,285,424)(4,176,684)(9,261,539)
Standardized measure of discounted future net cash flows$17,281,124 $3,366,458 $8,492,673 

(a)The majority of the Company's production is sold through liquid trading points on interstate pipelines.

For 2021, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $66.55 per Bbl for West Texas Intermediate (WTI) less regional adjustments of $14.98 per Bbl, or $51.57 per Bbl, and $3.598 per MMBtu for NYMEX less regional adjustments of $1.04 per MMBtu, or $2.694 per Mcf. Regional adjustments were calculated using historical average realized prices received in the Appalachian Basin. For 2021, NGLs pricing 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, resulted in a price of $29.95 per Bbl.

For 2020, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $39.54 per Bbl for WTI less regional adjustments of $18.60 per Bbl, or $20.94 per Bbl, and $1.985 per MMBtu for NYMEX less regional adjustments of $0.68 per MMBtu, or $1.38 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2020, NGLs pricing 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, resulted in a price of $11.97 per Bbl.

For 2019, reserves were computed using average first-day-of-the-month closing prices for the prior twelve months of $55.69 per Bbl for WTI less regional adjustments of $14.26 per Bbl, or $41.43 per Bbl, and $2.58 per MMBtu for NYMEX less regional adjustments of $0.29 per MMBtu, or $2.41 per Mcf. Regional adjustments were calculated using historical average realized prices received by the Company in the Appalachian Basin. For 2019, NGLs pricing 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, resulted in a price of $16.81 per Bbl.

(b)Includes approximately $1,937 million, $1,554 million and $1,186 million for future plugging and abandonment costs as of December 31, 2021, 2020 and 2019, 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, 2021 discounted future net cash flows before income taxes of the Company's proved reserves of approximately $1,125 million, $430 million and $76 million, respectively.
The following table summarizes the changes in the standardized measure of discounted future net cash flows.    
Years Ended December 31,
 202120202019
 (Thousands)
Net sales and transfers of natural gas and oil produced$(4,636,576)$(784,163)$(1,884,877)
Net changes in prices, production and development costs17,290,913 (6,761,447)(3,502,434)
Extensions, discoveries and improved recovery, net of related costs46,078 714,808 870,504 
Development costs incurred764,002 797,796 1,002,389 
Net purchase of minerals in place3,491,441 350,075 — 
Net sale of minerals in place— (226,497)— 
Revisions of previous quantity estimates184,552 (324,415)(2,080,040)
Accretion of discount336,646 849,267 900,004 
Net change in income taxes(3,614,029)152,978 1,444,368 
Timing and other51,639 105,383 130,861 
Net increase (decrease)13,914,666 (5,126,215)(3,119,225)
Balance at January 13,366,458 8,492,673 11,611,898 
Balance at December 31$17,281,124 $3,366,458 $8,492,673