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SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
 12 Months Ended
Dec. 31, 2021
Extractive Industries [Abstract]  
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
Oil and Gas Reserves
Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” natural gas and crude oil reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.
Estimates of total proved reserves at December 31, 2021, 2020 and 2019 were based on studies performed by the Company's petroleum engineering staff. The estimates were computed using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the respective year. Estimates with respect to the Company’s Marcellus Shale reserves were audited by Miller and Lents, Ltd. and estimates of the net reserves representing greater than 80 percent of the total future net revenue discounted at 10 percent attributable to the Company’s remaining reserves were subject to an independent evaluation performed by DeGolyer and MacNaughton. Miller and Lents and DeGolyer and MacNaughton each indicated that based on their investigations and subject to the limitations described in their audit letters, they believe the Company’s estimates were, in the aggregate, reasonable.
No major discovery or other favorable or unfavorable event after December 31, 2021, is believed to have caused a material change in the estimates of proved or proved developed reserves as of that date.
The following tables illustrate the Company's net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated, as estimated by the Company's engineering staff. All reserves are located within the continental U.S.
 
Oil (Mbbl)		Natural Gas
(Bcf)
NGLs
(Mbbl)		Total
(MBOE)
December 31, 2018120 11,604 — 1,934,136 
Revision of prior estimates(1)
(48)48 — 7,834 
Extensions, discoveries and other additions(2)
— 2,116 — 352,731 
Production— (865)— (144,229)
Sales of reserves in place(50)— — (50)
December 31, 201922 12,903 — 2,150,422 
Revision of prior estimates(3)
(3)(347)— (57,808)
Extensions, discoveries and other additions(2)
— 1,974 — 328,976 
Production(4)(858)— (142,954)
December 31, 202015 13,672 — 2,278,636 
Revision of prior estimates(4)
10,837 (538)16,797 (61,967)
Extensions, discoveries and other additions(2)
2,633 973 6,100 170,988 
Production(8,150)(911)(7,104)(167,113)
Purchases of reserves in place(5)
184,094 1,699 204,822 672,038 
December 31, 2021189,429 14,895 220,615 2,892,582 
Proved Developed Reserves    
December 31, 2018107 7,402 — 1,233,790 
December 31, 201922 8,056 — 1,342,589 
December 31, 202015 8,608 — 1,434,714 
December 31, 2021153,010 10,691 193,598 2,128,439 
Proved Undeveloped Reserves   
December 31, 201813 4,202 — 700,346 
December 31, 2019— 4,847 — 807,833 
December 31, 2020— 5,064 — 843,922 
December 31, 202136,419 4,204 27,017 764,143 
_______________________________________________________________________________
(1)The net upward revision of 8 MMBOE was primarily due to a net upward performance revision of 11 MMBOE, partially offset by a downward revision of 3 MMBOE associated with PUD reclassifications as a result of the five-year limitation. The net upward performance revision of 11 MMBOE was primarily due to an upward revision of 69 MMBOE associated with the Company's PUD reserves due to performance revisions and the drilling of longer lateral length wells, partially offset by a downward performance revision of 58 MMBOE related to certain proved developed producing properties.
(2)Extensions, discoveries and other additions were primarily related to drilling activity in the Dimock field located in northeast Pennsylvania. The Company added 152 MMBOE, 329 MMBOE and 353 MMBOE of proved reserves in this field in 2021, 2020 and 2019, respectively.
(3)The net downward revision of 58 MMBOE was primarily due to a net downward performance revision of 41 MMBOE and a downward revision of 11 MMBOE associated with PUD reclassifications as a result of the five-year limitation. The net downward performance revision of 41 MMBOE was primarily due to a downward performance revision of 61 MMBOE related to certain proved developed producing properties, partially offset by an upward revision of 21 MMBOE associated with the Company’s PUD reserves due to performance revisions and the drilling of longer lateral length wells.
(4)The net downward revision of 62 MMBOE was primarily related to 97 MMBOE downward performance revision coupled with a 6 MMBOE downward revision associated with PUD reclassifications as a result of the 5 year rule
which was partially offset by a 42 MMBOE positive pricing and cost revision. The net downward performance revision of 97 MMBOE, was primarily due to 57 MMBOE performance revision related to certain proved developed reserves and a 40 MMBOE downward performance revision associate with proved undeveloped reserves.
(5)Purchases of reserves in place were primarily related to the acquisition of Cimarex’s oil and gas properties in connection with the Merger. The reserves are primarily related to the Wolfcamp Shale in the Permian Basin and Woodford Shale in the Anadarko Basin.
Capitalized Costs Relating to Oil and Gas Producing Activities
Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization were as follows:
 December 31,
(In millions)202120202019
Aggregate capitalized costs relating to oil and gas producing activities$20,655 $7,154 $6,676 
Aggregate accumulated depreciation, depletion and amortization(3,775)(3,149)(2,861)
Net capitalized costs$16,880 $4,005 $3,815 
Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities
Costs incurred in property acquisition, exploration and development activities were as follows:
 Year Ended December 31,
(In millions)
2021(1)
20202019
Property acquisition costs, proved$7,472 $— $— 
Property acquisition costs, unproved 5,386 6 6 
Exploration costs 18 15 20 
Development costs688 547 761 
Total costs$13,564 $568 $787 
_______________________________________________________________________________
(1)These amounts include the fair value of the proved and unproved properties recorded in the purchase price allocation with respect to the Merger. The purchase was funded through the issuance of the Company’s common stock.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following information has been developed based on natural gas and crude oil reserve and production volumes estimated by the Company's engineering staff. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure of Discounted Future Net Cash Flows (“Standardized Measure”) be viewed as representative of the current value of the Company.
The Company believes that the following factors should be taken into account when reviewing the following information:
•Future costs and selling prices will differ from those required to be used in these calculations.

•Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations.

•Selection of a 10 percent discount rate is arbitrary and may not be a reasonable measure of the relative risk that is part of realizing future net oil and gas revenues.

•Future net revenues may be subject to different rates of income taxation.

Under the Standardized Measure, future cash inflows were estimated by using the 12-month average index price for the respective commodity, calculated as the unweighted arithmetic average for the first day of the month price for each month during the year.
The average prices (adjusted for basis and quality differentials) related to proved reserves are as follows:
 Year Ended December 31,
202120202019
Natural gas$2.93 $1.64 $2.35 
Oil
$65.40 $32.53 $55.80 
NGLs$25.74 $— $— 
In the above table, natural gas prices are stated per Mcf and oil and NGL prices are stated per barrel.
Future cash inflows were reduced by estimated future development and production costs based on year end costs to arrive at net cash flow before tax. Future income tax expense was computed by applying year end statutory tax rates to future pretax net cash flows, less the tax basis of the properties involved and utilization of available tax carryforwards related to oil and gas operations. The applicable accounting standards require the use of a 10 percent discount rate.
Management does not solely use the following information when making investment and operating decisions. These decisions are based on a number of factors, including estimates of proved reserves and varying price and cost assumptions considered more representative of a range of anticipated economic conditions.
Standardized Measure is as follows:
 Year Ended December 31,
(In millions)202120202019
Future cash inflows$60,908 $22,385 $30,302 
Future production costs(18,241)(10,784)(10,039)
Future development costs(1)
(2,449)(1,612)(2,006)
Future income tax expenses(8,535)(2,176)(4,043)
Future net cash flows31,683 7,813 14,214 
10% annual discount for estimated timing of cash flows(18,399)(4,751)(8,353)
Standardized measure of discounted future net cash flows$13,284 $3,062 $5,861 
______________________________________________________________________________
(1)Includes $390 million, $224 million and $213 million in plugging and abandonment costs for the years ended December 31, 2021, 2020 and 2019, respectively.
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following is an analysis of the changes in the Standardized Measure:
 Year Ended December 31,
(In millions)202120202019
Beginning of year$3,062 $5,861 $6,483 
Discoveries and extensions, net of related future costs800 311 1,076 
Net changes in prices and production costs9,573 (4,326)(1,510)
Accretion of discount551 750 813 
Revisions of previous quantity estimates467 (108)28 
Timing and other(161)6 (192)
Changes in estimated future development costs(103)— — 
Development costs incurred497 501 469 
Sales and transfers, net of production costs(2,801)(746)(1,317)
Sales of reserves in place(1)— (1)
Purchases of reserves in place6,477 — — 
Net change in income taxes(5,077)813 12 
End of year$13,284 $3,062 $5,861