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Supplemental Information on Oil and Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2023

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

Supplemental Information on Oil and Gas Producing Activities (Unaudited)

(19) Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The tables below set forth supplemental information regarding the Company’s consolidated oil and gas producing activities (in thousands). The amounts shown include the Company’s net working interests in all of its oil and gas properties.

(a)	Capitalized Costs Relating to Oil and Gas Producing Activities


	Year Ended December 31,
	2022		2023
Proved properties	$	13,234,777		13,908,804
Unproved properties		997,715		974,642
Total oil and gas properties		14,232,492		14,883,446
Accumulated depletion		(4,624,674)		(4,996,691)
Net capitalized costs	$	9,607,818		9,886,755

(b)	Costs Incurred in Certain Oil and Gas Activities


	Year Ended December 31,
	2021		2022		2023
Acquisition costs:
Unproved property	$	79,138		149,009		151,135
Development costs		581,352		775,106		956,267
Exploration costs		19,822		5,543		8,079
Total costs incurred	$	680,312		929,658		1,115,481

(c)Results of Operations for Oil and Gas Producing Activities


	Year Ended December 31,
	2021		2022		2023
Revenues	$	5,790,759		8,294,749		4,276,445
Operating expenses:
Production expenses		2,793,877		2,992,381		2,919,654
Exploration expenses		1,164		3,651		2,691
Depletion		735,687		737,504		682,109
Impairment of unproved properties		90,523		98,324		51,302
Results of operations before income tax expense		2,169,508		4,462,889		620,689
Income tax expense		(520,168)		(959,477)		(135,063)
Results of operations	$	1,649,340		3,503,412		485,626

(d)	Oil and Gas Reserves

Net proved oil and gas reserves for the years ended December 31, 2021, 2022 and 2023 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (“D&M”) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States.

Proved reserves are the estimated quantities of oil, condensate, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months.

Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital, future commodity prices, net cash provided by operating activities, future drilling and completion costs, and other economic factors.

The tables below set forth the changes in quantities of proved reserves and net quantities of proved developed and proved undeveloped reserves for the periods indicated. This information includes the Company’s royalty and net working interest share of the reserves in oil and gas properties.


			Oil and
	Natural Gas	NGLs	Condensate	Equivalents
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
Proved reserves:
December 31, 2020 ⁽¹⁾	10,025	1,236	33	17,635
Revisions	993	77	6	1,486
Extensions, discoveries and other additions	349	18	2	472
Production	(826)	(58)	(4)	(1,194)
Sales	(337)	(54)	(1)	(670)
December 31, 2021 ⁽¹⁾	10,204	1,219	36	17,729
Revisions	427	32	(4)	596
Extensions, discoveries and other additions	437	25	2	604
Production	(798)	(59)	(3)	(1,170)
December 31, 2022 ⁽¹⁾	10,270	1,217	31	17,759
Revisions	863	54	—	1,187
Extensions, discoveries and other additions	296	18	2	413
Production	(815)	(67)	(4)	(1,238)
December 31, 2023 ⁽¹⁾	10,614	1,222	29	18,121

(1)

Proved reserves for the noncontrolling interests in Martica as of December 31, 2021 were 167 Bcfe, which consisted of 101 Bcf of natural gas, 11 MMBbl of NGLs and 0.4 MMBbl of oil and condensate. Proved reserves for the noncontrolling interests in Martica as of December 31, 2022 were 92 Bcfe, which consisted of 71 Bcf of natural gas, 3 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate.


			Oil and
	Natural Gas	NGLs	Condensate	Equivalents
	(Bcf)	(MMBbl)	(MMBbl)	(Bcfe)
Proved developed reserves:
December 31, 2021 ⁽¹⁾	7,395	876	17	12,753
December 31, 2022 ⁽¹⁾	7,699	930	16	13,373
December 31, 2023 ⁽¹⁾	7,912	963	15	13,783
Proved undeveloped reserves:
December 31, 2021 ⁽²⁾	2,809	343	19	4,976
December 31, 2022 ⁽²⁾	2,571	287	15	4,386
December 31, 2023 ⁽²⁾	2,702	259	14	4,338

(1)

Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2021 were 133 Bcfe, which consisted of 78 Bcf of natural gas, 9 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2022 were 91 Bcfe, which consisted of 70 Bcf of natural gas, 3 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved developed reserves for the noncontrolling interests in Martica as of December 31, 2023 were 75 Bcfe, which consisted of 58 Bcf of natural gas, 3 MMBbl of NGLs and 0.1 MMBbl of oil and condensate.

(2)

Proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2021 were 34 Bcfe, which consisted of 23 Bcf of natural gas, 2 MMBbl of NGLs and 0.2 MMBbl of oil and condensate. Proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2022 were 1 Bcfe, which consisted entirely of natural gas. There were no proved undeveloped reserves for the noncontrolling interests in Martica as of December 31, 2023.

Significant changes in proved reserves for the years ended December 31, 2021, 2022 and 2023 include the following:

2021 Proved Reserve Changes

●

Extensions, discoveries, and other additions of 472 Bcfe resulted from delineation and development drilling in the Appalachian Basin.

●

Net upward revisions of 1,486 Bcfe include:

o

Net upward revision of 651 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 1,475 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, and downward revisions of 824 Bcfe for locations that were not developed within five years of initial booking as proved reserves.

o

Net upward performance revisions of 565 Bcfe.

o

Upward revisions of 149 Bcfe due to increases in prices for natural gas, NGLs and oil.

o

Upward revisions of 121 Bcfe are due to an increase in the Company’s assumed future ethane recovery.

●

Sales of reserves of 670 Bcfe related to the drilling partnership.

2022 Proved Reserve Changes

●

Extensions, discoveries, and other additions of 604 Bcfe resulted from delineation and development drilling in the Appalachian Basin.

●

Net upward revisions of 596 Bcfe include:

o

Net upward revisions of previous estimates of 414 Bcfe primarily due to changes in ownership interests.

o

Net upward revision of 92 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 692 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, and downward revisions of 600 Bcfe for locations that were not developed within five years of initial booking as proved reserves.

o

Upward revisions of 88 Bcfe are due to an increase in the Company’s assumed future ethane recovery.

o

Upward revisions of 2 Bcfe due to increases in prices for natural gas, NGLs and oil.

2023 Proved Reserve Changes

●

Extensions, discoveries, and other additions of 413 Bcfe resulted from delineation and development drilling in the Appalachian Basin.

●

Net upward revisions of 1,187 Bcfe include:

o

Net upward revisions of previous estimates of 814 Bcfe includes 846 Bcfe for increases in the Company’s ownership interests, partially offset by downward revisions of 32 Bcfe related to changes in the Company’s reserve forecast and operation cost estimates.

o

Net upward revision of 454 Bcfe related to optimization to the Company’s five-year development plan. This figure includes upward revisions of 698 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to the Company’s five-year development plan, and downward revisions of 244 Bcfe for locations that were not developed within five years of initial booking as proved reserves.

o

Downward revisions of 81 Bcfe due to decreases in prices for natural gas, NGLs and oil.

(e)	Standardized Measure of Discounted Future Net Cash Flow

The standardized measure relating to proved oil and reserves was prepared in accordance with the provisions of ASC 932. Future cash inflows were computed by applying historical 12 month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s

proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of available NOL carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.

The following table sets forth the Standardized Measure of the discounted future net cash flows attributable to the Company’s proved reserves (in millions):


	Year Ended December 31,
	2021		2022		2023
Future cash inflows	$	74,622		109,052		58,061
Future production costs		(34,665)		(39,378)		(41,887)
Future development costs		(1,704)		(2,073)		(2,027)
Future net cash flows before income tax		38,253		67,601		14,147
Future income tax expense		(7,813)		(13,692)		(2,178)
Future net cash flows		30,440		53,909		11,969
10% annual discount for estimated timing of cash flows		(17,007)		(30,345)		(6,874)
Standardized measure of discounted future net cash flows ⁽¹⁾	$	13,433		23,564		5,095

(1)	The standardized measure of discounted future net cash flows for the noncontrolling interests in Martica were $501 million, $458 million and $170 million for the years ended December 31, 2021, 2022 and 2023, respectively.

The Company used the following 12-month weighted average prices to estimate its total equivalent reserves (per Mcfe):


	Year Ended December 31,
	2021		2022		2023
12-month weighted average price	$	4.21		6.14		3.20

(f)	Changes in Standardized Measure of Discounted Future Net Cash Flow

The changes in the Standardized Measure relating to proved oil and natural gas reserves, which were prepared in accordance with the provisions of ASC 932, are as follows (in millions):


	Year Ended December 31,
	2021		2022		2023
Sales of oil and gas, net of productions costs	$	(2,917)		(5,302)		(1,357)
Net changes in prices and production costs ⁽¹⁾		14,099		13,793		(25,672)
Development costs incurred during the period		454		448		637
Net changes in future development costs		(117)		(289)		(96)
Extensions, discoveries and other additions		504		1,068		69
Divestitures		(125)		—		—
Revisions of previous quantity estimates		2,543		1,475		190
Accretion of discount		121		1,655		2,947
Net change in income taxes		(3,115)		(2,787)		5,069
Changes in timing and other		776		70		(256)
Net increase (decrease)		12,223		10,131		(18,469)
Beginning of year		1,210		13,433		23,564
End of year ⁽²⁾	$	13,433		23,564		5,095

(1)	The net changes in prices and production costs are calculated prior to the consideration of future income tax expense. The Standardized Measure included future income tax expense of $7.8 billion, $13.7 billion and $2.2 billion for the years ended December 31, 2021, 2022 and 2023, respectively.

(2)	The standardized measure for the noncontrolling interests in Martica were $501 million, $458 million and $170 million for the years ended December 31, 2021, 2022 and 2023, respectively.