Supplemental Information on Oil and Natural Gas Properties (Unaudited)

12 Months Ended

Dec. 31, 2022

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Estimated Reserves

For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third-party reserve engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.

There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.

Extrapolation of performance history and material balance estimates were utilized by D&M to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production and, to a small extent, horizontal PDP and PUD categories.

The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States:

	Years Ended December 31,
Proved reserves	2022	2021	2020
Oil (MBbls)
Beginning of period	290,296	289,487	346,361
Extensions and discoveries	41,064	22,520	25,678
Revisions to previous estimates	(31,163)	(10,514)	(49,336)
Purchase of reserves in place	—	35,045	—
Sales of reserves in place	(949)	(24,019)	(9,673)
Production	(23,639)	(22,223)	(23,543)
End of period	275,609	290,296	289,487
Natural Gas (MMcf)
Beginning of period	577,327	541,598	757,134
Extensions and discoveries	75,801	37,896	44,282
Revisions to previous estimates	(11,155)	(3,389)	(198,628)
Purchase of reserves in place	—	73,445	—
Sale of reserves in place	(7,503)	(34,837)	(20,389)
Production	(41,627)	(37,386)	(40,801)
End of period	592,843	577,327	541,598
NGLs (MBbls)
Beginning of period	98,104	96,126	67,462
Extensions and discoveries	14,264	7,345	8,349
Revisions to previous estimates	1,376	(3,103)	30,214
Purchase of reserves in place	—	10,366	—
Sale of reserves in place	(1,159)	(6,191)	(3,049)
Production	(7,476)	(6,439)	(6,850)
End of period	105,109	98,104	96,126
Total (MBoe)
Beginning of period	484,621	475,879	540,012
Extensions and discoveries	67,961	36,180	41,407
Revisions to previous estimates	(31,645)	(14,181)	(52,227)
Purchase of reserves in place	—	57,652	—
Sale of reserves in place	(3,359)	(36,015)	(16,120)
Production	(38,053)	(34,894)	(37,193)
End of period	479,525	484,621	475,879

	Years Ended December 31,
Proved developed reserves	2022	2021	2020
Oil (MBbls)
Beginning of period	162,886	128,923	152,687
End of period	170,866	162,886	128,923
Natural gas (MMcf)
Beginning of period	332,266	238,119	320,676
End of period	351,278	332,266	238,119
NGLs (MBbls)
Beginning of period	55,720	43,315	24,844
End of period	63,788	55,720	43,315
Total proved developed reserves (MBoe)
Beginning of period	273,983	211,925	230,977
End of period	293,200	273,983	211,925
Proved undeveloped reserves
Oil (MBbls)
Beginning of period	127,410	160,564	193,674
End of period	104,743	127,410	160,564
Natural gas (MMcf)
Beginning of period	245,061	303,479	436,458
End of period	241,565	245,061	303,479
NGLs (MBbls)
Beginning of period	42,384	52,811	42,618
End of period	41,321	42,384	52,811
Total proved undeveloped reserves (MBoe)
Beginning of period	210,638	263,954	309,035
End of period	186,325	210,638	263,954
Total proved reserves
Oil (MBbls)
Beginning of period	290,296	289,487	346,361
End of period	275,609	290,296	289,487
Natural gas (MMcf)
Beginning of period	577,327	541,598	757,134
End of period	592,843	577,327	541,598
NGLs (MBbls)
Beginning of period	98,104	96,126	67,462
End of period	105,109	98,104	96,126
Total proved reserves (MBoe)
Beginning of period	484,621	475,879	540,012
End of period	479,525	484,621	475,879

Total Proved Reserves

For the year ended December 31, 2022, the Company’s net decrease in proved reserves of 5.1 MMBoe was primarily due to the following:

•Increase of 68.0 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 8.7 MMBoe were proved developed reserves;

•Decrease of 31.6 MMBoe for revisions of previous estimates that were primarily comprised of:

◦44.4 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories, all of which were in the Permian. Certain PUDs were moved outside of their five-year development window as the Company continues to refine its future development plans for the Permian, including increased application of its “Life of Field” co-development model. This development model focuses on optimization of the value of a reservoir system through concurrent, co-development of multiple target zones within the system utilizing larger scale projects. As a result, the Company believes the model contributes to more consistent capital efficiency of its well inventory over time and its broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on its testing and delineation efforts during 2022;

◦13.1 MMBoe reduction primarily due to higher operating costs; offset by

◦13.7 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 45% as compared to December 31, 2021;

◦12.2 MMBoe increase primarily due to better results than previously forecasted on certain wells turned to production during 2022 in both the Permian and Eagle Ford.

•Decrease of 3.4 MMBoe for sales of reserves in place primarily associated with the divestitures of non-core assets primarily in the Western Delaware Basin; and

•Decrease of 38.1 MMBoe for production.

For the year ended December 31, 2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following:

•Increase of 36.2 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 10.1 MMBoe were proved developed reserves;

•Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of:

◦27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75% as compared to December 31, 2020; offset by

◦29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation as well as changes in its development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window;

◦13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts.

•Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition;

•Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and

•Decrease of 34.9 MMBoe for production.

For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following:

•Increase of 41.4 MMBoe through extensions and discoveries through the Company’s development efforts in its operating areas, of which 11.7 MMBoe were proved developed reserves;

•Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of:

◦26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31% as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with

proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil;

◦24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts;

◦24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation;

◦14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas;

◦7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo;

•Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and

•Decrease of 37.2 MMBoe for production.

Capitalized Costs

Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:

	As of December 31,
	2022	2021
Oil and natural gas properties:	(In thousands)
Evaluated properties	$10,367,478	$9,238,823
Unevaluated properties	1,711,306	1,812,827
Total oil and natural gas properties	12,078,784	11,051,650
Accumulated depreciation, depletion, amortization and impairments	(6,343,875)	(5,886,002)
Total oil and natural gas properties, net	$5,734,909	$5,165,648

Costs Incurred

Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:

	Years Ended December 31,
	2022	2021	2020
Acquisition costs:	(In thousands)
Evaluated properties	$—	$677,250	$—
Unevaluated properties	32,548	301,404	30,696
Development costs	742,991	396,181	379,900
Exploration costs	133,080	137,989	122,865
Total costs incurred	$908,619	$1,512,824	$533,461

Standardized Measure

The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2022. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each

month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.

	Years Ended December 31,
	2022	2021	2020
Oil ($/Bbl)	$95.02	$65.44	$37.44
Natural gas ($/Mcf)	$5.75	$3.31	$1.02
NGLs ($/Bbl)	$36.40	$29.19	$11.10

Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.

	Standardized Measure
	For the Year Ended December 31,
	2022	2021	2020
	(In thousands)
Future cash inflows	$33,424,190	$23,775,358	$12,458,033
Future costs
Production	(10,702,897)	(8,038,362)	(5,433,496)
Development and net abandonment	(2,326,789)	(1,927,789)	(2,204,301)
Future net inflows before income taxes	20,394,504	13,809,207	4,820,236
Future income taxes	(3,000,300)	(1,481,005)	(65,405)
Future net cash flows	17,394,204	12,328,202	4,754,831
10% discount factor	(8,390,068)	(6,077,447)	(2,444,441)
Standardized measure of discounted future net cash flows	$9,004,136	$6,250,755	$2,310,390

	Changes in Standardized Measure
	For the Year Ended December 31,
	2022	2021	2020
	(In thousands)
Standardized measure at the beginning of the period	$6,250,755	$2,310,390	$4,951,026
Sales and transfers, net of production costs	(2,208,492)	(1,466,413)	(649,781)
Net change in sales and transfer prices, net of production costs	4,168,425	4,336,078	(2,719,579)
Net change due to purchases of in place reserves	—	797,327	—
Net change due to sales of in place reserves	(36,389)	(105,376)	(202,928)
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	1,338,286	583,976	250,759
Changes in future development cost	(257,344)	(81,480)	361,008
Previously estimated development costs incurred	289,207	209,078	318,470
Revisions of quantity estimates	(215,828)	(104,572)	(671,800)
Accretion of discount	705,127	234,495	536,958
Net change in income taxes	(730,185)	(765,956)	383,999
Changes in production rates, timing and other	(299,426)	303,208	(247,742)
Aggregate change	2,753,381	3,940,365	(2,640,636)
Standardized measure at the end of period	$9,004,136	$6,250,755	$2,310,390