Supplemental Information on Oil and Natural Gas Properties (Unaudited)

12 Months Ended

Dec. 31, 2021

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, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. 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 the Company’s both D&M and Ryder Scott 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	2021	2020	2019
Oil (MBbls)
Beginning of period	289,487	346,361	180,097
Purchase of reserves in place	35,045	—	183,382
Sales of reserves in place	(24,019)	(9,673)	(17,980)
Extensions and discoveries	22,520	25,678	45,663
Revisions to previous estimates	(10,514)	(49,336)	(33,136)
Production	(22,223)	(23,543)	(11,665)
End of period	290,296	289,487	346,361
Natural Gas (MMcf)
Beginning of period	541,598	757,134	350,466
Purchase of reserves in place	73,445	—	455,158
Sale of reserves in place	(34,837)	(20,389)	(86,856)
Extensions and discoveries	37,896	44,282	82,566
Revisions to previous estimates	(3,389)	(198,628)	(24,482)
Production	(37,386)	(40,801)	(19,718)
End of period	577,327	541,598	757,134
NGLs (MBbls)
Beginning of period	96,126	67,462	—
Purchase of reserves in place	10,366	—	67,597
Sale of reserves in place	(6,191)	(3,049)	—
Extensions and discoveries	7,345	8,349	—
Revisions to previous estimates	(3,103)	30,214	—
Production	(6,439)	(6,850)	(135)
End of period	98,104	96,126	67,462
Total (MBoe)
Beginning of period	475,879	540,012	238,508
Purchase of reserves in place	57,652	—	326,838
Sale of reserves in place	(36,015)	(16,120)	(32,456)
Extensions and discoveries	36,180	41,407	59,424
Revisions to previous estimates	(14,181)	(52,227)	(37,216)
Production	(34,894)	(37,193)	(15,086)
End of period	484,621	475,879	540,012

	Years Ended December 31,
Proved developed reserves	2021	2020	2019
Oil (MBbls)
Beginning of period	128,923	152,687	92,202
End of period	162,886	128,923	152,687
Natural gas (MMcf)
Beginning of period	238,119	320,676	218,417
End of period	332,266	238,119	320,676
NGLs (MBbls)
Beginning of period	43,315	24,844	—
End of period	55,720	43,315	24,844
Total proved developed reserves (MBoe)
Beginning of period	211,925	230,977	128,605
End of period	273,983	211,925	230,977
Proved undeveloped reserves
Oil (MBbls)
Beginning of period	160,564	193,674	87,895
End of period	127,410	160,564	193,674
Natural gas (MMcf)
Beginning of period	303,479	436,458	132,049
End of period	245,061	303,479	436,458
NGLs (MBbls)
Beginning of period	52,811	42,618	—
End of period	42,384	52,811	42,618
Total proved undeveloped reserves (MBoe)
Beginning of period	263,954	309,035	109,903
End of period	210,638	263,954	309,035
Total proved reserves
Oil (MBbls)
Beginning of period	289,487	346,361	180,097
End of period	290,296	289,487	346,361
Natural gas (MMcf)
Beginning of period	541,598	757,134	350,466
End of period	577,327	541,598	757,134
NGLs (MBbls)
Beginning of period	96,126	67,462	—
End of period	98,104	96,126	67,462
Total proved reserves (MBoe)
Beginning of period	475,879	540,012	238,508
End of period	484,621	475,879	540,012

Total Proved Reserves

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 our development efforts in our 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 we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our 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 our development efforts in our 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.

For the year ended December 31, 2019, the Company’s net increase in proved reserves of 301.5 MMBoe was primarily due to the following:

•Increase of 326.8 MMBoe for purchases of reserves in place related to the acquisition of Carrizo Oil & Gas, Inc. in late 2019;

•Increase of 59.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed reserves;

•Decrease of 32.5 MMBoe as a result of sales of reserves in place, primarily associated with our Ranger Divestiture which totaled 27.1 MMBoe;

•Decrease of 37.2 MMBoe for revisions of previous estimates that were primarily comprised of:

◦21.7 MMBoe reduction due to the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates, primarily in the Midland Basin, as the Company advances larger scale development concepts across its multi-zone inventory;

◦9.8 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans, primarily related to certain fields within the Company’s Delaware Basin acreage, that were moved outside of the five-year development window primarily driven by the acquisition of Carrizo Oil & Gas, Inc. in December 2019, which afforded us the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency through larger scale development concepts as well as preserve our co-development philosophy to optimize resource capture from multiple zones;

◦5.7 MMBoe reduction due to pricing; and

•Decrease of 15.1 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,
	2021	2020
Oil and natural gas properties:	(In thousands)
Evaluated properties	$9,238,823	$7,894,513
Unevaluated properties	1,812,827	1,733,250
Total oil and natural gas properties	11,051,650	9,627,763
Accumulated depreciation, depletion, amortization and impairment	(5,886,002)	(5,538,803)
Total oil and natural gas properties capitalized	$5,165,648	$4,088,960

Costs Incurred

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

	Years Ended December 31,
	2021	2020	2019
Acquisition costs:	(In thousands)
Evaluated properties	$677,250	$—	$49,572
Unevaluated properties	301,404	30,696	107,347
Development costs	396,181	379,900	189,259
Exploration costs	137,989	122,865	309,013
Total costs incurred	$1,512,824	$533,461	$655,191

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, 2021. 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,
	2021	2020	2019
Oil ($/Bbl)	$65.44	$37.44	$53.90
Natural gas ($/Mcf)	$3.31	$1.02	$1.55
NGLs ($/Bbl)	$29.19	$11.10	$15.58

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,
	2021	2020	2019
	(In thousands)
Future cash inflows	$23,775,358	$12,458,033	$20,891,469
Future costs
Production	(8,038,362)	(5,433,496)	(6,717,088)
Development and net abandonment	(1,927,789)	(2,204,301)	(3,058,861)
Future net inflows before income taxes	13,809,207	4,820,236	11,115,520
Future income taxes	(1,481,005)	(65,405)	(941,768)
Future net cash flows	12,328,202	4,754,831	10,173,752
10% discount factor	(6,077,447)	(2,444,441)	(5,222,726)
Standardized measure of discounted future net cash flows	$6,250,755	$2,310,390	$4,951,026

	Changes in Standardized Measure
	For the Year Ended December 31,
	2021	2020	2019
	(In thousands)
Standardized measure at the beginning of the period	$2,310,390	$4,951,026	$2,941,293
Sales and transfers, net of production costs	(1,466,413)	(649,781)	(579,744)
Net change in sales and transfer prices, net of production costs	4,336,078	(2,719,579)	(387,970)
Net change due to purchases of in place reserves	797,327	—	2,975,296
Net change due to sales of in place reserves	(105,376)	(202,928)	(303,526)
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	583,976	250,759	607,146
Changes in future development cost	(81,480)	361,008	205,398
Previously estimated development costs incurred	209,078	318,470	134,037
Revisions of quantity estimates	(104,572)	(671,800)	(420,488)
Accretion of discount	234,495	536,958	314,921
Net change in income taxes	(765,956)	383,999	(210,641)
Changes in production rates, timing and other	303,208	(247,742)	(324,696)
Aggregate change	3,940,365	(2,640,636)	2,009,733
Standardized measure at the end of period	$6,250,755	$2,310,390	$4,951,026