Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

v3.24.0.1
Supplemental Information on Oil and Natural Gas Properties (Unaudited)
 12 Months Ended
Dec. 31, 2023
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 2023 2022 2021
Oil (MBbls)
Beginning of period 275,609  290,296  289,487 
Extensions and discoveries 40,684  41,064  22,520 
Revisions to previous estimates (28,278) (31,163) (10,514)
Purchase of reserves in place 38,731  —  35,045 
Sales of reserves in place (47,336) (949) (24,019)
Removed for five-year rule (18,259) —  — 
Production (21,891) (23,639) (22,223)
End of period 239,260  275,609  290,296 
Natural Gas (MMcf)
Beginning of period 592,843  577,327  541,598 
Extensions and discoveries 75,616  75,801  37,896 
Revisions to previous estimates 24,206  (11,155) (3,389)
Purchase of reserves in place 42,802  —  73,445 
Sale of reserves in place (53,317) (7,503) (34,837)
Removed for five-year rule (74,548) —  — 
Production (46,109) (41,627) (37,386)
End of period 561,493  592,843  577,327 
NGLs (MBbls)
Beginning of period 105,109  98,104  96,126 
Extensions and discoveries 14,718  14,264  7,345 
Revisions to previous estimates 317  1,376  (3,103)
Purchase of reserves in place 9,487  —  10,366 
Sale of reserves in place (9,537) (1,159) (6,191)
Removed for five-year rule (11,415) —  — 
Production (8,011) (7,476) (6,439)
End of period 100,668  105,109  98,104 
Total (MBoe)
Beginning of period 479,525  484,621  475,879 
Extensions and discoveries 68,005  67,961  36,180 
Revisions to previous estimates (23,927) (31,645) (14,181)
Purchase of reserves in place 55,352  —  57,652 
Sale of reserves in place (65,759) (3,359) (36,015)
Removed for five-year rule (42,099) —  — 
Production (37,587) (38,053) (34,894)
End of period 433,510  479,525  484,621 
Years Ended December 31,
Proved developed reserves 2023 2022 2021
Oil (MBbls)
Beginning of period 170,866  162,886  128,923 
End of period 149,898  170,866  162,886 
Natural gas (MMcf)
Beginning of period 351,278  332,266  238,119 
End of period 376,070  351,278  332,266 
NGLs (MBbls)
Beginning of period 63,788  55,720  43,315 
End of period 65,891  63,788  55,720 
Total proved developed reserves (MBoe)
Beginning of period 293,200  273,983  211,925 
End of period 278,467  293,200  273,983 
Proved undeveloped reserves
Oil (MBbls)
Beginning of period 104,743  127,410  160,564 
End of period 89,362  104,743  127,410 
Natural gas (MMcf)
Beginning of period 241,565  245,061  303,479 
End of period 185,423  241,565  245,061 
NGLs (MBbls)
Beginning of period 41,321  42,384  52,811 
End of period 34,777  41,321  42,384 
Total proved undeveloped reserves (MBoe)
Beginning of period 186,325  210,638  263,954 
End of period 155,043  186,325  210,638 
Total proved reserves
  Oil (MBbls)
Beginning of period 275,609  290,296  289,487 
End of period 239,260  275,609  290,296 
Natural gas (MMcf)
Beginning of period 592,843  577,327  541,598 
End of period 561,493  592,843  577,327 
NGLs (MBbls)
Beginning of period 105,109  98,104  96,126 
End of period 100,668  105,109  98,104 
Total proved reserves (MBoe)
Beginning of period 479,525  484,621  475,879 
End of period 433,510  479,525  484,621 
Total Proved Reserves
For the year ended December 31, 2023, the Company’s net decrease in proved reserves of 46.0 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 2.5 MMBoe were proved developed reserves;
•Decrease of 23.9 MMBoe for revisions of previous estimates that were primarily comprised of:
◦10.8 MMBoe reduction from the removal of PUD locations due to revised development spacing and changes in lateral lengths, primarily in the Company’s Delaware West operating area, as it focuses on the ongoing optimization of the value of the reservoir system through co-development of multiple target zones within the system utilizing larger scale projects and extended lateral lengths;
◦10.7 MMBoe reduction primarily due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 18% as compared to December 31, 2022; and
◦2.4 MMBoe reduction primarily due to higher operating costs as well as lower than expected recoveries from wells turned to production primarily in the western portion of our Permian acreage during 2023.
•Increase of 55.4 MMBoe for purchase of reserves in place associated with the Percussion Acquisition;
•Decrease of 65.8 MMBoe for sales of reserves in place primarily associated with the Eagle Ford Divestiture;
•Decrease of 42.1 MMBoe reduction due to PUD locations that were reclassified to unproved reserve categories as the Company adjusted its future Permian Basin development and capital allocation plans following the Eagle Ford Divestiture and the concurrent Percussion Acquisition, resulting in previously scheduled PUDs, primarily in the Delaware West operating area that is more weighted to natural gas volumes, now forecast to be developed outside of the five-year period from initial booking; and
•Decrease of 37.6 MMBoe for production.
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 we continue to refine our future development plans for the Permian, including increased application of our “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, we believe the model contributes to more consistent capital efficiency of our well inventory over time and our broader Permian development program is now being targeted for larger project sizes, accompanied by longer associated cycle times, based on our 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.
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,
2023 2022
Oil and natural gas properties: (In thousands)
   Proved properties $9,657,105  $9,268,135 
   Unproved properties 1,063,033  1,225,768 
Total oil and natural gas properties 10,720,138  10,493,903 
   Accumulated depreciation, depletion, amortization and impairment (4,570,132) (4,416,606)
Total oil and natural gas properties capitalized $6,150,006  $6,077,297 
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
Years Ended December 31,
2023 2022 2021
Acquisition costs: (In thousands)
   Proved properties $503,433  $—  $677,250 
   Unproved properties 78,144  32,548  301,404 
Development costs 872,808  742,991  396,181 
Exploration costs 113,782  133,080  137,989 
   Total costs incurred $1,568,167  $908,619  $1,512,824 
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2023. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.
Years Ended December 31,
2023 2022 2021
Oil ($/Bbl) $78.17  $95.02  $65.44 
Natural gas ($/Mcf) $1.53  $5.75  $3.31 
NGLs ($/Bbl) $22.27  $36.40  $29.19 
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,
2023 2022 2021
(In thousands)
Future cash inflows $21,804,152  $33,424,190  $23,775,358 
Future costs
Production (8,850,777) (10,702,897) (8,038,362)
Development and net abandonment (1,943,594) (2,326,789) (1,927,789)
Future net inflows before income taxes 11,009,781  20,394,504  13,809,207 
Future income taxes (936,057) (3,000,300) (1,481,005)
Future net cash flows 10,073,724  17,394,204  12,328,202 
10% discount factor (4,639,540) (8,390,068) (6,077,447)
Standardized measure of discounted future net cash flows $5,434,184  $9,004,136  $6,250,755 
Changes in Standardized Measure
For the Year Ended December 31,
2023 2022 2021
(In thousands)
Standardized measure at the beginning of the period $9,004,136  $6,250,755  $2,310,390 
Sales and transfers, net of production costs (1,428,805) (2,208,492) (1,466,413)
Net change in sales and transfer prices, net of production costs (3,387,434) 4,168,425  4,336,078 
Net change due to purchases of in place reserves 868,016  —  797,327 
Net change due to sales of in place reserves (1,724,612) (36,389) (105,376)
Extensions, discoveries, and improved recovery, net of future production and development costs incurred 702,960  1,338,286  583,976 
Changes in future development cost 21,705  (257,344) (81,480)
Previously estimated development costs incurred 570,765  289,207  209,078 
Revisions of quantity estimates (1,217,925) (215,828) (104,572)
Accretion of discount 1,053,483  705,127  234,495 
Net change in income taxes 1,075,309  (730,185) (765,956)
Changes in production rates, timing and other (103,414) (299,426) 303,208 
Aggregate change (3,569,952) 2,753,381  3,940,365 
Standardized measure at the end of period $5,434,184  $9,004,136  $6,250,755