Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

v3.22.4
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