Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

v3.22.0.1
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