Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

v3.20.4
Supplemental Information on Oil and Natural Gas Properties (Unaudited)
12 Months Ended
Dec. 31, 2020
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 nonproducing 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 2020 2019 2018
Oil (MBbls)
Beginning of period 346,361  180,097  107,072 
Purchase of reserves in place —  183,382  30,756 
Sales of reserves in place (9,673) (17,980) — 
Extensions and discoveries 25,678  45,663  67,763 
Revisions to previous estimates (49,336) (33,136) (16,051)
Production (23,543) (11,665) (9,443)
End of period 289,487  346,361  180,097 
Natural Gas (MMcf)
Beginning of period 757,134  350,466  179,410 
Purchase of reserves in place —  455,158  53,563 
Sale of reserves in place (20,389) (86,856) — 
Extensions and discoveries 44,282  82,566  103,149 
Revisions to previous estimates (198,628) (24,482) 29,791 
Production (40,801) (19,718) (15,447)
End of period 541,598  757,134  350,466 
NGLs (MBbls)
Beginning of period 67,462  —  — 
Purchase of reserves in place —  67,597  — 
Sale of reserves in place (3,049) —  — 
Extensions and discoveries 8,349  —  — 
Revisions to previous estimates 30,214  —  — 
Production (6,850) (135) — 
End of period 96,126  67,462  — 
Total (MBoe)
Beginning of period 540,012  238,508  136,974 
Purchase of reserves in place —  326,838  39,683 
Sale of reserves in place (16,120) (32,456) — 
Extensions and discoveries 41,407  59,424  84,955 
Revisions to previous estimates (52,227) (37,216) (11,086)
Production (37,193) (15,086) (12,018)
End of period 475,879  540,012  238,508 
Years Ended December 31,
Proved developed reserves 2020 2019 2018
Oil (MBbls)
Beginning of period 152,687  92,202  51,920 
End of period 128,923  152,687  92,202 
Natural gas (MMcf)
Beginning of period 320,676  218,417  104,389 
End of period 238,119  320,676  218,417 
NGLs (MBbls)
Beginning of period 24,844  —  — 
End of period 43,315  24,844  — 
Total proved developed reserves (MBoe)
Beginning of period 230,977  128,605  69,318 
End of period 211,925  230,977  128,605 
Proved undeveloped reserves
Oil (MBbls)
Beginning of period 193,674  87,895  55,152 
End of period 160,564  193,674  87,895 
Natural gas (MMcf)
Beginning of period 436,458  132,049  75,021 
End of period 303,479  436,458  132,049 
NGLs (MBbls)
Beginning of period 42,618  —  — 
End of period 52,811  42,618  — 
Total proved undeveloped reserves (MBoe)
Beginning of period 309,035  109,903  67,656 
End of period 263,954  309,035  109,903 
Total proved reserves
  Oil (MBbls)
Beginning of period 346,361  180,097  107,072 
End of period 289,487  346,361  180,097 
Natural gas (MMcf)
Beginning of period 757,134  350,466  179,410 
End of period 541,598  757,134  350,466 
NGLs (MBbls)
Beginning of period 67,462  —  — 
End of period 96,126  67,462  — 
Total proved reserves (MBoe)
Beginning of period 540,012  238,508  136,974 
End of period 475,879  540,012  238,508 
Total Proved Reserves
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.
For the year ended December 31, 2018, the Company’s net increase in proved reserves of 101.5 MMBoe was primarily due to the following:
Increase of 85.0 MMBoe through extensions and discoveries, 28.2 MMBoe of which were proved developed reserves, as a result of development efforts in the Permian where the Company drilled 70 gross (57.5 net) wells;
Increase of 39.7 MMBoe for purchases of reserves in place, of which 29.8 MMBoe were proved developed reserves, primarily related to the Company’s acquisition from Cimarex Energy Company in August 2018;
Decrease of 11.1 MMBoe for revisions of previous estimates that were primarily comprised of:
9.1 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans that were moved outside of the five-year development window primarily driven by larger pad development concepts and co-development of zones;
2.0 MMBoe related to technical revisions of PUDs; and
Decrease of 12.0 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,
2020 2019
Oil and natural gas properties: (In thousands)
   Evaluated properties $7,894,513  $7,203,482 
   Unevaluated properties 1,733,250  1,986,124 
Total oil and natural gas properties 9,627,763  9,189,606 
   Accumulated depreciation, depletion, amortization and impairment (5,538,803) (2,520,488)
Total oil and natural gas properties capitalized $4,088,960  $6,669,118 
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
Years Ended December 31,
2020 2019 2018
Acquisition costs: (In thousands)
   Evaluated properties $—  $49,572  $347,305 
   Unevaluated properties 30,696  107,347  466,816 
Development costs 379,900  189,259  259,410 
Exploration costs 122,865  309,013  323,458 
   Total costs incurred $533,461  $655,191  $1,396,989 
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2020. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.
Years Ended December 31,
2020 2019 2018
Oil ($/Bbl) $37.44  $53.90  $58.40 
Natural gas ($/Mcf) $1.02  $1.55  $3.64 
NGLs ($/Bbl) $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,
2020 2019 2018
(In thousands)
Future cash inflows $12,458,033  $20,891,469  $11,794,080 
Future costs
Production (5,433,496) (6,717,088) (2,923,959)
Development and net abandonment (2,204,301) (3,058,861) (1,429,787)
Future net inflows before income taxes 4,820,236  11,115,520  7,440,334 
Future income taxes (65,405) (941,768) (782,470)
Future net cash flows 4,754,831  10,173,752  6,657,864 
10% discount factor (2,444,441) (5,222,726) (3,716,571)
Standardized measure of discounted future net cash flows $2,310,390  $4,951,026  $2,941,293 
Changes in Standardized Measure
For the Year Ended December 31,
2020 2019 2018
(In thousands)
Standardized measure at the beginning of the period $4,951,026  $2,941,293  $1,556,682 
Sales and transfers, net of production costs (649,781) (579,744) (481,306)
Net change in sales and transfer prices, net of production costs (2,719,579) (387,970) 222,802 
Net change due to purchases of in place reserves —  2,975,296  554,697 
Net change due to sales of in place reserves (202,928) (303,526) — 
Extensions, discoveries, and improved recovery, net of future production and development costs incurred 250,759  607,146  1,001,873 
Changes in future development cost 361,008  205,398  40,483 
Previously estimated development costs incurred 318,470  134,037  91,900 
Revisions of quantity estimates (671,800) (420,488) (167,096)
Accretion of discount 536,958  314,921  157,676 
Net change in income taxes 383,999  (210,641) (187,841)
Changes in production rates, timing and other (247,742) (324,696) 151,423 
Aggregate change (2,640,636) 2,009,733  1,384,611 
Standardized measure at the end of period $2,310,390  $4,951,026  $2,941,293