Annual report pursuant to Section 13 and 15(d)

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

v3.19.3.a.u2
Supplemental Information on Oil and Natural Gas Properties (Unaudited)
 12 Months Ended
Dec. 31, 2019
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
The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). 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 Reserve Engineering Firms 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
 
2019
 
2018
 
2017
Oil (MBbls)
 
 
 
 
 
 
Beginning of period
 
180,097

 
107,072

 
71,145

Purchase of reserves in place
 
183,382

 
30,756

 
8,388

Sales of reserves in place
 
(17,980
)
 
—

 
—

Extensions and discoveries
 
45,663

 
67,763

 
39,267

Revisions to previous estimates
 
(33,136
)
 
(16,051
)
 
(5,171
)
Production
 
(11,665
)
 
(9,443
)
 
(6,557
)
End of period
 
346,361

 
180,097

 
107,072

Natural Gas (MMcf)
 
 
 
 
 
 
Beginning of period
 
350,466

 
179,410

 
122,611

Purchase of reserves in place
 
455,158

 
53,563

 
12,711

Sale of reserves in place
 
(86,856
)
 
—

 
—

Extensions and discoveries
 
82,566

 
103,149

 
48,648

Revisions to previous estimates
 
(24,482
)
 
29,791

 
6,336

Production
 
(19,718
)
 
(15,447
)
 
(10,896
)
End of period
 
757,134

 
350,466

 
179,410

NGLs (MBbls)
 
 
 
 
 
 
Beginning of period
 
—

 
—

 
—

Purchase of reserves in place
 
67,597

 
—

 
—

Production
 
(135
)
 
—

 
—

End of period
 
67,462

 
—

 
—

Total (MBoe)
 
 
 
 
 
 
Beginning of period
 
238,508

 
136,974

 
91,580

Purchase of reserves in place
 
326,838

 
39,683

 
10,507

Sale of reserves in place
 
(32,456
)
 
—

 
—

Extensions and discoveries
 
59,424

 
84,955

 
47,375

Revisions to previous estimates
 
(37,216
)
 
(11,086
)
 
(4,115
)
Production
 
(15,086
)
 
(12,018
)
 
(8,373
)
End of period
 
540,012

 
238,508

 
136,974

 
 
Years Ended December 31,
Proved developed reserves:
 
2019
 
2018
 
2017
Oil (MBbls)
 
 
 
 
 
 
Beginning of period
 
92,202

 
51,920

 
32,920

End of period
 
152,687

 
92,202

 
51,920

Natural gas (MMcf)
 
 
 
 
 
 
Beginning of period
 
218,417

 
104,389

 
61,871

End of period
 
320,676

 
218,417

 
104,389

NGLs (MBbls)
 
 
 
 
 
 
Beginning of period
 
—

 
—

 
—

End of period
 
24,844

 
—

 
—

Total proved developed reserves (MBoe)
 
 
 
 
 
 
Beginning of period
 
128,605

 
69,318

 
43,232

End of period
 
230,977

 
128,605

 
69,318

Proved undeveloped reserves
 
 
 
 
 
 
Oil (MBbls)
 
 
 
 
 
 
Beginning of period
 
87,895

 
55,152

 
38,225

End of period
 
193,674

 
87,895

 
55,152

Natural gas (MMcf)
 
 
 
 
 
 
Beginning of period
 
132,049

 
75,021

 
60,740

End of period
 
436,458

 
132,049

 
75,021

NGLs (MBbls)
 
 
 
 
 
 
Beginning of period
 
—

 
—

 
—

End of period
 
42,618

 
—

 
—

Total proved undeveloped reserves (MBoe)
 
 
 
 
 
 
Beginning of period
 
109,903

 
67,656

 
48,348

End of period
 
309,035

 
109,903

 
67,656

Total proved reserves
 
 
 
 
 
 
  Oil (MBbls)
 
 
 
 
 
 
Beginning of period
 
180,097

 
107,072

 
71,145

End of period
 
346,361

 
180,097

 
107,072

Natural gas (MMcf)
 
 
 
 
 
 
Beginning of period
 
350,466

 
179,410

 
122,611

End of period
 
757,134

 
350,466

 
179,410

NGLs (MBbls)
 
 
 
 
 
 
Beginning of period
 
—

 
—

 
—

End of period
 
67,462

 
—

 
—

Total proved reserves (MBoe)
 
 
 
 
 
 
Beginning of period
 
238,508

 
136,974

 
91,580

End of period
 
540,012

 
238,508

 
136,974


Total Proved Reserves
The Company ended 2019 with estimated proved reserves of 540.0 MMBoe, representing a 126% increase over 2018 year-end estimated proved reserves of 238.5 MMBoe. The Company added 386.3 MMBoe primarily from the Carrizo Acquisition completed in the fourth quarter of 2019 and development efforts in the Permian Basin, where it drilled a total of 61 gross (53.7 net) wells. This increase was offset by 2019 production, sales of reserves of 32.5 MMBoe, which are primarily related to the Ranger Divestiture, and negative revisions of previous estimates of 37.2 MMBoe. The negative revisions include 9.8 MMBoe from the reclassifications of PUDs within our optimized our development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which allowed the Company to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation. The remaining negative revisions were primarily from the observed impact of well spacing tests on producing wells and the related impact on reserve estimates as the Company advanced larger scale development concepts across its multi-zone inventory as well as the adverse effect of pricing and other economic factors.
The Company ended 2018 with estimated net proved reserves of 238.5 MMBoe, representing a 74% increase over 2017 year-end estimated net proved reserves of 137.0 MMBoe. The Company added 124.6 MMBoe primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross (57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2.0 MMBoe primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9.1 MMBoe from 19 PUD locations primarily due to
acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking.
The Company ended 2017 with estimated net proved reserves of 137.0 MMBoe, representing a 50% increase over 2016 year-end estimated net proved reserves of 91.6 MMBoe. The Company added 57.9 MMBoe primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross (38.2 net) wells. This increase was primarily offset by 2017 production, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations.
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,
 
 
2019
 
2018
Oil and natural gas properties:
 
(In thousands)
   Evaluated properties
 

$7,203,482

 

$4,585,020

   Unevaluated properties
 
1,986,124

 
1,404,513

Total oil and natural gas properties
 
9,189,606

 
5,989,533

   Accumulated depreciation, depletion, amortization and impairment
 
(2,520,488
)
 
(2,270,675
)
Total oil and natural gas properties capitalized
 

$6,669,118

 

$3,718,858


Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
 
 
Years Ended December 31,
 
 
2019
 
2018
 
2017
Acquisition costs:
 
(In thousands)
   Evaluated properties
 

$49,572

 

$347,305

 

$156,340

   Unevaluated properties
 
107,347

 
466,816

 
499,295

Development costs
 
189,259

 
259,410

 
148,254

Exploration costs
 
309,013

 
323,458

 
239,453

   Total costs incurred
 

$655,191

 

$1,396,989

 

$1,043,342


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, 2019. 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,
 
 
2019
 
2018
 
2017
Oil ($/Bbl) (1)
 

$53.90

 

$58.40

 

$49.48

Natural gas ($/Mcf) (2)
 

$1.55

 

$3.64

 

$3.47

NGLs ($/Bbl)
 

$15.58

 

$—

 

$—


 
(1)
Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.
(2)
Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.
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,
 
 
2019
 
2018
 
2017
 
 
(In thousands)
Future cash inflows
 

$20,891,469

 

$11,794,080

 

$5,920,328

Future costs
 
 
 
 
 
 
Production
 
(6,717,088
)
 
(2,923,959
)
 
(1,692,871
)
Development and net abandonment
 
(3,058,861
)
 
(1,429,787
)
 
(680,948
)
Future net inflows before income taxes
 
11,115,520

 
7,440,334

 
3,546,509

Future income taxes
 
(941,768
)
 
(782,470
)
 
(166,985
)
Future net cash flows
 
10,173,752

 
6,657,864

 
3,379,524

10% discount factor
 
(5,222,726
)
 
(3,716,571
)
 
(1,822,842
)
Standardized measure of discounted future net cash flows
 

$4,951,026

 

$2,941,293

 

$1,556,682

໿

 
Changes in Standardized Measure

 
For the Year Ended December 31,

 
2019
 
2018
 
2017
 
 
(In thousands)
Standardized measure at the beginning of the period
 

$2,941,293

 

$1,556,682

 

$809,832

Sales and transfers, net of production costs
 
(579,744
)
 
(481,306
)
 
(294,172
)
Net change in sales and transfer prices, net of production costs
 
(387,970
)
 
222,802

 
176,234

Net change due to purchases of in place reserves
 
2,975,296

 
554,697

 
129,454

Net change due to sales of in place reserves
 
(303,526
)
 
—

 
—

Extensions, discoveries, and improved recovery, net of future production and development costs incurred
 
607,146

 
1,001,873

 
635,000

Changes in future development cost
 
205,398

 
40,483

 
(8,148
)
Previously estimated development costs incurred
 
134,037

 
91,900

 
45,131

Revisions of quantity estimates
 
(420,488
)
 
(167,096
)
 
(79,325
)
Accretion of discount
 
314,921

 
157,676

 
80,983

Net change in income taxes
 
(210,641
)
 
(187,841
)
 
(20,073
)
Changes in production rates, timing and other
 
(324,696
)
 
151,423

 
81,766

Aggregate change
 
2,009,733

 
1,384,611

 
746,850

Standardized measure at the end of period
 

$4,951,026

 

$2,941,293

 

$1,556,682