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SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)
 12 Months Ended
Dec. 31, 2019
Oil and Gas Exploration and Production Industries Disclosures [Abstract]  
SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited) SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS OPERATIONS (Unaudited)

The Company’s oil and natural gas reserves are attributable solely to properties within the United States.

Capitalized oil and natural gas costs

Aggregate capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
 
December 31,
 
2019
 
2018
 
(In millions)
Oil and natural gas properties:
 
 
 
Proved properties
$
16,575

 
$
12,629

Unproved properties
9,207

 
9,670

Total oil and natural gas properties
25,782

 
22,299

Accumulated depreciation, depletion, amortization
(2,995
)
 
(1,599
)
Accumulated impairment
(1,934
)
 
(1,144
)
Net oil and natural gas properties capitalized
$
20,853

 
$
19,556



Costs incurred in oil and natural gas activities

Costs incurred in oil and natural gas property acquisition, exploration and development activities are as follows:
 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(In millions)
Acquisition costs:
 
 
 
 
 
Proved properties
$
194

 
$
5,665

 
$
455

Unproved properties
418

 
5,818

 
2,692

Development costs
956

 
493

 
145

Exploration costs
1,915

 
1,090

 
780

Total
$
3,483

 
$
13,066

 
$
4,072



Results of Operations from Oil and Natural Gas Producing Activities

The following schedule sets forth the revenues and expenses related to the production and sale of oil, natural gas and natural gas liquids. It does not include any interest costs or general and administrative costs and it reflects estimated corporate income taxes at enacted tax rates expected to be applicable the Company. Therefore, the following schedule is not necessarily indicative of the contribution to the net operating results of the Company’s oil, natural gas and natural gas liquids operations.

 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(In millions)
Oil, natural gas and natural gas liquid sales
$
3,887

 
$
2,130

 
$
1,186

Lease operating expenses
(490
)
 
(205
)
 
(127
)
Production and ad valorem taxes
(248
)
 
(133
)
 
(74
)
Gathering and transportation
(88
)
 
(26
)
 
(13
)
Depreciation, depletion, and amortization
(1,447
)
 
(595
)
 
(321
)
Impairment
(790
)
 
—

 
—

Asset retirement obligation accretion expense
(7
)
 
(2
)
 
(1
)
Income tax benefit (expense)
(89
)
 
(241
)
 
20

Results of operations
$
728

 
$
928

 
$
670


Oil and Natural Gas Reserves

Proved oil and natural gas reserve estimates as of December 31, 2019, 2018 and 2017 were prepared by Ryder Scott Company, L.P., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. Oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be precisely measured and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered.

The changes in estimated proved reserves are as follows:
 
Oil
(MBbls)
 
Natural Gas
Liquids
(MBbls)
 
Natural Gas
(MMcf)
Proved Developed and Undeveloped Reserves:
 
 
 
 
 
As of January 1, 2017
139,174

 
37,134

 
174,896

Extensions and discoveries
99,980

 
20,825

 
109,032

Revisions of previous estimates
(7,715
)
 
(1,466
)
 
(10,065
)
Purchase of reserves in place
24,322

 
2,633

 
34,640

Divestitures
(1,163
)
 
(461
)
 
(2,474
)
Production
(21,417
)
 
(4,056
)
 
(20,660
)
As of December 31, 2017
233,181

 
54,609

 
285,369

Extensions and discoveries
143,256

 
33,152

 
154,088

Revisions of previous estimates
3,689

 
11,138

 
3,642

Purchase of reserves in place
281,333

 
98,865

 
640,761

Divestitures
(156
)
 
(8
)
 
(543
)
Production
(34,367
)
 
(7,465
)
 
(34,668
)
As of December 31, 2018
626,936

 
190,291

 
1,048,649

Extensions and discoveries
256,569

 
66,572

 
318,874

Revisions of previous estimates
(84,789
)
 
(8,166
)
 
(149,657
)
Purchase of reserves in place
13,974

 
3,813

 
19,830

Divestitures
(33,269
)
 
(3,809
)
 
(21,272
)
Production
(68,518
)
 
(18,498
)
 
(97,613
)
As of December 31, 2019
710,903

 
230,203

 
1,118,811

 
 
 
 
 
 
Proved Developed Reserves:
 
 
 
 
 
January 1, 2017
79,457

 
22,080

 
105,399

December 31, 2017
141,246

 
35,412

 
190,740

December 31, 2018
403,051

 
125,509

 
705,084

December 31, 2019
457,083

 
165,173

 
824,760

 
 
 
 
 
 
Proved Undeveloped Reserves:
 
 
 
 
 
January 1, 2017
59,717

 
15,054

 
69,497

December 31, 2017
91,935

 
19,198

 
94,629

December 31, 2018
223,885

 
64,782

 
343,565

December 31, 2019
253,820

 
65,030

 
294,051



Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.

During the year ended December 31, 2019, the Company’s extensions and discoveries totaling 376,287 MBOE resulted primarily from the drilling of 283 new wells and from 291 new proved undeveloped locations added in which the Company owns a working interest. Viper royalty interests accounted for 5% of the extension volumes. The Company’s downward revisions of 117,898 MBOE were the result of proved undeveloped downgrades associated with inventory refinement following the Energen acquisition along with updated development plans and lower realized prices.  Purchases of 21,092 MBOE were the result of 10,939 MBOE of working interest purchases and 10,153 MBOE of Viper royalty purchases, excluding mineral interests dropped down to Viper.

During the year ended December 31, 2018, the Company’s extensions and discoveries of 202,089 MBOE resulted primarily from the drilling of 135 new wells and from 138 new proved undeveloped locations added in which the Company
owns a working interest. Viper royalty interests accounted for 10% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of positive technical and performance revisions of 14,218 MBOE, upward revisions of 6,032 MBOE due to higher pricing and downward revisions of 4,815 MBOE from PUD reclassifications due to timing. Purchases of 486,992 MBOE were the result of 477,686 of working interest purchases, primarily attributable to Energen, and 9,306 MBOE of Viper royalty purchases.

During the year ended December 31, 2017, the Company’s extensions and discoveries of 138,977 MBOE resulted primarily from the drilling of 102 new wells and from 87 new proved undeveloped locations added. Viper royalty interests accounted for 8% of the extension volumes. The Company’s revisions of previous estimates were primarily the result of 2,550 MBOE from reclassifying PUD locations due to anticipated timing, with the remaining 8,308 MBOE being technical revisions. Delaware Basin working interest purchases accounted for 87% of the total purchases and Viper royalty interest purchases accounted for 10%, with working interest purchases contributing the remainder.

At December 31, 2019, the Company’s estimated PUD reserves were approximately 367,859 MBOE, a 21,931 MBOE increase over the reserve estimate at December 31, 2018 of 345,928 MBOE. The following table includes the changes in PUD reserves for 2019:

 
(MBOE)
Beginning proved undeveloped reserves at December 31, 2018
345,928

Undeveloped reserves transferred to developed
(120,920
)
Revisions
(77,519
)
Net purchases
4,542

Divestitures
(5,672
)
Extensions and discoveries
221,500

Ending proved undeveloped reserves at December 31, 2019
367,859



The increase in proved undeveloped reserves was primarily attributable to extensions of 213,909 MBOE from 291 gross (262 net) wells in which the Company has a working interest and 7,591 MBOE from 97 gross wells in which Viper owns royalty interests. Of the 291 gross working interest wells, 64 were in the Delaware Basin. Transfers of 120,920 MBOE were the result of drilling or participating in 135 gross (119 net) horizontal wells in which the Company has a working interest and 79 gross wells in which the Company has a royalty interest or mineral interest through Viper. The Company owns a working interest in 75 of the 79 gross Viper wells. Downward revisions of 77,519 MBOE resulted from 67,114 MBOE of PUD downgrades due to refinement of the PUD inventory following the acquisition of Energen. These downgrades were offset with Extensions. The remaining 10,405 MOE of downward revisions were mostly from lower benchmark commodity prices.

As of December 31, 2019, all of the Company’s proved undeveloped reserves are planned to be developed within five years from the date they were initially recorded. During 2019, approximately $956 million in capital expenditures went toward the development of proved undeveloped reserves, which includes drilling, completion and other facility costs associated with developing proved undeveloped wells.

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is based on the unweighted average, first-day-of-the-month price. The projections should not be viewed as realistic estimates of future cash flows, nor should the “standardized measure” be interpreted as representing current value to the Company. Material revisions to estimates of proved reserves may occur in the future; development and production of the reserves may not occur in the periods assumed; actual prices realized are expected to vary significantly from those used; and actual costs may vary.

The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved oil and natural gas reserves as of December 31, 2019, 2018 and 2017.
 
December 31,
 
2019
 
2018
 
2017
 
(In millions)
Future cash inflows
$
40,681

 
$
43,578

 
$
12,922

Future development costs
(3,809
)
 
(3,560
)
 
(1,124
)
Future production costs
(9,319
)
 
(7,727
)
 
(2,995
)
Future production taxes
(2,905
)
 
(2,935
)
 
(929
)
Future income tax expenses
(2,635
)
 
(3,913
)
 
(84
)
Future net cash flows
22,013

 
25,443

 
7,790

10% discount to reflect timing of cash flows
(11,829
)
 
(13,767
)
 
(4,033
)
Standardized measure of discounted future net cash flows
$
10,184

 
$
11,676

 
$
3,757



In the table below the average first-day-of–the-month price for oil, natural gas and natural gas liquids is presented, all utilized in the computation of future cash inflows.
 
December 31,
 
2019
 
2018
 
2017
 
Unweighted Arithmetic Average
 
First-Day-of-the-Month Prices
Oil (per Bbl)
$
51.88

 
$
59.63

 
$
48.03

Natural gas (per Mcf)
$
0.18

 
$
1.47

 
$
2.06

Natural gas liquids (per Bbl)
$
15.65

 
$
24.43

 
$
20.79



Principal changes in the standardized measure of discounted future net cash flows attributable to the Company’s proved reserves are as follows:
 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(In millions)
Standardized measure of discounted future net cash flows at the beginning of the period
$
11,676

 
$
3,757

 
$
1,711

Sales of oil and natural gas, net of production costs
(3,334
)
 
(1,786
)
 
(986
)
Acquisition of reserves
309

 
5,520

 
439

Divestiture of reserves
(500
)
 
(2
)
 
(11
)
Extensions and discoveries, net of future development costs
4,004

 
3,287

 
1,792

Previously estimated development costs incurred during the period
120

 
535

 
190

Net changes in prices and production costs
831

 
1,805

 
578

Changes in estimated future development costs
(3,190
)
 
(81
)
 
(53
)
Revisions of previous quantity estimates
(1,242
)
 
271

 
(99
)
Accretion of discount
1,344

 
380

 
174

Net change in income taxes
693

 
(1,728
)
 
(9
)
Net changes in timing of production and other
(527
)
 
(282
)
 
31

Standardized measure of discounted future net cash flows at the end of the period
$
10,184

 
$
11,676

 
$
3,757