Supplemental Oil and Gas Disclosures

12 Months Ended

Dec. 31, 2019

We have significant continuing oil and gas producing activities primarily in the Delaware Basin in Texas and New Mexico and the Williston Basin in North Dakota, all of which are located in the United States.

The following information includes activity through the completion of any asset sales. These sales include operations which are reported within continuing operations and the operations of the San Juan Basin, which have been reported as discontinued operations in our consolidated financial statements. The San Juan Basin properties were sold in March 2018 and December 2017.

Capitalized Costs


	As of December 31,
	2019		2018
	(Millions)
Proved Properties	$	8,928	$	7,612
Unproved properties	1,765		1,891
	10,693		9,503
Accumulated depreciation, depletion and amortization and valuation provisions	(3,491)		(2,542)
Net capitalized costs	$	7,202	$	6,961

__________

•Excluded from capitalized costs are equipment and facilities in support of oil and gas production of $350 million and $276 million, net, as of December 31, 2019 and 2018, respectively.

•Proved properties include capitalized costs for oil and gas leaseholds holding proved reserves, development wells including uncompleted development well costs and successful exploratory wells.

•Unproved properties consist primarily of unproved leasehold costs.

Cost Incurred


	For the years ended December 31,
	2019		2018		2017
	(Millions)
Acquisition	$	115	$	68	$	864
Exploration	8		7		5
Development	1,099		1,350		1,048
	$	1,222	$	1,425	$	1,917

__________

•Costs incurred include capitalized and expensed items but excludes costs associated with facilities.

•Acquisition costs are as follows: Costs in 2019 primarily reflect the purchase of surface acreage within our Delaware Basin acreage. Costs in 2018 primarily relate to purchase of acreage in the Delaware Basin and include $13 million and 0.6 MMboe of proved reserves. Costs in 2017 primarily relate to our purchase of assets in the Delaware Basin in March 2017 that included approximately $200 million and 23.8 MMboe of proved developed reserves and facilities.

•Exploration costs include costs incurred for geological and geophysical activity, drilling and equipping exploratory wells, including costs incurred during the year for wells determined to be dry holes, exploratory lease acquisitions and retaining undeveloped leaseholds.

•Development costs include costs incurred to gain access to and prepare well locations for drilling and to drill and equip wells in our development basins. Development costs associated with our San Juan Basin operations were $24 million and $168 million for 2018 and 2017, respectively.

Proved Reserves

The SEC defines proved oil and gas reserves (Rule 4-10(a) of Regulation S-X) as those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Proved reserves consist of two categories, proved developed reserves and proved undeveloped reserves. Proved developed reserves are currently producing wells and wells awaiting minor sales connection expenditure, recompletion, additional perforations or borehole stimulation treatments. Proved undeveloped reserves are those reserves which are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. Proved reserves on undrilled acreage are limited to those that can be developed within five years according to planned drilling activity. Proved reserves on undrilled acreage also can include locations that are more than one offset away from current producing wells where there is a reasonable certainty of production when drilled or where it can be demonstrated with reasonable certainty that there is continuity of production from the existing productive formation.

The following is a summary of changes in our proved reserves including proved reserves activity through the completion of our sales of the San Juan and Piceance Basins which are reported as discontinued operations and other divestitures in continuing operations.


	Oil (MMbbls)	Natural Gas (Bcf)	NGLs (MMbbls)	All Products (MMboe)
Proved reserves at December 31, 2016	174.6	734.5	49.5	346.4
Revisions	4.7	(8.4)	(1.1)	2.3
Purchases	21.8	58.8	7.8	39.4
Divestitures	(1.7)	(312.5)	(0.8)	(54.6)
Extensions and discoveries	86.7	194.5	23.6	142.7
Production	(22.4)	(75.9)	(5.0)	(40.0)
Proved reserves at December 31, 2017	263.7	591.0	74.0	436.2
Revisions	—	(11.4)	5.3	3.4
Purchases	1.5	4.8	0.6	2.9
Divestitures	(27.6)	(79.8)	(10.4)	(51.3)
Extensions and discoveries	84.5	176.9	22.7	136.7
Production	(30.8)	(63.8)	(7.2)	(48.6)
Proved reserves at December 31, 2018	291.3	617.7	85.0	479.3
Revisions	(10.7)	41.4	8.6	4.8

Divestitures	(3.7)	(10.7)	(0.8)	(6.3)
Extensions and discoveries	56.7	170.7	25.5	110.7
Production	(37.8)	(78.4)	(10.0)	(60.9)
Proved reserves at December 31, 2019	295.8	740.7	108.3	527.6

Proved developed reserves:
December 31, 2017	130.3	321.2	38.8	222.7
December 31, 2018	156.4	365.4	48.4	265.8
December 31, 2019	184.3	456.5	65.5	325.9

Proved undeveloped reserves:
December 31, 2017	133.4	269.8	35.2	213.5
December 31, 2018	134.9	252.3	36.6	213.5
December 31, 2019	111.5	284.2	42.8	201.7

__________

•Natural gas reserves are computed at 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.

•Revisions in 2019 primarily reflect 21 MMboe of positive technical revisions partially offset by 16 MMboe of negative revisions due to a decrease in the 12 month average price. Revisions in 2018 primarily reflect 9 MMboe of positive revisions due to an increase in the 12 month average price offset by 5 MMboe of negative revisions. Revisions in 2017 primarily reflect 24 MMboe of positive revision due to an increase in the 12 month average price offset by 22 MMboe negative revisions primarily due to changes in the development plan for certain natural gas wells.

•Purchases in 2017 primarily reflect the Panther Acquisition of which 23.8 MMboe is proved developed.

•Divestitures in 2018 primarily relate to the sale of our oil assets in the San Juan Basin which included 40 MMboe of proved developed reserves and 11 MMboe of proved undeveloped reserves. Divestitures in 2017 primarily relate to the sale of our natural gas assets in the San Juan Basin which included 28.7 MMboe of proved developed reserves and 16.6 MMboe of proved undeveloped reserves.

•Extensions and discoveries in 2019 reflect 42 MMboe added for proved developed locations primarily in the Permian Basin and 68 MMboe added for proved undeveloped locations in the Permian Basin. Extensions and discoveries in 2018 reflect 52 MMboe added for proved developed locations and 85 MMboe of proved undeveloped locations. Extensions and discoveries in 2017 reflect 46 MMboe added for proved developed locations and 97 MMboe of proved undeveloped locations primarily in the Delaware and Williston Basins.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The following is based on the estimated quantities of proved reserves. Prices were calculated from the 12-month trailing average, first-of-the-month price for the applicable indices for each basin as adjusted for respective location price differentials. The average domestic oil price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $53.62, $61.57 and $46.39 per barrel, respectively. The average natural gas price used in the estimates for the years ended December 31, 2019, 2018 and 2017 was $0.97, $1.21 and $1.67 per Mcf, respectively. The average NGL price per barrel was $13.23, $26.76 and $21.16 for the same periods. Future income tax expenses have been computed considering applicable taxable cash flows, including historical tax basis and carry forwards (i.e. future deductions for taxable income calculations), and appropriate statutory tax rates. The discount rate of 10 is as prescribed by authoritative guidance. Continuation of year-end economic conditions also is assumed. The calculation is based on estimates of proved reserves, which are revised over time as new data becomes available. Probable or possible reserves, which may become proved in the future, are not considered. The calculation also requires assumptions as to the timing of future production of proved reserves, and the timing and amount of future development and production costs.

Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and timing of development expenditures. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates.

Standardized Measure of Discounted Future Net Cash Flows


	As of December 31,
	2019		2018
	(Millions)
Future cash inflows	$	18,012	$	20,963
Less:
Future production costs	8,407		7,615
Future development costs	1,469		2,345
Future income tax provisions	772		1,366
Future net cash flows	7,364		9,637
Less 10 percent annual discount for estimated timing of cash flows	3,233		4,446
Standardized measure of discounted future net cash inflows	$	4,131	$	5,191

Sources of Change in Standardized Measure of Discounted Future Net Cash Flows


	For the years ended December 31,
	2019		2018		2017
	(Millions)
Beginning of year	$	5,191	$	3,161	$	1,038
Sales of oil and gas produced, net of operating costs	(1,515)		(1,541)		(894)
Net change in prices and production costs	(2,247)		2,004		1,385
Extensions, discoveries and improved recovery, less estimated future costs	667		1,341		816
Development costs incurred during year	636		654		345
Changes in estimated future development costs	585		(35)		105
Purchase of reserves in place, less estimated future costs	—		27		305
Sale of reserves in place, less estimated future costs	(63)		(409)		20
Revisions of previous quantity estimates	85		75		30
Accretion of discount	548		324		104
Net change in income taxes	260		(396)		(83)
Other	(16)		(14)		(10)
Net changes	(1,060)		2,030		2,123
End of year	$	4,131	$	5,191	$	3,161