SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED) SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED) (Tables)

12 Months Ended

Dec. 31, 2016

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure

A summary of the costs incurred for FCX's oil and gas acquisition, exploration and development activities for the years ended December 31 follows:

	2016		2015		2014
Property acquisition costs:
Proved properties	$	—	$	—	$	463
Unproved properties	7		61		1,460
Exploration costs	22		1,250		1,482
Development costs	749		1,442		1,270
	$	778	$	2,753	$	4,675

Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure

The aggregate capitalized costs subject to amortization for oil and gas properties and the aggregate related accumulated amortization as of December 31 follow:

	2016				2015				2014
Properties subject to amortization	$	27,507			$	24,538			$	16,547
Accumulated amortization	(27,433		)	a	(22,276		)	a	(7,360		)	a
	$	74			$	2,262			$	9,187

a. Includes charges of $4.3 billion in 2016, $13.1 billion in 2015 and $3.7 billion in 2014 to reduce the carrying value of oil and gas properties pursuant to full cost accounting rules.

Results of Operations for Oil and Gas Producing Activities Disclosure

The results of operations from oil and gas producing activities for the years ended December 31, 2016, 2015 and 2014, presented below exclude non-oil and gas revenues, general and administrative expenses, goodwill impairment, interest expense and interest income. Income tax benefit was determined by applying the statutory rates to pre-tax operating results:

	2016				2015			2014
Revenues from oil and gas producing activities	$	1,513			$	1,994		$	4,710
Production and delivery costs	(1,829		)	a	(1,215		)	(1,237		)
Depreciation, depletion and amortization	(839		)		(1,772		)	(2,265		)
Impairment of oil and gas properties	(4,317		)		(13,144		)	(3,737		)
Income tax benefit (based on FCX's U.S. federal statutory tax rate)	—			b	5,368			958
Results of operations from oil and gas producing activities	$	(5,472	)		$	(8,769	)	$	(1,571	)

a. Includes $926 million in charges related to drillship settlements/idle rig and contract termination costs.

b. FCX has provided a full valuation allowance on losses associated with oil and gas activities in 2016.

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

The following table sets forth certain data pertaining to proved, proved developed and proved undeveloped reserves, all of which are in the U.S., for the years ended December 31, 2016, 2015 and 2014.

	Oil		Gas		Total
	(MMBbls)a,b		(Bcf)a		(MMBOE)a
2016
Proved reserves:
Balance at beginning of year	207		274		252
Extensions and discoveries	—		—		—
Acquisitions of reserves in-place	—		—		—
Revisions of previous estimates	1		—		1
Sale of reserves in-place	(168	)	(118	)	(187	)
Production	(36	)	(69	)	(48	)
Balance at end of year	4		87		18
Proved developed reserves at December 31, 2016	4		87		18
Proved undeveloped reserves at December 31, 2016	—		—		—

	Oil		Gas		Total
	(MMBbls)a,b		(Bcf)a		(MMBOE)a
2015
Proved reserves:
Balance at beginning of year	288		610		390
Extensions and discoveries	11		43		17
Acquisitions of reserves in-place	—		—		—
Revisions of previous estimates	(54	)	(287	)	(102	)
Sale of reserves in-place	—		(2	)	—
Production	(38	)	(90	)	(53	)
Balance at end of year	207		274		252
Proved developed reserves at December 31, 2015	129		245		169
Proved undeveloped reserves at December 31, 2015	78		29		83

2014
Proved reserves:
Balance at beginning of year	370		562		464
Extensions and discoveries	10		35		16
Acquisitions of reserves in-place	14		9		16
Revisions of previous estimates	(10	)	140		13
Sale of reserves in-place	(53	)	(54	)	(62	)
Production	(43	)	(82	)	(57	)
Balance at end of year	288		610		390
Proved developed reserves at December 31, 2014	184		369		246
Proved undeveloped reserves at December 31, 2014	104		241		144

a. MMBbls = million barrels; Bcf = billion cubic feet; MMBOE = million BOE

b. Includes NGL proved reserves of 1 MMBbls (all developed) at December 31, 2016, 9 MMBbls (6 MMBbls of developed and 3 MMBbls of undeveloped) at December 31, 2015, and 10 MMBbls (7 MMBbls of developed and 3 MMBbls of undeveloped) at December 31, 2014.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

The Standardized Measure related to proved oil and natural gas reserves as of December 31 follows:

	2016			2015			2014
Future cash inflows	$	345		$	10,536		$	29,504
Future production expense	(175		)	(4,768		)	(10,991		)
Future development costsa	(439		)	(4,130		)	(6,448		)
Future income tax expense	—			—			(2,487		)
Future net cash flows	(269		)	1,638			9,578
Discounted at 10% per year	32			(246		)	(3,157		)
Standardized Measure	$	(237	)	$	1,392		$	6,421

a. Includes estimated asset retirement costs of $0.4 billion at December 31, 2016, $1.9 billion at December 31, 2015, and $1.8 billion at December 31, 2014.

Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows

A summary of the principal sources of changes in the Standardized Measure for the years ended December 31 follows:

	2016			2015			2014
Balance at beginning of year	$	1,392		$	6,421		$	9,417
Changes during the year:
Sales, net of production expenses	(831		)	(928		)	(3,062		)
Net changes in sales and transfer prices, net of production expenses	(341		)	(7,766		)	(2,875		)
Extensions, discoveries and improved recoveries	—			45			194
Changes in estimated future development costs, including timing and other	146			1,287			(498		)
Previously estimated development costs incurred during the year	295			985			982
Sales of reserves in-place	(1,049		)	—			(1,323		)
Other purchases of reserves in-place	—			—			487
Revisions of quantity estimates	12			(1,170		)	399
Accretion of discount	139			797			1,195
Net change in income taxes	—			1,721			1,505
Total changes	(1,629		)	(5,029		)	(2,996		)
Balance at end of year	$	(237	)	$	1,392		$	6,421