SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

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



	2015		2014		2013^a
Property acquisition costs:
Proved properties	$	—	$	463	$	12,205	^b
Unproved properties	61		1,460		11,259		^c
Exploration costs	1,250		1,482		502
Development costs	1,442		1,270		854
	$	2,753	$	4,675	$	24,820


a.	Includes the results of FM O&G beginning June 1, 2013.


b.	Includes $12.2 billion from the acquisitions of PXP and MMR.


c.	Includes $11.1 billion from the acquisitions of PXP and MMR.

These amounts included (decreases) increases in AROs of $(80) million in 2015, $(27) million in 2014 and $1.1 billion in 2013 (including $1.0 billion assumed in the acquisitions of PXP and MMR), capitalized general and administrative expenses of $124 million in 2015, $143 million in 2014 and $67 million in 2013, and capitalized interest of $58 million in 2015, $88 million in 2014 and $69 million in 2013.

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



	2015				2014				2013
Properties subject to amortization	$	24,538			$	16,547			$	13,829
Accumulated amortization	(22,276		)	^a	(7,360		)	^a	(1,357		)
	$	2,262			$	9,187			$	12,472


a.	Includes charges of $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.

The average amortization rate per barrel of oil equivalents (BOE) was $33.46 in 2015, $39.74 in 2014 and $35.54 for the period from June 1, 2013, to December 31, 2013.

Costs Not Subject to Amortization. A summary of the categories of costs comprising the amount of unproved properties not subject to amortization by the year in which such costs were incurred follows:



			Years Ended December 31,
	Total		2015		2014		2013^a
U.S.:
Onshore
Acquisition costs	$	389	$	6	$	—	$	383
Exploration costs	8		7		1		—
Capitalized interest	2		2		—		—
Offshore
Acquisition costs	4,048		57		1,304		2,687
Exploration costs	331		201		130		—
Capitalized interest	37		25		11		1
International:
Offshore
Acquisition costs	7		—		—		7
Exploration costs	7		2		5		—
Capitalized interest	2		1		1		—
	$	4,831	$	301	$	1,452	$	3,078


a.	Includes the results of FM O&G beginning June 1, 2013.

FCX expects that 40 percent of the costs not subject to amortization at December 31, 2015, will be transferred to the amortization base over the next five years and the majority of the remainder in the next seven to ten years.

Of the total U.S. net undeveloped acres, 24 percent is covered by leases that expire from 2016 to 2018. As a result of declining crude oil prices, FCX's current plans anticipate that the majority of the expiring acreage will not be retained by drilling operations or other means. Currently, FM O&G has a commitment to drill a second well in Morocco in 2016. However, FM O&G is actively negotiating with its partners to modify its work program, which, if successful, would result in changes in the timing, amount or type of future commitment. The exploration permits covering FM O&G's Morocco acreage expire at the end of 2016; however, FM O&G has the ability, under certain circumstances, to extend the exploration permits through 2019. Over 95 percent of the acreage in the Haynesville shale in Louisiana is currently held by production or held by operations.

Results of Operations for Oil and Gas Producing Activities. The results of operations from oil and gas producing activities for the years ended December 31, 2015 and 2014, and the period from June 1, 2013, to December 31, 2014, presented below exclude non-oil and gas revenues, general and administrative expenses, goodwill impairment, interest expense and interest income. Income tax benefit (expense) was determined by applying the statutory rates to pre-tax operating results:



	Years Ended December 31,						June 1, 2013, to
	2015			2014			December 31, 2013
Revenues from oil and gas producing activities	$	1,994		$	4,710		$	2,616
Production and delivery costs	(1,215		)	(1,237		)	(682		)
Depreciation, depletion and amortization	(1,772		)	(2,265		)	(1,358		)
Impairment of oil and gas properties	(13,144		)	(3,737		)	—
Income tax benefit (expense) (based on FCX's statutory tax rate)	5,368			958			(219		)
Results of operations from oil and gas producing activities	$	(8,769	)	$	(1,571	)	$	357

Proved Oil and Natural Gas Reserve Information. The following information summarizes the net proved reserves of oil (including condensate and natural gas liquids (NGLs)) and natural gas and the standardized measure as described below. All of FCX's oil and natural gas reserves are located in the U.S.

Management believes the reserve estimates presented herein are reasonable and prepared in accordance with guidelines established by the SEC as prescribed in Regulation S-X, Rule 4-10. However, there are numerous uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production and the amount and timing of development expenditures, including many factors beyond FCX's control. Reserve engineering is a subjective process of estimating the recovery from underground accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Because all oil and natural gas reserve estimates are to some degree subjective, the quantities of oil and natural gas that are ultimately recovered, production and operating costs, the amount and timing of future development expenditures, and future crude oil and natural gas sales prices may all differ from those assumed in these estimates. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data. Therefore, the standardized measure of discounted future net cash flows (Standardized Measure) shown below represents estimates only and should not be construed as the current market value of the estimated reserves attributable to FCX's oil and gas properties. In this regard, the information set forth in the following tables includes revisions of reserve estimates attributable to proved properties acquired from PXP and MMR, and reflect additional information from subsequent development activities, production history of the properties involved and any adjustments in the projected economic life of such properties resulting from changes in product prices.

Decreases in the prices of crude oil and natural gas could have an adverse effect on the carrying value of the proved reserves, reserve volumes and FCX's revenues, profitability and cash flows. FCX's reference prices for reserve determination are the WTI spot price for crude oil and the Henry Hub price for natural gas. As of February 2016, the twelve-month average of the first-day-of-the-month historical reference price for crude oil has decreased from $50.28 per barrel at December 31, 2015, to $47.54 per barrel, while the comparable price for natural gas has decreased from $2.59 per MMBtu at December 31, 2015, to $2.50 per MMBtu.

The market price for California crude oil differs from the established market indices in the U.S. primarily because of the higher transportation and refining costs associated with heavy oil, which can vary based on global supply and demand, refinery utilization and inventory levels. Approximately 33 percent of FCX's oil and natural gas reserve volumes are attributable to properties in California where differentials to the reference prices have been volatile as a result of these factors.

The market price for GOM crude oil differs from WTI as a result of a large portion of FCX's production being sold under a Heavy Louisiana Sweet based pricing. Approximately 59 percent of FCX's December 31, 2015, oil and natural gas reserve volumes are attributable to properties in the GOM where oil price realizations are generally higher because of these marketing contracts.

Estimated Quantities of Oil and Natural Gas Reserves. 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, 2015 and 2014, and the period from June 1, 2013, to December 31, 2013.



	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



2013
Proved reserves:
Balance at beginning of year	—		—		—
Acquisitions of PXP and MMR	368		626		472
Extensions and discoveries	20		20		24
Revisions of previous estimates	11		(26	)	7
Sale of reserves in-place	—		(3	)	(1	)
Production	(29	)	(55	)	(38	)
Balance at end of year	370		562		464

Proved developed reserves at December 31, 2013	236		423		307

Proved undeveloped reserves at December 31, 2013	134		139		157


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


b.	Includes 9 MMBbls of NGL proved reserves (6 MMBbls of developed and 3 MMBbls of undeveloped) at December 31, 2015, 10 MMBbls of NGL proved reserves (7 MMBbls of developed and 3 MMBbls of undeveloped) at December 31, 2014, and 20 MMBbls of NGL proved reserves (14 MMBbls of developed and 6 MMBbls of undeveloped) at December 31, 2013.

For the year ended December 31, 2015, FCX had a total of 17 MMBOE of extensions and discoveries, including 14 MMBOE in the Deepwater GOM, primarily associated with the continued successful development of Horn Mountain and 3 MMBOE in the Haynesville shale resulting from continued successful drilling that extended and developed FCX's proved acreage. For the year ended December 31, 2014, FCX had a total of 16 MMBOE of extensions and discoveries, including 8 MMBOE in the Deepwater GOM, primarily associated with the continued successful development at Horn Mountain and 5 MMBOE in the Haynesville shale resulting from continued successful drilling that extended and developed FCX's proved acreage. From June 1, 2013, to December 31, 2013, FCX had a total of 24 MMBOE of extensions and discoveries, including 16 MMBOE in the Eagle Ford shale resulting from continued successful drilling that extended and developed FCX's proved acreage and 5 MMBOE in the Deepwater GOM, primarily associated with the previously drilled Holstein Deep development acquired during 2013.

For the year ended December 31, 2015, FCX had net negative revisions of 102 MMBOE primarily related to lower oil and gas price realizations. For the year ended December 31, 2014, FCX had net positive revisions of 13 MMBOE primarily related to improved gas price realizations in both the Haynesville shale and Madden field, as well as continued improved performance in the Eagle Ford shale prior to the disposition, partially offset by the downward revisions of certain proved undeveloped reserves resulting from deferred development plans, as well as lower oil price realizations and higher steam-related operating expenses resulting from higher natural gas prices at certain onshore California properties. From June 1, 2013, to December 31, 2013, FCX had net positive revisions of 7 MMBOE primarily related to improved performance at certain onshore California and Deepwater GOM properties, partially offset by performance reductions primarily related to certain other Deepwater GOM properties and the Haynesville shale.

Excluding the impact of crude oil derivative contracts, the average realized sales prices used in FCX's reserve reports as of December 31, 2015, were $47.80 per barrel of crude oil and $2.55 per one thousand cubic feet (Mcf) of natural gas. As of December 31, 2014, the average realized sales prices used in FCX's reserve report were $93.20 per barrel of crude oil and $4.35 per Mcf.

For the year ended December 31, 2014, FCX acquired reserves in-place totaling 16 MMBOE from the acquisition of interests in the Deepwater GOM, including interests in the Lucius and Heidelberg oil fields.

For the year ended December 31, 2014, FCX sold reserves in-place totaling 62 MMBOE primarily related to its Eagle Ford shale assets. From June 1, 2013, to December 31, 2013, FCX sold reserves in-place totaling 1 MMBOE related to its Panhandle properties.

Standardized Measure. The Standardized Measure (discounted at 10 percent) from production of proved oil and natural gas reserves has been developed as of December 31, 2015, 2014 and 2013, in accordance with SEC guidelines. FCX estimated the quantity of proved oil and natural gas reserves and the future periods in which they are expected to be produced based on year-end economic conditions. Estimates of future net revenues from FCX's proved oil and gas properties and the present value thereof were made using the twelve-month average of the first-day-of-the-month historical reference prices as adjusted for location and quality differentials, which are held constant throughout the life of the oil and gas properties, except where such guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations (excluding the impact of crude oil derivative contracts). Future gross revenues were reduced by estimated future operating costs (including production and ad valorem taxes) and future development and abandonment costs, all of which were based on current costs in effect at December 31, 2015, 2014 and 2013, and held constant throughout the life of the oil and gas properties. Future income taxes were calculated by applying the statutory federal and state income tax rate to pre-tax future net cash flows, net of the tax basis of the respective oil and gas properties and utilization of FCX's available tax carryforwards related to its oil and gas operations.

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



	2015			2014			2013
Future cash inflows	$	10,536		$	29,504		$	38,901
Future production expense	(4,768		)	(10,991		)	(12,774		)
Future development costs^a	(4,130		)	(6,448		)	(6,480		)
Future income tax expense	—			(2,487		)	(4,935		)
Future net cash flows	1,638			9,578			14,712
Discounted at 10% per year	(246		)	(3,157		)	(5,295		)
Standardized Measure	$	1,392		$	6,421		$	9,417


a.	Includes estimated asset retirement costs of $1.9 billion at December 31, 2015, and $1.8 billion at December 31, 2014 and 2013.

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



	2015			2014			2013^a
Balance at beginning of year	$	6,421		$	9,417		$	—
Changes during the year:
Reserves acquired in the acquisitions of PXP and MMR	—			—			14,467
Sales, net of production expenses	(928		)	(3,062		)	(2,296		)
Net changes in sales and transfer prices, net of production expenses	(7,766		)	(2,875		)	(459		)
Extensions, discoveries and improved recoveries	45			194			752
Changes in estimated future development costs	1,287			(498		)	(1,190		)
Previously estimated development costs incurred during the year	985			982			578
Sales of reserves in-place	—			(1,323		)	(12		)
Other purchases of reserves in-place	—			487			—
Revisions of quantity estimates	(1,170		)	399			102
Accretion of discount	797			1,195			701
Net change in income taxes	1,721			1,505			(3,226		)
Total changes	(5,029		)	(2,996		)	9,417
Balance at end of year	$	1,392		$	6,421		$	9,417


a.	Includes the results of FM O&G beginning June 1, 2013.