SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

Following the sales of substantially all of FCX’s oil and gas properties, including the sale of its Deepwater GOM, onshore California and Haynesville oil and gas properties in 2016, along with the sales of its property interests in the Madden area in central Wyoming and certain property interests in the GOM Shelf in 2017 and 2018, FCX’s oil and gas producing activities are not considered significant beginning in 2017. Refer to Note 2 for further discussion.

Costs Incurred. A summary of the costs incurred for FCX’s oil and gas acquisition, exploration and development activities for the year ended December 31, 2016, follows:



Property acquisition costs for unproved properties	$	7
Exploration costs	22
Development costs	749
	$	778

These amounts included increases in AROs of $37 million, capitalized general and administrative expenses of $78 million, and capitalized interest of $7 million.

Capitalized Costs. The aggregate capitalized costs subject to amortization for oil and gas properties and the aggregate related accumulated amortization as of December 31, 2016, follow:



Properties subject to amortization	$	27,507
Accumulated amortization^a	(27,433		)
	$	74


a.	Includes charges of $4.3 billion in 2016 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 $17.58 in 2016.

Costs Not Subject to Amortization. Including amounts determined to be impaired, FCX transferred $4.9 billion of costs associated with unevaluated properties to the full cost pool in 2016. Sales of unevaluated properties totaled $1.6 billion in 2016. Following FCX’s disposition of its Deepwater GOM and onshore California oil and gas properties in fourth-quarter 2016, the carrying value of all of FCX’s remaining oil and gas properties was included in the amortization base at December 31, 2018, and 2017.

Results of Operations for Oil and Gas Producing Activities. The results of operations from oil and gas producing activities for the year ended December 31, 2016, presented below, excludes non-oil and gas revenues, general and administrative expenses, interest expense and interest income. Income tax benefit was determined by applying the statutory rates to pre-tax operating results:



Revenues from oil and gas producing activities	$	1,513
Production and delivery costs^a	(1,829		)
Depreciation, depletion and amortization	(839		)
Impairment of oil and gas properties	(4,317		)
Income tax benefit (based on FCX’s U.S. federal statutory tax rate)^b	—
Results of operations from oil and gas producing activities	$	(5,472	)


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.

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 for the year ended December 31, 2016. 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 in the 2013 oil and gas acquisitions, and reflects 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.

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 year ended December 31, 2016.



	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	—		—		—


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.

The average realized sales prices used in FCX’s reserve reports as of December 31, 2016, were $34.26 per barrel of crude oil and $2.40 per one thousand cubic feet (Mcf) of natural gas.

For the year ended December 31, 2016, FCX sold reserves in-place totaling 187 MMBOE, primarily representing all of its Deepwater GOM, onshore California and Haynesville properties.

Standardized Measure. The Standardized Measure (discounted at 10 percent) from production of proved oil and natural gas reserves has been developed in accordance with SEC guidelines. FCX estimated the quantity of proved oil and natural gas reserves and the future periods in which they were 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 were 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, 2016, 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, 2016, follows:



Future cash inflows	$	345
Future production expense	(175		)
Future development costs^a	(439		)
Future income tax expense	—
Future net cash flows	(269		)
Discounted at 10% per year	32
Standardized Measure	$	(237	)


a.	Includes estimated asset retirement costs of $0.4 billion at December 31, 2016.

A summary of the principal sources of changes in the Standardized Measure for the year ended December 31, 2016, follows:



Balance at beginning of year	$	1,392
Changes during the year:
Sales, net of production expenses	(831		)
Net changes in sales and transfer prices, net of production expenses	(341		)
Extensions, discoveries and improved recoveries	—
Changes in estimated future development costs, including timing and other	146
Previously estimated development costs incurred during the year	295
Sales of reserves in-place	(1,049		)
Revisions of quantity estimates	12
Accretion of discount	139
Net change in income taxes	—
Total changes	(1,629		)
Balance at end of year	$	(237	)