SUPPLEMENTARY OIL AND GAS INFORMATION (UNAUDITED)

Costs Incurred. FCX's oil and gas acquisition, exploration and development activities since the acquisitions of PXP and MMR follow:



Property acquisition costs:
Proved properties^a	$	12,205
Unproved properties^b	11,259
Exploration costs	502
Development costs	854
	$	24,820


a.	Included $12.2 billion from the acquisitions of PXP and MMR.


b.	Included $11.1 billion from the acquisitions of PXP and MMR.

These amounts included AROs of $1.1 billion (including $1.0 billion assumed in the acquisitions of PXP and MMR), capitalized general and administrative expenses of $67 million and capitalized interest of $69 million.

Capitalized Costs. The following table presents the aggregate capitalized costs subject to amortization for oil and gas properties and the aggregate related accumulated amortization as of December 31, 2013:



Properties subject to amortization	$	13,829
Accumulated amortization	(1,357		)
	$	12,472

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

Costs Not Subject to Amortization. The following table summarizes the categories of costs comprising the amount of unproved properties not subject to amortization as of December 31, 2013:



U.S.:
Onshore
Acquisition costs	$	3,109
Exploration costs	8
Capitalized interest	11
Offshore
Acquisition costs	7,528
Exploration costs	163
Capitalized interest	53
International:
Offshore
Acquisition costs	15
Exploration costs	—
Capitalized interest	—
	$	10,887

FCX expects that 61 percent of the costs not subject to amortization at December 31, 2013, 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.

Approximately 41 percent of the total U.S. net undeveloped acres is covered by leases that expire from 2014 to 2016; however, a significant portion of this acreage is expected to be retained by drilling operations or other means. The lease for FM O&G's Morocco acreage expires in 2016; however, FM O&G has the ability to extend the lease through 2019. Over 90 percent of the acreage in the Haynesville shale play in Louisiana and over 70 percent of the acreage in the Eagle Ford shale play in Texas is currently held by production or held by operations, and future plans include drilling or otherwise extending leases on the remaining acreage.

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



Revenues from oil and gas producing activities	$	2,616
Production and delivery costs	(682		)
Depreciation, depletion and amortization	(1,358		)
Income tax expense (based on FCX's statutory tax rate)	(219		)
Results of operations from oil and gas producing activities (excluding general and administrative expenses, interest expense and interest income)	$	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 the oil and natural gas reserves are located in the U.S.

Management believes the reserve estimates presented herein, in accordance with generally accepted engineering and evaluation principles consistently applied, are reasonable. 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 spot price for natural gas. As of February 14, 2014, the twelve-month average of the first-day-of-the-month historical reference price for natural gas has increased from $3.67 per MMBtu at year-end 2013 to $3.89 per MMBtu, while the comparable price for crude oil has increased from $96.94 per barrel at year-end 2013 to $97.46 per barrel.

Historically, 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. Recently, however, the market price for California crude oil has strengthened relative to NYMEX and WTI primarily resulting from world demand and declining domestic supplies of both Alaskan and California crude oil. Approximately 40 percent of FCX's year-end 2013 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 25 percent of FCX's 2013 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 period June 1, 2013, to December 31, 2013.



	Oil		Gas		Total
	(MMbls)^a,b		(Bcf)^a		(MMBOE)^a
Proved reserves:
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 December 31, 2013	370		562		464

Proved developed reserves at December 31, 2013	236		423		307

Proved undeveloped reserves at December 31, 2013	134		139		157


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


b.	Included 20 MMBbls of NGL proved reserves, consisting of 14 MMBbls of proved developed and 6 MMBbls of proved undeveloped at December 31, 2013.

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 play 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.

From June 1, 2013, to December 31, 2013, FCX had net positive revisions of 7 MMBOE consisting of 29 MMBOE primarily related to improved performance at certain FCX onshore California and Deepwater GOM properties, partially offset by performance reductions of 22 MMBOE primarily related to certain other FCX Deepwater GOM properties and the Haynesville shale play.

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, 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. 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, 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.

Excluding the impact of crude oil and natural gas derivative contracts, the average realized sales prices used in FCX's reserve reports as of December 31, 2013, were $99.67 per barrel of crude oil and $3.64 per one thousand cubic feet (Mcf) of natural gas.

The Standardized Measure related to proved oil and natural gas reserves as of December 31, 2013, follows:



Future cash inflows	$	38,901
Future production expense	(12,774		)
Future development costs^a	(6,480		)
Future income tax expense	(4,935		)
Future net cash flows	14,712
Discounted at 10% per year	(5,295		)
Standardized Measure	$	9,417

a. Included estimated asset retirement costs of $1.8 billion.

The following table summarizes the principal sources of changes in the Standardized Measure from June 1, 2013, to December 31, 2013:



Reserves acquired in the acquisitions of PXP and MMR	$	14,467
Sales, net of production expenses	(2,296		)
Net changes in sales and transfer prices, net of production expenses	(459		)
Extensions, discoveries and improved recoveries	752
Changes in estimated future development costs	(1,190		)
Previously estimated development costs incurred during the year	578
Sales of reserves in-place	(12		)
Other purchases of reserves in-place	—
Revisions of quantity estimates	102
Accretion of discount	701
Net change in income taxes	(3,226		)
Balance at December 31, 2013	$	9,417