Freeport-McMoRan 2014 Annual Report Download - page 141

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
139
Excluding the impact of crude oil derivative contracts, the
average realized sales prices used in FCX’s reserve reports as of
December 31, 2014, were $93.20 per barrel of crude oil and $4.35
per one thousand cubic feet (Mcf) of natural gas.
The Standardized Measure related to proved oil and natural gas
reserves as of December 31 follows:
2014 2013
Future cash inflows $ 29,504 $ 3 8, 901
Future production expense (10,991) (12,774)
Future development costs
a
(6,448) (6,480)
Future income tax expense (2,487) (4,935)
Future net cash flows 9,578 14,712
Discounted at 10% per year (3,157) (5,295)
Standardized Measure $ 6,421 $ 9,417
a. Includes estimated asset retirement costs of $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:
2014 2013
a
Balance at beginning of year $ 9,417 $ —
Changes during the year:
Reserves acquired in the acquisitions of
PXP and MMR — 14,467
Sales, net of production expenses (3,062) (2,296)
Net changes in sales and transfer prices,
net of production expenses (2,875) (459)
Extensions, discoveries and improved recoveries 194 752
Changes in estimated future development costs (498) (1,190)
Previously estimated development costs incurred
during the year 982 578
Sales of reserves in-place (1,323) (12)
Other purchases of reserves in-place 487 —
Revisions of quantity estimates 399 102
Accretion of discount 1,195 701
Net change in income taxes 1,505 (3,226)
Total changes (2,996) 9,417
Balance at end of year $ 6,421 $ 9,417
a. Includes the results of FM O&G beginning June 1, 2013.
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 play and Madden field,
as well as continued improved performance in the Eagle Ford
shale play 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 in certain FCX 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 FCX onshore California and
Deepwater GOM properties, partially offset by performance
reductions primarily related to certain other FCX Deepwater GOM
properties and the Haynesville shale play.
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 properties.
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, 2014, 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,
2014, 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.