(16) Supplemental Information on Oil and Gas Producing Activities (Unaudited)

The following is supplemental information regarding the Company’s consolidated oil and gas producing activities. The amounts shown include the Company’s net working interests in all of its oil and gas properties.

(a) Capitalized Costs Relating to Oil and Gas Producing Activities


	Year ended December 31,
	2013		2014
	(In thousands)
Proved properties	$	3,621,672	$	6,515,221
Unproved properties		1,513,136		2,060,936
		5,134,808		8,576,157
Accumulated depreciation and depletion		(383,921)		(802,665)
Net capitalized costs	$	4,750,887	$	7,773,492

(b) Costs Incurred in Certain Oil and Gas Activities


	Year ended December 31,
	2012		2013		2014
Acquisition costs:
Proved property	$	10,254	$	15,300	$	64,066
Unproved property		687,403		440,825		777,422
Development costs		678,276		780,583		1,536,193
Exploration costs		158,074		835,382		940,957
Total costs incurred	$	1,534,007	$	2,072,090	$	3,318,638


	Year ended December 31,
	2012		2013		2014
Revenues	$	390,378	$	821,445	$	1,736,752
Operating expenses:
Production expenses		185,505		278,348		578,672
Exploration expenses		15,339		22,272		27,893
Depreciation and depletion		181,664		219,830		418,744
Impairment of unproved properties		13,032		10,928		15,198
Results of operations before income tax expense (benefit)		(5,162)		290,067		696,245
Income tax (expense) benefit		2,008		(110,805)		(263,126)
Results of operations	$	(3,154)	$	179,262	$	433,119

(d) Oil and Gas Reserves

The following table sets forth the net quantities of proved reserves and proved developed reserves during the periods indicated. This information includes the oil and gas segment’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the year ended December 31, 2012, 2013, and 2014 were prepared by the Company’s reserve engineers and audited by DeGolyer and MacNaughton (D&M) utilizing data compiled by the Company. There are many uncertainties inherent in estimating proved reserve quantities, and projecting future production rates and timing of future development costs. In addition, reserve estimates of new discoveries are more imprecise than those of properties with a production history. Accordingly, these estimates are subject to change as additional information becomes available. All reserves are located in the United States.

Proved reserves are the estimated quantities of crude oil, condensate, and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known oil and gas reservoirs under existing economic and operating conditions at the end of the respective years. Proved developed reserves are those reserves expected to be recovered through existing wells with existing equipment and operating methods. The Company estimates proved reserves using average prices received for the previous 12 months.

Proved undeveloped reserves include drilling locations that are more than one offset location away from productive wells and are reasonably certain of containing proved reserves and which are scheduled to be drilled within five years under the Company’s development plans. The Company’s development plans for drilling scheduled over the next five years are subject to many uncertainties and variables, including availability of capital; future oil and gas prices; and cash flows from operations, future drilling costs, demand for natural gas, and other economic factors.


	Natural gas (Bcf)	NGLs (MMBbl)		Oil and condensate (MMBbl)		Equivalents (Bcfe)
Proved reserves:
December 31, 2011	3,931	164		17		5,017
Revisions	198	4		—	(a)	222
Extensions, discoveries and other additions	1,242	115		3		1,951
Production	(87)	—	(a)	—	(a)	(87)
Sale of reserves in place	(1,590)	(80)		(17)		(2,174)
December 31, 2012	3,694	203		3		4,929
Revisions	152	(140)		—	(a)	(788)
Extensions, discoveries and other additions	3,084	76		7		3,682
Production	(177)	(2)		—	(a)	(191)
December 31, 2013	6,753	137		10		7,632
Revisions	(1,025)	(6)		—	(a)	(1,054)
Extensions, discoveries and other additions	5,095	206		19		6,444
Purchases	29	—		—		29
Production	(317)	(7)		(1)		(368)
December 31, 2014	10,535	330		28		12,683

^(a)

Less than 1.0.



	Natural gas (Bcf)	NGLs (MMBbl)	Oil and condensate (MMBbl)	Equivalents (Bcfe)
Proved developed reserves:
December 31, 2012	828	36	1	1,047
December 31, 2013	1,818	33	2	2,022
December 31, 2014	3,285	80	6	3,803
Proved undeveloped reserves:
December 31, 2012	2,866	167	2	3,822
December 31, 2013	4,936	105	8	5,610
December 31, 2014	7,250	250	22	8,880

Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2010, 2011, and 2012 in the above table include the following:

2012—Extensions, discoveries, and other additions during 2012 of 1,951 Bcfe were added through the drilling in the Marcellus and Utica Shales, including the addition of 709 Bcfe attributable to NGLs and oil. Downward price revisions resulted in a reduction of proved reserves of 102 Bcfe. Performance revisions increased proved reserves by 324 Bcfe. Sales of proved reserves of 2,174 Bcfe are the result of the sale of the Company’s Arkoma and Piceance Basin properties.

2013—Extensions, discoveries, and other additions during 2013 of 3,682 Bcfe were added through exploratory and developmental drilling in the Marcellus and Utica Shales. Downward revisions of 788 Bcfe resulted from changing the underlying production assumption used to estimate reserves to ethane rejection at December 31, 2013 from ethane recovery at December 31, 2012 as well as the reclassification of certain wells to the probable reserves category in 2013 because they are no longer expected to be drilled within five years of initial booking.

2014— Extensions, discoveries, and other additions during 2014 of 6,444 Bcfe were added through exploratory and developmental drilling in the Marcellus and Utica Shales. Purchases of 29 Bcfe relate to 5 horizontal producing wells acquired as part of our leasehold acquisition efforts. Upward performance revisions of 361 Bcfe relate to improved well performance from shorter stage length completions. Downward revisions of 1,417 Bcfe due were due to the reclassification of 191 dry gas locations to the probable category because they are no longer expected to be drilled within five years of initial booking. Upward price revisions of 2 Bcfe were due to increases in the reference price for natural gas, partially offset by decreases in the reference prices for NGLs and oil.

The following table sets forth the standardized measure of the discounted future net cash flows attributable to the Company’s proved reserves. Future cash inflows were computed by applying historical 12 month unweighted first day of the month average prices. Future prices actually received may materially differ from current prices or the prices used in the standardized measure.

Future production and development costs represent the estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. Future income tax expenses were computed by applying statutory income tax rates to the difference between pretax net cash flows relating to the Company’s proved reserves and the tax basis of proved oil and gas properties. In addition, the effects of available net operating loss carryforwards and alternative minimum tax credits were used in computing future income tax expense. The resulting annual net cash inflows were then discounted using a 10% annual rate.


	Year ended December 31,
(in millions)	2012		2013		2014
Future cash inflows	$	12,151	$	30,113	$	63,632
Future production costs		(1,660)		(5,967)		(21,722)
Future development costs		(3,270)		(5,349)		(8,212)
Future net cash flows before income tax		7,221		18,797		33,698
Future income tax expense		(1,603)		(5,308)		(10,726)
Future net cash flows		5,618		13,489		22,972
10% annual discount for estimated timing of cash flows		(4,017)		(8,979)		(15,337)
Standardized measure of discounted future net cash flows	$	1,601	$	4,510	$	7,635

The 12‑month weighted average prices used to estimate the Company’s total equivalent reserves were as follows (per Mcfe):


December 31, 2012	$	2.78
December 31, 2013	$	3.95
December 31, 2014	$	5.02

(f) Changes in Standardized Measure of Discounted Future Net Cash Flow


	Year ended December 31,
	2012		2013		2014
Sales of oil and gas, net of productions costs	$	(147)	$	(543)	$	(1,158)
Net changes in prices and production costs		(1,631)		1,061		(184)
Development costs incurred during the period		296		384		564
Net changes in future development costs		(92)		(181)		(102)
Extensions, discoveries and other additions		813		3,441		5,759
Acquisitions		—		2		42
Divestitures		(1,277)		—		—
Revisions of previous quantity estimates		88		(270)		(828)
Accretion of discount		322		192		600
Net change in income taxes		653		(1,165)		(2,198)
Other changes		106		(12)		630
Net increase (decrease)		(869)		2,909		3,125
Beginning of year		2,470		1,601		4,510
End of year	$	1,601	$	4,510	$	7,635