(19) 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,
(In thousands)	2015		2016
Proved properties	$	8,211,106		9,549,671
Unproved properties		1,996,081		2,331,173
		10,207,187		11,880,844
Accumulated depletion and depreciation		(1,415,005)		(2,089,500)
Net capitalized costs	$	8,792,182		9,791,344

(b) Costs Incurred in Certain Oil and Gas Activities


	Year ended December 31,
(In thousands)	2014		2015		2016
Acquisition costs:
Proved property	$	64,066		—		134,113
Unproved property		777,422		198,694		611,631
Development costs		1,536,193		1,039,301		1,000,903
Exploration costs		940,957		611,981		326,856
Total costs incurred	$	3,318,638		1,849,976		2,073,503


	Year ended December 31,
(In thousands)	2014		2015		2016
Revenues	$	1,736,752		1,375,128		1,755,061
Operating expenses:
Production expenses		578,672		773,697		999,516
Exploration expenses		27,893		3,846		6,862
Depletion and depreciation		418,744		614,700		700,274
Impairment of unproved properties		15,198		104,321		162,935
Results of operations before income tax expense		696,245		(121,436)		(114,526)
Income tax (expense) benefit		(263,126)		45,497		43,334
Results of operations	$	433,119		(75,939)		(71,192)

(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 Company’s royalty and net working interest share of the reserves in oil and gas properties. Net proved oil and gas reserves for the years ended December 31, 2014, 2015, and 2016 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, 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, 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 of reserves	29	—	—		29
Production	(317)	(7)	(1)		(368)
December 31, 2014	10,535	330	28		12,683
Revisions	(2,816)	176	(8)		(1,801)
Extensions, discoveries and other additions	2,253	97	8		2,878
Production	(439)	(16)	(2)		(545)
December 31, 2015	9,533	587	26		13,215
Revisions	(2,069)	275	3		(404)
Extensions, discoveries and other additions	1,990	99	9		2,637
Production	(505)	(27)	(2)		(676)
Purchases of reserves	475	23	2		624
Sales of reserves in place	(10)	—	—		(10)
December 31, 2016	9,414	957	38		15,386

^(a)

Less than 1.0.


	Natural gas (Bcf)	NGLs (MMBbl)	Oil and condensate (MMBbl)	Equivalents (Bcfe)
Proved developed reserves:
December 31, 2014	3,285	80	6	3,803
December 31, 2015	3,627	360	8	5,838
December 31, 2016	4,426	401	13	6,914
Proved undeveloped reserves:
December 31, 2014	7,250	250	22	8,880
December 31, 2015	5,906	227	18	7,377
December 31, 2016	4,988	556	25	8,472

Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2014, 2015, and 2016 in the above table include the following:

2014 Changes in Reserves

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 the Company’s leasehold acquisition efforts.

Positive 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 were 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 prices for NGLs and oil.

2015 Changes in Reserves

Extensions, discoveries, and other additions of 2,878 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.

Positive revisions of 1,091 Bcfe due to partial ethane recovery is a result of changing from ethane rejection at December 31, 2014 to partial ethane recovery in 2015. In 2015, the Company began ethane recovery and changed its underlying production assumptions to the recovery of approximately 11,500 gross barrels per day of ethane at December 31, 2015.

Negative performance revisions of 358 Bcfe resulted from the revised statistical analysis of reserves based on actual production results.

Negative revisions of 2,332 Bcfe were due to the SEC 5-year development rule because the Company no longer expected certain locations in the eastern portion of its Marcellus acreage containing primarily dry gas to be developed within five years.

Negative revisions of 202 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil.

2016 Changes in Reserves

Extensions, discoveries and other additions of 2,637 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales, which was aided in 2016 by longer laterals than in previous years and the utilization of advanced completion techniques.

Purchases of 624 Bcfe relate to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales.

Positive revisions of 1,359 Bcfe are due to an increase in our actual and assumed future ethane recovery rate based on existing sales contracts for ethane.

Positive performance revisions of 762 Bcfe primarily relate to improved well performance.

Negative revisions of 2,478 Bcfe were due to the impact of the SEC 5-year development rule. Due to the SEC 5-year development rule, these primarily dry gas reserves were displaced by our current development plan targeting more liquids-rich areas in our portfolio which have better economic returns.

Negative revisions of 47 Bcfe were due to the decreases in prices for natural gas, NGLs, and oil.

A negative revision of 10 Bcfe was related to our sale of producing and non-producing leasehold in Pennsylvania.

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)	2014		2015		2016
Future cash inflows	$	63,632		35,179		36,800
Future production costs		(21,722)		(17,393)		(21,275)
Future development costs		(8,212)		(5,217)		(3,902)
Future net cash flows before income tax		33,698		12,569		11,623
Future income tax expense		(10,726)		(1,708)		(1,042)
Future net cash flows		22,972		10,861		10,581
10% annual discount for estimated timing of cash flows		(15,337)		(7,628)		(7,294)
Standardized measure of discounted future net cash flows	$	7,635		3,233		3,287

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


December 31, 2014	$	5.02
December 31, 2015	$	2.66
December 31, 2016	$	2.39

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


	Year ended December 31,
(in millions)	2014		2015		2016
Sales of oil and gas, net of productions costs	$	(1,158)		(601)		(756)
Net changes in prices and production costs		(184)		(9,416)		(1,540)
Development costs incurred during the period		564		769		733
Net changes in future development costs		(102)		671		212
Extensions, discoveries and other additions		5,759		861		673
Acquisitions		42		—		66
Divestitures		—		—		(7)
Revisions of previous quantity estimates		(828)		(1,167)		461
Accretion of discount		600		1,132		363
Net change in income taxes		(2,198)		3,284		12
Other changes		630		65		(163)
Net increase (decrease)		3,125		(4,402)		54
Beginning of year		4,510		7,635		3,233
End of year	$	7,635		3,233		3,287