(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)	2017		2018
Proved properties	$	11,096,462		12,705,672
Unproved properties		2,266,673		1,767,600
		13,363,135		14,473,272
Accumulated depletion and depreciation		(2,783,832)		(3,615,680)
Net capitalized costs	$	10,579,303		10,857,592

(b) Costs Incurred in Certain Oil and Gas Activities


	Year ended December 31,
(In thousands)	2016		2017		2018
Acquisition costs:
Proved property	$	134,113		175,650		—
Unproved property		611,631		204,272		172,387
Development costs		1,000,903		897,287		1,164,800
Exploration costs		326,856		384,698		323,773
Total costs incurred	$	2,073,503		1,661,907		1,660,960


	Year ended December 31,
(In thousands)	2016		2017		2018
Revenues	$	1,755,061		2,747,920		3,652,894
Operating expenses:
Production expenses		999,516		1,279,217		1,601,985
Exploration expenses		6,862		8,538		4,958
Depletion and depreciation		700,274		694,332		832,326
Impairment of unproved properties		162,935		159,598		549,437
Results of operations before income tax (expense) benefit		(114,526)		606,235		664,188
Income tax (expense) benefit		43,334		(228,096)		(156,350)
Results of operations	$	(71,192)		378,139		507,838

(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, 2016, 2017, and 2018 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 oil, condensate, NGLs 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 commodity prices, cash flows from operations, future drilling and completion costs, and other economic factors.


	Natural gas (Bcf)	NGLs (MMBbl)	Oil and condensate (MMBbl)	Equivalents (Bcfe)
Proved reserves:
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
Revisions	342	(22)	(6)	176
Extensions, discoveries and other additions	1,644	77	7	2,148
Production	(591)	(36)	(2)	(822)
Purchases of reserves	289	13	1	373
December 31, 2017	11,098	989	38	17,261
Revisions	(1,087)	8	(1)	(1,042)
Extensions, discoveries and other additions	2,125	98	12	2,781
Production	(711)	(43)	(3)	(989)
Purchases of reserves	—	—	—	—
December 31, 2018	11,425	1,052	46	18,011


	Natural gas (Bcf)	NGLs (MMBbl)	Oil and condensate (MMBbl)	Equivalents (Bcfe)
Proved developed reserves:
December 31, 2016	4,426	401	13	6,914
December 31, 2017	5,587	467	16	8,488
December 31, 2018	6,669	600	20	10,389
Proved undeveloped reserves:
December 31, 2016	4,988	556	25	8,472
December 31, 2017	5,511	522	22	8,773
December 31, 2018	4,756	452	26	7,622

Significant items included in the categories of proved developed and undeveloped reserve changes for the years 2016, 2017, and 2018 in the above table include the following:

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.

Net downward revisions of 404 Bcfe include:

Upward 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.

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

Downward 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 updated development plan targeting more liquids-rich areas in our portfolio which have better economic returns.

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

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

We produced 676 Bcfe during the year ended December 31, 2016.

2017 Changes in Reserves

Extensions, discoveries, and other additions of 2,148 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.

Purchases of 373 Bcfe related to the acquisition of developed and undeveloped leasehold acreage in both the Marcellus and Utica Shales.

Net upward revisions of 176 Bcfe include:

Upward revisions of 345 Bcfe related to improved well performance.

Net downward revisions of 188 Bcfe related to revisions to our 5-year development plan. This figure includes upward revisions of 2,092 Bcfe for previously proved undeveloped properties reclassified from non-proved properties at December 31, 2016 to proved undeveloped at December 31, 2017 due to their addition to our 5-year development plan, and downward revisions of 2,280 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves.

Upward revisions of 132 Bcfe were due to increases in prices for natural gas, NGLs, and oil.

Downward revisions of 113 Bcfe are due to a decrease in our assumed future ethane recovery.

We produced 822 Bcfe during the year ended December 31, 2017.

2018 Changes in Reserves

Extensions, discoveries, and other additions of 2,781 Bcfe resulted from delineation and development drilling in both the Marcellus and Utica Shales.

Net downward revisions of 1,042 Bcfe include:

Downward revisions of 433 Bcfe related to well performance.

Net downward revisions of 742 Bcfe related to optimization to our 5-year development plan. This figure includes upward revisions of 1,722 Bcfe for previously proved undeveloped properties reclassified from non-proved properties due to their addition to our 5-year development plan, and downward revisions of 2,464 Bcfe for locations that were not developed within 5 years of initial booking as proved reserves.

Upward revisions of 18 Bcfe were due to increases in prices for natural gas, NGLs, and oil.

Upward revisions of 115 Bcfe are due to an increase in our assumed future ethane recovery.

We produced 989 Bcfe during the year ended December 31, 2018.

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)	2016		2017		2018
Future cash inflows	$	36,800		55,824		64,199
Future production costs		(21,275)		(26,375)		(30,007)
Future development costs		(3,902)		(3,312)		(3,453)
Future net cash flows before income tax		11,623		26,137		30,739
Future income tax expense		(1,042)		(4,104)		(5,505)
Future net cash flows		10,581		22,033		25,234
10% annual discount for estimated timing of cash flows		(7,294)		(13,406)		(14,756)
Standardized measure of discounted future net cash flows	$	3,287		8,627		10,478

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


December 31, 2016	$	2.39
December 31, 2017	$	3.23
December 31, 2018	$	3.56

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


	Year ended December 31,
(in millions)	2016		2017		2018
Sales of oil and gas, net of productions costs	$	(756)		(1,469)		(2,051)
Net changes in prices and production costs		(1,540)		3,918		707
Development costs incurred during the period		733		627		755
Net changes in future development costs		212		229		37
Extensions, discoveries and other additions		673		1,448		1,925
Acquisitions		66		258		—
Divestitures		(7)		—		—
Revisions of previous quantity estimates		461		734		(53)
Accretion of discount		363		368		1,018
Net change in income taxes		12		(1,159)		(563)
Other changes		(163)		386		76
Net increase		54		5,340		1,851
Beginning of year		3,233		3,287		8,627
End of year	$	3,287		8,627		10,478