Note 19—Supplemental Oil and Natural Gas Information (unaudited)

(a) Capitalized Costs

A summary of the Company’s capitalized costs are contained in the table below (in thousands):

	December 31,
	2016			2015
Oil and natural gas properties:
Unproved properties	$	526,270		$	720,159
Proved properties		1,545,860			1,288,609
Total oil and natural gas properties		2,072,130			2,008,768
Less accumulated depreciation, depletion and amortization		(1,131,378	)		(1,022,771	)
Net oil and natural gas properties	$	940,752		$	985,997

(b) Costs Incurred in Oil and Natural Gas Property Acquisition and Development Activities

A summary of the Company’s cost incurred in oil and natural gas property acquisition and development activities is set forth below (in thousands):

	December 31,
	2016		2015		2014
Acquisition costs:
Unproved properties	$	24,764	$	24,722	$	134,156
Proved properties		—		—		—
Development cost		150,778		259,655		714,796
Exploration cost		20,127		20,530		21,186
Total acquisition, development and exploration costs	$	195,669	$	304,907	$	870,138

The following information represents estimates of the Company’s proved reserves as of December 31, 2016 and December 31, 2015, which have been prepared and presented under SEC rules. These rules require companies to prepare their reserve estimates using specified reserve definitions and pricing based on a 12-month unweighted average of the first-day-of-the-month pricing. The pricing that was used for estimates of the Company’s reserves as of December 31, 2016, 2015, and 2014 was based on an unweighted average 12-month average West Texas Intermediate posted price per Bbl for oil and NGLs and a Henry Hub spot natural gas price per MMBtu for natural gas.

Subject to limited exceptions, proved undeveloped reserves may only be booked if they relate to wells scheduled to be drilled within five years of the date of booking. This requirement may limit the Company’s potential to record additional proved undeveloped reserves as it pursues its drilling program, particularly as it develops its significant acreage in the Appalachian Basin of Ohio. Moreover, the Company may be required to write down its proved undeveloped reserves if it does not drill on those reserves within the required five-year timeframe. The Company does not have any proved undeveloped reserves which have remained undeveloped for five years or more.

The Company’s proved oil and natural gas reserves are all located in the United States, within the State of Ohio. All of the estimates of the proved reserves at December 31, 2016, 2015, and 2014, were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers. Proved reserves were estimated in accordance with the guidelines established by the SEC and the FASB.

Oil and natural gas reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates.

Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

The following table provides a roll-forward of the total proved reserves for the year ended December 31, 2016, 2015, and 2014 as well as proved developed and proved undeveloped reserves at the beginning and end of each respective year:

	Natural Gas (Bcf)			Natural Gas Liquids (MBbl)			Oil (MBbl)			TOTAL (Bcfe)
End of year, December 31, 2013		52.3			1,938.4			2,417.4			78.5
Revisions		(12.1	)		(739.7	)		(462.6	)		(19.3	)
Extensions and discoveries		235.8			10,216.3			4,337.5			323.1
Production		(19.8	)		(536.0	)		(594.9	)		(26.5	)
End of year, December 31, 2014		256.3			10,879.0			5,697.4			355.8
Revisions		(115.3	)		(4,705.7	)		(1,550.1	)		(152.9	)
Extensions and discoveries		182.6			4,035.7			2,496.3			221.7
Production		(49.5	)		(2,450.3	)		(1,950.5	)		(75.9	)
End of year, December 31, 2015		274.1			7,758.7			4,693.1			348.8
Revisions		(0.1	)		1,273.7			1,196.8			14.8
Extensions and discoveries		175.4			2,156.0			1,300.2			196.1
Acquisitions		3.8			24.8			15.1			4.1
Divestitures		(5.9	)		(91.5	)		(703.7	)		(10.7	)
Production		(60.9	)		(2,446.2	)		(1,343.8	)		(83.7	)
End of year, December 31, 2016		386.4			8,675.5			5,157.7			469.4
Proved developed reserves:
December 31, 2014		133.0			6,758.6			3,880.9			196.8
December 31, 2015		209.5			7,245.7			4,239.2			278.4
December 31, 2016		226.1			7,520.0			4,439.5			297.8
Proved undeveloped reserves:
December 31, 2014		123.4			4,120.4			1,816.4			159.0
December 31, 2015		64.5			513.0			453.9			70.3
December 31, 2016		160.4			1,155.5			718.1			171.6

Extensions and discoveries of 196.1 Bcfe and 221.7 Bcfe during the years ended December 31, 2016 and December 31, 2015, respectively, resulted primarily from the drilling of new wells during each year and from new proved undeveloped locations added during each year.

(d) Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows does not purport to be, nor should it be interpreted to present, the fair value of the oil and natural gas reserves of the property. An estimate of fair value would take into account, among other things, the recovery of reserves not presently classified as proved, the value of unproved properties, and consideration of expected future economic and operating conditions. The estimates of future cash flows and future production and development costs as of December 31, 2016 and 2015 are based on the unweighted arithmetic average first-day-of-the-month price for the preceding 12-month period. Estimated future production of proved reserves and estimated future production and development costs of proved reserves are based on current costs and economic conditions. All wellhead prices are held flat over the forecast period for all reserve categories. The estimated future net cash flows are then discounted at a rate of 10%. The standardized measure of discounted future net cash flows relating to proved oil and natural gas reserves is as follows at December 31, 2016, 2015, and 2014 (in thousands):

	December 31,
	2016			2015			2014
Future cash inflows (total revenues)	$	1,143,142		$	975,664		$	1,870,319
Future production costs		(725,724	)		(592,073	)		(728,041	)
Future development costs (capital costs)		(116,988	)		(83,532	)		(350,187	)
Future income tax expense		—			—			(277,500	)
Future net cash flows		300,430			300,059			514,591
10% annual discount for estimated timing of cash flows		(94,449	)		(87,194	)		(183,934	)
Standardized measure of Discounted Future Net Cash Flow	$	205,981		$	212,865		$	330,657

It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of the Company’s proved reserves. The Company cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.

(e) Changes in the Standardized Measure of Discounted Future Net Cash Flows

A summary of the changes in the standardized measure of discounted future net cash flows are contained in the table below (in thousands):

	December 31,
	2016			2015			2014
Standardized Measure, beginning of the year	$	212,865		$	330,657		$	155,295
Net change in prices and production costs		(33,507	)		(372,664	)		(52,642	)
Net change in future development costs		1,552			79,244			(2,122	)
Sales, less production costs		(99,768	)		(121,646	)		(104,099	)
Extensions		79,941			107,749			491,067
Acquisitions		1,045			—			—
Divestitures		(5,231	)		—			—
Revisions of previous quantity estimates		15,754			(97,210	)		(38,201	)
Previously estimated development costs incurred		4,886			62,906			16,807
Accretion of discount		21,287			50,939			15,529
Net change in taxes		—			178,732			(178,732	)
Changes in timing and other		7,157			(5,842	)		27,755
Standardized Measure, end of year	$	205,981		$	212,865		$	330,657