Note 18—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,
	2017			2016
Oil and natural gas properties:
Unproved properties	$	459,549		$	526,270
Proved properties		1,896,081			1,545,860
Total oil and natural gas properties		2,355,630			2,072,130
Less accumulated depreciation, depletion and amortization		(1,248,200	)		(1,131,378	)
Net oil and natural gas properties	$	1,107,430		$	940,752

(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,
	2017		2016		2015
Acquisition costs:
Unproved properties	$	57,498	$	24,764	$	24,722
Proved properties		—		—		—
Development cost		257,119		150,778		259,655
Exploration cost		18,791		20,127		20,530
Total acquisition, development and exploration costs	$	333,408	$	195,669	$	304,907

The following information represents estimates of the Company’s proved reserves as of December 31, 2017 and December 31, 2016, 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, 2017, 2016, and 2015 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, 2017, 2016, and 2015, 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, 2017, 2016, and 2015 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, 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	)		(75.8	)
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
Revisions		515.1			20,327.3			9,746.8			695.6
Extensions and discoveries		274.4			15,598.8			6,192.9			405.1
Acquisitions		1.6			42.6			5.8			1.9
Production		(87.4	)		(2,713.6	)		(1,622.4	)		(113.4	)
End of year, December 31, 2017		1,090.1			41,930.6			19,480.8			1,458.6
Proved developed reserves:
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
December 31, 2017		334.6			13,782.9			6,449.6			456.0
Proved undeveloped reserves:
December 31, 2015		64.5			513.0			453.9			70.3
December 31, 2016		160.4			1,155.5			718.1			171.6
December 31, 2017		755.5			28,147.7			13,031.2			1,002.6

Extensions and discoveries of 405.1 Bcfe and 196.1 Bcfe during the years ended December 31, 2017 and December 31, 2016, respectively, resulted primarily from the drilling of new wells during each year and from new proved undeveloped locations. The revisions consisted of positive revisions of 27.0 Bcfe due to technical adjustments and 668.6 Bcfe due to pricing and differential changes.

(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, 2017 and 2016 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, 2017, 2016, and 2015 (in thousands):

	December 31,
	2017			2016			2015
Future cash inflows (total revenues)	$	4,750,238		$	1,143,142		$	975,664
Future production costs		(2,332,310	)		(725,724	)		(592,073	)
Future development costs (capital costs)		(879,399	)		(116,988	)		(83,532	)
Future income tax expense		—			—			—
Future net cash flows		1,538,529			300,430			300,059
10% annual discount for estimated timing of cash flows		(808,843	)		(94,449	)		(87,194	)
Standardized measure of Discounted Future Net Cash Flow	$	729,686		$	205,981		$	212,865

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,
	2017			2016			2015
Standardized Measure, beginning of the year	$	205,981		$	212,865		$	330,657
Net change in prices and production costs		653,347			(33,507	)		(372,664	)
Net change in future development costs		(385,042	)		1,552			79,244
Sales, less production costs		(226,324	)		(99,768	)		(121,646	)
Extensions		135,734			79,941			107,749
Acquisitions		2,365			1,045			—
Divestitures		—			(5,231	)		—
Revisions of previous quantity estimates		322,917			15,754			(97,210	)
Previously estimated development costs incurred		34,102			4,886			62,906
Accretion of discount		20,598			21,287			50,939
Net change in taxes		—			—			178,732
Changes in timing and other		(33,992	)		7,157			(5,842	)
Standardized Measure, end of year	$	729,686		$	205,981		$	212,865