Supplemental Oil and Natural Gas Information (unaudited)

12 Months Ended

Dec. 31, 2018

Supplemental Oil and Natural Gas Information (unaudited)

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,
	2018			2017
Oil and natural gas properties:
Unproved properties	$	482,475		$	459,549
Proved properties		2,188,233			1,896,081
Total oil and natural gas properties		2,670,708			2,355,630
Less accumulated depreciation, depletion and amortization		(1,380,650	)		(1,248,200	)
Net oil and natural gas properties	$	1,290,058		$	1,107,430

(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,
	2018		2017		2016
Acquisition costs:
Unproved properties	$	107,862	$	57,498	$	24,764
Proved properties		4,072		—		—
Development cost		239,467		257,119		150,778
Exploration cost		20,957		18,791		20,127
Total acquisition, development and exploration costs	$	372,358	$	333,408	$	195,669

The following information represents estimates of the Company’s proved reserves as of December 31, 2018 and December 31, 2017, 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, 2018, 2017, and 2016 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 and Pennsylvania. 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 States of Ohio and Pennsylvania. All of the estimates of the proved reserves at December 31, 2018 and December 31, 2017 and 2016, were prepared by SIS and NSAI, our independent petroleum engineers, respectively. 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, 2018, 2017, and 2016 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, 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
Revisions		5.6			(8,307.5	)		231.2			(42.8	)
Extensions and discoveries		515.8			4,059.4			2,995.7			558.1
Acquisitions		9.9			551			522			16.3
Divestitures		(0.2	)		—			—			(0.2	)
Production		(90.0	)		(3,503.0	)		(2,377.8	)		(125.3	)
End of year, December 31, 2018		1,531.2			34,730.9			20,852.1			1,864.7
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
December 31, 2018		501.0			20,213.8			8,058.7			670.7
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
December 31, 2018		1,030.2			14,517.2			12,793.4			1,194.1

2016 Changes in Reserves

•

Extensions of 196.1 Bcfe primarily from the development of the Company’s Utica asset.

•

Positive revisions of 14.8 Bcfe as a result of a negative revision of 50.8 Bcfe due to reductions in SEC pricing and a negative revision of 17.9 Bcfe due to changes in differentials. This was offset by a positive revision of 83.5 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate.

•

4.1 Bcfe related to acquiring proved developed and proved undeveloped leasehold acreage in the Utica Shale.

•

10.7 Bcfe related to divesting proved developed and proved undeveloped leasehold acreage in the Utica Shale.

2017 Changes in Reserves

•

Extensions of 405.1 Bcfe primarily from 361.0 Bcfe of development of the Company’s operated Utica asset. The Company also added 0.3 Bcfe from one non-operated Utica well through development. In addition, the Company proved 43.8 Bcfe from 3 Ohio Marcellus wells due to development in the Ohio Marcellus asset.

•

Positive revisions of 695.6 Bcfe as a result of a positive revision of 607.2 Bcfe due to improvements in SEC pricing, a positive revision of 61.4 Bcfe due to changes in pricing differentials, and a positive revision of 69.6 Bcfe primarily driven by proved developed producing wells in aggregate outperforming the previous estimate. This was offset by a negative revision of 42.6 Bcfe due a decision to not develop certain proved, undeveloped reserves within five years.

2018 Changes in Reserves

•

Extensions of 558.1 Bcfe from the development of 148.3 Bcfe of unproved wells to proved developed, 398.2 Bcfe from the development of the Company’s operated Utica asset and 11.6 Bcfe from the Company’s operated Marcellus asset.

•

16.3 Bcfe related to acquiring proved developed leasehold acreage in the Indian Castle/Flat Creek and Utica Shales.

•

0.2 Bcfe related to divesting a non-operated proved developed well in the Utica Shale.

•

Negative revisions of 42.8 Bcfe as a result of a positive revision of 15.0 Bcfe due to improvements in SEC pricing, a positive revision of 6.8 Bcfe due to changes in pricing differentials and a positive revision of 67.5 Bcfe primarily driven by proved developed producing wells outperforming the previous estimate. This was offset by a negative revision of 98.0 Bcfe due to changes in well spacing and 34.1 Bcfe due to changes in the five year development plan.

F-34

(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, 2018 and 2017 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, 2018, 2017, and 2016 (in thousands):

	December 31,
	2018			2017			2016
Future cash inflows (total revenues)	$	6,730,000		$	4,750,238		$	1,143,142
Future production costs		(2,964,098	)		(2,332,310	)		(725,724	)
Future development costs (capital costs)		(855,932	)		(879,399	)		(116,988	)
Future income tax expense		(136,472	)		—			—
Future net cash flows		2,773,498			1,538,529			300,430
10% annual discount for estimated timing of cash flows		(1,444,188	)		(808,843	)		(94,449	)
Standardized measure of Discounted Future Net Cash Flow	$	1,329,310		$	729,686		$	205,981

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,
	2018			2017			2016
Standardized Measure, beginning of the year	$	729,686		$	205,981		$	212,865
Net change in prices and production costs		369,578			653,347			(33,507	)
Net change in future development costs		87,466			(385,042	)		1,552
Sales, less production costs		(321,802	)		(226,324	)		(99,768	)
Extensions		363,708			135,734			79,941
Acquisitions		7,468			2,365			1,045
Divestitures		(20	)		—			(5,231	)
Revisions of previous quantity estimates		19,910			322,917			15,754
Previously estimated development costs incurred		65,035			34,102			4,886
Net changes in taxes		(37,345	)		—			—
Accretion of discount		72,969			20,598			21,287
Changes in timing and other		(27,343	)		(33,992	)		7,157
Standardized Measure, end of year	$	1,329,310		$	729,686		$	205,981