Supplemental Oil and Natural Gas Information (unaudited)

12 Months Ended

Dec. 31, 2019

Supplemental Oil and Natural Gas Information (unaudited)

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,
	2019			2018
Oil and natural gas properties:
Unproved properties	$	508,576		$	482,475
Proved properties		2,783,232			2,188,233
Total oil and natural gas properties		3,291,808			2,670,708
Less accumulated depreciation, depletion and amortization		(1,532,127	)		(1,380,650	)
Net oil and natural gas properties	$	1,759,681		$	1,290,058

(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,
	2019		2018		2017
Acquisition costs:
Unproved properties	$	106,758	$	107,862	$	57,498
Proved properties		201,884		4,072		—
Development cost		339,628		239,467		257,119
Exploration cost		11,142		20,957		18,791
Asset retirement obligations		29,346		—		—
Total acquisition, development and exploration costs	$	688,758	$	372,358	$	333,408

The following information represents estimates of the Company’s proved reserves as of December 31, 2019 and December 31, 2018, 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, 2019, 2018, and 2017 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 primarily in the Appalachian Basin of Ohio, Pennsylvania and West Virginia. 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, primarily within the States of Ohio, Pennsylvania and West Virginia. All of the estimates of the proved reserves at December 31, 2019 and 2018 and December 31, 2017, 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, 2019, 2018, and 2017 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, 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			551.4			522.2			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
Revisions		(77.0	)		4,454.5			(1,569.8	)		(59.6	)
Extensions and discoveries		418.7			19,016.3			11,078.1			599.2
Acquisitions		418.9			14,844.0			2,915.2			525.5
Production		(154.1	)		(4,686.3	)		(2,950.8	)		(200.0	)
End of year, December 31, 2019		2,137.7			68,359.4			30,324.8			2,729.8
Proved developed reserves:
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
December 31, 2019		1,183.2			39,316.3			12,512.6			1,494.2
Proved undeveloped reserves:
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
December 31, 2019		954.5			29,043.2			17,812.2			1,235.6

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.

2019 Changes in Reserves

•

Extensions of 599.2 Bcfe from the development of 100.5 Bcfe of unproved wells to proved developed, of which 70.2 Bcfe is from the development of the Company’s operated Marcellus asset, 23.3 Bcfe is from the Company’s operated Utica asset and 7.0 Bcfe was added from participation in non-operated wells. Extensions of 498.7 Bcfe from the development of unproved wells to proved undeveloped, of which 269.4 Bcfe is from the Company’s operated Utica asset and 229.3 Bcfe is from the Company’s operated Marcellus asset.

•

525.5 Bcfe related to acquiring proved assets from the merger with BRMR.

•

Revisions to previous estimates are comprised of 59.6 Bcfe of negative revisions primarily due to a negative adjustment of 277.3 due to downward SEC pricing and differentials and 44.2 Bcfe due adjustments in the drilling schedule. The negative revisions have been offset by a positive revision of 261.9 Bcfe due to well performance, capital allocation, and lease operating expense.

(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, 2019 and 2018 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, 2019, 2018, and 2017 (in thousands):

	December 31,
	2019			2018			2017
Future cash inflows (total revenues)	$	8,212,521		$	6,730,000		$	4,750,238
Future production costs		(3,867,182	)		(2,964,098	)		(2,332,310	)
Future development costs (capital costs)		(982,321	)		(855,932	)		(879,399	)
Future income tax expense		(633,086	)		(136,472	)		—
Future net cash flows		2,729,932			2,773,498			1,538,529
10% annual discount for estimated timing of cash flows		(1,534,108	)		(1,444,188	)		(808,843	)
Standardized measure of Discounted Future Net Cash Flow	$	1,195,824		$	1,329,310		$	729,686

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.

F-37

(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,
	2019			2018			2017
Standardized Measure, beginning of the year	$	1,329,310		$	729,686		$	205,981
Net change in prices and production costs		(531,056	)		369,578			653,347
Net change in future development costs		28,481			87,466			(385,042	)
Sales, less production costs		(327,373	)		(321,802	)		(226,324	)
Extensions		251,343			363,708			135,734
Acquisitions		387,117			7,468			2,365
Divestitures		—			(20	)		—
Revisions of previous quantity estimates		7,345			19,910			322,917
Previously estimated development costs incurred		245,931			65,035			34,102
Net changes in taxes		(237,482	)		(37,345	)		—
Accretion of discount		132,931			72,969			20,598
Changes in timing and other		(90,723	)		(27,343	)		(33,992	)
Standardized Measure, end of year	$	1,195,824		$	1,329,310		$	729,686