Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

12 Months Ended

Dec. 31, 2017

Supplemental Information on Oil and Natural Gas Producing Activities (Unaudited)

The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities. Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved oil, natural gas and NGL reserves.

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Company’s capitalized costs for oil and natural gas activities consisted of the following (in thousands):



	Successor						Predecessor
	December 31,			December 31,			December 31,
	2017			2016			2015
Oil and natural gas properties
Proved	$	1,056,806		$	840,201		$	12,529,681
Unproved	100,884			74,937			363,149
Total oil and natural gas properties	1,157,690			915,138			12,892,830
Less accumulated depreciation, depletion and impairment	(460,431		)	(353,030		)	(11,149,888		)
Net oil and natural gas properties capitalized costs	$	697,259		$	562,108		$	1,742,942

Costs Incurred in Oil and Natural Gas Property Acquisition, Exploration and Development

Costs incurred in oil and natural gas property acquisition, exploration and development activities which have been capitalized are summarized as follows (in thousands):



	Successor				Predecessor
	Year Ended December 31, 2017		Period from October 2, 2016 through December 31, 2016		Period from January 1, 2016 through October 1, 2016		Year Ended December 31, 2015
Acquisitions of properties
Proved	$	7,092	$	5,142	$	3,897	$	35,376
Unproved	91,139		5,491		1,899		210,065
Exploration(1)	8,850		—		1,234		29,297
Development	187,264		27,429		149,924		571,562
Total cost incurred	$	294,345	$	38,062	$	156,954	$	846,300

____________________


(1)	Includes 3-D seismic costs of $7.1 million for the year ended December 31, 2015.

Results of Operations for Oil and Natural Gas Producing Activities

The following table presents the Company’s results of operations from oil and natural gas producing activities (in thousands), which exclude any interest costs or indirect general and administrative costs and, therefore, are not necessarily indicative of the contribution to net earnings of the Company’s operations.



	Successor					Predecessor
	Year Ended December 31, 2017		Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015
Revenues	$	356,210	$	98,307		$	279,971		$	707,434
Expenses
Production costs	116,372		27,640			135,715			324,141
Depreciation and depletion	118,035		36,061			90,978			324,390
Impairment	—		319,087			657,392			4,473,787
Total expenses	234,407		382,788			884,085			5,122,318
Income (loss) before income taxes	121,803		(284,481		)	(604,114		)	(4,414,884		)
Income tax expense (benefit)(1)	47,722		(112,427		)	(229,986		)	(1,680,746		)
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	74,081	$	(172,054	)	$	(374,128	)	$	(2,734,138	)

____________________


(1)	Income tax expense (benefit) is hypothetical and is calculated by applying the Company’s statutory tax rate to income (loss) before income taxes attributable to our oil and natural gas producing activities, after giving effect to permanent differences and tax credits.

Oil, Natural Gas and NGL Reserve Quantities

Proved oil, natural gas and NGL reserves are those quantities, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible, based on oil, natural gas and NGL prices used to estimate reserves, from a given date forward from known reservoirs, and under existing economic conditions, operating methods, and government regulation prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

The term “reasonable certainty” implies a high degree of confidence that the quantities of oil, natural gas and NGLs actually recovered will equal or exceed the estimate. To achieve reasonable certainty, the Company’s engineers and independent petroleum consultants relied on technologies that have been demonstrated to yield results with consistency and repeatability. The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. The accuracy of the reserve estimates is dependent on many factors, including the following:


•	the quality and quantity of available data and the engineering and geological interpretation of that data;


•	estimates regarding the amount and timing of future costs, which could vary considerably from actual costs;


•	the accuracy of mandated economic assumptions; and


•	the judgment of the personnel preparing the estimates.

Proved developed reserves are proved reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure is required for recompletion.

The table below represents the Company’s estimate of proved oil, natural gas and NGL reserves attributable to the Company’s net interest in oil and natural gas properties, all of which are located in the continental United States, based upon the evaluation by the Company and its independent petroleum engineers of pertinent geoscience and engineering data in accordance

with the SEC’s regulations. Estimates of the substantial majority of the Company’s proved reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of the Company’s senior management with professional training in petroleum engineering to ensure that the Company consistently applies rigorous professional standards and the reserve definitions prescribed by the SEC.

Cawley, Gillespie & Associates, Inc. (“CG&A”), Ryder Scott Company, L.P. (“Ryder Scott”) and Netherland, Sewell & Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs attributable to the majority of the Company’s net interest in oil and natural gas properties as of the end of 2017, 2016 and 2015. CG&A, Ryder Scott and Netherland Sewell are independent petroleum engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Company or its properties and are not employed on a contingent basis. The remaining proved reserves were based on Company estimates.

The Company believes the geoscience and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic conditions change.

2017 Activity. During 2017, the Company recorded extensions and discoveries of 19.4 MMBoe, primarily from successful drilling in its NW STACK play in the Mid-Continent area and its North Park Basin properties, sold 1.9 MMBoe of proved reserves, and recorded upward revisions of 10.9 MMBoe, primarily as a result of significantly higher commodity prices in 2017 and minor revisions due to well performance.

2016 Activity. During 2016, on a pro forma combined basis, Predecessor Company and Successor Company recognized total downward revisions of prior estimates of approximately 105.4 MMBoe, predominantly from revisions of approximately 94.7 MMBoe due to well performance and 12.1 MMBoe due to a decrease in commodity prices. The negative revisions from well performance were from the Mid-Continent area and resulted from steeper than anticipated well production decline rates for Mississippian horizontal wells in areas with increased natural fracture density and that have been developed with three or more horizontal wells per section as inter-well pressure communication has had more impact on well performance than originally forecasted. Additionally, changing pressure conditions in the Company’s Mississippian wells producing with artificial lift have resulted in increased production decline rates that are now becoming more predictable on a large group of base wells as this population of wells has been producing for more than two years. Of the total performance revisions, approximately 85% were to gas and associated NGL reserves, with the revisions to gas mostly from changes made to late-life decline rates, and 15% were to oil reserves. Other decreases of reserves excluding production included the sale of WTO reserves of 24.6 MMBoe and 19.1 MMBoe of adjustment from change in accounting for Trusts. These decreases were partially offset by approximately 7.8 MMBoe of extensions due to successful drilling.

2015 Activity. During 2015, the Company recognized additional oil, NGL and natural gas reserves from extensions and discoveries of 9.7 MMBbls, 9.3 MMBbls, and 160.9 Bcf, respectively, primarily due to successful drilling in the Mississippian formation in the Mid-Continent area. Acquisition of the North Park Basin assets, located in Jackson County, Colorado, in December 2015 added 27.6 MMBoe of reserves. These positive revisions were offset by (i) negative pricing revisions of approximately 54 MMBbls for oil, 36 MMBbls for NGLs and 687 Bcf for natural gas, due primarily to significantly lower commodity prices in 2015, and (ii) negative revisions of approximately 16 MMBbls for oil, 1 MMBbls for NGLs and 74 Bcf for natural gas primarily from well performance in the Mid-Continent.

The summary below presents changes in the Company’s estimated reserves.



	Oil		NGL		Natural Gas		Total
	(MBbls)		(MBbls)		(MMcf)(1)		MBoe
Proved developed and undeveloped reserves
As of December 31, 2014(2) - Predecessor	126,031		91,786		1,788,233		515,856
Revisions of previous estimates	(70,708	)	(37,384	)	(759,106	)	(234,610	)
Acquisitions of new reserves	22,447		2,460		15,952		27,566
Extensions and discoveries	9,741		9,257		160,865		45,809
Production	(9,600	)	(5,044	)	(92,104	)	(29,995	)
As of December 31, 2015(2) - Predecessor	77,911		61,075		1,113,840		324,626
Adoption of ASU 2015-02	(6,971	)	(3,695	)	(50,508	)	(19,084	)
Revisions of previous estimates	(39,973	)	(21,475	)	(415,568	)	(130,709	)
Extensions and discoveries	987		472		7,955		2,785
Sales of reserves in place	(387	)	—		(145,267	)	(24,598	)
Production	(4,315	)	(3,358	)	(44,124	)	(15,027	)
As of October 1, 2016 - Predecessor	27,252		33,019		466,328		137,992


Revisions of previous estimates	23,978		1,139		915		25,270
Extensions and discoveries	2,868		448		10,309		5,034
Production	(1,214	)	(999	)	(12,770	)	(4,341	)
As of December 31, 2016 - Successor	52,884		33,607		464,782		163,955
Revisions of previous estimates	804		2,628		44,679		10,879
Acquisitions of new reserves	18		70		683		202
Extensions and discoveries	12,446		1,914		30,080		19,373
Sales of reserves in place	(204	)	(529	)	(7,055	)	(1,909	)
Production	(4,157	)	(3,376	)	(44,237	)	(14,906	)
As of December 31, 2017 - Successor	61,791		34,314		488,932		177,594
Proved developed reserves
As of December 31, 2014 - Predecessor	79,022		56,823		1,203,447		336,420
As of December 31, 2015 - Predecessor	48,639		51,089		964,617		260,498
As of October 1, 2016 - Predecessor	24,541		30,238		428,050		126,121


As of December 31, 2016 - Successor	25,911		29,290		393,028		120,706
As of December 31, 2017 - Successor	25,845		29,922		407,988		123,765
Proved undeveloped reserves
As of December 31, 2014 - Predecessor	47,009		34,963		584,786		179,436
As of December 31, 2015 - Predecessor	29,272		9,986		149,223		64,129
As of October 1, 2016 - Predecessor	2,711		2,781		38,278		11,872


As of December 31, 2016 - Successor	26,973		4,317		71,754		43,249
As of December 31, 2017 - Successor	35,946		4,392		80,944		53,829

____________________


(1)	Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.


(2)	Includes proved reserves attributable to noncontrolling interests as shown in the table below:



	Predecessor
	December 31,
	2015	2014
Oil (MBbl)	7,004	11,027
NGL (MBbl)	3,694	4,761
Natural gas (MMcf)	50,508	70,833

Standardized Measure of Discounted Future Net Cash Flows (Unaudited)

The standardized measure of discounted cash flows and summary of the changes in the standardized measure computation from year to year are prepared in accordance with ASC Topic 932, Extractive Activities—Oil and Gas (“ASC Topic 932”). The assumptions underlying the computation of the standardized measure of discounted cash flows may be summarized as follows:


•	the standardized measure includes the Company’s estimate of proved oil, natural gas and NGL reserves and projected future production volumes based upon economic conditions;


•	pricing is applied based upon 12-month average market prices at December 31, 2017, 2016, and 2015 adjusted for fixed or determinable contracts that are in existence at year-end. The calculated weighted average per unit prices for the Company’s proved reserves and future net revenues were as follows:



	Successor				Predecessor
	December 31,		December 31,		December 31,
	2017		2016		2015
Oil (per barrel)	$	48.47	$	38.59	$	45.29
NGL (per barrel)	$	20.28	$	10.99	$	12.68
Natural gas (per Mcf)	$	1.90	$	1.56	$	1.87


•	future development and production costs are determined based upon actual cost at year-end;


•	the standardized measure includes projections of future abandonment costs based upon actual costs at year-end; and


•	a discount factor of 10% per year is applied annually to the future net cash flows.

The summary below presents the Company’s future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in thousands).



	Successor						Predecessor
	December 31,			December 31,			December 31,
	2017			2016			2015
Future cash inflows from production	$	4,621,615		$	3,136,762		$	6,387,944
Future production costs	(1,837,852		)	(1,454,798		)	(2,731,542		)
Future development costs(1)	(966,203		)	(665,516		)	(838,945		)
Future income tax expenses	(107		)	(142		)	(901		)
Undiscounted future net cash flows	1,817,453			1,016,306			2,816,556
10% annual discount	(1,068,159		)	(577,942		)	(1,501,994		)
Standardized measure of discounted future net cash flows(2)	$	749,294		$	438,364		$	1,314,562

____________________


(1)	Includes abandonment costs.


(2)	Includes approximately $224.6 million attributable to noncontrolling interests at December 31, 2015.

The following table represents the Company’s estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):



	Successor						Predecessor
	Year Ended December 31, 2017			Period from October 2, 2016 through December 31, 2016			Period from January 1, 2016 through October 1, 2016			Year Ended December 31, 2015
Beginning present value	$	438,364		$	392,604		$	1,314,562		$	4,087,752
Changes during the year
Adoption of ASU 2015-02	—			—			(224,965		)	—
Revenues less production	(239,838		)	(70,668		)	(144,256		)	(383,293		)
Net changes in prices, production and other costs	347,458			35,684			(394,173		)	(3,813,465		)
Development costs incurred	35,517			7,941			69,080			217,596
Net changes in future development costs	(64,484		)	(291,232		)	436,041			273,437
Extensions and discoveries	112,556			14,986			12,449			230,055
Revisions of previous quantity estimates	26,697			308,374			(728,254		)	(1,354,778		)
Accretion of discount	37,226			9,375			91,337			512,483
Net change in income taxes	23			—			402			1,426,333
Purchases of reserves in-place	454			—			—			18,429
Sales of reserves in-place	(2,977		)	—			(13,314		)	—
Timing differences and other(1)	58,298			31,300			(26,305		)	100,013
Net change for the year	310,930			45,760			(921,958		)	(2,773,190		)
Ending present value(2)	$	749,294		$	438,364		$	392,604		$	1,314,562

____________________


(1)	The change in timing differences and other are related to revisions in the Company’s estimated time of production and development.

(2)

Includes approximately $224.6 million attributable to noncontrolling interests at December 31, 2015.