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

12 Months Ended

Dec. 31, 2019

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

The supplemental information below 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):


	December 31,
	2019		2018		2017
Oil and natural gas properties
Proved	$	1,484,359	$	1,269,091	$	1,056,806
Unproved	24,603		60,152		100,884
Total oil and natural gas properties	1,508,962		1,329,243		1,157,690
Less accumulated depreciation, depletion and impairment	(1,129,622)		(580,132)		(460,431)
Net oil and natural gas properties capitalized costs	$	379,340	$	749,111	$	697,259

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):


	Year Ended December 31,
	2019		2018		2017
Acquisitions of properties
Proved	$	(210)	$	30,641	$	7,092
Unproved	2,653		4,197		91,139
Exploration	2,900		1,940		8,850
Development	156,210		158,361		187,264
Total cost incurred	$	161,553	$	195,139	$	294,345

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 impact the Company’s operations have on actual net earnings.


	Year Ended December 31,
	2019		2018		2017
Revenues	$	266,104	$	348,726	$	356,210
Expenses
Production costs	110,711		112,173		116,372
Depreciation and depletion	146,874		127,281		118,035
Impairment	409,574		—		—
Total expenses	667,159		239,454		234,407
Income (loss) before income taxes	(401,055)		109,272		121,803
Income tax (benefit) expense (1)	(105,477)		28,520		47,722
Results of operations for oil and natural gas producing activities (excluding corporate overhead and interest costs)	$	(295,578)	$	80,752	$	74,081

____________________

(1) Income tax (benefit) expense is hypothetical and is calculated by applying the Company’s statutory tax rate to (loss) income 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 following table 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. Over 90% of the Company’s proved reserves estimates 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, Ryder Scott and Netherland Sewell, independent oil and natural gas consultants, prepared the estimates of proved reserves of oil, natural gas and NGLs for over 90% of the Company’s net interest in oil and natural gas properties as of the end of one or more of 2019, 2018 and 2017. Cawley, Gillespie & Associates, 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.

2019 Activity. Proved reserves decreased from 160.2 MMBoe at December 31, 2018 to 89.9 MMBoe at December 31, 2019, primarily as a result of downward revisions of 50.9 MMBoe associated with the decrease in year-end SEC prices for oil and natural gas consisting of (i) 39.8 MMBoe from downgrading PUDs, and (ii) 11.1 MMBoe from remaining proved reserves. The Company also recorded a decrease of 10.9 MMBoe attributable to increased commodity price differentials, and a decrease of 3.2 MMBoe attributable to well performance. These reductions were partially offset by a 12.6 MMBoe increase associated with converting undeveloped well locations from SRLs to planned XRLs as well as reduced future estimated development capital on these undeveloped locations.

2018 Activity. Proved reserves decreased from 177.6 MMBoe at December 31, 2017 to 160.2 MMBoe at December 31, 2018, primarily as a result of a one-time adjustment to future workover costs in the Company's Mississippian Lime wells. As its large population of Mississippian Lime wells transition into late-life mature production, the Company has experienced increasing operating costs which have been incorporated into its 2018 reserve report. This estimate of future costs contributed to a 24.9 MMBoe decrease associated with shorter economic lives. The Company also recorded a decrease of 8.3 MMBoe attributable to well performance and a decrease of 6.6 MMBoe due to divestitures of proved reserves. These reductions were partially offset by the acquisition of 15.4 MMBoe associated with the purchase of interests in Mid-Continent wells, extensions and discoveries of 19.3 MMBoe from successful drilling in the North Park Basin and to a lesser extent the NW STACK play in the Mid-Continent, as well as recording proved undeveloped reserves at an increased well density in the North Park Basin.

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.

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, 2016	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	61,791	34,314	488,932	177,594
Revisions of previous estimates	(2,316)	(8,952)	(131,518)	(33,188)
Acquisitions of new reserves	2,146	4,131	54,436	15,350
Extensions and discoveries	11,148	2,320	35,185	19,332
Sales of reserves in place	(5,273)	(809)	(2,969)	(6,577)
Production	(3,477)	(2,829)	(36,175)	(12,335)
As of December 31, 2018	64,019	28,175	407,891	160,176
Revisions of previous estimates	(25,530)	(9,277)	(142,239)	(58,514)

Extensions and discoveries	635	94	2,127	1,084
Sales of reserves in place	(297)	(223)	(2,308)	(905)
Production	(3,519)	(2,910)	(33,164)	(11,956)
As of December 31, 2019	35,308	15,859	232,307	89,885
Proved developed reserves
As of December 31, 2017	25,845	29,922	407,988	123,765
As of December 31, 2018	18,693	22,302	307,845	92,303
As of December 31, 2019	14,078	14,532	200,853	62,086
Proved undeveloped reserves
As of December 31, 2017	35,946	4,392	80,944	53,829
As of December 31, 2018	45,326	5,873	100,046	67,873
As of December 31, 2019	21,230	1,327	31,454	27,799

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

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 SEC prices at December 31, 2019, 2018, and 2017 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:



	At December 31,
	2019		2018		2017
Oil (per Bbl)	$	50.63	$	60.86	$	48.47
NGL (per Bbl)	$	12.45	$	25.62	$	20.28
Natural gas (per Mcf)	$	1.16	$	1.77	$	1.90

•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).


	December 31,
	2019		2018		2017
Future cash inflows from production	$	2,254,530	$	5,339,265	$	4,621,615
Future production costs	(1,028,695)		(1,996,689)		(1,837,852)
Future development costs(1)	(536,081)		(1,170,113)		(966,203)
Future income tax expenses (2)	—		—		(107)
Undiscounted future net cash flows	689,754		2,172,463		1,817,453
10% annual discount	(325,464)		(1,126,860)		(1,068,159)
Standardized measure of discounted future net cash flows	$	364,290	$	1,045,603	$	749,294

____________________

(1) Includes abandonment costs.

(2) The future income tax expenses have been computed using statutory tax rates, giving effect to allowable tax deductions and tax credits under current laws, including expected tax benefits to be realized from the utilization of net operating loss carryforwards.

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):


	Year Ended December 31,
	2019		2018		2017
Beginning present value	$	1,045,603	$	749,294	$	438,364
Changes during the year
Revenues less production	(155,772)		(236,553)		(239,838)
Net changes in prices, production and other costs	(491,035)		316,095		347,458
Development costs incurred	90,591		80,050		35,517
Net changes in future development costs(1)	450,162		(11,483)		(64,484)
Extensions and discoveries	11,921		102,961		112,556
Revisions of previous quantity estimates(1)	(478,238)		(91,038)		26,697
Accretion of discount	101,778		70,576		37,226
Net change in income taxes	—		56		23
Purchases of reserves in-place	—		35,713		454
Sales of reserves in-place	(3,331)		(2,029)		(2,977)
Timing differences and other(2)	(207,389)		31,961		58,298
Net change for the year	(681,313)		296,309		310,930
Ending present value(3)	$	364,290	$	1,045,603	$	749,294

____________________

(1) The change in estimated future development costs and revisions of previous quantity estimates primarily reflect a decrease in planned PUD development due to declining year end SEC prices for oil and natural gas.

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

(3) Standardized Measure was determined using SEC prices, and does not reflect actual prices received or current market prices.