Supplemental Information On Oil And Gas Exploration And Production Activities (Unaudited)

Costs Incurred Related to Oil and Gas Activities

Capitalized costs include the cost of properties, equipment, and facilities for oil and natural gas producing activities. Capitalized costs for proved properties include costs for oil and natural gas leaseholds where proved reserves have been identified, development wells, and related equipment and facilities, including development wells in progress. Capitalized costs for unproved properties include costs for acquiring oil and natural gas leaseholds where no proved reserves have been identified, including costs of exploratory wells that are in the process of drilling or in active completion, and costs of exploratory wells suspended or waiting on completion.

The Company’s oil and natural gas activities for 2018 and 2017 were entirely within the United States of America. Costs incurred in oil and natural gas producing activities were as follows (in thousands):



	Years Ended December 31,
	2018		2017
Acquisition cost (1):
Proved	$	41,569	$	315,376
Unproved	31,268		245,589
Exploration costs:
Exploratory drilling	—		—
Geological and geophysical	630		1
Development costs	153,161		77,876
Total additions	$	226,628	$	638,842


(1)	Acquisition costs incurred during 2018 consisted primarily of an acreage trade in the Midland Basin and during 2017 consisted primarily of the assets acquired in the Bold Transaction, both described in Note 3. Acquisitions and Divestitures of the Notes to Consolidated Financial Statements.

During the years ended December 31, 2018 and 2017, additions to oil and natural gas properties of $0.3 million and $0.1 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired.

During the years ended December 31, 2018 and 2017, the Company had no capitalized exploratory well costs, nor costs related to share-based compensation, general corporate overhead or similar activities.

Capitalized Costs

Capitalized costs, impairment, and depreciation, depletion and amortization relating to the Company’s oil and natural gas properties producing activities, all of which are conducted within the continental United States as of December 31, 2018 and 2017, are summarized below (in thousands):



	December 31,
	2018			2017
Oil and gas properties, successful efforts method:
Proved properties	$	830,843		$	708,646
Accumulated impairment to proved properties	(75,400		)	(103,608		)
Proved properties, net of accumulated impairments	755,443			605,038
Unproved properties	311,828			319,569
Accumulated impairment to Unproved properties	(45,688		)	(44,543		)
Unproved properties, net of accumulated impairments	266,140			275,026
Land	5,382			5,534
Total oil and gas properties, net of accumulated impairments	1,026,965			885,598
Accumulated depreciation, depletion and amortization	(127,256		)	(118,028		)
Net oil and gas properties	$	899,709		$	767,570

Oil and Natural Gas Reserves

Users of this information should be aware that the process of estimating quantities of “proved” and “proved developed” oil and natural gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. As a result, revisions to existing reserve estimates may occur from time to time. Although every reasonable effort is made to ensure reserve estimates reported represent the most accurate assessments possible, the subjective decisions and variances in available data for various reservoirs make these estimates generally less precise than other estimates included in the financial statement disclosures.

Proved reserves represent estimated quantities of oil, natural gas and natural gas liquids that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under economic and operating conditions in effect when the estimates were made. Proved developed reserves represent estimated quantities expected to be recovered through wells and equipment in place and under operating methods used when the estimates were made.

The proved reserves estimates shown herein for the years ended December 31, 2018 and 2017 have been prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Proved reserves were estimated in accordance with guidelines established by the SEC, which require that reserve estimates be prepared under existing economic and operating conditions based upon the 12-month unweighted average of the first-day-of-the-month prices.

The reserve information in these Consolidated Financial Statements represents only estimates. There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond the Company’s control, such as commodity pricing. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgement. As a result, estimates by different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may lead to revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent the Company acquires additional properties containing proved reserves or conducts successful exploration and development activities or both, the Company’s proved reserves will decline as reserves are produced.

The following table illustrates the Company’s estimated net proved reserves, including changes, and proved developed and proved undeveloped reserves for the periods indicated. The oil prices as of December 31, 2018 and 2017 are based on the respective 12-month unweighted average of the first of the month prices of the West Texas Intermediate (“WTI”) spot prices which equates to $65.56 per barrel and $51.34 per barrel, respectively. The natural gas prices as of December 31, 2018 and 2017 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $3.10 per MMBtu and $2.98 per MMBtu, respectively. Natural gas liquids are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics. The natural gas liquids prices used to value reserves as of December 31, 2018 and 2017 averaged $28.81 per barrel and $22.59 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials. All prices are held constant in accordance with SEC guidelines.

A summary of the Company’s changes in quantities of proved oil, natural gas and NGLs reserves for the years ended December 31, 2018 and 2017 are as follows:



	Oil (MBbl)		Natural Gas (MMcf)		NGLs (MBbl)		Total (MBOE)
Balance - December 31, 2016	7,111		20,401		1,540		12,051
Extensions and discoveries	19,558		29,644		6,264		30,763
Sales of minerals in place	(1,833	)	(6,853	)	(1	)	(2,976	)
Purchases of minerals in place	28,176		46,709		9,950		45,911
Production	(1,828	)	(3,260	)	(500	)	(2,872	)
Revision to previous estimates	(3,857	)	4,447		215		(2,901	)
Balance - December 31, 2017	47,327		91,088		17,468		79,976
Extensions and discoveries	10,148		17,673		3,116		16,209
Sales of minerals in place	(2,651	)	(14,300	)	(1,562	)	(6,596	)
Purchases of minerals in place	3,532		9,890		1,629		6,810
Production	(2,370	)	(3,610	)	(655	)	(3,627	)
Revision to previous estimates	3,048		12,476		947		6,075
Balance - December 31, 2018	59,034		113,217		20,943		98,847
Proved developed reserves:
December 31, 2016	6,052		13,545		1,051		9,361
December 31, 2017	11,949		23,336		4,123		19,961
December 31, 2018	14,325		26,110		4,969		23,646
Proved undeveloped reserves:
December 31, 2016	1,059		6,856		489		2,690
December 31, 2017	35,378		67,752		13,345		60,015
December 31, 2018	44,709		87,107		15,974		75,201

The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2018 and 2017:



As of December 31, 2018	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBOE)
Proved developed	7,917	14,430	2,746	13,068
Proved undeveloped	24,709	48,140	8,828	41,560
Total proved	32,626	62,570	11,574	54,628

As of December 31, 2017	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBOE)
Proved developed	6,775	13,232	2,338	11,318
Proved undeveloped	20,059	38,415	7,566	34,028
Total proved	26,834	51,647	9,904	45,346

Notable changes in proved reserves for the year ended December 31, 2018 included the following:


•	Extensions and discoveries. In 2018, total extensions and discoveries of 16.2 MMBOE was a result of successful drilling results and well performance primarily related to the Midland Basin.

•

Sales of minerals in place. Sales of minerals in place totaled 6.6 MMBOE during 2018, which consisted of 4.7 MMBOE resulting from the disposition of non-operated properties in the Midland Basin as part of an acreage trade and 1.9 MMBOE related to the disposition of non-operated Eagle Ford properties, both further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.


•	Purchases of minerals in place. In 2018, total purchases of minerals in place of 6.8 MMBOE were primarily attributable to developed non-producing wells and undeveloped acreage acquired in the Midland Basin as part of an acreage trade, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.


•	Revision to previous estimates. In 2018, the upward revisions of prior reserves of 6.1 MMBOE consisted of improved PUD reserves of 5.8 MMBOE with improved proved developed reserves of 0.3 MMBOE. PUD revisions are a result of our successful drilling efforts in the Midland Basin as well as improved commodity prices.

Notable changes in proved reserves for the year ended December 31, 2017 included the following:


•	Extensions and discoveries. In 2017, total extensions and discoveries of 30,763 MBOE was a result of successful drilling results and well performance primarily related to the Midland Basin. The closing of the Bold Transaction in May 2017 which included primarily operated acreage in the Midland Basin was a significant contributor to this.


•	Sales of minerals in place. Sales of minerals in place totaled 2,976 MBOE during 2017 and were primarily related to the disposition of the Bakken properties, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

•

Purchases of minerals in place. In 2017, total purchases of minerals in place of 45,911 MBOE were primarily attributable to the Bold Transaction, whereby the Company acquired interests in 63 producing oil and natural gas wells, developed non-producing wells and undeveloped acreage in the Midland Basin, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

•

Revision to previous estimates. In 2017, the downward revisions of prior reserves of 2,901 MBOE consisted of negative revisions to PUD reserves of 4,832 MBOE with improved proved developed reserves of 1,931 MBOE. PUD revisions are a result of (1) removal of approximately 2,011 MBOE of reserves due to delayed development plans of other operators in the Midland Basin that management previously expected to be developed within five years, (2) reduction of 2,378 MBOE upon closing of the Bold Transaction and making adjustments to development plans and PUD reserve assignments, and (3) non-participation in three Eagle Ford natural gas PUDs that were expected to develop 443 MBOE. Positive revisions are primarily a result of increased oil and natural gas prices during 2017.

For wells classified as proved developed producing where sufficient production history existed, reserves were based on individual well performance evaluation and production decline curve extrapolation techniques. For undeveloped locations and wells that lack sufficient production history, reserves were based on analogy to producing wells within the same area exhibiting similar geologic and reservoir characteristics. Well spacing was determined from drainage patterns derived from a combination of performance-based recoveries and analogous producing wells for each area or field. PUD locations were limited to areas of uniformly high-quality reservoir properties, between existing commercial producers where the reservoir can, with reasonable certainty, be judged to be continuous with existing producers and contain economically producible oil and natural gas on the basis of available geoscience and engineering data.

Changes in PUD reserves for the years ended December 31, 2018 and 2017 were as follows (in MBOE):



Proved undeveloped reserves at December 31, 2016	2,690
Conversions to developed	(2,756	)
Extensions and discoveries	27,977
Sales of minerals in place	(391	)
Purchases of minerals in place	37,327
Revision to previous estimates	(4,832	)

Proved undeveloped reserves at December 31, 2017 (1)	60,015
Conversions to developed	(4,419	)
Extensions and discoveries	13,734
Sales of minerals in place	(4,702	)
Purchases of minerals in place	4,735
Revision to previous estimates	5,838
Proved undeveloped reserves at December 31, 2018 (2)	75,201


(1)	Includes 34,029 MBOE attributable to noncontrolling interests.


(2)	Includes 41,560 MBOE attributable to noncontrolling interests.

2018 Changes in Proved Undeveloped Reserves

Conversions to developed. In the Company’s year-end 2017 plan to develop its PUDs within five years, the Company estimated that $51.9 million of capital would be expended in 2018 and that it would convert 4.3 MMBOE, which was consistent with the $55.4 million actually spent to convert 4.4 MMBOE to developed.

Extensions and discoveries. Additionally, 13.7 MMBOE were added as extensions and discoveries due to successful drilling results on the Company’s acreage positions because of the wells it drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to the Company’s acreage. All of these drilling results increased the confidence of the reservoir continuity and performance of the associated reservoirs which increased the number of PUDs primarily in the Midland Basin.

Sales of minerals in place. Sales of minerals in place totaled 4.7 MMBOE during 2018, which consisted of 3.7 MMBOE resulting from the disposition of non-operated properties in the Midland Basin as part of an acreage trade and 1.0 MMBOE related to the disposition of non-operated Eagle Ford properties, both further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

Purchases of minerals in place. In 2018, purchases of minerals in place of 4.7 MMBOE were attributable to developed non-producing wells and undeveloped acreage acquired in the Midland Basin as part of an acreage trade, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements.

Revision to previous estimates. Revisions of 5.8 MMBOE were primarily due to our successful drilling efforts in the Midland Basin as well as improved commodity prices.

2017 Changes in Proved Undeveloped Reserves

Conversions to developed. In the Company’s year-end 2016 plan to develop its PUDs within five years, the Company estimated that $6.9 million of capital would be expended in 2017 and that it would convert 732 MBOE. Because of the improvement in commodity prices and the change in its development plan for 2017, the Company actually spent $8.5 million to convert 622 MBOE to developed. The Company’s plan changed in that it developed more oil PUDs and elected not to participate in natural gas PUDs which included the above mentioned 443 MBOE associated with the Eagle Ford non-participation. The capital to develop the Company’s oil PUDs was higher on a per unit basis than the natural gas PUDs however the margins are higher for oil PUDs. The oil PUDs further benefited the Company’s longer-term operated development plans. Since the Bold Transaction closed in May 2017, the associated capital plan for the properties acquired in the Bold Transaction during 2017 was not considered in the Company’s year-end 2016 report. The Company did however incur $63.4 million to convert 2,134 MBOE of purchased PUD reserves to Developed.

Extensions and discoveries. Additionally, 27,977 MBOE were added as extensions and discoveries due to successful drilling results on the Company’s acreage positions because of the wells it drilled. The increase was also supported by successful drilling results by other operators directly offsetting and in close proximity to the Company’s acreage. All of these drilling results increased the confidence of the reservoir continuity and performance of the associated reservoirs which increased the number of PUDs primarily in the Midland Basin.

Sales of minerals in place. Sales of minerals in place totaled 391 MBOE during 2017 and were primarily related to the disposition of the Bakken properties, as further described in Note 3. Acquisitions and Divestitures in the Notes to Consolidated Financial Statements

Purchases of minerals in place. During 2017, 37,327 MBOE were added to PUD reserves upon the closing of the Bold Transaction.

Revision to previous estimates. Revisions of 4,832 MBOE were primarily due to (1) removal of approximately 2,011 MBOE of reserves due to delayed development plans of other operators in the Midland Basin that management previously expected to be developed within five years, (2) reduction of 2,378 MBOE upon the closing of the Bold Transaction and making adjustments to development plans and PUD reserve assignments, and (3) non-participation in three Eagle Ford natural gas PUDs that were expected to develop 443 MBOE. This non-participation has no impact on the Company’s ability to participate in future wells in this acreage position.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following Standardized Measure of Discounted Future Net Cash Flows (Standardized Measure) has been developed utilizing FASB ASC Topic 932, Extractives Activities – Oil and Gas (“ASC 932”) procedures and based on oil and natural gas reserve and production volumes estimated by the Company’s third-party petroleum engineering firm. It can be used for some comparisons, but should not be the only method used to evaluate the Company or its performance. Further, the information in the following table may not represent realistic assessments of future cash flows, nor should the Standardized Measure be viewed as representative of the current value of the Company.

The Company believes that the following factors should be taken into account when reviewing the following information:


•	Future costs and commodity prices will probably differ from those required to be used in these calculations;


•	Due to future market conditions and governmental regulations, actual rates of production in future years may vary significantly from the rate of production assumed in the calculations;


•	A 10% discount rate may not be reasonable as a measure of the relative risk inherent in realizing future net oil and natural gas revenues; and


•	Future net revenues may be subject to different rates of income taxation.

At December 31, 2018 and 2017, as specified by the SEC, the prices for oil and natural gas used in this calculation were the unweighted 12-month average of the first day of the month prices, except for volumes subject to fixed price contracts. Prices used to estimate reserves are included in Oil and Natural Gas Reserves above. Future production costs include per-well overhead expenses allowed under joint operating agreements, abandonment costs (net of salvage value), and a non-cancelable fixed cost agreement to reserve pipeline capacity of 10,000 MMBtu per day for gathering and processing. Estimates of future income taxes are computed using current statutory income tax rates including consideration for estimated future statutory depletion and tax credits. The resulting net cash flows are reduced to present value amounts by applying a 10% discount factor.

The Standardized Measure is as follows (in thousands):



	December 31,
	2018			2017
Future cash inflows	$	4,479,757		$	2,948,989
Future production costs	(1,013,131		)	(757,716		)
Future development costs	(963,536		)	(677,093		)
Future income tax expense	(90,570		)	(33,644		)
Future net cash flows	2,412,520			1,480,536
10% annual discount for estimated timing of cash flows	(1,453,068		)	(887,836		)
Standardized measure of discounted future net cash flows (1)	$	959,452		$	592,700


(1)	At December 31, 2018 and 2017, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $530.2 million and $336.1 million, respectively.

Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves

The following is a summary of the changes in the Standardized Measure for the Company’s proved oil and natural gas reserves during each of the years in the three-year period ended December 31, 2018 (in thousands):



	December 31,
	2018			2017
Beginning of year	$	592,700		$	85,883
Sales of oil and gas produced, net of production costs	(136,143		)	(81,926		)
Sales of minerals in place	(41,320		)	(15,553		)
Net changes in prices and production costs	319,486			155,629
Extensions, discoveries, and improved recoveries	185,540			201,801
Changes in income taxes, net	(43,108		)	(5,941		)
Previously estimated development costs incurred during the period	153,161			76,447
Net changes in future development costs	(316,765		)	(168,940		)
Purchases of minerals in place	57,013			244,785
Revisions of previous quantity estimates	144,356			68,705
Accretion of discount	51,222			28,985
Changes in timing of estimated cash flows and other	(6,690		)	2,825
End of year (1)	$	959,452		$	592,700


(1)	At December 31, 2018 and 2017, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $530.2 million and $336.1 million, respectively.