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 2019 and 2018 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,
	2019			2018
Acquisition cost ⁽¹⁾:
Proved	$	(141	)	$	41,569
Unproved	(125		)	31,268
Exploration costs:
Abandonment costs	653			—
Geological and geophysical	—			630
Development costs	210,520			153,161
Total additions	$	210,907		$	226,628


(1)	Acquisition costs incurred during 2019 consisted primarily of purchase price adjustments related to 2018 acquisitions and during 2018 consisted primarily of an acreage trade in the Midland Basin.

During the years ended December 31, 2019 and 2018, additions to oil and natural gas properties of $0.1 million and $0.3 million, respectively, were recorded for estimated costs of future abandonment related to new wells drilled or acquired.

During the years ended December 31, 2019 and 2018, 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, 2019 and 2018, are summarized below (in thousands):



	December 31,
	2019			2018
Oil and gas properties, successful efforts method:
Proved properties	$	1,046,208		$	830,843
Accumulated impairment to proved properties	(75,400		)	(75,400		)
Proved properties, net of accumulated impairments	970,808			755,443
Unproved properties	305,961			311,828
Accumulated impairment to Unproved properties	(45,690		)	(45,688		)
Unproved properties, net of accumulated impairments	260,271			266,140
Land	5,382			5,382
Total oil and gas properties, net of accumulated impairments	1,236,461			1,026,965
Accumulated depreciation, depletion and amortization	(195,567		)	(127,256		)
Net oil and gas properties	$	1,040,894		$	899,709

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, 2019 and 2018 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 judgment. 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, 2019 and 2018 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 $55.69 per barrel and $65.56 per barrel, respectively. The natural gas prices as of December 31, 2019 and 2018 are based on the respective 12-month unweighted average of the first of month prices of the Henry Hub spot price which equates to $2.58 per MMBtu and $3.10 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, 2019 and 2018 averaged $16.17 per barrel and $28.81 per barrel, respectively. All prices are adjusted by lease or field for energy content, transportation fees, and market differentials, resulting in the aforementioned oil, natural gas and natural gas liquids reserves as of December 31, 2019 being valued using prices of $52.60 per barrel, $0.91 per MMBtu and $16.17 per barrel, respectively. 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, 2019 and 2018 are as follows:



	Oil (MBbl)		Natural Gas (MMcf)		NGLs (MBbl)		Total (MBOE)
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
Extensions and discoveries	3,598		4,476		721		5,065
Sales of minerals in place	(31	)	(4	)	(1	)	(32	)
Production	(3,086	)	(4,760	)	(1,022	)	(4,902	)
Revision to previous estimates	(6,865	)	(4,939	)	3,047		(4,642	)
Balance - December 31, 2019	52,650		107,990		23,688		94,336
Proved developed reserves:
December 31, 2017	11,949		23,336		4,123		19,961
December 31, 2018	14,325		26,110		4,969		23,646
December 31, 2019	18,220		35,120		7,447		31,521
Proved undeveloped reserves:
December 31, 2017	35,378		67,752		13,345		60,015
December 31, 2018	44,709		87,107		15,974		75,201
December 31, 2019	34,430		72,870		16,241		62,815

The table below presents the quantities of proved oil, natural gas and NGLs reserves attributable to noncontrolling interests as of December 31, 2019 and 2018:



As of December 31, 2019	Oil (MBbl)	Natural Gas (MMcf)	NGLs (MBbl)	Total (MBOE)
Proved developed	9,933	19,146	4,060	17,183
Proved undeveloped	18,769	39,724	8,853	34,243
Total proved	28,702	58,870	12,913	51,426

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

Notable changes in proved reserves for the year ended December 31, 2019 included the following:


•	Extensions and discoveries. In 2019, total extensions and discoveries of 5.1 MMBOE was the 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 32.0 MBOE during 2019, resulting from the disposition of certain non-operated properties in the Midland Basin. See Note 3. Acquisitions and Divestitures.


•	Revision to previous estimates. In 2019, the downward revisions of prior reserves of 4.6 MMBOE were primarily due to reduced commodity prices.

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.


•	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.


•	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 the Company’s successful drilling efforts in the Midland Basin as well as improved commodity prices.

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, 2019 and 2018 were as follows (in MBOE):



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
Conversions to developed	(10,254	)
Extensions and discoveries	1,230
Revision to previous estimates	(3,362	)
Proved undeveloped reserves at December 31, 2019 (3)	62,815


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


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


(3)	Includes 34,243 MBOE attributable to noncontrolling interests.

2019 Changes in Proved Undeveloped Reserves

Conversions to developed. In the Company’s year-end 2018 plan to develop its PUDs within five years, the Company estimated that $103.8 million of capital would be expended in 2019 for the conversion of 30 gross / 12.3 net PUDs to add 9.9 MMBOE, which was consistent with the $111.5 million actually spent to convert 32 gross / 13.4 net PUDs adding 10.3 MMBOE to developed.

Extensions and discoveries. Additionally, 1.2 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.

Revision to previous estimates. Revisions of 3.4 MMBOE were primarily due to reduced commodity prices.

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 $41.5 million of capital would be expended in 2018 for the conversion of 14 gross / 6.2 net PUDs to add 4.3 MMBOE, which was consistent with the $55.4 million actually spent to convert 11 gross / 6.8 net PUDs adding 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.

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.

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

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, 2019 and 2018, 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,
	2019			2018
Future cash inflows	$	3,250,868		$	4,479,757
Future production costs	(1,027,464		)	(1,013,131		)
Future development costs	(628,692		)	(963,536		)
Future income tax expense	(58,824		)	(90,570		)
Future net cash flows	1,535,888			2,412,520
10% annual discount for estimated timing of cash flows	(746,311		)	(1,453,068		)
Standardized measure of discounted future net cash flows ⁽¹⁾	$	789,577		$	959,452


(1)	At December 31, 2019 and 2018, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $430.4 million and $530.2 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 two-year period ended December 31, 2019 (in thousands):



	December 31,
	2019			2018
Beginning of year	$	959,452		$	592,700
Sales of oil and gas produced, net of production costs	(150,708		)	(136,143		)
Sales of minerals in place	(458		)	(41,320		)
Net changes in prices and production costs	(565,240		)	319,486
Extensions, discoveries, and improved recoveries	127,182			185,540
Changes in income taxes, net	12,697			(43,108		)
Previously estimated development costs incurred during the period	210,520			153,161
Net changes in future development costs	118,348			(316,765		)
Purchases of minerals in place	—			57,013
Revisions of previous quantity estimates	(35,588		)	144,356
Accretion of discount	107,432			51,222
Changes in timing of estimated cash flows and other	5,940			(6,690		)
End of year ⁽¹⁾	$	789,577		$	959,452


(1)	At December 31, 2019 and 2018, the portion of the standardized measure of discounted future net cash flows attributable to noncontrolling interests was $430.4 million and $530.2 million, respectively.