NOTE 24 — SUPPLEMENTAL OIL AND GAS DISCLOSURES (Unaudited)

During January 2019, we finalized our development plan for the next five years and received an audit report from our outside engineers that agreed with our recognition of PUDs for the majority of that future development. During April 2019, in finalizing our financial reporting for 2018, we determined that we may fail to satisfy the leverage covenant under the Alta Mesa RBL during 2019. Accordingly, we were unable to conclude that we would have continuing access to that capital source in the event of a failure of the leverage covenant. Thus, we concluded that we did not satisfy the ability-to-drill threshold under the SEC’s reserve recognition rule with respect to our future drilling locations and did not recognize any proved undeveloped locations in our final December 31, 2018 reserve report. Should our ability to fund the required development costs improve in the future, we expect to recognize all or a portion of those resources as proved.

The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. The information presented during the Predecessor Periods includes amounts related to discontinued operations.

Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and gas properties. Accordingly, these estimates are expected to change as future information becomes available. Under our gathering contract with KFM, we have options regarding how we accept or reject ethane volumes. Our reserve disclosures that follow assume that we recover (rather than reject) ethane volumes, which generally has the effect of increasing the reserves, with no corresponding increase to value or future cash flow.

Reserve estimates incorporate assumptions regarding future prices and costs at the date estimates are made. Actual future prices and costs may be materially higher or lower. Actual future net revenue will also be affected by factors such as actual production, supply and demand for oil and gas, curtailments or increases in consumption by gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.

Oil and gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.

Estimated Quantities of Proved Reserves

The following table sets forth our net proved reserves as of the Successor Period, the 2018 Predecessor Period, the years ended December 31, 2017 and 2016, and the changes therein during the periods then ended. Proved oil and gas reserves are the estimated quantities of crude oil, gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the dates the estimates were made).

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	Oil (Mbbls)		Gas (MMcf)		NGL’s (Mbbls)		Boe (Mbbls)
Total Proved Reserves:
Balance at December 31, 2015 (Predecessor)	34,142		155,423		18,437		78,483
Production	(4,001	)	(13,959	)	(956	)	(7,284	)
Purchases in place⁽¹⁾	1,508		6,754		613		3,247
Discoveries and extensions	29,903		154,653		14,000		69,679
Sales of reserves in place	(73	)	(966	)	(10	)	(244	)
Revisions of previous quantity estimates and other	(3,680	)	14,100		(3,794	)	(5,124	)
Balance at December 31, 2016 (Predecessor)	57,799		316,005		28,290		138,757
Production	(4,850	)	(18,218	)	(1,387	)	(9,274	)
Purchases in place	725		4,860		401		1,936
Discoveries and extensions	20,135		108,676		9,640		47,888
Sales of reserves in place	(3,622	)	(1,280	)	—		(3,836	)
Revisions of previous quantity estimates and other	3,331		23,476		(57	)	7,187
Balance at December 31, 2017 (Predecessor)	73,518		433,519		36,887		182,658
Production	(521	)	(1,984	)	(161	)	(1,012	)
Purchases in place	—		—		—		—
Discoveries and extensions	—		—		—		—
Sales of reserves in place⁽²⁾	(1,667	)	(24,239	)	(771	)	(6,478	)
Revisions of previous quantity estimates and other	375		3,506		289		1,248
Balance at February 8, 2018 (Predecessor)	71,705		410,802		36,244		176,416
Production	(5,053	)	(16,913	)	(2,268	)	(10,140	)
Purchases in place⁽³⁾	2,658		13,331		1,751		6,631
Discoveries and extensions⁽³⁾	30,026		155,306		19,646		75,557
Sales of reserves in place	—		—		—		—
Revisions of previous quantity estimates and other⁽³⁾⁽⁴⁾	(74,064	)	(418,378	)	(35,581	)	(179,375	)
Balance at December 31, 2018 (Successor)	25,272		144,148		19,792		69,089

Proved Developed Reserves:
Balance at December 31, 2015	14,942		71,752		6,958		33,859
Balance at December 31, 2016	16,832		93,361		7,977		40,371
Balance at December 31, 2017	20,347		150,183		12,180		57,557
Balance at February 8, 2018	19,345		126,231		11,348		51,731
Balance at December 31, 2018	25,272		144,148		19,792		69,089
Proved Undeveloped Reserves:
Balance at December 31, 2015	19,200		83,671		11,479		44,624
Balance at December 31, 2016	40,967		222,644		20,313		98,386
Balance at December 31, 2017	53,171		283,336		24,707		125,101
Balance at February 8, 2018	52,360		284,571		24,896		124,685
Balance at December 31, 2018	—		—		—		—

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(1)	Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from HMI.


(2)	Sales of reserves in place during the 2018 Predecessor Period represent amounts related to our non-STACK properties that were distributed to the AM contributor and are classified as discontinued operations in our consolidated financial statements.

(3)

Effective as of December 31, 2018, due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the proved undeveloped reserves, we have removed all of our PUDs from our total estimated proved reserves. Discoveries and extensions and purchases in place during the 2018 Successor Period include approximately 47,092 MBoe in PUDs, and this amount is also included with our negative revisions and is consequently removed from our total proved reserves at December 31, 2018.

(4)

In addition to removing PUDs, we lowered our estimate of proved reserves at December 31, 2018 by approximately 101,516 MBoe, largely due to results of the 2018 drilling program demonstrating lower estimated recovery per 640-acre section. Partially offsetting this was an increase in recoverable reserves of approximately 11,196 MBoe, due mainly to higher average commodity prices in 2018 as compared to 2017.

Results of Operations for Oil and Gas Producing Activities



	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017		Year Ended December 31, 2016
Operating revenue	$	414,507		$	40,136		$	269,386	$	142,356
Production expense ⁽¹⁾	247,748			30,743			138,833		87,869
Depreciation, depletion and amortization	133,554			11,670			89,115		53,755
Exploration expense	34,085			7,003			13,563		17,230
Impairment expense	2,033,712			—			1,188		382
Income tax expense (benefit)	4			—			6		—
Results of operations	$	(2,034,596	)	$	(9,280	)	$	26,681	$	(16,880	)

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(1)	Production expense consists of direct lease operating expense, transportation and marketing expense, production taxes, workover expense and general and administrative expense.

Capitalized Costs Relating to Oil and Gas Producing Activities

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	December 31,
(in thousands)	Successor 2018			Predecessor 2017⁽¹⁾
Capitalized costs:
Proved properties	$	2,110,346		$	1,545,963
Unproved properties	816,282			116,787
Total	2,926,628			1,662,750
Accumulated depreciation, depletion, amortization and impairment	(2,163,291		)	(711,275		)
Net capitalized costs	$	763,337		$	951,475

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(1)	Includes amounts related to non-STACK assets distributed in the 2018 Predecessor Period and reflected as discontinued operations.

Costs Incurred in Oil and Gas Acquisition, Exploration and Development Activities

Acquisition costs in the table below include costs incurred to purchase, lease or otherwise acquire property. Exploration expenses include additions to exploratory wells and other exploration expenses, such as geological and geophysical costs. Development costs include drilling and completion costs plus additions to production facilities and equipment.

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	Successor		Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018		January 1, 2018 Through February 8, 2018		Year Ended December 31, 2017		Year Ended December 31, 2016
Costs incurred during the period: ⁽¹⁾
Property acquisition
Unproved ⁽²⁾	$	54,587	$	4,240	$	88,378	$	66,788
Proved ⁽³⁾	16,300		327		11,704		68,478
Exploration	32,130		3,678		26,836		28,480
Development ⁽⁴⁾	664,138		37,672		351,570		165,796
	$	767,155	45,917		$	478,488	$	329,542

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(1)	Costs incurred in all Predecessor Periods include amounts related to non-STACK oil and gas assets, which were distributed in connection with the Business Combination. Costs incurred in 2017 include amounts related to the Weeks Island field and other assets, all of which are classified as discontinued operations.


(2)	Property acquisition costs for unproved properties include the acquisition of unevaluated leasehold portion from an unaffiliated third party of approximately $22.3 million and $45.6 million for the 2018 Successor Period and the year ended December 31, 2017, respectively.


(3)	Property acquisition costs for proved properties in 2016 include the transfer of Contributed Wells by our former Class B partner to us of $65.7 million.


(4)	Includes asset retirement additions (revisions) of $5.6 million, $4.4 million, and $1.9 million for the Successor Period, and years ended December 31, 2017 and 2016, respectively. For the 2018 Predecessor Period, there were no material asset retirement additions (revisions).

Standardized Measure of Discounted Future Net Cash Flows

The following information utilizes reserve and production data prepared by us. Future cash inflows were calculated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month, for the Successor Period, the 2018 Predecessor Period, and for the years ended December 31, 2017 and 2016. Well costs, operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.

The following table sets forth the components of the standardized measure of discounted future net cash flows:



	Successor			Predecessor
(in thousands, except per unit data)	December 31, 2018			February 8, 2018			December 31, 2017			December 31, 2016
Future cash inflows	$	2,446,888		$	5,798,886		$	5,799,753		$	3,547,130
Future production costs	(1,214,479		)	(2,556,361		)	(2,617,476		)	(1,811,683		)
Future development costs	(23,183		)	(965,780		)	(1,035,481		)	(709,738		)
Future income taxes	—			—			—			—
Future net cash flows⁽¹⁾	1,209,226			2,276,745			2,146,796			1,025,709
Discount to present value at 10 percent per annum	(396,375		)	(1,096,859		)	(1,040,874		)	(467,101		)
Standardized measure of discounted future net cash flows	$	812,851		$	1,179,886		$	1,105,922		$	558,608
Base price for crude oil, per barrel, in the above computation	$	65.56		$	52.89		$	51.34		$	42.75
Base price for natural gas, per MMBtu, in the above computation	$	3.10		$	2.99		$	2.98		$	2.49
Realized price for NGLs, per barrel, in the above computation	$	22.44		$	27.48		$	26.06		$	15.18

Changes in Standardized Measure of Discounted Future Net Cash Flows



	Successor			Predecessor
(in thousands)	February 9, 2018 Through December 31, 2018			January 1, 2018 Through February 8, 2018			Year Ended December 31, 2017			Year Ended December 31, 2016
Balance at beginning of period	$	1,179,886		$	1,105,922		$	558,608		$	629,596
Sales and transfers of oil and gas produced, net of production costs	(278,091		)	(30,391		)	(202,232		)	(124,610		)
Net changes in prices and production costs	38,963			71,334			354,900			(324,638		)
Revisions of previous quantity estimates⁽¹⁾	(1,120,097		)	10,887			(12,106		)	(35,972		)
Purchases of reserves in-place	24,376			—			11,483			40,611
Sales of reserves in-place⁽²⁾	—			(4,807		)	(20,423		)	2,345
Current year discoveries and extensions, less related costs	684,700			—			513,012			356,631
Changes in estimated future development costs	(39,069		)	491			(5,869		)	849
Development costs incurred during the period	160,583			—			26,317			8,363
Accretion of discount	117,989			110,592			55,861			62,960
Net change in income taxes	—			—			—			—
Change in production rate (timing) and other	43,611			(84,142		)	(173,629		)	(57,527		)
Net change	(367,035		)	73,964			547,314			(70,988		)
Balance at end of period	$	812,851		$	1,179,886		$	1,105,922		$	558,608

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(1)	Our revisions include approximately $250.0 million of proved undeveloped reserves that were removed at December 31, 2018 due to our subsequent determination of substantial doubt about our ability to continue as a going-concern and the impact on our ability to fund the costs associated with developing those reserves.


(2)	The sale of reserves in-place during the 2018 Predecessor Period includes the sale of non-STACK properties, and in 2017 the sale of Weeks Island Field and other assets, all of which are reflected as discontinued operations in the Company’s consolidated financial statements.