Alta Mesa Inactive 10-Q28 Aug 192019 Q2 Quarterly reportFinancial data

Company Profile

Document And Entity Information

Document And Entity Information	6 Months Ended
Document And Entity Information	Jun. 30, 2019shares
Document And Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	0001518403
Document Type	10-Q
Document Period End Date	Jun. 30, 2019
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	true
Entity Ex Transition Period	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)	0
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations (Unaudited) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2018
Revenue
Operating revenue		$ 113,633	$ 95,741	$ 146,498	$ 230,230
Gain (loss) on sale of assets		0	(63)	5,076	1,483
Gain (loss) on derivatives		12,412	(29,219)	(51,230)	(11,365)
Total revenue		126,045	66,459	100,344	220,348
Operating expenses
Lease operating		19,123	12,679	20,996	44,231
Transportation and marketing		19,614	11,206	16,788	37,375
Production taxes		5,117	2,606	4,021	10,600
Workovers		412	333	1,578	609
Exploration		3,289	8,083	9,668	5,343
Depreciation, depletion and amortization		34,504	26,670	37,708	69,179
Impairment of assets		6,500	0	0	6,500
General and administrative		15,723	17,811	52,465	36,670
Total operating expenses		104,282	79,388	143,224	210,507
Operating income		21,763	(12,929)	(42,880)	9,841
Other income (expense)
Interest expense		(14,071)	(10,361)	(15,557)	(26,901)
Interest income and other		54	820	1,366	81
Total other expense, net		(14,017)	(9,541)	(14,191)	(26,820)
Income (loss) from continuing operations before income taxes		7,746	(22,470)	(57,071)	(16,979)
Income tax provision (benefit)		0	7	7	0
Income (loss) from continuing operations		7,746	(22,477)	(57,078)	(16,979)
Loss from discontinued operations, net of tax		0	0	0	0
Net income (loss)		7,746	(22,477)	(57,078)	(16,979)
Oil
Revenue
Operating revenue		90,668	75,291	115,569	177,031
Natural gas
Revenue
Operating revenue		12,384	7,980	13,190	30,834
Natural gas liquids
Revenue
Operating revenue		10,251	10,241	14,955	21,467
Other
Revenue
Operating revenue		$ 330	$ 2,229	$ 2,784	$ 898
Predecessor
Revenue
Operating revenue	$ 40,136
Gain (loss) on sale of assets	840
Gain (loss) on derivatives	6,663
Total revenue	47,639
Operating expenses
Lease operating	4,408
Transportation and marketing	3,725
Production taxes	953
Workovers	423
Exploration	7,003
Depreciation, depletion and amortization	11,670
Impairment of assets	0
General and administrative	21,234
Total operating expenses	49,416
Operating income	(1,777)
Other income (expense)
Interest expense	(5,511)
Interest income and other	172
Total other expense, net	(5,339)
Income (loss) from continuing operations before income taxes	(7,116)
Income tax provision (benefit)	0
Income (loss) from continuing operations	(7,116)
Loss from discontinued operations, net of tax	(7,746)
Net income (loss)	(14,862)
Predecessor \| Oil
Revenue
Operating revenue	30,972
Predecessor \| Natural gas
Revenue
Operating revenue	4,276
Predecessor \| Natural gas liquids
Revenue
Operating revenue	4,000
Predecessor \| Other
Revenue
Operating revenue	$ 888

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 78,275	$ 12,984
Restricted cash	890	1,001
Accounts receivable, net	61,662	68,370
Other receivables	3,530	6,267
Related party receivables, net	13,149	24,282
Notes receivable from related parties, net	0	0
Prepaid expenses and other current assets	4,623	747
Derivatives	4,727	16,423
Total current assets	166,856	130,074
Property and equipment, net
Oil and gas properties, successful efforts method	784,079	763,337
Other property and equipment	37,371	38,147
Total property and equipment	821,450	801,484
Other assets
Operating lease right-of-use assets, net	7,871
Deferred financing costs, net	1,021	1,151
Deposits and other long-term assets	38	63
Derivatives	2,508	2,947
Total other assets	11,438	4,161
Total assets	999,744	935,719
Current liabilities
Current portion of debt	871,162	0
Accounts payable and accrued liabilities	91,694	197,064
Accounts payable - related party	222	3,425
Advances from non-operators	1,755	5,193
Advances from related party	4,003	9,822
Asset retirement obligations	44	2,079
Current operating lease liability	938
Derivatives	840	1,710
Total current liabilities	970,658	219,293
Long-term liabilities
Asset retirement obligations, net of current portion	12,293	9,330
Long-term debt, net	0	690,123
Operating lease liabilities, net of current portion	13,733
Derivatives	189	180
Total long-term liabilities	26,215	699,633
Total liabilities	996,873	918,926
Commitments and contingencies
Partners’ capital	2,871	16,793
Total liabilities and partners’ capital	$ 999,744	$ 935,719

Condensed Consolidated Statem_2

Condensed Consolidated Statements Of Changes In Partners' Capital (Unaudited) $ in Thousands	USD ($)
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2017	$ 154,445
Distribution of non-STACK oil and gas assets, net of associated liabilities, and Contributions \| Predecessor	43,482
Net loss \| Predecessor	(14,862)
BALANCE, ENDING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, ENDING at Feb. 08, 2018	1,535,891
BALANCE, BEGINNING (Predecessor) at Dec. 31, 2017	154,445
Net loss	(16,979)
BALANCE, ENDING at Jun. 30, 2018	2,048,013
BALANCE, BEGINNING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, BEGINNING at Feb. 08, 2018	1,535,891
Distribution of non-STACK oil and gas assets, net of associated liabilities, and Contributions	560,344
Equity-based compensation expense	2,768
Net loss	(34,601)
BALANCE, ENDING at Mar. 31, 2018	2,064,402
BALANCE, BEGINNING (Predecessor) at Feb. 08, 2018	183,065
BALANCE, BEGINNING at Feb. 08, 2018	1,535,891
Net loss	(57,078)
BALANCE, ENDING at Jun. 30, 2018	2,048,013
BALANCE, BEGINNING at Mar. 31, 2018	2,064,402
Issuance of additional purchase consideration	9,467
Equity-based compensation expense	3,621
Distributions	(7,000)
Net loss	(22,477)
BALANCE, ENDING at Jun. 30, 2018	2,048,013
BALANCE, BEGINNING at Dec. 31, 2018	16,793
Equity-based compensation expense	1,661
Net loss	(24,725)
BALANCE, ENDING at Mar. 31, 2019	(6,271)
BALANCE, BEGINNING at Dec. 31, 2018	16,793
Net loss	(16,979)
BALANCE, ENDING at Jun. 30, 2019	2,871
BALANCE, BEGINNING at Mar. 31, 2019	(6,271)
Equity-based compensation expense	1,396
Net loss	7,746
BALANCE, ENDING at Jun. 30, 2019	$ 2,871

Condensed Consolidated Statem_3

Condensed Consolidated Statements Of Cash Flows (Unaudited) - USD ($) $ in Thousands	1 Months Ended	2 Months Ended	3 Months Ended			5 Months Ended	6 Months Ended		12 Months Ended
	Feb. 08, 2018	Mar. 31, 2018	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Cash flows from operating activities:
Net loss		$ (34,601)	$ 7,746	$ (24,725)	$ (22,477)	$ (57,078)	$ (16,979)	$ (16,979)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and accretion						37,708	69,179
Non-cash lease expense						0	1,587
Provision for uncollectible receivables						0	1,177
Impairment of assets						0	6,500
Amortization of deferred financing costs						80	139
Amortization of debt (premium) discount						(2,051)	(2,462)
Equity-based compensation expense			1,396		3,621	6,389	3,057
Non-cash exploration expense						10,658	388
(Gain) loss on derivatives			(12,412)		29,219	51,230	11,365	11,365
Cash settlements of derivatives						18,334	(909)
Premium paid on derivatives						0	(1,000)
Interest converted into debt						0	0
Interest added to notes receivable from affiliate						(417)	0
Loss on sale of fixed assets						63	0
Impact on cash from changes in:
Accounts receivable						(2,923)	6,384
Other receivables						1,426	2,737
Receivables from related parties						(18,494)	10,280
Prepaid expenses and other non-current assets						7,810	(3,853)
Advances from related party						(10,371)	(5,819)
Settlement of asset retirement obligations						(806)	0
Accounts payable to related party						(4,994)	(3,203)
Accounts payable, accrued liabilities and other liabilities						(45,385)	(17,281)
Operating lease obligations						0	(1,287)
Cash from operating activities						(45,489)	61,818
Cash flows from investing activities:
Capital expenditures						(319,042)	(180,138)
Acquisitions, net of cash acquired						0	0
Proceeds from sale of assets						11,299	0
Cash from investing activities						(307,743)	(180,138)
Cash flows from financing activities:
Proceeds from long-term debt borrowings						0	183,500
Repayments of long-term debt						(134,065)	0
Deferred financing costs paid						(1,366)	0
Capital distributions						(7,000)	0
Capital contributions						560,344	0
Cash from financing activities						417,913	183,500
Net increase in cash, cash equivalents and restricted cash						64,681	65,180
Cash, cash equivalents and restricted cash, beginning of period		10,345		$ 13,985		10,345	13,985
Cash, cash equivalents and restricted cash, end of period	$ 10,345		$ 79,165		$ 75,026	75,026	$ 79,165	75,026	$ 13,985
Predecessor
Cash flows from operating activities:
Net loss	(14,862)
Adjustments to reconcile net loss to cash from operating activities:
Depreciation, depletion, amortization and accretion	12,554
Non-cash lease expense	0
Provision for uncollectible receivables	0
Impairment of assets	5,560
Amortization of deferred financing costs	171
Amortization of debt (premium) discount	0
Equity-based compensation expense	0
Non-cash exploration expense	4,575
(Gain) loss on derivatives	(6,663)
Cash settlements of derivatives	2,296
Premium paid on derivatives									0
Interest converted into debt	103
Interest added to notes receivable from affiliate	(85)
Loss on sale of fixed assets	1,923
Impact on cash from changes in:
Accounts receivable	(21,184)
Other receivables	(662)
Receivables from related parties	(117)
Prepaid expenses and other non-current assets	(591)
Advances from related party	24,116
Settlement of asset retirement obligations	(63)
Accounts payable to related party	0
Accounts payable, accrued liabilities and other liabilities	23,857
Operating lease obligations	0
Cash from operating activities	26,336
Cash flows from investing activities:
Capital expenditures	(36,695)
Acquisitions, net of cash acquired	(1,218)
Proceeds from sale of assets									0
Cash from investing activities	(37,913)
Cash flows from financing activities:
Proceeds from long-term debt borrowings	60,000
Repayments of long-term debt	(43,000)
Deferred financing costs paid	0
Capital distributions	(68)
Capital contributions	0
Cash from financing activities	16,932
Net increase in cash, cash equivalents and restricted cash	5,355
Cash, cash equivalents and restricted cash, beginning of period	4,990	$ 10,345				$ 10,345		$ 4,990	$ 4,990
Cash, cash equivalents and restricted cash, end of period	$ 10,345

Description of Business and Bas

Description of Business and Basis of Presentation	6 Months Ended
Description of Business and Basis of Presentation	Jun. 30, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of Business and Basis of Presentation	DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION Alta Mesa Holdings, LP (“Alta Mesa” or “the Company”) is an exploration and production company focused on the acquisition, development, exploration and exploitation of unconventional onshore oil and natural gas reserves in the eastern portion of the Anadarko Basin in Oklahoma commonly referred to as the STACK. Our operations prior to February 9, 2018, also included other oil and natural gas interests in Texas, Idaho, Louisiana and Florida. In connection with our acquisition by Alta Mesa Resources, Inc. (“AMR”), on February 9, 2018 (“the Business Combination”), we distributed the non-STACK oil and gas assets and liabilities to our prior owner, High Mesa Holdings, LP (“High Mesa”), and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource unconventional play in the STACK. Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“HMI”). The 2018 10-K contains substantially more information about our operations and the Business Combination. All intercompany transactions and accounts have been eliminated. These interim condensed consolidated financial statements are unaudited, but we believe these statements reflect all adjustments necessary for a fair presentation for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These financial statements and disclosures have been prepared in accordance with the SEC’s rules for interim financial statements and do not include all the information and disclosures required by generally accepted accounting principles (“GAAP”). These financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our 2018 10-K. The results for the three and six months ended June 30, 2019 , are not necessarily indicative of the results to be expected for the full year. We have no items of other comprehensive income during any period presented.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	6 Months Ended
Summary Of Significant Accounting Policies	Jun. 30, 2019
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Going Concern We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors: • Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination. • Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties. • Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions. • On April 1, 2019 , our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019 . Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million , we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities. • We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019 . • We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value. • The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets. • Our ability to collect receivables due from High Mesa and its affiliates The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have: • retained financial advisors to assist in evaluating financial alternatives; • engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief; • considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and • engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal. Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the 12 months following the issuance of these financial statements. Based on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current. Recently Issued Accounting Standards Applicable to Us Adopted Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019. Not Yet Adopted In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations. In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

Adoption of ASU No. 2016-02, Le

Adoption of ASU No. 2016-02, Leases	6 Months Ended
Adoption of ASU No. 2016-02, Leases	Jun. 30, 2019
Leases [Abstract]
Adoption of ASU No. 2016-02, Leases	ADOPTION OF ASU NO. 2016-02, LEASES ASU No. 2016-02 requires us to recognize a right-of-use (“ROU”) asset and a discounted lease liability on the balance sheet for all leases with a term longer than one year. We adopted ASU No. 2016-02 and related guidance using the modified retrospective method to apply the standard as January 1, 2019, and this adoption had no effect on the earlier comparative periods presented. At adoption, we recognized operating lease ROU assets and operating lease liabilities of $15.0 million . There was no adjustment to beginning of period equity. We lease office space, office equipment and field equipment, including compressors. Many of our leases include both lease and non-lease components which are primarily management services performed by the lessors for the underlying assets. All of our leases of office space and office equipment were classified as operating leases upon adoption. Our leases of field equipment had remaining terms of less than one year at the date of adoption and were not recognized as operating leases on our balance sheet due to our election of the short term lease practical expedient described below. Our leases do not contain any residual value guarantees or restrictive covenants. We do not sublease any of our ROU assets, although we aspire to sublease our unused office lease space. Operating fixed lease expenses are recognized on a straight-line basis over the lease term. Variable lease payments, which cannot be determined at the lease commencement date, are not included in ROU assets or lease liabilities and are expensed as incurred. Upon adoption, we selected the following practical expedients: Practical expedient package We did not reassess whether any expired or existing contracts are, or contain, leases. We did not reassess the lease classification of any expired or existing leases. We did not reassess initial direct costs of any expired or existing leases. Hindsight practical expedient We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets. Easement expedient We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease. Combining lease and non-lease components expedient We elected to account for lease and non-lease components as a single component. Short-term lease expedient We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet. As most leases do not have readily determinable implicit rates, we estimated the incremental borrowing rates for our future lease payments based on prevailing financial market conditions at the later of date of adoption or lease commencement, comparable companies and credit analysis and management judgments to determine the present values of our lease payments. We also apply the portfolio approach to account for leases with similar terms. At June 30, 2019 , for our operating leases the weighted-average remaining lease terms were approximately 8.1 years and our weighted-average discount rates were 14.1% . Lease Costs (in thousands) Three Months Ended Six Months Ended June 30, 2019 Operating lease cost $ 776 $ 1,587 Variable lease cost 473 796 Short-term lease cost 1,075 3,261 Total lease cost $ 2,324 $ 5,644 Reported as: Lease operating expense $ 1,031 $ 3,326 General and administrative expense 1,293 2,318 Total lease cost $ 2,324 $ 5,644 Operating Lease Liability Maturities as of June 30, 2019 Fiscal year (in thousands) Remainder of 2019 $ 1,470 2020 2,965 2021 2,942 2022 3,010 2023 2,718 Thereafter 12,647 Total lease payments 25,752 Less: imputed interest (11,081 ) Present value of operating lease liabilities $ 14,671 Current portion of operating lease liabilities $ 938 Operating lease liabilities, net of current portion 13,733 Present value of operating lease liabilities $ 14,671 Operating Lease Payment Obligations as of December 31, 2018 As described further in our 2018 10-K, our minimum future contractual lease payments under ASC 840 at December 31, 2018 were $2.8 million for 2019, $2.9 million for 2020, $2.9 million for 2021, $3.1 million for 2022, $3.0 million for 2023 and $12.2 million thereafter. Right-of-Use Asset Impairment During the second quarter of 2019, we consolidated employees in existing leased office space in Houston, Texas and Oklahoma City, Oklahoma. We are seeking to sublease the unused office space within three buildings. We do not anticipate that we will be able to fully recover the cash due to the lessor under the existing operating lease obligations in those three buildings with proceeds from subleases. As a result, we recognized a $6.5 million impairment of our existing right-of-use lease assets in those buildings during the three months ended June 30, 2019. This impairment had no impact to our lease liability.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
Supplemental Cash Flow Information	Jun. 30, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	SUPPLEMENTAL CASH FLOW INFORMATION Successor Predecessor (in thousands) Six Months Ended February 9, 2018 January 1, 2018 Supplemental cash flow information: Cash paid for interest $ 25,070 $ 21,216 $ 1,145 Cash paid for state income taxes, net of refunds — 6 — Non-cash investing and financing activities: Increase in asset retirement obligations 634 877 — Increase (decrease) in accruals or payables for capital expenditures (91,639 ) (27,646 ) 4,896 Distribution of non-STACK assets, net of liabilities — — 43,482 We aggregate cash, cash equivalents and restricted cash in the statements of cash flows. ໿

Receivables

Receivables	6 Months Ended
Receivables	Jun. 30, 2019
Receivables [Abstract]
Receivables	RECEIVABLES Accounts Receivable (in thousands) June 30, 2019 December 31, 2018 Production sales $ 29,730 $ 31,532 Joint interest billings 20,836 18,147 Pooling interest (1) 11,506 18,786 Allowance for doubtful accounts (410 ) (95 ) Total accounts receivable, net $ 61,662 $ 68,370 _________________ (1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties. Related Party Receivables (in thousands) June 30, 2019 December 31, 2018 Related party receivables $ 23,037 $ 33,316 Allowance for doubtful accounts (9,888 ) (9,034 ) Related party receivables, net 13,149 24,282 Notes receivable from related parties 13,403 13,403 Allowance for doubtful accounts (13,403 ) (13,403 ) Notes receivable from related parties, net — — Total related party receivables, net $ 13,149 $ 24,282 KFM Receivables We have entered into contracts with KFM whereby they provide midstream services, including produced water disposal, to us. During the six months ended June 30, 2019 , the period February 9, 2018 through June 30, 2018, and the Predecessor Period, we incurred $30.8 million , $13.6 million , and $3.1 million , respectively, in midstream services, which we have recognized in transportation and marketing expense. Additionally, we had related party receivables from KFM which include its portion of allocated G&A, other expenditures attributable to KFM and proceeds due to us for KFM’s sale of our natural gas and NGLs reduced by the fees from midstream services that KFM provided to us totaling $4.6 million and $11.2 million at June 30, 2019 and December 31, 2018 , respectively. In addition, we sold a produced water disposal system to KFM during the fourth quarter of 2018. As of December 31, 2018 , related party receivables of $8.7 million were attributable to a purchase price adjustment due from KFM. We collected this receivable during June 2019. AMR Receivables We incur general and administrative costs that may be partially or fully allocable to AMR. These costs are either allocated monthly or charged directly to AMR but are cash settled in arrears. As of June 30, 2019 and December 31, 2018, respectively, we have receivables from AMR for such costs totaling $8.5 million and $3.3 million , respectively. Management Services Agreement with High Mesa (in thousands) June 30, 2019 High Mesa related party receivable at December 31, 2018 $ 10,066 Additions 894 Payments (1,072 ) High Mesa related party receivable at June 30, 2019 9,888 Allowance for uncollectibility (1) (9,888 ) Balance at June 30, 2019, net $ — _________________ (1) $9.0 million of the allowance was recognized during the 2018 Successor Period. Just prior to the Business Combination, we distributed the non-STACK oil and gas assets to High Mesa. High Mesa and certain of its subsidiaries agreed to indemnify and hold us harmless from any liabilities associated with those non-STACK oil and gas assets, regardless of when those liabilities arose. We also entered into a management services agreement (the “High Mesa Agreement”) with HMI with respect to the non-STACK assets. Under the High Mesa Agreement, during the 180 -day period following the Closing, we agreed to provide certain administrative, management and operational services necessary to manage the business of HMI and its subsidiaries (the “Services”). Thereafter, the High Mesa Agreement automatically renewed for additional consecutive 180 -day periods, unless terminated by either party upon at least 90 -days written notice prior to renewal. HMI agreed to pay us each month (i) a management fee of $ 10,000 and (ii) an amount equal to any and all costs and expenses incurred in connection with providing the Services. Although the automatic renewal of this agreement occurred in the third quarter of 2018, the parties subsequently agreed to terminate the High Mesa Agreement, effective January 31, 2019. Through April 1, 2019, we were obligated to take all actions that HMI reasonably requested to effect the transition of the Services to a successor service provider. During the transition period, HMI agreed to pay us (i) for all Services performed, (ii) an amount equal to our costs and expenses incurred in connection with providing the Services as provided for in the approved budget and (iii) an amount equal to our costs and expenses reimbursable pursuant to the High Mesa Agreement. As of June 30, 2019 , and December 31, 2018 , approximately $9.9 million and $10.1 million, respectively, were due from HMI for reimbursement of costs and expenses which are recorded as “Related party receivables, net” in the balance sheets. HMI has disputed certain of the amounts we billed. We are pursuing remedies under applicable law in connection with repayment of this receivable. There is no guarantee that HMI will pay the amounts it owes. In addition, our ability to collect these amounts or future amounts that may become due pursuant to indemnification obligations may be adversely impacted by liquidity and solvency issues at HMI. As a result of these circumstances, we have recognized an allowance for uncollectible accounts of $9.9 million and $9.0 million as of June 30, 2019 and December 31, 2018 , respectively, to fully provide for the unremitted balances. We may also be subject to future contingent liabilities for the non-STACK assets for which we should have been indemnified, including liabilities associated with litigation relating to the non-STACK assets. As of June 30, 2019 and December 31, 2018, we have established no liabilities for contingent obligations associated with non-STACK assets owned by High Mesa. Promissory notes receivable In September, 2017, we entered into a $ 1.5 million promissory note receivable with our affiliate, Northwest Gas Processing, LLC, whose obligation was subsequently transferred to High Mesa Services, LLC (“HMS”), a subsidiary of HMI. The promissory note bore interest, which could be paid-in-kind and added to the principal amount at a rate of 8% per annum. HMS defaulted under the terms of that promissory note when it was not paid at maturity on February 28, 2019, and HMS has failed to cure such default. We subsequently declared all amounts owed under the note immediately due and payable and we have fully reserved the promissory note balance, including interest paid-in-kind, totaling $1.7 million as of June 30, 2019 and December 31, 2018 . In addition, we have an $ 8.5 million note receivable from HMS which matures on December 31, 2019, and bears interest at 8% per annum, which may be paid-in-kind and added to the principal amount. HMI disputes its obligations under the $8.5 million note. As of June 30, 2019 , and December 31, 2018 , the note receivable balance, including interest paid-in-kind, amounted to $11.7 million, for each respective period. This balance was fully reserved at the end of both periods. We oppose HMI’s claims and believe HMI’s obligations under the notes to be valid assets and that the full amount is payable to us. We are pursuing remedies under applicable law in connection with repayment of the promissory notes. As a result of the potential conflict of interest from certain of AMR’s directors who are also controlling holders of HMI, AMR’s disinterested directors will address any potential conflicts of interest with respect to this matter.

Property And Equipment

Property And Equipment	6 Months Ended
Property And Equipment	Jun. 30, 2019
Property, Plant and Equipment [Abstract]
Property And Equipment	PROPERTY AND EQUIPMENT (in thousands) June 30, 2019 December 31, 2018 Oil and gas properties Unproved properties $ 76,665 $ 74,217 Proved oil and gas properties 2,196,605 2,110,346 Accumulated depletion and impairment (1,489,191 ) (1,421,226 ) Proved oil and gas properties, net 707,414 689,120 Total oil and gas properties, net 784,079 763,337 Other property and equipment Land 5,059 5,059 Fresh water wells 27,372 27,366 Produced water disposal system 3,590 3,608 Office furniture, equipment and vehicles 2,825 2,840 Accumulated depreciation (1,475 ) (726 ) Other property and equipment, net 37,371 38,147 Total property and equipment, net $ 821,450 $ 801,484 Depletion and Depreciation Expense Successor Predecessor (in thousands) Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Oil and gas properties depletion $ 33,923 $ 26,086 $ 67,965 $ 36,859 $ 11,021 Other property and equipment depreciation 341 423 749 586 609 Total depletion and depreciation $ 34,264 $ 26,509 $ 68,714 $ 37,445 $ 11,630 Impairment During the three months ended June 30, 2019, we evaluated the qualitative market conditions and other factors impacting our business and concluded that there were no indicators of impairment impacting our property and equipment. Therefore, we did not conduct further analysis on the recognition of additional impairment.

Discontinued Operations

Discontinued Operations	6 Months Ended
Discontinued Operations	Jun. 30, 2019
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS (Predecessor) Alta Mesa distributed the non-STACK oil and gas assets and related liabilities to High Mesa immediately prior to the Business Combination. This distribution, including the results of operations of these assets and liabilities, is presented as discontinued operations during the Predecessor Period. Predecessor (in thousands) January 1, 2018 Revenue Oil $ 1,617 Natural gas 1,023 Natural gas liquids 236 Other 16 Operating revenue 2,892 Loss on sale of assets (1,923 ) Total revenue 969 Operating expenses Lease operating 1,770 Transportation and marketing 83 Production taxes 167 Workovers 127 Depreciation, depletion and amortization 884 Impairment of assets 5,560 General and administrative 21 Total operating expenses 8,612 Other expense Interest expense (103 ) Loss from discontinued operations, net of tax $ (7,746 ) Predecessor (in thousands) January 1, 2018 Total operating cash flows of discontinued operations $ 2,974 Total investing cash flows of discontinued operations (601 )

Derivatives

Derivatives	6 Months Ended
Derivatives	Jun. 30, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivatives	DERIVATIVES All of our derivatives have the lenders under the Alta Mesa RBL as counterparty, and are collateralized by the security interests thereunder. We periodically monitor the creditworthiness of our counterparties. Although our counterparties provide no collateral, the agreements with each counterparty allow us to set-off unpaid amounts against the outstanding balance under the Alta Mesa RBL. The derivatives settle monthly. No derivatives have been entered into for trading or speculative purposes and none have been designated as hedges under GAAP. The following summarizes the fair value and classification of our derivatives: June 30, 2019 Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 13,855 $ (9,128 ) $ 4,727 Derivatives, long-term assets 11,977 (9,469 ) 2,508 Total $ 25,832 $ (18,597 ) $ 7,235 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 9,968 $ (9,128 ) $ 840 Derivatives, long-term liabilities 9,658 (9,469 ) 189 Total $ 19,626 $ (18,597 ) $ 1,029 December 31, 2018 Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 22,512 $ (6,089 ) $ 16,423 Derivatives, long-term assets 7,910 (4,963 ) 2,947 Total $ 30,422 $ (11,052 ) $ 19,370 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 7,799 $ (6,089 ) $ 1,710 Derivatives, long-term liabilities 5,143 (4,963 ) 180 Total $ 12,942 $ (11,052 ) $ 1,890 The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands): Successor Predecessor Derivatives not designated as hedges Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Gain (loss) on derivatives - Oil $ 5,134 $ (28,712 ) $ (16,535 ) $ (50,656 ) $ 4,796 Natural gas 7,278 (507 ) 5,170 (574 ) 1,867 Total gain (loss) on derivatives $ 12,412 $ (29,219 ) $ (11,365 ) $ (51,230 ) $ 6,663 Other receivables at June 30, 2019 and December 31, 2018 include $1.4 million and $1.3 million, respectively, of derivative positions scheduled to be settled in the ensuing month. We had the following call and put derivatives at June 30, 2019 : OIL Remaining Volume Weighted Range Settlement Period and Type of Contract in bbls Average High Low 2019 Price Swap Contracts 92,000 $ 63.03 $ 63.03 $ 63.03 Collar Contracts Short Call Options 1,361,600 66.31 75.20 56.50 Long Put Options 1,453,600 53.80 62.00 50.00 Short Put Options 1,453,600 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 1,017,600 63.95 73.80 59.55 Long Put Options 1,566,600 56.81 62.50 50.00 Short Put Options 1,566,600 42.81 50.00 37.50 2021 Collar Contracts Short Call Options 279,750 63.51 63.75 63.35 Long Put Options 659,850 46.94 55.00 41.00 Short Put Options 279,750 43.00 43.00 43.00 NATURAL GAS Remaining Volume Weighted Range Settlement Period and Type of Contract in MMBtu Average High Low 2019 Price Swap Contracts 7,980,000 $ 2.67 $ 2.72 $ 2.64 Basis Swap Contracts 9,680,000 (0.72 ) (0.49 ) (0.93 ) Collar Contracts Short Call Options 1,525,000 3.19 3.20 3.17 Long Put Options 1,525,000 2.70 2.70 2.70 Short Put Options 1,525,000 2.20 2.20 2.20 2020 Price Swap Contracts 1,284,000 2.54 2.54 2.54 Basis Swap Contracts 910,000 (0.49 ) (0.49 ) (0.50 ) Collar Contracts Short Call Options 3,874,500 3.19 3.69 2.77 Long Put Options 10,749,500 2.59 3.00 2.50 Short Put Options 9,696,000 2.10 2.50 2.00 2021 Collar Contracts Short Call Options 540,000 3.25 3.25 3.25 Long Put Options 2,790,000 2.62 2.65 2.50 Short Put Options 2,250,000 2.15 2.15 2.15 We had the following basis swaps at June 30, 2019 : Total Gas Volumes in MMBtu (1) over Remaining Term Reference Price 1 (1) Reference Price 2 (1) Period Weighted Average Spread ($ per MMBtu) 460,000 OneOK NYMEX Henry Hub Jul '19 — Dec '19 $ (0.93 ) 7,990,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jul '19 — Dec '19 (0.70 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 1,230,000 San Juan NYMEX Henry Hub Jul '19 — Oct '19 (0.81 ) ________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

Accounts Payable And Accrued Li

Accounts Payable And Accrued Liabilities	6 Months Ended
Accounts Payable And Accrued Liabilities	Jun. 30, 2019
Payables and Accruals [Abstract]
Accounts Payable And Accrued Liabilities	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES ໿ (in thousands) June 30, 2019 December 31, 2018 Accounts payable $ 8,871 $ 20,200 Accruals for capital expenditures 18,477 101,214 Revenue and royalties payable 39,232 46,870 Accruals for operating expenses 10,701 16,355 Accrued interest 5,642 1,784 Derivative settlements 743 109 Other 8,028 10,532 Total accrued liabilities 82,823 176,864 Accounts payable and accrued liabilities $ 91,694 $ 197,064

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
Asset Retirement Obligations	Jun. 30, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS Successor Predecessor (in thousands) Six Months Ended February 9, 2018 January 1, 2018 Balance, beginning of period $ 11,409 $ — $ 10,469 Liabilities assumed in Business Combination — 5,998 — Liabilities incurred 634 877 — Liabilities settled (162 ) (806 ) (63 ) Liabilities transferred in sale of properties — (20 ) — Revisions to estimates (9 ) 665 63 Accretion expense 465 263 40 Balance, end of period 12,337 6,977 10,509 Less: Current portion 44 538 33 Long-term portion $ 12,293 $ 6,439 $ 10,476

Debt

Debt	6 Months Ended
Debt	Jun. 30, 2019
Debt Disclosure [Abstract]
Debt	DEBT ໿ (in thousands) June 30, 2019 December 31, 2018 Alta Mesa RBL $ 344,500 $ 161,000 2024 Notes 500,000 500,000 Unamortized premium on 2024 Notes 26,662 29,123 Total debt, net 871,162 690,123 Less: Current portion 871,162 — Long-term debt, net $ — $ 690,123 Alta Mesa RBL The Alta Mesa RBL has two covenants that are tested quarterly: • a ratio of our current assets to current liabilities, inclusive of specified adjustments, of not less than 1.0 to 1.0; and • a ratio of our consolidated debt to our consolidated Adjusted EBITDAX (the “leverage ratio”) of not greater than 4.0 to 1.0 . For the first 3 measurement periods following the Business Combination we were able to annualize cumulative Successor Period results in measuring Adjusted EBITDAX. Before July 2020, and possibly as soon as September 30, 2019 , we do not expect to satisfy the leverage ratio. We recognize the need to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. At June 30, 2019 , inclusive of $20.2 million of outstanding letters of credit, we had $5.3 million of stated borrowing capacity remaining under the Alta Mesa RBL, dependent upon the lenders’ willingness to provide such funds. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. Our discussion about our ability to continue as a going concern provides information about the borrowing base and deficiency payments arising from the redetermination. 2024 Notes In connection with the Business Combination, we recorded the fair value of our $500.0 million unsecured senior notes at $ 533.6 million as of the acquisition date. We have estimated the fair value of our senior notes to be $193.8 million at June 30, 2019 . This estimation was based on the most recent trading values of the senior notes at or near the reporting date, which is a Level 1 determination. Scheduled Maturities of Debt Fiscal year (in thousands) 2019 $ — 2020 — 2021 — 2022 — 2023 344,500 Thereafter 500,000 $ 844,500 Based upon the factors leading to the substantial unresolved doubt about our ability to continue as a going concern, we believe that it is probable that our indebtedness will accelerate prior to July 1, 2020, and earlier than the scheduled maturities shown above. We have reported all of our debt as current at June 30, 2019 .

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended
Commitments And Contingencies	Jun. 30, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES There have been no material changes during the first six months of 2019 in our commitments and contingencies as compared to our discussion of those matters in our 2018 10-K.

Significant Concentrations

Significant Concentrations	6 Months Ended
Significant Concentrations	Jun. 30, 2019
Significant Concentrations [Abstract]
Significant Concentrations	SIGNIFICANT CONCENTRATIONS During a portion of 2019 and throughout 2018, ARM Energy Management, LLC ("ARM") marketed our oil, gas and NGLs for a marketing fee that is deducted from sales proceeds collected by ARM from purchasers. The sales are generally made under short-term contracts with month-to-month pricing based on published regional indices, adjusted for transportation, location and quality. In March 2019, in preparation for handling oil and NGL marketing responsibilities internally, we began receiving payments for the sale of oil and NGLs directly from purchasers and separately paying the marketing fee owed to ARM. As of June 1, 2019, we terminated our oil and NGL marketing agreement with ARM and have begun marketing such products internally. We have extended the term of our gas marketing agreement with ARM through November 30, 2019. Our affiliate, Kingfisher Midstream, LLC (“KFM”) is responsible for marketing our firm transportation on the ONEOK Gas Transmission, L.L.C. system, which is indirectly marketed by ARM through an asset management agreement. ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities. Successor Predecessor (in thousands) Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Revenue marketed by ARM on our behalf $ 7,703 $ 70,601 $ 91,534 $ 107,944 $ 28,757 Marketing and management fees paid to ARM $ 476 $ — $ 1,137 $ — $ — Fees paid to ARM for derivative services 218 209 411 283 66 Total fees paid to ARM $ 694 $ 209 $ 1,548 $ 283 $ 66 Receivables from ARM for sales on our behalf were $ 0.2 million and $38.4 million as of June 30, 2019 and December 31, 2018 , respectively, which are reflected in accounts receivable on our balance sheets. We believe that the loss of any of our customers, or of our marketing agent ARM, would not have a material adverse effect on us because alternative purchasers are readily available.

Equity-Based Compensation (Succ

Equity-Based Compensation (Successor)	6 Months Ended
Equity-Based Compensation (Successor)	Jun. 30, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation (Successor)	EQUITY-BASED COMPENSATION (Successor) Stock compensation expense allocated to us by AMR pursuant to its equity-based compensation programs was as follows: Successor Predecessor (in thousands) Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Stock options $ 744 $ 1,606 $ 1,535 $ 2,628 $ — Restricted stock awards 563 871 1,425 1,412 — Performance-based restricted stock units 89 1,144 97 2,349 — Total compensation expense $ 1,396 $ 3,621 $ 3,057 $ 6,389 $ — Performance-based restricted stock units (“PSUs”) issued in 2018 generally vest over three years at 20% during the first year (“2018 tranche”), 30% during the second year (“2019 tranche”), and 50% during the third year (“2020 tranche”). The number of PSUs vesting each year are based on achievement of annual company-specific performance goals and obligations applicable to each year of vesting. Based on achievement of those goals and objectives, the number of PSUs that can vest range from 0% to 200% of the target growth applicable to each vesting period. The performance goals set for the 2018 tranche were not attained and, therefore, the 2018 tranche was forfeited as of December 31, 2018, except with respect to separations involving employment agreements whereby the separated employee was eligible to receive the award granted. The performance targets for the 2019 tranche were established in March 2019 and 595,417 PSUs were deemed granted at that time. The fair value of the 2019 tranche granted was $0.27 per unit, which will be recognized as expense over the remainder of 2019, subject to continued employment. No performance targets have yet been established for the 2020 tranche and therefore, no expense will be recognized for those awards until the specific targets have been established and probability of attainment can be measured.

Related Party Transactions

Related Party Transactions	6 Months Ended
Related Party Transactions	Jun. 30, 2019
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 15 — RELATED PARTY TRANSACTIONS As of December 31, 2018, we had a payable of $2.9 million to KFM for produced water disposal services provided following the sale of the produced water system to them during the fourth quarter of 2018. Beginning in 2019, these costs are utilized to reduce the amount that KFM owes us for marketing our production, which are reported in related party receivables. As of December 31, 2018, we had a payable to AMR of $0.5 million which was settled during the second quarter of 2019. David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provided land consulting services to us until termination of our contract in December 2018. The primary employee of David Murrell & Associates was his spouse, Brigid Murrell. Services were provided at a pre-negotiated hourly rate based on actual time utilized by us. Total expenditures under this arrangement were approximately $83,000 and $ 28,000 for the period February 9, 2018 through June 30, 2018 , and the Predecessor Period, respectively. These amounts are recorded in general and administrative expenses. David McClure, AMR’s former Vice President of Facilities and Infrastructure, and the son-in-law of our former President and Chief Executive Officer, Harlan H. Chappelle, received total compensation of $768,860 , $929,428 and $28,874 during the six months ended June 30, 2019 , the period February 9, 2018 through June 30, 2018 , and the Predecessor Period, respectively. These amounts are included in general and administrative expense and represent the portion that was allocated to AMH. Mr. McClure separated from the Company in February 2019. Bayou City Agreement In January 2016, our wholly owned subsidiary Oklahoma Energy entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “JDA”), with BCE, a fund advised by Bayou City, to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. The JDA established a development plan of 60 wells in three tranches, and provides opportunities for an additional 20 wells. Pursuant to the JDA, BCE committed to fund 100% of our working interest up to a maximum average well cost of $ 3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding approved amounts. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. In exchange for funding the drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE each bear our respective proportionate working interest share of all subsequent costs related to such joint well. Mr. William McMullen, one of our directors, is founder and managing partner of BCE. The approximate dollar value of the amount involved in this transaction, or Mr. McMullen’s interests in the transaction, depends on a number of factors outside his control and is not known at this time. During the Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the JDA. Through June 30, 2019 , 61 joint wells have been drilled or spudded. At June 30, 2019 and December 31, 2018 , $4.0 million and $9.8 million, respectively of revenue and net advances remaining from BCE for their working interest share of the drilling and development costs arising under the JDA were included as “Advances from related party” in our condensed consolidated balance sheets. At June 30, 2019 , there were no funded horizontal wells in progress, and we do not expect any wells to be developed in 2019 pursuant to the JDA. On June 11, 2019, we received a letter from BCE noticing us of alleged defaults under the JDA. We dispute these allegations and intend to vigorously defend ourselves.

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policies)	6 Months Ended
Summary Of Significant Accounting Policies (Policies)	Jun. 30, 2019
Accounting Policies [Abstract]
Going Concern	Going Concern We are required to evaluate our ability to continue as a going concern for a period of one year following the date of issuance of our financial statements. As part of that evaluation, we took into consideration the following factors: • Market prices for crude oil have declined since the Business Combination. This negatively impacted our future operating cash flow and lowers our expected future economic results from our assets compared with the time of the Business Combination. • Our 2018 drilling program, much of which involved the drilling of additional wells in close proximity to existing wells, did not meet our expectations for production and recovery and reduces the number of wells we expect to develop in the future compared with the time of the Business Combination. We also experienced an increasing gas-to-oil ratio as a well’s production ages, which has contributed to a lowering of the expected economics of our properties. • Although our well costs for our 2019 capital program have averaged less than $3.0 million per well, we still expect our operating cash flow to be less than our 2019 capital spending. Future well costs are expected to increase as we move into higher cost areas of our acreage which have less infrastructure in place and that may require more intense completions. • On April 1, 2019 , our borrowing base under the Alta Mesa RBL was reduced to $370.0 million and we had no meaningful remaining capacity available thereunder at June 30, 2019 . Without additional capital, we will only be able to utilize the cash on hand, which at July 31, 2019 was $79.7 million, to fund development and meet our financial obligations. We may be unable to obtain covenant relief or to replace the Alta Mesa RBL with debt that would allow us to meet any attendant covenant requirements. Also, the lack of sufficient capital may prevent us from maintaining our current levels of production, which could negatively impact our ability over time to service our debt and meet our other obligations. In August 2019, the lenders exercised their ability to make an optional redetermination of our borrowing base ahead of the regular redetermination scheduled in October 2019, and via this redetermination, our borrowing base was reset to $200 million, effective August 13, 2019. As our combined borrowings and letters of credit outstanding exceed the new borrowing base amount by $162.4 million , we have five months to make ratable payments of $32.5 million to cause utilization to be less than or equal to the borrowing base. The first payment is due in September 2019. If we are unable to make this repayment, we will be in default under the Alta Mesa RBL. There is a risk that future redeterminations could reduce the borrowing base further. Our decreased borrowing base could cause us to reduce or abandon our development activities. • We do not anticipate meeting our existing leverage covenants through June 2020 without relief from our lenders and currently expect not to be able to satisfy the consolidated total leverage ratio covenant in the Alta Mesa RBL as early as the measurement date of September 30, 2019 . • We have $500.0 million of unsecured debt in the form of our 2024 Notes, with an interest payment of approximately $20.0 million due in December 2019, which could become an event of default if unpaid before January 14, 2020. The 2024 Notes trade substantially below par value. • The Class A common stock of our parent company, AMR, has been trading below $1.00 per share since February 22, 2019. On April 3, 2019, AMR was notified by NASDAQ that it was not in compliance with the minimum bid price requirement. Continued trading at these levels may limit its and our ability to raise additional capital in the equity markets. • Our ability to collect receivables due from High Mesa and its affiliates The above factors raise substantial doubt about our and our parent’s ability to continue as a going concern. To address this, we have: • retained financial advisors to assist in evaluating financial alternatives; • engaged in discussions with the advisors for the Alta Mesa RBL lenders about obtaining covenant relief to address the future expected inability to satisfy the leverage requirement. To date we have been unable to reach an accord on any such relief and do not expect that the lenders would grant any extended period of covenant relief; • considered seeking new sources of financing, however, such efforts do not appear to present a substantive solution; and • engaged in discussions with and provided requested information to financial and legal advisors for a group of holders of Alta Mesa’s 2024 Notes, but we cannot predict what will result from the discussions or whether they will yield a constructive deal. Regardless of whether we are able to reach an agreement with our creditors, it may be necessary for us to file a voluntary petition for relief under Chapter 11 of the U.S. Bankruptcy Code. In light of these factors, we believe substantial unresolved doubt exists regarding our ability to continue as a going concern for the 12 months following the issuance of these financial statements. Based on the foregoing, we believe that it is probable that our indebtedness will accelerate before July 2020 and, therefore, have reported all of our debt as current. Recently Issue
Recently Issued and Applicable Accounting Standards	Recently Issued Accounting Standards Applicable to Us Adopted Effective January 1, 2019, we adopted ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which requires that lessees recognize a lease liability, which is a lessee’s discounted obligation to make payments under a lease and a right-of-use asset, arising from a lessee’s right to use an asset over the lease term. Upon adoption, we used the modified retrospective method to apply the standard as of January 1, 2019 for existing leases with terms in excess of 12 months entered into prior to January 1, 2019. Not Yet Adopted In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard requires the use of a new “expected credit loss” impairment model rather than the “incurred loss” model we use today. With respect to our trade and notes receivables and certain other financial instruments, we may be required to (i) maintain and use lifetime loss information rather than annual loss data and (ii) forecast future economic conditions and quantify the effect of those conditions on future expected losses. The standard, including related amendments, which will be effective for us on January 1, 2020, also requires additional disclosures regarding the credit quality of our trade and notes receivables and other financial instruments. No determination has yet been made of the impact of this new standard on our financial position or results of operations. In August 2018, the FASB issued ASU No. 2018-15, Intangibles - Goodwill and Other - Internal-Use Software (Topic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract (“ASU 2018-15”). The amendments in this standard align the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal use software (and hosting arrangements that include an internal-use software license). Under this new standard, a customer in a hosting arrangement that is a service contract is required to follow the guidance in Subtopic 350-40 to determine which implementation costs to capitalize as a prepaid asset related to the service contract and which costs to expense. The capitalized implementation costs are to be expensed over the term of the hosting arrangement and reflected in the same line in the consolidated statement of operations as the fees associated with the hosting element of the arrangement. Similarly, capitalized implementation costs are to be presented in the statement of cash flows in the same line as payments made for fees associated with the hosting element. We will adopt this new standard no later than January 1, 2020, although early adoption is permitted. We are currently evaluating the impact of this new standard on our consolidated financial position and results of operations and have not yet determined when to adopt and whether to apply the new standard retrospectively or prospectively to implementation costs incurred after the date of adoption. In August 2018, the FASB issued ASU No. 2018-13, Fair Value Measurement (Topic 820) Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”), which modifies the disclosure requirements of fair value measurements. ASU 2018-13 is effective for us beginning January 1, 2020. Certain disclosures are required to be applied on a retrospective basis and others on a prospective basis. We do not expect the adoption of this standard to impact our financial position or results of operations.

Adoption of ASU No. 2016-02, _2

Adoption of ASU No. 2016-02, Leases (Tables)	6 Months Ended
Adoption of ASU No. 2016-02, Leases (Tables)	Jun. 30, 2019
Leases [Abstract]
Schedule of Practical Expedients	Upon adoption, we selected the following practical expedients: Practical expedient package We did not reassess whether any expired or existing contracts are, or contain, leases. We did not reassess the lease classification of any expired or existing leases. We did not reassess initial direct costs of any expired or existing leases. Hindsight practical expedient We did not elect to use the hindsight practical expedient which allows for the use of hindsight when determining lease term, including option periods, and impairment of operating assets. Easement expedient We elected to maintain the current accounting treatment of existing contracts and not reassess whether those contracts met the definition of a lease. Combining lease and non-lease components expedient We elected to account for lease and non-lease components as a single component. Short-term lease expedient We elected the short-term lease recognition exemption for all classes of underlying assets. Expense for short-term leases is recognized on a straight-line basis over the lease term. Leases with an initial term of 12 months or less and that do not include an option to purchase the underlying asset that is reasonably certain to be recognized are not recorded on the balance sheet.
Lease Cost	Lease Costs (in thousands) Three Months Ended Six Months Ended June 30, 2019 Operating lease cost $ 776 $ 1,587 Variable lease cost 473 796 Short-term lease cost 1,075 3,261 Total lease cost $ 2,324 $ 5,644 Reported as: Lease operating expense $ 1,031 $ 3,326 General and administrative expense 1,293 2,318 Total lease cost $ 2,324 $ 5,644
Maturities of Operating Lease Liabilities	Operating Lease Liability Maturities as of June 30, 2019 Fiscal year (in thousands) Remainder of 2019 $ 1,470 2020 2,965 2021 2,942 2022 3,010 2023 2,718 Thereafter 12,647 Total lease payments 25,752 Less: imputed interest (11,081 ) Present value of operating lease liabilities $ 14,671 Current portion of operating lease liabilities $ 938 Operating lease liabilities, net of current portion 13,733 Present value of operating lease liabilities $ 14,671

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	6 Months Ended
Supplemental Cash Flow Information (Tables)	Jun. 30, 2019
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosures To The Consolidated Statements Of Cash Flows	Successor Predecessor (in thousands) Six Months Ended February 9, 2018 January 1, 2018 Supplemental cash flow information: Cash paid for interest $ 25,070 $ 21,216 $ 1,145 Cash paid for state income taxes, net of refunds — 6 — Non-cash investing and financing activities: Increase in asset retirement obligations 634 877 — Increase (decrease) in accruals or payables for capital expenditures (91,639 ) (27,646 ) 4,896 Distribution of non-STACK assets, net of liabilities — — 43,482

Receivables (Tables)

Receivables (Tables)	6 Months Ended
Receivables (Tables)	Jun. 30, 2019
Receivables [Abstract]
Schedule of Accounts Receivable	Accounts Receivable (in thousands) June 30, 2019 December 31, 2018 Production sales $ 29,730 $ 31,532 Joint interest billings 20,836 18,147 Pooling interest (1) 11,506 18,786 Allowance for doubtful accounts (410 ) (95 ) Total accounts receivable, net $ 61,662 $ 68,370 _________________ (1) Pooling interest relates to Oklahoma’s forced pooling process which permits mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents unbilled costs for wells where the option remains pending. Depending upon the mineral owner’s decision, these costs will be billed to them or added to oil and gas properties. Related Party Receivables (in thousands) June 30, 2019 December 31, 2018 Related party receivables $ 23,037 $ 33,316 Allowance for doubtful accounts (9,888 ) (9,034 ) Related party receivables, net 13,149 24,282 Notes receivable from related parties 13,403 13,403 Allowance for doubtful accounts (13,403 ) (13,403 ) Notes receivable from related parties, net — — Total related party receivables, net $ 13,149 $ 24,282 Management Services Agreement with High Mesa (in thousands) June 30, 2019 High Mesa related party receivable at December 31, 2018 $ 10,066 Additions 894 Payments (1,072 ) High Mesa related party receivable at June 30, 2019 9,888 Allowance for uncollectibility (1) (9,888 ) Balance at June 30, 2019, net $ — _________________ (1) $9.0 million of the allowance was recognized during the 2018 Successor Period.

Property And Equipment (Tables)

Property And Equipment (Tables)	6 Months Ended
Property And Equipment (Tables)	Jun. 30, 2019
Property, Plant and Equipment [Abstract]
Summary Of Property And Equipment	Successor Predecessor (in thousands) Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Oil and gas properties depletion $ 33,923 $ 26,086 $ 67,965 $ 36,859 $ 11,021 Other property and equipment depreciation 341 423 749 586 609 Total depletion and depreciation $ 34,264 $ 26,509 $ 68,714 $ 37,445 $ 11,630 (in thousands) June 30, 2019 December 31, 2018 Oil and gas properties Unproved properties $ 76,665 $ 74,217 Proved oil and gas properties 2,196,605 2,110,346 Accumulated depletion and impairment (1,489,191 ) (1,421,226 ) Proved oil and gas properties, net 707,414 689,120 Total oil and gas properties, net 784,079 763,337 Other property and equipment Land 5,059 5,059 Fresh water wells 27,372 27,366 Produced water disposal system 3,590 3,608 Office furniture, equipment and vehicles 2,825 2,840 Accumulated depreciation (1,475 ) (726 ) Other property and equipment, net 37,371 38,147 Total property and equipment, net $ 821,450 $ 801,484

Discontinued Operations (Tables

Discontinued Operations (Tables)	6 Months Ended
Discontinued Operations (Tables)	Jun. 30, 2019
Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Schedule Of Discontinued Operations	Predecessor (in thousands) January 1, 2018 Revenue Oil $ 1,617 Natural gas 1,023 Natural gas liquids 236 Other 16 Operating revenue 2,892 Loss on sale of assets (1,923 ) Total revenue 969 Operating expenses Lease operating 1,770 Transportation and marketing 83 Production taxes 167 Workovers 127 Depreciation, depletion and amortization 884 Impairment of assets 5,560 General and administrative 21 Total operating expenses 8,612 Other expense Interest expense (103 ) Loss from discontinued operations, net of tax $ (7,746 ) Predecessor (in thousands) January 1, 2018 Total operating cash flows of discontinued operations $ 2,974 Total investing cash flows of discontinued operations (601 )

Derivatives (Tables)

Derivatives (Tables)	6 Months Ended
Derivatives (Tables)	Jun. 30, 2019
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The following summarizes the fair value and classification of our derivatives: June 30, 2019 Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 13,855 $ (9,128 ) $ 4,727 Derivatives, long-term assets 11,977 (9,469 ) 2,508 Total $ 25,832 $ (18,597 ) $ 7,235 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 9,968 $ (9,128 ) $ 840 Derivatives, long-term liabilities 9,658 (9,469 ) 189 Total $ 19,626 $ (18,597 ) $ 1,029 December 31, 2018 Balance sheet location Gross fair value of assets Gross liabilities offset against assets in the Balance Sheet Net fair value of assets presented in the Balance Sheet (in thousands) Derivatives, current assets $ 22,512 $ (6,089 ) $ 16,423 Derivatives, long-term assets 7,910 (4,963 ) 2,947 Total $ 30,422 $ (11,052 ) $ 19,370 Balance sheet location Gross fair value of liabilities Gross assets offset against liabilities in the Balance Sheet Net fair value of liabilities presented in the Balance Sheet (in thousands) Derivatives, current liabilities $ 7,799 $ (6,089 ) $ 1,710 Derivatives, long-term liabilities 5,143 (4,963 ) 180 Total $ 12,942 $ (11,052 ) $ 1,890
Effect Of Derivative Instruments In The Consolidated Statements Of Operations	The following table summarizes the effect of our derivatives in the consolidated statements of operations (in thousands): Successor Predecessor Derivatives not designated as hedges Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Gain (loss) on derivatives - Oil $ 5,134 $ (28,712 ) $ (16,535 ) $ (50,656 ) $ 4,796 Natural gas 7,278 (507 ) 5,170 (574 ) 1,867 Total gain (loss) on derivatives $ 12,412 $ (29,219 ) $ (11,365 ) $ (51,230 ) $ 6,663
Oil Derivative Contracts
Derivative [Line Items]
Open Derivative Contracts	Remaining Volume Weighted Range Settlement Period and Type of Contract in bbls Average High Low 2019 Price Swap Contracts 92,000 $ 63.03 $ 63.03 $ 63.03 Collar Contracts Short Call Options 1,361,600 66.31 75.20 56.50 Long Put Options 1,453,600 53.80 62.00 50.00 Short Put Options 1,453,600 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 1,017,600 63.95 73.80 59.55 Long Put Options 1,566,600 56.81 62.50 50.00 Short Put Options 1,566,600 42.81 50.00 37.50 2021 Collar Contracts Short Call Options 279,750 63.51 63.75 63.35 Long Put Options 659,850 46.94 55.00 41.00 Short Put Options 279,750 43.00 43.00 43.00
Natural Gas Derivative Contract
Derivative [Line Items]
Open Derivative Contracts	Remaining Volume Weighted Range Settlement Period and Type of Contract in MMBtu Average High Low 2019 Price Swap Contracts 7,980,000 $ 2.67 $ 2.72 $ 2.64 Basis Swap Contracts 9,680,000 (0.72 ) (0.49 ) (0.93 ) Collar Contracts Short Call Options 1,525,000 3.19 3.20 3.17 Long Put Options 1,525,000 2.70 2.70 2.70 Short Put Options 1,525,000 2.20 2.20 2.20 2020 Price Swap Contracts 1,284,000 2.54 2.54 2.54 Basis Swap Contracts 910,000 (0.49 ) (0.49 ) (0.50 ) Collar Contracts Short Call Options 3,874,500 3.19 3.69 2.77 Long Put Options 10,749,500 2.59 3.00 2.50 Short Put Options 9,696,000 2.10 2.50 2.00 2021 Collar Contracts Short Call Options 540,000 3.25 3.25 3.25 Long Put Options 2,790,000 2.62 2.65 2.50 Short Put Options 2,250,000 2.15 2.15 2.15
Basis Swap Derivative Contract
Derivative [Line Items]
Natural Gas Basis Swap Contracts	We had the following basis swaps at June 30, 2019 : Total Gas Volumes in MMBtu (1) over Remaining Term Reference Price 1 (1) Reference Price 2 (1) Period Weighted Average Spread ($ per MMBtu) 460,000 OneOK NYMEX Henry Hub Jul '19 — Dec '19 $ (0.93 ) 7,990,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jul '19 — Dec '19 (0.70 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 1,230,000 San Juan NYMEX Henry Hub Jul '19 — Oct '19 (0.81 ) ________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.

Accounts Payable And Accrued _2

Accounts Payable And Accrued Liabilities (Tables)	6 Months Ended
Accounts Payable And Accrued Liabilities (Tables)	Jun. 30, 2019
Payables and Accruals [Abstract]
Detail Of Accounts Payable And Accrued Liabilities	(in thousands) June 30, 2019 December 31, 2018 Accounts payable $ 8,871 $ 20,200 Accruals for capital expenditures 18,477 101,214 Revenue and royalties payable 39,232 46,870 Accruals for operating expenses 10,701 16,355 Accrued interest 5,642 1,784 Derivative settlements 743 109 Other 8,028 10,532 Total accrued liabilities 82,823 176,864 Accounts payable and accrued liabilities $ 91,694 $ 197,064

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
Asset Retirement Obligations (Tables)	Jun. 30, 2019
Asset Retirement Obligation Disclosure [Abstract]
Summary Of Changes In Asset Retirement Obligations	Successor Predecessor (in thousands) Six Months Ended February 9, 2018 January 1, 2018 Balance, beginning of period $ 11,409 $ — $ 10,469 Liabilities assumed in Business Combination — 5,998 — Liabilities incurred 634 877 — Liabilities settled (162 ) (806 ) (63 ) Liabilities transferred in sale of properties — (20 ) — Revisions to estimates (9 ) 665 63 Accretion expense 465 263 40 Balance, end of period 12,337 6,977 10,509 Less: Current portion 44 538 33 Long-term portion $ 12,293 $ 6,439 $ 10,476

Debt (Tables)

Debt (Tables)	6 Months Ended
Debt (Tables)	Jun. 30, 2019
Debt Disclosure [Abstract]
Long-Term Debt, Net And Notes Payable To Founder	(in thousands) June 30, 2019 December 31, 2018 Alta Mesa RBL $ 344,500 $ 161,000 2024 Notes 500,000 500,000 Unamortized premium on 2024 Notes 26,662 29,123 Total debt, net 871,162 690,123 Less: Current portion 871,162 — Long-term debt, net $ — $ 690,123
Summary Of Future Maturities Of Long-Term Debt	Fiscal year (in thousands) 2019 $ — 2020 — 2021 — 2022 — 2023 344,500 Thereafter 500,000 $ 844,500

Significant Concentrations (Tab

Significant Concentrations (Tables)	6 Months Ended
Significant Concentrations (Tables)	Jun. 30, 2019
Significant Concentrations [Abstract]
Schedule of Significant Concentrations	ARM also provides us with strategic advice, execution and reporting services with respect to our derivatives activities. Successor Predecessor (in thousands) Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Revenue marketed by ARM on our behalf $ 7,703 $ 70,601 $ 91,534 $ 107,944 $ 28,757 Marketing and management fees paid to ARM $ 476 $ — $ 1,137 $ — $ — Fees paid to ARM for derivative services 218 209 411 283 66 Total fees paid to ARM $ 694 $ 209 $ 1,548 $ 283 $ 66

Equity-Based Compensation (Su_2

Equity-Based Compensation (Successor) (Tables)	6 Months Ended
Equity-Based Compensation (Successor) (Tables)	Jun. 30, 2019
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock compensation expense recognized	Stock compensation expense allocated to us by AMR pursuant to its equity-based compensation programs was as follows: Successor Predecessor (in thousands) Three Months Ended Three Months Ended Six Months Ended February 9, 2018 January 1, 2018 Stock options $ 744 $ 1,606 $ 1,535 $ 2,628 $ — Restricted stock awards 563 871 1,425 1,412 — Performance-based restricted stock units 89 1,144 97 2,349 — Total compensation expense $ 1,396 $ 3,621 $ 3,057 $ 6,389 $ —

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Details) - USD ($)	Aug. 13, 2019	Dec. 31, 2019	Jul. 31, 2019	Jun. 30, 2019	Apr. 01, 2019	Feb. 22, 2019	Dec. 31, 2018	Feb. 09, 2018
Summary Of Significant Accounting Policies [Line Items]
Capital program well costs				$ 3,000,000
2024 Notes								$ 533,600,000
2024 Notes
Summary Of Significant Accounting Policies [Line Items]
2024 Notes				$ 500,000,000			$ 500,000,000
Parent Company \| Common Class A
Summary Of Significant Accounting Policies [Line Items]
Common stock par value (in dollars per share)						$ 1
Alta Mesa Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Current borrowing capacity					$ 370,000,000
Subsequent Event \| Alta Mesa Credit Facility
Summary Of Significant Accounting Policies [Line Items]
Current borrowing capacity	$ 200,000,000
Cash			$ 79,700,000
Amount exceeding borrowing base	162,400,000
Monthly payments	$ 32,500,000
Scenario, Forecast
Summary Of Significant Accounting Policies [Line Items]
Interest payment		$ 20,000,000

Adoption of ASU No. 2016-02, _3

Adoption of ASU No. 2016-02, Leases (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		5 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2018	Jan. 01, 2019	Dec. 31, 2018
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right of use asset recognized	$ 7,871
Weighted-average remaining lease term (in years)	8 years 1 month 18 days
Weighted-average discount rate	14.10%
Lease payment under ASC 840, due 2019						$ 2,800
Lease payment under ASC 840, due 2020						2,900
Lease payment under ASC 840, due 2021						2,900
Lease payment under ASC 840, due 2022						3,100
Lease payment under ASC 840, due 2023						3,000
Lease payment under ASC 840, due thereafter						$ 12,200
Impairment loss	$ 6,500	$ 0	$ 0	$ 6,500
Accounting Standards Update 2016-02
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, right of use asset recognized					$ 15,000

Adoption of ASU No. 2016-02, _4

Adoption of ASU No. 2016-02, Leases (Lease Costs) (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Operating lease cost	$ 776	$ 1,587
Variable lease cost	473	796
Short-term lease cost	1,075	3,261
Total lease cost	2,324	5,644
Lease operating expense
Lessee, Lease, Description [Line Items]
Total lease cost	1,031	3,326
General and administrative
Lessee, Lease, Description [Line Items]
Total lease cost	$ 1,293	$ 2,318

Adoption of ASU No. 2016-02, _5

Adoption of ASU No. 2016-02, Leases (Operating Lease Liability Maturities) (Details) $ in Thousands	Jun. 30, 2019USD ($)
Leases [Abstract]
Remainder of 2019	$ 1,470
2020	2,965
2021	2,942
2022	3,010
2023	2,718
Thereafter	12,647
Total lease payments	25,752
Less: imputed interest	(11,081)
Present value of operating lease liability	14,671
Current portion of operating lease liabilities	938
Operating lease liabilities, net of current portion	13,733
Operating lease liability recognized	$ 14,671

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019
Supplemental cash flow information:
Cash paid for interest		$ 21,216	$ 25,070
Cash paid for state income taxes, net of refunds		6	0
Non-cash investing and financing activities:
Increase in asset retirement obligations		877	634
Increase (decrease) in accruals or payables for capital expenditures		(27,646)	(91,639)
Distribution of non-STACK assets, net of liabilities		$ 0	$ 0
Predecessor
Supplemental cash flow information:
Cash paid for interest	$ 1,145
Cash paid for state income taxes, net of refunds	0
Non-cash investing and financing activities:
Increase in asset retirement obligations	0
Increase (decrease) in accruals or payables for capital expenditures	4,896
Distribution of non-STACK assets, net of liabilities	$ 43,482

Receivables (Schedule of Accoun

Receivables (Schedule of Accounts Receivable) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
Production sales	$ 29,730	$ 31,532
Joint interest billings	20,836	18,147
Pooling interest	11,506	18,786
Allowance for doubtful accounts	(410)	(95)
Total related party receivables, net	$ 61,662	$ 68,370

Receivables (Schedule of Relate

Receivables (Schedule of Related Party Receivables) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Receivables [Abstract]
Related party receivables	$ 23,037	$ 33,316
Allowance for doubtful accounts	(9,888)	(9,034)
Related party receivables, net	13,149	24,282
Notes receivable from related parties	13,403	13,403
Allowance for doubtful accounts	(13,403)	(13,403)
Notes receivable from related parties, net	0	0
Total related party receivables, net	$ 13,149	$ 24,282

Receivables Receivables (Narrat

Receivables Receivables (Narrative) (Details) - USD ($)	1 Months Ended	3 Months Ended	5 Months Ended	6 Months Ended	12 Months Ended
Receivables Receivables (Narrative) (Details) - USD ($)	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018	Sep. 29, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Notes receivable from related parties, net		$ 0		$ 0	$ 0
Related party receivables, net		13,149,000		13,149,000	24,282,000
Northwest Gas Processing
Accounts, Notes, Loans and Financing Receivable [Line Items]
Promissory note						$ 1,500,000
Debt Instrument, Interest Rate, Stated Percentage						8.00%
Notes receivable from related parties, net		1,700,000		1,700,000	1,700,000
Alta Mesa Resources
Accounts, Notes, Loans and Financing Receivable [Line Items]
Related party receivables		$ 8,500,000		8,500,000	3,300,000
High Mesa Agreement \| Affiliated Entity
Accounts, Notes, Loans and Financing Receivable [Line Items]
Initial agreement term		180 days
Automatic renewal period		180 days
Notice period to terminate agreement		90 days
Management fee					10,000
Balance of note receivable		$ 9,900,000		9,900,000	10,100,000
Allowance for uncollectible accounts					9,000,000
Unamortized premium on 2024 Notes \| High Mesa Services LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance of note receivable		$ 11,700,000		$ 11,700,000	11,700,000
Debt Instrument, Interest Rate, Stated Percentage		8.00%		8.00%
Related party receivables, net		$ 8,500,000		$ 8,500,000
Kingfisher
Accounts, Notes, Loans and Financing Receivable [Line Items]
Transportation and marketing expense			$ 13,600,000	30,800,000
Related party receivables		$ 4,600,000		$ 4,600,000	11,200,000
Kingfisher \| High Mesa Agreement
Accounts, Notes, Loans and Financing Receivable [Line Items]
Related party receivables					$ 8,700,000
Predecessor \| Kingfisher
Accounts, Notes, Loans and Financing Receivable [Line Items]
Transportation and marketing expense	$ 3,100,000

Receivables (Management Service

Receivables (Management Services Agreement with High Mesa) (Details) - USD ($) $ in Thousands	2 Months Ended	5 Months Ended	6 Months Ended
	Mar. 31, 2018	Jun. 30, 2018	Jun. 30, 2019	Dec. 31, 2018
Allowance for Doubtful Accounts Receivable [Roll Forward]
Related party receivables, beginning of period			$ 33,316
Related party receivables, end of period			23,037
Allowance for uncollectibility			(9,888)	$ (9,034)
Related party receivables, net			13,149	$ 24,282
Provision for uncollectible receivables		$ 0	1,177
High Mesa Agreement
Allowance for Doubtful Accounts Receivable [Roll Forward]
Related party receivables, beginning of period			10,066
Additions			894
Payments			(1,072)
Related party receivables, end of period			9,888
Allowance for uncollectibility			(9,888)
Related party receivables, net			$ 0
Provision for uncollectible receivables	$ 9,000

Property And Equipment (Summary

Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Unproved properties	$ 76,665	$ 74,217
Proved oil and gas properties	2,196,605	2,110,346
Accumulated depletion and impairment	(1,489,191)	(1,421,226)
Proved oil and gas properties, net	707,414	689,120
Total oil and gas properties, net	784,079	763,337
Land	5,059	5,059
Fresh water wells	27,372	27,366
Produced water disposal system	3,590	3,608
Office furniture, equipment and vehicles	2,825	2,840
Accumulated depreciation	(1,475)	(726)
Other property and equipment, net	37,371	38,147
Total property and equipment, net	$ 821,450	$ 801,484

Property And Equipment (Depreci

Property And Equipment (Depreciation and Depletion Expense) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Property, Plant and Equipment [Line Items]
Oil and gas properties depletion		$ 33,923	$ 26,086	$ 36,859	$ 67,965
Other property and equipment depreciation		341	423	586	749
Total depletion and depreciation		$ 34,264	$ 26,509	$ 37,445	$ 68,714
Predecessor
Property, Plant and Equipment [Line Items]
Oil and gas properties depletion	$ 11,021
Other property and equipment depreciation	609
Total depletion and depreciation	$ 11,630

Discontinued Operations (Schedu

Discontinued Operations (Schedule Of Operations And Other Items Reclassified In Discontinued Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019
Operating expenses
Interest expense		$ 0	$ 0
Predecessor
Operating expenses
Interest expense	$ (103)
Predecessor \| Weeks Island Field, Louisiana \| Non Stack Assets \| Disposed of by Sale
Revenue
Oil	1,617
Natural gas	1,023
Natural gas liquids	236
Other	16
Operating revenue	2,892
Loss on sale of assets	(1,923)
Total revenue	969
Operating expenses
Lease operating	1,770
Transportation and marketing	83
Production taxes	167
Workovers	127
Depreciation, depletion and amortization	884
Impairment of assets	5,560
General and administrative	21
Total operating expenses	8,612
Interest expense	(103)
Loss from discontinued operations, net of tax	$ (7,746)

Discontinued Operations (Total

Discontinued Operations (Total Operating And Investing Cash Flows Of Discontinued Operations) (Details) - Predecessor - Weeks Island Field, Louisiana - Disposed of by Sale $ in Thousands	1 Months Ended
	Feb. 08, 2018USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total operating cash flows of discontinued operations	$ 2,974
Total investing cash flows of discontinued operations	$ (601)

Derivatives (Fair Values Of Der

Derivatives (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Gross fair value of assets	$ 25,832	$ 30,422
Gross liabilities offset against assets in the Balance Sheet	(18,597)	(11,052)
Net fair value of assets presented in the Balance Sheet	7,235	19,370
Gross fair value of liabilities	19,626	12,942
Gross assets offset against liabilities in the Balance Sheet	(18,597)	(11,052)
Net fair value of liabilities presented in the Balance Sheet	1,029	1,890
Derivatives, current assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	13,855	22,512
Gross liabilities offset against assets in the Balance Sheet	(9,128)	(6,089)
Net fair value of assets presented in the Balance Sheet	4,727	16,423
Derivatives, long-term assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	11,977	7,910
Gross liabilities offset against assets in the Balance Sheet	(9,469)	(4,963)
Net fair value of assets presented in the Balance Sheet	2,508	2,947
Derivatives, current liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	9,968	7,799
Gross assets offset against liabilities in the Balance Sheet	(9,128)	(6,089)
Net fair value of liabilities presented in the Balance Sheet	840	1,710
Derivatives, long-term liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	9,658	5,143
Gross assets offset against liabilities in the Balance Sheet	(9,469)	(4,963)
Net fair value of liabilities presented in the Balance Sheet	$ 189	$ 180

Derivatives (Effect Of Derivati

Derivatives (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		$ 12,412	$ (29,219)	$ (51,230)	$ (11,365)	$ (11,365)
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	$ 6,663
Derivatives Not Designated As Hedging
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		12,412	(29,219)	(51,230)	(11,365)
Derivatives Not Designated As Hedging \| Oil
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		5,134	(28,712)	(50,656)	(16,535)
Derivatives Not Designated As Hedging \| Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts		$ 7,278	$ (507)	$ (574)	$ 5,170
Derivatives Not Designated As Hedging \| Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	6,663
Derivatives Not Designated As Hedging \| Predecessor \| Oil
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	4,796
Derivatives Not Designated As Hedging \| Predecessor \| Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (loss) on derivative contracts	$ 1,867

Derivatives (Additional Informa

Derivatives (Additional Information) (Details) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Contracts To be Settled January 2019
Derivative [Line Items]
Derivative contracts	$ 1.4	$ 1.3

Derivatives (Oil Derivative Con

Derivatives (Oil Derivative Contracts) (Details) - Oil Derivative Contracts	6 Months Ended
	Jun. 30, 2019$ / bblbbl
Price Swap Contracts \| 2019
Derivative [Line Items]
Volume in Bbls \| bbl	92,000
Weighted Average Swap Price (USD per unit)	63.03
Price Swap Contracts \| 2019 \| High
Derivative [Line Items]
Swap Price (USD per unit)	63.03
Price Swap Contracts \| 2019 \| Low
Derivative [Line Items]
Swap Price (USD per unit)	63.03
Short Call Options \| 2019
Derivative [Line Items]
Volume in Bbls \| bbl	1,361,600
Weighted Average Option Price (USD per unit)	66.31
Short Call Options \| 2019 \| High
Derivative [Line Items]
Option Price (USD per unit)	75.20
Short Call Options \| 2019 \| Low
Derivative [Line Items]
Option Price (USD per unit)	56.50
Short Call Options \| 2020
Derivative [Line Items]
Volume in Bbls \| bbl	1,017,600
Weighted Average Option Price (USD per unit)	63.95
Short Call Options \| 2020 \| High
Derivative [Line Items]
Option Price (USD per unit)	73.80
Short Call Options \| 2020 \| Low
Derivative [Line Items]
Option Price (USD per unit)	59.55
Short Call Options \| 2021
Derivative [Line Items]
Volume in Bbls \| bbl	279,750
Weighted Average Option Price (USD per unit)	63.51
Short Call Options \| 2021 \| High
Derivative [Line Items]
Option Price (USD per unit)	63.75
Short Call Options \| 2021 \| Low
Derivative [Line Items]
Option Price (USD per unit)	63.35
Long Put Options \| 2019
Derivative [Line Items]
Volume in Bbls \| bbl	1,453,600
Weighted Average Option Price (USD per unit)	53.80
Long Put Options \| 2019 \| High
Derivative [Line Items]
Option Price (USD per unit)	62
Long Put Options \| 2019 \| Low
Derivative [Line Items]
Option Price (USD per unit)	50
Long Put Options \| 2020
Derivative [Line Items]
Volume in Bbls \| bbl	1,566,600
Weighted Average Option Price (USD per unit)	56.81
Long Put Options \| 2020 \| High
Derivative [Line Items]
Option Price (USD per unit)	62.50
Long Put Options \| 2020 \| Low
Derivative [Line Items]
Option Price (USD per unit)	50
Long Put Options \| 2021
Derivative [Line Items]
Volume in Bbls \| bbl	659,850
Weighted Average Option Price (USD per unit)	46.94
Long Put Options \| 2021 \| High
Derivative [Line Items]
Option Price (USD per unit)	55
Long Put Options \| 2021 \| Low
Derivative [Line Items]
Option Price (USD per unit)	41
Short Put Options \| 2019
Derivative [Line Items]
Volume in Bbls \| bbl	1,453,600
Weighted Average Option Price (USD per unit)	42.72
Short Put Options \| 2019 \| High
Derivative [Line Items]
Option Price (USD per unit)	52
Short Put Options \| 2019 \| Low
Derivative [Line Items]
Option Price (USD per unit)	37.50
Short Put Options \| 2020
Derivative [Line Items]
Volume in Bbls \| bbl	1,566,600
Weighted Average Option Price (USD per unit)	42.81
Short Put Options \| 2020 \| High
Derivative [Line Items]
Option Price (USD per unit)	50
Short Put Options \| 2020 \| Low
Derivative [Line Items]
Option Price (USD per unit)	37.50
Short Put Options \| 2021
Derivative [Line Items]
Volume in Bbls \| bbl	279,750
Weighted Average Option Price (USD per unit)	43
Short Put Options \| 2021 \| High
Derivative [Line Items]
Option Price (USD per unit)	43
Short Put Options \| 2021 \| Low
Derivative [Line Items]
Option Price (USD per unit)	43

Derivatives (Natural Gas Deriva

Derivatives (Natural Gas Derivative Contracts) (Details) - Natural Gas Derivative Contract	6 Months Ended
	Jun. 30, 2019MMBTU$ / MMBTU
2019 \| Price Swap Contracts
Derivative [Line Items]
Volume in MMbtu \| MMBTU	7,980,000
Weighted Average Swap Price (USD per unit)	2.67
2019 \| Price Swap Contracts \| High
Derivative [Line Items]
Swap Price (USD per unit)	2.72
2019 \| Price Swap Contracts \| Low
Derivative [Line Items]
Swap Price (USD per unit)	2.64
2019 \| Basis Swap Contracts
Derivative [Line Items]
Volume in MMbtu \| MMBTU	9,680,000
Weighted Average Swap Price (USD per unit)	(0.72)
2019 \| Basis Swap Contracts \| High
Derivative [Line Items]
Swap Price (USD per unit)	(0.49)
2019 \| Basis Swap Contracts \| Low
Derivative [Line Items]
Swap Price (USD per unit)	(0.93)
2019 \| Short Call Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	3.19
2019 \| Short Call Options \| High
Derivative [Line Items]
Option Price (USD per unit)	3.20
2019 \| Short Call Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	3.17
2019 \| Long Put Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	2.70
2019 \| Long Put Options \| High
Derivative [Line Items]
Option Price (USD per unit)	2.70
2019 \| Long Put Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2.70
2019 \| Short Put Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	1,525,000
Weighted Average Option Price (USD per unit)	2.20
2019 \| Short Put Options \| High
Derivative [Line Items]
Option Price (USD per unit)	2.20
2019 \| Short Put Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2.20
2020 \| Price Swap Contracts
Derivative [Line Items]
Volume in MMbtu \| MMBTU	1,284,000
Weighted Average Swap Price (USD per unit)	2.54
2020 \| Price Swap Contracts \| High
Derivative [Line Items]
Swap Price (USD per unit)	2.54
2020 \| Price Swap Contracts \| Low
Derivative [Line Items]
Swap Price (USD per unit)	2.54
2020 \| Basis Swap Contracts
Derivative [Line Items]
Volume in MMbtu \| MMBTU	910,000
Weighted Average Swap Price (USD per unit)	(0.49)
2020 \| Basis Swap Contracts \| High
Derivative [Line Items]
Swap Price (USD per unit)	(0.49)
2020 \| Basis Swap Contracts \| Low
Derivative [Line Items]
Swap Price (USD per unit)	(0.50)
2020 \| Short Call Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	3,874,500
Weighted Average Option Price (USD per unit)	3.19
2020 \| Short Call Options \| High
Derivative [Line Items]
Option Price (USD per unit)	3.69
2020 \| Short Call Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2.77
2020 \| Long Put Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	10,749,500
Weighted Average Option Price (USD per unit)	2.59
2020 \| Long Put Options \| High
Derivative [Line Items]
Option Price (USD per unit)	3
2020 \| Long Put Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2.50
2020 \| Short Put Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	9,696,000
Weighted Average Option Price (USD per unit)	2.10
2020 \| Short Put Options \| High
Derivative [Line Items]
Option Price (USD per unit)	2.50
2020 \| Short Put Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2
2021 \| Short Call Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	540,000
Weighted Average Option Price (USD per unit)	3.25
2021 \| Short Call Options \| High
Derivative [Line Items]
Option Price (USD per unit)	3.25
2021 \| Short Call Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	3.25
2021 \| Long Put Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	2,790,000
Weighted Average Option Price (USD per unit)	2.62
2021 \| Long Put Options \| High
Derivative [Line Items]
Option Price (USD per unit)	2.65
2021 \| Long Put Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2.50
2021 \| Short Put Options
Derivative [Line Items]
Volume in MMbtu \| MMBTU	2,250,000
Weighted Average Option Price (USD per unit)	2.15
2021 \| Short Put Options \| High
Derivative [Line Items]
Option Price (USD per unit)	2.15
2021 \| Short Put Options \| Low
Derivative [Line Items]
Option Price (USD per unit)	2.15

Derivatives (Basis Swap Derivat

Derivatives (Basis Swap Derivative Contracts) (Details) - Natural Gas Basis Swap Derivative Contracts	6 Months Ended
	Jun. 30, 2019MMBTU$ / MMBTU
Jul 19 - Dec 19
Derivative [Line Items]
Volume in MMbtu \| MMBTU	460,000
Weighted average spread \| $ / MMBTU	(0.93)
Jan 19 - Dec 19
Derivative [Line Items]
Volume in MMbtu \| MMBTU	7,990,000
Weighted average spread \| $ / MMBTU	(0.70)
Jan 20 - Mar 20
Derivative [Line Items]
Volume in MMbtu \| MMBTU	910,000
Weighted average spread \| $ / MMBTU	(0.49)
Jan 19 - Oct 19
Derivative [Line Items]
Volume in MMbtu \| MMBTU	1,230,000
Weighted average spread \| $ / MMBTU	(0.81)

Accounts Payable And Accrued _3

Accounts Payable And Accrued Liabilities (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 8,871	$ 20,200
Accruals for capital expenditures	18,477	101,214
Revenue and royalties payable	39,232	46,870
Accruals for operating expenses	10,701	16,355
Accrued interest	5,642	1,784
Derivative settlements	743	109
Other	8,028	10,532
Total accrued liabilities	82,823	176,864
Accounts payable and accrued liabilities	$ 91,694	$ 197,064

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Thousands	1 Months Ended	5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2019	Dec. 31, 2018	Jun. 30, 2018	Feb. 08, 2018
Asset Retirement Obligation [Line Items]
Balance, beginning of period		$ 0	$ 11,409
Liabilities assumed in Business Combination		5,998	0
Liabilities incurred		877	634
Liabilities settled		(806)	(162)
Liabilities transferred in sale of properties		(20)	0
Revisions to estimates		665	(9)
Accretion expense		263	465
Balance, end of period		0	$ 11,409	$ 12,337	$ 11,409	$ 6,977	$ 0
Less: Current portion				44	2,079	538
Long-term portion				$ 12,293	$ 9,330	$ 6,439
Predecessor
Asset Retirement Obligation [Line Items]
Balance, beginning of period	$ 10,469	10,509
Liabilities assumed in Business Combination	0
Liabilities incurred	0
Liabilities settled	(63)
Liabilities transferred in sale of properties	0
Revisions to estimates	63
Accretion expense	40
Balance, end of period	$ 10,469	$ 10,509					10,509
Less: Current portion							33
Long-term portion							$ 10,476

Debt (Schedule of Long-Term Deb

Debt (Schedule of Long-Term Debt, Net) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018	Feb. 09, 2018
Debt Instrument [Line Items]
2024 Notes			$ 533,600
Total debt, net	$ 871,162	$ 690,123
Less: Current portion	871,162	0
Long-term debt, net	0	690,123
2024 Notes
Debt Instrument [Line Items]
2024 Notes	500,000	500,000
Unamortized premium on 2024 Notes
Debt Instrument [Line Items]
Unamortized premium on 2024 Notes	26,662	29,123
Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	20,200
Alta Mesa RBL \| Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	$ 344,500	$ 161,000

Debt (Narrative) (Details)

Debt (Narrative) (Details) $ in Thousands	6 Months Ended
Debt (Narrative) (Details) $ in Thousands	Jun. 30, 2019USD ($)	Aug. 13, 2019USD ($)	Apr. 01, 2019USD ($)	Dec. 31, 2018USD ($)	Feb. 09, 2018USD ($)
Debt Instrument [Line Items]
2024 Notes					$ 533,600
2024 Notes
Debt Instrument [Line Items]
2024 Notes	$ 500,000			$ 500,000
Alta Mesa Credit Facility
Debt Instrument [Line Items]
Debt covenant, current ratio, minimum required	1
Maximum leverage ratio	4
Current borrowing capacity			$ 370,000
Alta Mesa RBL
Debt Instrument [Line Items]
Alta Mesa RBL	$ 20,200
Remaining borrowing capacity	5,300
Alta Mesa RBL \| 2024 Notes
Debt Instrument [Line Items]
Notes Payable, Fair Value Disclosure	$ 193,800
Subsequent Event \| Alta Mesa Credit Facility
Debt Instrument [Line Items]
Current borrowing capacity		$ 200,000

Debt (Summary Of Future Maturit

Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) $ in Thousands	Jun. 30, 2019USD ($)
Summary of future maturities of long-term debt
2019	$ 0
2020	0
2021	0
2022	0
2023	344,500
Thereafter	500,000
Total long-term debt	$ 844,500

Significant Concentrations (Det

Significant Concentrations (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Concentration Risk [Line Items]
Revenues		$ 126,045	$ 66,459	$ 100,344		$ 220,348
AEM
Concentration Risk [Line Items]
Revenues		7,703	70,601	107,944	$ 91,534
Fees paid		218	209	283	411
Total fees paid to ARM		694	209	283	1,548
Accounts receivable		200			200		$ 38,400
Marketing fees \| AEM
Concentration Risk [Line Items]
Fees paid		$ 476	$ 0	$ 0	$ 1,137
Predecessor
Concentration Risk [Line Items]
Revenues	$ 47,639
Predecessor \| AEM
Concentration Risk [Line Items]
Revenues	28,757
Fees paid	66
Total fees paid to ARM	66
Predecessor \| Marketing fees \| AEM
Concentration Risk [Line Items]
Fees paid	$ 0

Equity-Based Compensation (Su_3

Equity-Based Compensation (Successor) (Stock Compensation Expense) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		5 Months Ended	6 Months Ended
	Feb. 08, 2018	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2018	Jun. 30, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		$ 1,396	$ 3,621	$ 6,389	$ 3,057
Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		744	1,606	2,628	1,535
Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		563	871	1,412	1,425
Performance-based restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense		$ 89	$ 1,144	$ 2,349	$ 97
Predecessor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 0
Predecessor \| Stock options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	0
Predecessor \| Restricted stock awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	0
Predecessor \| Performance-based restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 0

Equity-Based Compensation (Su_4

Equity-Based Compensation (Successor) (Narrative) (Details) - Performance-based restricted stock units - $ / shares	6 Months Ended	11 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Awards deemed granted (in shares)	595,417
Fair value of tranche granted (in USD per share)	$ 0.27
Tranche one
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		20.00%
Tranche two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		30.00%
Tranche three
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting rate		50.00%
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		0.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned		200.00%

Related Party Transactions (Det

Related Party Transactions (Details)	Feb. 08, 2018USD ($)	Dec. 31, 2016	Mar. 31, 2018USD ($)	Jun. 30, 2019USD ($)well	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Jan. 13, 2016well
Related Party Transaction [Line Items]
Advances from related party				$ 4,003,000	$ 9,822,000
BCE
Related Party Transaction [Line Items]
Advances from related party				4,000,000	9,800,000
Land consulting services \| Vice President \| David Murrell, VP of Land and Business Development
Related Party Transaction [Line Items]
Total fees paid to ARM			$ 83,000
Land consulting services \| Predecessor \| Vice President \| David Murrell, VP of Land and Business Development
Related Party Transaction [Line Items]
Total fees paid to ARM	$ 28,000
Compensation to related party \| Vice President \| David Mcclure Vp of Facilities and Infrastructure
Related Party Transaction [Line Items]
Total compensation			$ 929,428	768,860
Compensation to related party \| Predecessor \| Vice President \| David Mcclure Vp of Facilities and Infrastructure
Related Party Transaction [Line Items]
Total compensation					28,874
KFM \| Affiliated Entity
Related Party Transaction [Line Items]
Advances from related party					2,900,000
AMR \| Affiliated Entity
Related Party Transaction [Line Items]
Advances from related party					$ 500,000
Joint Development Agreement
Related Party Transaction [Line Items]
Number of wells to be drilled in three tranches \| well							60
Number of additional wells to be drilled \| well							20
Reduced interest (percent)		12.50%
Internal rate of return		25.00%
Joint Development Agreement \| BCE
Related Party Transaction [Line Items]
Percent committed to fund		100.00%
Drilling and completion costs (maximum)						$ 3,200,000
Working interest received (percent)		80.00%
Reduced interest (percent)		20.00%
Internal rate of return		15.00%
Advances from related party				$ 39,500,000
Number of wells drilled \| well				61