Alta Mesa 10-Q 14 Nov 18 2018 Q3 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	9 Months Ended
	Sep. 30, 2018shares
Document And Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	1,518,403
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding (in shares)	0
Entity Emerging Growth Company	true
Entity Small Business	false
Entity Ex Transition Period	false

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Successor
CURRENT ASSETS
Cash and cash equivalents	$ 8,869
Restricted cash	872
Accounts receivable, net	107,984
Other receivables	246
Receivables due from affiliate	16,656
Receivables due from related party	13,085
Note receivable due from related party	1,642
Prepaid expenses and other current assets	3,423
Current assets — discontinued operations	0
Derivative financial instruments	0
Total current assets	152,777
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	2,697,757
Other property and equipment, net	93,956
Total property and equipment, net	2,791,713
OTHER ASSETS
Deferred financing costs, net	1,216
Notes receivable due from related party	11,492
Deposits and other long-term assets	86
Non-current assets — discontinued operations	0
Derivative financial instruments	0
Total other assets	12,794
TOTAL ASSETS	2,957,284
CURRENT LIABILITIES
Accounts payable and accrued liabilities	227,139
Accounts payable — affiliate	481
Advances from non-operators	9,233
Advances from related party	16,917
Asset retirement obligations	1,300
Current liabilities — discontinued operations	0
Derivative financial instruments	34,396
Total current liabilities	289,466
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	9,169
Long-term debt, net	610,354
Noncurrent liabilities — discontinued operations	0
Derivative financial instruments	7,078
Other long-term liabilities	5
Total long-term liabilities	626,606
TOTAL LIABILITIES	916,072
Commitments and Contingencies (Note 13)
PARTNERS’ CAPITAL	2,041,212
TOTAL LIABILITIES AND PARTNERS’ CAPITAL	$ 2,957,284
Predecessor
CURRENT ASSETS
Cash and cash equivalents		$ 3,660
Restricted cash		1,269
Accounts receivable, net		76,161
Other receivables		1,388
Receivables due from affiliate		0
Receivables due from related party		790
Note receivable due from related party		0
Prepaid expenses and other current assets		2,932
Current assets — discontinued operations		5,195
Derivative financial instruments		216
Total current assets		91,611
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net		894,630
Other property and equipment, net		32,140
Total property and equipment, net		926,770
OTHER ASSETS
Deferred financing costs, net		1,787
Notes receivable due from related party		12,369
Deposits and other long-term assets		9,067
Non-current assets — discontinued operations		43,785
Derivative financial instruments		8
Total other assets		67,016
TOTAL ASSETS		1,085,397
CURRENT LIABILITIES
Accounts payable and accrued liabilities		170,489
Accounts payable — affiliate		5,476
Advances from non-operators		5,502
Advances from related party		23,390
Asset retirement obligations		69
Current liabilities — discontinued operations		15,419
Derivative financial instruments		19,303
Total current liabilities		239,648
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion		10,400
Long-term debt, net		607,440
Noncurrent liabilities — discontinued operations		66,862
Derivative financial instruments		1,114
Other long-term liabilities		5,488
Total long-term liabilities		691,304
TOTAL LIABILITIES		930,952
Commitments and Contingencies (Note 13)
PARTNERS’ CAPITAL		154,445
TOTAL LIABILITIES AND PARTNERS’ CAPITAL		$ 1,085,397

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		8 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Successor
Total operating revenues		$ 134,103		$ 280,601
OPERATING REVENUES AND OTHER
Gain (loss) on sale of assets and other		(18)		5,898
Gain on acquisition of oil and gas properties		0		0
Gain (loss) on derivative contracts		(11,212)		(63,077)
Total operating revenues and other		122,873		223,422
OPERATING EXPENSES
Production taxes		6,311		10,332
Workover expense		1,065		2,643
Exploration expense		1,029		14,067
Depreciation, depletion and amortization expense		45,623		83,068
Impairment expense		0		0
Accretion expense		226		489
General and administrative expense		7,918		57,188
Total operating expenses		94,343		237,742
INCOME (LOSS) FROM OPERATIONS		28,530		(14,320)
OTHER INCOME (EXPENSE)
Interest expense		(11,008)		(26,565)
Interest income and other		322		1,688
Total other income (expense), net		(10,686)		(24,877)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES		17,844		(39,197)
Provision for state income taxes		0		7
INCOME (LOSS) FROM CONTINUING OPERATIONS		17,844		(39,204)
Loss from discontinued operations, net of state income tax		0		0
NET INCOME (LOSS)		17,844		(39,204)
Predecessor
Total operating revenues	$ 40,136		$ 63,124		$ 189,511
OPERATING REVENUES AND OTHER
Gain (loss) on sale of assets and other	0		0		0
Gain on acquisition of oil and gas properties	0		5,267		5,267
Gain (loss) on derivative contracts	7,298		(10,468)		38,024
Total operating revenues and other	47,434		57,923		232,802
OPERATING EXPENSES
Production taxes	953		1,262		3,712
Workover expense	423		1,441		3,131
Exploration expense	3,633		3,649		11,888
Depreciation, depletion and amortization expense	11,784		24,159		63,247
Impairment expense	0		0		1,188
Accretion expense	39		108		234
General and administrative expense	24,352		17,445		35,474
Total operating expenses	49,394		66,785		172,257
INCOME (LOSS) FROM OPERATIONS	(1,960)		(8,862)		60,545
OTHER INCOME (EXPENSE)
Interest expense	(5,511)		(13,545)		(38,165)
Interest income and other	172		244		792
Total other income (expense), net	(5,339)		(13,301)		(37,373)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE STATE INCOME TAXES	(7,299)		(22,163)		23,172
Provision for state income taxes	0		0		285
INCOME (LOSS) FROM CONTINUING OPERATIONS	(7,299)		(22,163)		22,887
Loss from discontinued operations, net of state income tax	(7,593)		(2,041)		(37,490)
NET INCOME (LOSS)	(14,892)		(24,204)		(14,603)
Oil | Successor
Total operating revenues		107,253		222,822
Oil | Predecessor
Total operating revenues	30,972		44,201		133,489
Natural gas | Successor
Total operating revenues		11,959		25,149
Natural gas | Predecessor
Total operating revenues	4,276		9,583		29,816
Natural gas liquids | Successor
Total operating revenues		13,880		28,835
Natural gas liquids | Predecessor
Total operating revenues	4,000		7,548		21,201
Other revenues | Successor
Total operating revenues		1,011		3,795
Other revenues | Predecessor
Total operating revenues	888		1,792		5,005
Lease operating expense | Successor
OPERATING EXPENSES
Marketing and transportation expense		16,351		37,347
Lease operating expense | Predecessor
OPERATING EXPENSES
Marketing and transportation expense	4,485		10,407		32,897
Marketing and transportation expense | Successor
OPERATING EXPENSES
Marketing and transportation expense		$ 15,820		$ 32,608
Marketing and transportation expense | Predecessor
OPERATING EXPENSES
Marketing and transportation expense	$ 3,725		$ 8,314		$ 20,486

Condensed Consolidated Statem_2

Condensed Consolidated Statements Of Changes In Partners' Capital $ in Thousands	USD ($)
Beginning balance (Predecessor) at Dec. 31, 2016	$ 32,106
Distribution of non-stack (assets) net liability | Predecessor	0
Capital contributions | Predecessor	200,000
Distributions | Predecessor	0
Issuance of additional Alta Mesa purchase consideration | Predecessor	0
Equity-based compensation expense | Predecessor	0
Net income (loss) | Predecessor	(14,603)
Ending balance (Predecessor) at Sep. 30, 2017	217,503
Beginning balance (Predecessor) at Jun. 30, 2017	41,707
Distribution of non-stack (assets) net liability | Predecessor	0
Capital contributions | Predecessor	200,000
Distributions | Predecessor	0
Issuance of additional Alta Mesa purchase consideration | Predecessor	0
Equity-based compensation expense | Predecessor	0
Net income (loss) | Predecessor	(24,204)
Ending balance (Predecessor) at Sep. 30, 2017	217,503
Beginning balance (Predecessor) at Dec. 31, 2017	154,445
Distribution of non-stack (assets) net liability | Predecessor	33,102
Capital contributions | Predecessor	0
Distributions | Predecessor	0
Issuance of additional Alta Mesa purchase consideration | Predecessor	0
Equity-based compensation expense | Predecessor	0
Net income (loss) | Predecessor	(14,892)
Ending balance (Successor) at Feb. 08, 2018	1,535,891
Ending balance (Predecessor) at Feb. 08, 2018	172,655
Distribution of non-stack (assets) net liability | Successor	0
Capital contributions | Successor	560,344
Distributions | Successor	(32,000)
Issuance of additional Alta Mesa purchase consideration | Successor	9,467
Equity-based compensation expense | Successor	6,714
Net income (loss) | Successor	(39,204)
Ending balance (Successor) at Sep. 30, 2018	2,041,212
Beginning balance (Successor) at Jun. 30, 2018	2,048,043
Distribution of non-stack (assets) net liability | Successor	0
Capital contributions | Successor	0
Distributions | Successor	(25,000)
Issuance of additional Alta Mesa purchase consideration | Successor	0
Equity-based compensation expense | Successor	325
Net income (loss) | Successor	17,844
Ending balance (Successor) at Sep. 30, 2018	$ 2,041,212

Condensed Consolidated Statem_3

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	1 Months Ended	8 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Sep. 30, 2017
Adjustments to reconcile net loss to net cash provided by operating activities:
Amortization of debt premium		$ 3,300
Successor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss		(39,204)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization expense		83,068
Impairment expense		0
Accretion expense		489
Amortization of deferred financing costs		151
Amortization of debt premium		(3,281)
Equity-based compensation expense		6,714
Dry hole expense		0
Expired leases		10,658
(Gain) loss on derivative contracts		63,077
Cash settlements of derivative contracts		(32,836)
Premium paid on derivative contracts		0
Interest converted into debt		0
Interest added to notes receivable due from related party		(680)
Loss on sale of assets and other		81
Gain on acquisition of oil and gas properties		0
Impact on cash from changes in assets and liabilities:
Accounts receivable		(5,715)
Other receivables		976
Receivables due from affiliate		(16,656)
Receivables due from related party		(12,178)
Prepaid expenses and other current and non-current assets		8,181
Advances from related party		(30,589)
Settlement of asset retirement obligations		(1,249)
Accounts payable — related party		(4,994)
Accounts payable, accrued liabilities and other liabilities		(10,531)
NET CASH PROVIDED BY OPERATING ACTIVITIES		15,482
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment		(489,009)
Acquisitions		0
Proceeds from sale of assets and other, net		11
Notes receivable due from affiliate		0
NET CASH USED IN INVESTING ACTIVITIES		(488,998)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuances of long-term debt		80,000
Repayments of long-term debt		(134,065)
Additions to deferred financing costs		(1,367)
Capital distributions		(32,000)
Capital contributions		560,344
NET CASH PROVIDED BY FINANCING ACTIVITIES		472,912
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH		(604)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period		10,345
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$ 10,345	9,741
Predecessor
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	(14,892)		$ (14,603)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization expense	12,414		80,082
Impairment expense	5,560		29,206
Accretion expense	140		1,447
Amortization of deferred financing costs	171		2,205
Amortization of debt premium	0		0
Equity-based compensation expense	0		0
Dry hole expense	(45)		2,447
Expired leases	1,250		8,394
(Gain) loss on derivative contracts	(7,298)		(38,024)
Cash settlements of derivative contracts	(1,661)		1,775
Premium paid on derivative contracts	0		(520)
Interest converted into debt	103		904
Interest added to notes receivable due from related party	(85)		(619)
Loss on sale of assets and other	1,923		0
Gain on acquisition of oil and gas properties	0		(6,893)
Impact on cash from changes in assets and liabilities:
Accounts receivable	(20,895)		(33,649)
Other receivables	(9,887)		7,382
Receivables due from affiliate	0		0
Receivables due from related party	(117)		169
Prepaid expenses and other current and non-current assets	9,970		(9,938)
Advances from related party	24,116		5,266
Settlement of asset retirement obligations	(63)		(6,083)
Accounts payable — related party	0		0
Accounts payable, accrued liabilities and other liabilities	25,815		27,308
NET CASH PROVIDED BY OPERATING ACTIVITIES	26,519		56,256
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(38,096)		(244,308)
Acquisitions	0		(55,236)
Proceeds from sale of assets and other, net	0		0
Notes receivable due from affiliate	0		(1,515)
NET CASH USED IN INVESTING ACTIVITIES	(38,096)		(301,059)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuances of long-term debt	60,000		286,065
Repayments of long-term debt	(43,000)		(251,622)
Additions to deferred financing costs	0		(220)
Capital distributions	(68)		0
Capital contributions	0		207,875
NET CASH PROVIDED BY FINANCING ACTIVITIES	16,932		242,098
NET INCREASE (DECREASE) IN CASH, CASH EQUIVALENTS AND RESTRICTED CASH	5,355		(2,705)
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, beginning of period	4,990	$ 10,345	7,618
CASH, CASH EQUIVALENTS AND RESTRICTED CASH, end of period	$ 10,345		$ 4,913

Description Of Business

Description Of Business	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description Of Business	DESCRIPTION OF BUSINESS Alta Mesa Holdings, LP, together with its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”), 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. Our activities are primarily directed at the horizontal development of an oil and liquids-rich resource play in an area of the basin commonly referred to as the Sooner Trend Anadarko Basin Canadian and Kingfisher County (“STACK”). As described further in Note 5 — Business Combination , certain transactions were consummated on February 9, 2018 that resulted in our acquisition by Alta Mesa Resources, Inc. (“AMR”). These transactions are referred to as the “Business Combination”. AMR is a publicly traded corporation that is not under the control of any person. Prior to the closing of the Business Combination, we were controlled by High Mesa Inc. (“High Mesa”) and indirectly by our founder and Chief Operating Officer, Michael E. Ellis. In connection with the closing of the Business Combination, we distributed our non-STACK assets and liabilities to High Mesa Holdings, LP (the “AM Contributor”) and completed our transition from a diversified asset base composed of a portfolio of conventional assets to an oil and liquids-rich resource play in the STACK.

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES We have provided a discussion of significant accounting policies in Note 2 in our Annual Report on Form 10-K for the year ended December 31, 2017 (the “2017 Annual Report”). As of September 30, 2018 , our significant accounting policies are consistent with those discussed in Note 2 in the 2017 Annual Report, other than as noted below. Basis of Presentation . As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree. Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 805, Business Combinations , (“ASC 805”), our identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the Closing Date of the Business Combination (also referred to herein as the “acquisition date”). Fair value adjustments related to the transaction have been pushed down to us resulting in our assets and liabilities being recorded at fair value as of the acquisition date. As a result of the Transactions described above, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. The Successor periods presented herein are for the three months ended September 30, 2018 and from February 9, 2018 to September 30, 2018 (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three months ended September 30, 2017 and the nine months ended September 30, 2017 (“2017 Predecessor Period,” and, together with the 2018 Predecessor Period, the “Predecessor Periods”). As noted above, we distributed our non-STACK assets and liabilities to the AM Contributor in connection with the closing of the Business Combination. The distribution of our non-STACK assets and liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin. As a result, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within the condensed consolidated financial statements. See Note 7 — Discontinued Operations (Predecessor) for further discussion. Principles of Consolidation and Reporting . The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The condensed consolidated financial statements included herein as of September 30, 2018 , and for the three months ended September 30, 2018 (Successor) and the period from February 9, 2018 through September 30, 2018 (Successor), the period from January 1, 2018 through February 8, 2018 (Predecessor) and the three and nine months ended September 30, 2017 (Predecessor), are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2017 , which were filed with the Securities and Exchange Commission (the “SEC”) in our 2017 Annual Report. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The reclassifications had no impact on net income (loss) or partners’ capital. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year. The Company’s condensed consolidated statement of operations subsequent to the Business Combination includes depreciation and amortization expense on the Company’s property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination. Use of Estimates . The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other estimates are utilized to determine amounts related to oil and natural gas revenues, the value of oil and natural gas properties, the value of other property and equipment, bad debts, asset retirement obligations, derivative contracts, accounting for business combinations, state taxes, share-based compensation and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates. Restricted Cash . The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows (in thousands): ໿  Successor Predecessor  September 30, December 31, Cash and cash equivalents $ 8,869 $ 3,660 Restricted cash 872 1,269 Cash of discontinued operations — 61 Total cash, cash equivalents and restricted cash $ 9,741 $ 4,990 Bond Premium on Senior Unsecured Notes . As a result of the pushdown accounting related to the Business Combination, the Company estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million as of the acquisition date. The amount in excess of the original principal balance was recorded as a bond premium, which is being amortized as a reduction to interest expense. Equity-Based Compensation (Successor) . The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options, restricted stock and performance-based restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock awards and performance-based restricted stock units are valued using the market price of AMR’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period. See Note 16 — Equity-Based Compensation for additional information regarding the Company’s equity based compensation. Going Concern . The Company’s management is required to evaluate an entity’s ability to continue as a going concern for a period of one year following the date of the issuance of the Company’s consolidated financial statements. Disclosure is required if substantial doubt exists about an entity’s ability to continue as a going concern during the evaluation period, including management’s plans to alleviate the conditions and events that raise substantial doubt of going concern, if applicable. At the date of the issuance of these consolidated financial statements, management considers the Company to be a going concern and has prepared these consolidated financial statements on a going concern basis. Recent Accounting Pronouncements Issued But Not Yet Adopted . 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. The Company will adopt this new standard at the same time as our parent company, which will be no later than the fiscal year beginning after December 15, 2019, although early adoption is permitted. The Company is currently evaluating the impact of this new standard on its consolidated financial position and results of operations and has 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 May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. Subsequent to the issuance of ASU 2014-09, the FASB amended the standard to provide clarification and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. The core principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company is entitled in exchange for those services. In order to comply with the new standard, companies will need to (i) identify performance obligations in each contract, (ii) estimate the amount of variable consideration to include in the transaction price and (iii) allocate the transaction price to each separate performance obligation. ASU 2014-09, as amended, is effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. ASU 2014-09 allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company, we previously elected to use the extended transition period to defer implementation of the new standard until the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR, our parent company, is also an emerging growth company, but will cease to be an emerging growth company on December 31, 2018, which will require them to adopt ASU 2014-09 on December 31, 2018, with modified retroactive implementation as of January 1, 2018. Accordingly, we will also adopt ASU 2014-09 at the same time as our parent company. We are continuing our review of contracts for each of our revenue streams and evaluating the impact on our consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09, as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our revenues and expenses under the new gross-versus-net presentation guidance and on our current accounting policies, including the need to make changes to relevant accounting policies and internal controls, if needed. Based on assessments performed to date, we do not expect ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we currently expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to natural gas processing contracts; however, the impact of such presentation changes will not impact our consolidated operating income, net income or cash flows. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (except for short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. The standard, as amended, will be effective for interim and annual periods beginning after December 15, 2018. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets. The standard provides several optional practical expedients in transition. We expect to elect the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date. We also expect to elect the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we expect to elect the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. We do not expect to elect the use-of-hindsight practical expedient. At this time, we are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption may also result in a change in the amount of lease expense recorded on our consolidated statements of operations, as well as add additional disclosures. We expect our implementation work team will complete its evaluation of this new standard by the end of 2018. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. As an emerging growth company, we had elected to use the extended transition period to defer adoption of this standard until 2019 . However, our parent company will lose its emerging growth status, effective December 31, 2018 . Accordingly, we will be required to adopt this new standard on December 31, 2018, when adopted by our parent company. The adoption of this guidance will not impact our financial position or results of operations but could result in presentational changes in our consolidated statements of cash flows. 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 used today. With respect to our trade 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, which will be effective for us in fiscal years beginning after December 15, 2019, also requires additional disclosures regarding the credit quality of our trade 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.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	9 Months Ended
	Sep. 30, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flow disclosures and non-cash investing and financing activities are presented below (in thousands): ໿  Successor Predecessor  February 9, 2018 January 1, 2018 Nine Through Through Months Ended  September 30, 2018 February 8, 2018 September 30, 2017 Supplemental cash flow information: Cash paid for interest $ 22,073 $ 1,145 $ 25,675 Cash paid for state income taxes 7 — — Non-cash investing and financing activities: Increase in asset retirement obligations 4,652 — 3,778 Asset retirement obligations assumed, purchased properties — — 705 Increase in accruals or payables for capital expenditures 35,967 4,712 41,322 Distribution of non-STACK (assets) net liability — 33,102 — Increase in accounts receivable for sale of assets (524 ) — —

Accounts Receivable

Accounts Receivable	9 Months Ended
	Sep. 30, 2018
Receivables [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE Accounts receivable consisted of the following (in thousands): ໿  Successor Predecessor  September 30, December 31, Oil, natural gas and natural gas liquids sales $ 40,134 $ 26,916 Joint interest billings 44,548 13,821 Pooling interest (1) 23,367 35,839 Allowance for doubtful accounts (65 ) (415 ) Total accounts receivable, net $ 107,984 $ 76,161 _________________ (1) Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents costs of unbilled interests on wells which the Company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.

Business Combination

Business Combination	9 Months Ended
	Sep. 30, 2018
Business Combinations [Abstract]
Business Combination	BUSINESS COMBINATION On February 9, 2018 (the “Closing Date”), we consummated the transactions contemplated by the Contribution Agreement, dated August 16, 2017, with AMR (formerly Silver Run Acquisition Corporation II), AM Contributor, High Mesa Holdings GP, LLC, the sole general partner of the AM Contributor, Alta Mesa Holdings GP, LLC, our sole general partner (“AMH GP”), and, solely for certain provisions therein, the equity owners of the AM Contributor (“AM Contribution Agreement”). Simultaneous with the execution of the AM Contribution Agreement, AMR entered into (i) a Contribution Agreement, dated August 16, 2017, with KFM Holdco, LLC, a Delaware limited liability company (the “KFM Contributor”), Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”), and, solely for certain provisions therein, the equity owners of the KFM Contributor (the “KFM Contribution Agreement”); and (ii) a Contribution Agreement (the “Riverstone Contribution Agreement” and, together with the AM Contribution Agreement and the KFM Contribution Agreement, the “Contribution Agreements”) with Riverstone VI Alta Mesa Holdings, L.P., a Delaware limited partnership (the “Riverstone Contributor”). Pursuant to the Contribution Agreements, SRII Opco, LP, a newly formed subsidiary of AMR (“SRII Opco”), acquired (a) (i) all of the limited partner interests in us and (ii) 100% of the economic interests and 90% of the voting interests in AMH GP ((i) and (ii) together, the “AM Contribution”) and (b) 100% of the economic interests in Kingfisher (the “Kingfisher Contribution”). The acquisition of us and Kingfisher pursuant to the Contribution Agreements is referred to herein as the “Business Combination” and the transactions contemplated by the Contribution Agreements are referred to herein as the “Transactions.” As a result of the Transactions, AMR has obtained control over the management of AMH GP and, consequently, us. At the closing of the Transactions, the AM Contributor received 138,402,398 common units representing limited partner interests (the “Common Units”) in SRII Opco. The AM Contributor also acquired from AMR a number of newly issued shares of non-economic capital stock of AMR, designated as Class C common stock, par value $0.0001 per share (the “Class C Common Stock”), corresponding to the number of Common Units received by the AM Contributor at closing. Additionally, for a period of seven years following the closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20 -day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”): ໿ 20-Day VWAP Earn-Out Consideration $14.00 10,714,285 Common Units $16.00 9,375,000 Common Units $18.00 13,888,889 Common Units $20.00 12,500,000 Common Units The AM Contributor will not be entitled to receive a particular Earn-Out Payment on more than one occasion and, if, on a particular date, the 20-Day VWAP entitles the AM Contributor to more than one Earn-Out Payment (each of which has not been previously paid), the AM Contributor will be entitled to receive each such Earn-Out Payment. The AM Contributor will be entitled to the earn-out consideration described above in connection with certain liquidity events of AMR, including a merger or sale of all or substantially all of AMR’s assets, if the consideration paid to holders of Class A Common Stock in connection with such liquidity event is greater than any of the above-specified 20-Day VWAP hurdles. AMR also contributed $560 million in net cash to us at the closing. AMR’s source for these funds was from the sale of its securities to investors in a public offering and in private placements. We used a portion of the amount to repay all outstanding balance under the senior secured revolving credit facility described in Note 11 — Long-Term Debt, Net . Pursuant to the AM Contribution Agreement, AM Contributor delivered a final closing statement during the second quarter of 2018. Based on the final closing statement, the AM Contributor received an additional 1,197,934 SRII Opco Common Units and an equivalent number of shares of AMR’s Class C Common Stock. The Business Combination has been accounted for using the acquisition method. The acquisition method of accounting is based on FASB ASC 805, Business Combination (“ASC 805”) , and uses the fair value concepts defined in FASB ASC 820, Fair Value Measurements (“ASC 820”). ASC 805 requires, among other things, that our assets acquired and liabilities assumed be recognized at their fair values as of the acquisition date by AMR, who was determined to be the accounting acquirer. We have not completed the detailed valuation studies necessary to arrive at the final determination of the fair value of the assets acquired, the liabilities assumed and the related allocations of the purchase price in the Business Combination. As a result, the values of certain of our long-term assets and liabilities are preliminary in nature and are subject to change as additional information becomes available and as additional analysis is performed. Pursuant to ASC 805, finalization of the values is to be completed within one year of the acquisition date. Preliminary Estimated Purchase Price AMR’s preliminary estimated purchase price consideration for Alta Mesa was as follows (in thousands): ໿  February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Preliminary Purchase Consideration: (2) SRII Opco Common Units issued (3) $ 1,251,782 $ 9,467 $ 1,261,249 Estimated fair value of contingent earn-out purchase consideration (4) 284,109 — 284,109 Total purchase price consideration $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor). (2) The preliminary purchase price consideration is for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP. (3) At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity. (4) For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million , which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life. Preliminary Estimated Purchase Price Allocation The allocation of AMR’s preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in the acquisition of Alta Mesa was as follows (in thousands): ໿  February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Estimated Fair Value of Assets Acquired (2) Cash, cash equivalents and short term restricted cash $ 10,345 $ — $ 10,345 Accounts receivable 101,745 — 101,745 Other receivables 1,222 — 1,222 Receivables due from related party 907 — 907 Prepaid expenses and other current assets 1,405 — 1,405 Derivative financial instruments 352 — 352 Property and equipment: (3) Oil and natural gas properties, successful efforts 2,314,858 (1,479 ) 2,313,379 Other property and equipment, net 43,318 — 43,318 Notes receivable due from related party 12,454 — 12,454 Deposits and other long-term assets 10,286 — 10,286 Total fair value of assets acquired 2,496,892 (1,479 ) 2,495,413 Estimated Fair Value of Liabilities Assumed (2) Accounts payable and accrued liabilities 210,867 (10,946 ) 199,921 Accounts payable — affiliate 5,476 — 5,476 Advances from non-operators 6,803 — 6,803 Advances from related party 47,506 — 47,506 Asset retirement obligations (3) 5,998 — 5,998 Derivative financial instruments 11,585 — 11,585 Long-term debt (4) 667,700 — 667,700 Other long-term liabilities 5,066 — 5,066 Total fair value of liabilities assumed 961,001 (10,946 ) 950,055 Total consideration and fair value $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustments are recognized in the reporting period in which the adjustments were determined and calculated as if the accounting had been completed at the acquisition date. (2) The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets. (3) The estimated fair values of oil and natural gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates. (4) Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024 , totaling approximately $533.6 million , based on Level 1 inputs, and outstanding borrowings under the Eighth A&R credit facility (described in Note 11 — Long-Term Debt, Net ) of approximately $134.1 million as of the acquisition date.

Property And Equipment

Property And Equipment	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
Property And Equipment	PROPERTY AND EQUIPMENT Property and equipment consisted of the following (in thousands):  Successor Predecessor  September 30, December 31, OIL AND NATURAL GAS PROPERTIES Unproved properties $ 865,695 $ 84,590 Accumulated impairment of unproved properties — — Unproved properties, net 865,695 84,590 Proved oil and natural gas properties 1,913,526 1,061,105 Accumulated depreciation, depletion, amortization and impairment (81,464 ) (251,065 ) Proved oil and natural gas properties, net 1,832,062 810,040 TOTAL OIL AND NATURAL GAS PROPERTIES, net 2,697,757 894,630 OTHER PROPERTY AND EQUIPMENT Land 5,059 2,912 Salt water disposal system 88,176 30,990 Office furniture and equipment and vehicles 2,325 20,008 Accumulated depreciation (1,604 ) (21,770 ) OTHER PROPERTY AND EQUIPMENT, net 93,956 32,140 TOTAL PROPERTY AND EQUIPMENT, net $ 2,791,713 $ 926,770 In conjunction with pushdown accounting, property and equipment was measured at fair value as of the acquisition date, which also impacted how value was assigned between the categories within property and equipment (see Note 5 — Business Combination for details).

Discontinued Operations (Predec

Discontinued Operations (Predecessor)	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations (Predecessor)	DISCONTINUED OPERATIONS (Predecessor) We distributed our non-STACK assets and related liabilities to the AM Contributor immediately prior to the Closing Date of the Business Combination. The distribution of our non-STACK assets and related liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 were part of our overall strategic shift to operate only in the eastern Anadarko Basin. As a result, the Predecessor’s non-STACK assets and liabilities have been presented as discontinued operations in the consolidated balance sheets. The operating results directly related to non-STACK assets and liabilities have been segregated and presented as discontinued operations within the condensed consolidated financial statements in the 2018 Predecessor Period and the 2017 Predecessor Periods. Prior to the Business Combination, we had notes payable to our founder (“Founder Notes”) that bore simple interest at 10% . In connection with the Transactions described in Note 5 – Business Combination , the Founder Notes were converted into an equity interest in the AM Contributor immediately prior to the closing of the Business Combination as they were considered part of the non-STACK asset distribution. The balance of the Founder Notes at the time of conversion was approximately $28.3 million , including accrued interest. Interest on the Founder Notes was $0.1 million for the 2018 Predecessor Period and $0.3 million and $0.9 million for the three months ended September 30, 2017 (Predecessor) and 2017 Predecessor Period, respectively. The assets and liabilities directly related to the non-STACK assets presented as discontinued operations in the condensed consolidated balance sheets were as follows (in thousands): ໿ Predecessor December 31, 2017 Assets associated with discontinued operations: Current assets Cash $ 61 Accounts receivable 4,980 Other receivables 154 Total current assets 5,195 Noncurrent assets Investments in LLC - Cost 9,000 Proved oil and natural gas properties, net 15,408 Unproved properties, net 15,504 Land 2,706 Other long-term assets 1,167 Total noncurrent assets 43,785 Total assets associated with discontinued operations $ 48,980  Liabilities associated with discontinued operations: Current liabilities Accounts payable and accrued liabilities $ 7,882 Asset retirement obligations 7,537 Total current liabilities 15,419 Noncurrent liabilities Asset retirement obligations, net of current 37,049 Founder notes 28,166 Other long-term liabilities 1,647 Total noncurrent liabilities 66,862 Total liabilities associated with discontinued operations $ 82,281 The operating results directly related to the non-STACK assets and liabilities presented as discontinued operations within the condensed consolidated financial statements were as follows (in thousands): ໿  Predecessor  Three Months Ended January 1, 2018 Through February 8, 2018 Nine Months Ended Operating revenues and other: Oil $ 10,994 $ 1,617 $ 36,122 Natural gas 2,376 1,023 7,964 Natural gas liquids 571 236 1,613 Other revenues 72 16 274 Total operating revenues 14,013 2,892 45,973 Loss on sale of assets — (1,923 ) — Gain on acquisition of oil and gas properties — — 1,626 Total operating revenues and other 14,013 969 47,599 Operating expenses: Lease operating expense 6,888 1,770 21,944 Marketing and transportation expense 352 83 1,080 Production taxes 1,443 167 5,100 Workover expense 273 127 1,981 Exploration expense 1,874 — 8,042 Depreciation, depletion and amortization 4,625 630 16,835 Impairment expense 82 5,560 28,018 Accretion expense 287 101 1,213 General and administrative expense 13 21 60 Total operating expenses 15,837 8,459 84,273 Other income (expense) Interest expense (305 ) (103 ) (904 ) Interest income and other 88 — 88 Total other income (expense) (217 ) (103 ) (816 ) Loss from discontinued operations, net of state income taxes $ (2,041 ) $ (7,593 ) $ (37,490 ) The total operating and investing cash flows of the non-STACK assets were as follows (in thousands): ໿  Predecessor  January 1, 2018 Through February 8, 2018 Nine Months Ended Total operating cash flows of discontinued operations $ (6,838 ) $ 16,166 Total investing cash flows of discontinued operations (570 ) (15,950 )

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value Measurements	FAIR VALUE MEASUREMENTS We follow ASC 820, which provides a hierarchy of fair value measurements based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances. In connection with our acquisition, 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 $476.3 million at September 30, 2018 (Successor). 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. See Note 11— Long-Term Debt, Net for information on long-term debt. We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil, natural gas and natural gas liquids derivative contracts. Inputs to these models include observable inputs from the NYMEX for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil, natural gas and natural gas liquids prices. We have classified the inputs used to determine fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2. Oil and natural gas properties are subject to impairment testing and potential impairment write down. During the 2017 Predecessor Period, certain of our oil and natural gas properties with a carrying amount of $3.3 million were written down to their fair value of $2.1 million , resulting in an impairment charge of $1.2 million . Significant Level 3 assumptions used in the calculation of estimated discounted cash flows in the impairment analysis included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated timing of production of proved reserves, appropriate risk-adjusted discount rates and other relevant data. New additions to asset retirement obligations result from estimations for new or acquired properties. Such estimations of fair value are based on present value techniques that utilize company-specific information for such inputs as cost and timing of plugging and abandonment of wells and facilities. These inputs are classified as Level 3. We recorded $1.7 million , zero and $1.0 million in additions to asset retirement obligations measured at fair value during the Successor Period, the 2018 Predecessor Period, and the 2017 Predecessor Period, respectively. The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017 , and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:  Level 1 Level 2 Level 3 Total  (in thousands) At September 30, 2018: (Successor) Financial Assets: Derivative contracts for oil and natural gas — $ 5,670 — $ 5,670 Financial Liabilities: Derivative contracts for oil and natural gas — $ 47,144 — $ 47,144 At December 31, 2017: (Predecessor) Financial Assets: Derivative contracts for oil and natural gas — $ 4,416 — $ 4,416 Financial Liabilities: Derivative contracts for oil and natural gas — $ 24,609 — $ 24,609 The amounts above are presented on a gross basis. We will net the value of assets and liabilities with the same counterparty for purposes of presentation in our condensed consolidated balance sheets where master netting agreements are in place. For additional information on derivative contracts, see Note 9 — Derivative Financial Instruments .

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	DERIVATIVE FINANCIAL INSTRUMENTS We have entered into forward-swap contracts and collar contracts to reduce our exposure to price risk in the spot market for oil, natural gas and natural gas liquids. From time to time, we also utilize financial basis swap contracts, which address the price differential between market-wide benchmark prices and other benchmark pricing referenced in certain of our oil, natural gas and natural gas liquids sales contracts. Substantially all of our derivative contracts are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 11 — Long-Term Debt, Net , and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the senior secured revolving credit facility. The derivative contracts settle monthly and are scheduled to coincide with oil production equivalent to barrels (bbl) per month, natural gas production equivalent to volumes in millions of British thermal units (MMBtu) per month, and natural gas liquids production equivalent to volumes in gallons (gal) per month. The derivative contracts represent agreements between us and the counterparties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading or speculative purposes. From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates. As of September 30, 2018 , we are not a party to any interest rate swap agreements. We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the condensed consolidated statements of operations at each reporting date. Derivative contracts are subject to master netting arrangements and are presented on a net basis in the condensed consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a liability account on the condensed consolidated balance sheets. Likewise, derivative liabilities could be presented in a derivative asset account. The following table summarizes the fair value and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815: Fair Values of Derivative Contracts: ໿  September 30, 2018 (Successor) 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) Derivative financial instruments, current assets $ 2,407 $ (2,407 ) $ — Derivative financial instruments, long-term assets 3,263 (3,263 ) — Total $ 5,670 $ (5,670 ) $ — ໿ 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) Derivative financial instruments, current liabilities $ 36,803 $ (2,407 ) $ 34,396 Derivative financial instruments, long-term liabilities 10,341 (3,263 ) 7,078 Total $ 47,144 $ (5,670 ) $ 41,474 ໿  December 31, 2017 (Predecessor) 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) Derivative financial instruments, current assets $ 1,406 $ (1,190 ) $ 216 Derivative financial instruments, long-term assets 3,010 (3,002 ) 8 Total $ 4,416 $ (4,192 ) $ 224 ໿ 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) Derivative financial instruments, current liabilities $ 20,493 $ (1,190 ) $ 19,303 Derivative financial instruments, long-term liabilities 4,116 (3,002 ) 1,114 Total $ 24,609 $ (4,192 ) $ 20,417 The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations (in thousands): ໿  Successor Predecessor Successor Predecessor Derivatives not Three Three February 9, 2018 January 1, 2018 Nine designated as hedging Months Ended Months Ended Through Through Months Ended instruments under ASC 815 September 30, 2018 September 30, 2017 September 30, 2018 February 8, 2018 September 30, 2017 Gain (loss) on derivative contracts Oil commodity contracts $ (12,339 ) $ (10,873 ) $ (63,630 ) $ 5,431 $ 31,665 Natural gas commodity contracts 1,127 1,035 553 1,867 6,763 Natural gas liquids commodity contracts — (630 ) — — (404 ) Total gain (loss) on derivative contracts $ (11,212 ) $ (10,468 ) $ (63,077 ) $ 7,298 $ 38,024 The Company periodically monitors the creditworthiness of its counterparties. Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, under certain circumstances, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the senior secured revolving credit facility described in Note 11 — Long-Term Debt, Net . If a counterparty were to default on payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the derivative could be lost. The value of our derivative financial instruments would be impacted. We had the following open derivative contracts for crude oil at September 30, 2018 : OIL DERIVATIVE CONTRACTS ໿ ໿  Volume in bbls Weighted Average Range Settlement Period and Type of Contract High Low 2018 Price Swap Contracts 552,000 $ 53.55 $ 61.26 $ 50.27 Collar Contracts Short Call Options 552,000 61.28 64.60 60.50 Long Put Options 552,000 51.67 60.00 50.00 Short Put Options 552,000 42.08 52.50 40.00 2019 Price Swap Contracts 182,500 63.03 63.03 63.03 Collar Contracts Short Call Options 2,701,000 66.31 75.20 56.50 Long Put Options 2,883,500 53.80 62.00 50.00 Short Put Options 2,883,500 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 366,000 67.00 73.80 60.20 Long Put Options 1,317,600 56.46 62.50 50.00 Short Put Options 1,317,600 45.83 50.00 40.00 We had the following open derivative contracts for natural gas at September 30, 2018 : NATURAL GAS DERIVATIVE CONTRACTS ໿  Volume in MMBtu Weighted Average Range Settlement Period and Type of Contract High Low 2018 Price Swap Contracts 1,842,500 $ 2.95 $ 3.09 $ 2.75 Collar Contracts Short Call Options 1,832,500 3.36 3.75 3.14 Long Put Options 1,527,500 2.89 2.90 2.75 Short Put Options 610,000 2.40 2.40 2.40 2019 Price Swap Contracts 10,905,000 2.69 3.09 2.64 Collar Contracts Short Call Options 4,000,000 3.31 3.75 3.17 Long Put Options 3,550,000 2.81 2.90 2.70 Short Put Options 2,425,000 2.27 2.40 2.20 2020 Collar Contracts Short Call Options 2,275,000 3.19 3.20 3.17 Long Put Options 9,150,000 2.57 2.70 2.50 Short Put Options 9,150,000 2.07 2.20 2.00 2021 Collar Contracts Long Put Options 2,250,000 2.65 2.65 2.65 Short Put Options 2,250,000 2.15 2.15 2.15 In those instances where contracts are identical as to time period, volume and strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either the NYMEX index or may reflect a mix of positions settling on various combinations of these benchmarks. We had the following open financial basis swaps at September 30, 2018 : NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS Volume in MMBtu (1) 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 ) 4,445,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Oct '18 — Dec '18 (0.63 ) 17,950,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '19 — Dec '19 (0.68 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 152,500 San Juan NYMEX Henry Hub Nov '18 — Dec '18 (0.47 ) 2,365,000 San Juan NYMEX Henry Hub Jan '19 — Oct '19 (0.78 ) _________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub. OIL BASIS SWAP DERIVATIVE CONTRACTS ໿ Volume in bbl (1) Reference Price 1 (1) Reference Price 2 (1) Period Weighted Average Spread ($ per bbl) 552,000 CMA Oil WTI Oct '18 — Dec '18 $ (0.54 ) _________________ (1) Represents basis swaps for the basis differentials between NYMEX CMA (Calendar Monthly Average) Roll that reconcile the trade month versus the delivery month for physical contract pricing and West Texas Intermediate (“WTI”).

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS A summary of the changes in asset retirement obligations is included in the table below (in thousands): ໿  2018 Balance, as of January 1 (Predecessor) $ 10,469 Liabilities settled (63 ) Revisions to estimates 63 Accretion expense 39 Balance, as of February 8 (Predecessor) $ 10,508  Balance, as of February 9 (Successor) $ — Liabilities assumed from Business Combination 5,998 Liabilities incurred 1,689 Liabilities settled (1,249 ) Liabilities transferred in sale of properties (20 ) Revisions to estimates (1) 3,562 Accretion expense 489 Balance, as of September 30 (Successor) 10,469 Less: Current portion 1,300 Long-term portion $ 9,169 (1) The total revisions included $3.0 million related to additions to property, plant and equipment for the Successor Period.

Long Term Debt, Net

Long Term Debt, Net	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long Term Debt, Net	LONG-TERM DEBT, NET Long-term debt, net consisted of the following (in thousands): ໿  Successor Predecessor  September 30, December 31, 2017 Senior secured revolving credit facility $ 80,000 $ 117,065 7.875% senior unsecured notes due 2024 500,000 500,000 Unamortized premium on senior unsecured notes 30,354 — Unamortized deferred financing costs — (9,625 ) Total long-term debt, net $ 610,354 $ 607,440 Senior Secured Revolving Credit Facility (Successor). In connection with the consummation of the Business Combination, all indebtedness at that time under the senior secured revolving credit facility was repaid in full. On February 9, 2018, and in connection with the closing of the AM Contribution Agreement (as described in Note 5), we entered into the Eighth Amended and Restated Credit Agreement with Wells Fargo Bank, National Association, as the administrative agent (the “Eighth A&R credit facility”). The Eighth A&R credit facility is for an aggregate maximum credit amount of $1.0 billion with an initial $350.0 million borrowing base. In April 2018 , our borrowing base was increased to $400.0 million . This borrowing base was reaffirmed by the lenders subsequent to September 30, 2018. The next scheduled redetermination will occur in April 2019, at which time the borrowing base may be increased, lowered or stay the same. The Eighth A&R credit facility does not permit us to borrow funds if, at the time of such borrowing, we are not in compliance with the financial covenants set forth in the Eighth A&R credit facility. As of September 30, 2018 , we had $80.0 million of borrowings outstanding under the Eighth A&R credit facility and had $21.9 million of outstanding letters of credit, leaving a total borrowing capacity of $298.1 million remaining available for future use. The principal amounts borrowed are payable on the maturity date of February 9, 2023 . We have a choice of borrowing in Eurodollars or at the reference rate, with such borrowings bearing interest, payable quarterly for reference rate loans or, for Eurodollar loans, in one, three or six-month tranches. Eurodollar loans bear interest at a rate per annum equal to the applicable LIBOR rate, plus a margin ranging from 2.00% to 3.00% . Reference rate loans bear interest at a rate per annum equal to the greater of (i) the agent bank’s reference rate, (ii) the federal funds effective rate plus 50 basis points or (iii) the rate for one-month Eurodollar loans plus 1.00% , plus a margin ranging from 1.00% to 2.00% . The amounts outstanding under the Eighth A&R credit facility are secured by the first priority liens on substantially all of the Company’s, and its material operating subsidiaries’, oil and natural gas properties and associated assets and all of the equity of our material operating subsidiaries that are guarantors of the Eighth A&R credit facility. Additionally, SRII Opco and AMH GP have pledged their respective limited partner interests in us as security for our obligations. If an event of default occurs under the Eighth A&R credit facility, the administrative agent will have the right to proceed against the pledged collateral and take control of substantially all of our assets and our material operating subsidiaries that are guarantors. The Eighth A&R credit facility, as amended effective August 13, 2018, contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions in excess of specific amounts, enter into or be party to hedge agreements, amend organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The Eighth A&R credit facility permits us to make distributions to any parent entity (i) to pay for reimbursement of third party costs and general and administrative expenses (“G&A”) incurred in the ordinary course of business by such parent entity or (ii) in order to permit such parent entity to (x) make permitted tax distributions and (y) pay the obligations under the tax receivable agreement. The Eighth A&R credit facility also requires us to maintain the following two financial ratios: • a current ratio, subject to various adjustments as defined in the Eighth A&R credit facility, tested quarterly, commencing with the fiscal quarter ended June 30, 2018 , of our consolidated current assets to our consolidated current liabilities of not less than 1.0 to 1.0 as of the end of each fiscal quarter; and • a leverage ratio, tested quarterly, commencing with the fiscal quarter ended June 30, 2018 , of our consolidated debt (other than obligations under hedge agreements) as of the end of such fiscal quarter to our consolidated EBITDAX annualized by multiplying EBITDAX for the period of (a) the fiscal quarter ended June 30, 2018 times 4, (b) the two fiscal quarter periods ended September 30, 2018 times 2 (c) the three fiscal quarter periods ending December 31, 2018 times 4/3rds and (d) for each fiscal quarter on or after March 31, 2019, EBITDAX for the four-fiscal quarter period then ended, of not greater than 4.0 to 1.0 . As of September 30, 2018 , we were in compliance with the financial ratios described above. Senior Secured Revolving Credit Facility (Predecessor). As of December 31, 2017 , the Company had $117.1 million of borrowings outstanding. At the date of the Business Combination, the outstanding balance under our credit facility was paid off. Senior Unsecured Notes. We have $500.0 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) which were issued at par by us and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016 . The senior notes were issued in a private placement but were exchanged for substantially identical registered senior notes in November 2017 . The senior notes will mature on December 15, 2024 , and interest is payable semi-annually on June 15 and December 15 of each year. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the senior notes for an amount of cash not greater than the net cash proceeds from certain equity offerings at a redemption price of 107.875% of the principal amount, plus accrued and unpaid interest, if any, to the date of redemption, if at least 65% of the aggregate principal amount of the senior notes remains outstanding after such redemption and the redemption occurs within 120 days of the closing date of such equity offering. At any time prior to December 15, 2019, we may, on any one or more occasions, redeem all or part of the senior notes for cash at a redemption price equal to 100% of their principal amount of the senior notes redeemed plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of redemption. Upon the occurrence of certain kinds of change of control, each holder of the senior notes may require us to repurchase all or a portion of the senior notes for cash at a price equal to 101% of the aggregate principal amount of the senior notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, we may redeem the senior notes, in whole or in part, at redemption prices (expressed as percentages of principal amount) equal to 105.906% for the twelve-month period beginning on December 15, 2019, 103.938% for the twelve-month period beginning on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption. The senior notes are fully and unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries, subject to certain customary release provisions. Accordingly, they will rank equal in right of payment to all of our existing and future senior indebtedness; senior in right of payment to all of our existing and future indebtedness that is expressly subordinated to the senior notes or the respective guarantees; effectively subordinated to all of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under our credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of our subsidiaries that do not guarantee the senior notes. The senior notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in the indenture governing the senior notes to, under certain circumstances, prepay subordinated indebtedness, pay distributions, redeem stock or make certain restricted investments; incur indebtedness; create liens on the Issuers’ assets to secure debt; restrict dividends, distributions or other payments; enter into transactions with affiliates; designate subsidiaries as unrestricted subsidiaries; sell or otherwise transfer or dispose of assets, including equity interests of restricted subsidiaries; effect a consolidation or merger; and change our line of business. Under the terms of the indenture for the senior notes, if we experience certain specific change of control events, unless the Issuers have previously or concurrently exercised their right to redeem all of the senior notes under the optional redemption provision, such holder has the right to require us to purchase such holder’s senior notes at 101% of the principal amount plus accrued and unpaid interest to the date of the purchase. The closing of the Business Combination with AMR did not constitute a change of control under the indenture governing the senior notes because certain existing owners of the Company and SRII Opco entered into an amended and restated voting agreement with respect to the voting interests in AMH GP. See Note 5 — Business Combination to the consolidated condensed financial statements for further detail. The indenture contains customary events of default, including: • default in any payment of interest on the senior notes when due, continued for 30 days; • default in the payment of principal or premium, if any, on the senior notes when due; • failure by the Issuers or any subsidiary guarantor to comply with its obligations under the indenture; • default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by the Issuers or restricted subsidiaries; • certain events of bankruptcy, insolvency or reorganization of the Issuers or restricted subsidiaries; and • failure by the Issuers or certain subsidiaries that would constitute a payment of final judgment aggregating in excess of $20 million . If an event of default occurs and is continuing, the holders of such indebtedness may elect to declare all the funds borrowed to be immediately due and payable with accrued and unpaid interest. Borrowings under other debt instruments that contain cross-acceleration or cross-default provisions may also be accelerated and become due and payable. As of September 30, 2018 , we were in compliance with the indentures governing the senior notes. Bond Premium (Successor). As discussed in Note 5 , the fair value of our senior notes as of the acquisition date was $533.6 million . The bond premium of $33.6 million is being amortized over the respective term of the senior notes. The bond premium amortization recognized in interest expense was $1.2 million and $3.3 million for the three months ended September 30, 2018 (Successor) and the Successor Period, respectively. The unamortized bond premium related to the senior notes is included as a component of long-term debt in the condensed consolidated balance sheet as of September 30, 2018 . Deferred financing costs. As of December 31, 2017 (Predecessor), we had $11.4 million of unamortized deferred financing costs related to both our senior secured notes and the Eighth A&R credit facility. As a result of the Business Combination, our unamortized deferred financing costs were adjusted to a fair value of zero at February 9, 2018. During the Successor Period, we incurred additional deferred financing costs related to the Eighth A&R credit facility of $1.4 million . These costs are reflected as deferred financing costs, net in other noncurrent assets in the condensed consolidated balance sheets as of September 30, 2018 (Successor). The amortization of the deferred financing costs is included in interest expense in the consolidated statements of operations. For the three months ended September 30, 2018 (Successor) and 2017 (Predecessor), the amortization of deferred financing costs was $0.1 million and $0.7 million, respectively. For the Successor Period, the 2018 Predecessor Period and the 2017 Predecessor Period, the amortization of deferred financing costs was $0.2 million, $0.2 million and $2.2 million, respectively.

Accounts Payable And Accrued Li

Accounts Payable And Accrued Liabilities	9 Months Ended
	Sep. 30, 2018
Payables and Accruals [Abstract]
Accounts Payable And Accrued Liabilities	ACCOUNTS PAYABLE AND ACCRUED LIABILITIES The following provides the details of accounts payable and accrued liabilities (in thousands): ໿  Successor Predecessor  September 30, December 31, Accruals for capital expenditures $ 83,687 $ 48,771 Revenues and royalties payable 44,626 29,514 Accruals for operating expenses/taxes 8,156 14,632 Accrued interest 11,651 2,587 Derivative settlement payable 4,593 2,106 Other 3,408 4,301 Total accrued liabilities 156,121 101,911 Accounts payable 71,018 68,578 Accounts payable and accrued liabilities $ 227,139 $ 170,489

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES Commitments We lease office space and certain field equipment such as compressors, under long-term operating lease agreements. On April 1, 2018, we amended the lease agreement for our corporate headquarters located in Houston, Texas. The amended lease agreement provides for additional office space and extends the original lease term through April 2028. Due to the amendment, we have additional lease commitment obligations of approximately $17.6 million through April 2028 . Any initial rent-free months are amortized over the life of the lease. The Company has entered into certain firm transportation contracts that extend through 2028. At September 30, 2018 , the future minimum commitments related to these contracts were approximately $5.7 million a year. Contingencies Environmental claims . Various landowners have sued us in lawsuits concerning several fields in which we have, or historically had, operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our condensed consolidated financial statements at September 30, 2018 . Title/lease disputes . Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made. Litigation (Predecessor) . On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our former subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claimed they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. In connection with the Business Combination, the liability was included in the distribution of our non-STACK assets to the AM Contributor. On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP and Alta Mesa Services, LP, each a wholly owned subsidiary, and us (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit alleged that the AMH Parties made improper post production deductions that resulted in underpayment of royalties on natural gas and/or constituents of the gas stream produced from wells. The case was moved to federal court and stayed by the court pending the parties’ efforts to settle the case. In June 2017, the court administratively closed the case following mediation. As of December 31, 2017 , we had accruals of approximately $4.7 million in accounts payable and accrued liabilities in our condensed consolidated balance sheets and in G&A in our condensed consolidated statements of operations as a result of this litigation. During January 2018, approximately $4.7 million was paid to fund the settlement. On March 12, 2018, the class settlement was approved by the Court. Litigation (Successor) . On March 1, 2017, Mustang Gas Products, LLC (“Mustang”) filed suit in the District Court of Kingfisher County, Oklahoma, against Oklahoma Energy Acquisitions, LP, and eight other entities, including us. Mustang alleges that (1) Mustang is a party to gas purchase agreements with Oklahoma Energy containing gas dedication covenants that burden land, leases and wells in Kingfisher County, Oklahoma, and (2) Oklahoma Energy, in concert with the other defendants, has wrongfully diverted gas sales to us in contravention of these agreements. Mustang asserts claims for declaratory judgment, anticipatory repudiation and breach of contract against Oklahoma Energy only. Mustang also claims tortious interference with contract, conspiracy and unjust enrichment/constructive trust against all defendants, including us. We believe that the allegations contained in this lawsuit are without merit and intend to vigorously defend ourselves. Other contingencies . We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. The outcomes cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Performance appreciation rights . In the third quarter of 2014 , we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan was intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants were granted performance appreciation rights (“PARs”) with a stipulated initial designated value. The Company accelerated the vesting and payment of all outstanding PARs in connection with the Business Combination with AMR as described in Note 5. The value of the PARs that vested was approximately $10.9 million and such amount was recorded in G&A in the Successor Period. Following the closing of the Business Combination, the Plan was terminated. Nonqualified Deferred Compensation . In 2013, we established a nonqualified deferred compensation plan, the Alta Mesa Holdings, L.P. Supplemental Executive Retirement Plan (the “Retirement Plan”). The Retirement Plan was intended to provide additional flexibility and tax planning advantages to our senior executives and other key highly compensated employees. In connection with the Business Combination, we terminated the Retirement Plan resulting in approximately $9.4 million being recorded in G&A in the Successor Period.

Significant Risks And Uncertain

Significant Risks And Uncertainties	9 Months Ended
	Sep. 30, 2018
Risks and Uncertainties [Abstract]
Significant Risks And Uncertainties	SIGNIFICANT RISKS AND UNCERTAINTIES Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. Prices for oil and natural gas can fluctuate widely in response to relatively minor changes in the global and regional supply of and demand for oil and natural gas, as well as market uncertainty, economic conditions and a variety of additional factors. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Declines in oil and/or natural gas prices or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness. We mitigate some of this vulnerability by entering into oil, natural gas, and natural gas liquids price derivative contracts. See Note 9 — Derivative Financial Instruments for further details on derivatives.

Partners' Capital

Partners' Capital	9 Months Ended
	Sep. 30, 2018
Partners' Capital [Abstract]
Partners' Capital	PARTNERS’ CAPITAL Management and Control: Our Seventh Amended and Restated Agreement of Limited Partnership (the “Seventh Amended Partnership Agreement”) currently provides for interests to be divided into economic units held by the partners referred to as “LP Units” and non-economic general partner interests owned by AMH GP referred to as “GP Units”. AMH GP owns all the GP Units and in connection with the Business Combination, SRII Opco owns all the LP Units. As a limited partnership, our operations and activities are managed by the board of directors (the “Board of Directors”) of our general partner, AMH GP. The limited liability company agreement of AMH GP provides for two classes of interests: (i) Class A Units, which hold 100% of the economic interests in AMH GP and (ii) Class B Units, which hold 100% of the voting interests in AMH GP. SRII Opco is the sole owner of Class A Units and owns 90% of the Class B Units. Harlan H. Chappelle, our Chief Executive Officer and a director, Michael Ellis, the founder, our Chief Operating Officer and a director and certain affiliates of Bayou City Energy Management, LLC, a Delaware limited liability company, and HPS Investment Partners, LLC, a Delaware limited liability company, own an aggregate 10% of the Class B Units. AMH GP’s Board of Directors are selected by the Class B members. Notwithstanding the foregoing, voting control of AMH GP is vested in SRII Opco pursuant to a voting agreement. The Seventh Amended Partnership Agreement specifies the manner in which we will make cash distribution to our partners. When AMH GP so directs, we shall make distributions of Net Cash Flow (as defined in the Seventh Amended Partnership Agreement) to the limited partner.

Equity Based Compensation (Succ

Equity Based Compensation (Successor)	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Based Compensation (Successor)	EQUITY-BASED COMPENSATION (Successor) Following the closing of the Business Combination, AMR adopted the Alta Mesa Resources, Inc. 2018 Long Term Incentive Plan (the “LTIP”). A total of 50,000,000 shares of AMR’s Class A Common Stock were reserved for issuance under the LTIP. The LTIP provides for the grant of stock options, including incentive stock options (“ISOs”), nonqualified stock options (“NSOs”), stock appreciation rights (“SARs”), restricted stock, dividend equivalents, restricted stock units (“RSUs”) and other stock-based awards in AMR’s Class A Common Stock. Prior to the Business Combination, we did not have any equity-based compensation programs. Pursuant to the LTIP, certain grants of stock-based awards have been made to various employees of the Company since February 9, 2018. During the Successor Period, we recognized non-cash stock-based compensation expense of $6.7 million resulting from stock options, restricted stock, and RSUs awards granted to our employees, which is included in general and administrative expense in the accompanying condensed consolidated statements of operations. Historical amounts may not be representative of future amounts as the value of future awards may vary from historical amounts. We recognize compensation expense on a straight-line basis for service-based grants to our employees over the vesting period. The fair value of restricted stock awards and performance-based restricted stock units is determined based on the estimated fair market value of AMR’s Class A Common Stock on the date of grant. As provided in ASU 2016-09, Compensation—Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting , the Company has elected to recognize actual forfeitures as they occur. Stock options . Options that have been granted under the LTIP expire seven years from the grant date and generally vest in one-third increments each year on the anniversary date following the date of grant, based on continued employment. The exercise price for an option granted under the LTIP may not be below the fair value of AMR’s Class A Common Stock on the grant date. Information about outstanding stock options is summarized in the table below: ໿  Successor  Stock Options Weighted Average Grant - Date Fair Value Weighted Average Remaining Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding as of February 9, 2018 — $ — — Granted 4,704,433 4.45 — Exercised — — — Forfeited or expired (94,693 ) 4.52 — Outstanding as of September 30, 2018 4,609,740 $ 4.44 6.4 $ — Exercisable as of September 30, 2018 — $ — — $ — Compensation cost related to stock options is based on the grant-date fair value of the award, recognized ratably over the applicable three -year vesting period. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the re-levered asset volatility implied by a set of comparable companies. Expected term is based on the simplified method, and is estimated as the average of the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates. The following summarizes the assumptions used to determine the fair value of those options: ໿ Successor  February 9, 2018 Through September 30, 2018 Expected term (in years) 4.5 Expected stock volatility 64.6 % Dividend yield — Risk-free interest rate 2.4 % As of September 30, 2018 , there was $16.2 million of unrecognized compensation cost related to non-vested stock options. The Company expects to recognize that cost on a pro rata basis over a weighted average period of 2.4 years. Restricted stock . Restricted stock granted to employees generally vests in one-third increments each year on the anniversary date following the date of grant, based on continued employment. Prior to vesting, no dividends are paid and the shares may not be traded. The following table provides information about restricted stock awards granted during the Successor Period: ໿  Successor  Restricted Stock Awards Weighted Average Grant Date Fair Value per share Outstanding as of February 9, 2018 — $ — Granted 1,658,756 7.77 Vested — — Forfeited or expired (42,086 ) 8.74 Outstanding as of September 30, 2018 1,616,670 $ 7.75 Compensation cost for restricted shares is based upon the grant-date market value of the award, recognized ratably over the applicable three -year vesting period, subject to the employee’s continued service. Unrecognized compensation cost related to unvested restricted shares at September 30, 2018 was $10.1 million , which the Company expects to recognize over a weighted average remaining period of 2.5 years. Restricted stock units . The Company also grants performance-based restricted stock units (“PSUs”) to key employees under the LTIP. PSUs granted during the period will vest over three years at 20% during the first year, 30% during the second year and 50% during the third year. The number of PSUs vesting each year will be based on the achievement of annual company-specified performance goals and objectives applicable to each respective year of vesting. Based on achievement of those goals and objectives, the number of PSUs that vest can range from 0% to 200% of the target grant applicable to each vesting period. For accounting purposes, the Company will only recognize PSUs granted when the specified performance thresholds for future periods have been established. For PSUs granted during the period February 9, 2018 to September 30, 2018 , only the performance goals and objectives for 2018 have been established to date. Those 2018 performance goals are related to the Company achieving a specified level of EBITDAX for the period ended December 31, 2018. The following summary provides information about the target number of PSUs granted during the Successor Period:  Successor  PSUs Weighted Average Grant - Date Fair Value per unit Outstanding as of February 9, 2018 — $ — Granted 781,200 8.69 Vested — — Forfeited or expired (4,174 ) 8.45 Outstanding as of September 30, 2018 777,026 — $ 8.69 As of September 30, 2018 , there was no material unrecognized compensation cost related to the unvested PSUs.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions	RELATED PARTY TRANSACTIONS On January 13, 2016, Alta Mesa’s wholly owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a Joint Development Agreement, as amended on June 10, 2016 and December 31, 2016, (the “Joint Development Agreement”), with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City, to fund a portion of Alta Mesa’s drilling operations and to allow Alta Mesa to accelerate development of our STACK acreage. The Joint Development Agreement, as amended, establishes a development plan of 60 wells in three tranches, and provides opportunities for the parties to potentially agree to an additional 20 wells. Pursuant to the terms and provisions of the Joint Development Agreement, BCE committed to fund 100% of Alta Mesa’s working interest share up to a maximum average well cost of $3.2 million in drilling and completion costs per well for any tranche , subject to modifications or adjustments proposed and approved by the parties. We are responsible for any drilling and completion costs exceeding approved amounts. In exchange for the payment of 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, Alta Mesa and BCE will each bear its respective proportionate working interest share of all subsequent costs and expenses related to such joint well. Mr. William McMullen, one of our former 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 2018 Predecessor Period, BCE advanced us approximately $39.5 million to drill wells under the Joint Development Agreement. As of September 30, 2018 , 55 joint wells have been drilled or spudded. As of September 30, 2018 (Successor), and December 31, 2017 (Predecessor), $16.9 million and $23.4 million, respectively, of net advances remaining from BCE for their working interest share of the drilling and development costs arising under the Joint Development Agreement were included as “Advances from related party” in our consolidated balance sheets. BCE may request refunds of certain advances from time to time if funded wells previously on the drilling schedule were subsequently removed. On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with Kingfisher. The Gas Gathering and Processing Agreement was subsequently amended on February 3, 2017, effective as of December 1, 2016, and thereafter amended on June 29, 2018, effective as of April 1, 2018. The recent amendment to the Gas Gathering and Processing Agreement impacts our net NGL production volumes but will not impact our consolidated financial statements. Effective June 1, 2018, we entered into a Marketing Services Agreement with ARM Energy Management, LLC (“AEM”) pursuant to which AEM markets our oil, natural gas and natural gas liquids and sells them under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location and quality taken into account. AEM remits monthly collections on these sales to us, and receives a marketing fee. In addition, AEM markets our firm transportation on the ONEOK Gas Transportation, L.L.C. system for an asset management fee. The AM Contributor owns less than 10% of AEM. For the period from June 1, 2018 to September 30, 2018 , we paid AEM $0.8 million for our share of the marketing fees.

Subsidiary Guarantors

Subsidiary Guarantors	9 Months Ended
	Sep. 30, 2018
Guarantees [Abstract]
Subsidiary Guarantors	SUBSIDIARY GUARANTORS All of our wholly owned subsidiaries are guarantors under the terms of the senior notes and the Eighth A&R credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. As the parent company to these subsidiaries, we have no independent operations, assets, or liabilities. The guarantees are full and unconditional (except for customary release provisions) and joint and several. Those subsidiaries which are not wholly owned by us and are not guarantors of our senior notes or our credit facility, are immaterial subsidiaries. There are no restrictions on dividends, distributions, loans or other transfers of funds from the subsidiary guarantors to us.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
Subsequent Events	SUBSEQUENT EVENTS Sale of Produced Water Assets Effective November 9, 2018, the Company sold its produced water assets, consisting of over 200 miles of produced water gathering pipelines, and related facilities and equipment, along with 20 produced water disposal wells, surface leases, easements and other agreements, net of related obligations, to a subsidiary of Kingfisher Midstream, LLC, a related party and wholly owned subsidiary of our parent, AMR, for a total purchase price of $ 90.0 million in cash, subject to normal acquisition adjustments. At September 30, 2018 , the net book value of long-lived assets associated with these operations totaled $ 86.9 million. In conjunction with the sale, the Company entered into a new fifteen-year water gathering and disposal agreement with Kingfisher Midstream.

Summary Of Significant Accoun_2

Summary Of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation . As a result of the Business Combination, AMR was treated as the accounting acquirer and we are the accounting acquiree. Pursuant to Financial Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 805, Business Combinations , (“ASC 805”), our identifiable assets acquired and liabilities assumed were provisionally recorded at their estimated fair values on the Closing Date of the Business Combination (also referred to herein as the “acquisition date”). Fair value adjustments related to the transaction have been pushed down to us resulting in our assets and liabilities being recorded at fair value as of the acquisition date. As a result of the Transactions described above, the financial statements and certain footnote presentations separate the Company’s presentations into two distinct periods, the period before the consummation of the transaction (“Predecessor”) and the period after that date (“Successor”), to indicate the application of the different basis of accounting between the periods presented. The Successor periods presented herein are for the three months ended September 30, 2018 and from February 9, 2018 to September 30, 2018 (collectively, “Successor Periods”); and the Predecessor periods presented herein are from January 1, 2018 to February 8, 2018 (“2018 Predecessor Period”), the three months ended September 30, 2017 and the nine months ended September 30, 2017 (“2017 Predecessor Period,” and, together with the 2018 Predecessor Period, the “Predecessor Periods”). As noted above, we distributed our non-STACK assets and liabilities to the AM Contributor in connection with the closing of the Business Combination. The distribution of our non-STACK assets and liabilities and the sale of our Weeks Island field during the fourth quarter of 2017 (collectively, the “non-STACK assets”) were part of the Company’s overall strategic shift to operate only in the eastern Anadarko Basin. As a result, we have classified the assets and liabilities and operating results of the non-STACK assets as discontinued operations during the Predecessor Periods within the condensed consolidated financial statements. See Note 7 — Discontinued Operations (Predecessor) for further discussion. Principles of Consolidation and Reporting . The accompanying condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the condensed consolidated financial statements do not include all of the information and footnotes required by GAAP for complete financial statements. The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The condensed consolidated financial statements included herein as of September 30, 2018 , and for the three months ended September 30, 2018 (Successor) and the period from February 9, 2018 through September 30, 2018 (Successor), the period from January 1, 2018 through February 8, 2018 (Predecessor) and the three and nine months ended September 30, 2017 (Predecessor), are unaudited, and in the opinion of management, the information furnished reflects all material adjustments, consisting of normal recurring adjustments, necessary for a fair presentation of consolidated financial position and of the results of operations for the interim periods presented. The condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated financial statements for the year ended December 31, 2017 , which were filed with the Securities and Exchange Commission (the “SEC”) in our 2017 Annual Report. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The reclassifications had no impact on net income (loss) or partners’ capital. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year. The Company’s condensed consolidated statement of operations subsequent to the Business Combination includes depreciation and amortization expense on the Company’s property and equipment balances resulting from the fair value adjustments made under the new basis of accounting. Certain other items of income and expense were also impacted. Therefore, the Company’s financial information prior to the Business Combination is not comparable to its financial information subsequent to the Business Combination.
Use of Estimates	Use of Estimates . The preparation of condensed consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Reserve estimates significantly impact depreciation, depletion, and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other estimates are utilized to determine amounts related to oil and natural gas revenues, the value of oil and natural gas properties, the value of other property and equipment, bad debts, asset retirement obligations, derivative contracts, accounting for business combinations, state taxes, share-based compensation and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.
Bond Premium on Senior Unsecured Notes	Bond Premium on Senior Unsecured Notes . As a result of the pushdown accounting related to the Business Combination, the Company estimated the fair value of our $500.0 million senior unsecured notes at $533.6 million as of the acquisition date. The amount in excess of the original principal balance was recorded as a bond premium, which is being amortized as a reduction to interest expense.
Equity-Based Compensation (Successor)	Equity-Based Compensation (Successor) . The Company recognizes compensation related to all stock-based awards in the financial statements based on their estimated grant-date fair value. AMR grants various types of stock-based awards including stock options, restricted stock and performance-based restricted stock units. The fair value of stock option awards is determined using the Black-Scholes option pricing model. Service-based restricted stock awards and performance-based restricted stock units are valued using the market price of AMR’s common stock on the grant date. Compensation cost is recognized ratably over the applicable vesting period.
Going Concern	Going Concern . The Company’s management is required to evaluate an entity’s ability to continue as a going concern for a period of one year following the date of the issuance of the Company’s consolidated financial statements. Disclosure is required if substantial doubt exists about an entity’s ability to continue as a going concern during the evaluation period, including management’s plans to alleviate the conditions and events that raise substantial doubt of going concern, if applicable. At the date of the issuance of these consolidated financial statements, management considers the Company to be a going concern and has prepared these consolidated financial statements on a going concern basis.
Recent Accounting Pronouncements	Recent Accounting Pronouncements Issued But Not Yet Adopted . 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. The Company will adopt this new standard at the same time as our parent company, which will be no later than the fiscal year beginning after December 15, 2019, although early adoption is permitted. The Company is currently evaluating the impact of this new standard on its consolidated financial position and results of operations and has 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 May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASU 2014-09”), which seeks to provide a single, comprehensive revenue recognition model for all contracts with customers concerning the recognition, measurement and disclosure of revenue from those contracts. Subsequent to the issuance of ASU 2014-09, the FASB amended the standard to provide clarification and interpretive guidance to assist entities with implementation efforts, including guidance pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. The core principle of the new amended standard is that a company will recognize revenue when it transfers promised goods and services to customers in an amount that reflects the consideration to which the company is entitled in exchange for those services. In order to comply with the new standard, companies will need to (i) identify performance obligations in each contract, (ii) estimate the amount of variable consideration to include in the transaction price and (iii) allocate the transaction price to each separate performance obligation. ASU 2014-09, as amended, is effective for interim and annual periods beginning after December 15, 2017, except for emerging growth companies that elect to use the extended transition period for complying with any new or revised financial accounting standards pursuant to Section 7(a)(2)(b) of the Securities Act. ASU 2014-09 allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. As an emerging growth company, we previously elected to use the extended transition period to defer implementation of the new standard until the first quarter of 2019 using the modified retrospective method with a cumulative adjustment to retained earnings as necessary. AMR, our parent company, is also an emerging growth company, but will cease to be an emerging growth company on December 31, 2018, which will require them to adopt ASU 2014-09 on December 31, 2018, with modified retroactive implementation as of January 1, 2018. Accordingly, we will also adopt ASU 2014-09 at the same time as our parent company. We are continuing our review of contracts for each of our revenue streams and evaluating the impact on our consolidated financial statements. We are continuing to evaluate the provisions of ASU 2014-09, as it relates to certain sales contracts, and in particular, as it relates to disclosure requirements. In addition, we are evaluating the impact, if any, on the presentation of our revenues and expenses under the new gross-versus-net presentation guidance and on our current accounting policies, including the need to make changes to relevant accounting policies and internal controls, if needed. Based on assessments performed to date, we do not expect ASU 2014-09 to have an effect on the timing of revenue recognition or our financial position. In addition, we currently expect the impact regarding gross-versus-net presentation to involve certain presentation changes specifically related to natural gas processing contracts; however, the impact of such presentation changes will not impact our consolidated operating income, net income or cash flows. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 “Leases.” The amendments in this update require, among other things, that lessees recognize the following for all leases (except for short-term leases) at the commencement date: (i) a lease liability, which is a lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis; and (ii) a right-of-use asset, which is an asset that represents a lessee’s right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ASU 2016-02 also requires disclosures designed to provide information on the amount, timing, and uncertainty of cash flows arising from leases. In January 2018, the FASB issued ASU No. 2018-01, Land easement practical expedient for transition to Topic 842 (“ASU 2018-01”), which provides an optional transition practical expedient to not evaluate under Topic 842 existing or expired land easements that were not previously accounted for as leases under Topic 840, Leases. The standard, as amended, will be effective for interim and annual periods beginning after December 15, 2018. In the normal course of business, we enter into operating lease agreements to support our exploration and development operations and lease assets such as drilling rigs, well equipment, compressors, office space and other assets. The standard provides several optional practical expedients in transition. We expect to elect the “package of practical expedients”, which permits us to forgo reassessment of our prior conclusions about lease identification, lease classification and initial direct costs for leases entered into prior to the effective date. We also expect to elect the land easement relief which permits us to forgo reassessment of existing or expired land easements not previously accounted for under ASC 840. Additionally, we expect to elect the practical expedient to not provide comparative reporting periods and therefore financial information will not be updated and the disclosures required under the new standard will not be provided for dates and periods before January 1, 2019. We do not expect to elect the use-of-hindsight practical expedient. At this time, we are evaluating the financial impact ASU 2016-02 will have on our financial statements; however, the adoption and implementation of ASU 2016-02 is expected to have an impact on our consolidated balance sheets resulting in an increase in both the assets and liabilities relating to our operating lease activities greater than twelve months. The adoption may also result in a change in the amount of lease expense recorded on our consolidated statements of operations, as well as add additional disclosures. We expect our implementation work team will complete its evaluation of this new standard by the end of 2018. In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. As an emerging growth company, we had elected to use the extended transition period to defer adoption of this standard until 2019 . However, our parent company will lose its emerging growth status, effective December 31, 2018 . Accordingly, we will be required to adopt this new standard on December 31, 2018, when adopted by our parent company. The adoption of this guidance will not impact our financial position or results of operations but could result in presentational changes in our consolidated statements of cash flows. 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 used today. With respect to our trade 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, which will be effective for us in fiscal years beginning after December 15, 2019, also requires additional disclosures regarding the credit quality of our trade 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.

Summary Of Significant Accoun_3

Summary Of Significant Accounting Policies (Tables)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Reconciliation of cash, cash equivalents and restricted cash	The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets and the consolidated statements of cash flows (in thousands): ໿  Successor Predecessor  September 30, December 31, Cash and cash equivalents $ 8,869 $ 3,660 Restricted cash 872 1,269 Cash of discontinued operations — 61 Total cash, cash equivalents and restricted cash $ 9,741 $ 4,990

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	9 Months Ended
	Sep. 30, 2018
Supplemental Cash Flow Information [Abstract]
Supplemental cash flow disclosures and non-cash investing and financing activities	Supplemental cash flow disclosures and non-cash investing and financing activities are presented below (in thousands): ໿  Successor Predecessor  February 9, 2018 January 1, 2018 Nine Through Through Months Ended  September 30, 2018 February 8, 2018 September 30, 2017 Supplemental cash flow information: Cash paid for interest $ 22,073 $ 1,145 $ 25,675 Cash paid for state income taxes 7 — — Non-cash investing and financing activities: Increase in asset retirement obligations 4,652 — 3,778 Asset retirement obligations assumed, purchased properties — — 705 Increase in accruals or payables for capital expenditures 35,967 4,712 41,322 Distribution of non-STACK (assets) net liability — 33,102 — Increase in accounts receivable for sale of assets (524 ) — —

Accounts Receivable (Tables)

Accounts Receivable (Tables)	9 Months Ended
	Sep. 30, 2018
Receivables [Abstract]
Schedule of accounts receivable	Accounts receivable consisted of the following (in thousands): ໿  Successor Predecessor  September 30, December 31, Oil, natural gas and natural gas liquids sales $ 40,134 $ 26,916 Joint interest billings 44,548 13,821 Pooling interest (1) 23,367 35,839 Allowance for doubtful accounts (65 ) (415 ) Total accounts receivable, net $ 107,984 $ 76,161 _________________ (1) Pooling interest relates to Oklahoma’s forced pooling process which requires the Company to offer mineral interest owners the option to participate in the drilling of proposed wells. The pooling interest listed above represents costs of unbilled interests on wells which the Company incurred before the pooling process was completed. Depending upon the outcome of the pooling process, these costs may be billed to potential working interest owners or added to oil and gas properties.

Business Combination (Tables)

Business Combination (Tables)	9 Months Ended
	Sep. 30, 2018
Business Acquisition [Line Items]
Purchase consideration	AMR’s preliminary estimated purchase price consideration for Alta Mesa was as follows (in thousands): ໿  February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Preliminary Purchase Consideration: (2) SRII Opco Common Units issued (3) $ 1,251,782 $ 9,467 $ 1,261,249 Estimated fair value of contingent earn-out purchase consideration (4) 284,109 — 284,109 Total purchase price consideration $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustment relates to the issuance of 1,197,934 of additional SRII Opco Common Units, valued at approximately $7.90 per unit, to the AM Contributor based on a final closing statement agreed to by the parties during the three months ended June 30, 2018 (Successor). (2) The preliminary purchase price consideration is for 100% of the limited partner interests in us and 100% of the economic interests and 90% of the voting interests in AMH GP. (3) At closing, the Riverstone Contributor received consideration of 20,000,000 SRII Opco Common Units and the AM Contributor received consideration of 138,402,398 SRII Opco Common Units. The estimated fair value of an SRII Opco Common Unit was approximately $7.90 per unit and reflects discounts for holding requirements and liquidity. (4) For a period of seven years following Closing, the AM Contributor will be entitled to receive an earn-out consideration to be paid in the form of SRII Opco Common Units (and a corresponding number of shares of AMR Class C Common Stock) if the 20-day VWAP of the Class A Common Stock of AMR equals or exceeds the specified prices pursuant to the AM Contribution Agreement. Pursuant to ASC 805 and ASC 480, Distinguishing Liabilities from Equity (“ASC 480”), we have determined that the fair value of the earn-out consideration was approximately $284.1 million , which was classified as equity. The fair value of the contingent equity earn-out consideration was determined using the Monte Carlo simulation valuation method based on Level 3 inputs as defined in the fair value hierarchy. The key inputs included the listed market price for Class A Common Stock, market volatility of a peer group of companies similar to AMR (due to the lack of trading activity in the Class A Common Stock), no dividend yield, an expected life of each earn-out threshold based on the remaining contractual term of the contingent liability earn-out period and a risk-free rate based on U.S. dollar overnight indexed swaps with a maturity equivalent to the earn-out’s expected life.
Allocation of purchase consideration	The allocation of AMR’s preliminary estimate of the purchase consideration to the assets acquired and liabilities assumed in the acquisition of Alta Mesa was as follows (in thousands): ໿  February 9, 2018 (As initially reported) Measurement Period Adjustment (1) February 9, 2018 (As adjusted) Estimated Fair Value of Assets Acquired (2) Cash, cash equivalents and short term restricted cash $ 10,345 $ — $ 10,345 Accounts receivable 101,745 — 101,745 Other receivables 1,222 — 1,222 Receivables due from related party 907 — 907 Prepaid expenses and other current assets 1,405 — 1,405 Derivative financial instruments 352 — 352 Property and equipment: (3) Oil and natural gas properties, successful efforts 2,314,858 (1,479 ) 2,313,379 Other property and equipment, net 43,318 — 43,318 Notes receivable due from related party 12,454 — 12,454 Deposits and other long-term assets 10,286 — 10,286 Total fair value of assets acquired 2,496,892 (1,479 ) 2,495,413 Estimated Fair Value of Liabilities Assumed (2) Accounts payable and accrued liabilities 210,867 (10,946 ) 199,921 Accounts payable — affiliate 5,476 — 5,476 Advances from non-operators 6,803 — 6,803 Advances from related party 47,506 — 47,506 Asset retirement obligations (3) 5,998 — 5,998 Derivative financial instruments 11,585 — 11,585 Long-term debt (4) 667,700 — 667,700 Other long-term liabilities 5,066 — 5,066 Total fair value of liabilities assumed 961,001 (10,946 ) 950,055 Total consideration and fair value $ 1,535,891 $ 9,467 $ 1,545,358 _________________ (1) The measurement period adjustments are recognized in the reporting period in which the adjustments were determined and calculated as if the accounting had been completed at the acquisition date. (2) The assets acquired and liabilities assumed relate to Alta Mesa’s STACK assets. (3) The estimated fair values of oil and natural gas properties and asset retirement obligations were determined using valuation techniques that convert future cash flows to a single discounted amount and involve the use of certain inputs that are not observable in the market (Level 3 inputs). Significant inputs include, but are not limited to recoverable reserves, production rates, future operating and development costs, future commodity prices, appropriate risk-adjusted discount rates and other relevant data. These inputs required significant judgments and estimates by management at the time of the valuation. Actual results may vary from these estimates. (4) Represents the approximate fair value as of the acquisition date of Alta Mesa’s $500.0 million aggregate principal amount of 7.875% senior unsecured notes due December 15, 2024 , totaling approximately $533.6 million , based on Level 1 inputs, and outstanding borrowings under the Eighth A&R credit facility (described in Note 11 — Long-Term Debt, Net ) of approximately $134.1 million as of the acquisition date.
SRII Opco, LP
Business Acquisition [Line Items]
Earn-out consideration	Additionally, for a period of seven years following the closing, the AM Contributor will be entitled to receive additional SRII Opco Common Units (and acquire a corresponding number of shares of AMR’s Class C Common Stock) as earn-out consideration if the 20 -day volume-weighted average price (“20-Day VWAP”) of the Class A Common Stock of AMR equals or exceeds the following prices (each such payment, an “Earn-Out Payment”): ໿ 20-Day VWAP Earn-Out Consideration $14.00 10,714,285 Common Units $16.00 9,375,000 Common Units $18.00 13,888,889 Common Units $20.00 12,500,000 Common Units

Property And Equipment (Tables)

Property And Equipment (Tables)	9 Months Ended
	Sep. 30, 2018
Property, Plant and Equipment [Abstract]
Summary of property and equipment	Property and equipment consisted of the following (in thousands):  Successor Predecessor  September 30, December 31, OIL AND NATURAL GAS PROPERTIES Unproved properties $ 865,695 $ 84,590 Accumulated impairment of unproved properties — — Unproved properties, net 865,695 84,590 Proved oil and natural gas properties 1,913,526 1,061,105 Accumulated depreciation, depletion, amortization and impairment (81,464 ) (251,065 ) Proved oil and natural gas properties, net 1,832,062 810,040 TOTAL OIL AND NATURAL GAS PROPERTIES, net 2,697,757 894,630 OTHER PROPERTY AND EQUIPMENT Land 5,059 2,912 Salt water disposal system 88,176 30,990 Office furniture and equipment and vehicles 2,325 20,008 Accumulated depreciation (1,604 ) (21,770 ) OTHER PROPERTY AND EQUIPMENT, net 93,956 32,140 TOTAL PROPERTY AND EQUIPMENT, net $ 2,791,713 $ 926,770

Discontinued Operations (Pred_2

Discontinued Operations (Predecessor) (Tables)	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
Schedule of discontinued operations	The assets and liabilities directly related to the non-STACK assets presented as discontinued operations in the condensed consolidated balance sheets were as follows (in thousands): ໿ Predecessor December 31, 2017 Assets associated with discontinued operations: Current assets Cash $ 61 Accounts receivable 4,980 Other receivables 154 Total current assets 5,195 Noncurrent assets Investments in LLC - Cost 9,000 Proved oil and natural gas properties, net 15,408 Unproved properties, net 15,504 Land 2,706 Other long-term assets 1,167 Total noncurrent assets 43,785 Total assets associated with discontinued operations $ 48,980  Liabilities associated with discontinued operations: Current liabilities Accounts payable and accrued liabilities $ 7,882 Asset retirement obligations 7,537 Total current liabilities 15,419 Noncurrent liabilities Asset retirement obligations, net of current 37,049 Founder notes 28,166 Other long-term liabilities 1,647 Total noncurrent liabilities 66,862 Total liabilities associated with discontinued operations $ 82,281 The operating results directly related to the non-STACK assets and liabilities presented as discontinued operations within the condensed consolidated financial statements were as follows (in thousands): ໿  Predecessor  Three Months Ended January 1, 2018 Through February 8, 2018 Nine Months Ended Operating revenues and other: Oil $ 10,994 $ 1,617 $ 36,122 Natural gas 2,376 1,023 7,964 Natural gas liquids 571 236 1,613 Other revenues 72 16 274 Total operating revenues 14,013 2,892 45,973 Loss on sale of assets — (1,923 ) — Gain on acquisition of oil and gas properties — — 1,626 Total operating revenues and other 14,013 969 47,599 Operating expenses: Lease operating expense 6,888 1,770 21,944 Marketing and transportation expense 352 83 1,080 Production taxes 1,443 167 5,100 Workover expense 273 127 1,981 Exploration expense 1,874 — 8,042 Depreciation, depletion and amortization 4,625 630 16,835 Impairment expense 82 5,560 28,018 Accretion expense 287 101 1,213 General and administrative expense 13 21 60 Total operating expenses 15,837 8,459 84,273 Other income (expense) Interest expense (305 ) (103 ) (904 ) Interest income and other 88 — 88 Total other income (expense) (217 ) (103 ) (816 ) Loss from discontinued operations, net of state income taxes $ (2,041 ) $ (7,593 ) $ (37,490 ) The total operating and investing cash flows of the non-STACK assets were as follows (in thousands): ໿  Predecessor  January 1, 2018 Through February 8, 2018 Nine Months Ended Total operating cash flows of discontinued operations $ (6,838 ) $ 16,166 Total investing cash flows of discontinued operations (570 ) (15,950 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Measurement of fair value of assets and liabilities on a recurring basis	The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2018 and December 31, 2017 , and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:  Level 1 Level 2 Level 3 Total  (in thousands) At September 30, 2018: (Successor) Financial Assets: Derivative contracts for oil and natural gas — $ 5,670 — $ 5,670 Financial Liabilities: Derivative contracts for oil and natural gas — $ 47,144 — $ 47,144 At December 31, 2017: (Predecessor) Financial Assets: Derivative contracts for oil and natural gas — $ 4,416 — $ 4,416 Financial Liabilities: Derivative contracts for oil and natural gas — $ 24,609 — $ 24,609

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative [Line Items]
Fair values of derivative contracts	Fair Values of Derivative Contracts: ໿  September 30, 2018 (Successor) 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) Derivative financial instruments, current assets $ 2,407 $ (2,407 ) $ — Derivative financial instruments, long-term assets 3,263 (3,263 ) — Total $ 5,670 $ (5,670 ) $ — ໿ 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) Derivative financial instruments, current liabilities $ 36,803 $ (2,407 ) $ 34,396 Derivative financial instruments, long-term liabilities 10,341 (3,263 ) 7,078 Total $ 47,144 $ (5,670 ) $ 41,474 ໿  December 31, 2017 (Predecessor) 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) Derivative financial instruments, current assets $ 1,406 $ (1,190 ) $ 216 Derivative financial instruments, long-term assets 3,010 (3,002 ) 8 Total $ 4,416 $ (4,192 ) $ 224 ໿ 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) Derivative financial instruments, current liabilities $ 20,493 $ (1,190 ) $ 19,303 Derivative financial instruments, long-term liabilities 4,116 (3,002 ) 1,114 Total $ 24,609 $ (4,192 ) $ 20,417
Effect of derivative instruments in the consolidated statements of operations	The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations (in thousands): ໿  Successor Predecessor Successor Predecessor Derivatives not Three Three February 9, 2018 January 1, 2018 Nine designated as hedging Months Ended Months Ended Through Through Months Ended instruments under ASC 815 September 30, 2018 September 30, 2017 September 30, 2018 February 8, 2018 September 30, 2017 Gain (loss) on derivative contracts Oil commodity contracts $ (12,339 ) $ (10,873 ) $ (63,630 ) $ 5,431 $ 31,665 Natural gas commodity contracts 1,127 1,035 553 1,867 6,763 Natural gas liquids commodity contracts — (630 ) — — (404 ) Total gain (loss) on derivative contracts $ (11,212 ) $ (10,468 ) $ (63,077 ) $ 7,298 $ 38,024
Oil derivative contracts
Derivative [Line Items]
Open derivative contracts	We had the following open derivative contracts for crude oil at September 30, 2018 : OIL DERIVATIVE CONTRACTS ໿ ໿  Volume in bbls Weighted Average Range Settlement Period and Type of Contract High Low 2018 Price Swap Contracts 552,000 $ 53.55 $ 61.26 $ 50.27 Collar Contracts Short Call Options 552,000 61.28 64.60 60.50 Long Put Options 552,000 51.67 60.00 50.00 Short Put Options 552,000 42.08 52.50 40.00 2019 Price Swap Contracts 182,500 63.03 63.03 63.03 Collar Contracts Short Call Options 2,701,000 66.31 75.20 56.50 Long Put Options 2,883,500 53.80 62.00 50.00 Short Put Options 2,883,500 42.72 52.00 37.50 2020 Collar Contracts Short Call Options 366,000 67.00 73.80 60.20 Long Put Options 1,317,600 56.46 62.50 50.00 Short Put Options 1,317,600 45.83 50.00 40.00
Natural gas derivative contracts
Derivative [Line Items]
Open derivative contracts	We had the following open derivative contracts for natural gas at September 30, 2018 : NATURAL GAS DERIVATIVE CONTRACTS ໿  Volume in MMBtu Weighted Average Range Settlement Period and Type of Contract High Low 2018 Price Swap Contracts 1,842,500 $ 2.95 $ 3.09 $ 2.75 Collar Contracts Short Call Options 1,832,500 3.36 3.75 3.14 Long Put Options 1,527,500 2.89 2.90 2.75 Short Put Options 610,000 2.40 2.40 2.40 2019 Price Swap Contracts 10,905,000 2.69 3.09 2.64 Collar Contracts Short Call Options 4,000,000 3.31 3.75 3.17 Long Put Options 3,550,000 2.81 2.90 2.70 Short Put Options 2,425,000 2.27 2.40 2.20 2020 Collar Contracts Short Call Options 2,275,000 3.19 3.20 3.17 Long Put Options 9,150,000 2.57 2.70 2.50 Short Put Options 9,150,000 2.07 2.20 2.00 2021 Collar Contracts Long Put Options 2,250,000 2.65 2.65 2.65 Short Put Options 2,250,000 2.15 2.15 2.15
Natural gas basis swap derivative contracts
Derivative [Line Items]
Basis swap contracts	We had the following open financial basis swaps at September 30, 2018 : NATURAL GAS BASIS SWAP DERIVATIVE CONTRACTS Volume in MMBtu (1) 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 ) 4,445,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Oct '18 — Dec '18 (0.63 ) 17,950,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '19 — Dec '19 (0.68 ) 910,000 Tex/OKL Panhandle Eastern Pipeline NYMEX Henry Hub Jan '20 — Mar '20 (0.49 ) 152,500 San Juan NYMEX Henry Hub Nov '18 — Dec '18 (0.47 ) 2,365,000 San Juan NYMEX Henry Hub Jan '19 — Oct '19 (0.78 ) _________________ (1) Represents short swaps that fix the basis differentials between OneOK, T ex/OKL Panhandle Eastern Pipeline (“PEPL”), San Juan and NYMEX Henry Hub.
Oil basis swap derivative contracts
Derivative [Line Items]
Basis swap contracts	OIL BASIS SWAP DERIVATIVE CONTRACTS ໿ Volume in bbl (1) Reference Price 1 (1) Reference Price 2 (1) Period Weighted Average Spread ($ per bbl) 552,000 CMA Oil WTI Oct '18 — Dec '18 $ (0.54 ) _________________ (1) Represents basis swaps for the basis differentials between NYMEX CMA (Calendar Monthly Average) Roll that reconcile the trade month versus the delivery month for physical contract pricing and West Texas Intermediate (“WTI”).

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation Disclosure [Abstract]
Summary of changes in asset retirement obligations	A summary of the changes in asset retirement obligations is included in the table below (in thousands): ໿  2018 Balance, as of January 1 (Predecessor) $ 10,469 Liabilities settled (63 ) Revisions to estimates 63 Accretion expense 39 Balance, as of February 8 (Predecessor) $ 10,508  Balance, as of February 9 (Successor) $ — Liabilities assumed from Business Combination 5,998 Liabilities incurred 1,689 Liabilities settled (1,249 ) Liabilities transferred in sale of properties (20 ) Revisions to estimates (1) 3,562 Accretion expense 489 Balance, as of September 30 (Successor) 10,469 Less: Current portion 1,300 Long-term portion $ 9,169 (1) The total revisions included $3.0 million related to additions to property, plant and equipment for the Successor Period.

Long Term Debt, Net (Tables)

Long Term Debt, Net (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long-term debt, net	Long-term debt, net consisted of the following (in thousands): ໿  Successor Predecessor  September 30, December 31, 2017 Senior secured revolving credit facility $ 80,000 $ 117,065 7.875% senior unsecured notes due 2024 500,000 500,000 Unamortized premium on senior unsecured notes 30,354 — Unamortized deferred financing costs — (9,625 ) Total long-term debt, net $ 610,354 $ 607,440

Accounts Payable And Accrued _2

Accounts Payable And Accrued Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Payables and Accruals [Abstract]
Details of accounts payable and accrued liabilities	The following provides the details of accounts payable and accrued liabilities (in thousands): ໿  Successor Predecessor  September 30, December 31, Accruals for capital expenditures $ 83,687 $ 48,771 Revenues and royalties payable 44,626 29,514 Accruals for operating expenses/taxes 8,156 14,632 Accrued interest 11,651 2,587 Derivative settlement payable 4,593 2,106 Other 3,408 4,301 Total accrued liabilities 156,121 101,911 Accounts payable 71,018 68,578 Accounts payable and accrued liabilities $ 227,139 $ 170,489

Equity Based Compensation (Su_2

Equity Based Compensation (Successor) (Tables)	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of stock option plans	Information about outstanding stock options is summarized in the table below: ໿  Successor  Stock Options Weighted Average Grant - Date Fair Value Weighted Average Remaining Term (in years) Aggregate Intrinsic Value (in thousands) Outstanding as of February 9, 2018 — $ — — Granted 4,704,433 4.45 — Exercised — — — Forfeited or expired (94,693 ) 4.52 — Outstanding as of September 30, 2018 4,609,740 $ 4.44 6.4 $ — Exercisable as of September 30, 2018 — $ — — $ —
Summary of stock options granted and valuation assumptions	The following summarizes the assumptions used to determine the fair value of those options: ໿ Successor  February 9, 2018 Through September 30, 2018 Expected term (in years) 4.5 Expected stock volatility 64.6 % Dividend yield — Risk-free interest rate 2.4 %
Schedule of restricted stock	The following table provides information about restricted stock awards granted during the Successor Period: ໿  Successor  Restricted Stock Awards Weighted Average Grant Date Fair Value per share Outstanding as of February 9, 2018 — $ — Granted 1,658,756 7.77 Vested — — Forfeited or expired (42,086 ) 8.74 Outstanding as of September 30, 2018 1,616,670 $ 7.75
Schedule of restricted stock units	The following summary provides information about the target number of PSUs granted during the Successor Period:  Successor  PSUs Weighted Average Grant - Date Fair Value per unit Outstanding as of February 9, 2018 — $ — Granted 781,200 8.69 Vested — — Forfeited or expired (4,174 ) 8.45 Outstanding as of September 30, 2018 777,026 — $ 8.69

Summary Of Significant Accoun_4

Summary Of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions	Sep. 30, 2018	Feb. 09, 2018
Summary Of Significant Accounting Policies [Line Items]
Fair value of senior notes payable	$ 476.3
7.875% Senior Unsecured Notes Due 2024
Summary Of Significant Accounting Policies [Line Items]
Face value of senior notes issued	$ 500
Fair value of senior notes payable		$ 533.6

Summary Of Significant Accoun_5

Summary Of Significant Accounting Policies (Reconciliation Of Cash, Cash Equivalents And Restricted Cash) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Feb. 08, 2018	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2016
Successor
Summary Of Significant Accounting Policies [Line Items]
Cash and cash equivalents	$ 8,869
Restricted cash	872
Total cash, cash equivalents and restricted cash	$ 9,741	$ 10,345
Predecessor
Summary Of Significant Accounting Policies [Line Items]
Cash and cash equivalents			$ 3,660
Restricted cash			1,269
Cash of discontinued operations			61
Total cash, cash equivalents and restricted cash		$ 10,345	$ 4,990	$ 4,913	$ 7,618

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	3 Months Ended		8 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Successor
Supplemental Cash Flow Information [Line Items]
Cash paid for interest				$ 22,073
Cash paid for state income taxes				7
Non-cash investing and financing activities:
Increase in asset retirement obligations				4,652
Asset retirement obligations assumed, purchased properties				0
Increase in accruals or payables for capital expenditures				35,967
Distribution of non-STACK (assets) net liability		$ 0		0
Increase in accounts receivable for sale of assets				$ (524)
Predecessor
Supplemental Cash Flow Information [Line Items]
Cash paid for interest	$ 1,145				$ 25,675
Non-cash investing and financing activities:
Increase in asset retirement obligations					3,778
Asset retirement obligations assumed, purchased properties					705
Increase in accruals or payables for capital expenditures	4,712				41,322
Distribution of non-STACK (assets) net liability	$ 33,102		$ 0		$ 0

Accounts Receivable (Schedule O

Accounts Receivable (Schedule Of Accounts Receivable ) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Successor
Oil, natural gas and natural gas liquids sales	$ 40,134
Joint interest billings	44,548
Pooling interest	23,367
Allowance for doubtful accounts	(65)
Total accounts receivable, net	$ 107,984
Predecessor
Oil, natural gas and natural gas liquids sales		$ 26,916
Joint interest billings		13,821
Pooling interest		35,839
Allowance for doubtful accounts		(415)
Total accounts receivable, net		$ 76,161

Business Combination (Narrative

Business Combination (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 09, 2018	Aug. 16, 2017	Sep. 30, 2018	Sep. 30, 2018
SRII Opco, LP
Business Acquisition [Line Items]
Redeemable period				7 years
SRII Opco, LP | Alta Mesa Holdings GP, LLC
Business Acquisition [Line Items]
Economic interests	100.00%
Voting interests	90.00%	90.00%
SRII Opco, LP | Kingfisher Midstream, LLC
Business Acquisition [Line Items]
Economic interests	100.00%
Alta Mesa Resources
Business Acquisition [Line Items]
Economic interests	100.00%
Redeemable period		7 years
Earn-out consideration, day for volume-weighted average price		20 days
Contributions from AMR	$ 560
AM Contributor
Business Acquisition [Line Items]
Common units (in shares)	138,402,398		1,197,934
AM Contributor | SRII Opco, LP
Business Acquisition [Line Items]
Common units (in shares)		138,402,398
Common Class C | AM Contributor | Alta Mesa Resources
Business Acquisition [Line Items]
Common stock par value (in dollars per share)	$ 0.0001

Business Combination (Earn-Out

Business Combination (Earn-Out Consideration) (Details) - SRII Opco, LP	Aug. 16, 2017$ / sharesshares
$14.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share) | $ / shares	$ 14
Earn-Out Consideration (in shares) | shares	10,714,285
$16.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share) | $ / shares	$ 16
Earn-Out Consideration (in shares) | shares	9,375,000
$18.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share) | $ / shares	$ 18
Earn-Out Consideration (in shares) | shares	13,888,889
$20.00 VWAP
Business Acquisition, Equity Interests Issued or Issuable [Line Items]
20-Day VWAP (in dollars per share) | $ / shares	$ 20
Earn-Out Consideration (in shares) | shares	12,500,000

Business Combination (Purchase

Business Combination (Purchase Consideration) (Details) - USD ($) $ / shares in Units, $ in Thousands	Feb. 09, 2018	Aug. 16, 2017	Sep. 30, 2018	Sep. 30, 2018
Alta Mesa Resources
Business Acquisition [Line Items]
Economic interests	100.00%
Redeemable period		7 years
SRII Opco, LP
Business Acquisition [Line Items]
SRII Opco Common Units issued	$ 1,261,249
Estimated fair value of contingent earn-out purchase consideration	284,109
Total purchase price consideration	$ 1,545,358
Redeemable period				7 years
Alta Mesa Holdings GP, LLC | SRII Opco, LP
Business Acquisition [Line Items]
Economic interests	100.00%
Voting interests	90.00%	90.00%
AM Contributor
Business Acquisition [Line Items]
Common units (in shares)	138,402,398		1,197,934
AM Contributor | SRII Opco, LP
Business Acquisition [Line Items]
Common units (in shares)		138,402,398
Riverstone Contributor Agreement
Business Acquisition [Line Items]
Common units (in shares)	20,000,000
Successor
Business Acquisition [Line Items]
Estimated fair value of contingent earn-out purchase consideration	$ 284,100
Successor | SRII Opco, LP
Business Acquisition [Line Items]
Common stock, price of saleable stocks (in dollars per share)	$ 7.90
As initially reported | SRII Opco, LP
Business Acquisition [Line Items]
SRII Opco Common Units issued	$ 1,251,782
Estimated fair value of contingent earn-out purchase consideration	284,109
Total purchase price consideration	1,535,891
Measurement Period Adjustment | SRII Opco, LP
Business Acquisition [Line Items]
SRII Opco Common Units issued	9,467
Total purchase price consideration	$ 9,467

Business Combination (Allocatio

Business Combination (Allocation Of Purchase Consideration) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Feb. 09, 2018
Business Acquisition [Line Items]
Cash, cash equivalents and short term restricted cash		$ 10,345
Accounts receivable		101,745
Other receivables		1,222
Receivables due from related party		907
Prepaid expenses and other current assets		1,405
Derivative financial instruments		352
Oil and natural gas properties, successful efforts		2,313,379
Other property and equipment, net		43,318
Notes receivable due from related party		12,454
Deposits and other long-term assets		10,286
Total fair value of assets acquired		2,495,413
Accounts payable and accrued liabilities		199,921
Accounts payable — affiliate		5,476
Advances from non-operators		6,803
Advances from related party		47,506
Asset retirement obligation		5,998
Derivative financial instruments		11,585
Long-term debt		667,700
Other long-term liabilities		5,066
Total fair value of liabilities assumed		950,055
Total consideration and fair value		1,545,358
Fair value of senior notes payable	$ 476,300
Senior secured revolving credit facility		134,100
7.875% Senior Unsecured Notes Due 2024
Business Acquisition [Line Items]
7.875% senior unsecured notes due 2024	$ 500,000
Stated interest rate of senior notes	7.875%
Fair value of senior notes payable		533,600
Successor
Business Acquisition [Line Items]
Asset retirement obligation		5,998
Successor | 7.875% Senior Unsecured Notes Due 2024
Business Acquisition [Line Items]
7.875% senior unsecured notes due 2024	$ 500,000
Successor | 7.875% Senior Unsecured Notes Due 2024 | Level 1
Business Acquisition [Line Items]
Fair value of senior notes payable		533,600
As initially reported
Business Acquisition [Line Items]
Cash, cash equivalents and short term restricted cash		10,345
Accounts receivable		101,745
Other receivables		1,222
Receivables due from related party		907
Prepaid expenses and other current assets		1,405
Derivative financial instruments		352
Oil and natural gas properties, successful efforts		2,314,858
Other property and equipment, net		43,318
Notes receivable due from related party		12,454
Deposits and other long-term assets		10,286
Total fair value of assets acquired		2,496,892
Accounts payable and accrued liabilities		210,867
Accounts payable — affiliate		5,476
Advances from non-operators		6,803
Advances from related party		47,506
Asset retirement obligation		5,998
Derivative financial instruments		11,585
Long-term debt		667,700
Other long-term liabilities		5,066
Total fair value of liabilities assumed		961,001
Total consideration and fair value		1,535,891
Measurement Period Adjustment
Business Acquisition [Line Items]
Cash, cash equivalents and short term restricted cash		0
Accounts receivable		0
Other receivables		0
Receivables due from related party		0
Prepaid expenses and other current assets		0
Derivative financial instruments		0
Oil and natural gas properties, successful efforts		(1,479)
Other property and equipment, net		0
Notes receivable due from related party		0
Deposits and other long-term assets		0
Total fair value of assets acquired		(1,479)
Accounts payable and accrued liabilities		(10,946)
Accounts payable — affiliate		0
Advances from non-operators		0
Advances from related party		0
Asset retirement obligation		0
Derivative financial instruments		0
Long-term debt		0
Other long-term liabilities		0
Total fair value of liabilities assumed		(10,946)
Total consideration and fair value		$ 9,467

Property And Equipment (Summary

Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Successor
Property, Plant and Equipment [Line Items]
Unproved properties	$ 865,695
Accumulated impairment of unproved properties	0
Unproved properties, net	865,695
Proved oil and natural gas properties	1,913,526
Accumulated depreciation, depletion, amortization and impairment	(81,464)
Proved oil and natural gas properties, net	1,832,062
TOTAL OIL AND NATURAL GAS PROPERTIES, net	2,697,757
Land	5,059
Salt water disposal system	88,176
Office furniture and equipment and vehicles	2,325
Accumulated depreciation	(1,604)
OTHER PROPERTY AND EQUIPMENT, net	93,956
Total property and equipment, net	$ 2,791,713
Predecessor
Property, Plant and Equipment [Line Items]
Unproved properties		$ 84,590
Accumulated impairment of unproved properties		0
Unproved properties, net		84,590
Proved oil and natural gas properties		1,061,105
Accumulated depreciation, depletion, amortization and impairment		(251,065)
Proved oil and natural gas properties, net		810,040
TOTAL OIL AND NATURAL GAS PROPERTIES, net		894,630
Land		2,912
Salt water disposal system		30,990
Office furniture and equipment and vehicles		20,008
Accumulated depreciation		(21,770)
OTHER PROPERTY AND EQUIPMENT, net		32,140
Total property and equipment, net		$ 926,770

Discontinued Operations (Pred_3

Discontinued Operations (Predecessor) (Narrative) (Details) - Predecessor - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2017	Sep. 30, 2017	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest on notes payable to founder	$ 103		$ 904
Notes payable to founder
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Effective rate of interest				10.00%
Notes payable to founder				$ 28,300
Interest on notes payable to founder	$ 100	$ 300	$ 900

Discontinued Operations (Pred_4

Discontinued Operations (Predecessor) (Schedule Of Assets And Liabilities Reclassified In Discontinued Operation) (Details) - Predecessor $ in Thousands	Dec. 31, 2017USD ($)
Current assets associated with discontinued operations:
Total current assets	$ 5,195
Noncurrent assets associated with discontinued operations:
Total noncurrent assets	43,785
Current liabilities associated with discontinued operations
Total current liabilities	15,419
Noncurrent liabilities associated with discontinued operations
Total noncurrent liabilities	66,862
Weeks Island Field, Louisiana | Non-STACK Assets | Discontinued Operations, Disposed of by Sale
Current assets associated with discontinued operations:
Cash	61
Accounts receivable	4,980
Other receivables	154
Total current assets	5,195
Noncurrent assets associated with discontinued operations:
Investments in LLC - Cost	9,000
Proved oil and natural gas properties, net	15,408
Unproved properties, net	15,504
Land	2,706
Other long-term assets	1,167
Total noncurrent assets	43,785
Total assets associated with discontinued operations	48,980
Current liabilities associated with discontinued operations
Accounts payable and accrued liabilities	7,882
Asset retirement obligations	7,537
Total current liabilities	15,419
Noncurrent liabilities associated with discontinued operations
Asset retirement obligations, net of current	37,049
Founder notes	28,166
Other long-term liabilities	1,647
Total noncurrent liabilities	66,862
Total liabilities associated with discontinued operations	$ 82,281

Discontinued Operations (Pred_5

Discontinued Operations (Predecessor) (Schedule Of Operations And Other Items Reclassified In Discontinued Operations) (Details) - Non-STACK Assets - Predecessor - Weeks Island Field, Louisiana - Discontinued Operations, Disposed of by Sale - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2017	Sep. 30, 2017
Operating revenue and other loss from discontinued operations
Oil	$ 1,617	$ 10,994	$ 36,122
Natural gas	1,023	2,376	7,964
Natural gas liquids	236	571	1,613
Other revenues	16	72	274
Total operating revenues	2,892	14,013	45,973
Loss on sale of assets	(1,923)	0	0
Gain on acquisition of oil and gas properties	0	0	1,626
Total operating revenues and other	969	14,013	47,599
Operating expenses from discontinued operations:
Lease operating expense	1,770	6,888	21,944
Marketing and transportation expense	83	352	1,080
Production taxes	167	1,443	5,100
Workover expense	127	273	1,981
Exploration expense	0	1,874	8,042
Depreciation, depletion and amortization	630	4,625	16,835
Impairment expense	5,560	82	28,018
Accretion expense	101	287	1,213
General and administrative expense	21	13	60
Total operating expenses	8,459	15,837	84,273
Interest expense	(103)	(305)	(904)
Interest income and other	0	88	88
Total other income (expense)	(103)	(217)	(816)
Loss from discontinued operations, net of state income taxes	$ (7,593)	$ (2,041)	$ (37,490)

Discontinued Operations (Pred_6

Discontinued Operations (Predecessor) (Total Operating And Investing Cash Flows Of Discontinued Operations) (Details) - Non-STACK Assets - Predecessor - Weeks Island Field, Louisiana - Discontinued Operations, Disposed of by Sale - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total operating cash flows of discontinued operations	$ (6,838)	$ 16,166
Total investing cash flows of discontinued operations	$ (570)	$ (15,950)

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		8 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Feb. 09, 2018	Dec. 31, 2017
Fair Value Disclosures [Line Items]
Fair value of senior notes payable		$ 476,300		$ 476,300
Predecessor
Fair Value Disclosures [Line Items]
Carrying value of oil and gas properties					$ 3,300
Written down fair value of oil and gas properties					2,100
Impairment charges to oil and gas properties	$ 0		$ 0		1,188
Asset retirement obligation measured at fair value	$ 0				$ 1,000
Successor
Fair Value Disclosures [Line Items]
Impairment charges to oil and gas properties		0		0
Asset retirement obligation measured at fair value				1,700
7.875% Senior Unsecured Notes Due 2024
Fair Value Disclosures [Line Items]
7.875% senior unsecured notes due 2024		500,000		500,000
Fair value of senior notes payable						$ 533,600
7.875% Senior Unsecured Notes Due 2024 | Predecessor
Fair Value Disclosures [Line Items]
7.875% senior unsecured notes due 2024							$ 500,000
7.875% Senior Unsecured Notes Due 2024 | Successor
Fair Value Disclosures [Line Items]
7.875% senior unsecured notes due 2024		$ 500,000		$ 500,000

Fair Value Measurements (Measu

Fair Value Measurements (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Successor
Financial Assets:
Derivative contracts for oil and natural gas	$ 5,670
Financial Liabilities:
Derivative contracts for oil and natural gas	47,144
Successor | Level 1
Financial Assets:
Derivative contracts for oil and natural gas	0
Financial Liabilities:
Derivative contracts for oil and natural gas	0
Successor | Level 2
Financial Assets:
Derivative contracts for oil and natural gas	5,670
Financial Liabilities:
Derivative contracts for oil and natural gas	47,144
Successor | Level 3
Financial Assets:
Derivative contracts for oil and natural gas	0
Financial Liabilities:
Derivative contracts for oil and natural gas	$ 0
Predecessor
Financial Assets:
Derivative contracts for oil and natural gas		$ 4,416
Financial Liabilities:
Derivative contracts for oil and natural gas		24,609
Predecessor | Level 1
Financial Assets:
Derivative contracts for oil and natural gas		0
Financial Liabilities:
Derivative contracts for oil and natural gas		0
Predecessor | Level 2
Financial Assets:
Derivative contracts for oil and natural gas		4,416
Financial Liabilities:
Derivative contracts for oil and natural gas		24,609
Predecessor | Level 3
Financial Assets:
Derivative contracts for oil and natural gas		0
Financial Liabilities:
Derivative contracts for oil and natural gas		$ 0

Derivative Financial Instrume_3

Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Successor
Derivatives, Fair Value [Line Items]
Gross fair value of assets	$ 5,670
Gross liabilities offset against assets in the Balance Sheet	(5,670)
Net fair value of assets presented in the Balance Sheet	0
Gross fair value of liabilities	47,144
Gross assets offset against liabilities in the Balance Sheet	(5,670)
Net fair value of liabilities presented in the Balance Sheet	41,474
Successor | Derivative financial instruments, current assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	2,407
Gross liabilities offset against assets in the Balance Sheet	(2,407)
Net fair value of assets presented in the Balance Sheet	0
Successor | Derivative financial instruments, long-term assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets	3,263
Gross liabilities offset against assets in the Balance Sheet	(3,263)
Net fair value of assets presented in the Balance Sheet	0
Successor | Derivative financial instruments, current liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	36,803
Gross assets offset against liabilities in the Balance Sheet	(2,407)
Net fair value of liabilities presented in the Balance Sheet	34,396
Successor | Derivative financial instruments, long-term liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities	10,341
Gross assets offset against liabilities in the Balance Sheet	(3,263)
Net fair value of liabilities presented in the Balance Sheet	$ 7,078
Predecessor
Derivatives, Fair Value [Line Items]
Gross fair value of assets		$ 4,416
Gross liabilities offset against assets in the Balance Sheet		(4,192)
Net fair value of assets presented in the Balance Sheet		224
Gross fair value of liabilities		24,609
Gross assets offset against liabilities in the Balance Sheet		(4,192)
Net fair value of liabilities presented in the Balance Sheet		20,417
Predecessor | Derivative financial instruments, current assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets		1,406
Gross liabilities offset against assets in the Balance Sheet		(1,190)
Net fair value of assets presented in the Balance Sheet		216
Predecessor | Derivative financial instruments, long-term assets
Derivatives, Fair Value [Line Items]
Gross fair value of assets		3,010
Gross liabilities offset against assets in the Balance Sheet		(3,002)
Net fair value of assets presented in the Balance Sheet		8
Predecessor | Derivative financial instruments, current liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities		20,493
Gross assets offset against liabilities in the Balance Sheet		(1,190)
Net fair value of liabilities presented in the Balance Sheet		19,303
Predecessor | Derivative financial instruments, long-term liabilities
Derivatives, Fair Value [Line Items]
Gross fair value of liabilities		4,116
Gross assets offset against liabilities in the Balance Sheet		(3,002)
Net fair value of liabilities presented in the Balance Sheet		$ 1,114

Derivative Financial Instrume_4

Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		8 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Successor
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts		$ (11,212)		$ (63,077)
Successor | Derivatives not designated as hedging instruments under ASC 815 | Oil commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts		(12,339)		(63,630)
Successor | Derivatives not designated as hedging instruments under ASC 815 | Natural gas commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts		1,127		553
Successor | Derivatives not designated as hedging instruments under ASC 815 | Natural gas liquids commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts		$ 0		$ 0
Predecessor
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts	$ 7,298		$ (10,468)		$ 38,024
Predecessor | Derivatives not designated as hedging instruments under ASC 815 | Oil commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts	5,431		(10,873)		31,665
Predecessor | Derivatives not designated as hedging instruments under ASC 815 | Natural gas commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts	1,867		1,035		6,763
Predecessor | Derivatives not designated as hedging instruments under ASC 815 | Natural gas liquids commodity contracts
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts	$ 0		$ (630)		$ (404)

Derivative Financial Instrume_5

Derivative Financial Instruments (Oil Derivative Contracts) (Details) - Oil derivative contracts	9 Months Ended
	Sep. 30, 2018$ / bblbbl
Price Swap Contracts | 2018
Derivative [Line Items]
Volume in bbls | bbl	552,000
Weighted average swap price	53.55
Price Swap Contracts | 2018 | High
Derivative [Line Items]
Swap price	61.26
Price Swap Contracts | 2018 | Low
Derivative [Line Items]
Swap price	50.27
Price Swap Contracts | 2019
Derivative [Line Items]
Volume in bbls | bbl	182,500
Weighted average swap price	63.03
Price Swap Contracts | 2019 | High
Derivative [Line Items]
Swap price	63.03
Price Swap Contracts | 2019 | Low
Derivative [Line Items]
Swap price	63.03
Short Call Options | 2018
Derivative [Line Items]
Volume in bbls | bbl	552,000
Weighted average option price	61.28
Short Call Options | 2018 | High
Derivative [Line Items]
Option price	64.60
Short Call Options | 2018 | Low
Derivative [Line Items]
Option price	60.50
Short Call Options | 2019
Derivative [Line Items]
Volume in bbls | bbl	2,701,000
Weighted average option price	66.31
Short Call Options | 2019 | High
Derivative [Line Items]
Option price	75.20
Short Call Options | 2019 | Low
Derivative [Line Items]
Option price	56.50
Short Call Options | 2020
Derivative [Line Items]
Volume in bbls | bbl	366,000
Weighted average option price	67
Short Call Options | 2020 | High
Derivative [Line Items]
Option price	73.80
Short Call Options | 2020 | Low
Derivative [Line Items]
Option price	60.20
Long Put Options | 2018
Derivative [Line Items]
Volume in bbls | bbl	552,000
Weighted average option price	51.67
Long Put Options | 2018 | High
Derivative [Line Items]
Option price	60
Long Put Options | 2018 | Low
Derivative [Line Items]
Option price	50
Long Put Options | 2019
Derivative [Line Items]
Volume in bbls | bbl	2,883,500
Weighted average option price	53.80
Long Put Options | 2019 | High
Derivative [Line Items]
Option price	62
Long Put Options | 2019 | Low
Derivative [Line Items]
Option price	50
Long Put Options | 2020
Derivative [Line Items]
Volume in bbls | bbl	1,317,600
Weighted average option price	56.46
Long Put Options | 2020 | High
Derivative [Line Items]
Option price	62.50
Long Put Options | 2020 | Low
Derivative [Line Items]
Option price	50
Short Put Options | 2018
Derivative [Line Items]
Volume in bbls | bbl	552,000
Weighted average option price	42.08
Short Put Options | 2018 | High
Derivative [Line Items]
Option price	52.50
Short Put Options | 2018 | Low
Derivative [Line Items]
Option price	40
Short Put Options | 2019
Derivative [Line Items]
Volume in bbls | bbl	2,883,500
Weighted average option price	42.72
Short Put Options | 2019 | High
Derivative [Line Items]
Option price	52
Short Put Options | 2019 | Low
Derivative [Line Items]
Option price	37.50
Short Put Options | 2020
Derivative [Line Items]
Volume in bbls | bbl	1,317,600
Weighted average option price	45.83
Short Put Options | 2020 | High
Derivative [Line Items]
Option price	50
Short Put Options | 2020 | Low
Derivative [Line Items]
Option price	40

Derivative Financial Instrume_6

Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) - Natural gas	9 Months Ended
	Sep. 30, 2018MMBTU$ / MMBTU
2018 | Price Swap Contracts
Derivative [Line Items]
Volume in MMBtu | MMBTU	1,842,500
Weighted average swap price	2.95
2018 | Price Swap Contracts | High
Derivative [Line Items]
Swap price	3.09
2018 | Price Swap Contracts | Low
Derivative [Line Items]
Swap price	2.75
2018 | Short Call Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	1,832,500
Weighted average option price	3.36
2018 | Short Call Options | High
Derivative [Line Items]
Option price	3.75
2018 | Short Call Options | Low
Derivative [Line Items]
Option price	3.14
2018 | Long Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	1,527,500
Weighted average option price	2.89
2018 | Long Put Options | High
Derivative [Line Items]
Option price	2.90
2018 | Long Put Options | Low
Derivative [Line Items]
Option price	2.75
2018 | Short Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	610,000
Weighted average option price	2.40
2018 | Short Put Options | High
Derivative [Line Items]
Option price	2.40
2018 | Short Put Options | Low
Derivative [Line Items]
Option price	2.40
2019 | Price Swap Contracts
Derivative [Line Items]
Volume in MMBtu | MMBTU	10,905,000
Weighted average swap price	2.69
2019 | Price Swap Contracts | High
Derivative [Line Items]
Swap price	3.09
2019 | Price Swap Contracts | Low
Derivative [Line Items]
Swap price	2.64
2019 | Short Call Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	4,000,000
Weighted average option price	3.31
2019 | Short Call Options | High
Derivative [Line Items]
Option price	3.75
2019 | Short Call Options | Low
Derivative [Line Items]
Option price	3.17
2019 | Long Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	3,550,000
Weighted average option price	2.81
2019 | Long Put Options | High
Derivative [Line Items]
Option price	2.90
2019 | Long Put Options | Low
Derivative [Line Items]
Option price	2.70
2019 | Short Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	2,425,000
Weighted average option price	2.27
2019 | Short Put Options | High
Derivative [Line Items]
Option price	2.40
2019 | Short Put Options | Low
Derivative [Line Items]
Option price	2.20
2020 | Short Call Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	2,275,000
Weighted average option price	3.19
2020 | Short Call Options | High
Derivative [Line Items]
Option price	3.20
2020 | Short Call Options | Low
Derivative [Line Items]
Option price	3.17
2020 | Long Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	9,150,000
Weighted average option price	2.57
2020 | Long Put Options | High
Derivative [Line Items]
Option price	2.70
2020 | Long Put Options | Low
Derivative [Line Items]
Option price	2.50
2020 | Short Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	9,150,000
Weighted average option price	2.07
2020 | Short Put Options | High
Derivative [Line Items]
Option price	2.20
2020 | Short Put Options | Low
Derivative [Line Items]
Option price	2
2021 | Long Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	2,250,000
Weighted average option price	2.65
2021 | Long Put Options | High
Derivative [Line Items]
Option price	2.65
2021 | Long Put Options | Low
Derivative [Line Items]
Option price	2.65
2021 | Short Put Options
Derivative [Line Items]
Volume in MMBtu | MMBTU	2,250,000
Weighted average option price	2.15
2021 | Short Put Options | High
Derivative [Line Items]
Option price	2.15
2021 | Short Put Options | Low
Derivative [Line Items]
Option price	2.15

Derivative Financial Instrume_7

Derivative Financial Instruments (Natural Gas Basis Swap Derivative Contracts) (Details) - Natural gas basis swap derivative contracts	9 Months Ended
	Sep. 30, 2018MMBTU$ / MMBTU
Jul 2019 to Dec 2019
Derivative [Line Items]
Volume in MMBtu | MMBTU	460,000
Weighted average spread ($/MMBtu) | $ / MMBTU	(0.93)
Oct 2018 to Dec 2018
Derivative [Line Items]
Volume in MMBtu | MMBTU	4,445,000
Weighted average spread ($/MMBtu) | $ / MMBTU	(0.63)
Jan 2019 to Dec 2019
Derivative [Line Items]
Volume in MMBtu | MMBTU	17,950,000
Weighted average spread ($/MMBtu) | $ / MMBTU	(0.68)
Jan 2020 to Mar 2020
Derivative [Line Items]
Volume in MMBtu | MMBTU	910,000
Weighted average spread ($/MMBtu) | $ / MMBTU	(0.49)
Nov 2018 to Dec 2018
Derivative [Line Items]
Volume in MMBtu | MMBTU	152,500
Weighted average spread ($/MMBtu) | $ / MMBTU	(0.47)
Jan 2019 to Oct 2019
Derivative [Line Items]
Volume in MMBtu | MMBTU	2,365,000
Weighted average spread ($/MMBtu) | $ / MMBTU	(0.78)

Derivative Financial Instrume_8

Derivative Financial Instruments (Oil Basis Swap Derivative Contracts) (Details) - Oil basis swap derivative contracts - Oct 2018 to Dec 2018	9 Months Ended
	Sep. 30, 2018$ / bblbbl
Derivative [Line Items]
Volume in bbls | bbl	552,000
Weighted average spread ($/MMBtu) | $ / bbl	(0.54)

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended		8 Months Ended	9 Months Ended
	Feb. 08, 2018	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Feb. 09, 2018	Dec. 31, 2017
Asset Retirement Obligation [Line Items]
Liabilities assumed from Business Combination						$ 5,998
Predecessor
Asset Retirement Obligation [Line Items]
Balance, beginning of period	$ 10,469
Liabilities settled	(63)
Revisions to estimates	63
Accretion expense	39		$ 108		$ 234
Balance, end of period	$ 10,469					10,508	$ 10,469
Less: Current portion							69
Long-term portion							$ 10,400
Successor
Asset Retirement Obligation [Line Items]
Liabilities assumed from Business Combination						5,998
Liabilities incurred				$ 1,689
Liabilities settled				(1,249)
Liabilities transferred in sale of properties				(20)
Revisions to estimates				3,562
Accretion expense		$ 226		489
Balance, end of period		10,469		10,469		$ 0
Less: Current portion		1,300		1,300
Long-term portion		$ 9,169		9,169
Revisions related to property, plant and equipment				$ 3,000

Long Term Debt, Net (Schedule o

Long Term Debt, Net (Schedule of Long-Term Debt, Net) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Feb. 09, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Senior secured revolving credit facility		$ 134,100
7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Stated interest rate of senior notes	7.875%
7.875% senior unsecured notes due 2024	$ 500,000
Successor
Debt Instrument [Line Items]
Total long-term debt, net	610,354
Successor | Eighth Amended And Restated Credit Agreement
Debt Instrument [Line Items]
Senior secured revolving credit facility	80,000
Successor | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
7.875% senior unsecured notes due 2024	500,000
Unamortized deferred financing costs	0
Successor | Senior Unsecured Notes
Debt Instrument [Line Items]
Unamortized premium on senior unsecured notes	$ 30,354
Predecessor
Debt Instrument [Line Items]
Total long-term debt, net			$ 607,440
Predecessor | 7th Amended And Restated Credit Agreement
Debt Instrument [Line Items]
Senior secured revolving credit facility			117,065
Predecessor | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
7.875% senior unsecured notes due 2024			500,000
Unamortized deferred financing costs			(9,625)
Predecessor | Senior Unsecured Notes
Debt Instrument [Line Items]
Unamortized premium on senior unsecured notes			$ 0

Long Term Debt, Net (Narrative)

Long Term Debt, Net (Narrative) (Details)	1 Months Ended	3 Months Ended		8 Months Ended	9 Months Ended		12 Months Ended
	Feb. 08, 2018USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Apr. 30, 2018USD ($)	Feb. 09, 2018USD ($)
Debt Instrument [Line Items]
Senior secured revolving credit facility									$ 134,100,000
Period following closing additional borrowings can be made					120 days
Default amount		$ 20,000,000		$ 20,000,000	$ 20,000,000
Fair value of senior notes payable		476,300,000		476,300,000	476,300,000
Bond premium amortization				3,300,000
7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Senior secured revolving credit facility		$ 500,000,000		$ 500,000,000	$ 500,000,000
Stated interest rate of senior notes		7.875%		7.875%	7.875%
Redemption percentage of aggregate remaining outstanding					65.00%
Fair value of senior notes payable									533,600,000
7.875% Senior Unsecured Notes Due 2024 | Prior to December 15, 2019
Debt Instrument [Line Items]
Redemption price					107.875%
Redemption price plus make-whole premium					100.00%
7.875% Senior Unsecured Notes Due 2024 | Twelve Mos Beginning December 15, 2019
Debt Instrument [Line Items]
Redemption price					105.906%
7.875% Senior Unsecured Notes Due 2024 | Twelve Mos Beginning December 15, 2020
Debt Instrument [Line Items]
Redemption price					103.938%
7.875% Senior Unsecured Notes Due 2024 | Twelve Mos Beginning December 15, 2021
Debt Instrument [Line Items]
Redemption price					101.969%
7.875% Senior Unsecured Notes Due 2024 | Twelve Mos Beginning December 15, 2022
Debt Instrument [Line Items]
Redemption price					100.00%
Maximum | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Redemption percentage of Senior Notes					35.00%
Eighth A&R Credit Facility
Debt Instrument [Line Items]
Debt issuance costs		$ 1,400,000		$ 1,400,000	$ 1,400,000
Successor
Debt Instrument [Line Items]
Bond premium amortization		1,200,000		(3,281,000)
Amortization of deferred financing costs		100,000		151,000
Successor | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Senior secured revolving credit facility		500,000,000		500,000,000	500,000,000
Deferred financing costs, net		0		0	0
Successor | Eighth A&R Credit Facility
Debt Instrument [Line Items]
Credit facility amount									1,000,000,000
Credit facility borrowing base								$ 400,000,000
Senior secured revolving credit facility		80,000,000		80,000,000	80,000,000
Letter of credit outstanding		21,900,000		21,900,000	21,900,000
Total borrowing capacity remaining available for future use		$ 298,100,000		$ 298,100,000	$ 298,100,000
Maximum leverage ratio					4
Successor | Eighth A&R Credit Facility | Maximum
Debt Instrument [Line Items]
Credit facility borrowing base									350,000,000
Predecessor
Debt Instrument [Line Items]
Bond premium amortization	$ 0					$ 0
Deferred financing cost write-off							$ 11,400,000
Amortization of deferred financing costs	$ 171,000		$ 700,000			$ 2,205,000
Predecessor | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Margin interest rate					0.50%
Predecessor | 7th Amended And Restated Credit Agreement
Debt Instrument [Line Items]
Senior secured revolving credit facility							117,065,000
Predecessor | Credit Facility And Senior Notes [Member]
Debt Instrument [Line Items]
Deferred financing costs, net									0
Predecessor | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Senior secured revolving credit facility							500,000,000
Deferred financing costs, net							$ 9,625,000
Predecessor | Eighth A&R Credit Facility
Debt Instrument [Line Items]
Minimum current ratio		1		1	1
Predecessor | Eighth A&R Credit Facility | Eurodollar
Debt Instrument [Line Items]
Margin interest rate					1.00%
Predecessor | Eighth A&R Credit Facility | Minimum | Eurodollar
Debt Instrument [Line Items]
Margin interest rate					2.00%
Predecessor | Eighth A&R Credit Facility | Minimum | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Margin interest rate					1.00%
Predecessor | Eighth A&R Credit Facility | Maximum | Eurodollar
Debt Instrument [Line Items]
Margin interest rate					3.00%
Predecessor | Eighth A&R Credit Facility | Maximum | Federal Funds Effective Swap Rate
Debt Instrument [Line Items]
Margin interest rate					2.00%
Level 1 | Successor | 7.875% Senior Unsecured Notes Due 2024
Debt Instrument [Line Items]
Fair value of senior notes payable									533,600,000
Senior Notes
Debt Instrument [Line Items]
Redemption price due to specific change of control events					101.00%
Senior Notes | Successor
Debt Instrument [Line Items]
Bond premium									$ 33,600,000

Accounts Payable And Accrued _3

Accounts Payable And Accrued Liabilities (Detail Of Accounts Payable And Accrued Liabilities) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Successor
Accounts Payable And Accrued Liabilities [Line Items]
Accruals for capital expenditures	$ 83,687
Revenues and royalties payable	44,626
Accruals for operating expenses/taxes	8,156
Accrued interest	11,651
Derivative settlement payable	4,593
Other	3,408
Total accrued liabilities	156,121
Accounts payable	71,018
Accounts payable and accrued liabilities	$ 227,139
Predecessor
Accounts Payable And Accrued Liabilities [Line Items]
Accruals for capital expenditures		$ 48,771
Revenues and royalties payable		29,514
Accruals for operating expenses/taxes		14,632
Accrued interest		2,587
Derivative settlement payable		2,106
Other		4,301
Total accrued liabilities		101,911
Accounts payable		68,578
Accounts payable and accrued liabilities		$ 170,489

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($) $ in Thousands	Apr. 01, 2018	Feb. 09, 2018	Jan. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Commitment And Contingencies [Line Items]
Additional lease commitment obligations	$ 17,600
Firm transportation contract				$ 5,700
Litigation
Commitment And Contingencies [Line Items]
Accounts payable and accrued liabilities					$ 4,700
Payment for legal fees			$ 4,700
Predecessor
Commitment And Contingencies [Line Items]
Accounts payable and accrued liabilities					$ 170,489
PAR value vested		$ 10,900
Successor
Commitment And Contingencies [Line Items]
Accounts payable and accrued liabilities				227,139
Nonqualified deferred compensation				$ 9,400

Partners' Capital (Narrative) (

Partners' Capital (Narrative) (Details) - SRII Opco, LP	Sep. 30, 2018	Feb. 09, 2018	Aug. 16, 2017
Alta Mesa Holdings GP, LLC
Partners' Capital l[Line Items]
Economic interests		100.00%
Voting interests		90.00%	90.00%
Common Class A | Alta Mesa Holdings GP, LLC
Partners' Capital l[Line Items]
Economic interests	100.00%
Common Class B
Partners' Capital l[Line Items]
Percentage of ownership	90.00%
Common Class B | Alta Mesa Holdings GP, LLC
Partners' Capital l[Line Items]
Voting interests	100.00%
Harlan H. Chappelle, Micheal Ellis, and Other Affiliates | Common Class B
Partners' Capital l[Line Items]
Percentage of ownership	10.00%

Equity Based Compensation (Su_3

Equity Based Compensation (Successor) (Narrative) (Details) $ in Thousands	8 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)shares	Sep. 30, 2018USD ($)shares	Sep. 30, 2018USD ($)shares
Vested during first year | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			33.33%
Vested during first year | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			33.33%
Vesting during second year | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			33.33%
Vesting during second year | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			33.33%
Vesting during third year | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			33.33%
Vesting during third year | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			33.33%
Successor
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity-based compensation expense		$ 6,714
Unrecognized compensation cost related to non-vested stock options	$ 16,200	16,200	$ 16,200
Options granted (in shares) | shares	4,704,433
Successor | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Period for unrecognized compensation cost			2 years 5 months 1 day
Successor | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Period for unrecognized compensation cost			2 years 6 months 7 days
Unrecognized compensation cost	$ 10,100	10,100	$ 10,100
Successor | Performance Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Successor | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to non-vested stock options	$ 0	$ 0	$ 0
Successor | Long Term Incentive Plan | Alta Mesa Resources | Common Class A
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance (in shares) | shares	50,000,000	50,000,000	50,000,000
Successor | Long Term Incentive Plan | Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expiration period			7 years
Successor | Long Term Incentive Plan | Vested during first year | Performance Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			20.00%
Successor | Long Term Incentive Plan | Vesting during second year | Performance Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			30.00%
Successor | Long Term Incentive Plan | Vesting during third year | Performance Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested percentage			50.00%
Successor | Long Term Incentive Plan | Minimum | Performance Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned			0.00%
Successor | Long Term Incentive Plan | Maximum | Performance Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of shares that may be earned			200.00%

Equity Based Compensation (Su_4

Equity Based Compensation (Successor) (Schedule Of Stock Option Plans) (Details) - Successor $ / shares in Units, $ in Thousands	8 Months Ended
	Sep. 30, 2018USD ($)$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Options - Outstanding, beginning balance (in shares)	0
Options - Granted (in shares)	4,704,433
Options - Exercised (in shares)	0
Options - Forfeited or expired (in shares)	(94,693)
Options - Outstanding, ending balance (in shares)	4,609,740
Options - Exercisable (in shares)	0
Weighted Average Exercise Price - Beginning balance (in dollars per share) | $ / shares	$ 0
Weighted Average Exercise Price Per Share - Granted (in dollars per share) | $ / shares	4.45
Weighted Average Exercise Price - Exercised (in dollars per share) | $ / shares	0
Weighted Average Exercise Price - Forfeited or expired (in dollars per share) | $ / shares	4.52
Weighted Average Exercise Price - Ending balance (in dollars per share) | $ / shares	$ 4.44
Weighted Average Remaining Term - Outstanding	6 years 5 months 12 days
Aggregate Intrinsic Value - Outstanding | $	$ 0

Equity Based Compensation (Su_5

Equity Based Compensation (Successor) (Summary Of Stock Options Granted And Valuation Assumptions) (Details) - Successor	8 Months Ended
	Sep. 30, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	4 years 6 months
Expected stock volatility	64.60%
Dividend yield	0.00%
Risk-free interest rate	2.40%

Equity Based Compensation (Su_6

Equity Based Compensation (Successor) (Schedule Of Restricted Stock) (Details) - Successor - Restricted Stock	8 Months Ended
	Sep. 30, 2018$ / sharesshares
Restricted Stock Awards
Awards - Outstanding, beginning balance (in shares) | shares	0
Awards - Granted (in shares) | shares	1,658,756
Awards - Vested (in shares) | shares	0
Awards - Forfeited or expired (in shares) | shares	(42,086)
Awards - Outstanding, ending balance (in shares) | shares	1,616,670
Weighted Average Grant Date Fair Value per share
Weighted Average Grant-Date Fair Value - Outstanding, beginning balance (in dollars per share) | $ / shares	$ 0
Weighted Average Grant-Date Fair Value - Granted (in dollars per share) | $ / shares	7.77
Weighted Average Grant-Date Fair Value - Vested (in dollars per share) | $ / shares	0
Weighted Average Grant-Date Fair Value - Forfeited or expired (in dollars per share) | $ / shares	8.74
Weighted-Average Grant-Date Fair Value - Outstanding ending balance (in dollars per share) | $ / shares	$ 7.75

Equity Based Compensation (Su_7

Equity Based Compensation (Successor) (Schedule Of Restricted Stock Units) (Details) - Successor - Restricted Stock Units (RSUs)	8 Months Ended
	Sep. 30, 2018$ / sharesshares
PSUs
Awards - Outstanding, beginning balance (in shares) | shares	0
Awards - Granted (in shares) | shares	781,200
Awards - Vested (in shares) | shares	0
Awards - Forfeited or expired (in shares) | shares	(4,174)
Awards - Outstanding, ending balance (in shares) | shares	777,026
Weighted Average Grant - Date Fair Value per unit
Weighted Average Grant-Date Fair Value - Outstanding, beginning balance (in dollars per share) | $ / shares	$ 0
Weighted Average Grant-Date Fair Value - Granted (in dollars per share) | $ / shares	8.69
Weighted Average Grant-Date Fair Value - Vested (in dollars per share) | $ / shares	0
Weighted Average Grant-Date Fair Value - Forfeited or expired (in dollars per share) | $ / shares	8.45
Weighted-Average Grant-Date Fair Value - Outstanding ending balance (in dollars per share) | $ / shares	$ 8.69

Related Party Transactions (Det

Related Party Transactions (Details) $ in Thousands	4 Months Ended	12 Months Ended
	Sep. 30, 2018USD ($)well	Dec. 31, 2016USD ($)	Feb. 08, 2018USD ($)	Dec. 31, 2017USD ($)	Jan. 13, 2016well
BCE-STACK
Related Party Transaction [Line Items]
Advances from related party			$ 39,500
Marketing fees
Related Party Transaction [Line Items]
Marketing fees paid	$ 800
Successor
Related Party Transaction [Line Items]
Advances from related party	$ 16,917
Predecessor
Related Party Transaction [Line Items]
Advances from related party				$ 23,390
AEM | AM Contributor
Related Party Transaction [Line Items]
Ownership percentage	10.00%
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
Percent of interest reduced		12.50%
Percent of internal rate of return		25.00%
Joint Development Agreement | BCE-STACK
Related Party Transaction [Line Items]
Percent committed to fund working interest		100.00%
Percent of interest sold		80.00%
Percent of interest reduced		20.00%
Percent of internal rate of return		15.00%
Number of wells drilled | well	55
Joint Development Agreement | Maximum | BCE-STACK
Related Party Transaction [Line Items]
Drilling and completion costs		$ 3,200

Subsequent Events (Details)

Subsequent Events (Details) $ in Millions	Nov. 09, 2018USD ($)well	Sep. 30, 2018USD ($)
Subsequent Event [Line Items]
Long-lived assets		$ 86.9
Affiliated Entity | Midstream | Subsequent Event
Subsequent Event [Line Items]
Number of produced water disposal wells sold | well	20
Proceeds from sale of produced water assets	$ 90