Alta Mesa 10-Q 18 Aug 17 2017 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	6 Months Ended
	Jun. 30, 2017shares
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	Jun. 30, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 5,279	$ 7,185
Short-term restricted cash	805	433
Accounts receivable, net of allowance of $774 and $889, respectively	49,089	37,611
Other receivables	3,780	8,061
Receivables due from affiliate	1,688	8,883
Prepaid expenses and other current assets	1,899	3,986
Derivative financial instruments	15,002	83
Total current assets	77,542	66,242
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	822,498	712,162
Other property and equipment, net	9,690	9,731
Total property and equipment, net	832,188	721,893
OTHER ASSETS
Investment in LLC - cost	9,000	9,000
Deferred financing costs, net	2,299	3,029
Notes receivable due from affiliate	10,393	9,987
Deposits and other long-term assets	16,707	2,977
Derivative financial instruments	8,873	723
Total other assets	47,272	25,716
TOTAL ASSETS	957,002	813,851
CURRENT LIABILITIES
Accounts payable and accrued liabilities	130,225	84,234
Advances from non-operators	3,165	4,058
Advances from related party		42,528
Asset retirement obligations	1,006	376
Derivative financial instruments		21,207
Total current liabilities	134,396	152,403
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	60,663	61,128
Long-term debt, net	685,526	529,905
Notes payable to founder	27,556	26,957
Derivative financial instruments		4,482
Other long-term liabilities	7,154	6,870
Total long-term liabilities	780,899	629,342
TOTAL LIABILITIES	915,295	781,745
Commitments and Contingencies (Note 11)
PARTNERS' CAPITAL	41,707	32,106
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 957,002	$ 813,851

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Condensed Consolidated Balance Sheets [Abstract]
Allowance for doubtful accounts	$ 774	$ 889

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
OPERATING REVENUES AND OTHER
Oil	$ 55,071	$ 43,843	$ 114,416	$ 75,087
Natural gas	13,136	5,796	25,821	10,487
Natural gas liquids	7,076	4,010	14,695	6,115
Other revenues	86	174	202	301
Total operating revenues	75,369	53,823	155,134	91,990
Gain on sale of assets		1,083		3,731
Gain on acquisition of oil and natural gas properties	1,626		1,626
Gain (loss) on derivative contracts	18,250	(38,293)	48,492	(27,478)
Total operating revenues and other	95,245	16,613	205,252	68,243
OPERATING EXPENSES
Lease and plant operating expense	16,597	13,452	34,333	30,577
Marketing and transportation expense	6,857	1,472	12,900	2,887
Production and ad valorem taxes	3,039	2,731	6,107	5,126
Workover expense	2,015	1,118	3,398	2,515
Exploration expense	6,265	3,428	14,407	6,714
Depreciation, depletion, and amortization expense	26,494	22,931	51,298	44,424
Impairment expense	27,904	11,555	29,124	13,319
Accretion expense	480	536	1,052	1,075
General and administrative expense	8,328	12,076	18,076	22,259
Total operating expenses	97,979	69,299	170,695	128,896
INCOME (LOSS) FROM OPERATIONS	(2,734)	(52,686)	34,557	(60,653)
OTHER INCOME (EXPENSE)
Interest expense	(12,879)	(17,672)	(25,219)	(34,067)
Interest income	299	227	548	433
Total other income (expense)	(12,580)	(17,445)	(24,671)	(33,634)
INCOME (LOSS) BEFORE STATE INCOME TAXES	(15,314)	(70,131)	9,886	(94,287)
Provision for state income taxes		106	285	107
NET INCOME (LOSS)	$ (15,314)	$ (70,237)	$ 9,601	$ (94,394)

Condensed Consolidated Stateme5

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 9,601	$ (94,394)
Adjustments to reconcile net (income) loss to net cash used in operating activities:
Depreciation, depletion, and amortization expense	51,298	44,424
Impairment expense	29,124	13,319
Accretion expense	1,052	1,075
Amortization of deferred financing costs	1,456	1,965
Amortization of debt discount		255
Dry hole expense	888	215
Expired leases	5,922	2,435
(Gain) loss on derivative contracts	(48,492)	27,478
Settlements of derivative contracts	254	65,991
Premium paid on derivative contracts	(520)
Interest converted into debt	599	600
Interest on notes receivable due from affiliates	(406)	(378)
Gain on sale of assets		(3,731)
Gain on acquisition of oil and natural gas properties	(1,626)
Changes in assets and liabilities:
Restricted cash	(372)	(121,935)
Accounts receivable	(11,478)	(6,927)
Other receivables	4,281	14,377
Receivables due from affiliate	(680)	(1,615)
Prepaid expenses and other non-current assets	(11,644)	(3,951)
Advances from related party	(42,528)
Settlement of asset retirement obligation	(977)	(741)
Accounts payable, accrued liabilities, and other liabilities	7,655	14,619
NET CASH USED IN OPERATING ACTIVITIES	(6,593)	(46,919)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(151,832)	(94,997)
Acquisitions	(6,251)
Proceeds from sale of property		1,358
NET CASH USED IN INVESTING ACTIVITIES	(158,083)	(93,639)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	165,065	141,935
Repayments of long-term debt	(10,000)
Additions to deferred financing costs	(170)	(799)
Capital contributions	7,875
NET CASH PROVIDED BY FINANCING ACTIVITIES	162,770	141,136
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1,906)	578
CASH AND CASH EQUIVALENTS, beginning of period	7,185	8,869
CASH AND CASH EQUIVALENTS, end of period	$ 5,279	$ 9,447

Description Of Business

Description Of Business	6 Months Ended
	Jun. 30, 2017
Description Of Business [Abstract]
Description Of Business	1. DESCRIPTION OF BUSINESS Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company engaged primarily in the acquisition, exploration, develop ment, and production of oil and natural gas properties . Our principal area of operation is in the eastern portion of the Anadarko Basin commonly referred to as the STACK. The STACK is an acronym describing both its location – Sooner Trend Anadarko Basin Canadian and Kingfisher County – and the multiple, stacked productive formations present in the area. Our operations also include other non-STACK oil and natural gas interests within the continental United States. 

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2017
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2. 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, 2016 (the “2016 Annual Report”). As of June 30, 2017 , our significant accounting policies are consistent with those discussed in Note 2 in the 2016 Annual Report. Principles of Consolidation and Reporting The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. 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, 2016 , which were filed with the Securities and Exchange Commission (the “SEC”) in our 2016 Annual Report. The condensed consolidated financial statements included herein as of June 30, 2017 , and for the three and six months ended June 30, 2017 and 2016 , 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 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. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year. 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. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, state taxes, and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates. Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09 (“ASU 2014-09”), Revenue from Contracts with Customers . The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are in the process of assessing our contracts and evaluating the impact on the condensed 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 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 (with the exception of 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. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. We continue to evaluate the impacts of the amendments to our financial statements and accounting practices for leases. Although we are still in the process of evaluating the effect of adopting ASU 2016 ‑02, the adoption is expected to result in an increase in the assets and liabilities recorded on our condensed consolidated balance sheet. We anticipate adoption of ASU 2016-02 effective January 1, 2019.  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 beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our condensed consolidated statements of cash flows.  In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash (“ASU 2016-18”), which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.  In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended
	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	3 . SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:     Six Months Ended June 30,  2017 2016   (in thousands)  Supplemental cash flow information:  Cash paid for interest $ 23,452 $ 31,071  Cash paid for state income taxes — 422  Non-cash investing and financing activities:  Change in asset retirement obligations 235 577  Asset retirement obligations assumed, purchased properties 89 —  Change in accruals or liabilities for capital expenditures 37,494 (4,869) 

Acquisitions

Acquisitions	6 Months Ended
	Jun. 30, 2017
Acquisition [Abstract]
Acquisitions	4. ACQUISITIONS  During the second quarter of 2017, we entered into a purchase and sale agreement with an unaffiliated third party to acquire certain oil and natural gas properties in Oklahoma. The acquired oil and natural gas prope rties were primarily unproved leasehold in Oklahoma. We made a deposit concurrently with the execution of the purchase and sale agreement of approximately $4.6 million, which is recorded in oil and natural gas properties on our condensed consolidated balance sheet as of June 30, 2017. On July 7, 2017, we closed and funded the remaining purchase price of the acquisition for approximately $40.4 million, net of customary post-closing adjustments, with borrowings under our senior secured revolving credit facility.  In April 2017, we completed an acquisition of certain non-STACK proved oil and natural gas properties from Setanta Energy, LLC (“Setanta”) for a purchase price, net of customary purchase price adjustments, of approximately $0.9 million. We funded the acquisition with borrowings under our senior secured revolving credit facility. This purchase increases our working interest in various wells in which we already hold an interest. The acquisition was accounted for using the acquisition method under ASC 805, “Business Combinations,” which requires acquired assets and liabilities to be recorded at fair value as of the acquisition date.  A summary of the consideration paid and the allocation of the total purchase price to the assets acquired and the liabilities assumed in the Setanta acquisition based on the preliminary fair value at the acquisition date are as follows:    (in thousands)  Summary of Consideration  Cash $ 890  Total consideration paid 890   Summary of Purchase Price Allocation  Plus: fair value of liabilities assumed  Asset retirement obligations assumed 89  Total fair value liabilities assumed 89  Less: fair value of assets acquired  Proved oil and natural gas properties 2,605  Unproved oil and natural gas properties —  Total fair value assets acquired 2,605   Bargain Purchase Gain $ (1,626)  The fair value of the net assets acquired was approximately $2.6 million. As the fair value of the net assets acquired exceeded the total consideration paid, we recorded a bargain purchase gain of approximately $1.6 million. The bargain purchase gain is reflected in gain on acquisition of oil and natural gas properties on our condensed consolidated statement of operations.  In accordance with ASC 805, the following unaudited pro forma results of operations for the six months ended June 30, 2017 and 2016 have been prepared to give effect to the Setanta acquisition on our condensed consolidated results of operations as if it had occurred on January 1, 2016. Therefore, the bargain purchase gain on acquisition of $1.6 million has been included in pro forma income (loss) for the six months ended June 30, 2016. The difference between the historical results of operations and the unaudited pro forma results of operations for the three months ended June 30, 2017 and 2016 was determined to be de minimus and therefore not provided.      Total Operating Income  Revenues (Loss)   (in thousands)   Pro forma results of operations for the six months ended June 30, 2017 $ 155,474 $ 8,016  Pro forma results of operations for the six months ended June 30, 2016 $ 92,033 $ (92,864)  This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during this period.  On December 31, 2016, our Class B partner, High Mesa, Inc. (“High Mesa”) purchased from BCE-STACK Development LLC (“ BCE”) and contributed interests in 24 producing wells (the “Contributed Wells”) drilled under the joint development agreement to us. The Company accounted for the Contributed Wells as a business combination in the prior year and the results of operations from the acquisition is reflected in the consolidated statement of operations for the three and six months ended June 30, 2017. The difference between the historical results of operations and the unaudited pro forma results of operations for the three and six months ended June 30, 2016 was determined to be de minimus and therefore not provided.

Property And Equipment

Property And Equipment	6 Months Ended
	Jun. 30, 2017
Property And Equipment [Abstract]
Property And Equipment	5. PROPERTY AND EQUIPMENT  Property and equipment consists of the following:    June 30, December 31,  2017 2016   (in thousands)  OIL AND NATURAL GAS PROPERTIES  Unproved properties $ 102,922 $ 116,311  Accumulated impairment of unproved properties (18,893) (65)  Unproved properties, net 84,029 116,246  Proved oil and natural gas properties 1,814,057 1,611,249  Accumulated depreciation, depletion, amortization and impairment (1,075,588) (1,015,333)  Proved oil and natural gas properties, net 738,469 595,916  TOTAL OIL AND NATURAL GAS PROPERTIES, net 822,498 712,162  OTHER PROPERTY AND EQUIPMENT  Land 5,339 4,730  Office furniture and equipment, vehicles 20,135 19,446  Accumulated depreciation (15,784) (14,445)  OTHER PROPERTY AND EQUIPMENT, net 9,690 9,731  TOTAL PROPERTY AND EQUIPMENT, net $ 832,188 $ 721,893  

Fair Value Disclosures

Fair Value Disclosures	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Disclosures	6. FAIR VALUE DISCLOSURES The Company follows ASC 820, “Fair Value Measurements and Disclosures.” ASC 820 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. The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. Our senior notes are carried at historical cost, and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $507.5 million at June 30, 2017 . This estimation is based on the most recent trading values of the senior notes at or near the reporting dates, which is a Level 1 determination. See Note 9 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 New York Mercantile Exchange (“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 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. Oil and natural gas properties with a carrying amount of $36.2 million were written down to their fair value of $7.1 million, resulting in an impairment charge of $29.1 million for the six months ended June 30, 2017 . For the six months ended June 30, 2016 , oil and natural gas properties with a carrying amount of $27.5 million were written down to their fair value of $14.2 million, resulting in an impairment charge of $13.3 million. Oil and natural gas properties with a carrying amount of $32.8 million were written down to their fair value of $4.9 million, resulting in an impairment charge of $27.9 million for the three months ended June 30, 2017 . For the three months ended June 30, 2016 , oil and natural gas properties with a carrying amount of $24.2 million were written down to their fair value of $12.6 million, resulting in an impairment charge of $11.6 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 properties, and fair values for them are categorized as Level 3. Such estimations 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. We recorded $0.7 million and $0.6 million in additions to asset retirement obligations me asured at fair value during the six months ended June 30, 2017 and 2016, respectively. The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of June 30, 2017 and December 31, 2016, 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 June 30, 2017:  Financial Assets:  Commodity derivative contracts — $ 36,073 — $ 36,073  Financial Liabilities:  Commodity derivative contracts — $ 12,198 — $ 12,198  At December 31, 2016:  Financial Assets:  Commodity derivative contracts — $ 15,773 — $ 15,773  Financial Liabilities:  Commodity derivative contracts — $ 40,656 — $ 40,656 The amounts above are presented on a gross basis. Presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place. For additional information on derivative contracts, see Note 7.

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended
	Jun. 30, 2017
Derivative Financial Instruments [Abstract]
Derivative Financial Instruments	7. DERIVATIVE FINANCIAL INSTRUMENTS We account for our derivative contracts under the provisions of ASC 815, “Derivatives and Hedging.” 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 hedging agreements are executed by affiliates of our lenders under the senior secured revolving credit facility described in Note 9, 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 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 to volumes in gallons (Gal) per month . The 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. 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:     June 30, 2017  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 19,405 $ (4,403) $ 15,002  Derivative financial instruments, long-term assets 16,668 (7,795) 8,873  Total $ 36,073 $ (12,198) $ 23,875      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 4,403 $ (4,403) $ —  Derivative financial instruments, long-term liabilities 7,795 (7,795) —  Total $ 12,198 $ (12,198) $ —      December 31, 2016  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 3,296 $ (3,213) $ 83  Derivative financial instruments, long-term assets 12,477 (11,754) 723  Total $ 15,773 $ (14,967) $ 806      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 24,420 $ (3,213) $ 21,207  Derivative financial instruments, long-term liabilities 16,236 (11,754) 4,482  Total $ 40,656 $ (14,967) $ 25,689  The following table summarizes the effect of our derivative instruments in the condensed consolidated statements of operations:      Derivatives not Three Months Ended Six Months Ended  designated as hedging June 30, June 30,  instruments under ASC 815 2017 2016 2017 2016   (in thousands)  Gain (loss) on derivative contracts  Oil commodity contracts $ 16,451 $ (31,517) $ 42,537 $ (23,371)   Natural gas commodity contracts 1,830 (6,584) 5,728 (3,770)   Natural gas liquids commodity contracts (31) (192) 227 (337)  Total gain (loss) on derivative contracts $ 18,250 $ (38,293) $ 48,492 $ (27,478)  Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow us, so long as we are not a defaulting party, after a default or the occurrence of a termination event, 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. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted. We had the following open derivative contracts for crude oil at June 30, 2017 :  OIL DERIVATIVE CONTRACTS       Volume Weighted Range  Period and Type of Contract in Bbls Average High Low  2017  Price Swap Contracts 1,133,500 $ 50.39 $ 57.25 $ 46.00  Collar Contracts  Long Call Options 92,000 85.00 85.00 85.00  Short Call Options 989,000 60.47 85.00 54.40  Long Put Options 835,000 48.40 50.00 47.00  Short Put Options 713,000 36.97 40.00 35.00  2018  Price Swap Contracts 547,500 57.22 57.25 57.20  Collar Contracts  Long Call Options 365,000 54.00 54.00 54.00  Short Call Options 2,190,000 60.87 62.00 60.50  Long Put Options 1,825,000 50.00 50.00 50.00  Short Put Options 2,190,000 40.26 42.00 40.00  2019  Collar Contracts  Short Call Options 1,241,000 62.90 63.00 62.75  Long Put Options 1,241,000 50.00 50.00 50.00  Short Put Options 1,241,000 37.50 37.50 37.50    We had the following open derivative contracts for natural gas at June 30, 2017 :  NATURAL GAS DERIVATIVE CONTRACTS      Volume in Weighted Range  Period and Type of Contract MMBtu Average High Low  2017  Price Swap Contracts 922,500 $ 3.40 $ 3.40 $ 3.39  Collar Contracts  Short Call Options 6,072,000 3.65 4.11 3.25  Long Put Options 5,304,500 3.14 3.60 3.00  Long Call Options 615,000 2.95 2.95 2.95  Short Put Options 5,919,500 2.59 3.00 2.50  2018  Collar Contracts  Short Call Options 6,582,000 5.26 5.53 4.00  Long Put Options 5,925,000 4.43 4.50 3.60  Short Put Options 5,925,000 3.92 4.00 3.00  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 or Brent ICE indices or may reflect a mix of positions settling on various of these benchmarks. We had the following open derivative contracts for natural gas liquids at June 30, 2017 :  NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS    Volume Weighted Range  Period and Type of Contract in Gal Average High Low  2017  Price Swap Contracts  Short Price Swaps 3,091,200 $ 0.47 $ 0.47 $ 0.47  We had the following open financial basis swaps at June 30, 2017 :  BASIS SWAP DERIVATIVE CONTRACTS      Weighted  Average Spread  Volume in MMBtu (1) Reference Price 1 Reference Price 2 Period ($ per MMBtu)  6,135,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Jul'17 — Dec '17 $ (0.25)  5,910,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Jan '18 — Oct '18 (0.27)   (1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) Inside FERC (“IFERC”) and NYMEX Henry Hub. 

Asset Retirement Obligations

Asset Retirement Obligations	6 Months Ended
	Jun. 30, 2017
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	8. ASSET RETIREMENT OBLIGATIONS A summary of the changes in asset retirement obligations is included in the table below:    Six  Months Ended  June 30, 2017  (in thousands)  Balance, beginning of year $ 61,504  Liabilities incurred 584  Liabilities assumed with acquired producing properties 89  Liabilities settled (977)  Revisions to estimates (583)  Accretion expense 1,052  Balance, June 30, 2017 61,669  Less: Current portion 1,006  Long-term portion $ 60,663  The total revisions to estimates include approximately $0.3 million related to reduction to oil and natural gas properties for the six months ended June 30, 2017. 

Long Term Debt, Net And Notes P

Long Term Debt, Net And Notes Payable To Founder	6 Months Ended
	Jun. 30, 2017
Long Term Debt, Net And Notes Payable To Founder [Abstract]
Long Term Debt, Net And Notes Payable To Founder	9. LONG-TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER Long-term debt, net and notes payable to founder consists of the following:     June 30, December 31,  2017 2016   (in thousands)  Senior secured revolving credit facility $ 195,687 $ 40,622  7.875% senior unsecured notes due 2024 500,000 500,000  Unamortized deferred financing costs (10,161) (10,717)  Total long-term debt, net $ 685,526 $ 529,905  Notes payable to founder $ 27,556 $ 26,957  Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. On June 13, 2017, we entered into an Agreement and Amendment No. 2 (the “Second Amendment”) to the credit facility which, among other things: (a) increased our borrowing base from $287.5 million to $315.0 million until the next scheduled redetermination and (b) permits us to make a one -time cash distribution of no more than $1.0 million to a limited partner. As of June 30, 2017 , we had $195.7 million outstanding with $114.0 million of available borrowing capacity under the credit facility. The letters of credit outstanding as of June 30, 2017 and December 31, 2016 were approximately $ 5.3 million and $7.6 million, respectively. The borrowing base is currently $315.0 million and is redetermined semi-annually in May and November of each year. The principal amount is payable on the maturity date of November 10, 2020 .  The credit facility is secured by substantially all of our oil and natural gas properties and is based on our proved reserves and the value attributed to those reserves. We have a choice of borrowing in Eurodollars or at the “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, National Association. The credit facility bears interest at the London Interbank Offered Rate (“LIBOR”) plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00. The Reference Rate loans bear interest at a rate per annum equal to the greatest of (i) the agent bank’s Reference Rate, (ii) the federal funds effective rate plus 50 basis points and (iii) the rate for one month Eurodollar loans plus 1% , plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00. The weighted average and effective interest rate on outstanding borrowings was 5.90% as of June 30, 2017 and 4.00% as of December 31, 2016.  The credit facility 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, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect. The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses (“EBITDAX”) over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.  As of June 30, 2017 , we were in compliance with all financial covenants of the cred it facility. Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (the “senior notes”) due December 15, 2024 which were issued at par by the Company and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. 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 in an amount of cash not greater than the net cash proceeds from certain equity offerings at the 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 (the “indenture”)) 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 purchase. As of June 30, 2017, we were in compliance with the indentures governing the senior notes. Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $27.6 million and $27.0 million at June 30, 2017 and December 31, 2016, respectively. The maturity date was extended on March 25, 2014 from December 31, 2018 to December 31, 2021 . Interest and principal are payable at maturity. Our founder shall convert t he notes into shares of common stock of High Mesa upon certain conditions, in the event of a liquidity event as defined Note 13. These Founder Notes are unsecured and subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner, the Founder Notes were amended and restated to subordinate them to the paid in kind (“PIK”) notes of our Class B partner. The Founder Notes were also subordinated to the rights of the holders of Class B units to receive distributions under our partnership agreement and subordinated to the rights of the holders of certain equity interests to receive payments. Interest on the Founder Notes amounted to $0.6 million for each of the six months ended June 30, 2017 and 2016 and $0.3 million for each of the three months ended June 30, 2017 and 2016 . Such amounts have been added to the balance of the Founder Notes. Deferred financing costs. As of June 30, 2017 , we had $12.5 million of deferred financing costs related to the credit facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.2 million related to the senior notes are netted with long-term debt on the condensed consolidated balance sheet as of June 30, 2017 . Deferred financing costs of $2.3 million related to the credit facility are included in deferred financing costs, net on the condensed consolidated balance sheets at June 30, 2017 . Amortization of deferred financing costs re corded for the six months ended June 30, 2017 and 2016 was $1.5 million and $2.0 million, respectively. Amortization of deferred financing costs recorded for each of the three months ended June 30, 2017 and 2016 was $0.5 million and $1.0 million, respectively. The amortization of these costs are included in interest expense on the condensed consolidated statements of operations. The credit facility and the senior notes contain customary events of default. 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.

Accounts Payable And Accrued Li

Accounts Payable And Accrued Liabilities	6 Months Ended
	Jun. 30, 2017
Accounts Payable And Accrued Liabilities [Abstract]
Accounts Payable And Accrued Liabilities	10. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES The following provides the details of accounts payable and accrued liabilities:      June 30, December 31,  2017 2016   (in thousands)  Capital expenditures $ 57,268 $ 15,155  Revenues and royalties payable 20,559 12,187  Operating expenses/taxes 18,193 17,499  Interest 2,334 2,627  Compensation 3,208 5,302  Derivative settlement payable 208 1,126  Other 631 1,164  Total accrued liabilities 102,401 55,060  Accounts payable 27,824 29,174  Accounts payable and accrued liabilities $ 130,225 $ 84,234 

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended
	Jun. 30, 2017
Commitments And Contingencies [Abstract]
Commitments And Contingencies	11. COMMITMENTS AND CONTINGENCIES 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 June 30, 2017 . 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 : On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, The Meridian Resource Corporation (“TMRC,” our wholly-owned 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. As of June 30, 2017 , we have accrued approximately $3.2 million ( $0.8 million in current liabilities and $2.4 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable. The settlement requires payment over the term of six years. On January 25, 2017, Bollenbach Enterprises Limited Partnership filed a class action petition in Kingfisher County, Oklahoma against Oklahoma Energy Acquisitions, LP, our wholly-owned subsidiary (“OEA”), Alta Mesa Services, LP, our wholly-owned subsidiary (“AMS”), and the Company (collectively, the “AMH Parties”) claiming royalty underpayment or non-payment of royalty. The suit against the AMH Parties alleges that the AMH Parties made improper 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. Class settlement requires approval of the court after certain lengthy notice periods. We believe losses are probable in connection with this litigation; however, we have not accrued a loss contingency because we are currently unable to reasonably estimate an amount or range of loss. Other contingencies : We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business for which the outcome 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 is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted performance appreciation rights (“PARs”) with a stipulated initial designated value (“SIDV”). The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the SIDV and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During the first six months of 2017, we granted 308,800 new PARs with a SIDV of $40 and terminated 500 PARs with a SIDV of $40 , resulting in 88 4,200 PARs issued at a weighted average of $37.9 1 as of June 30, 2017 . We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our condensed consolidated financial statements at June 30, 2017 or December 31, 2016.

Significant Risks And Uncertain

Significant Risks And Uncertainties	6 Months Ended
	Jun. 30, 2017
Significant Risks And Uncertainties [Abstract]
Significant Risks And Uncertainties	12. SIGNIFICANT RISKS AND UNCERTAINTIES Our business makes us vulnerable to changes in wellhead prices of crude 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. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014 . Although oil and natural gas prices have recently begun to recover from lows experienced since such decline, forecasted prices for both oil and natural gas continue to remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further price declines 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. Sustained low oil or natural gas prices may require us to write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. 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 7. 

Partners' Capital

Partners' Capital	6 Months Ended
	Jun. 30, 2017
Partners' Capital [Abstract]
Partners' Capital	13. PARTNERS’ CAPITAL Management and Control : Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in our partnership agreement. Our partnership agreement provides for two classes of limited partners. Class A partners include our founder and other parties. Our sole Class B partner is High Mesa. The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture. In connection with the sale of Series E preferred stock by our Class B partner on February 24, 2017, our General Partner, High Mesa and all of our Class A limited partners entered into a Fifth Amended and Restated Limited Partnership Agreement, and the owners of the General Partner entered into a Fourth Amended and Restated Limited Liability Company Agreement to provide for the Series E preferred stock in the distribution formula and certain other provisions of the amended agreements. Contribution, Distribution and Income Allocation : All distributions under the partnership agreement shall first be made to holders of Class B units, until certain provisions are met. After such provisions are met, distributions shall then be made to holders of Class A and Class B units pursuant to the distribution formulas set forth in the partnership agreement. The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes. Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.  On December 31, 2016, High Mesa purchased from BCE and contributed interest in 24 producing wells drilled under the joint development agreement to us. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected d uring the first quarter of 2017. There were no contributions during the first half of 2016. 

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended
	Jun. 30, 2017
Subsidiary Guarantors [Abstract]
Subsidiary Guarantors	14. SUBSIDIARY GUARANTORS All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our condensed consolidated financial statements reflect the financial position of these subsidiary guarantors. The parent company, Alta Mesa Holdings, LP, has 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 and are not guarantors and are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to the parent company.

Subsequent Event

Subsequent Event	6 Months Ended
	Jun. 30, 2017
Subsequent Event [Abstract]
Subsequent Event	1 5 . SUBSEQUENT EVENT Alta Mesa Contribution Agreement. On August 16, 2017, we entered into a Contribution Agreement (the “Contribution Agreement”) with Silver Run Acquisition Corporation II , a Delaware corporation (“SRII”), High Mesa Holdings, LP , a Delaware limited partnership (the “AM Contributor”), High Mesa Holdings GP, LLC, a Texas limited liability company, our General Partner and solely for certain provisions therein, the equity owners of AM Contributor. Pursuant to the Contribution Agreement, SRII will acquire from the AM Contributor (i) all of its limited partner i nterest in the Company and (ii) 100% of the economic interests and 90% of the voting interests in our General Partner. In return, the AM Contributor will receive: (i) 220,000,000 common units as adjusted of SRII Opco, LP , a Delaware limited partnership and wholly owned subsidiary of SRII ; (ii) $400 million in cash, which shall be contributed to us; and (iii) up to $800 million in earn-out consideration in the form of common units of SRII Opco, LP (the “Earn-out Consideration”). The Earn-out Consideration will be paid as set forth below if the 20 -day volume-weighted average price (“VWAP”) of the Class A Common Stock of SRII (the “Class A Common Stock”) equals or exceeds the following prices:     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 Additionally, the AM Contributor will purchase non-economic capital stock of SRII, dedicated as Class C Common Stock (“Class C Common Stock”). The common units of SRII Opco, LP and corresponding Class C Common Stock are redeemable for Class A Common Stock beginning 180 days after the closing.  The Contribution Agreement contains customary representations and warranties and pre-closing covenants, with the representations and warranties not survive the closing. Additionally, we have agreed to transfer to the AM Contributor prior to closing all assets and liabilities related to the non-STACK assets. The closing of the Contribution Agreement is subject to (i) the approval of the SRII stockholders, (ii) the simultaneous closing of the contribution agreement by and among SRII, KFM Holdco, LLC, Kingfisher Midstream, LLC, a Delaware limited liability company (“Kingfisher”) and the equity owners party thereto pursuant to which SRII will acquire 100% of the outstanding membership interests in Kingfisher, (iii) a SRII Opco, LP leverage ratio of less than 1.5x , (iv) certain regulatory approvals and (v) the satisfaction or waiver of other customary closing conditions. The Contribution Agreement also contains certain customary termination rights, including if the transaction is not consummated by February 28, 2018.  Sixth Amended and Restated Agreement of Limited Partnership. On August 16, 2017, our General Partner, the AM Contributor and Riverstone VI Alta Mesa Holdings, L.P. , a Delaware limited partnership ( the “RS Contributor”) entered into a Sixth Amended and Restated Agreement of Limited Partnership (the “Amended Partnership Agreement”). The Amended Partnership Agreement reflects, among other things, certain changes in the ownership of the Company, and provides for certain preemptive rights, tag-along rights, and drag-along rights for the limited partners. In connection with Amended Partnership Agreement, the existing limited partners of the Company transferred their interests in the Company to the AM Contributor. The Amended Partnership Agreement also reflects the admission of the RS Contributor and the AM Contributor to the Company as limited partners, and provides for certain distribution rights for the Class A and Class B Limited Partners (as defined therein) with respect to the STACK and non-STACK assets.  The RS Contributor was admitted as a limited partner in connection with its $200 million capital contribution to us on August 17, 2017 , in exchange for limited partner interests in Alta Mesa. We used all of the capital contribution to pay down our senior secured revolving credit facility.  Fifth Amended and Restated Limited Liability Company Agreement. On August 16, 2017, the owners of our General Partner entered into a Fifth Amended and Restated Limited Liability Company Agreement, which was amended to, among other things, show certain changes in the ownership of our General Partner and reflect that the holders of Class A Units (as defin ed therein) are entitled to 100% of the economic rights with respect to our General Partner and the holders of Class B Units (as defined therein) are entitled to 100% of the voting rights with respect to our General Partner.  

Summary Of Significant Accoun21

Summary Of Significant Accounting Policies (Policy)	6 Months Ended
	Jun. 30, 2017
Summary Of Significant Accounting Policies [Abstract]
Principles Of Consolidation And Reporting	Principles of Consolidation and Reporting The condensed consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. 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, 2016 , which were filed with the Securities and Exchange Commission (the “SEC”) in our 2016 Annual Report. The condensed consolidated financial statements included herein as of June 30, 2017 , and for the three and six months ended June 30, 2017 and 2016 , 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 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. Certain reclassifications of prior period condensed consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.
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. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, state taxes, and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09 (“ASU 2014-09”), Revenue from Contracts with Customers . The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We are in the process of assessing our contracts and evaluating the impact on the condensed 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 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 (with the exception of 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. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. We enter into lease agreements to support our operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. We continue to evaluate the impacts of the amendments to our financial statements and accounting practices for leases. Although we are still in the process of evaluating the effect of adopting ASU 2016 ‑02, the adoption is expected to result in an increase in the assets and liabilities recorded on our condensed consolidated balance sheet. We anticipate adoption of ASU 2016-02 effective January 1, 2019.  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 beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact our financial position or results of operations but could result in presentation changes on our condensed consolidated statements of cash flows.  In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash (“ASU 2016-18”), which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.  In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. We are currently evaluating the effect that adopting this guidance will have on our financial position, cash flows and results of operations.

Fair Value Disclosures (Policy)

Fair Value Disclosures (Policy)	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements And Disclosures	The Company follows ASC 820, “Fair Value Measurements and Disclosures.” ASC 820 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. The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. Our senior notes are carried at historical cost, and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $507.5 million at June 30, 2017 . This estimation is based on the most recent trading values of the senior notes at or near the reporting dates, which is a Level 1 determination. See Note 9 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 New York Mercantile Exchange (“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 fair values of all our oil, natural gas and natural gas liquids derivative contracts as Level 2.

Derivative Financial Instrume23

Derivative Financial Instruments (Policy)	6 Months Ended
	Jun. 30, 2017
Derivative Financial Instruments [Line Items]
Derivative Financial Instruments	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.
Netting Presentation for Derivatives Policy [Member]
Derivative Financial Instruments [Line Items]
Derivative Financial Instruments	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.

Supplemental Cash Flow Inform24

Supplemental Cash Flow Information (Tables)	6 Months Ended
	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosures To The Consolidated Statements Of Cash Flows	  Six Months Ended June 30,  2017 2016   (in thousands)  Supplemental cash flow information:  Cash paid for interest $ 23,452 $ 31,071  Cash paid for state income taxes — 422  Non-cash investing and financing activities:  Change in asset retirement obligations 235 577  Asset retirement obligations assumed, purchased properties 89 —  Change in accruals or liabilities for capital expenditures 37,494 (4,869) 

Acquisitions (Tables)

Acquisitions (Tables)	6 Months Ended
	Jun. 30, 2017
Acquisition [Abstract]
Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices	  (in thousands)  Summary of Consideration  Cash $ 890  Total consideration paid 890   Summary of Purchase Price Allocation  Plus: fair value of liabilities assumed  Asset retirement obligations assumed 89  Total fair value liabilities assumed 89  Less: fair value of assets acquired  Proved oil and natural gas properties 2,605  Unproved oil and natural gas properties —  Total fair value assets acquired 2,605   Bargain Purchase Gain $ (1,626) 
Summary Of Pro Forma Information	   Total Operating Income  Revenues (Loss)   (in thousands)   Pro forma results of operations for the six months ended June 30, 2017 $ 155,474 $ 8,016  Pro forma results of operations for the six months ended June 30, 2016 $ 92,033 $ (92,864) 

Property And Equipment (Tables)

Property And Equipment (Tables)	6 Months Ended
	Jun. 30, 2017
Property And Equipment [Abstract]
Summary Of Property And Equipment	   June 30, December 31,  2017 2016   (in thousands)  OIL AND NATURAL GAS PROPERTIES  Unproved properties $ 102,922 $ 116,311  Accumulated impairment of unproved properties (18,893) (65)  Unproved properties, net 84,029 116,246  Proved oil and natural gas properties 1,814,057 1,611,249  Accumulated depreciation, depletion, amortization and impairment (1,075,588) (1,015,333)  Proved oil and natural gas properties, net 738,469 595,916  TOTAL OIL AND NATURAL GAS PROPERTIES, net 822,498 712,162  OTHER PROPERTY AND EQUIPMENT  Land 5,339 4,730  Office furniture and equipment, vehicles 20,135 19,446  Accumulated depreciation (15,784) (14,445)  OTHER PROPERTY AND EQUIPMENT, net 9,690 9,731  TOTAL PROPERTY AND EQUIPMENT, net $ 832,188 $ 721,893 

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	6 Months Ended
	Jun. 30, 2017
Fair Value Disclosures [Abstract]
Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis	   Level 1 Level 2 Level 3 Total   (in thousands)  At June 30, 2017:  Financial Assets:  Commodity derivative contracts — $ 36,073 — $ 36,073  Financial Liabilities:  Commodity derivative contracts — $ 12,198 — $ 12,198  At December 31, 2016:  Financial Assets:  Commodity derivative contracts — $ 15,773 — $ 15,773  Financial Liabilities:  Commodity derivative contracts — $ 40,656 — $ 40,656 

Derivative Financial Instrume28

Derivative Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2017
Derivative [Line Items]
Fair Values Of Derivative Contracts	 Fair Values of Derivative Contracts:     June 30, 2017  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 19,405 $ (4,403) $ 15,002  Derivative financial instruments, long-term assets 16,668 (7,795) 8,873  Total $ 36,073 $ (12,198) $ 23,875      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 4,403 $ (4,403) $ —  Derivative financial instruments, long-term liabilities 7,795 (7,795) —  Total $ 12,198 $ (12,198) $ —      December 31, 2016  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 3,296 $ (3,213) $ 83  Derivative financial instruments, long-term assets 12,477 (11,754) 723  Total $ 15,773 $ (14,967) $ 806      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 24,420 $ (3,213) $ 21,207  Derivative financial instruments, long-term liabilities 16,236 (11,754) 4,482  Total $ 40,656 $ (14,967) $ 25,689 
Effect Of Derivative Instruments In The Consolidated Statements Of Operations	   Derivatives not Three Months Ended Six Months Ended  designated as hedging June 30, June 30,  instruments under ASC 815 2017 2016 2017 2016   (in thousands)  Gain (loss) on derivative contracts  Oil commodity contracts $ 16,451 $ (31,517) $ 42,537 $ (23,371)   Natural gas commodity contracts 1,830 (6,584) 5,728 (3,770)   Natural gas liquids commodity contracts (31) (192) 227 (337)  Total gain (loss) on derivative contracts $ 18,250 $ (38,293) $ 48,492 $ (27,478) 
Oil Derivative Contracts [Member]
Derivative [Line Items]
Open Derivative Contracts	OIL DERIVATIVE CONTRACTS       Volume Weighted Range  Period and Type of Contract in Bbls Average High Low  2017  Price Swap Contracts 1,133,500 $ 50.39 $ 57.25 $ 46.00  Collar Contracts  Long Call Options 92,000 85.00 85.00 85.00  Short Call Options 989,000 60.47 85.00 54.40  Long Put Options 835,000 48.40 50.00 47.00  Short Put Options 713,000 36.97 40.00 35.00  2018  Price Swap Contracts 547,500 57.22 57.25 57.20  Collar Contracts  Long Call Options 365,000 54.00 54.00 54.00  Short Call Options 2,190,000 60.87 62.00 60.50  Long Put Options 1,825,000 50.00 50.00 50.00  Short Put Options 2,190,000 40.26 42.00 40.00  2019  Collar Contracts  Short Call Options 1,241,000 62.90 63.00 62.75  Long Put Options 1,241,000 50.00 50.00 50.00  Short Put Options 1,241,000 37.50 37.50 37.50 
Natural Gas Derivative Contract [Member]
Derivative [Line Items]
Open Derivative Contracts	NATURAL GAS DERIVATIVE CONTRACTS      Volume in Weighted Range  Period and Type of Contract MMBtu Average High Low  2017  Price Swap Contracts 922,500 $ 3.40 $ 3.40 $ 3.39  Collar Contracts  Short Call Options 6,072,000 3.65 4.11 3.25  Long Put Options 5,304,500 3.14 3.60 3.00  Long Call Options 615,000 2.95 2.95 2.95  Short Put Options 5,919,500 2.59 3.00 2.50  2018  Collar Contracts  Short Call Options 6,582,000 5.26 5.53 4.00  Long Put Options 5,925,000 4.43 4.50 3.60  Short Put Options 5,925,000 3.92 4.00 3.00 
Natural Gas Liquids Derivative Contracts [Member]
Derivative [Line Items]
Open Derivative Contracts	NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS    Volume Weighted Range  Period and Type of Contract in Gal Average High Low  2017  Price Swap Contracts  Short Price Swaps 3,091,200 $ 0.47 $ 0.47 $ 0.47 
Basis Swap Derivative Contract [Member]
Derivative [Line Items]
Natural Gas Basis Swap Contracts	We had the following open financial basis swaps at June 30, 2017 :  BASIS SWAP DERIVATIVE CONTRACTS      Weighted  Average Spread  Volume in MMBtu (1) Reference Price 1 Reference Price 2 Period ($ per MMBtu)  6,135,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Jul'17 — Dec '17 $ (0.25)  5,910,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Jan '18 — Oct '18 (0.27)   (1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) Inside FERC (“IFERC”) and NYMEX Henry Hub.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	6 Months Ended
	Jun. 30, 2017
Asset Retirement Obligations [Abstract]
Summary Of Changes In Asset Retirement Obligations	  Six  Months Ended  June 30, 2017  (in thousands)  Balance, beginning of year $ 61,504  Liabilities incurred 584  Liabilities assumed with acquired producing properties 89  Liabilities settled (977)  Revisions to estimates (583)  Accretion expense 1,052  Balance, June 30, 2017 61,669  Less: Current portion 1,006  Long-term portion $ 60,663 

Long Term Debt, Net And Notes30

Long Term Debt, Net And Notes Payable To Founder (Tables)	6 Months Ended
	Jun. 30, 2017
Long Term Debt, Net And Notes Payable To Founder [Abstract]
Long-Term Debt, Net And Notes Payable To Founder	   June 30, December 31,  2017 2016   (in thousands)  Senior secured revolving credit facility $ 195,687 $ 40,622  7.875% senior unsecured notes due 2024 500,000 500,000  Unamortized deferred financing costs (10,161) (10,717)  Total long-term debt, net $ 685,526 $ 529,905  Notes payable to founder $ 27,556 $ 26,957 

Accounts Payable And Accrued 31

Accounts Payable And Accrued Liabilities (Tables)	6 Months Ended
	Jun. 30, 2017
Accounts Payable And Accrued Liabilities [Abstract]
Detail Of Accounts Payable And Accrued Liabilities	   June 30, December 31,  2017 2016   (in thousands)  Capital expenditures $ 57,268 $ 15,155  Revenues and royalties payable 20,559 12,187  Operating expenses/taxes 18,193 17,499  Interest 2,334 2,627  Compensation 3,208 5,302  Derivative settlement payable 208 1,126  Other 631 1,164  Total accrued liabilities 102,401 55,060  Accounts payable 27,824 29,174  Accounts payable and accrued liabilities $ 130,225 $ 84,234 

Subsequent Event (Tables)

Subsequent Event (Tables)	6 Months Ended
	Jun. 30, 2017
SRII [Member]
Subsequent Event [Line Items]
Earn-out Consideration	  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 

Supplemental Cash Flow Inform33

Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 23,452	$ 31,071
Cash paid for state income taxes		422
Non-cash Investing And Financing Activities:
Change in asset retirement obligations	235	577
Asset retirement obligations assumed, purchased properties	89
Change in accruals or liabilities for capital expenditures	$ 37,494	$ (4,869)

Acquisitions (Narrative) (Detai

Acquisitions (Narrative) (Details) $ in Thousands	Jul. 07, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2016item
Business Acquisition [Line Items]
Gain(loss) on sale of oil and gas property		$ 1,083		$ 3,731
Adjusted cost of business acquisition	$ 40,400
Deposit for the purchase and sale agreement			$ 4,600
Setanta [Member]
Business Acquisition [Line Items]
Payment towards acquisition of all working interests			890
Fair value assets acquired			2,605
Bargain purchase gain			$ (1,626)
High Mesa [Member] | Contributed Wells [Member]
Business Acquisition [Line Items]
Number of wells | item					24

Acquisitions (Summary Of Consid

Acquisitions (Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices) (Details) - Setanta [Member] $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)
Business Acquisition [Line Items]
Cash	$ 890
Total	890
Asset retirement obligations assumed	89
Total fair value liabilities assumed	89
Proved oil and natural gas properties	2,605
Total fair value assets acquired	2,605
Bargain Purchase Gain	$ (1,626)

Acquisitions (Summary Of Pro Fo

Acquisitions (Summary Of Pro Forma Information) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Acquisition [Abstract]
Pro forma revenues	$ 155,474	$ 92,033
Pro forma income (loss)	$ 8,016	$ (92,864)

Property And Equipment (Summary

Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Property And Equipment [Abstract]
Unproved properties	$ 102,922	$ 116,311
Accumulated impairment of unproved properties	(18,893)	(65)
Unproved properties, net	84,029	116,246
Proved oil and natural gas properties	1,814,057	1,611,249
Accumulated depreciation, depletion, amortization and impairment	(1,075,588)	(1,015,333)
Proved oil and natural gas properties, net	738,469	595,916
TOTAL OIL AND NATURAL GAS PROPERTIES, net	822,498	712,162
Land	5,339	4,730
Office furniture and equipment, vehicles	20,135	19,446
Accumulated depreciation	(15,784)	(14,445)
OTHER PROPERTY AND EQUIPMENT, net	9,690	9,731
Total property and equipment, net	$ 832,188	$ 721,893

Fair Value Disclosures (Narrati

Fair Value Disclosures (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Face value of senior notes issued	$ 500,000		$ 500,000
Fair value of senior notes payable	507,500		507,500
Carrying value of oil and gas properties	32,800	$ 24,200	36,200	$ 27,500
Written down fair value of oil and gas properties	4,900	12,600	7,100	14,200
Impairment charges to oil and gas properties	$ 27,904	$ 11,555	29,124	13,319
Asset retirement obligation measured at fair value			$ 700	$ 600

Fair Value Disclosures (Measure

Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Financial Assets:
Commodity derivative contracts, gross	$ 36,073	$ 15,773
Financial Liabilities:
Commodity derivative contracts, gross	12,198	40,656
Commodity Derivative Contract [Member]
Financial Assets:
Commodity derivative contracts, gross	36,073	15,773
Financial Liabilities:
Commodity derivative contracts, gross	12,198	40,656
Level 1 [Member] | Commodity Derivative Contract [Member]
Financial Assets:
Commodity derivative contracts, gross
Financial Liabilities:
Commodity derivative contracts, gross
Level 2 [Member] | Commodity Derivative Contract [Member]
Financial Assets:
Commodity derivative contracts, gross	36,073	15,773
Financial Liabilities:
Commodity derivative contracts, gross	12,198	40,656
Level 3 [Member] | Commodity Derivative Contract [Member]
Financial Assets:
Commodity derivative contracts, gross
Financial Liabilities:
Commodity derivative contracts, gross

Derivative Financial Instrume40

Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Gross Fair Value of Assets	$ 36,073	$ 15,773
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(12,198)	(14,967)
Derivative Asset, Net Fair Value of Assets presented in the Balance Sheet	23,875	806
Gross Fair Value of Liabilities	12,198	40,656
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(12,198)	(14,967)
Derivative Liability, Net Fair Value of Liabilities presented in the Balance Sheet		25,689
Derivative Assets Current [Member]
Derivatives, Fair Value [Line Items]
Gross Fair Value of Assets	19,405	3,296
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(4,403)	(3,213)
Derivative Asset, Net Fair Value of Assets presented in the Balance Sheet	15,002	83
Derivative Asset Non-Current [Member]
Derivatives, Fair Value [Line Items]
Gross Fair Value of Assets	16,668	12,477
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(7,795)	(11,754)
Derivative Asset, Net Fair Value of Assets presented in the Balance Sheet	8,873	723
Derivative Liabilities Current [Member]
Derivatives, Fair Value [Line Items]
Gross Fair Value of Liabilities	4,403	24,420
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(4,403)	(3,213)
Derivative Liability, Net Fair Value of Liabilities presented in the Balance Sheet		21,207
Derivative Liabilities Non Current [Member]
Derivatives, Fair Value [Line Items]
Gross Fair Value of Liabilities	7,795	16,236
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(7,795)	(11,754)
Derivative Liability, Net Fair Value of Liabilities presented in the Balance Sheet		$ 4,482

Derivative Financial Instrume41

Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative Instruments, Gain [Line Items]
Total gains (loss) on derivative contracts	$ 18,250	$ (38,293)	$ 48,492	$ (27,478)
Derivatives Not Designated As Hedging Instruments [Member] | Oil Commodity Contracts [Member]
Derivative Instruments, Gain [Line Items]
Total gains (loss) on derivative contracts	16,451	(31,517)	42,537	(23,371)
Derivatives Not Designated As Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member]
Derivative Instruments, Gain [Line Items]
Total gains (loss) on derivative contracts	1,830	(6,584)	5,728	(3,770)
Derivatives Not Designated As Hedging Instruments [Member] | Natural Gas Liquids Commodity Contract [Member]
Derivative Instruments, Gain [Line Items]
Total gains (loss) on derivative contracts	$ (31)	$ (192)	$ 227	$ (337)

Derivative Financial Instrume42

Derivative Financial Instruments (Oil Derivative Contracts) (Details) - Oil Derivative Contracts [Member]	6 Months Ended
	Jun. 30, 2017$ / bblbbl
Price Swap Contracts [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,133,500
Weighted Average Swap Price	50.39
Price Swap Contracts [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Weighted Average Swap Price	57.25
Price Swap Contracts [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Weighted Average Swap Price	46
Price Swap Contracts [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	547,500
Weighted Average Swap Price	57.22
Price Swap Contracts [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Weighted Average Swap Price	57.25
Price Swap Contracts [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Weighted Average Swap Price	57.20
Long Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	92,000
Weighted Average Option Price	85
Long Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	85
Long Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	85
Long Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	365,000
Weighted Average Option Price	54
Long Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	54
Long Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	54
Short Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	989,000
Weighted Average Option Price	60.47
Short Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	85
Short Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	54.40
Short Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,190,000
Weighted Average Option Price	60.87
Short Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	62
Short Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60.50
Short Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000
Weighted Average Option Price	62.90
Short Call Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	63
Short Call Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	62.75
Long Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	835,000
Weighted Average Option Price	48.40
Long Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	47
Long Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,825,000
Weighted Average Option Price	50
Long Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000
Weighted Average Option Price	50
Long Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	50
Short Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	713,000
Weighted Average Option Price	36.97
Short Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	40
Short Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	35
Short Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,190,000
Weighted Average Option Price	40.26
Short Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	42
Short Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	40
Short Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000
Weighted Average Option Price	37.50
Short Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	37.50
Short Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	37.50

Derivative Financial Instrume43

Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) - Natural Gas [Member]	6 Months Ended
	Jun. 30, 2017MMBTU$ / MMBTU
2017 [Member] | Price Swap Contracts [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	922,500
Weighted Average Swap Price	3.40
2017 [Member] | Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Weighted Average Swap Price	3.40
2017 [Member] | Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Weighted Average Swap Price	3.39
2017 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,072,000
Weighted Average Option Price	3.65
2017 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.11
2017 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.25
2017 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,304,500
Weighted Average Option Price	3.14
2017 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	3.60
2017 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3
2017 [Member] | Long Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	615,000
Weighted Average Option Price	2.95
2017 [Member] | Long Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	2.95
2017 [Member] | Long Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.95
2017 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,919,500
Weighted Average Option Price	2.59
2017 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	3
2017 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.50
2018 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,582,000
Weighted Average Option Price	5.26
2018 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.53
2018 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4
2018 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,925,000
Weighted Average Option Price	4.43
2018 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.50
2018 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.60
2018 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,925,000
Weighted Average Option Price	3.92
2018 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4
2018 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3

Derivative Financial Instrume44

Derivative Financial Instruments (Natural Gas Liquids Derivative Contracts) (Details) - 2017 [Member] - Natural Gas Liquids Derivative Contracts [Member] - Short Price Swaps [Member]	6 Months Ended
	Jun. 30, 2017$ / galgal
Derivative [Line Items]
Volume in Gal | gal	3,091,200
Weighted Average Swap Price	0.47
Minimum [Member]
Derivative [Line Items]
Weighted Average Swap Price	0.47
Maximum [Member]
Derivative [Line Items]
Weighted Average Swap Price	0.47

Derivative Financial Instrume45

Derivative Financial Instruments (Natural Gas Basis Swap Contracts) (Details) - Basis Swap Derivative Contracts [Member]	6 Months Ended
	Jun. 30, 2017MMBTU$ / MMBTU
2017 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,135,000
First remaining period of term of derivative contract	Jul. 1, 2017
Last remaining period of term of derivative contract	Dec. 31, 2017
Weighted average spread | $ / MMBTU	(0.25)
2018 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,910,000
First remaining period of term of derivative contract	Jan. 1, 2018
Last remaining period of term of derivative contract	Oct. 31, 2018
Weighted average spread | $ / MMBTU	(0.27)

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Details) $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)
Asset Retirement Obligations [Abstract]
Reductions To PPE Included In ARO Revisions	$ 0.3

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Asset Retirement Obligations [Abstract]
Balance, beginning of year			$ 61,504
Liabilities incurred			584
Liabilities assumed with acquired producing properties			89
Liabilities settled			(977)
Revisions to estimates			(583)
Accretion expense	$ 480	$ 536	1,052	$ 1,075
Balance, end of period	61,669		$ 61,504		$ 61,504
Less: Current portion	1,006				376
Long-term portion	$ 60,663				$ 61,128

Long Term Debt, Net And Notes48

Long Term Debt, Net And Notes Payable To Founder (Narrative) (Details)	Jun. 13, 2017USD ($)item	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2014	Jun. 12, 2017USD ($)	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Period following closing additional borrowings can be made				120 days
Face value of senior notes issued		$ 500,000,000		$ 500,000,000
Notes payable to founder		27,556,000		27,556,000				$ 26,957,000
Interest on notes payable to founder				599,000	$ 600,000
Deferred financing costs		10,161,000		10,161,000				10,717,000
Amortization of deferred financing costs		500,000	$ 1,000,000	1,456,000	1,965,000
Deferred financing costs, net		2,299,000		2,299,000				3,029,000
Senior secured revolving credit facility		195,687,000		$ 195,687,000				40,622,000
Federal Funds Effective Swap Rate [Member]
Debt Instrument [Line Items]
Margin interest rate				0.50%
7th Amended And Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description				plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00.
Credit Facility And Senior Notes [Member]
Debt Instrument [Line Items]
Deferred financing costs		12,500,000		$ 12,500,000
7.875% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Face value of senior notes issued		500,000,000		$ 500,000,000
Maturity date of debt				Dec. 15, 2024
Redemption price due to specific change of control events				101.00%
Notes payable		$ 500,000,000		$ 500,000,000				$ 500,000,000
Stated interest rate of senior notes		7.875%		7.875%
First annual payment date				June 15
Second annual payment date				December 15
Redemption percentage of aggregate remaining outstanding				65.00%
7.875% Senior Unsecured Notes Due 2024 [Member] | Prior to December 15, 2019 [Member]
Debt Instrument [Line Items]
Redemption price plus make-whole premium				100.00%
Redemption price				107.875%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2019 [Member]
Debt Instrument [Line Items]
Redemption price				105.906%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2020 [Member]
Debt Instrument [Line Items]
Redemption price				103.938%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2021 [Member]
Debt Instrument [Line Items]
Redemption price				101.969%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2022 [Member]
Debt Instrument [Line Items]
Redemption price				100.00%
Maximum [Member] | 7.875% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Redemption percentage of Senior Notes				35.00%
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility borrowing base		$ 315,000,000		$ 315,000,000			$ 287,500,000
Line of Credit Facility, Remaining borrowing capacity		$ 114,000,000		$ 114,000,000
Date of maturity of credit facility				Nov. 10, 2020
Credit facility interest rate		5.90%		5.90%				4.00%
Pro forma leverage ratio				3
Letter of credit outstanding		$ 5,300,000		$ 5,300,000				$ 7,600,000
Minimum Working Capital Ratio				1
Maximum Leverage Ratio				4
Debt instrument collateral				The credit facility is secured by substantially all of our oil and natural gas properties
Debt covenants description				The credit facility 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, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect.The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses ("EBITDAX") over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.
Debt covenant compliance description				As of June 30, 2017, we were in compliance with all financial covenants of the credit facility.
Percent of unused distribution				20.00%
Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Leverage rate				3.25
Senior Secured Revolving Credit Facility [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Leverage rate				3.25
Senior Secured Revolving Credit Facility [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Margin interest rate				1.00%
Senior Secured Revolving Credit Facility [Member] | 7th Amended And Restated Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description				the London Interbank Offered Rate ("LIBOR") plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00.
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate				2.75%
Exceeded leverage rate				3.00%
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate				1.75%
Exceeded leverage rate				2.00%
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate				3.75%
Exceeded leverage rate				4.00%
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate				2.75%
Exceeded leverage rate				3.00%
Second Amendment [Member]
Debt Instrument [Line Items]
Credit facility borrowing base	$ 315,000,000
Number of cash distribution | item	1
Second Amendment [Member] | Maximum [Member]
Debt Instrument [Line Items]
Cash distribution to a limited partner	$ 1,000,000
Notes Payable To Founder [Member]
Debt Instrument [Line Items]
Maturity date of debt				Dec. 31, 2021		Dec. 31, 2018
Effective rate of interest		10.00%		10.00%
Debt instrument collateral				These Founder Notes are unsecured and subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner, the Founder Notes were amended and restated to subordinate them to the paid in kind ("PIK") notes of our Class B partner. The Founder Notes were also subordinated to the rights of the holders of Class B units to receive distributions under our partnership agreement and subordinated to the rights of the holders of certain equity interests to receive payments.
Notes payable to founder		$ 27,600,000		$ 27,600,000				$ 27,000,000
Payment terms, notes payable to founder				Interest and principal are payable at maturity.
Interest on notes payable to founder		$ 300,000	$ 300,000	$ 600,000	$ 600,000
Conversion feature, notes payable to founder				Our founder shall convert the notes into shares of common stock of High Mesa upon certain conditions, in the event of a liquidity event as defined Note 13.

Long Term Debt, Net And Notes49

Long Term Debt, Net And Notes Payable To Founder (Long-Term Debt, Net And Notes Payable To Founder) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Senior secured revolving credit facility	$ 195,687	$ 40,622
Unamortized deferred financing costs	(10,161)	(10,717)
Total long-term debt, net	685,526	529,905
Notes payable to founder	27,556	26,957
7.875% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Notes payable	$ 500,000	$ 500,000
Maturity date of debt	Dec. 15, 2024
Stated interest rate of senior notes	7.875%

Accounts Payable And Accrued 50

Accounts Payable And Accrued Liabilities (Detail Of Accounts Payable And Accrued Liabilities) (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016
Accounts Payable And Accrued Liabilities [Abstract]
Capital expenditures	$ 57,268	$ 15,155
Revenues and royalties payable	20,559	12,187
Operating expenses/taxes	18,193	17,499
Interest	2,334	2,627
Compensation	3,208	5,302
Derivative settlement payable	208	1,126
Other	631	1,164
Total accrued liabilities	102,401	55,060
Accounts payable	27,824	29,174
Accounts payable and accrued liabilities	$ 130,225	$ 84,234

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	6 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Commitment And Contingencies [Line Items]
Vesting period, PARs	5 years
Weighted average stipulated price of PARs granted	$ 37.91
Stipulated initial designated price of PARs granted	$ 40
Number of performance appreciation rights granted	308,800
Number of performance appreciation rights terminated	500
Number of performance appreciation rights	884,200
Weighted average stipulated price of PARs terminated	$ 40
Other long-term liabilities	$ 7,154	$ 6,870
Litigation [Member]
Commitment And Contingencies [Line Items]
Estimated litigation liability	3,200
Current litigation liabilities	800
Other long-term liabilities	$ 2,400
Settlement payment term	6 years

Significant Risks And Uncerta52

Significant Risks And Uncertainties (Details)	6 Months Ended
	Jun. 30, 2017
Significant Risks And Uncertainties [Abstract]
Risks and uncertainties inherent	Our business makes us vulnerable to changes in wellhead prices of crude 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. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from lows experienced since such decline, forecasted prices for both oil and natural gas continue to remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further price declines 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. Sustained low oil or natural gas prices may require us to write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.

Partners' Capital (Details)

Partners' Capital (Details)	3 Months Ended	6 Months Ended		12 Months Ended
	Mar. 31, 2017USD ($)	Jun. 30, 2017item	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)item
Debt Instrument [Line Items]
Number of classes of limited partners | item		2
High Mesa [Member]
Debt Instrument [Line Items]
Cash contribution				$ 11,300,000
Cash collected	$ 7,900,000
Contribution			$ 0	$ 65,700,000
Contributed Wells [Member] | High Mesa [Member]
Debt Instrument [Line Items]
Number of wells | item				24

Subsequent Event (Narrative) (D

Subsequent Event (Narrative) (Details) - Subsequent Event [Member] $ in Millions	Aug. 16, 2017USD ($)shares	Aug. 17, 2017USD ($)
AM Contributor [Member]
Subsequent Event [Line Items]
Cash contributions to be received	$ 400
SRII [Member]
Subsequent Event [Line Items]
Earn-out consideration, Day for volume-weighted average price	20 days
Capital contribution		$ 200
SRII [Member] | SRII Opco, LP [Member]
Subsequent Event [Line Items]
Leverage ratio	1.5
SRII [Member] | SRII Opco, LP [Member] | AM Contributor [Member]
Subsequent Event [Line Items]
Common units | shares	220,000,000
Value in earn-out consideration	$ 800
SRII [Member] | Common Class C [Member] | SRII Opco, LP [Member]
Subsequent Event [Line Items]
Redeemable days after closing	180 days
Alta Mesa Holdings GP, LLC [Member] | Common Class A [Member]
Subsequent Event [Line Items]
Economic rights	100.00%
Alta Mesa Holdings GP, LLC [Member] | Common Class B [Member]
Subsequent Event [Line Items]
Voting rights	100.00%
Alta Mesa Holdings GP, LLC [Member] | SRII [Member]
Subsequent Event [Line Items]
Economic interests	100.00%
Voting interests	90.00%
Kingfisher Midstream, LLC [Member] | SRII [Member]
Subsequent Event [Line Items]
Percentage of ownership	100.00%

Subsequent Event (Earn-Out Cons

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