AM Michigan S-4 4 Oct 17 Registration of securities issued in business combination transactions Financial data

Document and Entity Information

Document and Entity Information	6 Months Ended
	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	S4
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Trading Symbol	altms
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	1,518,403
Entity Filer Category	Non-accelerated Filer

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
CURRENT ASSETS
Cash and cash equivalents	$ 5,279	$ 7,185	$ 8,869
Short-term restricted cash	805	433	105
Accounts receivable	49,089	37,611	27,111
Other receivables	3,780	8,061	18,526
Receivables due from affiliate	1,688	8,883	1,053
Prepaid expenses and other current assets	1,899	3,986	4,774
Derivative financial instruments	15,002	83	62,631
Total current assets	77,542	66,242	123,069
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	822,498	712,162	525,942
Other property and equipment, net	9,690	9,731	11,097
Total property and equipment, net	832,188	721,893	537,039
OTHER ASSETS
Investment in LLC - cost	9,000	9,000	9,000
Deferred financing costs, net	2,299	3,029	1,199
Notes receivable due from affiliate	10,393	9,987	9,213
Deposits and other long-term assets	16,707	2,977	1,370
Derivative financial instruments	8,873	723	41,635
Total other assets	47,272	25,716	62,417
TOTAL ASSETS	957,002	813,851	722,525
CURRENT LIABILITIES
Accounts payable and accrued liabilities	130,225	84,234	82,621
Advances from non-operators	3,165	4,058	1,381
Advances from related party		42,528
Asset retirement obligations	1,006	376	729
Derivative financial instruments		21,207
Total current liabilities	134,396	152,403	84,731
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	60,663	61,128	60,491
Long-term debt, net	685,526	529,905	717,775
Notes payable to founder	27,556	26,957	25,748
Derivative financial instruments		4,482
Other long-term liabilities	7,154	6,870	10,829
Total long-term liabilities	780,899	629,342	814,843
TOTAL LIABILITIES	915,295	781,745	899,574
Commitments and Contingencies
PARTNERS' CAPITAL (DEFICIT)	41,707	32,106	(177,049)
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 957,002	$ 813,851	$ 722,525

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 774	$ 889	$ 1,402

Condensed Consolidated Statemen

Condensed Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
OPERATING REVENUES AND OTHER
Oil	$ 55,071	$ 43,843	$ 114,416	$ 75,087	$ 163,677	$ 199,799	$ 347,842
Natural gas	13,136	5,796	25,821	10,487	30,953	30,621	65,002
Natural gas liquids	7,076	4,010	14,695	6,115	15,663	10,864	18,281
Other revenues	86	174	202	301	415	682	1,003
Total operating revenues	75,369	53,823	155,134	91,990	210,708	241,966	432,128
Gain on sale of assets		1,083		3,731	3,542	67,781	87,520
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)	(40,460)	124,141	96,559
Total operating revenues and other	95,245	16,613	205,252	68,243	173,790	433,888	616,207
OPERATING EXPENSES
Lease and plant operating expense	16,597	13,452	34,333	30,577	56,893	67,706	64,686
Marketing and transportation expense	6,857	1,472	12,900	2,887	13,326	4,030	9,134
Production and ad valorem taxes	3,039	2,731	6,107	5,126	10,750	15,131	28,214
Workover expense	2,015	1,118	3,398	2,515	4,714	6,511	8,961
Exploration expense	6,265	3,428	14,407	6,714	24,777	42,718	61,912
Depreciation, depletion, and amortization expense	26,494	22,931	51,298	44,424	92,901	143,969	141,804
Impairment expense	27,904	11,555	29,124	13,319	16,306	176,774	74,927
Accretion expense	480	536	1,052	1,075	2,174	2,076	2,198
General and administrative expense	8,328	12,076	18,076	22,259	41,758	44,454	69,198
Total operating expenses	97,979	69,299	170,695	128,896	263,599	503,369	461,034
INCOME (LOSS) FROM OPERATIONS	(2,734)	(52,686)	34,557	(60,653)	(89,809)	(69,481)	155,173
OTHER INCOME (EXPENSE)
Interest expense	(12,879)	(17,672)	(25,219)	(34,067)	(60,884)	(62,473)	(55,812)
Interest income	299	227	548	433	894	723	15
Loss on extinguishment of debt					(18,151)
Total other income (expense)	(12,580)	(17,445)	(24,671)	(33,634)	(78,141)	(61,750)	(55,797)
INCOME (LOSS) BEFORE STATE INCOME TAXES	(15,314)	(70,131)	9,886	(94,287)	(167,950)	(131,231)	99,376
Provision for (benefit from) state income taxes		106	285	107	(29)	562	176
NET INCOME (LOSS)	$ (15,314)	$ (70,237)	$ 9,601	$ (94,394)	$ (167,921)	$ (131,793)	$ 99,200

Consolidated Statements Of Chan

Consolidated Statements Of Changes In Partners' Capital (Deficit) $ in Thousands	USD ($)
Balance, Beginning at Dec. 31, 2013	$ (160,107)
Statement of Partners' Capital [Abstract]
Distributions	(539)
NET INCOME (LOSS)	99,200
Balance, Ending at Dec. 31, 2014	(61,446)
Statement of Partners' Capital [Abstract]
Contributions	20,000
Distributions	(3,810)
NET INCOME (LOSS)	(131,793)
Balance, Ending at Dec. 31, 2015	(177,049)
Statement of Partners' Capital [Abstract]
Contributions	377,076
NET INCOME (LOSS)	(167,921)
Balance, Ending at Dec. 31, 2016	32,106
Statement of Partners' Capital [Abstract]
NET INCOME (LOSS)	9,601
Balance, Ending at Jun. 30, 2017	$ 41,707

Condensed Consolidated Stateme6

Condensed Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ 9,601	$ (94,394)	$ (167,921)	$ (131,793)	$ 99,200
Adjustments to reconcile net (income) loss to net cash used in operating activities:
Depreciation, depletion, and amortization expense	51,298	44,424	92,901	143,969	141,804
Impairment expense	29,124	13,319	16,306	176,774	74,927
Accretion expense	1,052	1,075	2,174	2,076	2,198
Amortization of deferred financing costs	1,456	1,965	3,905	3,392	2,885
Amortization of debt discount		255	468	510	510
Dry hole expense	888	215	419	22,708	30,294
Expired leases	5,922	2,435	11,158	6,526	4,319
(Gain) loss on derivative contracts	(48,492)	27,478	40,460	(124,141)	(96,559)
Settlements of derivative contracts	254	65,991	88,689	106,949	9,493
Loss on extinguishment of debt			18,151
Premium paid on derivative contracts	(520)
Interest converted into debt	599	600	1,209	1,208	1,209
Interest on notes receivable due from affiliate	(406)	(378)	(774)	(713)
Gain on sale of assets		(3,731)	(3,542)	(67,781)	(87,520)
Gain on acquisition of oil and natural gas properties	(1,626)
Changes in assets and liabilities:
Restricted cash unrelated to property divestiture			(328)		(106)
Restricted cash	(372)	(121,935)
Accounts receivable	(11,478)	(6,927)	(10,500)	16,470	(95)
Other receivables	4,281	14,377	10,465	(10,288)	(5,686)
Receivables due from affiliate	(680)	(1,615)	45	(1,725)
Prepaid expenses and other non-current assets	(11,644)	(3,951)	(819)	(2,269)	7,251
Advances from related party	(42,528)		42,528
Settlement of asset retirement obligation	(977)	(741)	(2,125)	(1,794)	(3,942)
Accounts payable, accrued liabilities, and other liabilities	7,655	14,619	(11,493)	3,900	4,702
NET CASH (USED IN) PROVIDED BY OPERATING ACTIVITIES	(6,593)	(46,919)	131,376	143,978	184,884
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(151,832)	(94,997)	(214,061)	(223,604)	(366,090)
Acquisitions	(6,251)		(11,527)	(48,202)	(18,110)
Proceeds from sale of property		1,358	1,290	141,404	177,476
Proceeds from property divestiture classified as restricted cash					41,590
Investment in restricted cash related to property divestitures				24,587	(24,587)
NET CASH USED IN INVESTING ACTIVITIES	(158,083)	(93,639)	(224,298)	(105,815)	(189,721)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	165,065	141,935	222,557	252,500	169,500
Repayments of long-term debt	(10,000)		(333,935)	(295,020)	(169,270)
Repayments of senior secured term loan			(127,708)
Repurchase of senior notes due 2018			(459,391)
Proceeds from issuance of senior notes due 2024			500,000
Additions to deferred financing costs	(170)	(799)	(13,747)	(4,313)	(42)
Capital distributions				(3,810)	(539)
Capital contributions	7,875		303,462	20,000
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES	162,770	141,136	91,238	(30,643)	(351)
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(1,906)	578	(1,684)	7,520	(5,188)
CASH AND CASH EQUIVALENTS, beginning of period	7,185	8,869	8,869	1,349	6,537
CASH AND CASH EQUIVALENTS, end of period	$ 5,279	$ 9,447	$ 7,185	$ 8,869	$ 1,349

Description Of Business

Description Of Business	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [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, development, 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.	NOTE 1 — NATURE OF OPERATIONS Nature of Operations

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 Deferral of the Effective Date In February 2016, the FASB issued ASU No. 2016-02 , Leases (Topic 842) ASU 2016-02, In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash (“ASU 2016-18”), In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business,	NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”). Certain prior-period amounts in the consolidated financial statements have been reclassified to conform to the current-year presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit). Principles of Consolidation Use of Estimates Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquired properties), oil and natural gas revenues, 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. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates. Cash and Cash Equivalents Restricted Cash. Accounts Receivable Accounts receivable consisted of the following: As of December 31, 2016 2015 (in thousands) Oil, natural gas and natural gas liquids sales $ 25,149 $ 17,865 Joint interest billings 13,344 10,162 Other 7 486 Allowance for doubtful accounts (889 ) (1,402 ) Total accounts receivable, net $ 37,611 $ 27,111 See Note 13 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $17.7 million and $12.6 million as of December 31, 2016 and 2015, respectively. Allowance for Doubtful Accounts Deferred Financing Costs. Property and Equipment Unproved Properties Exploration Expense Proved Oil and Natural Gas Properties Impairment Our evaluation of the Company’s proved properties resulted in impairment expense of $16.1 million, $172.0 million and $72.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, primarily due to lower forecasted commodity prices. Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. For the years ended December 31, 2016, 2015 and 2014, impairment expense of unproved properties was $0.2 million, $4.8 million, and $2.0 million, respectively. Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment. If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2016, 2015 and 2014, respectively, the Company did not record any impairment expense related to other long-lived assets. Depreciation, Depletion and Amortization DD&A expense for the years ended December 31, 2016, 2015 and 2014 related to oil and natural gas properties was $90.0 million, $140.9 million, and $139.0 million, respectively. Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2016, 2015 and 2014 was $2.9 million, $3.0 million, and $2.8 million respectively. Investments Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 13. Asset Retirement Obligations Derivative Financial Instruments Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. Cash flows from settlements of derivative contracts are classified as operating cash flows. Income Taxes Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $101.5 million at December 31, 2016. The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax. We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2016 and 2015. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2016, 2015 or 2014. The Company’s tax returns for the years ended December 31, 2013 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities. Revenue Recognition Fair Value of Financial Instruments. Acquisitions Recent Accounting Pronouncements In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers Deferral of the Effective Date In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities In February 2016, the FASB issued ASU 2016-02 , Leases (Topic 842) In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business,

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [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 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 )	NOTE 3 — SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Year Ended December 31, 2016 2015 2014 (in thousands) Supplemental cash flow information: Cash paid for interest $ 74,694 $ 56,579 $ 51,219 Cash paid (received) for state income taxes, net of refunds 285 751 (123 ) Non-cash investing and financing activities: Change in asset retirement obligations 2,719 487 2,643 Asset retirement obligations assumed, purchased properties — — 3,002 Change in accruals or liabilities for capital expenditures 12,375 (34,160 ) 23,858 Divestiture of oil and gas properties — — (34,000 ) Acquisition of property and land — 2,473 — Contribution of interests in oil and gas properties 65,740 — — Contribution receivable 7,875 — —

ACQUISITIONS

ACQUISITIONS	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Business Combinations [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 properties 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.	NOTE 4 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES 2016 Activity During 2016, we acquired approximately $10.6 million of oil and gas properties in Oklahoma which were primarily related to unevaluated leasehold. On December 31, 2016, our Class B partner, High Mesa, Inc. (“High Mesa”) purchased from 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 and therefore, recorded the contribution at their estimated contribution date fair value. 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 subsequent to year end. The unaudited pro forma combined financial results, had the contribution of the Contributed Wells occurred at January 1, 2016, are provided below. The Contributed Wells came online during 2016, therefore, no unaudited pro forma combined results are shown for the beginning of the comparable prior year. Total operating Net loss (in thousands) (unaudited) Pro forma results for the combined entity for the year ended December 31, 2016 $ 199,982 $ (157,230 ) This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information is not necessarily indicative of what actually would have occurred if the contribution had been completed as of the beginning of the period, nor are they necessarily indicative of future results. 2015 Activity Alta Mesa Eagle, LLC Divestiture On September 30, 2015, we closed the sale of all of the membership interests (the “Membership Interests”) in Alta Mesa Eagle, LLC (“AME”), our wholly owned subsidiary, to EnerVest Energy Institutional Fund XIV-A, L.P. and EnerVest Energy Institutional Fund XIV-WIC, L.P. (collectively, “EnerVest”) pursuant to a purchase and sale agreement entered into by us, AME and EnerVest on September 16, 2015 (the “Eagle Ford divestiture”). AME owned our remaining non-operated oil and natural gas producing properties located in the Eagle Ford shale play in Karnes County, Texas. In connection with the Eagle Ford divestiture, we disposed of all of our remaining interests in this area. The effective date of the transaction (the “Effective Date”) is July 1, 2015. The aggregate cash purchase price for the Membership Interests was $125.0 million subject to certain adjustments, consisting of $118.0 million (the “Base Purchase Price”), and additional contingent payments of approximately $7.0 million in the aggregate, payable to us by EnerVest by the 15th of each calendar month in which certain amounts owed to AME prior to the Effective Date have been received. The purchase and sale agreement provides for customary purchase price adjustments to the Base Purchase Price based on the Effective Date. As of December 31 2015, we received net proceeds of $122.0 million including $4.0 million of customary purchase price adjustments, and recognized a gain of approximately $67.6 million. Cash received was utilized to pay down borrowings under our senior secured revolving credit facility. As of the Effective Date, the estimated net proved reserves sold were approximately 7.8 MMBOE. The sale of AME contributed approximately $68.9 million in pre-tax profit for the year ended December 31, 2015, which includes the $67.6 million gain on sale of asset and $118.5 million in pre-tax profit for the year ended December 31, 2014, which includes a $72.5 million gain on sale of assets for the first portion of the Eagleville divestiture, owned by AME, as described below. Kingfisher Leasehold Acquisition On July 6, 2015, we acquired approximately 19,000 net acres of primarily undeveloped leasehold interest in Kingfisher County, Oklahoma. The consideration for the purchase was approximately $46.2 million and was subject to customary purchase price adjustments. The effective date of the acquisition was April 1, 2015. The purchase was funded with borrowings under our senior secured revolving credit facility. 2014 Activity Eagleville Divestiture On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville Divestiture”). The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014. We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017. Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014. The initial cash purchase price was $173.0 million, subsequently adjusted to approximately $171.0 million for settlement adjustments. The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date. As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE. We recorded a gain on sale from the Eagleville Divestiture of $72.5 million during 2014, based on an allocation of basis between the properties sold and properties retained. The sold portion of Eagleville field contributed approximately $11.1 million in pre-tax income in the first quarter of 2014, prior to its sale. Hilltop Divestiture On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a gain on the sale of $15.9 million. As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE. The Hilltop interests contributed approximately $7.7 million in net pre-tax income during the year ended December 31, 2014.

PROPERTY AND EQUIPMENT

PROPERTY AND EQUIPMENT	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Property And Equipment	5. PROPERTY AND EQUIPMENT Property and equipment consists of the following: June 30, December 31, (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	NOTE 5 — PROPERTY AND EQUIPMENT Property and equipment consists of the following: December 31, December 31, (in thousands) OIL AND NATURAL GAS PROPERTIES Unproved properties $ 116,311 $ 127,551 Accumulated impairment (65 ) (2,684 ) Unproved properties, net 116,246 124,867 Proved oil and natural gas properties 1,611,249 1,345,482 Accumulated depreciation, depletion, amortization and impairment (1,015,333 ) (944,407 ) Proved oil and natural gas properties, net 595,916 401,075 TOTAL OIL AND NATURAL GAS PROPERTIES, net 712,162 525,942 OTHER PROPERTY AND EQUIPMENT Land 4,730 3,868 Office furniture and equipment, vehicles 19,446 18,794 Accumulated depreciation (14,445 ) (11,565 ) OTHER PROPERTY AND EQUIPMENT, net 9,731 11,097 TOTAL PROPERTY AND EQUIPMENT, net $ 721,893 $ 537,039 Capitalized Exploratory Well Costs The following table reflects the net changes in capitalized exploratory well costs during 2016, 2015, and 2014. The table does not include amounts that were capitalized and either subsequently expensed within the same year. Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 6,006 $ 13,301 $ 20,317 Additions to capitalized well costs pending determination of proved reserves 3,736 4,364 15,870 Reclassifications to proved properties (7,484 ) (8,583 ) (6,593 ) Capitalized exploratory well costs charged to expense (169 ) (3,076 ) (16,293 ) Balance, end of year $ 2,089 $ 6,006 $ 13,301 The ending balance in capitalized exploratory well costs includes the costs of five wells primarily in three prospects that were capitalized for periods greater than one year at December 31, 2016. We have capitalized $0.7 million and $3.0 million of exploratory well costs covering periods greater than one year at December 31, 2016 and 2015. We continue to assess and evaluate these projects.

FAIR VALUE DISCLOSURES

FAIR VALUE DISCLOSURES	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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 measured 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.	NOTE 6 — FAIR VALUE DISCLOSURES The Company follows ASC 820, “Fair Value Measurements and Disclosure.” 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. 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. We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (“NYMEX”) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil, natural gas, and natural gas liquids derivative contracts as Level 2. Our senior notes are carried at historical cost. We estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification. Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $33.9 million were written down to their fair value of $17.6 million, resulting in an impairment charge of $16.3 million for the year ended December 31, 2016. Oil and natural gas properties with a carrying amount of $499.6 million were written down to their fair value of $322.8 million, resulting in an impairment charge of $176.8 million for the year ended December 31, 2015. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and 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 which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $1.4 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2016. We recorded a total of $2.0 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2015. The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2016 and 2015, 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 December 31, 2016: Financial Assets: Derivative contracts for oil and natural gas — $ 15,773 — $ 15,773 Financial Liabilities: Derivative contracts for oil and natural gas — $ 40,656 — $ 40,656 At December 31, 2015: Financial Assets: Derivative contracts for oil and natural gas — $ 166,106 — $ 166,106 Financial Liabilities: Derivative contracts for oil and natural gas — $ 61,840 — $ 61,840 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.

Derivative Financial Instrument

Derivative Financial Instruments	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [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 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current assets $ 19,405 $ (4,403 ) $ 15,002 Derivative financial instruments, long-term 16,668 (7,795 ) 8,873 Total $ 36,073 $ (12,198 ) $ 23,875 Balance sheet location Gross Gross amounts Net Fair (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 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current assets $ 3,296 $ (3,213 ) $ 83 Derivative financial instruments, long-term 12,477 (11,754 ) 723 Total $ 15,773 $ (14,967 ) $ 806 Balance sheet location Gross Gross amounts Net Fair (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 designated as hedging instruments under ASC 815 Three Months Ended Six Months Ended 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 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 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 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 Volume in MMBtu (1) Reference Price 1 Reference Price 2 Period Weighted 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.	NOTE 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 the benchmark index price and the specific locational index pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our senior secured revolving credit facility described in Note 10 below, 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, 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 counter-parties 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 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 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 consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account. The following table summarizes the fair value (see Note 6 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815: December 31, 2016 Balance sheet location Gross Gross amounts Net Fair (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 Balance sheet location Gross Gross amounts Net Fair (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 December 31, 2015 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current assets $ 86,000 $ (23,369 ) $ 62,631 Derivative financial instruments, long-term assets 80,106 (38,471 ) 41,635 Total $ 166,106 $ (61,840 ) $ 104,266 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current liabilities $ 23,369 $ (23,369 ) $ — Derivative financial instruments, long-term liabilities 38,471 (38,471 ) — Total $ 61,840 $ (61,840 ) $ — The following table summarizes the effect of our derivative instruments in the consolidated statements of operations: Derivatives not designated as hedging instruments under ASC 815 Year Ended December 31, 2016 2015 2014 (in thousands) Gain (loss) on derivative contracts Oil commodity contracts $ (36,572 ) $ 113,295 $ 82,510 Natural gas commodity contracts (2,410 ) 10,712 14,049 Natural gas liquids commodity contracts (1,478 ) 134 — Total gain (loss) on derivative contracts $ (40,460 ) $ 124,141 $ 96,559 Other receivables include $7.8 million and $17.5 million of derivative positions settled, but not yet received as of December 31, 2016 and 2015, respectively. Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is 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 December 31, 2016: OIL DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts 1,460,000 $ 46.93 $ 48.43 $ 45.00 Collar Contracts Short Call Options 2,075,000 60.46 85.00 54.40 Long Put Options 1,527,500 48.39 50.00 47.00 Short Put Options 1,527,500 37.19 40.00 35.00 2018 Collar Contracts Short Call Options 1,825,000 60.64 60.90 60.50 Long Put Options 1,825,000 50.00 50.00 50.00 Short Put Options 1,825,000 40.00 40.00 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 December 31, 2016: NATURAL GAS DERIVATIVE CONTRACTS Volume in Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts 450,000 $ 2.47 $ 2.47 $ 2.47 Collar Contracts Short Call Options 10,220,000 3.68 3.94 3.56 Long Put Options 9,320,000 3.09 3.30 3.00 Long Call Options 1,125,000 3.44 3.56 3.25 Short Put Options 9,320,000 2.56 2.70 2.50 2018 Collar Contracts Short Call Options 6,132,000 5.34 5.53 4.00 Long Put Options 5,475,000 4.50 4.50 4.50 Short Put Options 5,475,000 4.00 4.00 4.00 In those instances where contracts are identical as to time period, volume, 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 NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, 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 December 31, 2016: NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts 5,371,800 $ 0.46 $ 0.47 $ 0.45 We had the following open financial basis swap contracts for natural gas at December 31, 2016: BASIS SWAP DERIVATIVE CONTRACTS Volume in MMBtu Reference Price 1 (1) Reference Price 2 (1) Period Weighted 12,470,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan ’17 —Dec ’17 $(0.24) 5,910,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline 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	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [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 (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.	NOTE 8 — ASSET RETIREMENT OBLIGATIONS A summary of the changes in our asset retirement obligations is included in the table below: Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 61,220 $ 62,872 $ 56,023 Liabilities incurred 1,438 1,988 1,129 Liabilities assumed with acquired producing properties — — 3,002 Liabilities settled (2,125 ) (1,794 ) (3,942 ) Liabilities transferred in sales of properties (3,036 ) (3,149 ) (1,886 ) Revisions to estimates 1,833 (773 ) 6,348 Accretion expense 2,174 2,076 2,198 Balance, end of year 61,504 61,220 62,872 Less: Current portion 376 729 1,136 Long-term portion $ 61,128 $ 60,491 $ 61,736 The total revisions included $1.3 million related to additions to property, plant and equipment for the year ended December 31, 2016. Total revisions included $1.5 million related to reductions and $2.9 million related to additions to property, plant and equipment for the years ended December 31, 2015 and 2014, respectively.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 9 — RELATED PARTY TRANSACTIONS We have notes payable to our founder which bear interest at 10% with a balance of $27.0 million and $25.7 million at December 31, 2016 and 2015, respectively. See Note 10 for further information. Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received no capital distributions during the years ended December 31, 2016 and 2015 and received $516,500 of capital distributions from us during the year ended December 31, 2014, respectively. David Murrell, our Vice President of Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2016, 2015 and 2014 were approximately $146,000, $133,000 and $150,000. The contract may be terminated by either party without penalty upon 30 days’ notice. David McClure, our Vice President of Facilities and Midstream, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $425,000, $275,000 and $450,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. David Pepper, one of our Landmen, and the cousin of our Vice President of Land and Business Development, David Murrell, received total compensation of $180,000, $146,000 and $260,000 for the years ended December 31, 2016, 2015 and 2014. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight. On January 13, 2016, our wholly-owned subsidiary Oklahoma Energy Acquisitions, LP (“Oklahoma Energy”) entered into a joint development agreement (the “joint development agreement”), with BCE-STACK Development LLC (“BCE”), a fund advised by Bayou City Energy Management LLC (“Bayou City”), to fund a portion of our drilling operations and to allow us to accelerate development of our STACK acreage. As described in Note 16, William W. McMullen and Mark Stoner, partners at Bayou City, were appointed to the board of managers of Alta Mesa Holdings GP, LLC, our general partner during the third quarter of 2016. The drilling program initially called for the development of forty identified well locations, which developed in two tranches of twenty wells each. The parties subsequently agreed to add a third and fourth tranche of investment that will allow for the drilling of an additional forty wells. On December 31, 2016, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us. See Notes 4 and 16 for further details. In connection with the acquisition of the Contributed Wells, the joint development agreement was amended to exclude the Contributed Wells from the drilling program. The drilling program will fund the development of 80 additional wells in four tranches of 20 wells each. As of December 31, 2016, 20 additional joint wells have been drilled or spudded leaving 60 wells to be drilled under the joint development agreement. Under the joint development agreement, as amended on December 31, 2016, BCE has committed to fund 100% of our working interest share up to a maximum of an average of $3.2 million in drilling and completion costs per well for any tranche. We are responsible for any drilling and completion costs exceeding the aggregate limit of $64 million in any tranche. In exchange for the payment of drilling and completion costs, BCE receives 80% of our working interest in each wellbore, which BCE interest will be reduced to 20% of our initial working interest upon BCE achieving a 15% internal rate of return on the wells within in a tranche and automatically further reduced to 12.5% of our initial interest upon BCE achieving a 25% internal rate of return. Following the completion of each joint well, we and BCE will each bear our respective proportionate working interest share of all subsequent costs and expenses related to such joint well. The approximate dollar value of the amount involved in this transaction or Messrs. McMullen or Stoner’s interests in the transaction depends on a number of factors outside their control and is not known at this time. As of December 31, 2016, we recorded $42.5 million in advances from related party on our consolidated balance sheets, which represents net advances from BCE for their working interest share of the drilling and development cost as part of the joint development agreement. During the year ended December 31, 2016, High Mesa contributed $311.3 million to us, of which $7.9 million is included in receivables due from affiliate at December 31, 2016 and the amount was collected subsequent to year-end. During the year ended December 31, 2015, High Mesa contributed $20 million to us. For additional information, see Note 16 — Partners’ Capital (Deficit). As of December 31, 2016 and 2015, approximately $0.9 million and $1.1 million, respectively, were due from High Mesa for reimbursement of expenses which is recorded in the receivables due from affiliates on the consolidated balance sheets. On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate, Northwest Gas Processing, LLC (“NWGP”), which is a subsidiary of High Mesa. We recorded $25.5 million in other receivables and $8.5 million in long-term notes receivable, while recording no gain or loss on the sale at December 31, 2014. On January 2, 2015, the receivable of $25.5 million was paid in full. The $8.5 million long-term note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019. Immediately after the consummation of the transaction, NWGP’s obligation under the $8.5 million promissory note was transferred to High Mesa Services, LLC, a subsidiary of High Mesa. The Company believes the promissory note to be fully collectible and accordingly has not recorded a reserve. Interest income on the note receivable from our affiliate amounted to $0.8 million and $0.7 million during the years ended December 31, 2016 and 2015, respectively. Such amounts have been added to the balance of the note receivable. On December 31, 2015, we repurchased land originally sold to NWGP at cost of $0.7 million. We are party to a services agreement dated January 1, 2016 with NWGP. Pursuant to the agreement, we agree to provide administrative and management services to NWGP relating to the midstream assets we sold to NWGP on December 31, 2014. During the year ended December 31, 2016, NWGP was billed for management services provided in the amount of approximately $0.1 million. On August 31, 2015, Oklahoma Energy entered into a Crude Oil Gathering Agreement (the “Crude Oil Gathering Agreement”) and Gas Gathering and Processing Agreement (the “Gas Gathering and Processing Agreement”) with KFM, which was subsequently amended and restated on February 3, 2017, effective as of December 1, 2016. High Mesa owns a minority interest in KFM. Alta Mesa also indirectly owns a minimal interest in KFM through its less than 10% ownership of AEM. We have committed the oil and natural gas production from our Kingfisher County acreage, not otherwise committed to others, to KFM for gathering and processing. Under the Crude Oil Gathering Agreement and the Gas Gathering and Processing Agreement, Oklahoma Energy dedicates and delivers to KFM crude oil and natural gas and associated natural gas liquids produced from present and future wells located in certain lands in Kingfisher, Logan, Canadian, Blaine and Garfield Counties in Oklahoma to designated receipt points on KFM’s system for gathering and processing. The Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement will remain in effect for a primary term of 15 years from the in-service date of July 1, 2016 and, after the primary term, an extended term for as long as there are wells connected to the system that continue to produce crude oil or gas in commercial (paying) quantities. Under the Crude Oil Gathering Agreement, KFM operates a crude oil gathering system for the purpose of providing gathering services to Oklahoma Energy. KFM receives from Oklahoma Energy a fixed service fee per barrel of crude oil delivered. The fixed gathering fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the crude oil gathering system. Under the Gas Gathering and Processing Agreement, KFM operates a gas gathering and processing system for the purpose of providing gathering and processing services to Oklahoma Energy. KFM provides gathering and processing services for a fixed fee. The fixed service fee consists of (i) a gathering fee assessed on the volume of gas allocated to the central receipt point, (ii) a processing fee assessed on the volume of gas allocated to the central receipt point, (iii) a dehydration fee assessed on the volume of gas allocated to the central receipt point, (iv) a compression fee for each stage of compression for any volume of gas allocated to the central receipt point and (v) a facility fee for the first four years of the agreement, at which time the facility fee is removed. Beginning in January 2021, each fee is subject to an annual percentage increase tied to the consumer price index. Oklahoma Energy also pays KFM its allocated share, if any, of the electricity consumed in the operation of the gas gathering and processing system. Under the Gas Gathering and Processing Agreement, we have secured firm processing rights of 260 MMcf/d at the expanding KFM plant. The aggregate amounts paid under the Crude Oil Gathering Agreement and Gas Gathering and Processing Agreement depends on the volumes produced and gathered pursuant to these agreements. Under such agreements, the fees for the year ended December 31, 2016 were $7.5 million. The plant commenced operations in the second quarter of 2016. These fees are recorded as marketing and transportation expense in the consolidated statements of operations. As of December 31, 2016, we accrued approximately $3.0 million as a reduction of accounts receivable on the consolidated balance sheets for fees related to marketing and transportation for the KFM plant. Subsequent to year-end, Oklahoma Energy entered into an agreement with KFM whereby the Company made a deposit of $10.0 million on January 13, 2017 to KFM to provide us with 100,000 Dth/day for firm transportation. The deposit will be released back to us as we utilize the marketing and transportation services in 2018.

Long Term Debt, Net

Long Term Debt, Net	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Long Term Debt, Net	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, (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. 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 credit facility. Senior Unsecured Notes. 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. 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. 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.	NOTE 10 — LONG TERM DEBT, NET Long-term debt, net consists of the following: December 31, December 31, (in thousands) Senior secured revolving credit facility $ 40,622 $ 152,000 Senior secured term loan — 125,000 9.625% senior unsecured notes due 2018 — 448,598 7.875% senior unsecured notes due 2024 500,000 — Unamortized deferred financing costs (10,717 ) (7,823 ) Total long-term debt, net $ 529,905 $ 717,775 Notes payable to founder $ 26,957 $ 25,748 Senior Secured Revolving Credit Facility. As of December 31, 2016, the Company had $40.6 million outstanding with $239.3 million of available borrowing capacity under the credit facility. The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. 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 4.00% as of December 31, 2016 and 2.89% as of December 31, 2015. The letters of credit outstanding as of December 31, 2016 and 2015 were $7.6 million and $65,000, respectively. 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. As of December 31, 2016, the covenants of the Company’s credit facility prohibit it from making any distributions. 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, commencing with the fiscal quarter ending December 31, 2016. As of December 31, 2016, we were in compliance with all covenants under the credit facility . Senior Secured Term Loan. For the year ended December 31, 2016, the Company recognized a loss of $4.7 million, which included unamortized deferred financing cost write-offs of $2.0 million, and are reflected in loss on extinguishment of debt in the consolidated statements of operations. Senior Unsecured Notes. The 2024 Notes will mature on December 15, 2024, and 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, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 2024 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 2024 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, the Company may, on any one or more occasions, redeem all or part of the 2024 Notes for cash at a redemption price equal to 100% of their principal amount of the 2024 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 2024 Notes may require the Company to repurchase all or a portion of the 2024 Notes for cash at a price equal to 101% of the aggregate principal amount of the 2024 Notes, plus accrued and unpaid interest, if any, to the date of repurchase. On and after December 15, 2019, the Company may redeem the 2024 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 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 2024 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 the Company’s existing and future senior indebtedness; senior in right of payment to all of the Company’s existing and future indebtedness that is expressly subordinated to the 2024 Notes or the respective guarantees; effectively subordinated to all of the Company’s existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness, including amounts outstanding under the Company’s credit facility; and structurally subordinated to all existing and future indebtedness and obligations of any of the Company’s subsidiaries that do not guarantee the 2024 Notes. The 2024 Notes contain certain covenants limiting the Issuers’ ability and the ability of the Restricted Subsidiaries (as defined in 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 the Company’s line of business. As of December 31, 2016, the covenants of the Company’s senior secured revolving credit facility prohibit it from making any distributions. Under the terms of the indenture for the 2024 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. Repurchase and Redemption of 9.625% Senior Unsecured Notes due 2018 On November 30, 2016 we commenced a tender offer for any and all outstanding 2018 Notes. The tender offer expired on December 7, 2016 and on December 8, 2016, we made payment of the aggregate principal amount of the 2018 Notes validly tendered. In connection therewith, on December 8, 2016, the Company caused to be deposited, with Wells Fargo Bank, National Association, the Trustee for the 2018 Notes (the “Trustee”), funds sufficient to redeem any 2018 Notes remained outstanding on December 8, 2016. On December 20, 2016, the Trustee executed a satisfaction and discharge (the “Satisfaction and Discharge”) of the indenture relating to the 2018 Notes. The Satisfaction and Discharge, among other things, discharged the indenture and the obligations of the Company thereunder. As a result of the tender offer and redemption, the Company repurchased and redeemed its $450 million outstanding 2018 Notes for an aggregate cost of $459.4 million, including accrued interest and fees, for the year ended December 31, 2016. For the year ended December 31, 2016, the Company recognized a loss of $13.5 million, which includes unamortized discount write-off of $0.9 million, unamortized deferred financing costs write-off of $3.2 million, tender premium of $2.5 million and accrued interest of $6.9 million, which is all reflected in loss on extinguishment of debt in the consolidated statements of operations. Notes Payable to Founder. These founder notes are unsecured and are subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 16, the founder notes were amended and restated to subordinate them to the paid in kind 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, as amended, and subordinated to the rights of the holders of Series B preferred stock to receive payments. Interest on the notes payable to our founder amounted to $1.2 million during each of the years ended December 31, 2016, 2015 and 2014. Such amounts have been added to the balance of the founder notes. Deferred financing costs. Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs, at December 31, 2016 are as follows (in thousands): Year ending December 31, 2017 $ — 2018 — 2019 — 2020 40,622 2021 26,957 Thereafter 500,000 $ 567,579 The credit facility and the 2024 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. At December 31, 2016, we were in compliance with the covenants of our debt agreements.

Accounts Payable And Accrued Li

Accounts Payable And Accrued Liabilities	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Payables and Accruals [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, (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	NOTE 11 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES The following provides the detail of accounts payable and accrued liabilities: December 31, December 31, (in thousands) Capital expenditures $ 15,155 $ 10,780 Revenues and royalties payable 12,187 5,082 Operating expenses/taxes 17,499 17,955 Interest 2,627 9,919 Compensation 5,302 5,434 Derivatives settlement payable 1,126 11,149 Other 1,164 1,201 Total accrued liabilities 55,060 61,520 Accounts payable 29,174 21,101 Accounts payable and accrued liabilities $ 84,234 $ 82,621

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	11. COMMITMENTS AND CONTINGENCIES Contingencies Environmental claims Title/lease disputes Litigation 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 Performance appreciation rights	NOTE 12 — COMMITMENTS AND CONTINGENCIES Contingencies Environmental claims Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any. Management revised the estimated liability for groundwater contamination in Florida based on our reassessment of our remediation costs and plan, which is pending approval by the State of Florida. As of December 31, 2016, our revised estimated remediation liability was approximately $0.1 million. As of December 31, 2015, we had estimated a liability of $1.3 million, based on our undiscounted engineering estimates. The obligations are included in accounts payable and accrued liabilities at December 31, 2016 and other long-term liabilities at December 31, 2015 in the accompanying consolidated balance sheets. Title/lease disputes Litigation Other contingencies We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met. Performance appreciation rights: Commitments Office and Equipment Leases At December 31, 2016, the future minimum base rentals for non-cancelable operating leases are as follows: Year Ending December 31, Amount (1) 2017 $ 3,956 2018 1,453 2019 1,545 2020 1,593 2021 1,620 Thereafter 1,207 $ 11,374 (1) These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.2 million of total sublease income through 2019. Additionally, at December 31, 2016, the Company had posted bonds in the aggregate amount of $24.0 million, primarily to cover future abandonment costs.

Significant Concentrations

Significant Concentrations	12 Months Ended
	Dec. 31, 2016
Significant Concentrations [Abstract]
Significant Concentrations	NOTE 13 — SIGNIFICANT CONCENTRATIONS We sell our oil and natural gas primarily through a marketing contract with AEM. AEM is our marketing agent and acts on our behalf to market our oil and natural gas to any purchasers identified by AEM. We are a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. The fee charged to us by AEM for marketing is recorded as a marketing and transportation expense. Our marketing agreement with AEM commenced in June 2013. This agreement will terminate in June 2018, with additional provisions for extensions beyond five years and for early termination. AEM marketed majority of our production from operated fields between 2014 and 2016. Production from non-operated fields was marketed on our behalf by the operators of those properties. For the year ended December 31, 2016, revenues marketed by AEM were $160.7 million, or 80% of total revenue excluding hedging activities. For the year ended December 31, 2015, revenues marketed by AEM were $178.2 million, or 73.9% of total revenue excluding hedging activities. For the year ended December 31, 2014, revenues marketed by AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities, and based on revenues excluding hedging activities, one major customer, Murphy Oil Corporation accounted for 10% or more of those revenues, with revenues excluding hedges of $61.2 million. We believe that the loss of any of our significant customers, or of our marketing agent AEM, would not have a material adverse effect on us because alternative purchasers are readily available.

401(k) SAVINGS PLAN

401(k) SAVINGS PLAN	12 Months Ended
	Dec. 31, 2016
Savings Plan [Abstract]
401(k) SAVINGS PLAN	NOTE 14 — 401(k) SAVINGS PLAN Employees of Alta Mesa Services, LP, our wholly owned subsidiary (“Alta Mesa Services”), and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 100% of an employee’s salary deferral contribution up to a maximum of 5% of an employee’s salary, effective January 1, 2016. Matching contributions to the plan were approximately $1,122,000, $710,000, and $683,000 for the years ended December 31, 2016, 2015 and 2014, respectively.

SIGNIFICANT RISKS AND UNCERTAIN

SIGNIFICANT RISKS AND UNCERTAINTIES	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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.	NOTE 15 — SIGNIFICANT RISKS AND UNCERTAINTIES Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. 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 the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas 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 further 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 and natural gas price derivative contracts. See Note 7.

Partners' Capital (Deficit)

Partners' Capital (Deficit)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Partners' Capital [Abstract]
Partners' Capital (Deficit)	13. PARTNERS’ CAPITAL Management and Control : 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 : 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 during the first quarter of 2017. There were no contributions during the first half of 2016.	NOTE 16 — PARTNERS’ CAPITAL (DEFICIT) 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. On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”). Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our board of directors includes one member nominated by Highbridge, five members nominated by the Class A partners and two members nominated by Bayou City. Management and Control: On August 31, 2016, our Class B partner completed the sale of preferred stock to BCE-MESA Holdings LLC (“BCE-MESA”), a fund managed by Bayou City. In connection with the sale of preferred stock, our General Partner, Class B partner, and all of our Class A partners entered into a Fourth Amended and Restated Limited Partnership Agreement (the “Amended Partnership Agreement”). The Amended Partnership Agreement provides, among other things, for certain drag-along rights, including the mandatory contribution to the Class B partner by the Class A partners of their remaining Class A units upon an initial public offering. In addition, on August 31, 2016, the owners of our General Partner entered into a Third Amended and Restated Limited Liability Company Agreement, which was amended to provide that the number of members of the board of managers of our General Partner be increased to match the number of members of the board of directors of our Class B partner. William W. McMullen, the founder and managing partner of Bayou City, was appointed to the board of managers of our General Partner. On September 30, 2016, our Class B partner completed an additional sale of preferred stock to Bayou City. In connection with this investment, Mark Stoner, as a nominee of Bayou City, was appointed to the board of managers of our General Partner. Contribution, Distribution, and Income Allocation: 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 Amended 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. In connection with the final sale of preferred stock to Bayou City, our Class B partner contributed $300 million from the Bayou City investment to us. We used a portion of the contribution to repay all amounts outstanding under the term loan facility of $127.7 million, which includes accrued interest and a $2.5 million prepayment premium for repaying all amounts owed under the term loan facility prior to maturity date. The remaining funds are available to be used for general corporate purposes. As described in Notes 4 and 9, High Mesa purchased from BCE and contributed interests in 24 producing wells drilled under the joint development agreement to us on December 31, 2016. High Mesa’s equity contribution was recorded at the contribution date 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 subsequent to year end. During 2015, our partnership agreement was amended and restated, pursuant to which our Class B partner contributed $20 million to us, which we used to pay down amounts owed under the credit facility. We made no distributions for the year ended December 31, 2016. For the year ended December 31, 2015, we made distributions of approximately $3.8 million to our Class B partner. For the year ended December 31, 2014, we made distributions of approximately $0.5 million to our founder as discussed in Note 9 and the partners’ share of taxes related to the sale of AME as discussed in Note 4.

Subsidiary Guarantors

Subsidiary Guarantors	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Guarantees 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.	NOTE 17 — SUBSIDIARY GUARANTORS All of our material wholly-owned subsidiaries are guarantors under the terms of our senior notes and our credit facility. Our consolidated financial statements reflect the combined 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.

Supplemental Quarterly Informat

Supplemental Quarterly Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Supplemental Quarterly Information	NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited) Results of operations by quarter for the year ended December 31, 2016 were: Quarter Ended 2016 March 31 June 30 Sept 30 Dec 31 (in thousands) Total operating revenues $ 38,167 $ 53,823 $ 54,532 $ 64,186 Loss from operations (1)(2) (7,967 ) (52,686 ) (8,620 ) (20,536 ) Net loss $ (24,157 ) $ (70,327 ) $ (26,567 ) $ (46,870 ) (1) Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively. (2) Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016. Results of operations by quarter for the year ended December 31, 2015 were: Quarter Ended 2015 March 31 June 30 Sept 30 Dec 31 (in thousands) Total operating revenues $ 60,542 $ 71,755 $ 61,344 $ 48,325 Income (loss) from operations (3)(4)(5) (95,077 ) (23,881 ) 110,069 (60,592 ) Net income (loss) $ (109,211 ) $ (39,509 ) $ 93,079 $ (76,152 ) (3) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. (4) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively. (5) Includes $72.0 million gain on derivative contracts during the quarter ended September 30, 2015.

Supplemental Oil And Natural Ga

Supplemental Oil And Natural Gas Disclosures	12 Months Ended
	Dec. 31, 2016
Supplemental Oil And Natural Gas Disclosures Unaudited [Abstract]
Supplemental Oil And Natural Gas Disclosures	NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited) The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235. Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States. Estimated Quantities of Proved Reserves The following table sets forth our net proved reserves as of December 31, 2016, 2015 and 2014, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Oil Gas NGL’s BOE Total Proved Reserves: Balance at December 31, 2013 32,517 132,265 5,735 60,296 Production (3,770 ) (14,449 ) (537 ) (6,715 ) Purchases in place 610 327 — 665 Discoveries and extensions 13,281 28,822 4,119 22,204 Sales of reserves in place (6,298 ) (35,857 ) (949 ) (13,223 ) Revisions of previous quantity estimates and other (4,996 ) (7,960 ) 20 (6,304 ) Balance at December 31, 2014 31,344 103,148 8,388 56,923 Production (4,203 ) (11,900 ) (678 ) (6,865 ) Discoveries and extensions 12,981 58,129 7,763 30,432 Sales of reserves in place (6,544 ) (8,250 ) (748 ) (8,667 ) Revisions of previous quantity estimates and other 564 14,296 3,712 6,660 Balance at December 31, 2015 34,142 155,423 18,437 78,483 Production (4,001 ) (13,959 ) (956 ) (7,284 ) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73 ) (966 ) (10 ) (244 ) Revisions of previous quantity estimates and other (3,680 ) 14,100 (3,794 ) (5,124 ) Balance at December 31, 2016 57,799 316,005 28,290 138,757 Proved Developed Reserves: Balance at December 31, 2014 15,182 63,334 4,028 29,765 Balance at December 31, 2015 14,942 71,752 6,958 33,859 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Proved Undeveloped Reserves: Balance at December 31, 2014 16,162 39,814 4,360 27,158 Balance at December 31, 2015 19,200 83,671 11,479 44,624 Balance at December 31, 2016 40,967 222,644 20,313 98,386 (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 9 — Related Party Transactions and Note 16 — Partners’ Capital (Deficit) for further details. Capitalized Costs Relating to Oil and Natural Gas Producing Activities December 31, 2016 2015 (in thousands) Capitalized costs: Proved properties $ 1,611,249 $ 1,345,482 Unproved properties 116,311 127,551 Total 1,727,560 1,473,033 Accumulated depreciation, depletion, amortization and impairment (1,015,398 ) (947,091 ) Net capitalized costs $ 712,162 $ 525,942 Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress. Year Ended December 31, 2016 2015 2014 (in thousands) Costs incurred during the year: Property acquisition costs Unproved (1) $ 66,788 $ 74,475 $ 33,787 Proved (2) 68,478 2,899 7,462 Exploration 28,480 34,275 59,201 Development (3) 165,796 146,299 341,594 $ 329,542 $ 257,948 $ 442,044 (1) Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million. (2) Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $65.7 million. (3) Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. Standardized Measure of Discounted Future Net Cash Flows The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available. Future cash inflows as of December 31, 2016, 2015 and 2014 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation. Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs. The following table sets forth the components of the standardized measure of discounted future net cash flows at December 31, 2016, 2015 and 2014: At December 31, 2016 2015 2014 (in thousands) Future cash flows $ 3,547,130 $ 2,395,128 $ 3,737,412 Future production costs (1,811,683 ) (860,600 ) (991,149 ) Future development costs (709,738 ) (403,953 ) (450,659 ) Future taxes on income — — — Future net cash flows 1,025,709 1,130,575 2,295,604 Discount to present value at 10 percent per annum (467,101 ) (500,979 ) (877,558 ) Standardized measure of discounted future net cash flows $ 558,608 $ 629,596 $ 1,418,046 Base price for crude oil, per Bbl, in the above computation was: $ 42.75 $ 50.28 $ 94.99 Base price for natural gas, per Mcf, in the above computation was: $ 2.49 $ 2.58 $ 4.35 No consideration was given to the Company’s hedged transactions. The estimated realized prices for natural gas liquids using a $42.75 per Bbl benchmark and adjusted for average differentials were $15.18. Natural gas liquid prices vary depending on the composition of the natural gas liquids basket and current prices for various components thereof, such as butane, ethane, and propane, among others. Changes in Standardized Measure of Discounted Future Net Cash Flows The following table sets forth the changes in standardized measure of discounted future net cash flows: Year Ended December 31, 2016 2015 2014 (in thousands) Balance at beginning of year $ 629,596 $ 1,418,046 $ 1,406,274 Sales of oil and natural gas, net of production costs (124,610 ) (147,906 ) (320,130 ) Changes in sales and transfer prices, net of production costs (324,638 ) (823,073 ) (153,770 ) Revisions of previous quantity estimates (35,972 ) 53,101 (477,377 ) Purchases of reserves-in-place 40,611 — 21,633 Sales of reserves-in-place 2,345 (244,251 ) (107,414 ) Current year discoveries and extensions 356,631 260,078 701,820 Changes in estimated future development costs 849 4,376 2,591 Development costs incurred during the year 8,363 42,420 161,357 Accretion of discount 62,960 141,805 140,627 Net change in income taxes — — — Change in production rate (timing) and other (57,527 ) (75,000 ) 42,435 Net change (70,988 ) (788,450 ) 11,772 Balance at end of year $ 558,608 $ 629,596 $ 1,418,046

SUBSEQUENT EVENT

SUBSEQUENT EVENT	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
SUBSEQUENT EVENT	15. SUBSEQUENT EVENT Alta Mesa Contribution Agreement. 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. 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.

Summary Of Significant Accoun27

Summary Of Significant Accounting Policies (Policies)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Reclassifications		The reclassifications had no impact on net income (loss) or partners’ capital (deficit).
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.	Principles of Consolidation
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.	Use of Estimates Reserve estimates significantly impact depreciation, depletion and amortization expense and impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquired properties), oil and natural gas revenues, 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. We review estimates and underlying assumptions on a regular basis. Actual results may differ from these estimates.
Cash And Cash Equivalents		Cash and Cash Equivalents
Restricted Cash		Restricted Cash.
Accounts Receivable		Accounts Receivable Accounts receivable consisted of the following: As of December 31, 2016 2015 (in thousands) Oil, natural gas and natural gas liquids sales $ 25,149 $ 17,865 Joint interest billings 13,344 10,162 Other 7 486 Allowance for doubtful accounts (889 ) (1,402 ) Total accounts receivable, net $ 37,611 $ 27,111 See Note 13 for further information regarding marketing arrangements with our primary marketing representative, ARM Energy Management, LLC (“AEM”) and significant concentrations. Accounts receivable from AEM arising from sales marketed on our behalf were $17.7 million and $12.6 million as of December 31, 2016 and 2015, respectively.
Allowance For Doubtful Accounts		Allowance for Doubtful Accounts
Deferred Financing Costs		Deferred Financing Costs.
Property And Equipment		Property and Equipment Unproved Properties Exploration Expense Proved Oil and Natural Gas Properties Impairment Our evaluation of the Company’s proved properties resulted in impairment expense of $16.1 million, $172.0 million and $72.9 million for the years ended December 31, 2016, 2015 and 2014, respectively, primarily due to lower forecasted commodity prices. Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statements of operations. For the years ended December 31, 2016, 2015 and 2014, impairment expense of unproved properties was $0.2 million, $4.8 million, and $2.0 million, respectively. Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment. If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2016, 2015 and 2014, respectively, the Company did not record any impairment expense related to other long-lived assets. Depreciation, Depletion and Amortization DD&A expense for the years ended December 31, 2016, 2015 and 2014 related to oil and natural gas properties was $90.0 million, $140.9 million, and $139.0 million, respectively. Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2016, 2015 and 2014 was $2.9 million, $3.0 million, and $2.8 million respectively.
Investments		Investments Alta Mesa is a part owner of AEM with an ownership interest of less than 10%. AEM markets our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly collections of these sales to us, and receives a 1% marketing fee. For additional information on AEM, see Note 13.
Asset Retirement Obligations		Asset Retirement Obligations
Income Taxes		Income Taxes Net income (loss) for financial statement purposes may differ significantly from taxable income (loss) reportable to limited partners as a result of differences between the tax bases and financial reporting bases of assets and liabilities and the taxable income allocation requirements under the partnership agreement. As a result, the aggregate difference in the basis of net assets for financial and tax reporting purposes cannot be readily determined as the Partnership does not have access to information about each unitholder’s tax attributes in the Partnership. However, with respect to the Partnership, the Partnership’s book basis in its net assets exceeds the Partnership’s net tax basis by $101.5 million at December 31, 2016. The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Provision for (benefit from) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax. We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement. We have considered our exposure under the standard at both the federal and state tax levels. We have not recorded any liabilities for uncertain tax positions as of December 31, 2016 and 2015. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2016, 2015 or 2014. The Company’s tax returns for the years ended December 31, 2013 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.
Revenue Recognition		Revenue Recognition
Fair Value Of Financial Instruments		Fair Value of Financial Instruments.
Acquisitions		Acquisitions
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 Deferral of the Effective Date In February 2016, the FASB issued ASU No. 2016-02 , Leases (Topic 842) ASU 2016-02, In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash (“ASU 2016-18”), In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business,	Recent Accounting Pronouncements In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers Deferral of the Effective Date In January 2016, the FASB issued ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities In February 2016, the FASB issued ASU 2016-02 , Leases (Topic 842) In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments In October 2016, the FASB issued ASU No. 2016-17, Consolidation: Interests Held through Related Parties That Are under Common Control In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business,
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.	Derivative Financial Instruments . We use derivative contracts to hedge the effects of fluctuations in the prices of oil, natural gas and natural gas liquids. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 6 for information on fair value).  Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in gain (loss) on derivative contracts in the consolidated statement of operations. Gains or losses from the settlement of matured derivatives contracts are also included in gain (loss) on derivatives contracts in the consolidated statement of operations. Cash flows from settlements of derivative contracts are classified as operating cash flows.
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.
Netting Presentation For Derivatives Policy [Member]
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.	Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets. Likewise, derivative (liabilities) could be presented in an asset account.
Commodity Derivative Contract [Member]
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 the benchmark index price and the specific locational index pricing referenced in certain of our crude oil, natural gas, and natural gas liquids sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our senior secured revolving credit facility described in Note 10 below, 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, 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 counter-parties 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.
Interest Rate Contract [Member]
Derivative Financial Instruments		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.

Summary Of Significant Accoun28

Summary Of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Schedule Of Accounts Receivable	As of December 31, 2016 2015 (in thousands) Oil, natural gas and natural gas liquids sales $ 25,149 $ 17,865 Joint interest billings 13,344 10,162 Other 7 486 Allowance for doubtful accounts (889 ) (1,402 ) Total accounts receivable, net $ 37,611 $ 27,111

Supplemental Cash Flow Inform29

Supplemental Cash Flow Information (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Supplemental Cash Flow Elements [Abstract]
Supplemental Disclosures To The Consolidated Statements Of Cash Flows	Six Months Ended 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 )	Supplemental cash flow disclosures and non-cash investing and financing activities are presented below: Year Ended December 31, 2016 2015 2014 (in thousands) Supplemental cash flow information: Cash paid for interest $ 74,694 $ 56,579 $ 51,219 Cash paid (received) for state income taxes, net of refunds 285 751 (123 ) Non-cash investing and financing activities: Change in asset retirement obligations 2,719 487 2,643 Asset retirement obligations assumed, purchased properties — — 3,002 Change in accruals or liabilities for capital expenditures 12,375 (34,160 ) 23,858 Divestiture of oil and gas properties — — (34,000 ) Acquisition of property and land — 2,473 — Contribution of interests in oil and gas properties 65,740 — — Contribution receivable 7,875 — —

ACQUISITIONS (Tables)

ACQUISITIONS (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Business Combinations [Abstract]
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 )	Total operating Net loss (in thousands) (unaudited) Pro forma results for the combined entity for the year ended December 31, 2016 $ 199,982 $ (157,230 )
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 )

PROPERTY AND EQUIPMENT (Tables)

PROPERTY AND EQUIPMENT (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Property, Plant and Equipment [Abstract]
Summary Of Property And Equipment	June 30, December 31, (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	Property and equipment consists of the following: December 31, December 31, (in thousands) OIL AND NATURAL GAS PROPERTIES Unproved properties $ 116,311 $ 127,551 Accumulated impairment (65 ) (2,684 ) Unproved properties, net 116,246 124,867 Proved oil and natural gas properties 1,611,249 1,345,482 Accumulated depreciation, depletion, amortization and impairment (1,015,333 ) (944,407 ) Proved oil and natural gas properties, net 595,916 401,075 TOTAL OIL AND NATURAL GAS PROPERTIES, net 712,162 525,942 OTHER PROPERTY AND EQUIPMENT Land 4,730 3,868 Office furniture and equipment, vehicles 19,446 18,794 Accumulated depreciation (14,445 ) (11,565 ) OTHER PROPERTY AND EQUIPMENT, net 9,731 11,097 TOTAL PROPERTY AND EQUIPMENT, net $ 721,893 $ 537,039
Capitalized Exploratory Well Costs		Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 6,006 $ 13,301 $ 20,317 Additions to capitalized well costs pending determination of proved reserves 3,736 4,364 15,870 Reclassifications to proved properties (7,484 ) (8,583 ) (6,593 ) Capitalized exploratory well costs charged to expense (169 ) (3,076 ) (16,293 ) Balance, end of year $ 2,089 $ 6,006 $ 13,301

FAIR VALUE DISCLOSURES (Tables)

FAIR VALUE DISCLOSURES (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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	Level 1 Level 2 Level 3 Total (in thousands) At December 31, 2016: Financial Assets: Derivative contracts for oil and natural gas — $ 15,773 — $ 15,773 Financial Liabilities: Derivative contracts for oil and natural gas — $ 40,656 — $ 40,656 At December 31, 2015: Financial Assets: Derivative contracts for oil and natural gas — $ 166,106 — $ 166,106 Financial Liabilities: Derivative contracts for oil and natural gas — $ 61,840 — $ 61,840

Derivative Financial Instrume33

Derivative Financial Instruments (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Fair Values Of Derivative Contracts	Fair Values of Derivative Contracts: June 30, 2017 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current assets $ 19,405 $ (4,403 ) $ 15,002 Derivative financial instruments, long-term 16,668 (7,795 ) 8,873 Total $ 36,073 $ (12,198 ) $ 23,875 Balance sheet location Gross Gross amounts Net Fair (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 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current assets $ 3,296 $ (3,213 ) $ 83 Derivative financial instruments, long-term 12,477 (11,754 ) 723 Total $ 15,773 $ (14,967 ) $ 806 Balance sheet location Gross Gross amounts Net Fair (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	December 31, 2016 Balance sheet location Gross Gross amounts Net Fair (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 Balance sheet location Gross Gross amounts Net Fair (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 December 31, 2015 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current assets $ 86,000 $ (23,369 ) $ 62,631 Derivative financial instruments, long-term assets 80,106 (38,471 ) 41,635 Total $ 166,106 $ (61,840 ) $ 104,266 Balance sheet location Gross Gross amounts Net Fair (in thousands) Derivative financial instruments, current liabilities $ 23,369 $ (23,369 ) $ — Derivative financial instruments, long-term liabilities 38,471 (38,471 ) — Total $ 61,840 $ (61,840 ) $ —
Effect Of Derivative Instruments In The Consolidated Statements Of Operations	Derivatives not designated as hedging instruments under ASC 815 Three Months Ended Six Months Ended 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 )	Derivatives not designated as hedging instruments under ASC 815 Year Ended December 31, 2016 2015 2014 (in thousands) Gain (loss) on derivative contracts Oil commodity contracts $ (36,572 ) $ 113,295 $ 82,510 Natural gas commodity contracts (2,410 ) 10,712 14,049 Natural gas liquids commodity contracts (1,478 ) 134 — Total gain (loss) on derivative contracts $ (40,460 ) $ 124,141 $ 96,559
Oil Derivative Contracts [Member]
Open Derivative Contracts	OIL DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract 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	Volume Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts 1,460,000 $ 46.93 $ 48.43 $ 45.00 Collar Contracts Short Call Options 2,075,000 60.46 85.00 54.40 Long Put Options 1,527,500 48.39 50.00 47.00 Short Put Options 1,527,500 37.19 40.00 35.00 2018 Collar Contracts Short Call Options 1,825,000 60.64 60.90 60.50 Long Put Options 1,825,000 50.00 50.00 50.00 Short Put Options 1,825,000 40.00 40.00 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]
Open Derivative Contracts	NATURAL GAS DERIVATIVE CONTRACTS Volume in Weighted Range Period and Type of Contract 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	Volume in Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts 450,000 $ 2.47 $ 2.47 $ 2.47 Collar Contracts Short Call Options 10,220,000 3.68 3.94 3.56 Long Put Options 9,320,000 3.09 3.30 3.00 Long Call Options 1,125,000 3.44 3.56 3.25 Short Put Options 9,320,000 2.56 2.70 2.50 2018 Collar Contracts Short Call Options 6,132,000 5.34 5.53 4.00 Long Put Options 5,475,000 4.50 4.50 4.50 Short Put Options 5,475,000 4.00 4.00 4.00
Natural Gas Liquids Derivative Contracts [Member]
Open Derivative Contracts	NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS Volume Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts Short Price Swaps 3,091,200 $ 0.47 $ 0.47 $ 0.47	Volume Weighted Range Period and Type of Contract High Low 2017 Price Swap Contracts 5,371,800 $ 0.46 $ 0.47 $ 0.45
Basis Swap Derivative Contract [Member]
Natural Gas Basis Swap Contracts	We had the following open financial basis swaps at June 30, 2017: BASIS SWAP DERIVATIVE CONTRACTS Volume in MMBtu (1) Reference Price 1 Reference Price 2 Period Weighted 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.	Volume in MMBtu Reference Price 1 (1) Reference Price 2 (1) Period Weighted 12,470,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline Jan ’17 —Dec ’17 $(0.24) 5,910,000 NYMEX Henry Hub Tex/OKL Panhandle Eastern Pipeline 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	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Summary Of Changes In Asset Retirement Obligations	Six Months (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	Year Ended December 31, 2016 2015 2014 (in thousands) Balance, beginning of year $ 61,220 $ 62,872 $ 56,023 Liabilities incurred 1,438 1,988 1,129 Liabilities assumed with acquired producing properties — — 3,002 Liabilities settled (2,125 ) (1,794 ) (3,942 ) Liabilities transferred in sales of properties (3,036 ) (3,149 ) (1,886 ) Revisions to estimates 1,833 (773 ) 6,348 Accretion expense 2,174 2,076 2,198 Balance, end of year 61,504 61,220 62,872 Less: Current portion 376 729 1,136 Long-term portion $ 61,128 $ 60,491 $ 61,736

Long Term Debt, Net (Tables)

Long Term Debt, Net (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
Long-Term Debt, Net	June 30, December 31, (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	December 31, December 31, (in thousands) Senior secured revolving credit facility $ 40,622 $ 152,000 Senior secured term loan — 125,000 9.625% senior unsecured notes due 2018 — 448,598 7.875% senior unsecured notes due 2024 500,000 — Unamortized deferred financing costs (10,717 ) (7,823 ) Total long-term debt, net $ 529,905 $ 717,775 Notes payable to founder $ 26,957 $ 25,748
Summary Of Future Maturities Of Long-Term Debt		Future maturities of long-term debt, including the notes payable to our founder and excluding unamortized deferred financing costs, at December 31, 2016 are as follows (in thousands): Year ending December 31, 2017 $ — 2018 — 2019 — 2020 40,622 2021 26,957 Thereafter 500,000 $ 567,579

Accounts Payable And Accrued 36

Accounts Payable And Accrued Liabilities (Tables)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Detail Of Accounts Payable And Accrued Liabilities	June 30, December 31, (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	December 31, December 31, (in thousands) Capital expenditures $ 15,155 $ 10,780 Revenues and royalties payable 12,187 5,082 Operating expenses/taxes 17,499 17,955 Interest 2,627 9,919 Compensation 5,302 5,434 Derivatives settlement payable 1,126 11,149 Other 1,164 1,201 Total accrued liabilities 55,060 61,520 Accounts payable 29,174 21,101 Accounts payable and accrued liabilities $ 84,234 $ 82,621

Commitments And Contingencies (

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Future Base Rentals For Non-Cancelable Leases	Year Ending December 31, Amount (1) 2017 $ 3,956 2018 1,453 2019 1,545 2020 1,593 2021 1,620 Thereafter 1,207 $ 11,374 (1) These amounts include long-term lease payments for office space and compressors, net of sublease income. The Company expects to receive $0.2 million of total sublease income through 2019.

Supplemental Quarterly Inform38

Supplemental Quarterly Information (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Summary Of Quarterly Results Of Operations	Results of operations by quarter for the year ended December 31, 2016 were: Quarter Ended 2016 March 31 June 30 Sept 30 Dec 31 (in thousands) Total operating revenues $ 38,167 $ 53,823 $ 54,532 $ 64,186 Loss from operations (1)(2) (7,967 ) (52,686 ) (8,620 ) (20,536 ) Net loss $ (24,157 ) $ (70,327 ) $ (26,567 ) $ (46,870 ) (1) Includes $1.8 million, $11.6 million, and $2.1 million of impairment expense during the quarters ended March 31, 2016, June 30, 2016, and December 31, 2016, respectively. (2) Includes $38.3 million and $16.5 million loss on derivative contracts during the quarters ended June 30, 2016 and December 31, 2016. Results of operations by quarter for the year ended December 31, 2015 were: Quarter Ended 2015 March 31 June 30 Sept 30 Dec 31 (in thousands) Total operating revenues $ 60,542 $ 71,755 $ 61,344 $ 48,325 Income (loss) from operations (3)(4)(5) (95,077 ) (23,881 ) 110,069 (60,592 ) Net income (loss) $ (109,211 ) $ (39,509 ) $ 93,079 $ (76,152 ) (3) Includes $66.4 million gain on sale of asset during the quarter ended September 30, 2015. (4) Includes $73.1 million, $8.9 million, and $90.5 million of impairment expense during the quarters ended March 31, 2015, September 30, 2015, and December 31, 2015, respectively. (5) Includes $72.0 million gain on derivative contracts during the quarter ended September 30, 2015.

Supplemental Oil And Natural 39

Supplemental Oil And Natural Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2016
Supplemental Oil And Natural Gas Disclosures Unaudited [Abstract]
Estimated Quantities Of Proved Reserves	Oil Gas NGL’s BOE Total Proved Reserves: Balance at December 31, 2013 32,517 132,265 5,735 60,296 Production (3,770 ) (14,449 ) (537 ) (6,715 ) Purchases in place 610 327 — 665 Discoveries and extensions 13,281 28,822 4,119 22,204 Sales of reserves in place (6,298 ) (35,857 ) (949 ) (13,223 ) Revisions of previous quantity estimates and other (4,996 ) (7,960 ) 20 (6,304 ) Balance at December 31, 2014 31,344 103,148 8,388 56,923 Production (4,203 ) (11,900 ) (678 ) (6,865 ) Discoveries and extensions 12,981 58,129 7,763 30,432 Sales of reserves in place (6,544 ) (8,250 ) (748 ) (8,667 ) Revisions of previous quantity estimates and other 564 14,296 3,712 6,660 Balance at December 31, 2015 34,142 155,423 18,437 78,483 Production (4,001 ) (13,959 ) (956 ) (7,284 ) Purchases in place (1) 1,508 6,754 613 3,247 Discoveries and extensions 29,903 154,653 14,000 69,679 Sales of reserves in place (73 ) (966 ) (10 ) (244 ) Revisions of previous quantity estimates and other (3,680 ) 14,100 (3,794 ) (5,124 ) Balance at December 31, 2016 57,799 316,005 28,290 138,757 Proved Developed Reserves: Balance at December 31, 2014 15,182 63,334 4,028 29,765 Balance at December 31, 2015 14,942 71,752 6,958 33,859 Balance at December 31, 2016 16,832 93,361 7,977 40,371 Proved Undeveloped Reserves: Balance at December 31, 2014 16,162 39,814 4,360 27,158 Balance at December 31, 2015 19,200 83,671 11,479 44,624 Balance at December 31, 2016 40,967 222,644 20,313 98,386 (1) Purchases in place includes 3.1 MMBoe of reserves related to the Contributed Wells from our Class B partner. See Note 9 — Related Party Transactions and Note 16 — Partners’ Capital (Deficit) for further details.
Capitalized Costs Relating To Oil And Natural Gas Producing Activities	December 31, 2016 2015 (in thousands) Capitalized costs: Proved properties $ 1,611,249 $ 1,345,482 Unproved properties 116,311 127,551 Total 1,727,560 1,473,033 Accumulated depreciation, depletion, amortization and impairment (1,015,398 ) (947,091 ) Net capitalized costs $ 712,162 $ 525,942
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities	Year Ended December 31, 2016 2015 2014 (in thousands) Costs incurred during the year: Property acquisition costs Unproved (1) $ 66,788 $ 74,475 $ 33,787 Proved (2) 68,478 2,899 7,462 Exploration 28,480 34,275 59,201 Development (3) 165,796 146,299 341,594 $ 329,542 $ 257,948 $ 442,044 (1) Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million. (2) Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $65.7 million. (3) Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Components Of The Standardized Measure Of Discounted Future Net Cash Flows	At December 31, 2016 2015 2014 (in thousands) Future cash flows $ 3,547,130 $ 2,395,128 $ 3,737,412 Future production costs (1,811,683 ) (860,600 ) (991,149 ) Future development costs (709,738 ) (403,953 ) (450,659 ) Future taxes on income — — — Future net cash flows 1,025,709 1,130,575 2,295,604 Discount to present value at 10 percent per annum (467,101 ) (500,979 ) (877,558 ) Standardized measure of discounted future net cash flows $ 558,608 $ 629,596 $ 1,418,046 Base price for crude oil, per Bbl, in the above computation was: $ 42.75 $ 50.28 $ 94.99 Base price for natural gas, per Mcf, in the above computation was: $ 2.49 $ 2.58 $ 4.35
Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows	Year Ended December 31, 2016 2015 2014 (in thousands) Balance at beginning of year $ 629,596 $ 1,418,046 $ 1,406,274 Sales of oil and natural gas, net of production costs (124,610 ) (147,906 ) (320,130 ) Changes in sales and transfer prices, net of production costs (324,638 ) (823,073 ) (153,770 ) Revisions of previous quantity estimates (35,972 ) 53,101 (477,377 ) Purchases of reserves-in-place 40,611 — 21,633 Sales of reserves-in-place 2,345 (244,251 ) (107,414 ) Current year discoveries and extensions 356,631 260,078 701,820 Changes in estimated future development costs 849 4,376 2,591 Development costs incurred during the year 8,363 42,420 161,357 Accretion of discount 62,960 141,805 140,627 Net change in income taxes — — — Change in production rate (timing) and other (57,527 ) (75,000 ) 42,435 Net change (70,988 ) (788,450 ) 11,772 Balance at end of year $ 558,608 $ 629,596 $ 1,418,046

SUBSEQUENT EVENT (Tables)

SUBSEQUENT EVENT (Tables)	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
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

Summary Of Significant Accoun41

Summary Of Significant Accounting Policies (Narrative) (Detail) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary Of Significant Accounting Policies [Line Items]
FDIC insured maximum amount		$ 250,000
Accounts receivable		37,611,000	$ 27,111,000
Impairment expense of proved properties		16,100,000	172,000,000	$ 72,900,000
Impairment expense of unproved properties		200,000	4,800,000	2,000,000
Other write-downs and impairment expense		0	0	0
Depreciation depletion and amortization related to oil and gas properties		90,000,000	140,900,000	139,000,000
Depreciation expense for other property and equipment		$ 2,900,000	3,000,000	2,800,000
Ownership interest in a drilling company		10.17%
Investment in LLC - cost	$ 9,000,000	$ 9,000,000	9,000,000
Amount of excess of net assets		101,500,000
Liability for uncertain tax positions		0	0
Income tax penalties and interest		0	0	$ 0
Notes payable		567,579,000
Fair value of senior notes payable	$ 507,500,000	520,000,000
7.875% Senior Unsecured Notes Due 2024 [Member]
Summary Of Significant Accounting Policies [Line Items]
Notes payable		$ 500,000,000
Stated interest rate of senior notes	7.875%	7.875%
Maturity date of debt	Dec. 15, 2024	Dec. 15, 2024
Minimum [Member] | Other Property And Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment		3 years
Maximum [Member] | Other Property And Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment		7 years
ARM Energy Management, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable		$ 17,700,000	$ 12,600,000

Summary Of Significant Accoun42

Summary Of Significant Accounting Policies (Schedule Of Accounts Receivable ) (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Abstract]
Oil, natural gas and natural gas liquids sales	$ 25,149	$ 17,865
Joint interest billings	13,344	10,162
Other	7	486
Allowance for doubtful accounts	(889)	(1,402)
Total accounts receivable net	$ 37,611	$ 27,111

Supplemental Cash Flow Inform43

Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 23,452	$ 31,071	$ 74,694	$ 56,579	$ 51,219
Cash paid for state income taxes		422	285	751	(123)
Non-cash Investing And Financing Activities:
Change in asset retirement obligations	235	577	2,719	487	2,643
Asset retirement obligations assumed, purchased properties	89				3,002
Change in accruals or liabilities for capital expenditures	$ 37,494	$ (4,869)	12,375	(34,160)	23,858
Non-cash divestiture of oil and gas properties					$ (34,000)
Non-cash acquisition of property and land				$ 2,473
Non-cash contribution of interests in oil and gas properties			65,740
Contribution receivable			$ 7,875

Significant Acquisitions And Di

Significant Acquisitions And Divestitures (Narrative) (Detail) $ in Thousands

Jul. 07, 2017USD ($)

Jul. 06, 2015USD ($)a

Sep. 20, 2014USD ($)

Sep. 19, 2014USD ($)MMcf

Mar. 25, 2014USD ($)

Mar. 31, 2016USD ($)

Mar. 31, 2014USD ($)

Jun. 30, 2017USD ($)

Sep. 30, 2015USD ($)

Dec. 31, 2016USD ($)Item

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)MMBbls

Jul. 01, 2015MMBbls

Business Acquisition [Line Items]

Contribution

$ 65,740

Cash contribution

11,300

Cash collected

7,900

Other receivables

$ 3,780

8,061

$ 18,526

Deposit for the purchase and sale agreement

4,600

Alta Mesa Eagle Llc Divestiture [Member]

Business Acquisition [Line Items]

Initial cash purchase price for properties sold

$ 118,000

Cash purchase price

125,000

Additional contingent payment

$ 7,000

Other receivables

122,000

Adjusted cash purchase price, net of costs of transaction

4,000

Gain on sale of oil and gas properties

67,600

$ 72,500

Estimated proved reserves | MMBbls

7.8

Operating income from sold oil and gas properties

$ 68,900

118,500

Undeveloped Leasehold In Oklahoma [Member]

Business Acquisition [Line Items]

Cash consideration for Undeveloped Leasehold

$ 10,600

Kingfisher Leasehold [Member]

Business Acquisition [Line Items]

Cash consideration for Undeveloped Leasehold

$ 46,200

Net acres | a | a

19,000

Eagleville Divestiture [Member]

Business Acquisition [Line Items]

Initial cash purchase price for properties sold

$ 173,000

Cash purchase price

$ 171,000

Gain on sale of oil and gas properties

$ 72,500

Operating income from sold oil and gas properties

$ 11,100

Date of acquisition or sale of properties

Mar. 25, 2014

Percentage of original working interest net profits interest in wells is retained on, 2014

50.00%

Percentage of original working interest net profits interest in wells is retained on, 2015

30.00%

Percentage of original working interest net profits interest in wells is retained on, 2016

15.00%

Percentage of original working interest net profits interest in wells is retained on, 2017

0.00%

Percentage of undivided interest in mineral leases and interests included in sale

30.00%

Percentage of working interest in all wells in progress on December 31, 2013 or drilled after January 1, 2014 included in sale

30.00%

Eagleville Divestiture [Member] | BOE [Member]

Business Acquisition [Line Items]

Estimated proved reserves | MMBbls

7.5

Hilltop Divestiture 2014 [Member]

Business Acquisition [Line Items]

Cash purchase price

$ 38,900

$ 41,600

Gain on sale of oil and gas properties

$ 15,900

Operating income from sold oil and gas properties

$ 7,700

Date of acquisition or sale of properties

Sep. 19, 2014

Hilltop Divestiture 2014 [Member] | Natural Gas In Mmcf [Member]

Business Acquisition [Line Items]

Estimated proved reserves | MMcf

29,800

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]

Business Acquisition [Line Items]

Contribution

$ 0

$ 65,700

Cash contribution

$ 11,300

Cash collected

$ 7,900

High Mesa [Member] | Contributed Wells [Member]

Business Acquisition [Line Items]

Number of wells | Item

24

Subsequent Event [Member]

Business Acquisition [Line Items]

Adjusted cost of business acquisition

$ 40,400

Significant Acquisitions And 45

Significant Acquisitions And Divestitures (Summary Of Pro Forma Information) (Detail) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Business Combinations [Abstract]
Pro forma revenues	$ 155,474	$ 92,033	$ 199,982
Pro forma income (loss)	$ 8,016	$ (92,864)	$ (157,230)

Property And Equipment (Summary

Property And Equipment (Summary Of Property And Equipment) (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Property And Equipment [Abstract]
Unproved properties	$ 102,922	$ 116,311	$ 127,551
Accumulated impairment	(18,893)	(65)	(2,684)
Unproved properties, net	84,029	116,246	124,867
Proved oil and natural gas properties	1,814,057	1,611,249	1,345,482
Accumulated depreciation, depletion, amortization and impairment	(1,075,588)	(1,015,333)	(944,407)
Proved oil and natural gas properties, net	738,469	595,916	401,075
TOTAL OIL AND NATURAL GAS PROPERTIES, net	822,498	712,162	525,942
Land	5,339	4,730	3,868
Office furniture and equipment, vehicles	20,135	19,446	18,794
Accumulated depreciation	(15,784)	(14,445)	(11,565)
Other property and equipment, net	9,690	9,731	11,097
TOTAL PROPERTY AND EQUIPMENT, net	$ 832,188	$ 721,893	$ 537,039

Property And Equipment (Capital

Property And Equipment (Capitalized Exploratory Well Costs) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property And Equipment [Abstract]
Capitalized Exploratory Well Costs, Beginning Balance	$ 6,006	$ 13,301	$ 20,317
Additions to capitalized well costs pending determination of proved reserves	3,736	4,364	15,870
Reclassifications to proved properties	(7,484)	(8,583)	(6,593)
Capitalized exploratory well costs charged to expense	(169)	(3,076)	(16,293)
Capitalized Exploratory Well Costs, Ending Balance	$ 2,089	$ 6,006	$ 13,301

Property And Equipment (Narrati

Property And Equipment (Narrative) (Detail) $ in Millions	Dec. 31, 2016USD ($)Item	Dec. 31, 2015USD ($)
Property And Equipment [Abstract]
Number of wells included in ending balance in deferred capitalized exploratory well costs	5
Number of prospects	3
Capitalized exploratory well costs that have been capitalized for period greater than one year | $	$ 0.7	$ 3

Fair Value Disclosures (Narrati

Fair Value Disclosures (Narrative) (Detail) - USD ($) $ in Thousands	3 Months Ended							6 Months Ended		12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Mar. 31, 2015	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Carrying value of oil and gas properties	$ 32,800		$ 24,200					$ 36,200	$ 27,500	$ 33,900	$ 499,600	$ 148,400
Written down fair value of oil and gas properties	4,900		12,600					7,100	14,200	17,600	322,800	73,500
Impairment charges to oil and gas properties	27,904	$ 2,100	$ 11,555	$ 1,800	$ 90,500	$ 8,900	$ 73,100	29,124	13,319	16,306	176,774	$ 74,927
Asset retirement obligation measured at fair value								700	$ 600	1,400	$ 2,000
Face value of senior notes issued	500,000							500,000
Fair value of senior notes payable	$ 507,500	$ 520,000						$ 507,500		$ 520,000

Fair Value Disclosures - Measur

Fair Value Disclosures - Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Financial Assets:
Commodity derivative contracts, gross	$ 36,073	$ 15,773	$ 166,106
Financial Liabilities:
Commodity derivative contracts, gross	12,198	40,656	61,840
Commodity Derivative Contract [Member]
Financial Assets:
Commodity derivative contracts, gross	36,073	15,773	166,106
Financial Liabilities:
Commodity derivative contracts, gross	12,198	40,656	61,840
Level 2 [Member] | Commodity Derivative Contract [Member]
Financial Assets:
Commodity derivative contracts, gross	36,073	15,773	166,106
Financial Liabilities:
Commodity derivative contracts, gross	$ 12,198	$ 40,656	$ 61,840

Derivative Financial Instrume51

Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Gross Fair Value of Assets	$ 36,073	$ 15,773	$ 166,106
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(12,198)	(14,967)	(61,840)
Derivative Asset, Net Fair Value of Assets presented in the Balance Sheet	23,875	806	104,266
Gross Fair Value of Liabilities	12,198	40,656	61,840
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(12,198)	(14,967)	(61,840)
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	86,000
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(4,403)	(3,213)	(23,369)
Derivative Asset, Net Fair Value of Assets presented in the Balance Sheet	15,002	83	62,631
Derivative Asset Non-Current [Member]
Derivatives, Fair Value [Line Items]
Gross Fair Value of Assets	16,668	12,477	80,106
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(7,795)	(11,754)	(38,471)
Derivative Asset, Net Fair Value of Assets presented in the Balance Sheet	8,873	723	41,635
Derivative Liabilities Current [Member]
Derivatives, Fair Value [Line Items]
Gross Fair Value of Liabilities	4,403	24,420	23,369
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(4,403)	(3,213)	(23,369)
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	38,471
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	$ (7,795)	(11,754)	$ (38,471)
Derivative Liability, Net Fair Value of Liabilities presented in the Balance Sheet		$ 4,482

Derivative Financial Instrume52

Derivative Financial Instruments - Effect Of Derivative Instruments In The Consolidated Statements Of Operations (Detail) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended		12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Sep. 30, 2015	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments, Gain [Line Items]
Total gain (loss) on derivative contracts	$ 18,250	$ 16,500	$ (38,293)	$ 72,000	$ 48,492	$ (27,478)	$ (40,460)	$ 124,141	$ 96,559
Derivatives Not Designated As Hedging Instruments [Member] | Oil Commodity Contracts [Member]
Derivative Instruments, Gain [Line Items]
Total gain (loss) on derivative contracts	16,451		(31,517)		42,537	(23,371)	(36,572)	113,295	82,510
Derivatives Not Designated As Hedging Instruments [Member] | Natural Gas Commodity Contracts [Member]
Derivative Instruments, Gain [Line Items]
Total gain (loss) on derivative contracts	1,830		(6,584)		5,728	(3,770)	(2,410)	10,712	$ 14,049
Derivatives Not Designated As Hedging Instruments [Member] | Natural Gas Liquids Commodity Contract [Member]
Derivative Instruments, Gain [Line Items]
Total gain (loss) on derivative contracts	$ (31)		$ (192)		$ 227	$ (337)	$ (1,478)	$ 134

Derivative Financial Instrume53

Derivative Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative receivables	$ 7.8	$ 17.5
Derivative Asset, Setoff Rights, Description	Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is 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.

Derivative Financial Instrume54

Derivative Financial Instruments - (Oil Derivative Contracts) (Detail) - Oil Derivative Contracts [Member]	6 Months Ended	12 Months Ended
	Jun. 30, 2017$ / bblbbl	Dec. 31, 2016$ / bblbbl
Price Swap Contracts [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,133,500	1,460,000
Weighted Average Swap Price	50.39	46.93
Price Swap Contracts [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Weighted Average Swap Price	57.25	48.43
Price Swap Contracts [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Weighted Average Swap Price	46	45
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
Short Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	989,000	2,075,000
Weighted Average Option Price	60.47	60.46
Short Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	85	85
Short Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	54.40	54.40
Short Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,190,000	1,825,000
Weighted Average Option Price	60.87	60.64
Short Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	62	60.90
Short Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60.50	60.50
Short Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000	1,241,000
Weighted Average Option Price	62.90	62.90
Short Call Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	63	63
Short Call Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	62.75	62.75
Long Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	835,000	1,527,500
Weighted Average Option Price	48.40	48.39
Long Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50	50
Long Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	47	47
Long Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,825,000	1,825,000
Weighted Average Option Price	50	50
Long Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50	50
Long Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	50	50
Long Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000	1,241,000
Weighted Average Option Price	50	50
Long Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50	50
Long Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	50	50
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 Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	713,000	1,527,500
Weighted Average Option Price	36.97	37.19
Short Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	40	40
Short Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	35	35
Short Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,190,000	1,825,000
Weighted Average Option Price	40.26	40
Short Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	42	40
Short Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	40	40
Short Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000	1,241,000
Weighted Average Option Price	37.50	37.50
Short Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	37.50	37.50
Short Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	37.50	37.50

Derivative Financial Instrume55

Derivative Financial Instruments - (Natural Gas Derivative Contracts) (Detail) - Natural Gas [Member]	6 Months Ended	12 Months Ended
	Jun. 30, 2017MMBTU$ / MMBTU	Dec. 31, 2016MMBTU$ / MMBTU
2017 [Member] | Price Swap Contracts [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	922,500	450,000
Weighted Average Swap Price	3.40	2.47
2017 [Member] | Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Weighted Average Swap Price	3.40	2.47
2017 [Member] | Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Weighted Average Swap Price	3.39	2.47
2017 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,072,000	10,220,000
Weighted Average Option Price	3.65	3.68
2017 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.11	3.94
2017 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.25	3.56
2017 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,304,500	9,320,000
Weighted Average Option Price	3.14	3.09
2017 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	3.60	3.30
2017 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3	3
2017 [Member] | Long Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	615,000	1,125,000
Weighted Average Option Price	2.95	3.44
2017 [Member] | Long Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	2.95	3.56
2017 [Member] | Long Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.95	3.25
2017 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,919,500	9,320,000
Weighted Average Option Price	2.59	2.56
2017 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	3	2.70
2017 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.50	2.50
2018 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,582,000	6,132,000
Weighted Average Option Price	5.26	5.34
2018 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.53	5.53
2018 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4	4
2018 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,925,000	5,475,000
Weighted Average Option Price	4.43	4.50
2018 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.50	4.50
2018 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.60	4.50
2018 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,925,000	5,475,000
Weighted Average Option Price	3.92	4
2018 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4	4
2018 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3	4

Derivative Financial Instrume56

Derivative Financial Instruments (Natural Gas Liquids Derivative Contracts) (Detail) - 2017 [Member] - Natural Gas Liquids Derivative Contracts [Member]	6 Months Ended	12 Months Ended
	Jun. 30, 2017$ / galgal	Dec. 31, 2016$ / galgal
Price Swap Contracts [Member]
Derivative [Line Items]
Volume in Gal | gal		5,371,800
Weighted Average Swap Price		0.46
Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price		0.45
Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price		0.47
Short Price Swaps [Member]
Derivative [Line Items]
Volume in Gal | gal	3,091,200
Weighted Average Swap Price	0.47
Short Price Swaps [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	0.47
Short Price Swaps [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	0.47

Derivative Financial Instrume57

Derivative Financial Instruments (Natural Gas Basis Swap Contracts) (Detail) - Basis Swap Derivative Contracts [Member]	6 Months Ended	12 Months Ended
	Jun. 30, 2017MMBTU$ / MMBTU	Dec. 31, 2016MMBTU$ / MMBTU
2017 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,135,000	12,470,000
First remaining period of term of derivative contract	Jul. 1, 2017	Jan. 1, 2017
Last remaining period of term of derivative contract	Dec. 31, 2017	Dec. 31, 2017
Weighted average spread | $ / MMBTU	(0.25)	(0.24)
2018 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,910,000	5,910,000
First remaining period of term of derivative contract	Jan. 1, 2018	Jan. 31, 2018
Last remaining period of term of derivative contract	Oct. 31, 2018	Oct. 31, 2018
Weighted average spread | $ / MMBTU	(0.27)	(0.27)

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Balance, beginning of year			$ 61,504	$ 61,220	$ 61,220	$ 62,872	$ 56,023
Liabilities incurred			584		1,438	1,988	1,129
Liabilities assumed with acquired producing properties			89				3,002
Liabilities settled			(977)		(2,125)	(1,794)	(3,942)
Liabilities transferred in sales of properties					(3,036)	(3,149)	(1,886)
Revisions to estimates			(583)		1,833	(773)	6,348
Accretion expense	$ 480	$ 536	1,052	$ 1,075	2,174	2,076	2,198
Balance, end of period	61,669		61,669		61,504	61,220	62,872
Less: Current portion	1,006		1,006		376	729	1,136
Long-term portion	$ 60,663		$ 60,663		$ 61,128	$ 60,491	$ 61,736

Asset Retirement Obligations (N

Asset Retirement Obligations (Narrative) (Detail) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Reductions To PPE Included In ARO Revisions	$ 0.3		$ 1.5
Additions To PPE Included In ARO Revisions		$ 1.3		$ 2.9

Related Party Transactions (Det

Related Party Transactions (Detail)	Jan. 13, 2017USD ($)MMBTU	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)Itemshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jan. 02, 2015USD ($)
Related Party Transaction [Line Items]
Notes payable to founder				$ 27,000,000	$ 25,700,000
Total expenditures for land consulting services				$ 146,000	133,000	$ 150,000
Contract termination period without penalty for either party				30 days
Advances from related party				$ 42,528,000
Contributions				377,076,000	20,000,000
Contribution receivable				7,875,000
Receivables due from affiliate		$ 1,688,000		$ 8,883,000	1,053,000
Amount of receivable paid							$ 25,500,000
Interest rate on note receivable				8.00%
Interest income on notes receivable		$ 406,000	$ 378,000	$ 774,000	713,000
Non-cash land acquisition from affiliate					700,000
Related party total cost				3,000,000
High Mesa [Member]
Related Party Transaction [Line Items]
Contributions				311,300,000
Receivables due from affiliate				900,000	1,100,000
Other Receivable [Member]
Related Party Transaction [Line Items]
Amount recorded for sale of partially constructed pipeline and gas processing plant						25,500,000
Long Term Note Receivable [Member]
Related Party Transaction [Line Items]
Amount recorded for sale of partially constructed pipeline and gas processing plant						8,500,000
Vice President, Facilities and Midstream [Member]
Related Party Transaction [Line Items]
Total compensation				425,000	275,000	450,000
Landman [Member]
Related Party Transaction [Line Items]
Total compensation				180,000	146,000	260,000
Founder [Member]
Related Party Transaction [Line Items]
Distributions				$ 0	$ 0	$ 516,500
BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				40
Threshold of project cost				$ 64,000,000
NWGP [Member]
Related Party Transaction [Line Items]
Receivables due from affiliate				$ 100,000
Crude Oil Gathering Agreement And Gas Gathering And Processing Agreement [Member]
Related Party Transaction [Line Items]
Period of term				15 years
Related party total cost				$ 7,500,000
Gas Gathering And Processing Agreement [Member]
Related Party Transaction [Line Items]
Allocated shares of processing rights | shares				260
Oklahoma Energy [Member]
Related Party Transaction [Line Items]
Prepaid expense	$ 10,000,000
Prepaid expense, Transporation capacity | MMBTU	100,000
ARM Energy Management, LLC [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Percentage of ownership				10.00%
Notes Payable To Founder [Member]
Related Party Transaction [Line Items]
Effective rate of interest on senior notes		10.00%		10.00%	10.00%
Joint Development Agreement [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				60
Number of wells drilled | Item				20
Joint Development Agreement [Member] | BCE-STACK [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Drilling and completion costs				$ 3,200,000
Joint Development Agreement Tranch 1 [Member]
Related Party Transaction [Line Items]
Percent of interest reduced				12.50%
Percent of internal return rate				25.00%
Joint Development Agreement Tranch 1 [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				20
Percent committed to fund				100.00%
Percent of working interest				80.00%
Percent of interest reduced				20.00%
Percent of internal return rate				15.00%
Joint Development Agreement Tranch 2 [Member]
Related Party Transaction [Line Items]
Percent of interest reduced				12.50%
Percent of internal return rate				25.00%
Joint Development Agreement Tranch 2 [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				20
Percent committed to fund				100.00%
Percent of working interest				80.00%
Percent of interest reduced				20.00%
Percent of internal return rate				15.00%
Joint Development Agreement Tranch 3 [Member]
Related Party Transaction [Line Items]
Percent of interest reduced				12.50%
Percent of internal return rate				25.00%
Joint Development Agreement Tranch 3 [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				20
Percent committed to fund				100.00%
Percent of working interest				80.00%
Percent of interest reduced				20.00%
Percent of internal return rate				15.00%
Joint Development Agreement Tranch 4 [Member]
Related Party Transaction [Line Items]
Percent of interest reduced				12.50%
Percent of internal return rate				25.00%
Joint Development Agreement Tranch 4 [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				20
Percent committed to fund				100.00%
Percent of working interest				80.00%
Percent of interest reduced				20.00%
Percent of internal return rate				15.00%
Joint Development Agreement Tranch 1, 2, 3, and 4 [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				80
Joint Development Agreement Tranch 3 and 4 [Member] | BCE-STACK [Member]
Related Party Transaction [Line Items]
Number of wells | Item				40
Contributed Wells [Member] | High Mesa [Member]
Related Party Transaction [Line Items]
Number of wells | Item				24

Long Term Debt, Net - Long-Term

Long Term Debt, Net - Long-Term Debt, Net (Detail) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Senior secured revolving credit facility	$ 195,687	$ 40,622	$ 152,000
Unamortized deferred financing costs	(10,161)	(10,717)	(7,823)
Total long-term debt, net	685,526	529,905	717,775
Notes payable to founder	27,556	26,957	25,748
Senior Notes [Member]
Debt Instrument [Line Items]
Senior Secured Term Loan			125,000
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	Dec. 15, 2024
Stated interest rate of senior notes	7.875%	7.875%
9.625% Senior Unsecured Notes Due 2018 [Member]
Debt Instrument [Line Items]
Notes payable			$ 448,598
Maturity date of debt		Oct. 15, 2018
Stated interest rate of senior notes		9.625%

Long Term Debt, Net (Narrative)

Long Term Debt, Net (Narrative) (Detail)	1 Months Ended		3 Months Ended		6 Months Ended		12 Months Ended
	Nov. 30, 2016USD ($)	Oct. 31, 2016USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Jun. 13, 2017USD ($)	Oct. 31, 2015	Jun. 02, 2015USD ($)
Shares Issued And Outstanding [Line Items]
Letter of credit outstanding							$ 7,600,000	$ 65,000
Loss on extinguishment of debt							(18,151,000)
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	25,748,000
Interest on notes payable to founder					599,000	$ 600,000	1,209,000	1,208,000	$ 1,209,000
Deferred financing costs			10,161,000		10,161,000		10,717,000	7,823,000
Amortization of deferred financing costs			500,000	$ 1,000,000	1,456,000	1,965,000	$ 3,905,000	3,392,000	$ 2,885,000
Debt covenant compliance description							At December 31, 2016, we were in compliance with the covenants of our debt agreements
Debt Instrument, Customary events of default							The credit facility and the 2024 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.
Senior secured revolving credit facility			195,687,000		$ 195,687,000		$ 40,622,000	152,000,000
Period following closing additional borrowings can be made					120 days
Deferred financing costs, net			2,299,000		$ 2,299,000		$ 3,029,000	$ 1,199,000
Federal Funds Effective Swap Rate [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate							50.00%
Eurodollar [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate							1.00%
Senior Secured Revolving Credit Facility [Member]
Shares Issued And Outstanding [Line Items]
Credit facility borrowing base	$ 300,000,000		315,000,000		315,000,000					$ 287,500,000
Credit facility amount		$ 500,000,000
Margin interest rate		25.00%
Line of Credit Facility, Remaining borrowing capacity			$ 114,000,000		$ 114,000,000
Debt instrument collateral							The principal amount is payable at maturity. The credit facility borrowing base is redetermined semi-annually, on or about May 1 and November 1 of each year. 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.
Credit facility interest rate			5.90%		5.90%		4.00%	2.89%
Letter of credit outstanding			$ 5,300,000		$ 5,300,000		$ 7,600,000
Pro forma leverage ratio					3		0.0300
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.		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. As of December 31, 2016, the covenants of the Company's credit facility prohibit it from making any distributions. 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, commencing with the fiscal quarter ending December 31, 2016.
Percent of unused distribution					20.00%		20.00%
Minimum Working Capital Ratio					100.00%		100.00%
Maximum Leverage Ratio					4		4
Deferred financing costs							$ 3,000,000
Debt covenant compliance description					As of June 30, 2017, we were in compliance with all financial covenants of the credit facility.
Date of maturity of credit facility					Nov. 10, 2010
Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Shares Issued And Outstanding [Line Items]
Credit facility applicable interest rate, description							the London Interbank Offered Rate ("LIBOR") plus applicable margins ranging from 2.75% and 3.75%
Leverage rate					325.00%		3.25%
Senior Secured Revolving Credit Facility [Member] | Prime Rate [Member]
Shares Issued And Outstanding [Line Items]
Credit facility applicable interest rate, description							plus a margin ranging from 1.75% to 2.75%
Leverage rate							3.25%
Senior Secured Revolving Credit Facility [Member] | Eurodollar [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate					1.00%
Amended And Restated Credit Facility [Member]
Shares Issued And Outstanding [Line Items]
Credit facility borrowing base							$ 287,500,000
Credit facility amount	$ 750,000,000
Maturity date of debt							Nov. 10, 2020
Percentage of proven reserves value	90.00%										85.00%
Margin interest rate	50.00%
Minimum [Member] | Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate					2.75%		2.75%
Exceeded leverage rate					3.00%		3.00%
Minimum [Member] | Senior Secured Revolving Credit Facility [Member] | Prime Rate [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate					1.75%
Exceeded leverage rate					2.00%		2.00%
Maximum [Member] | Senior Secured Revolving Credit Facility [Member]
Shares Issued And Outstanding [Line Items]
Cash distribution to a limited partner					$ 1,000,000
Maximum [Member] | Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate					3.75%		3.75%
Exceeded leverage rate					4.00%		4.00%
Maximum [Member] | Senior Secured Revolving Credit Facility [Member] | Prime Rate [Member]
Shares Issued And Outstanding [Line Items]
Margin interest rate					2.75%
Exceeded leverage rate					3.00%		3.00%
6th Amended And Restated Credit Agreement [Member]
Shares Issued And Outstanding [Line Items]
Credit facility borrowing base							$ 40,600,000
6th Amended And Restated Credit Agreement [Member] | Senior Secured Revolving Credit Facility [Member]
Shares Issued And Outstanding [Line Items]
Line of Credit Facility, Remaining borrowing capacity							$ 239,300,000
7.875% Senior Unsecured Notes Due 2024 [Member]
Shares Issued And Outstanding [Line Items]
Maturity date of debt					Dec. 15, 2024		Dec. 15, 2024
Notes payable			$ 500,000,000		$ 500,000,000		$ 500,000,000
Stated interest rate of senior notes			7.875%		7.875%		7.875%
Net proceeds							$ 491,300,000
First annual payment date					06-15		June 15
Second annual payment date					12-15		December 15
Redemption percentage of aggregate principle					65.00%		65.00%
Redemption price due to specific change of control events					101.00%
7.875% Senior Unsecured Notes Due 2024 [Member] | Debt Instrument, Redemption, Period One [Member]
Shares Issued And Outstanding [Line Items]
Redemption price			107.875%		107.875%		107.875%
Redemption price plus make-whole premium					100.00%
7.875% Senior Unsecured Notes Due 2024 [Member] | Debt Instrument, Redemption, Period Five [Member]
Shares Issued And Outstanding [Line Items]
Redemption price			100.00%		100.00%		100.00%
7.875% Senior Unsecured Notes Due 2024 [Member] | Debt Instrument, Redemption, Period Two [Member]
Shares Issued And Outstanding [Line Items]
Redemption price			105.906%		105.906%		105.906%
7.875% Senior Unsecured Notes Due 2024 [Member] | Debt Instrument, Redemption, Period Three [Member]
Shares Issued And Outstanding [Line Items]
Redemption price			103.938%		103.938%		103.938%
7.875% Senior Unsecured Notes Due 2024 [Member] | Debt Instrument, Redemption, Period Four [Member]
Shares Issued And Outstanding [Line Items]
Redemption price			101.969%		101.969%		101.969%
7.875% Senior Unsecured Notes Due 2024 [Member] | Maximum [Member]
Shares Issued And Outstanding [Line Items]
Redemption percentage of Senior Notes					35.00%
Senior Notes [Member]
Shares Issued And Outstanding [Line Items]
Redemption price							101.00%
Face value of senior notes issued							$ 450,000,000
9.625% Senior Unsecured Notes Due 2018 [Member]
Shares Issued And Outstanding [Line Items]
Maturity date of debt							Oct. 15, 2018
Loss on extinguishment of debt							$ 13,500,000
Deferred financing cost write-off							$ 3,200,000
Notes payable								$ 448,598,000
Stated interest rate of senior notes							9.625%
Repurchase amount							$ 459,400,000
Unamortized discount write-off							900,000
Unamortized premium							2,500,000
Interest expense							6,900,000
Amortization of deferred financing costs							5,100,000
Credit Facility Term Loan Facility And Senior Notes [Member]
Shares Issued And Outstanding [Line Items]
Deferred financing costs							13,700,000
Term Loan Facility And Senior Notes [Member]
Shares Issued And Outstanding [Line Items]
Deferred financing costs							10,700,000
7th Amended And Restated Credit Agreement [Member] | Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Shares Issued And Outstanding [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.
Credit Facility And Senior Notes [Member]
Shares Issued And Outstanding [Line Items]
Deferred financing costs			$ 12,500,000		$ 12,500,000
Senior Secured Term Loan [Member]
Shares Issued And Outstanding [Line Items]
Amount borrowed												$ 125,000,000
Net proceeds used to pay down outstanding amounts under existing credit facility							127,700,000
Prepayment premium							2,500,000
Loss on extinguishment of debt							4,700,000
Deferred financing cost write-off							$ 2,000,000
Notes Payable To Founder [Member]
Shares Issued And Outstanding [Line Items]
Maturity date of debt					Dec. 31, 2021		Dec. 31, 2021		Dec. 31, 2018
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.		These founder notes are unsecured and are subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 16, the founder notes were amended and restated to subordinate them to the paid in kind 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, as amended, and subordinated to the rights of the holders of Series B preferred stock to receive payments.
Effective rate of interest			10.00%		10.00%		10.00%	10.00%
Notes payable to founder			$ 27,600,000		$ 27,600,000		$ 27,000,000
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.
ayment terms, notes payable to founder					Interest and principal are payable at maturity.

Long Term Debt (Summary Of Futu

Long Term Debt (Summary Of Future Maturities Of Long-Term Debt) (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Summary of future maturities of long-term debt
2,020	$ 40,622
2,021	26,957
Thereafter	500,000
Total long-term debt	$ 567,579

Accounts Payable And Accrued 64

Accounts Payable And Accrued Liabilities (Detail Of Accounts Payable And Accrued Liabilities) (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounts Payable And Accrued Liabilities [Abstract]
Capital expenditures	$ 57,268	$ 15,155	$ 10,780
Revenues and royalties payable	20,559	12,187	5,082
Operating expenses/taxes	18,193	17,499	17,955
Interest	2,334	2,627	9,919
Compensation	3,208	5,302	5,434
Derivative settlement payable	208	1,126	11,149
Other	631	1,164	1,201
Total accrued liabilities	102,401	55,060	61,520
Accounts payable	27,824	29,174	21,101
Accounts payable and accrued liabilities	$ 130,225	$ 84,234	$ 82,621

Commitments and Contingencies65

Commitments and Contingencies (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Thousands	Jan. 01, 2017	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitment And Contingencies [Line Items]
Liability for soil contamination			$ 100	$ 1,300
Other long-term liabilities		$ 7,154	6,870	10,829
Payment under contingent commitment towards properties acquired			$ 2,200
Vesting period, PARs		5 years	5 years
Number of performance appreciation rights granted	306,300	308,800	360,000
Number of performance appreciation rights terminated	500	500	26,200
Weighted average stipulated price of PARs terminated	$ 40	$ 40	$ 40
Number of performance appreciation rights	881,100	884,200	575,300
Weighted average stipulated price of PARs granted	$ 37.90	$ 37.91	$ 36.78
Rent expense			$ 5,700	$ 4,800	$ 5,700
Performance Bonds Outstanding			$ 24,000
Stipulated initial designated price of PARs granted		$ 40
Building [Member]
Commitment And Contingencies [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases			The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease.
Upstream Equipment [Member]
Commitment And Contingencies [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases			Equipment leases are generally for four years or less
Upstream Equipment [Member] | Maximum [Member]
Commitment And Contingencies [Line Items]
Term of leases			4 years
Litigation [Member]
Commitment And Contingencies [Line Items]
Estimated litigation liability		$ 3,200	$ 4,000
Current litigation liabilities		800	800
Other long-term liabilities		$ 2,400	$ 3,200
Settlement payment term		6 years	6 years

Commitments And Contingencies66

Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)
Future base rentals for non-cancelable leases
2,017	$ 3,956
2,018	1,453
2,019	1,545
2,020	1,593
2,021	1,620
Thereafter	1,207
Total future base rental	11,374
Expected sublease income	$ 200

Significant Concentrations (Det

Significant Concentrations (Detail) $ in Thousands	3 Months Ended									6 Months Ended		12 Months Ended
	Jun. 30, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)Customer
Concentration Risk [Line Items]
Revenues	$ 95,245	$ 64,186	$ 54,532	$ 16,613	$ 38,167	$ 48,325	$ 61,344	$ 71,755	$ 60,542	$ 205,252	$ 68,243	$ 173,790	$ 433,888	$ 616,207
Benchmark for determining customer significance												revenues excluding hedging activities
Number of customers that accounted for 10% or more of revenues | Customer														1
Minimum percentage of contribution of customers to revenue														10.00%
Murphy [Member]
Concentration Risk [Line Items]
Revenues														$ 61,200
ARM Energy Management, LLC [Member]
Concentration Risk [Line Items]
Marketing fee												1.00%
Term of agreement left until extensions may come into effect												5 years
Revenues												$ 160,700	$ 178,200	$ 220,900
ARM Energy Management, LLC [Member] | AEM [Member] | Revenues [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage												80.00%	73.90%	51.10%
ARM Energy Management, LLC [Member] | Maximum [Member]
Concentration Risk [Line Items]
Percentage of ownership		10.00%										10.00%

401(k) Savings Plan (Details) (

401(k) Savings Plan (Details) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Savings Plan [Abstract]
Percentage of matching contribution by company	100.00%
Maximum percentage of employee's salary deferral contribution	5.00%
Matching contributions to the plan	$ 1,122,000	$ 710,000	$ 683,000

Significant Risks And Uncerta69

Significant Risks And Uncertainties (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016
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.	Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. 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 the lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas 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 further 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 (Deficit) (De

Partners' Capital (Deficit) (Details) (Detail) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)	Jun. 30, 2017USD ($)Item	Dec. 31, 2016USD ($)Item	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Mar. 25, 2014USD ($)
Debt Instrument [Line Items]
Number of classes of limited partners | Item		2	2
Amount of recapitalization						$ 350,000
Number of members added to Board of Directors, nominated by Highbridge | Item			1
Number of members added to Board of Directors, nominated by Class A partners | Item			5
Contributions			$ 377,076	$ 20,000
Contribution			65,740
Cash contribution			11,300
Cash collected			7,900
High Mesa [Member]
Debt Instrument [Line Items]
Contributions			$ 311,300
High Mesa [Member] | Contributed Wells [Member]
Debt Instrument [Line Items]
Number of wells | Item			24
Limited Partner [Member]
Debt Instrument [Line Items]
Distributions			$ 0	$ 3,800	$ 500
High Mesa [Member]
Debt Instrument [Line Items]
Contribution		$ 0	65,700
Cash contribution			$ 11,300
Cash collected	$ 7,900
High Mesa [Member] | Contributed Wells [Member]
Debt Instrument [Line Items]
Number of wells | Item			24
Senior Secured Term Loan [Member]
Debt Instrument [Line Items]
Prepayment premium			$ 2,500
Net proceeds used to pay down outstanding amounts under existing credit facility			$ 127,700

Supplemental Quarterly Inform71

Supplemental Quarterly Information (Summary Of Quarterly Results Of Operations) (Detail) - USD ($) $ in Thousands	3 Months Ended									6 Months Ended		12 Months Ended
	Jun. 30, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Quarterly Information [Abstract]
Total operating revenues	$ 95,245	$ 64,186	$ 54,532	$ 16,613	$ 38,167	$ 48,325	$ 61,344	$ 71,755	$ 60,542	$ 205,252	$ 68,243	$ 173,790	$ 433,888	$ 616,207
Income (loss) from operations	(2,734)	(20,536)	(8,620)	(52,686)	(7,967)	(60,592)	110,069	(23,881)	(95,077)	34,557	(60,653)	(89,809)	(69,481)	155,173
NET INCOME (LOSS)	(15,314)	(46,870)	$ (26,567)	(70,237)	(24,157)	(76,152)	93,079	$ (39,509)	(109,211)	9,601	(94,394)	(167,921)	(131,793)	99,200
Impairment expense	27,904	2,100		11,555	$ 1,800	$ 90,500	8,900		$ 73,100	29,124	13,319	16,306	176,774	74,927
Gain (loss) on derivative contracts	$ 18,250	$ 16,500		(38,293)			72,000			$ 48,492	$ (27,478)	$ (40,460)	$ 124,141	$ 96,559
Gain on sale of assets							$ 66,400
Scenario, Previously Reported [Member]
Supplemental Quarterly Information [Abstract]
Total operating revenues				53,823
NET INCOME (LOSS)				$ (70,327)

Supplemental Oil And Natural 72

Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Detail)	12 Months Ended
	Dec. 31, 2016MMcfMBbls	Dec. 31, 2015MMcfMBbls	Dec. 31, 2014MMcfMBbls
Oil [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	34,142	31,344	32,517
Production	(4,001)	(4,203)	(3,770)
Purchases in place	1,508		610
Discoveries and extensions	29,903	12,981	13,281
Sales of reserves in place	(73)	(6,544)	(6,298)
Revisions of previous quantity estimates and other	(3,680)	564	(4,996)
Proved Reserves, Ending balance	57,799	34,142	31,344
Proved Developed Reserves	16,832	14,942	15,182
Proved Undeveloped Reserves	40,967	19,200	16,162
Natural Gas [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance | MMcf	155,423	103,148	132,265
Production | MMcf	(13,959)	(11,900)	(14,449)
Purchases in place | MMcf	6,754		327
Discoveries and extensions | MMcf	154,653	58,129	28,822
Sales of reserves in place | MMcf	(966)	(8,250)	(35,857)
Revisions of previous quantity estimates and other | MMcf	14,100	14,296	(7,960)
Proved Reserves, Ending balance | MMcf	316,005	155,423	103,148
Proved Developed Reserves | MMcf	93,361	71,752	63,334
Proved Undeveloped Reserves | MMcf	222,644	83,671	39,814
Natural Gas Liquids [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	18,437	8,388	5,735
Production	(956)	(678)	(537)
Purchases in place	613
Discoveries and extensions	14,000	7,763	4,119
Sales of reserves in place	(10)	(748)	(949)
Revisions of previous quantity estimates and other	(3,794)	3,712	20
Proved Reserves, Ending balance	28,290	18,437	8,388
Proved Developed Reserves	7,977	6,958	4,028
Proved Undeveloped Reserves	20,313	11,479	4,360
BOE [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	78,483	56,923	60,296
Production	(7,284)	(6,865)	(6,715)
Purchases in place	3,247		665
Discoveries and extensions	69,679	30,432	22,204
Sales of reserves in place	(244)	(8,667)	(13,223)
Revisions of previous quantity estimates and other	(5,124)	6,660	(6,304)
Proved Reserves, Ending balance	138,757	78,483	56,923
Proved Developed Reserves	40,371	33,859	29,765
Proved Undeveloped Reserves	98,386	44,624	27,158

Supplemental Oil And Natural 73

Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Detail) - USD ($) $ in Thousands	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Capitalized costs:
Proved properties	$ 1,814,057	$ 1,611,249	$ 1,345,482
Unproved properties	102,922	116,311	127,551
Total		1,727,560	1,473,033
Accumulated depreciation, depletion, amortization and impairment		(1,015,398)	(947,091)
TOTAL OIL AND NATURAL GAS PROPERTIES, net	$ 822,498	$ 712,162	$ 525,942

Supplemental Oil And Natural 74

Supplemental Oil And Natural Gas Disclosures (Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Property acquisition costs, unproved properties	[1]	$ 66,788	$ 74,475	$ 33,787
Property acquisition costs, proved properties	[1],[2]	68,478	2,899	7,462
Costs incurred, exploration		28,480	34,275	59,201
Costs incurred, development	[3]	165,796	146,299	341,594
Costs Incurred, Total		329,542	257,948	442,044
Unproven leasehold acquisition cost			46,600
Additions to asset retirement obligations		1,900	$ (300)	$ 4,500
Stone [Member]
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Total cost of business acquisition		$ 65,700
[1]	Property acquisition costs in unproved properties in 2015 include the unevaluated leasehold portion of the Kingfisher leasehold acquisition of $46.6 million.
[2]	Property acquisition costs in the proved properties in 2016 include the Contributed Wells by our Class B partner to us of $65.7 million.
[3]	Includes asset retirement additions (revisions) of $1.9 million, ($0.3) million, and $4.5 million for the years ended December 31, 2016, 2015 and 2014, respectively.

Supplemental Oil And Natural 75

Supplemental Oil And Natural Gas Disclosures (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2016USD ($)$ / bbl$ / Mcf	Dec. 31, 2015USD ($)$ / bbl$ / Mcf	Dec. 31, 2014USD ($)$ / bbl$ / Mcf	Dec. 31, 2013USD ($)
Components of the standardized measure of discounted future net cash flows
Future cash flows	$ 3,547,130	$ 2,395,128	$ 3,737,412
Future production costs	(1,811,683)	(860,600)	(991,149)
Future development costs	(709,738)	(403,953)	(450,659)
Future taxes on income	0	0	0
Future net cash flows	1,025,709	1,130,575	2,295,604
Discount to present value at 10 percent per annum	(467,101)	(500,979)	(877,558)
Standardized measure of discounted future net cash flows	$ 558,608	$ 629,596	$ 1,418,046	$ 1,406,274
Base price for crude oil, per Bbl, in the above computation was | $ / bbl	42.75	50.28	94.99
Base price for natural gas, per Mcf, in the above computation was | $ / Mcf	2.49	2.58	4.35

Supplemental Oil And Natural 76

Supplemental Oil And Natural Gas Disclosures (Narrative) (Detail) - $ / bbl	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Supplemental Oil And Natural Gas Disclosures Unaudited [Abstract]
Base price for crude oil, per Bbl, in the above computations was	42.75	50.28	94.99
Estimated realized prices	15.18

Supplemental Oil And Natural 77

Supplemental Oil And Natural Gas Disclosures (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Components of changes in standardized measure of discounted future net cash flows
Balance at beginning of year	$ 629,596	$ 1,418,046	$ 1,406,274
Sales of oil and natural gas, net of production costs	(124,610)	(147,906)	(320,130)
Changes in sales and transfer prices, net of production costs	(324,638)	(823,073)	(153,770)
Revisions of previous quantity estimates	(35,972)	53,101	(477,377)
Purchases of reserves-in-place	40,611		21,633
Sales of reserves-in-place	2,345	(244,251)	(107,414)
Current year discoveries and extensions	356,631	260,078	701,820
Changes in estimated future development costs	849	4,376	2,591
Development costs incurred during the year	8,363	42,420	161,357
Accretion of discount	62,960	141,805	140,627
Net change in income taxes	0	0	0
Change in production rate (timing) and other	(57,527)	(75,000)	42,435
Net change	(70,988)	(788,450)	11,772
Balance at end of year	$ 558,608	$ 629,596	$ 1,418,046

Acquisitions (Summary Of Consid

Acquisitions (Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices) (Detail) - Setanta [Member] $ in Thousands	6 Months Ended
	Jun. 30, 2017USD ($)
Business Acquisition [Line Items]
Cash	$ 890
Total consideration paid	890
Plus: fair value of liabilities assumed 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)

Subsequent Event - Additional I

Subsequent Event - Additional Information (Detail) $ in Millions	Aug. 16, 2017USD ($)shares	Aug. 17, 2017USD ($)	Dec. 31, 2016USD ($)
Subsequent Event [Line Items]
Value in earn-out consideration			$ 2.2
Subsequent Event [Member] | High Mesa Holdings Lp [Member]
Subsequent Event [Line Items]
Cash contributions to be received	$ 400
SRII [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Earn-out consideration, Day for volume-weighted average price	20 days
Capital contribution		$ 200
SRII [Member] | Subsequent Event [Member] | Silver Run Acquisition Corporation Opco Lp [Member]
Subsequent Event [Line Items]
Leverage ratio	1.5
SRII [Member] | Subsequent Event [Member] | High Mesa Holdings Lp [Member] | Silver Run Acquisition Corporation Opco Lp [Member]
Subsequent Event [Line Items]
Common units | shares	220,000,000
Value in earn-out consideration	$ 800
Common Class C [Member] | SRII [Member] | Subsequent Event [Member] | Silver Run Acquisition Corporation Opco Lp [Member]
Subsequent Event [Line Items]
Redeemable days after closing	180 days
Alta Mesa Holdings Gp Llc [Member] | SRII [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Economic interests	100.00%
Voting interests	90.00%
Alta Mesa Holdings Gp Llc [Member] | Common Class A [Member] | SRII [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Economic interests	100.00%
Alta Mesa Holdings Gp Llc [Member] | Common Class B [Member] | SRII [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Economic interests	100.00%
Kingfisher Midstream Llc [Member] | SRII [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Percentage of ownership	100.00%

Subsequent Event (Earn-Out Cons

Subsequent Event (Earn-Out Consideration) (Detail) - 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