Alta Mesa 10-Q 11 May 17 2017 Q1 Quarterly report Financial data

Document And Entity Information

Document And Entity Information	3 Months Ended
	Mar. 31, 2017shares
Document And Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	1,518,403
Document Type	10-Q
Document Period End Date	Mar. 31, 2017
Amendment Flag	false
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
CURRENT ASSETS
Cash and cash equivalents	$ 5,376	$ 7,185
Short-term restricted cash	589	433
Accounts receivable, net of allowance of $895 and $889, respectively	42,985	37,611
Other receivables	567	8,061
Receivables due from affiliate	869	8,883
Prepaid expenses and other current assets	13,212	3,986
Derivative financial instruments	3,896	83
Total current assets	67,494	66,242
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	764,772	712,162
Other property and equipment, net	9,760	9,731
Total property and equipment, net	774,532	721,893
OTHER ASSETS
Investment in LLC - cost	9,000	9,000
Deferred financing costs, net	2,422	3,029
Notes receivable due from affiliate	10,187	9,987
Deposits and other long-term assets	3,292	2,977
Derivative financial instruments	7,173	723
Total other assets	32,074	25,716
TOTAL ASSETS	874,100	813,851
CURRENT LIABILITIES
Accounts payable and accrued liabilities	115,196	84,234
Advances from non-operators	3,741	4,058
Advances from related party	12,737	42,528
Asset retirement obligations	1,383	376
Derivative financial instruments	3,740	21,207
Total current liabilities	136,797	152,403
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	60,988	61,128
Long-term debt, net	585,261	529,905
Notes payable to founder	27,255	26,957
Derivative financial instruments		4,482
Other long-term liabilities	6,778	6,870
Total long-term liabilities	680,282	629,342
TOTAL LIABILITIES	817,079	781,745
Commitments and Contingencies (Note 10)
PARTNERS' CAPITAL	57,021	32,106
TOTAL LIABILITIES AND PARTNERS' CAPITAL	$ 874,100	$ 813,851

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Consolidated Balance Sheets [Abstract]
Allowance for doubtful accounts	$ 895	$ 889

Consolidated Statements Of Oper

Consolidated Statements Of Operations - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
OPERATING REVENUES AND OTHER
Oil	$ 59,345	$ 31,244
Natural gas	12,685	4,691
Natural gas liquids	7,619	2,105
Other revenues	116	127
Total operating revenues	79,765	38,167
Gain on sale of assets		2,648
Gain on derivative contracts	30,242	10,815
Total operating revenues and other	110,007	51,630
OPERATING EXPENSES
Lease and plant operating expense	17,736	17,125
Marketing and transportation expense	6,043	1,415
Production and ad valorem taxes	3,068	2,395
Workover expense	1,383	1,397
Exploration expense	8,142	3,286
Depreciation, depletion, and amortization expense	24,804	21,493
Impairment expense	1,220	1,764
Accretion expense	572	539
General and administrative expense	9,748	10,183
Total operating expenses	72,716	59,597
INCOME (LOSS) FROM OPERATIONS	37,291	(7,967)
OTHER INCOME (EXPENSE)
Interest expense	(12,340)	(16,395)
Interest income	249	206
Total other income (expense)	(12,091)	(16,189)
INCOME (LOSS) BEFORE STATE INCOME TAXES	25,200	(24,156)
Provision for state income taxes	285	1
NET INCOME (LOSS)	$ 24,915	$ (24,157)

Consolidated Statements Of Cash

Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 24,915	$ (24,157)
Adjustments to reconcile net income (loss) to net cash used in operating activities:
Depreciation, depletion, and amortization expense	24,804	21,493
Impairment expense	1,220	1,764
Accretion expense	572	539
Amortization of deferred financing costs	962	934
Amortization of debt discount		127
Dry hole expense		212
Expired leases	3,333	1,166
Gain on derivative contracts	(30,242)	(10,815)
Settlements of derivative contracts	(1,970)	25,228
Interest converted into debt	298	298
Interest on notes receivable due from affiliate	(200)	(188)
Gain on sale of assets		(2,648)
Changes in assets and liabilities:
Restricted cash	(156)	(141,935)
Accounts receivable	(5,374)	2,890
Other receivables	7,494	8,448
Receivables due from affiliate	139	(1,464)
Prepaid expenses and other non-current assets	(9,543)	845
Advances from related party	(29,791)
Settlement of asset retirement obligation	(2,394)	(191)
Accounts payable, accrued liabilities, and other liabilities	11,837	15,669
NET CASH USED IN OPERATING ACTIVITIES	(4,096)	(101,785)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	(60,589)	(44,435)
NET CASH USED IN INVESTING ACTIVITIES	(60,589)	(44,435)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	55,065	141,935
Additions to deferred financing costs	(64)	(799)
Capital contributions	7,875
NET CASH PROVIDED BY FINANCING ACTIVITIES	62,876	141,136
NET DECREASE IN CASH AND CASH EQUIVALENTS	(1,809)	(5,084)
CASH AND CASH EQUIVALENTS, beginning of period	7,185	8,869
CASH AND CASH EQUIVALENTS, end of period	$ 5,376	$ 3,785

Description Of Business

Description Of Business	3 Months Ended
	Mar. 31, 2017
Nature Of Operations [Abstract]
Description Of Business	1. DESCRIPTION OF BUSINESS Alta Mesa Holdings, LP and its subsidiaries (“we,” “us,” “our,” the “Company,” and “Alta Mesa”) is an independent exploration and production company engaged primarily in the acquisition, exploration, develop ment, and production of oil and natural gas properties . Our principal area of operation is in the eastern portion of the Anadarko Basin 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 oil and natural gas interests in Texas, Louisiana and Florida. 

Summary Of Significant Accounti

Summary Of Significant Accounting Policies	3 Months Ended
	Mar. 31, 2017
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES We have provided a discussion of significant acco unting 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 March 31, 2017 , our significant accounting policies are consistent with those discussed in Note 2 in the 2016 Annual Report. Principles of Consolidation and Reporting The consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated fina ncial statements for the year ended December 31, 2016 , which were filed with the Securities and Exchange Commission in our 2016 Annual Report. The consolidated financial statements included herein as of March 31, 2017 , and for the three months ended March 31, 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 consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain reclassifications of prior period 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 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 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 FASB issued ASU No. 2014-09, Revenue from Contracts with Customers . The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements. In February 2016, the FASB issued ASU No. 2016-02 , Leases (Topic 842), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective January 1, 2019.  In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments , which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.  In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.  In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	3 . SUPPLEMENTAL CASH FLOW INFORMATION Supplemental cash flow disclosures and non-cash investing and financing activities are presented below:     Three Months Ended March 31,  2017 2016   (in thousands)  Supplemental cash flow information:  Cash paid for interest $ 1,162 $ 3,960  Cash paid for state income taxes — 1  Non-cash investing and financing activities:  Change in asset retirement obligations 296 322  Change in accruals or liabilities for capital expenditures 21,111 (3,340)  

Property And Equipment

Property And Equipment	3 Months Ended
	Mar. 31, 2017
Property And Equipment [Abstract]
Property And Equipment	 4 . PROPERTY AND EQUIPMENT  Property and equipment consists of the following (unaudited) :    March 31, December 31,  2017 2016   (in thousands)  OIL AND NATURAL GAS PROPERTIES  Unproved properties $ 111,035 $ 116,311  Accumulated impairment of unproved properties (70) (65)  Unproved properties, net 110,965 116,246  Proved oil and natural gas properties 1,694,486 1,611,249  Accumulated depreciation, depletion, amortization and impairment (1,040,679) (1,015,333)  Proved oil and natural gas properties, net 653,807 595,916  TOTAL OIL AND NATURAL GAS PROPERTIES, net 764,772 712,162  OTHER PROPERTY AND EQUIPMENT  Land 5,172 4,730  Office furniture and equipment, vehicles 19,706 19,446  Accumulated depreciation (15,118) (14,445)  OTHER PROPERTY AND EQUIPMENT, net 9,760 9,731  TOTAL PROPERTY AND EQUIPMENT, net $ 774,532 $ 721,893 

Fair Value Disclosures

Fair Value Disclosures	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Disclosures	5 . 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 $511.3 million at March 31, 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 Not e 8 for information on long-term debt. We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to est imate 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 a s implied volatility of oil, natural gas and natural gas liquids prices. We have classified the fair values of all our oil and natural gas 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 $3.4 million were written down to their fair value of $2.2 million, resulting in an impairment charge of $1.2 million for the three months ended March 31, 2017 . For the three months ended March 31, 2016 , oil and natural gas properties with a carrying amount of $3.3 million were written down to their fair value of $1.5 million, resulting in an impairment charge of $1.8 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 $0.3 million and $0.3 million in additions to asset retirement obligations me asured at fair value during the three months ended March 31, 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 March 31, 2017 and December 31, 201 6 , and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value (unaudited) :    Level 1 Level 2 Level 3 Total   (in thousands)  At March 31, 2017:  Financial Assets:  Commodity derivative contracts — $ 28,064 — $ 28,064  Financial Liabilities:  Commodity derivative contracts — $ 20,735 — $ 20,735  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. P resentation 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 6 .

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2017
Derivative Financial Instruments [Abstract]
Derivative Financial Instruments	6. 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 8, 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 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 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 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 (unaudited):     March 31, 2017  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 10,166 $ (6,270) $ 3,896  Derivative financial instruments, long-term assets 17,898 (10,725) 7,173  Total $ 28,064 $ (16,995) $ 11,069      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 10,010 $ (6,270) $ 3,740  Derivative financial instruments, long-term liabilities 10,725 (10,725) —  Total $ 20,735 $ (16,995) $ 3,740      December 31, 2016  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 3,296 $ (3,213) $ 83  Derivative financial instruments, long-term assets 12,477 (11,754) 723  Total $ 15,773 $ (14,967) $ 806      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 24,420 $ (3,213) $ 21,207  Derivative financial instruments, long-term liabilities 16,236 (11,754) 4,482  Total $ 40,656 $ (14,967) $ 25,689  The following table summarizes the effect of our derivative instruments in the consolidated statements of operations (unaudited) :      Derivatives not Three Months Ended  designated as hedging March 31,  instruments under ASC 815 2017 2016   (in thousands)  Gain (loss) on derivative contracts  Oil commodity contracts $ 26,085 $ 8,146   Natural gas commodity contracts 3,899 2,814   Natural gas liquids commodity contracts 258 (145)  Total gain on derivative contracts $ 30,242 $ 10,815  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 March 31, 2017 (unaudited) :  OIL DERIVATIVE CONTRACTS       Volume Weighted Range  Period and Type of Contract in Bbls Average High Low  2017  Price Swap Contracts 1,710,500 $ 50.31 $ 57.25 $ 45.00  Collar Contracts  Long Call Options 137,500 85.00 85.00 85.00  Short Call Options 1,535,000 60.46 85.00 54.40  Long Put Options 1,122,500 48.35 50.00 47.00  Short Put Options 1,122,500 37.12 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 March 31, 2017 (unaudited) :  NATURAL GAS DERIVATIVE CONTRACTS      Volume in Weighted Range  Period and Type of Contract MMBtu Average High Low  2017  Price Swap Contracts 1,070,000 $ 3.40 $ 3.40 $ 3.40  Collar Contracts  Short Call Options 8,620,000 3.62 3.80 3.25  Long Put Options 7,700,000 3.11 3.30 3.00  Long Call Options 920,000 2.95 2.95 2.95  Short Put Options 8,620,000 2.57 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 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 March 31, 2017 (unaudited) :  NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS    Volume Weighted Range  Period and Type of Contract in Gal Average High Low  2017  Price Swap Contracts  Short Price Swaps 4,237,800 $ 0.46 $ 0.47 $ 0.45  We had the following open financia l basis swap contracts for natural gas March 31, 2017 (unaudited) :  BASIS SWAP DERIVATIVE CONTRACTS      Weighted  Average Spread  Volume in MMBtu (1) Reference Price 1 Reference Price 2 Period ($ per MMBtu)  9,320,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Apr'17 — Dec '17 $ (0.26)  5,910,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Jan '18 — Oct '18 (0.27)   (1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) INSIDE FERC (“IFERC”) and NYMEX Henry Hub. 

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2017
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	7 . ASSET RETIREMENT OBLIGATIONS A summary of the changes in asset retirement obligations is included in the table below (unaudited) :    Three  Months Ended  March 31, 2017  (in thousands)  Balance, beginning of year $ 61,504  Liabilities incurred 296  Liabilities settled (2,394)  Liabilities transferred in sales of properties —  Revisions to estimates 2,393  Accretion expense 572  Balance, March 31, 2017 62,371  Less: Current portion 1,383  Long-term portion $ 60,988  

Long Term Debt, Net And Notes P

Long Term Debt, Net And Notes Payable To Founder	3 Months Ended
	Mar. 31, 2017
Long Term Debt, Net And Notes Payable To Founder [Abstract]
Long Term Debt, Net And Notes Payable To Founder	8 . LONG-TERM DEBT, NET AND NOTES PAYABLE TO FOUNDER Long-term debt, net and notes payable to founder consists of the following (unaudited) :     March 31, December 31,  2017 2016   (in thousands)  Senior secured revolving credit facility $ 95,687 $ 40,622  7.875% senior unsecured notes due 2024 500,000 500,000  Unamortized deferred financing costs (10,426) (10,717)  Total long-term debt, net $ 585,261 $ 529,905  Notes payable to founder $ 27,255 $ 26,957  Senior Secured Revolving Credit Facility. In November 2016, we entered into the Seventh Amended and Restated Credit Agreement (as amended, the “credit facility”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks. As of March 31, 2017 , we had $95.7 million outstanding with $184.2 million of available borrowing capacity under the credit facility. The borrowing base is currently $287.5 million and the principal amount is payable on the maturity date of November 10, 2020 . The credit facility borrowing base is redetermined semi-annually in May and November 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 4.48% as of March 31, 2017 and 4.00% as of December 31, 2016. The letters of credit outstanding as of March 31, 2017 and December 31, 2016 were approximately $ 7.6 million.  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 March 31, 2017 , we were in compliance with all financial covenants of the cred it facility. Senior Unsecured Notes. We have $500 million in aggregate principal amount of 7.875% senior unsecured notes (“2024 Notes”) due December 15, 2024 which were issued at par by the Company and our wholly owned subsidiary Alta Mesa Finance Services Corp. (collectively, the “Issuers”) during the fourth quarter of 2016. Interest is payable semi-annually on June 15 and December 15 of each year, beginning June 15, 2017. At any time prior to December 15, 2019, we may, from time to time, redeem up to 35% of the aggregate principal amount of the 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, we 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 us 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, we 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 on December 15, 2020, 101.969% for the twelve-month period beginning on December 15, 2021 and 100.000% beginning on December 15, 2022, plus accrued and unpaid interest, if any, to the date of redemption. The 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 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 2024 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 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 our line of business. 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. The indenture governing the 2024 Notes includes covenants requiring us to maintain certain financial covenants including a current ratio and leverage ratio. As of March 31, 2017, we were in compliance with all financial covenants of the 2024 Notes . Notes Payable to Founder. We have notes payable to our founder (“Founder Notes”) that bear simple interest at 10% with a balance of $27.3 million and $27.0 million at March 31, 2017 and December 31, 2016 , respectively. The maturity date was extended on March 25, 2014 from December 31, 2018 to December 31, 2021 . Interest and principal are payable at maturity. Our founder shall convert t he notes into shares of common stock of our Class B partner, High Mesa, Inc. (“High Mesa”), upon certain conditions in the event of an initial public offering of High Mesa. These Founder Notes are unsecured and subordinate to all debt. In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 12, 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 Series B preferred stock to receive payments. Interest on the Founder Notes amounted to $0.3 million for each of the three months ended March 31, 2017 and 2016 . Such amounts have been added to the balance of the Founder Notes. Deferred financing costs. As of March 31, 2017 , we had $12.8 million of deferred financing costs related to the senior secured revolving credit facility and senior notes, which are being amortized over the respective terms of the related debt instrument. Deferred financing costs of $10.4 million related to the senior notes are netted with long-term debt on the consolidated balance sheet as of March 31, 2017 . Deferred financing costs of $2.4 million related to the credit facility are included in deferred financing costs, net on the consolidated balance sheets at March 31, 201 7 . Amortization of deferred financing costs recorded for the three months ended March 31, 2017 and 2016 was $1.0 million and $0.9 million, respectively. These costs are included in interest expense on the consolidated statements of operations. 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.

Accounts Payable And Accrued Li

Accounts Payable And Accrued Liabilities	3 Months Ended
	Mar. 31, 2017
Accounts Payable And Accrued Liabilities [Abstract]
Accounts Payable And Accrued Liabilities	9 . ACCOUNTS PAYABLE AND ACCRUED LIABILITIES The following provides the details of accounts payable and accrued liabilities (unaudited) :      March 31, December 31,  2017 2016   (in thousands)  Capital expenditures $ 29,019 $ 15,155  Revenues and royalties payable 14,491 12,187  Operating expenses/taxes 14,465 17,499  Interest 12,542 2,627  Compensation 5,277 5,302  Derivative settlement payable 571 1,126  Other 972 1,164  Total accrued liabilities 77,337 55,060  Accounts payable 37,859 29,174  Accounts payable and accrued liabilities $ 115,196 $ 84,234 

Commitments And Contingencies

Commitments And Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments And Contingencies [Abstract]
Commitments And Contingencies	10 . COMMITMENTS AND CONTINGENCIES Contingencies Environmental claims : Various landowners have sued us in lawsuits concerning several fields in which we have or historically had operations. The lawsuits seek injunctive relief and other relief, including unspecified amounts in both actual and punitive damages for alleged breaches of mineral leases and alleged failure to restore the plaintiffs’ lands from alleged contamination and otherwise from our oil and natural gas operations. We are unable to express an opinion with respect to the likelihood of an unfavorable outcome of the various environmental claims or to estimate the amount or range of potential loss should the outcome be unfavorable. Therefore, we have not provided any material amounts for these claims in our consolidated financial statements at March 31, 2017 . Title/lease disputes : Title and lease disputes may arise in the normal course of our operations. These disputes are usually small but could result in an increase or decrease in reserves and/or other forms of settlement, such as cash, once a final resolution to the title dispute is made. Litigation : On April 13, 2005, Henry Sarpy and several other plaintiffs (collectively, “Plaintiffs”) filed a petition against Exxon, Extex, the Meridian Resource Company (“TMRC,” our wholly-owned subsidiary), and the State of Louisiana for contamination of their land in the New Sarpy and/or Good Hope Field in St. Charles Parish. Plaintiffs claim they are owners of land upon which oil field waste pits containing dangerous and contaminating substances are located. Plaintiffs alleged that they discovered in May 2004 that their property is contaminated with oil field wastes greater than represented by Exxon. The property was originally owned by Exxon and was sold to TMRC. TMRC subsequently sold the property to Extex. We have been defending this ongoing case and investigating the scope of the Plaintiffs’ alleged damage. On April 14, 2015, TMRC entered into a Memorandum of Understanding with Exxon to settle the claims in this ongoing matter. On July 10, 2015, the settlement and comprised agreements were finalized and signed by the Plaintiffs and Exxon. On July 28, 2015, the State of Louisiana issued a letter of no objection to the settlement. As of March 31, 2017 , we have accrued approximately $3.2 million ( $0.8 million in current liabilities and $2.4 million in other long-term liabilities) as the outcome of the litigation was deemed probable and estimable. The settlement requires payment over the term of six years. Other contingencies : We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business for which the outcome cannot be reasonably estimated; however, in the opinion of management, such litigation and claims will be resolved without material adverse effect on our financial position, results of operations or cash flows. Accruals for losses associated with litigation are made when losses are deemed probable and can be reasonably estimated. Performance appreciation rights : In the third quarter of 2014, we adopted the Alta Mesa Holdings, LP Amended and Restated Performance Appreciation Rights Plan (the “Plan”), effective September 24, 2014. The Plan is intended to provide incentive compensation to key employees and consultants who make significant contributions to the Company. Under the Plan, participants are granted performance appreciation rights (“PARs”) with a stipulated initial designated value (“SIDV”). The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, betw een the SIDV and the designated value of the PAR on the payment valuation date. The payment valuation date is the earlier of a liquidity event (as defined in the Plan, but generally can be construed in accordance with the meaning of the term “change in control event”) or as selected by the participant, but no earlier than five years from the end of the year of the grant. Both the initial designated value and the designated payment value of the PAR are determined by the Plan’s administrative committee, composed of members of our board of directors. In the case of a liquidity event, the designated value of all PARs is to be based on the net sale proceeds (as defined in the Plan) from the liquidity event. After any payment valuation date, regardless of payment or none, vested PARs expire. During the first three months of 201 7 , we granted 306,300 new PARs with a SIDV of $40 and terminated 500 PARs with a SIDV of $40 , resulting in 881,100 PARs issued at a weighted average of $37.90 as of March 31, 2017 . We are unable to express an opinion with respect to the likelihood of a qualifying liquidity event which would result in any payment under the Plan or to estimate any amount which may become payable under the Plan. We consider the possibility of payment at a fixed determination date absent a positive liquidity event to be remote. Therefore, we have not provided any amount for this contingent liability in our consolidated financial statements at March 31, 2017 or December 31, 201 6 .

Significant Risks And Uncertain

Significant Risks And Uncertainties	3 Months Ended
	Mar. 31, 2017
Significant Risks And Uncertainties [Abstract]
Significant Risks And Uncertainties	1 1 . 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 the decline in the second half of 2014, 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 6 . 

Partners' Capital

Partners' Capital	3 Months Ended
	Mar. 31, 2017
Partners' Capital [Abstract]
Partners' Capital	1 2 . PARTNERS’ CAPITAL Management and Control : Our business and affairs are managed by Alta Mesa Holdings GP, LLC, our general partner (“General Partner”). With certain exceptions, the General Partner may not be removed except for the reasons of “cause,” which are defined in the partnership agreement. Our partnership agreement provides for two classes of limited partners. Class A partners include our founder and other parties. Our sole Class B partner is High Mesa . The Class B partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture. In connection with the sale of Series E preferred stock by our Class B partner, on February 24, 2017, our General Partner, High Mesa and all of our Class A limited partners entered into a Fifth Amended and Restated Limited Partnership Agreement, and the owners of the General Partner entered into a Fourth Amended and Restated Limited Liability Company Agreement to provide for the Series E preferred stock in the distribution formula and certain other provisions of the amended agreements. Contribution, Distribution and Income Allocation : All distributions under the partnership agreement shall first be ma de to holders of Class B u nits, until certain provisions are met. After such provisions are met, distributions shall then be made to holders of Class A and Class B u nits pursuant to the distribution formulas set forth in the partnership agreement . The Class B partner may require the General Partner to make distributions; however, any distribution must be permitted under the terms of our credit facility and our senior notes. Distribution of net cash flow from a Liquidity Event (as defined below) is distributed to the Class A and Class B partners according to a variable formula as defined in the partnership agreement. A “Liquidity Event” is defined as the first to occur, in one or a series of related transactions, of (i) a disposition of all or substantially of the assets of High Mesa and its subsidiaries to a person that is not an affiliate of High Mesa, (ii) a disposition of all the equity securities of High Mesa, or (iii) the consummation of a public offering of the common equity securities of High Mesa or any of its subsidiaries that hold all of substantially all of High Mesa’s assets on a consolidated basis, and if the public offering is of a subsidiary of High Mesa, the subsequent distribution of the public company equity securities or proceeds obtained in the public offering to the holders of equity securities of High Mesa. The Class B partner can, without consent of any other partners, request that the General Partner take action to cause us, or our assets, to be sold to one or more third parties.  On December 31, 2016, High Mesa purchased from BCE-STACK Development LLC and contributed interest in 24 producing wells drilled under the joint development agreement to us. High Mesa’s equity contribution was recorded at the fair value of the wells contributed of approximately $65.7 million and included contributed cash of $11.3 million, of which $7.9 million was collected d uring the first quarter of 2017. There were no contributions during the first quarter of 2016. 

Subsidiary Guarantors

Subsidiary Guarantors	3 Months Ended
	Mar. 31, 2017
Subsidiary Guarantors [Abstract]
Subsidiary Guarantors	1 3 . 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 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.

Summary Of Significant Accoun19

Summary Of Significant Accounting Policies (Policy)	3 Months Ended
	Mar. 31, 2017
Summary Of Significant Accounting Policies [Abstract]
Principles Of Consolidation And Reporting	Principles of Consolidation and Reporting The consolidated financial statements reflect our accounts after elimination of all significant intercompany transactions and balances. The consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in our annual consolidated fina ncial statements for the year ended December 31, 2016 , which were filed with the Securities and Exchange Commission in our 2016 Annual Report. The consolidated financial statements included herein as of March 31, 2017 , and for the three months ended March 31, 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 consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the U.S. (“GAAP”) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. Certain reclassifications of prior period consolidated financial statements have been made to conform to current reporting practices. The consolidated results of operations for interim periods are not necessarily indicative of results to be expected for a full year.
Use Of Estimates	Use of Estimates The preparation of 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 consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Reserve estimates significantly impact depreciation, depletion and amortization expense and potential impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities. We analyze estimates, including those related to oil and natural gas reserves, oil and natural gas revenues, the value of oil and natural gas properties, bad debts, asset retirement obligations, derivative contracts, state taxes, and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. Actual results may differ from these estimates.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers . The update provides guidance concerning the recognition, measurement and disclosure of revenue from contracts with customers. Its objective is to increase the usefulness of information in the financial statements regarding the nature, timing and uncertainty of revenues. ASU 2014-09 is effective for annual and interim periods beginning after December 15, 2016. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. In August 2015, the FASB issued ASU No. 2015-14, Deferral of the Effective Date (“ASU 2015-14”). ASU 2015-14 deferred the effective date of the new revenue standard by one year, making it effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company has not yet selected a transition method and is currently assessing the impact on the consolidated financial statements. The Company is continuing to evaluate the provisions of this ASU as it relates to certain sales contracts and in particular as it relates to disclosure requirements. In February 2016, the FASB issued ASU No. 2016-02 , Leases (Topic 842), which supersedes ASC 840 “Leases” and creates a new topic, ASC 842 "Leases." The amendments in this update require, among other things, that lessees recognize the following for all leases (with the exception of short-term leases) at the commencement date: (1) a lease liability, which is a lessee's obligation to make lease payments arising from a lease, measured on a discounted basis; and (2) a right-of-use asset, which is an asset that represents the lessee's right to use, or control the use of, a specified asset for the lease term. Lessees and lessors must apply a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. The amendments are effective for interim and annual reporting periods beginning after December 15, 2018. The Company enters into lease agreements to support its operations. These agreements are for leases on assets such as office space, vehicles, field services and equipment. The Company continues to evaluate the impacts of the amendments to our financial statements and accounting practices for leases. We anticipate adoption of ASU 2016-02 effective January 1, 2019.  In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments , which is intended to reduce diversity in practice in how certain transactions are classified in the statements of cash flows. ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.  In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows: Restricted Cash, which requires an entity to explain the changes in the total of cash, cash equivalents, restricted cash, and restricted cash equivalents on the statements of cash flows and to provide a reconciliation of the totals in that statement to the related captions in the balance sheet when the cash, cash equivalents, restricted cash, and restricted cash equivalents are presented in more than one line item on the balance sheet. This ASU is effective for annual and interim periods beginning after December 15, 2017, and is required to be adopted using a retrospective approach, with early adoption permitted. The adoption of this guidance will not impact the Company’s financial position or results of operations but could result in presentation changes on its consolidated statements of cash flows.  In January 2017, the FASB issued ASU No. 2017-01, Clarifying the Definition of a Business, which provides guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 requires entities to use a screen test to determine when an integrated set of assets and activities is not a business or if the integrated set of assets and activities needs to be further evaluated against the framework. ASU 2017-01 is effective for fiscal years beginning after December 15, 2017, including interim periods within those years. The Company is currently evaluating the effect that adopting this guidance will have on its financial position, cash flows and results of operations.

Fair Value Disclosures (Policy)

Fair Value Disclosures (Policy)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements And Disclosures	The Company follows ASC 820, “Fair Value Measurements and Disclosures.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least reliable. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances. The fair value of cash, accounts receivable, other current assets, and current liabilities approximate book value due to their short-term nature. The estimate of fair value of long-term debt under our senior secured revolving credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the notes payable to our founder is not practicable to determine because the transactions cannot be assumed to have been consummated at arm’s length, the terms are not deemed to be market terms, there are no quoted values available for this instrument, and an independent valuation would not be practicable due to the lack of data regarding similar instruments, if any, and the associated potential costs. Our senior notes are carried at historical cost and we estimate the fair value of the senior notes for disclosure purposes. We have estimated the fair value of our $500 million senior notes payable to be $511.3 million at March 31, 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 Not e 8 for information on long-term debt. We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to est imate 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 a s implied volatility of oil, natural gas and natural gas liquids prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2.

Derivative Financial Instrume21

Derivative Financial Instruments (Policy)	3 Months Ended
	Mar. 31, 2017
Derivative Financial Instruments [Line Items]
Derivative Financial Instruments	We have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the 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 a derivative asset account.
Netting Presentation for Derivatives Policy [Member]
Derivative Financial Instruments [Line Items]
Derivative Financial Instruments	Derivative contracts are subject to master netting arrangements and are presented on a net basis in the 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 a derivative asset account.

Supplemental Cash Flow Inform22

Supplemental Cash Flow Information (Tables)	3 Months Ended
	Mar. 31, 2017
Supplemental Cash Flow Information [Abstract]
Supplemental Disclosures To The Consolidated Statements Of Cash Flows	  Three Months Ended March 31,  2017 2016   (in thousands)  Supplemental cash flow information:  Cash paid for interest $ 1,162 $ 3,960  Cash paid for state income taxes — 1  Non-cash investing and financing activities:  Change in asset retirement obligations 296 322  Change in accruals or liabilities for capital expenditures 21,111 (3,340) 

Property And Equipment (Tables)

Property And Equipment (Tables)	3 Months Ended
	Mar. 31, 2017
Property And Equipment [Abstract]
Summary Of Property And Equipment	   March 31, December 31,  2017 2016   (in thousands)  OIL AND NATURAL GAS PROPERTIES  Unproved properties $ 111,035 $ 116,311  Accumulated impairment of unproved properties (70) (65)  Unproved properties, net 110,965 116,246  Proved oil and natural gas properties 1,694,486 1,611,249  Accumulated depreciation, depletion, amortization and impairment (1,040,679) (1,015,333)  Proved oil and natural gas properties, net 653,807 595,916  TOTAL OIL AND NATURAL GAS PROPERTIES, net 764,772 712,162  OTHER PROPERTY AND EQUIPMENT  Land 5,172 4,730  Office furniture and equipment, vehicles 19,706 19,446  Accumulated depreciation (15,118) (14,445)  OTHER PROPERTY AND EQUIPMENT, net 9,760 9,731  TOTAL PROPERTY AND EQUIPMENT, net $ 774,532 $ 721,893 

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis	   Level 1 Level 2 Level 3 Total   (in thousands)  At March 31, 2017:  Financial Assets:  Commodity derivative contracts — $ 28,064 — $ 28,064  Financial Liabilities:  Commodity derivative contracts — $ 20,735 — $ 20,735  At December 31, 2016:  Financial Assets:  Commodity derivative contracts — $ 15,773 — $ 15,773  Financial Liabilities:  Commodity derivative contracts — $ 40,656 — $ 40,656 

Derivative Financial Instrume25

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2017
Derivative [Line Items]
Fair Values Of Derivative Contracts	 Fair Values of Derivative Contracts (unaudited):     March 31, 2017  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 10,166 $ (6,270) $ 3,896  Derivative financial instruments, long-term assets 17,898 (10,725) 7,173  Total $ 28,064 $ (16,995) $ 11,069      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 10,010 $ (6,270) $ 3,740  Derivative financial instruments, long-term liabilities 10,725 (10,725) —  Total $ 20,735 $ (16,995) $ 3,740      December 31, 2016  Net Fair  Gross Gross amounts Value of Assets  Fair Value offset against assets presented in  Balance sheet location of Assets in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current assets $ 3,296 $ (3,213) $ 83  Derivative financial instruments, long-term assets 12,477 (11,754) 723  Total $ 15,773 $ (14,967) $ 806      Net Fair  Gross Gross amounts Value of Liabilities  Fair Value offset against liabilities presented in  Balance sheet location of Liabilities in the Balance Sheet the Balance Sheet   (in thousands)  Derivative financial instruments, current liabilities $ 24,420 $ (3,213) $ 21,207  Derivative financial instruments, long-term liabilities 16,236 (11,754) 4,482  Total $ 40,656 $ (14,967) $ 25,689 
Effect Of Derivative Instruments In The Consolidated Statements Of Operations	   Derivatives not Three Months Ended  designated as hedging March 31,  instruments under ASC 815 2017 2016   (in thousands)  Gain (loss) on derivative contracts  Oil commodity contracts $ 26,085 $ 8,146   Natural gas commodity contracts 3,899 2,814   Natural gas liquids commodity contracts 258 (145)  Total gain on derivative contracts $ 30,242 $ 10,815 
Oil Derivative Contracts [Member]
Derivative [Line Items]
Open Derivative Contracts	We had the following open derivative contracts for crude oil at March 31, 2017 (unaudited) :  OIL DERIVATIVE CONTRACTS       Volume Weighted Range  Period and Type of Contract in Bbls Average High Low  2017  Price Swap Contracts 1,710,500 $ 50.31 $ 57.25 $ 45.00  Collar Contracts  Long Call Options 137,500 85.00 85.00 85.00  Short Call Options 1,535,000 60.46 85.00 54.40  Long Put Options 1,122,500 48.35 50.00 47.00  Short Put Options 1,122,500 37.12 40.00 35.00  2018  Price Swap Contracts 547,500 57.22 57.25 57.20  Collar Contracts  Long Call Options 365,000 54.00 54.00 54.00  Short Call Options 2,190,000 60.87 62.00 60.50  Long Put Options 1,825,000 50.00 50.00 50.00  Short Put Options 2,190,000 40.26 42.00 40.00  2019  Collar Contracts  Short Call Options 1,241,000 62.90 63.00 62.75  Long Put Options 1,241,000 50.00 50.00 50.00  Short Put Options 1,241,000 37.50 37.50 37.50 
Natural Gas Derivative Contract [Member]
Derivative [Line Items]
Open Derivative Contracts	We had the following open derivative contracts for natural gas at March 31, 2017 (unaudited) :  NATURAL GAS DERIVATIVE CONTRACTS      Volume in Weighted Range  Period and Type of Contract MMBtu Average High Low  2017  Price Swap Contracts 1,070,000 $ 3.40 $ 3.40 $ 3.40  Collar Contracts  Short Call Options 8,620,000 3.62 3.80 3.25  Long Put Options 7,700,000 3.11 3.30 3.00  Long Call Options 920,000 2.95 2.95 2.95  Short Put Options 8,620,000 2.57 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]
Derivative [Line Items]
Open Derivative Contracts	We had the following open derivative contracts for natural gas liquids at March 31, 2017 (unaudited) :  NATURAL GAS LIQUIDS DERIVATIVE CONTRACTS    Volume Weighted Range  Period and Type of Contract in Gal Average High Low  2017  Price Swap Contracts  Short Price Swaps 4,237,800 $ 0.46 $ 0.47 $ 0.45 
Basis Swap Derivative Contract [Member]
Derivative [Line Items]
Natural Gas Basis Swap Contracts	We had the following open financia l basis swap contracts for natural gas March 31, 2017 (unaudited) :  BASIS SWAP DERIVATIVE CONTRACTS      Weighted  Average Spread  Volume in MMBtu (1) Reference Price 1 Reference Price 2 Period ($ per MMBtu)  9,320,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Apr'17 — Dec '17 $ (0.26)  5,910,000 TEX/OKL Mainline (PEPL) NYMEX Henry Hub Jan '18 — Oct '18 (0.27)   (1) Represents short swaps that fix the basis differentials between Tex/OKL Panhandle Eastern Pipeline (“PEPL”) INSIDE FERC (“IFERC”) and NYMEX Henry Hub.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2017
Asset Retirement Obligations [Abstract]
Summary Of Changes In Asset Retirement Obligations	  Three  Months Ended  March 31, 2017  (in thousands)  Balance, beginning of year $ 61,504  Liabilities incurred 296  Liabilities settled (2,394)  Liabilities transferred in sales of properties —  Revisions to estimates 2,393  Accretion expense 572  Balance, March 31, 2017 62,371  Less: Current portion 1,383  Long-term portion $ 60,988 

Long Term Debt, Net And Notes27

Long Term Debt, Net And Notes Payable To Founder (Tables)	3 Months Ended
	Mar. 31, 2017
Long Term Debt, Net And Notes Payable To Founder [Abstract]
Long-Term Debt, Net And Notes Payable To Founder	   March 31, December 31,  2017 2016   (in thousands)  Senior secured revolving credit facility $ 95,687 $ 40,622  7.875% senior unsecured notes due 2024 500,000 500,000  Unamortized deferred financing costs (10,426) (10,717)  Total long-term debt, net $ 585,261 $ 529,905  Notes payable to founder $ 27,255 $ 26,957 

Accounts Payable And Accrued 28

Accounts Payable And Accrued Liabilities (Tables)	3 Months Ended
	Mar. 31, 2017
Accounts Payable And Accrued Liabilities [Abstract]
Detail Of Accounts Payable And Accrued Liabilities	   March 31, December 31,  2017 2016   (in thousands)  Capital expenditures $ 29,019 $ 15,155  Revenues and royalties payable 14,491 12,187  Operating expenses/taxes 14,465 17,499  Interest 12,542 2,627  Compensation 5,277 5,302  Derivative settlement payable 571 1,126  Other 972 1,164  Total accrued liabilities 77,337 55,060  Accounts payable 37,859 29,174  Accounts payable and accrued liabilities $ 115,196 $ 84,234 

Supplemental Cash Flow Inform29

Supplemental Cash Flow Information (Supplemental Disclosures To The Consolidated Statements Of Cash Flows) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 1,162	$ 3,960
Cash paid for state income taxes		1
Non-cash Investing And Financing Activities:
Change in asset retirement obligations	296	322
Change in accruals or liabilities for capital expenditures	$ 21,111	$ (3,340)

Property And Equipment (Summary

Property And Equipment (Summary Of Property And Equipment) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Property And Equipment [Abstract]
Unproved properties	$ 111,035	$ 116,311
Accumulated impairment	(70)	(65)
Unproved properties, net	110,965	116,246
Proved oil and natural gas properties	1,694,486	1,611,249
Accumulated depreciation, depletion, amortization and impairment	(1,040,679)	(1,015,333)
Proved oil and natural gas properties, net	653,807	595,916
TOTAL OIL AND NATURAL GAS PROPERTIES, net	764,772	712,162
Land	5,172	4,730
Office furniture and equipment, vehicles	19,706	19,446
Accumulated depreciation	(15,118)	(14,445)
OTHER PROPERTY AND EQUIPMENT, net	9,760	9,731
Total property and equipment, net	$ 774,532	$ 721,893

Fair Value Disclosures (Narrati

Fair Value Disclosures (Narrative) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Face value of senior notes issued	$ 500,000
Fair value of senior notes payable	511,300
Carrying value of oil and gas properties	3,400	$ 3,300
Written down fair value of oil and gas properties	2,200	1,500
Impairment charges to oil and gas properties	1,220	1,764
Asset retirement obligation measured at fair value	$ 300	$ 300

Fair Value Disclosures (Measure

Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Financial Assets:
Commodity derivative contracts, gross	$ 28,064	$ 15,773
Financial Liabilities:
Commodity derivative contracts, gross	20,735	40,656
Level 1 [Member]
Financial Assets:
Commodity derivative contracts, gross
Financial Liabilities:
Commodity derivative contracts, gross
Level 2 [Member]
Financial Assets:
Commodity derivative contracts, gross	28,064	15,773
Financial Liabilities:
Commodity derivative contracts, gross	20,735	40,656
Level 3 [Member]
Financial Assets:
Commodity derivative contracts, gross
Financial Liabilities:
Commodity derivative contracts, gross

Derivative Financial Instrume33

Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	$ 28,064	$ 15,773
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(16,995)	(14,967)
Derivative Assets, Current	3,896	83
Derivative Assets, Noncurrent	7,173	723
Derivative assets, net, total	11,069	806
Derivative liabilities, Gross Fair Value of Liabilities	20,735	40,656
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(16,995)	(14,967)
Derivative Liabilities, Current	3,740	21,207
Derivative Liabilities, Noncurrent		4,482
Derivative liabilities, net, total	3,740	25,689
Derivative Assets Current [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	10,166	3,296
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(6,270)	(3,213)
Derivative Assets, Current	3,896	83
Derivative Asset Non-Current [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	17,898	12,477
Derivative assets, Gross amounts offset against assets in the Balance Sheet	(10,725)	(11,754)
Derivative Assets, Noncurrent	7,173	723
Derivative Liabilities Current [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, Gross Fair Value of Liabilities	10,010	24,420
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(6,270)	(3,213)
Derivative Liabilities, Current	3,740	21,207
Derivative Liabilities Non Current [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, Gross Fair Value of Liabilities	10,725	16,236
Derivative liabilities, Gross amounts offset against liabilities in the Balance Sheet	(10,725)	(11,754)
Derivative Liabilities, Noncurrent		$ 4,482

Derivative Financial Instrume34

Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments, Gain [Line Items]
Total gains on derivative contracts	$ 30,242	$ 10,815
Not Designated As Hedging Instrument [Member] | Oil Commodity Contracts [Member]
Derivative Instruments, Gain [Line Items]
Total gains on derivative contracts	26,085	8,146
Not Designated As Hedging Instrument [Member] | Natural Gas Commodity Contracts [Member]
Derivative Instruments, Gain [Line Items]
Total gains on derivative contracts	3,899	2,814
Not Designated As Hedging Instrument [Member] | Natural Gas Liquids Commodity Contract [Member]
Derivative Instruments, Gain [Line Items]
Total gains on derivative contracts	$ 258	$ (145)

Derivative Financial Instrume35

Derivative Financial Instruments (Oil Derivative Contracts) (Details) - Oil Derivative Contracts [Member]	3 Months Ended
	Mar. 31, 2017$ / bblbbl
Price Swap Contracts [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,710,500
Swap Price	50.31
Price Swap Contracts [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	57.25
Price Swap Contracts [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	45
Price Swap Contracts [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	547,500
Swap Price	57.22
Price Swap Contracts [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	57.25
Price Swap Contracts [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	57.20
Long Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	137,500
Weighted Average Option Price	85
Long Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	85
Long Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	85
Long Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	365,000
Weighted Average Option Price	54
Long Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	54
Long Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	54
Short Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,535,000
Weighted Average Option Price	60.46
Short Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	85
Short Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	54.40
Short Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,190,000
Weighted Average Option Price	60.87
Short Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	62
Short Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60.50
Short Call Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000
Weighted Average Option Price	62.90
Short Call Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	63
Short Call Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	62.75
Long Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,122,500
Weighted Average Option Price	48.35
Long Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	47
Long Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,825,000
Weighted Average Option Price	50
Long Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000
Weighted Average Option Price	50
Long Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	50
Long Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	50
Short Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,122,500
Weighted Average Option Price	37.12
Short Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	40
Short Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	35
Short Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	2,190,000
Weighted Average Option Price	40.26
Short Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	42
Short Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	40
Short Put Options [Member] | 2019 [Member]
Derivative [Line Items]
Volume in Bbls | bbl	1,241,000
Weighted Average Option Price	37.50
Short Put Options [Member] | 2019 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	37.50
Short Put Options [Member] | 2019 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	37.50

Derivative Financial Instrume36

Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) - Natural Gas [Member]	3 Months Ended
	Mar. 31, 2017MMBTU$ / MMBTU
2017 [Member] | Price Swap Contracts [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	1,070,000
Weighted Average Swap Price	3.40
2017 [Member] | Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	3.40
2017 [Member] | Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	3.40
2017 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	8,620,000
Weighted Average Option Price	3.62
2017 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	3.80
2017 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.25
2017 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	7,700,000
Weighted Average Option Price	3.11
2017 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	3.30
2017 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3
2017 [Member] | Long Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	920,000
Weighted Average Option Price	2.95
2017 [Member] | Long Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	2.95
2017 [Member] | Long Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.95
2017 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	8,620,000
Weighted Average Option Price	2.57
2017 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	2.70
2017 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	2.50
2018 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	6,132,000
Weighted Average Option Price	5.34
2018 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.53
2018 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4
2018 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,475,000
Weighted Average Option Price	4.50
2018 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.50
2018 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.50
2018 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,475,000
Weighted Average Option Price	4
2018 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4
2018 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4

Derivative Financial Instrume37

Derivative Financial Instruments (Natural Gas Liquids Derivative Contracts) (Details) - 2017 [Member] - Natural Gas Liquids Derivative Contracts [Member] - Price Swap Contracts [Member]	3 Months Ended
	Mar. 31, 2017$ / galgal
Derivative [Line Items]
Volume in Gal | gal	4,237,800
Weighted Average Swap Price	0.46
Minimum [Member]
Derivative [Line Items]
Swap Price	0.45
Maximum [Member]
Derivative [Line Items]
Swap Price	0.47

Derivative Financial Instrume38

Derivative Financial Instruments (Natural Gas Basis Swap Contracts) (Details) - Financial Basis Swap Contracts For Gas [Member]	3 Months Ended
	Mar. 31, 2017MMBTU$ / MMBTU
2017 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	9,320,000
First remaining period of term of derivative contract	Apr. 1, 2017
Last remaining period of term of derivative contract	Dec. 31, 2017
Weighted average spread | $ / MMBTU	(0.26)
2018 [Member]
Derivative [Line Items]
Volume in MMbtu | MMBTU	5,910,000
First remaining period of term of derivative contract	Jan. 1, 2018
Last remaining period of term of derivative contract	Oct. 31, 2018
Weighted average spread | $ / MMBTU	(0.27)

Asset Retirement Obligations (S

Asset Retirement Obligations (Summary Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations [Abstract]
Balance, beginning of year	$ 61,504
Liabilities incurred	296
Liabilities settled	(2,394)
Liabilities transferred in sales of properties
Revisions to estimates	2,393
Accretion expense	572	$ 539
Balance, end of period	$ 61,504		$ 62,371	$ 61,504
Less: Current portion			1,383	376
Long-term portion			$ 60,988	$ 61,128

Long Term Debt, Net And Notes40

Long Term Debt, Net And Notes Payable To Founder (Narrative) (Details) - USD ($)	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2016
Debt Instrument [Line Items]
Face value of senior notes issued	$ 500,000,000
Notes payable to founder	27,255,000			$ 26,957,000
Interest on notes payable to founder	298,000	$ 298,000
Deferred financing costs	10,426,000			10,717,000
Amortization of deferred financing costs	962,000	934,000
Deferred financing costs, net	$ 2,422,000			3,029,000
Federal Funds Effective Swap Rate [Member]
Debt Instrument [Line Items]
Margin interest rate	50.00%
7th Amended And Restated Credit Agreement [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description	plus 1%, plus a margin ranging from 1.75% to 2.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing base utilized, and ranging from 2.00% to 3.00% if our leverage ratio exceeds 3.25 to 1.00.
Credit Facility And Senior Notes [Member]
Debt Instrument [Line Items]
Deferred financing costs	$ 12,800,000
7.875% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Face value of senior notes issued	$ 500,000,000
Maturity date of debt	Dec. 15, 2024
Debt covenant compliance description	The indenture governing the 2024 Notes includes covenants requiring us to maintain certain financial covenants including a current ratio and leverage ratio. As of March 31, 2017, we were in compliance with all financial covenants of the 2024 Notes.
Redemption price due to specific change of control events	101.00%
Notes payable	$ 500,000,000			$ 500,000,000
Stated interest rate of senior notes	7.875%
First annual payment date	June 15
Second annual payment date	December 15
Redemption percentage of aggregate remaining outstanding	65.00%
7.875% Senior Unsecured Notes Due 2024 [Member] | Prior to December 15, 2019 [Member]
Debt Instrument [Line Items]
Redemption price plus make-whole premium	100.00%
Redemption price	107.875%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2019 [Member]
Debt Instrument [Line Items]
Redemption price	105.906%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2020 [Member]
Debt Instrument [Line Items]
Redemption price	103.938%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2021 [Member]
Debt Instrument [Line Items]
Redemption price	101.969%
7.875% Senior Unsecured Notes Due 2024 [Member] | Twelve Mos Beginning December 15, 2022 [Member]
Debt Instrument [Line Items]
Redemption price	100.00%
Maximum [Member] | 7.875% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Redemption percentage of Senior Notes	35.00%
Senior Secured Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility borrowing base	$ 287,500,000
Line of Credit Facility, Remaining borrowing capacity	$ 184,200,000
Date of maturity of credit facility	Nov. 10, 2020
Credit facility interest rate	4.48%			4.00%
Pro forma leverage ratio	3
Letter of credit outstanding	$ 7,600,000
Minimum Working Capital Ratio	1
Maximum Leverage Ratio	4
Debt instrument collateral	The credit facility is secured by substantially all of our oil and natural gas properties
Debt covenants description	The credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, sell assets, guaranty or make loans to others, make investments, enter into mergers, make certain payments and distributions, enter into or be party to hedge agreements, amend our organizational documents, incur liens and engage in certain other transactions without the prior consent of the lenders. The credit facility permits us to make distributions in any fiscal quarter so long as (i) the amount of distributions made in such fiscal quarter does not exceed our excess cash flow from the immediately preceding fiscal quarter, (ii) no event of default exists, before and after giving effect to such distribution, (iii) our pro forma leverage ratio is less than 3.00 to 1.00 and (iv) before and after giving effect to such distribution the unused commitment amounts available under the credit facility are at least 20% of the commitments in effect.The credit facility also requires us to maintain a current ratio (as defined in the credit facility), of consolidated current assets (including unused borrowing base committed capacity and with exclusions as described in the credit facility) to consolidated current liabilities of no less than 1.0 to 1.0 as of the last day of any fiscal quarter and leverage ratio of our consolidated debt (other than obligations under hedge agreements and founder notes) as of the end of such fiscal quarter to our consolidated earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses ("EBITDAX") over the four quarter period then ended (but annualized for the fiscal quarters ending December 31, 2016, March 31, 2017, and June 30, 2017) of not greater than 4.0 to 1.0.
Debt covenant compliance description	As of March 31, 2017, we were in compliance with all financial covenants of the credit facility.
Percent of unused distribution	20.00%
Senior Secured Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Leverage rate	3.25
Senior Secured Revolving Credit Facility [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Leverage rate	3.25
Senior Secured Revolving Credit Facility [Member] | Eurodollar [Member]
Debt Instrument [Line Items]
Margin interest rate	1.00%
Senior Secured Revolving Credit Facility [Member] | 7th Amended And Restated Credit Agreement [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description	the London Interbank Offered Rate ("LIBOR") plus applicable margins ranging from 2.75% and 3.75% if our leverage ratio does not exceed 3.25 to 1.00, depending on the percentage of our borrowing based utilized, and ranging from 3.00% to 4.00% if our leverage ratio exceeds 3.25 to 1.00.
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate	2.75%
Exceeded leverage rate	3.00%
Senior Secured Revolving Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate	1.75%
Exceeded leverage rate	2.00%
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate	3.75%
Exceeded leverage rate	4.00%
Senior Secured Revolving Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate	2.75%
Exceeded leverage rate	3.00%
Notes Payable To Founder [Member]
Debt Instrument [Line Items]
Maturity date of debt	Dec. 31, 2021		Dec. 31, 2018
Effective rate of interest	10.00%
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 described in Note 12, 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 Series B preferred stock to receive payments.
Notes payable to founder	$ 27,300,000			$ 27,000,000
Payment terms, notes payable to founder	Interest and principal are payable at maturity.
Interest on notes payable to founder	$ 300,000	$ 300,000
Conversion feature, notes payable to founder	Our founder shall convert the notes into shares of common stock of our Class B partner, High Mesa, Inc. ("High Mesa"), upon certain conditions in the event of an initial public offering of High Mesa.

Long Term Debt, Net And Notes41

Long Term Debt, Net And Notes Payable To Founder (Long-Term Debt, Net And Notes Payable To Founder) (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Credit Facility	$ 95,687	$ 40,622
Unamortized deferred financing costs	(10,426)	(10,717)
Total long-term debt, net	585,261	529,905
Notes payable to founder	27,255	26,957
7.875% Senior Unsecured Notes Due 2024 [Member]
Debt Instrument [Line Items]
Notes payable	$ 500,000	$ 500,000
Maturity date of debt	Dec. 15, 2024
Stated interest rate of senior notes	7.875%

Accounts Payable And Accrued 42

Accounts Payable And Accrued Liabilities (Detail Of Accounts Payable And Accrued Liabilities) (Details) - USD ($) $ in Thousands	Mar. 31, 2017	Dec. 31, 2016
Accounts Payable And Accrued Liabilities [Abstract]
Capital expenditures	$ 29,019	$ 15,155
Revenues and royalties payable	14,491	12,187
Operating expenses/taxes	14,465	17,499
Interest	12,542	2,627
Compensation	5,277	5,302
Derivatives settlement payable	571	1,126
Other	972	1,164
Total accrued liabilities	77,337	55,060
Accounts payable	37,859	29,174
Accounts payable and accrued liabilities	$ 115,196	$ 84,234

Commitments and Contingencies (

Commitments and Contingencies (Narrative) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Commitment And Contingencies [Line Items]
Vesting period, PARs	5 years
Weighted average stipulated price of PARs granted	$ 37.90
Stipulated initial designated price of PARs granted	$ 40
Number of performance appreciation rights granted	306,300
Number of performance appreciation rights terminated	500
Number of performance appreciation rights	881,100
Weighted average stipulated price of PARs terminated	$ 40
Other long-term litigation liabilities	$ 6,778	$ 6,870
Litigation [Member]
Commitment And Contingencies [Line Items]
Estimated litigation liability	3,200
Current litigation liabilities	800
Other long-term litigation liabilities	$ 2,400

Significant Risks And Uncerta44

Significant Risks And Uncertainties (Details)	3 Months Ended
	Mar. 31, 2017
Significant Risks And Uncertainties [Abstract]
Risks and uncertainties inherent	Our business makes us vulnerable to changes in wellhead prices of crude oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas have been highly volatile and declined dramatically since the second half of 2014. Although oil and natural gas prices have recently begun to recover from lows experienced since the decline in the second half of 2014, forecasted prices for both oil and natural gas continue to remain depressed. The duration and magnitude of changes in oil and natural gas prices cannot be predicted. Continued depressed oil and natural gas prices, further price declines or any other unfavorable market conditions could have a material adverse effect on our financial condition and on the carrying value of our proved oil and natural gas reserves. Sustained low oil or natural gas prices may require us to write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. This could cause a reduction in the borrowing base under our credit facility to the extent that we are not able to replace the reserves that we produce. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.

Partners' Capital (Details)

Partners' Capital (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017USD ($)item	Dec. 31, 2016USD ($)item
Debt Instrument [Line Items]
Number of classes of limited partners | item	2
High Mesa [Member]
Debt Instrument [Line Items]
Cash contribution		$ 11.3
Cash collected	$ 7.9
Contribution		$ 65.7
Contributed Wells [Member] | High Mesa [Member]
Debt Instrument [Line Items]
Number of wells | item		24