Alta Mesa 10-K 26 Mar 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014
Document And Entity Information [Abstract]
Entity Registrant Name	Alta Mesa Holdings, LP
Entity Central Index Key	1518403
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	-19
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	0
Entity Public Float	$0
Entity Current Reporting Status	Yes
Entity Voluntary Filers	Yes
Entity Well-known Seasoned Issuer	No

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS
Cash and cash equivalents	$1,349	$6,537
Restricted cash	23,793
Accounts receivable, net	43,581	43,486
Other receivables	33,738	2,552
Prepaid expenses and other current assets	2,132	3,077
Derivative financial instruments	59,803	5,572
TOTAL CURRENT ASSETS	164,396	61,224
PROPERTY AND EQUIPMENT
Oil and natural gas properties, successful efforts method, net	686,176	691,770
Other property and equipment, net	11,505	9,100
TOTAL PROPERTY AND EQUIPMENT, NET	697,681	700,870
OTHER ASSETS
Long-term restricted cash	900
Investment in LLC - cost	9,000	9,000
Deferred financing costs, net	8,100	10,943
Notes receivable	8,500
Advances to operators	619	6,863
Deposits and other assets	1,124	1,186
Derivative financial instruments	27,271	3,405
TOTAL OTHER ASSETS	55,514	31,397
TOTAL ASSETS	917,591	793,491
CURRENT LIABILITIES
Accounts payable and accrued liabilities	117,560	96,095
Current portion, asset retirement obligations	1,136	3,844
Derivative financial instruments		4,483
TOTAL CURRENT LIABILITIES	118,696	104,422
LONG-TERM LIABILITIES
Asset retirement obligations, net of current portion	61,736	52,179
Long-term debt	767,608	766,868
Notes payable to founder	24,540	23,331
Derivative financial instruments		4,486
Other long-term liabilities	6,457	2,312
TOTAL LONG-TERM LIABILITIES	860,341	849,176
TOTAL LIABILITIES	979,037	953,598
COMMITMENTS AND CONTINGENCIES (NOTE11)
PARTNERS' CAPITAL (DEFICIT)	-61,446	-160,107
TOTAL LIABILITIES AND PARTNERS' CAPITAL (DEFICIT)	$917,591	$793,491

Consolidated_Statements_Of_Ope

Consolidated Statements Of Operations (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
REVENUES
Oil	$347,842	$297,836	$221,800
Natural gas	65,002	61,350	57,575
Natural gas liquids	18,281	15,264	15,606
Other revenues	1,003	1,207	4,567
Total	432,128	375,657	299,548
Gain (loss) on sale of assets	87,520	-2,715
Gain (loss) - oil and natural gas derivative contracts	96,559	-17,150	19,751
TOTAL REVENUES	616,207	355,792	319,299
EXPENSES
Lease and plant operating expense	73,820	70,450	69,047
Production and ad valorem taxes	28,214	26,369	23,485
Workover expense	8,961	13,679	12,740
Exploration expense	61,912	33,065	21,912
Depreciation, depletion, and amortization expense	141,804	118,558	109,252
Impairment expense	74,927	143,166	96,227
Accretion expense	2,198	2,133	1,813
General and administrative expense	69,198	47,023	40,222
TOTAL EXPENSES	461,034	454,443	374,698
INCOME (LOSS) FROM OPERATIONS	155,173	-98,651	-55,399
OTHER INCOME (EXPENSE)
Interest expense	-55,812	-55,188	-41,932
Interest income	15	124	99
Litigation settlement			1,250
TOTAL OTHER INCOME (EXPENSE)	-55,797	-55,064	-40,583
INCOME (LOSS) BEFORE STATE INCOME TAXES	99,376	-153,715	-95,982
BENEFIT FROM (PROVISION FOR) STATE INCOME TAXES	-176		107
NET INCOME (LOSS)	$99,200	($153,715)	($95,875)

Consolidated_Statements_Of_Cha

Consolidated Statements Of Changes In Partners' Capital (Deficit) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Consolidated Statements of Changes in Partners' Capital (Deficit) [Abstract]
Balance, Beginning	($160,107)	($6,368)	$89,672
Distributions	-539	-24	-165
Net income (loss)	99,200	-153,715	-95,875
Balance, Ending	($61,446)	($160,107)	($6,368)

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$99,200	($153,715)	($95,875)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion, and amortization expense	141,804	118,558	109,252
Impairment expense	74,927	143,166	96,227
Accretion expense	2,198	2,133	1,813
Amortization of loan costs	2,885	2,839	2,424
Amortization of debt discount	510	510	322
Dry hole expense	30,294	15,295	8,454
Expired leases	4,319	3,289
(Gain) loss - derivative contracts	-96,559	17,150	-19,714
Settlements on derivative contracts	9,493	18,177	35,848
Interest converted into debt	1,209	1,208	1,212
(Gain) loss on sale of assets	-87,520	2,715
Changes in assets and liabilities:
Restricted cash unrelated to property divestiture	-106	2,305	-2,305
Accounts receivable	-95	-2,771	92
Other receivables	-5,686	1,863	-1,609
Prepaid expenses and other non-current assets	7,251	4,477	-5,558
Settlement of asset retirement obligation	-3,942	-1,548	-3,562
Accounts payable, accrued liabilities, and other long-term liabilities	4,702	-3,132	20,172
NET CASH PROVIDED BY OPERATING ACTIVITIES	184,884	172,519	147,193
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for property and equipment	-366,090	-311,438	-224,719
Acquisitions of property and equipment	-18,110	-51,377	-30,346
Proceeds from sale of property	177,476	26,668
Proceeds from property divesture classified as restricted cash	41,590
Investment in restricted cash related to property divestitures	-24,587
NET CASH USED IN INVESTING ACTIVITIES	-189,721	-336,147	-255,065
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt	169,500	214,500	270,000
Repayments of long-term debt	-169,270	-50,000	-155,500
Additions to deferred financing costs	-42	-97	-3,307
Capital distributions	-539	-24	-165
NET CASH (USED IN) PROVIDED BY FINANCING ACTIVITIES	-351	164,379	111,028
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	-5,188	751	3,156
CASH AND CASH EQUIVALENTS, beginning of period	6,537	5,786	2,630
CASH AND CASH EQUIVALENTS, end of period	1,349	6,537	5,786
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Cash paid during the period for interest	51,219	50,731	36,853
Cash paid (received) during the period for state taxes	-123	18	124
Change in asset retirement obligations	2,643	854	1,661
Asset retirement obligations assumed, purchased properties	3,002	5,480	1,476
Change in accruals or liabilities for capital expenditures	23,858	-14,085	22,061
Non-cash divestiture of oil and gas properties	($34,000)

Nature_Of_Operations

Nature Of Operations	12 Months Ended
	Dec. 31, 2014
Nature Of Operations [Abstract]
Nature Of Operations	NOTE 1 — NATURE OF OPERATIONS
	Nature of Operations.  Alta Mesa Holdings, LP (“Alta Mesa,” the “Company,” “us,” “our,” or “we”) is engaged primarily in the acquisition, exploration, development, and production of oil and natural gas properties. Our core properties are located in Oklahoma, Louisiana and Texas.

Summary_Of_Significant_Account

Summary Of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Summary Of Significant Accounting Policies	NOTE 2 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	We use accounting policies which reflect industry practices and conform to accounting principles generally accepted in the U.S. (“GAAP”). As used herein, the following acronyms have the following meanings: “FASB” means the Financial Accounting Standards Board; the “Codification” refers to the Accounting Standards Codification, the collected accounting and reporting guidance maintained by the FASB; “ASC” means Accounting Standards Codification and is generally followed by a number indicating a particular section of the Codification; and “ASU” means Accounting Standards Update, followed by an identification number, which are the periodic updates made to the Codification by the FASB. “SEC” means the Securities and Exchange Commission.
	Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.
	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 impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.
	Reclassifications.   Certain amounts in the 2013 and 2012 consolidated financial statements have been reclassified to conform to the 2014 presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit).
	Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
	Restricted Cash.    The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2014, the Company had $24.6 million of proceeds from the sale of our Hilltop field Deep Bossier properties in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code. As December 31, 2014, the Company has utilized or plans to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. The remaining $23.7 million of restricted cash was returned to us in March 2015 and, as such, is classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures.
	Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized.  Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $10.3 million and $13.8 million at December 31, 2014 and 2013, respectively.  Trade receivables for the sale of oil and natural gas were $35.1 million and $37.8 million at December 31, 2014 and 2013, respectively.  See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC.  Accounts receivable from ARM Energy Management, LLC were $16.6 million and $7.5 million as of December 31, 2014 and 2013, respectively.
	Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated. Accounts receivable are shown net of allowance for doubtful accounts of $1.4 million for the years ended December 31, 2014 and 2013, respectively.
	Deferred Financing Costs. Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the years ended December 31, 2014, 2013, and 2012, amortization of deferred financing costs included in interest expense amounted to $2.9 million, $2.8 million, and $2.4 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $15.6 million and $12.8 million at December 31, 2014 and 2013, respectively.
	Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
	Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
	Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.
	Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.
	Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
	Our evaluation of the Company’s proved properties resulted in impairment expense of $72.9 million, $135.2 million and $90.3 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2014, 2013 and 2012, impairment expense of unproved properties was $2.0 million, $8.0 million, and $5.9 million, respectively.
	Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.
	If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2014, 2013, and 2012, respectively, the Company did not record any impairment expense related to other long-lived assets.
	Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.
	DD&A expense for the years ended December 31, 2014, 2013, and 2012 related to oil and natural gas properties was $139.0 million, $115.5 million, and $106.6 million, respectively.
	Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years.  Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2014, 2013, and 2012 was $2.8 million, $3.1 million, and $2.7 million respectively.
	Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.
	Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset.  Accretion expense is recognized as the discounted liability is accreted to its expected settlement value.   Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.
	Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil and natural gas. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).
	Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.   All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows.
	Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.
	The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Benefit from (provision for) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.
	We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.
	We have considered our exposure under the standard at both the federal and state tax levels.  We have not recorded any liabilities for uncertain tax positions as of December 31, 2014 and 2013. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2014,  2013, or 2012.
	The Company’s tax returns for the years ended December 31, 2010 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.
	Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed.
	Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The estimated of fair value of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $380.3 million on December 31, 2014. Derivative financial instruments are carried at fair value. See Note 5 for further information on fair values of financial instruments. See Note 9 for information on long-term debt.
	Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.
	Recent Accounting Pronouncements
	In April 2014, the Financial Accounting Standards Board issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results.  The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations.  In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented.  ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”  We early adopted ASU 2014-08 as of January 1, 2014 and have provided disclosures in accordance with this new guidance in Note 3.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement 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. We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.
	In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  The new standard requires management to assess the company’s ability to continue as a going concern.  Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements.  The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016.    We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.
	In January 2015, the FASB issued ASU 2015-01, Extraordinary and Unusual Items.  The new standard eliminates the concept of “extraordinary items,” which prior guidance required to be presented separately from income from continuing operations.  Items that are infrequent and unusual in nature are to be disclosed either on the face of the financial statements as a component of income from continuing operations or in the notes to the financial statements.  ASU 2015-01 is effective for years beginning after December 15, 2015, with early adoption permitted.  We adopted the guidance on January 1, 2015.   We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.

Significant_Acquisitions_And_D

Significant Acquisitions And Divestitures	12 Months Ended
	Dec. 31, 2014
Significant Acquisitions And Divestitures [Abstract]
Significant Acquisitions And Divestitures	NOTE 3 — SIGNIFICANT ACQUISITIONS AND DIVESTITURES
	Eagleville Divestiture
	On March 25, 2014, we closed the sale of certain of our properties located primarily in Karnes County, Texas to Memorial Production Operating LLC, comprising a portion of our Eagleville field (“Eagleville divestiture”).  The properties sold included a working interest in all of our producing wells as of the effective date of January 1, 2014.  We retained a net profits interest in these wells based on 50% of our original working interest in 2014, declining to 30% in 2015, 15% in 2016, and zero in 2017.  Also included in the sale was a 30% undivided interest in all our Eagleville mineral leases and interests, and 30% of our working interest in all our wells in progress on December 31, 2013 or drilled after January 1, 2014.  The initial cash purchase price was $173 million, subsequently adjusted to approximately $171 million for settlement adjustments through December 31, 2014.  The purchase and sale agreement provides for customary adjustments to the purchase price for revenues and expenses incurred after the effective date.  As of December 31, 2014, estimated net proved reserves associated with the sold portion of these properties were approximately 7.5 MMBOE.  We recorded a preliminary gain on sale from the Eagleville divestiture of $72.5 million during 2014, based on a preliminary allocation of basis between the properties sold and properties retained.
	The sold portion of Eagleville field contributed approximately $11.1 million in the first quarter of 2014, prior to its sale. The sold portion of Eagleville field contributed approximately $47.0 million and $22.1 million in net pre-tax profit for the years ended December 31, 2013 and 2012.
	Hilltop Divestiture
	On October 2, 2013, we closed the sale of certain of our properties in East Texas, comprising a portion of our Hilltop field (“Hilltop divestiture”). The properties sold were primarily producers of dry natural gas located in Leon County, Texas. As of July 1, 2013, estimated net proved reserves associated with these properties were 11.2  BCFE. The cash purchase price was approximately $19 million (net of costs of the sale).   There was no material gain on the sale.
	On September 19, 2014, we sold our remaining interests in the Hilltop field for a cash payment of $41.6 million, which was subsequently adjusted to $38.9 million for customary settlement adjustments. We recorded a preliminary gain on the sale of $15.9 million.  As of the date of sale, estimated proved reserves associated with these properties were 29.8 BCFE.
	The Hilltop interests contributed approximately $7.7 million in net pre-tax income during the year ended December 31, 2014 and $6.9 million and $53.2 million in net pre-tax loss during the years ended December 31, 2013 and 2012, respectively.
	Weeks Island Acquisition
	On October 1, 2013, we closed a transaction to purchase certain producing properties in South Louisiana from Stone Energy Offshore, L.L.C. (“Stone”) for cash consideration of approximately $42 million plus related abandonment costs. This purchase increased our working interest in our Weeks Island field. Total estimated net proved reserves associated with the acquisition were 1.8 million BOE as of the effective date of July 1, 2013.
	A summary of the consideration paid and the preliminary allocation of the purchase prices are as follows:
		October 1,
		2013
		(dollars in thousands)
	Summary of Consideration
	Cash	$	41,841
	Fair value of asset retirement obligations assumed		5,311
	Total	$	47,152
	Summary of Purchase Price Allocation
	Proved oil and natural gas properties	$	30,279
	Unproved oil and natural gas properties		16,873
	Total	$	47,152
	The revenue and earnings related to the Weeks Island acquisition are included in our consolidated statement of operations for the year ended December 31, 2013 from date of acquisition. The revenue and earnings of the combined entity, had the acquisitions occurred at January 1, 2012, are provided below. This unaudited pro forma information has been derived from historical information and is for illustrative purposes only. The unaudited pro forma financial information does not attempt to predict or suggest future results. It also does not necessarily reflect what the historical results of the combined company would have been had the companies been combined during these periods.
		Total		Income
		Revenue		(Loss)
		(dollars in thousands)
	Actual results of Weeks Island included in our statement of operations for the period October 1, 2013
	through December 31, 2013	$	10,509	$	8,575
	Pro forma results for the combined entity for the year ended December 31, 2012	$	340,103	$	-85,985
	Pro forma results for the combined entity for the year ended December 31, 2013	$	376,063	$	-146,866
	Other
	During 2013, we sold our drilling rig for a cash purchase price of approximately $7.0 million and recorded a loss on sale of approximately $1.2 million.

Property_And_Equipment

Property And Equipment	12 Months Ended
	Dec. 31, 2014
Property And Equipment [Abstract]
Property And Equipment	NOTE 4 — PROPERTY AND EQUIPMENT
	Property and equipment consists of the following:
		December 31,		December 31,
		2014		2013
		(dollars in thousands)
	OIL AND NATURAL GAS PROPERTIES
	Unproved properties	$	84,620	$	86,721
	Accumulated impairment		-3,749		-7,356
	Unproved properties, net		80,871		79,365
	Proved oil and natural gas properties		1,417,785		1,405,658
	Accumulated depreciation, depletion, amortization and impairment		-812,480		-793,253
	Proved oil and natural gas properties, net		605,305		612,405
	TOTAL OIL AND NATURAL GAS PROPERTIES, net		686,176		691,770
	LAND		2,820		1,418
	OTHER PROPERTY AND EQUIPMENT
	Office furniture and equipment, vehicles		17,302		13,802
	Accumulated depreciation		-8,617		-6,120
	OTHER PROPERTY AND EQUIPMENT, net		8,685		7,682
	TOTAL PROPERTY AND EQUIPMENT, net	$	697,681	$	700,870
	Capitalized Exploratory Well Costs
	The following table reflects the net changes in deferred capitalized exploratory well costs during 2014, 2013, and 2012. The table does not include amounts that were capitalized and either subsequently expensed or reclassified to producing well costs in the same year.
		Year Ended December 31,
		2014		2013		2012
		(dollars in thousands)
	Balance, beginning of year	$	18,364	$	4,627	$	—
	Additions to capitalized well costs pending determination of proved reserves		2,889		21,693		4,627
	Capitalized exploratory well costs charged to expense		-16,706		-7,956		—
	Balance, end of year	$	4,547	$	18,364	$	4,627
	The ending balance in deferred capitalized exploratory well costs includes the costs of five wells in two different prospects.  We have capitalized $2.2 million and $0 of exploratory well costs covering periods greater than one year at December 31, 2014 and 2013.

Fair_Value_Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Disclosures	NOTE 5 — FAIR VALUE DISCLOSURES
	The Company follows ASC 820, “Fair Value Measurements and Disclosure.” ASC 820 provides a hierarchy of fair value measurements, based on the inputs to the fair value estimation process. It requires disclosure of fair values classified according to defined “levels,” which are based on the reliability of the evidence used to determine fair value, with Level 1 being the most reliable and Level 3 the least. Level 1 evidence consists of observable inputs, such as quoted prices in an active market. Level 2 inputs typically correlate the fair value of the asset or liability to a similar, but not identical item which is actively traded. Level 3 inputs include at least some unobservable inputs, such as valuation models developed using the best information available in the circumstances.
	We utilize the modified Black-Scholes and the Turnbull Wakeman option pricing models to estimate the fair values of oil and natural gas derivative contracts. Inputs to these models include observable inputs from the New York Mercantile Exchange (NYMEX) and other exchanges for futures contracts, and inputs derived from NYMEX observable inputs, such as implied volatility of oil and natural gas prices. We have classified the fair values of all our oil and natural gas derivative contracts as Level 2.
	The fair value of our interest rate derivative contracts, which expired in 2012, was calculated using the Black-Scholes option pricing model and is also considered a Level 2 fair value.
	Our senior notes are carried at historical cost, net of amortized discount; we estimate the fair value of the senior notes for disclosure purposes (see Note 2). This estimation is based on the most recent trading values of the notes at or near the reporting date, a Level 1 classification.
	Oil and natural gas properties are subject to impairment testing and potential impairment write down as described in Note 2. Oil and natural gas properties with a carrying amount of $148.4 million were written down to their fair value of $73.5 million, resulting in an impairment charge of $74.9 million for the year ended December 31, 2014. Oil and natural gas properties with a carrying amount of $237.2 million were written down to their fair value of $94.0 million, resulting in an impairment charge of $143.2 million for the year ended December 31, 2013. Oil and natural gas properties with a carrying amount of $363.7 million were written down to their fair value of $267.5 million, resulting in an impairment charge of $96.2 million for the year ended December 31, 2012. The impairment analysis is based on the estimated discounted future cash flows for those properties. Significant Level 3 assumptions used in the calculation of estimated discounted cash flows included our estimate of future oil and natural gas prices, production costs, development expenditures, estimated quantities and timing of production of proved reserves, appropriate risk-adjusted discount rates, and other relevant data.
	In connection with the Stone acquisition in 2013 we recorded oil and natural gas properties with a fair value of $47.2 million.  Significant Level 3 inputs used were the same as those used in determining impairments based on estimated discounted cash flows for the acquired properties.
	New additions to asset retirement obligations result from estimations for new properties, and fair values for them are categorized as Level 3. Such estimations are based on present value techniques which utilize company-specific information for such inputs as cost and timing of plug and abandonment of wells and facilities. We recorded a total of $4.1 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2014.  We recorded a total of $6.5 million in additions to asset retirement obligations measured at fair value for the year ended December 31, 2013.
	The following table presents information about our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2014 and 2013, and indicates the fair value hierarchy of the valuation techniques we utilized to determine such fair value:
		Level 1		Level 2		Level 3		Total
			(dollars in thousands)
	At December 31, 2014:
	Financial Assets:
	Derivative contracts for oil and natural gas		—	$	140,652		—	$	140,652
	Financial Liabilities:
	Derivative contracts for oil and natural gas		—	$	53,578		—	$	53,578
	At December 31, 2013:
	Financial Assets:
	Derivative contracts for oil and natural gas		—	$	27,850		—	$	27,850
	Financial Liabilities:
	Derivative contracts for oil and natural gas		—	$	27,842		—	$	27,842
	The amounts above are presented on a gross basis; presentation on our consolidated balance sheets utilizes netting of assets and liabilities with the same counterparty where master netting agreements are in place.
	For additional information on derivative contracts, see Note 6.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Financial Instruments [Abstract]
Derivative Financial Instruments	NOTE 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 and natural gas. 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 crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMBtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly. No derivative contracts have been entered into for trading purposes.
	From time to time, we enter into interest rate swap agreements with financial institutions to mitigate the risk of loss due to changes in interest rates.
	We have not designated any of our derivative contracts as fair value or cash flow hedges; accordingly we use mark-to-market accounting, recognizing changes in the fair value of derivative contracts in the consolidated statement of operations at each reporting date.
	Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets.  Likewise, derivative (liabilities) could be presented in an asset account.
	The following table summarizes the fair value (see Note 5 for further discussion of fair value) and classification of our derivative instruments, none of which have been designated as hedging instruments under ASC 815:
								Net Fair
		Gross			Gross amounts			Value of Assets
	31-Dec-14	Fair Value			offset against assets			presented in
	Balance sheet location	of Assets			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current assets	$	91,341		$	-31,538		$	59,803
	Derivative financial instruments, long-term assets		55,325			-28,054			27,271
	Total	$	146,666		$	-59,592		$	87,074
								Net Fair
		Gross			Gross amounts			Value of Liabilities
	31-Dec-14	Fair Value			offset against liabilities			presented in
	Balance sheet location	of Liabilities			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current liabilities	$	31,538		$	-31,538		$	—
	Derivative financial instruments, long-term liabilities		28,054			-28,054			—
	Total	$	59,592		$	-59,592		$	—
								Net Fair
		Gross			Gross amounts			Value of Assets
	31-Dec-13	Fair Value			offset against assets			presented in
	Balance sheet location	of Assets			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current assets	$	13,218		$	-7,646		$	5,572
	Derivative financial instruments, long-term assets		14,632			-11,227			3,405
	Total	$	27,850		$	-18,873		$	8,977
								Net Fair
		Gross			Gross amounts			Value of Liabilities
	31-Dec-13	Fair Value			offset against liabilities			presented in
	Balance sheet location	of Liabilities			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current liabilities	$	12,129		$	-7,646		$	4,483
	Derivative financial instruments, long-term liabilities		15,713			-11,227			4,486
	Total	$	27,842		$	-18,873		$	8,969
	The following table summarizes the effect of our derivative instruments in the consolidated statements of operations (dollars in thousands):
	Derivatives not
	designated as hedging	Location of		Year Ended December 31,
	instruments under ASC 815	Gain (Loss)		2014			2013			2012
	Oil commodity contracts	Gain (loss) —
		oil and natural gas
		derivative contracts		$	82,510		$	-17,715		$	3,720
	Natural gas commodity contracts	Gain (loss) —
		oil and natural gas
		derivative contracts			14,049			565			16,031
	Total gains (losses) from oil and				96,559			-17,150			19,751
	natural gas commodity contracts
	Interest rate contracts	Interest expense			—			—			-37
	Total gains (losses) from
	derivatives not designated as hedges			$	96,559		$	-17,150		$	19,714
	Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.
	We had the following open derivative contracts for crude oil at December 31, 2014:
	OIL DERIVATIVE CONTRACTS
		Volume		Weighted			Range
	Period and Type of Contract	in Bbls		Average			High			Low
	2015
	Price Swap Contracts	1,587,000			91.39			95.02			86.45
	Collar Contracts
	Short Call Options	392,350			114.10			135.98			95.50
	Long Put Options	1,049,350			85.78			90.00			85.00
	Short Put Options	1,998,350			70.05			75.00			60.00
2016
Price Swap Contracts	366,000			93.00			94.92			85.35
Collar Contracts
Short Call Options	859,700			107.97			130.00			103.87
Long Put Options	859,700			85.99			95.00			80.00
Short Put Options	1,225,700			68.67			75.00			60.00
2017
Collar Contracts
Short Call Options	744,950			107.99			113.83			104.15
Long Put Options	744,950			83.26			90.00			80.00
Short Put Options	744,950			63.26			70.00			60.00
2018
Collar Contracts
Short Call Options	307,400			104.39			104.65			104.15
Long Put Options	307,400			80.00			80.00			80.00
Short Put Options	307,400			60.00			60.00			60.00
We had the following open derivative contracts for natural gas at December 31, 2014:
NATURAL GAS DERIVATIVE CONTRACTS
	Volume in		Weighted			Range
Period and Type of Contract	MMBtu		Average			High			Low
2015
Price Swap Contracts	3,832,500			5.07			5.91			4.31
Collar Contracts
Short Call Options	7,750,000			4.59			5.75			4.51
Long Put Options	8,113,500			4.01			5.00			3.50
Long Call Options	495,000			4.31			4.31			4.31
Short Put Options	9,116,000			3.34			4.45			3.25
2016
Price Swap Contracts	8,418,000			4.22			4.23			4.22
Collar Contracts
Short Call Options	455,000			7.50			7.50			7.50
Long Put Options	455,000			5.50			5.50			5.50
Short Put Options	1,681,100			3.64			4.00			3.50
2017
Collar Contracts
Short Call Options	6,570,000			5.00			5.00			4.98
Long Put Options	6,570,000			4.50			4.50			4.50
Short Put Options	6,570,000			4.00			4.00			4.00
2018
Collar Contracts
Short Call Options	5,475,000			5.50			5.53			5.48
Long Put Options	5,475,000			4.50			4.50			4.50
Short Put Options	5,475,000			4.00			4.00			4.00
In those instances where contracts are identical as to time period, volume, strike price, and counterparty, but opposite as to direction (long and short), the volumes and average prices have been netted in the two tables above. Prices stated in the table above for oil may settle against either NYMEX, Brent ICE, or Argus Louisiana Light Sweet Crude indices or quotations, or may reflect a mix of positions settling on various of these benchmarks.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Asset Retirement Obligations	NOTE 7 — ASSET RETIREMENT OBLIGATIONS
	A summary of the changes in our asset retirement obligations is included in the table below:
		Year Ended December 31,
		2014		2013		2012
		(dollars in thousands)
	Balance, beginning of year	$	56,023	$	48,593	$	46,096
	Liabilities incurred		1,129		1,052		787
	Liabilities assumed with acquired producing properties		3,002		5,480		1,476
	Liabilities settled		-3,942		-1,548		-3,562
	Liabilities transferred in sales of properties		-1,886		-606		—
	Revisions to estimates		6,348		919		1,983
	Accretion expense		2,198		2,133		1,813
	Balance, end of year		62,872		56,023		48,593
	Less: Current portion		1,136		3,844		64
	Long term portion	$	61,736	$	52,179	$	48,529
	The total revisions included $2.9 million,  $0.4 million, and $0.9 million related to additions to property, plant and equipment for the years ended December 31, 2014, 2013, and 2012, respectively.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	NOTE 8 — RELATED PARTY TRANSACTIONS
	We have notes payable to our founder which bear interest at 10% with a balance of $24.5 million and $23.3 million at December 31, 2014 and 2013, respectively. See further information at Note 9.
	During 2014 and 2013 Michael E. Ellis, our founder, Chief Operating Officer, and Chairman of the Board, received capital distributions from us of $516,500 and $17,500, respectively.
	David Murrell, our Vice President, Land and Business Development, is the principal of David Murrell & Associates, which provides land consulting services to us. The primary employee of David Murrell & Associates is his spouse, Brigid Murrell. Services are provided at a pre-negotiated hourly rate based on actual time employed by us. Total expenditures under this arrangement for the years ended December 31, 2014, 2013 and 2012 were approximately $150,000,  $175,000 and $116,000. The contract may be terminated by either party without penalty upon 30 days’ notice.
	David McClure, our Vice President, Louisiana Operations, and the son-in-law of our CEO, Harlan H. Chappelle, received total compensation of $450,000,  $390,000 and $327,000 for the years ended December 31, 2014, 2013 and 2012. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.
	David Pepper,  one of our Landmen, and the nephew of our Vice President, Land and Business Development, David Murrell, received total compensation of $260,000,  $125,000 and $105,000 for the years ended December 31, 2014, 2013 and 2012. Additionally, his position provides him with the use of a company vehicle, similar to our other engineers whose duties include field oversight.
	On December 31, 2014, we sold our interests in a partially constructed pipeline and gas processing plant at cost to an affiliate of our Class B unitholder, High Mesa. We recorded $25.5 million in other receivable and $8.5 million in long term note receivable, while recording no gain or loss on the sale at December 31, 2014.  On January 2, 2015, the receivable of $25.5 million was paid. The $8.5 million note receivable, dated December 31, 2014, bears interest at 8% per annum, interest payable only in quarterly installments beginning January 1, 2015, and matures on December 31, 2019.  Immediately after the consummation of the transaction, the $8.5 million promissory note was transferred from NWGP to HMS, a subsidiary of the Parent company High Mesa.  The Company believes the note to be fully collectible and accordingly has not recorded a reserve.
	Alta Mesa is a part owner of AEM with an ownership interest of less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee.  For additional information on AEM, see Note 12.

Long_Term_Debt

Long Term Debt	12 Months Ended
	Dec. 31, 2014
Long Term Debt [Abstract]
Long Term Debt	NOTE 9 — LONG TERM DEBT
	Long-term debt consists of the following:
		December 31,			December 31,
		2014			2013
		(dollars in thousands)
	Credit Facility	$	319,520		$	319,290
	Senior Notes		448,088			447,578
	Total long-term debt	$	767,608		$	766,868
	Notes payable to founder	$	24,540		$	23,331
	Credit Facility. On May 13, 2010, we entered into a Sixth Amended and Restated Credit Agreement (as amended, the “credit facility”). The credit facility matures on May 23, 2016 and is secured by substantially all of our oil and natural gas properties. The credit facility borrowing base is redetermined periodically and, as of December 31, 2014, the borrowing base under the facility was $375.0 million. The credit facility bears interest at LIBOR plus applicable margins between 2.00% and 2.75% or a “Reference Rate,” which is based on the prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%, depending on the utilization of our borrowing base. The weighted average rate on outstanding borrowings was 2.89% as of December 31, 2014 and 2.75% as of December 31, 2013.   The letters of credit outstanding as of December 31, 2014 and 2013 were $0.9 million and $65,000, respectively.
	The credit facility contains customary covenants including, among others, defined financial covenants, including minimum working capital levels (the ratio of current assets plus the unused borrowing base, to current liabilities, excluding assets and liabilities related to derivative contracts) of 1.0 to 1.0, minimum coverage of interest expenses of 3.0 to 1.0, and maximum leverage of 4.00 to 1.00.  The interest coverage and leverage ratios refer to the ratio of earnings before interest, taxes, depreciation, depletion, amortization, and exploration expense (“EBITDAX”, as defined more specifically in the credit agreement) to interest expense and to total debt (as defined), respectively. Financial ratios are calculated quarterly using EBITDAX for the most recent twelve months.
	As of December 31, 2014, we were in compliance with all covenants.  The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Recent declines in prices for oil and natural gas may cause our banks to reduce the borrowing base under our revolving credit facility when it is next redetermined in May 2015.
	Senior Notes. We have $450 million in outstanding registered senior notes due October 15, 2018 that carry a stated interest rate of 9.625% and an effective interest rate of 9.7825%.  Interest is payable semi-annually each April 15th and October 15th.    The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries. The balance is presented net of unamortized discount of $1.9 million and $2.4 million at December 31, 2014 and December 31, 2013, respectively.
	The senior notes contain an optional redemption provision available beginning October 15, 2015 allowing us to retire the principal outstanding, in whole or in part, at 102.406%.  Additional optional redemption provisions allow for retirement at 100.0% beginning on October 15, 2016, respectively.
	Notes Payable to Founder. We have notes payable to our founder which bear simple interest at 10% with a balance of $24.5 million and $23.3 million at December 31, 2014 and December 31, 2013, 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. The notes are convertible into shares of our Class B partner, High Mesa, common stock upon certain conditions in the event of an initial public offering.
	These founder notes are unsecured and are subordinate to all debt.  In connection with the March 25, 2014 recapitalization of our Class B partner described in Note 15, 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 amended partnership agreement and subordinated to the rights of the holders of Series B Preferred Stock to receive payments.
	Interest on the notes payable to our founder amounted to $1.2 million during each of 2014, 2013, and 2012. Such amounts have been added to the balance of the founder notes.
	Future maturities of long-term debt, including the notes payable to our founder and unamortized discount, at December 31, 2014 are as follows (dollars in thousands):
	Year ending December 31,
	2015		$	—
	2016			319,520
	2017			—
	2018			450,000
	2019			—
	Thereafter			24,540
			$	794,060
	The credit facility and senior notes include covenants requiring that we maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio. At December 31, 2014, we were in compliance with the covenants. The terms of the credit facility also restrict our ability to make distributions and investments.

Accounts_Payable_And_Accrued_L

Accounts Payable And Accrued Liabilities	12 Months Ended
	Dec. 31, 2014
Accounts Payable And Accrued Liabilities [Abstract]
Accounts Payable And Accrued Liabilities	NOTE 10 — ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
	The following provides the detail of accounts payable and accrued liabilities:
		December 31,		December 31,
		2014		2013
		(dollars in thousands)
	Capital expenditures	$	32,990	$	18,629
	Revenues and royalties payable		7,302		9,699
	Operating expenses/taxes		20,716		17,071
	Interest		9,136		9,146
	Compensation		10,586		8,862
	Other		2,605		2,711
	Total accrued liabilities		83,335		66,118
	Accounts payable		34,225		29,977
	Accounts payable and accrued liabilities	$	117,560	$	96,095

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies [Abstract]
Commitments And Contingencies	NOTE 11 — COMMITMENTS AND CONTINGENCIES
	Contingencies
	Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East:    On July 24, 2013, the Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East sued us and approximately 100 other energy companies for long-term damage to the wetlands in southeast Louisiana.  Case No. 2013-6911 was filed in state court and subsequently remanded to federal court.  The plaintiff seeks damages and injunctive relief in the form of abatement and restoration of wetlands, alleging that the activities of the oil and gas industry over the past century have contributed significantly to the degradation of the wetlands that protect the populated areas in and around New Orleans from storm surge and other extreme weather effects.  The plaintiff alleges damages from increased costs of providing man-made storm protection structures, and emphasizes the destructive effect of canals built by the oil and gas industry.  Legal arguments include breach of the restoration and maintenance clauses of contracts with the State of Louisiana for drilling, dredging, and right-of-way agreements for pipelines.  Other legal arguments include negligence, strict liability, natural servitude of drain, public nuisance and private nuisance.   Our wholly-owned subsidiary The Meridian Resource Company, LLC is named as a defendant with 32 wells, two dredging permits and four right of way agreements in the relevant area.  Almost all of these wells are inactive.  In June 2014, Act 544 of the Louisiana Legislature was enacted, stating that the plaintiff does not have the authority to bring this suit.  However, the constitutionality of Act 544 may be litigated, and this development does not end the litigation to which we are a party.
	On February 13, 2015, the case was dismissed by the U.S. District Judge.  As of December 31, we have not provided any amount for this matter in our consolidated financial statements.
	Environmental claims:  Various landowners have sued the Company and/or our wholly owned subsidiaries, 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 amount for these claims in our consolidated financial statements at December 31, 2014.
	Due to the nature of our business, some contamination of the real estate property owned or leased by us is possible. Environmental site assessments of the property would be necessary to adequately determine remediation costs, if any.  Management has established a liability for soil contamination in Florida of $1.1 million at December 31, 2014 and $1.1 million at December 31, 2013, based on our undiscounted engineering estimates. The obligations are included in other long-term liabilities in the accompanying consolidated balance sheets.
	Title/lease disputes: Title and lease disputes may arise in the normal course of our operations. These disputes have historically been 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.
	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 value.  The PARs vest over time (as specified in each grant, typically five years) and entitle the owner to receive a cash amount equal to the increase, if any, between the initial stipulated value 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 intended to be either a recapitalization or an initial public offering of Company equity) 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 2014, we granted 271,500 PARs at a weighted average initial value of $33.19.  Subsequently to year end, 27,500 PARs with present value of $40 were terminated, resulting in 244,000 PARs issued at a weighted average value of $32.42.  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 December 31, 2014.
	Other contingencies: We are subject to legal proceedings, claims and liabilities arising in the ordinary course of business. 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.
	We have a contingent commitment to pay an amount up to a maximum of approximately $2.2 million for properties acquired in 2008. The additional purchase consideration will be paid if certain product price conditions are met.
	Commitments
	Office and Equipment Leases: We lease office space, as well as certain field equipment such as compressors, under long-term operating lease agreements. The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease. Equipment leases are generally for four years or less. Rent expense, including office space and compressors, for the years ended December 31, 2014, 2013, and 2012 amounted to approximately $5.7 million, $5.3 million, and $4.5 million, respectively.
	At December 31, 2014, future base rentals for non-cancelable operating leases are as follows (dollars in thousands):
	Year Ending December 31,
	2015	$	2,004
	2016		1,562
	2017		1,552
	2018		1,529
	2019		1,580
	Thereafter		4,420
		$	12,647
	Additionally, at December 31, 2014, the Company had posted bonds in the aggregate amount of $24.2 million, primarily to cover future abandonment costs.

Major_Customers

Major Customers	12 Months Ended
	Dec. 31, 2014
Major Customers [Abstract]
Major Customers	NOTE 12 — MAJOR CUSTOMERS
	We sell our oil and natural gas primarily under a contract with ARM Energy Management, LLC (“AEM”). Alta Mesa is a part owner of AEM with an ownership interest of less than 10%.  AEM purchases our oil and natural gas and sells it under short-term contracts generally with month-to-month pricing based on published regional indices, with differentials for transportation, location, and quality taken into account. AEM remits monthly proceeds of its sales to us, and receives a 1% marketing fee. Sales to AEM commenced in June 2013. The agreement will terminate in 2018, with additional provisions for extensions beyond five years, and for early termination beginning in January 2015. During the second half of 2013 and throughout 2014, we sold the majority of our production from operated fields to AEM. Production from non-operated fields, the most significant of which were our Eagleville oil field in South Texas and our Hilltop natural gas field in East Texas, was marketed on our behalf by the operators of those properties. Production from the Eagleville field was sold by Murphy Oil Corporation (“Murphy”), the operator of that property. Production from the Hilltop field was sold primarily by EnCana Oil & Gas (USA), Inc. (“EnCana”), the operator of a substantial portion of the wells in that field.
	For the year ended December 31, 2014, revenues from AEM were $220.9 million, or 51.1% of total revenue excluding hedging activities. Based on revenues excluding hedging activities, one other major customer, Murphy accounted for 10% or more of revenues, with revenues excluding hedging activities of $61.2 million. For the year ended December 31, 2013, revenues from AEM were $61.3 million, or 16% of total revenue excluding hedging activities. Based on revenues excluding hedging activities,  three other major customers accounted for 10% or more of those revenues individually, with contributions of $119.3 million (Murphy), $53.9 million (Shell Trading (US) Company), and $42.0 million (Plains Marketing and Transportation, Inc.)  On the same basis, for the year ended December 31, 2012, three major customers accounted for 10% or more of those revenues individually, with contributions of $63.3 million (Shell Trading (US) Company), $50.1 million (Murphy), and $44.8 million (EnCana).    We believe that the loss of any of our significant direct or indirect customers, or of AEM, would not have a material adverse effect on us because alternative purchasers are readily available.

401k_Savings_Plan

401(k) Savings Plan	12 Months Ended
	Dec. 31, 2014
Savings Plan [Abstract]
401(k) Savings Plan	NOTE 13 — 401(k) SAVINGS PLAN
	Employees of Alta Mesa Services and Petro Operating Company, LP (“POC”) may participate in a 401(k) savings plan, whereby the employees may elect to make contributions pursuant to a salary reduction agreement. Alta Mesa Services and POC make a matching contribution equal to 50% of an employee’s salary deferral contribution up to a maximum of 8% of an employee’s salary. Matching contributions to the plan were approximately $683,000,  $585,000, and $422,000 for the years ended December 31, 2014, 2013, and 2012, respectively.

Significant_Risks_And_Uncertai

Significant Risks And Uncertainties	12 Months Ended
	Dec. 31, 2014
Significant Risks And Uncertainties [Abstract]
Significant Risks And Uncertainties	NOTE 14 — SIGNIFICANT RISKS AND UNCERTAINTIES
	Our business makes us vulnerable to changes in wellhead prices of  oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and declined dramatically in the second half of the year.  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 reserves.  Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.    We mitigate some of this vulnerability by entering into oil and natural gas price derivative contracts. See Note 6.

Partners_Capital_Deficit

Partners' Capital (Deficit)	12 Months Ended
	Dec. 31, 2014
Partners' Capital (Deficit) [Abstract]
Partners' Capital (Deficit)	NOTE 15 — PARTNERS’ CAPITAL (DEFICIT)
	Our partnership agreement provides for two classes of limited partners.  Class A partners include our founder and other parties.  Our Class B partner was Alta Mesa Investment Holdings, Inc. (“AMIH”).  AMIH has subsequently changed its name to High Mesa, Inc. (“High Mesa”).  Prior to March 25, 2014, AMIH was an affiliate of Denham Capital Management LP, a private equity firm focused on energy and commodities.
	On March 25, 2014, High Mesa completed a $350 million recapitalization with an investment from Highbridge Principal Strategies LLC (“Highbridge”).  Proceeds from the investment were used in part to purchase the investment of Denham Capital Management LP in High Mesa. Our Board of Directors includes one member nominated by Highbridge and four members nominated by the Class A partners.  High Mesa is our sole Class B partner.
	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. The Class B limited partner has certain approval rights, generally over capital plans and significant transactions in the areas of finance, acquisition, and divestiture.
	Ownership of High Mesa is distributed among two classes of equity.  Highbridge owns all of the convertible PIK preferred stock of High Mesa.  The common stock of High Mesa is owned by our Class A partners. Highbridge also holds senior PIK notes issued by High Mesa.
	Distribution and Income Allocation: In connection with the recapitalization, our partnership agreement was amended and restated to provide, among other things, that all distributions under the partnership agreement shall first be made to holders of Class B Units, until all principal and interest has been extinguished under the senior PIK notes issued by High Mesa to Highbridge.  After such extinguishment of the senior PIK notes, distributions shall then be made to holders of Class A and Class B Units pursuant to the distribution formulas set forth in the amended 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 any event in which we receive cash proceeds outside the ordinary course of our business. 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.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2014
Subsequent Events [Abstract]
Subsequent Events	NOTE 16 — SUBSEQUENT EVENTS
	The Company has evaluated the period after the balance sheet date, noting no subsequent events or transactions that required recognition or disclosure in the financial statements.

Subsidiary_Guarantors

Subsidiary Guarantors	12 Months Ended
	Dec. 31, 2014
Subsidiary Guarantors [Abstract]
Subsidiary Guarantors	NOTE 17 — SUBSIDIARY GUARANTORS
	All of our material wholly-owned subsidiaries are guarantors under the terms of both our senior notes and our credit facility.
	Our consolidated financial statements reflect the combined financial position of these subsidiary guarantors. Our 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 are minor. There are no restrictions on dividends, distributions, loans, or other transfers of funds from the subsidiary guarantors to our parent company.

Supplemental_Quarterly_Informa

Supplemental Quarterly Information	12 Months Ended
	Dec. 31, 2014
Supplemental Quarterly Information [Abstract]
Supplemental Quarterly Information
	NOTE 18 — SUPPLEMENTAL QUARTERLY INFORMATION (Unaudited)
	Results of operations by quarter for the year ended December 31, 2014 were:
		Quarter Ended
	2014	31-Mar			30-Jun		30-Sep		31-Dec
			(dollars in thousands)
	Revenues (1)	$	165,891		$	86,254	$	184,111	$	179,951
	Income (loss) from operations (2)		71,461			-25,186		73,025		35,873
	Net income (loss)	$	56,893		$	-38,812	$	59,326	$	21,793
		-1		Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively.
		-2		Includes $18.3 million and $8.7 million of impairment expense in June 30, 2014 and September 30, 2014, respectively.
	Results of operations by quarter for the year ended December 31, 2013 were:
		Quarter Ended
	2013	31-Mar			30-Jun		30-Sep		31-Dec
			(dollars in thousands)
	Revenues	$	68,578		$	123,531	$	77,759	$	85,924
	Income (loss) from operations (3)		-1,066			29,799		-11,915		-115,469
	Net income (loss)	$	-14,286		$	16,168	$	-25,737	$	-129,860
		-3		Includes $7.4 million, $19.2 million and $114.5 million of impairment expense in March, 31, 2013, June 30, 2013 and December 31, 2013, respectively.

Supplemental_Oil_And_Natural_G

Supplemental Oil And Natural Gas Disclosures	12 Months Ended
	Dec. 31, 2014
Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]
Supplemental Oil And Natural Gas Disclosures (Unaudited)	NOTE 19 — SUPPLEMENTAL OIL AND NATURAL GAS DISCLOSURES (Unaudited)
	The unaudited reserve and other information presented below is provided as supplemental information in accordance with the provisions of ASC Topic 932-235.
	Oil and natural gas producing activities are conducted onshore within the continental United States and all of our proved reserves are located within the United States.
	Estimated Quantities of Proved Reserves
	The following table sets forth our net proved reserves as of December 31, 2014, 2013, and 2012, and the changes therein during the years then ended. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made.
			Oil		Gas		NGL's	BOE
			(MBbls)		(MMcf)		(MBbls)	(MBbls)
	Total Proved Reserves:
	Balance at December 31, 2011		16,933		217,266		4,845	57,989
	Production		-2,138		-21,372		-365	-6,065
	Purchases in place		335		6,619		8	1,446
	Discoveries and extensions		10,173		18,870		1,187	14,505
	Revisions of previous quantity estimates and other		-4,683		-68,894		20	-16,144
	Balance at December 31, 2012		20,620		152,489		5,695	51,731
	Production		-2,897		-16,664		-398	-6,072
	Purchases in place		1,462		1,265		—	1,673
	Discoveries and extensions		14,541		29,012		1,969	21,345
	Sales of reserves in place		-13		-10,912		—	-1,832
	Revisions of previous quantity estimates and other		-1,196		-22,925		-1,531	-6,549
	Balance at December 31, 2013		32,517		132,265		5,735	60,296
	Production		-3,770		-14,449		-537	-6,715
	Purchases in place		610		327		—	665
	Discoveries and extensions		13,281		28,822		4,119	22,204
	Sales of reserves in place		-6,298		-35,857		-949	-13,223
	Revisions of previous quantity estimates and other		-4,996		-7,960		20	-6,304
	Balance at December 31, 2014		31,344		103,148		8,388	56,923
	Proved Developed Reserves:
	Balance at December 31, 2012		10,467		111,206		4,209	33,211
	Balance at December 31, 2013		16,335		92,640		3,138	34,913
	Balance at December 31, 2014		15,182		63,334		4,028	29,765
	Proved Undeveloped Reserves:
	Balance at December 31, 2012		10,153		41,283		1,486	18,520
	Balance at December 31, 2013		16,182		39,625		2,597	25,383
	Balance at December 31, 2014		16,162		39,814		4,360	27,158
	Capitalized Costs Relating to Oil and Natural Gas Producing Activities
			December 31,
			2014			2013
			(dollars in thousands)
	Capitalized costs:
	Proved properties		$	1,417,785		$	1,405,658
	Unproved properties			84,620			86,721
	Total			1,502,405			1,492,379
	Accumulated depreciation, depletion, amortization and impairment			-816,229			-800,609
	Net capitalized costs		$	686,176		$	691,770
	Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
	Acquisition costs in the table below include costs incurred to purchase, lease, or otherwise acquire property. Exploration expenses include additions to exploratory wells, including those in progress, and other exploration expenses, such as geological and geophysical costs. Development costs include additions to production facilities and equipment and additions to development wells, including those in progress.
			Year Ended December 31,
			2014			2013		2012
			(dollars in thousands)
	Costs incurred during the year:
	Property acquisition costs
	Unproved		$	33,787		$	34,884	$	31,695
	Proved (1)			7,462			35,954		12,192
	Exploration			59,201			55,300		46,559
	Development (2)			341,594			242,912		200,974
			$	442,044		$	369,050	$	291,420
		-1		Property acquisition costs for proved properties in 2013 include primarily the proved portion of the Stone acquisition ($30.6 million).
	(2)   Includes asset retirement costs of $4.5 million, $1.4 million, and $1.7 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	Standardized Measure of Discounted Future Net Cash Flows
	The information that follows has been developed pursuant to ASC 932-235 and utilizes reserve and production data prepared by us. Reserve estimates are inherently imprecise and estimates of new discoveries are less precise than those of producing oil and natural gas properties. Accordingly, these estimates are expected to change as future information becomes available.
	Future cash inflows as of December 31, 2014 and 2013 were calculated using an un-weighted arithmetic average of oil and natural gas prices in effect on the first day of each month in the respective year, except where prices are defined by contractual arrangements. Operating costs, production and ad valorem taxes and future development costs are based on current costs with no escalation.
	Actual future prices and costs may be materially higher or lower. Actual future net revenues also will be affected by factors such as actual production, supply and demand for oil and natural gas, curtailments or increases in consumption by natural gas purchasers, changes in governmental regulations or taxation and the impact of inflation on costs.
	The following table sets forth the components of the standardized measure of discounted future net cash flows for the years ended December 31, 2014, 2013, and 2012:
			Year Ended December 31,
		2014			2013		2012
			(dollars in thousands)
Future cash flows		$	3,737,412		$	3,959,938	$	2,742,588
Future production costs			-991,149			-1,146,123		-928,398
Future development costs			-450,659			-474,191		-348,042
Future taxes on income			—			—		—
Future net cash flows			2,295,604			2,339,624		1,466,148
Discount to present value at 10 percent per annum			-877,558			-933,350		-551,727
Standardized measure of discounted future net cash flows		$	1,418,046		$	1,406,274	$	914,421
Base price for crude oil, per Bbl, in the above computation was:		$	94.99		$	96.78	$	94.71
Base price for natural gas, per Mcf, in the above computation was:		$	4.35		$	3.67	$	2.76
No consideration was given to the Company’s hedged transactions.
Changes in Standardized Measure of Discounted Future Net Cash Flows
The following table sets forth the changes in standardized measure of discounted future net cash flows:
		Year Ended December 31,
		2014			2013		2012
			(dollars in thousands)
Balance at beginning of year		$	1,406,274		$	914,421	$	1,070,196
Sales of oil and natural gas, net of production costs			-320,130			-263,952		-189,709
Changes in sales and transfer prices, net of production costs			-153,770			69,609		-291,285
Revisions of previous quantity estimates			-477,377			-150,634		-250,424
Purchases of reserves-in-place			21,633			93,877		10,283
Sales of reserves-in-place			-107,414			-11,193		—
Current year discoveries and extensions			701,820			621,832		420,496
Changes in estimated future development costs			2,591			11,623		54,493
Development costs incurred during the year			161,357			75,973		49,834
Accretion of discount			140,627			91,442		107,020
Net change in income taxes			—			—		—
Change in production rate (timing) and other			42,435			-46,724		-66,483
Net change			11,772			491,853		-155,775
Balance at end of year		$	1,418,046		$	1,406,274	$	914,421

Summary_Of_Significant_Account1

Summary Of Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
Summary Of Significant Accounting Policies [Abstract]
Principles Of Consolidation	Principles of Consolidation. The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries, after eliminating all significant intercompany transactions. The Company’s interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated.
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 impairments of oil and natural gas properties and are subject to change based on changes in oil and natural gas prices and trends and changes in estimated reserve quantities.  Other significant estimates include those related to oil and natural gas reserves, the value of oil and natural gas properties (including acquisition properties), oil and natural gas revenues, bad debts, asset retirement obligations, derivative contracts, state taxes and contingencies and litigation. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances. We review estimates and underlying assumptions on a regular basis.  Actual results may differ from these estimates.
Reclassifications	Reclassifications.   Certain amounts in the 2013 and 2012 consolidated financial statements have been reclassified to conform to the 2014 presentation. The reclassifications had no impact on net income (loss) or partners’ capital (deficit).
Cash And Cash Equivalents	Cash and Cash Equivalents. We consider all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents. The Company maintains cash balances at financial institutions in the United States of America, which at times exceed federally insured amounts. The Federal Deposit Insurance provides insurance up to $250,000 per depositor. We monitor the financial condition of the financial institutions and have experienced no losses associated with these accounts.
Restricted Cash	Restricted Cash.    The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of December 31, 2014, the Company had $24.6 million of proceeds from the sale of our Hilltop field Deep Bossier properties in a money market fund held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code. As December 31, 2014, the Company has utilized or plans to utilize $0.9 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on our consolidated balance sheet as of December 31, 2014. The remaining $23.7 million of restricted cash was returned to us in March 2015 and, as such, is classified as short-term restricted cash on our consolidated balance sheet as of December 31, 2014. For more information regarding the sale of the Hilltop field properties, please refer to Note 3—Significant Acquisitions and Divestitures.
Accounts Receivable	Accounts Receivable. Our receivables arise from the sale of oil and natural gas and joint interest owner receivables for properties in which we serve as the operator. This concentration of customers may impact our overall credit risk, either positively or negatively, in that these entities may be similarly affected by changes in economic or other conditions affecting the oil and natural gas industry. Accounts receivable are generally not collateralized.  Receivables from joint interest owners, including amounts advanced under joint operating agreements, were $10.3 million and $13.8 million at December 31, 2014 and 2013, respectively.  Trade receivables for the sale of oil and natural gas were $35.1 million and $37.8 million at December 31, 2014 and 2013, respectively.  See Note 12 for further information regarding marketing arrangements and sales to major customers, including our primary marketing representative, ARM Energy Management, LLC.  Accounts receivable from ARM Energy Management, LLC were $16.6 million and $7.5 million as of December 31, 2014 and 2013, respectively.
Allowance For Doubtful Accounts	Allowance for Doubtful Accounts. We routinely assess the recoverability of all material trade and other receivables to determine their collectability. We accrue a reserve when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve can be reasonably estimated. Accounts receivable are shown net of allowance for doubtful accounts of $1.4 million for the years ended December 31, 2014 and 2013, respectively.
Deferred Financing Costs	Deferred Financing Costs. Deferred financing costs and the amount of discount at which notes payable have been issued (debt discount) are amortized using the straight-line method, which approximates the interest method, over the term of the related debt. For the years ended December 31, 2014, 2013, and 2012, amortization of deferred financing costs included in interest expense amounted to $2.9 million, $2.8 million, and $2.4 million, respectively. Deferred financing costs are listed among our long-term assets, net of accumulated amortization of $15.6 million and $12.8 million at December 31, 2014 and 2013, respectively.
Property And Equipment	Property and Equipment. Oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, lease acquisition costs and all development costs, including unsuccessful development wells, are capitalized.
	Unproved Properties — Acquisition costs associated with the acquisition of leases are recorded as unproved properties and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease, in addition to options to lease, broker fees, recording fees and other similar costs related to activities in acquiring properties. Unproved properties are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.
	Exploration Expense — Exploration expenses, other than exploration drilling costs, are charged to expense as incurred. These expenses include seismic expenditures and other geological and geophysical costs, expired leases, gain or loss on settlement of asset retirement obligations and lease rentals. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense. Exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is being made. Assessments of such capitalized costs are made quarterly.
	Proved Oil and Natural Gas Properties — Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering, and storing oil and natural gas are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, and service wells, including unsuccessful development wells, are capitalized.
	Impairment — The capitalized costs of proved oil and natural gas properties are reviewed quarterly for impairment following the guidance provided in ASC 360-10-35, “Property, Plant and Equipment, Subsequent Measurement,” or whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset or asset group exceeds its fair market value and is not recoverable. The determination of recoverability is based on comparing the estimated undiscounted future net cash flows at a producing field level to the carrying value of the assets. If the future undiscounted cash flows, based on estimates of anticipated production from proved reserves and future crude oil and natural gas prices and operating costs, are lower than the carrying cost, the carrying cost of the asset or group of assets is reduced to fair value. For our proved oil and natural gas properties, we estimate fair value by discounting the projected future cash flows at an appropriate risk-adjusted discount rate.
	Our evaluation of the Company’s proved properties resulted in impairment expense of $72.9 million, $135.2 million and $90.3 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	Unproved properties are assessed at least annually to determine whether they have been impaired. Individually significant properties are assessed for impairment on a property-by-property basis, while individually insignificant unproved properties may be assessed in the aggregate. If unproved properties are found to be impaired, an impairment allowance is provided and a loss is recognized in the consolidated statement of operations. For the years ended December 31, 2014, 2013 and 2012, impairment expense of unproved properties was $2.0 million, $8.0 million, and $5.9 million, respectively.
	Management evaluates whether the carrying value of all other long-lived assets has been impaired when circumstances indicate the carrying value of those assets may not be recoverable. This evaluation is based on undiscounted cash flow projections. The carrying amount is not recoverable if it exceeds the undiscounted sum of cash flows expected to result from the use and eventual disposition of the assets. Management considers various factors when determining if these assets should be evaluated for impairment.
	If the carrying value is not recoverable on an undiscounted basis, the impairment loss is measured as the excess of the asset’s carrying value over its fair value. Management assesses the fair value of long-lived assets using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales, internally developed discounted cash flow analysis and analysis from outside advisors. Significant changes in market conditions resulting from events such as the condition of an asset or a change in management’s intent to utilize the asset would generally require management to reassess the cash flows related to the long-lived assets. For the years ended December 31, 2014, 2013, and 2012, respectively, the Company did not record any impairment expense related to other long-lived assets.
	Depreciation, Depletion and Amortization — Depreciation, depletion, and amortization (“DD&A”) of capitalized costs of proved oil and natural gas properties is computed using the unit-of-production method based upon estimated proved reserves. Assets are grouped for DD&A on the basis of reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The reserve base used to calculate DD&A for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate DD&A for lease and well equipment costs, which include development costs and successful exploration drilling costs, includes only proved developed reserves.
	DD&A expense for the years ended December 31, 2014, 2013, and 2012 related to oil and natural gas properties was $139.0 million, $115.5 million, and $106.6 million, respectively.
	Leasehold improvements to offices are depreciated using the straight-line method over the life of the lease. The Company’s drilling rig, which was sold during 2013, was depreciated using the straight-line method of depreciation over a period of approximately fifteen years.  Other property and equipment is depreciated using the straight-line method over periods ranging from three to seven years. Depreciation expense for non-oil and gas property and equipment for the years ended December 31, 2014, 2013, and 2012 was $2.8 million, $3.1 million, and $2.7 million respectively.
Investment	Investment. The Company’s investment consists of a 10.17% ownership interest in a drilling company, Orion Drilling Company, LLC (“Orion”). The investment is accounted for under the cost method. Under this method, the Company’s share of earnings or losses of the investment are not included in the consolidated statements of operations.
Asset Retirement Obligations	Asset Retirement Obligations. We recognize liabilities for the future costs of dismantlement and abandonment of our wells, facilities, and other tangible long-lived assets along with an associated increase in the carrying amount of the related long-lived asset.  The fair values of new asset retirement obligations are estimated using expected future costs discounted to present value.  The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset.  Accretion expense is recognized as the discounted liability is accreted to its expected settlement value.   Asset retirement obligations are subject to revision primarily for changes to the estimated timing and cost of abandonment.
Derivative Financial Instruments	Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil and natural gas. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).
	Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.   All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows.
Income Taxes	Income Taxes. The Company has elected under the Internal Revenue Code provisions to be treated as individual partnerships for tax purposes. Accordingly, items of income, expense, gains and losses flow through to the partners and are taxed at the partner level. Accordingly, no tax provision for federal income taxes is included in the consolidated financial statements.
	The Company is subject to the Texas margin tax, which is considered a state income tax, and is included in “Benefit from (provision for) state income tax” on the consolidated statements of operations. The Company records state income tax (current and deferred) based on taxable income, as defined under the rules for the margin tax.
	We follow guidance issued by the FASB in accounting for uncertainty in income taxes. This guidance clarifies the accounting for income taxes by prescribing the minimum recognition threshold an income tax position is required to meet before being recognized in the consolidated financial statements and applies to all income tax positions. Each income tax position is assessed using a two-step process. A determination is first made as to whether it is more likely than not that the income tax position will be sustained, based upon technical merits, upon examination by the taxing authorities. If the income tax position is expected to meet the more likely than not criteria, the benefit recorded in the consolidated financial statements equals the largest amount that is greater than 50% likely to be realized upon its ultimate settlement.
	We have considered our exposure under the standard at both the federal and state tax levels.  We have not recorded any liabilities for uncertain tax positions as of December 31, 2014 and 2013. We record income tax, related interest, and penalties, if any, as a component of income tax expense. We did not incur any interest or penalties on income taxes for the years ended December 31, 2014,  2013, or 2012.
	The Company’s tax returns for the years ended December 31, 2010 forward remain open for examination. None of the Company’s federal or state tax returns are currently under examination by the relevant authorities.
Revenue Recognition	Revenue Recognition. We recognize oil, natural gas and natural gas liquids revenues when products are delivered at a fixed or determinable price, title has transferred and collectability is reasonably assured. We use the sales method of accounting for recognition of natural gas imbalances. Revenue from drilling rigs was recorded when services were performed.
Fair Value Of Financial Instruments	Fair Value of Financial Instruments. The fair values of cash, accounts receivable and current liabilities approximate book value due to their short-term nature. The estimated of fair value of long-term debt under our credit facility is not considered to be materially different from carrying value due to market rates of interest. The fair value of the debt to our founder is not practicable to determine. We have estimated the fair value of our $450 million senior notes payable at $380.3 million on December 31, 2014. Derivative financial instruments are carried at fair value. See Note 5 for further information on fair values of financial instruments. See Note 9 for information on long-term debt.
Acquisitions	Acquisitions. Acquisitions are accounted for as purchases using the acquisition method of accounting. Accordingly, the results of operations are included in our consolidated statements of operations from the closing date of the acquisitions. Purchase prices are allocated to acquired assets and assumed liabilities based on their estimated fair values at the time of the acquisition.
Recent Accounting Pronouncements	Recent Accounting Pronouncements
	In April 2014, the Financial Accounting Standards Board issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity.  ASU 2014-08 narrows the definition of “discontinued operations” to dispositions that represent a strategic shift that has or will have a significant impact on the entity’s operations and financial results.  The ASU requires additional disclosures regarding assets and liabilities held for sale, and income and losses, including gain or loss on sale, and cash flows from discontinued operations.  In addition, the ASU requires disclosures for disposals of individually significant components of the business which do not qualify as discontinued operations, including general information about the disposition and disclosure of the pretax profit or loss from the component for the period of disposal and all comparable historic periods presented.  ASU 2014-08 is effective for all fiscal years beginning after December 15, 2014, and can be adopted early for certain asset dispositions and reclassifications of assets from “held and used” to “held for sale.”  We early adopted ASU 2014-08 as of January 1, 2014 and have provided disclosures in accordance with this new guidance in Note 3.
	In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers.  The update provides guidance concerning the recognition and measurement 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. We are currently evaluating the impact of adopting this standard on our consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.
	In August 2014, the FASB issued ASU 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern.  The new standard requires management to assess the company’s ability to continue as a going concern.  Disclosures are required if there is substantial doubt as to the company’s continuation as a going concern within one year after the issue date of financial statements.  The standard provides guidance for making the assessment, including consideration of management’s plans which may alleviate doubt regarding the company’s ability to continue as a going concern. ASU 2014-15 is effective for years beginning after December 15, 2016.    We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.
	In January 2015, the FASB issued ASU 2015-01, Extraordinary and Unusual Items.  The new standard eliminates the concept of “extraordinary items,” which prior guidance required to be presented separately from income from continuing operations.  Items that are infrequent and unusual in nature are to be disclosed either on the face of the financial statements as a component of income from continuing operations or in the notes to the financial statements.  ASU 2015-01 is effective for years beginning after December 15, 2015, with early adoption permitted.  We adopted the guidance on January 1, 2015.   We do not expect the adoption of this pronouncement to have a material impact on our consolidated financial statements.

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Policy)	12 Months Ended
	Dec. 31, 2014
Derivative Financial Instruments [Line Items]
Derivatives And Hedging	Derivative Financial Instruments. We use derivative contracts to hedge the effects of fluctuations in the prices of oil and natural gas. We account for such derivative instruments in accordance with ASC 815, “Derivatives and Hedging,” which establishes accounting and disclosure requirements for derivative instruments and requires them to be measured at fair value and recorded as assets or liabilities in the consolidated balance sheets (see Note 5 for information on fair value).
	Under ASC 815, hedge accounting is used to defer recognition of unrealized changes in the fair value of such financial instruments, for those contracts which qualify as fair value or cash flow hedges, as defined in the guidance. Historically, we have not designated any of our derivative contracts as fair value or cash flow hedges. Accordingly, the changes in fair value of the contracts are included in earnings as “Gain (loss) — oil and natural gas derivative contracts.”  Cash flows from settlements of derivative contracts are classified as operating cash flows.   All gains, losses, and settlements related to interest rate swaps are included in interest expense; cash flows related to interest rate swaps are included in operating cash flows.
Commodity Contract [Member]
Derivative Financial Instruments [Line Items]
Derivatives, Use of Derivatives	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 and natural gas. 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 crude oil and natural gas sales contracts. Substantially all of our hedging agreements are executed by affiliates of the lenders under our credit facility described in Note 9 below, and are collateralized by the security interests of the respective affiliated lenders in certain of our assets under the credit facility. The contracts settle monthly and are scheduled to coincide with either oil production equivalent to barrels (Bbl) per month or gas production equivalent to volumes in millions of British thermal units (MMBtu) per month. The contracts represent agreements between us and the counter-parties to exchange cash based on a designated price, or in the case of financial basis hedging contracts, based on a designated price differential between various benchmark prices. Cash settlement occurs monthly.
Interest Rate Contracts [Member]
Derivative Financial Instruments [Line Items]
Derivatives, Use of Derivatives	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.
Netting Presentation for Derivatives Policy [Member]
Derivative Financial Instruments [Line Items]
Derivatives And Hedging	Derivative contracts are subject to master netting arrangements and are presented on a net basis in the consolidated balance sheets. This netting can cause derivative assets to be ultimately presented in a (liability) account on the consolidated balance sheets.  Likewise, derivative (liabilities) could be presented in an asset account.

Significant_Acquisitions_And_D1

Significant Acquisitions And Divestitures (Tables)	12 Months Ended
	Dec. 31, 2014
Significant Acquisitions And Divestitures [Abstract]
Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices
		October 1,
		2013
		(dollars in thousands)
	Summary of Consideration
	Cash	$	41,841
	Fair value of asset retirement obligations assumed		5,311
	Total	$	47,152
	Summary of Purchase Price Allocation
	Proved oil and natural gas properties	$	30,279
	Unproved oil and natural gas properties		16,873
	Total	$	47,152
Summary Of Pro Forma Information
		Total		Income
		Revenue		(Loss)
		(dollars in thousands)
	Actual results of Weeks Island included in our statement of operations for the period October 1, 2013
	through December 31, 2013	$	10,509	$	8,575
	Pro forma results for the combined entity for the year ended December 31, 2012	$	340,103	$	-85,985
	Pro forma results for the combined entity for the year ended December 31, 2013	$	376,063	$	-146,866

Property_And_Equipment_Tables

Property And Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property And Equipment [Abstract]
Property And Equipment
		December 31,		December 31,
		2014		2013
		(dollars in thousands)
	OIL AND NATURAL GAS PROPERTIES
	Unproved properties	$	84,620	$	86,721
	Accumulated impairment		-3,749		-7,356
	Unproved properties, net		80,871		79,365
	Proved oil and natural gas properties		1,417,785		1,405,658
	Accumulated depreciation, depletion, amortization and impairment		-812,480		-793,253
	Proved oil and natural gas properties, net		605,305		612,405
	TOTAL OIL AND NATURAL GAS PROPERTIES, net		686,176		691,770
	LAND		2,820		1,418
	OTHER PROPERTY AND EQUIPMENT
	Office furniture and equipment, vehicles		17,302		13,802
	Accumulated depreciation		-8,617		-6,120
	OTHER PROPERTY AND EQUIPMENT, net		8,685		7,682
	TOTAL PROPERTY AND EQUIPMENT, net	$	697,681	$	700,870
Capitalized Exploratory Well Costs Roll Forward Table
		Year Ended December 31,
		2014		2013		2012
		(dollars in thousands)
	Balance, beginning of year	$	18,364	$	4,627	$	—
	Additions to capitalized well costs pending determination of proved reserves		2,889		21,693		4,627
	Capitalized exploratory well costs charged to expense		-16,706		-7,956		—
	Balance, end of year	$	4,547	$	18,364	$	4,627

Fair_Value_Disclosures_Tables

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis
		Level 1		Level 2		Level 3		Total
			(dollars in thousands)
	At December 31, 2014:
	Financial Assets:
	Derivative contracts for oil and natural gas		—	$	140,652		—	$	140,652
	Financial Liabilities:
	Derivative contracts for oil and natural gas		—	$	53,578		—	$	53,578
	At December 31, 2013:
	Financial Assets:
	Derivative contracts for oil and natural gas		—	$	27,850		—	$	27,850
	Financial Liabilities:
	Derivative contracts for oil and natural gas		—	$	27,842		—	$	27,842

Derivative_Financial_Instrumen2

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative [Line Items]
Fair Values Of Derivative Contracts
								Net Fair
		Gross			Gross amounts			Value of Assets
	31-Dec-14	Fair Value			offset against assets			presented in
	Balance sheet location	of Assets			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current assets	$	91,341		$	-31,538		$	59,803
	Derivative financial instruments, long-term assets		55,325			-28,054			27,271
	Total	$	146,666		$	-59,592		$	87,074
								Net Fair
		Gross			Gross amounts			Value of Liabilities
	31-Dec-14	Fair Value			offset against liabilities			presented in
	Balance sheet location	of Liabilities			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current liabilities	$	31,538		$	-31,538		$	—
	Derivative financial instruments, long-term liabilities		28,054			-28,054			—
	Total	$	59,592		$	-59,592		$	—
								Net Fair
		Gross			Gross amounts			Value of Assets
	31-Dec-13	Fair Value			offset against assets			presented in
	Balance sheet location	of Assets			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current assets	$	13,218		$	-7,646		$	5,572
	Derivative financial instruments, long-term assets		14,632			-11,227			3,405
	Total	$	27,850		$	-18,873		$	8,977
								Net Fair
		Gross			Gross amounts			Value of Liabilities
	31-Dec-13	Fair Value			offset against liabilities			presented in
	Balance sheet location	of Liabilities			in the Balance Sheet			the Balance Sheet
		(dollars in thousands)
	Derivative financial instruments, current liabilities	$	12,129		$	-7,646		$	4,483
	Derivative financial instruments, long-term liabilities		15,713			-11,227			4,486
	Total	$	27,842		$	-18,873		$	8,969
Effect Of Derivative Instruments In The Consolidated Statements Of Operations
	Derivatives not
	designated as hedging	Location of		Year Ended December 31,
	instruments under ASC 815	Gain (Loss)		2014			2013			2012
	Oil commodity contracts	Gain (loss) —
		oil and natural gas
		derivative contracts		$	82,510		$	-17,715		$	3,720
	Natural gas commodity contracts	Gain (loss) —
		oil and natural gas
		derivative contracts			14,049			565			16,031
	Total gains (losses) from oil and				96,559			-17,150			19,751
	natural gas commodity contracts
	Interest rate contracts	Interest expense			—			—			-37
	Total gains (losses) from
	derivatives not designated as hedges			$	96,559		$	-17,150		$	19,714
Oil [Member]
Derivative [Line Items]
Open Derivative Contracts
		Volume		Weighted			Range
	Period and Type of Contract	in Bbls		Average			High			Low
	2015
	Price Swap Contracts	1,587,000			91.39			95.02			86.45
	Collar Contracts
	Short Call Options	392,350			114.10			135.98			95.50
	Long Put Options	1,049,350			85.78			90.00			85.00
	Short Put Options	1,998,350			70.05			75.00			60.00
	2016
	Price Swap Contracts	366,000			93.00			94.92			85.35
	Collar Contracts
	Short Call Options	859,700			107.97			130.00			103.87
	Long Put Options	859,700			85.99			95.00			80.00
	Short Put Options	1,225,700			68.67			75.00			60.00
	2017
	Collar Contracts
	Short Call Options	744,950			107.99			113.83			104.15
	Long Put Options	744,950			83.26			90.00			80.00
	Short Put Options	744,950			63.26			70.00			60.00
	2018
	Collar Contracts
	Short Call Options	307,400			104.39			104.65			104.15
	Long Put Options	307,400			80.00			80.00			80.00
	Short Put Options	307,400			60.00			60.00			60.00
Natural Gas [Member]
Derivative [Line Items]
Open Derivative Contracts
		Volume in		Weighted			Range
	Period and Type of Contract	MMBtu		Average			High			Low
	2015
	Price Swap Contracts	3,832,500			5.07			5.91			4.31
	Collar Contracts
	Short Call Options	7,750,000			4.59			5.75			4.51
	Long Put Options	8,113,500			4.01			5.00			3.50
	Long Call Options	495,000			4.31			4.31			4.31
	Short Put Options	9,116,000			3.34			4.45			3.25
	2016
	Price Swap Contracts	8,418,000			4.22			4.23			4.22
	Collar Contracts
	Short Call Options	455,000			7.50			7.50			7.50
	Long Put Options	455,000			5.50			5.50			5.50
	Short Put Options	1,681,100			3.64			4.00			3.50
	2017
	Collar Contracts
	Short Call Options	6,570,000			5.00			5.00			4.98
	Long Put Options	6,570,000			4.50			4.50			4.50
	Short Put Options	6,570,000			4.00			4.00			4.00
	2018
	Collar Contracts
	Short Call Options	5,475,000			5.50			5.53			5.48
	Long Put Options	5,475,000			4.50			4.50			4.50
	Short Put Options	5,475,000			4.00			4.00			4.00

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligations [Abstract]
Summary Of Changes In Asset Retirement Obligations
		Year Ended December 31,
		2014		2013		2012
		(dollars in thousands)
	Balance, beginning of year	$	56,023	$	48,593	$	46,096
	Liabilities incurred		1,129		1,052		787
	Liabilities assumed with acquired producing properties		3,002		5,480		1,476
	Liabilities settled		-3,942		-1,548		-3,562
	Liabilities transferred in sales of properties		-1,886		-606		—
	Revisions to estimates		6,348		919		1,983
	Accretion expense		2,198		2,133		1,813
	Balance, end of year		62,872		56,023		48,593
	Less: Current portion		1,136		3,844		64
	Long term portion	$	61,736	$	52,179	$	48,529

Long_Term_Debt_Tables

Long Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Long Term Debt [Abstract]
Long-Term Debt
		December 31,			December 31,
		2014			2013
		(dollars in thousands)
	Credit Facility	$	319,520		$	319,290
	Senior Notes		448,088			447,578
	Total long-term debt	$	767,608		$	766,868
	Notes payable to founder	$	24,540		$	23,331
Summary Of Future Maturities Of Long-Term Debt
	Year ending December 31,
	2015		$	—
	2016			319,520
	2017			—
	2018			450,000
	2019			—
	Thereafter			24,540
			$	794,060

Accounts_Payable_And_Accrued_L1

Accounts Payable And Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Accounts Payable And Accrued Liabilities [Abstract]
Detail Of Accounts Payable And Accrued Liabilities
		December 31,		December 31,
		2014		2013
		(dollars in thousands)
	Capital expenditures	$	32,990	$	18,629
	Revenues and royalties payable		7,302		9,699
	Operating expenses/taxes		20,716		17,071
	Interest		9,136		9,146
	Compensation		10,586		8,862
	Other		2,605		2,711
	Total accrued liabilities		83,335		66,118
	Accounts payable		34,225		29,977
	Accounts payable and accrued liabilities	$	117,560	$	96,095

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Commitments And Contingencies [Abstract]
Future Base Rentals For Non-Cancelable Leases
	Year Ending December 31,
	2015	$	2,004
	2016		1,562
	2017		1,552
	2018		1,529
	2019		1,580
	Thereafter		4,420
		$	12,647

Supplemental_Quarterly_Informa1

Supplemental Quarterly Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Quarterly Information [Abstract]
Summary Of Quarterly Results Of Operations
		Quarter Ended
	2014	31-Mar			30-Jun		30-Sep		31-Dec
			(dollars in thousands)
	Revenues (1)	$	165,891		$	86,254	$	184,111	$	179,951
	Income (loss) from operations (2)		71,461			-25,186		73,025		35,873
	Net income (loss)	$	56,893		$	-38,812	$	59,326	$	21,793
		-1		Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively.
		-2		Includes $18.3 million and $8.7 million of impairment expense in June 30, 2014 and September 30, 2014, respectively.
	Results of operations by quarter for the year ended December 31, 2013 were:
		Quarter Ended
	2013	31-Mar			30-Jun		30-Sep		31-Dec
			(dollars in thousands)
	Revenues	$	68,578		$	123,531	$	77,759	$	85,924
	Income (loss) from operations (3)		-1,066			29,799		-11,915		-115,469
	Net income (loss)	$	-14,286		$	16,168	$	-25,737	$	-129,860
		-3		Includes $7.4 million, $19.2 million and $114.5 million of impairment expense in March, 31, 2013, June 30, 2013 and December 31, 2013, respectively.

Supplemental_Oil_And_Natural_G1

Supplemental Oil And Natural Gas Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Oil and Natural Gas Disclosures (Unaudited) [Abstract]
Estimated Quantities Of Proved Reserves
			Oil		Gas		NGL's	BOE
			(MBbls)		(MMcf)		(MBbls)	(MBbls)
	Total Proved Reserves:
	Balance at December 31, 2011		16,933		217,266		4,845	57,989
	Production		-2,138		-21,372		-365	-6,065
	Purchases in place		335		6,619		8	1,446
	Discoveries and extensions		10,173		18,870		1,187	14,505
	Revisions of previous quantity estimates and other		-4,683		-68,894		20	-16,144
	Balance at December 31, 2012		20,620		152,489		5,695	51,731
	Production		-2,897		-16,664		-398	-6,072
	Purchases in place		1,462		1,265		—	1,673
	Discoveries and extensions		14,541		29,012		1,969	21,345
	Sales of reserves in place		-13		-10,912		—	-1,832
	Revisions of previous quantity estimates and other		-1,196		-22,925		-1,531	-6,549
	Balance at December 31, 2013		32,517		132,265		5,735	60,296
	Production		-3,770		-14,449		-537	-6,715
	Purchases in place		610		327		—	665
	Discoveries and extensions		13,281		28,822		4,119	22,204
	Sales of reserves in place		-6,298		-35,857		-949	-13,223
	Revisions of previous quantity estimates and other		-4,996		-7,960		20	-6,304
	Balance at December 31, 2014		31,344		103,148		8,388	56,923
	Proved Developed Reserves:
	Balance at December 31, 2012		10,467		111,206		4,209	33,211
	Balance at December 31, 2013		16,335		92,640		3,138	34,913
	Balance at December 31, 2014		15,182		63,334		4,028	29,765
	Proved Undeveloped Reserves:
	Balance at December 31, 2012		10,153		41,283		1,486	18,520
	Balance at December 31, 2013		16,182		39,625		2,597	25,383
	Balance at December 31, 2014		16,162		39,814		4,360	27,158
Capitalized Costs Relating To Oil And Natural Gas Producing Activities
			December 31,
			2014			2013
			(dollars in thousands)
	Capitalized costs:
	Proved properties		$	1,417,785		$	1,405,658
	Unproved properties			84,620			86,721
	Total			1,502,405			1,492,379
	Accumulated depreciation, depletion, amortization and impairment			-816,229			-800,609
	Net capitalized costs		$	686,176		$	691,770
Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities
			Year Ended December 31,
			2014			2013		2012
			(dollars in thousands)
	Costs incurred during the year:
	Property acquisition costs
	Unproved		$	33,787		$	34,884	$	31,695
	Proved (1)			7,462			35,954		12,192
	Exploration			59,201			55,300		46,559
	Development (2)			341,594			242,912		200,974
			$	442,044		$	369,050	$	291,420
		-1		Property acquisition costs for proved properties in 2013 include primarily the proved portion of the Stone acquisition ($30.6 million).
	(2)   Includes asset retirement costs of $4.5 million, $1.4 million, and $1.7 million for the years ended December 31, 2014, 2013, and 2012, respectively.
Components Of The Standardized Measure Of Discounted Future Net Cash Flows
			Year Ended December 31,
			2014			2013		2012
				(dollars in thousands)
	Future cash flows		$	3,737,412		$	3,959,938	$	2,742,588
	Future production costs			-991,149			-1,146,123		-928,398
	Future development costs			-450,659			-474,191		-348,042
	Future taxes on income			—			—		—
	Future net cash flows			2,295,604			2,339,624		1,466,148
	Discount to present value at 10 percent per annum			-877,558			-933,350		-551,727
	Standardized measure of discounted future net cash flows		$	1,418,046		$	1,406,274	$	914,421
	Base price for crude oil, per Bbl, in the above computation was:		$	94.99		$	96.78	$	94.71
	Base price for natural gas, per Mcf, in the above computation was:		$	4.35		$	3.67	$	2.76
Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows
			Year Ended December 31,
			2014			2013		2012
				(dollars in thousands)
	Balance at beginning of year		$	1,406,274		$	914,421	$	1,070,196
	Sales of oil and natural gas, net of production costs			-320,130			-263,952		-189,709
	Changes in sales and transfer prices, net of production costs			-153,770			69,609		-291,285
	Revisions of previous quantity estimates			-477,377			-150,634		-250,424
	Purchases of reserves-in-place			21,633			93,877		10,283
	Sales of reserves-in-place			-107,414			-11,193		—
	Current year discoveries and extensions			701,820			621,832		420,496
	Changes in estimated future development costs			2,591			11,623		54,493
	Development costs incurred during the year			161,357			75,973		49,834
	Accretion of discount			140,627			91,442		107,020
	Net change in income taxes			—			—		—
	Change in production rate (timing) and other			42,435			-46,724		-66,483
	Net change			11,772			491,853		-155,775
	Balance at end of year		$	1,418,046		$	1,406,274	$	914,421

Summary_Of_Significant_Account2

Summary Of Significant Accounting Policies (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 25, 2015
Summary Of Significant Accounting Policies [Line Items]
FDIC insured maximum amount	$250,000
Proceeds from sale of property	177,476,000	26,668,000
Amount expended or committed from the restricted account for purchase of qualifying properties	900,000
Receivables from joint interest owners	10,300,000	13,800,000
Trade receivables for the sale of oil and natural gas	35,100,000	37,800,000
Allowance for doubtful accounts	1,400,000	1,400,000
Amortization of loan costs	2,885,000	2,839,000	2,424,000
Accumulated amortization, deferred financing costs	15,600,000	12,800,000
Impairment expense of proved properties	72,900,000	135,200,000	90,300,000
Impairment expense of unproved properties	2,000,000	8,000,000	5,900,000
Depreciation depletion and amortization related to oil and gas properties	139,000,000	115,500,000	106,600,000
Depreciation expense for other property and equipment	2,800,000	3,100,000	2,700,000
Ownership interest in a drilling company	10.17%
Liability for uncertain tax positions	0	0
Income tax penalties and interest	0	0	0
Face value of senior notes issued	450,000,000
Fair value of senior notes payable	380,300,000
ARM Energy Management, LLC [Member]
Summary Of Significant Accounting Policies [Line Items]
Accounts receivable	16,600,000	7,500,000
Hilltop Field Deep Bossier Properties [Member]
Summary Of Significant Accounting Policies [Line Items]
Proceeds from sale of property	24,600,000
Drilling Rig [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	15 years
Subsequent Event [Member]
Summary Of Significant Accounting Policies [Line Items]
Amount of restricted cash refunded from investment				$23,700,000
Minimum [Member] | Other Property And Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	3 years
Maximum [Member] | Other Property And Equipment [Member]
Summary Of Significant Accounting Policies [Line Items]
Depreciable life of property and equipment	7 years

Significant_Acquisitions_And_D2

Significant Acquisitions And Divestitures (Narrative) (Details) (USD $)	3 Months Ended		12 Months Ended			0 Months Ended
	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 19, 2014	Oct. 01, 2013	Jul. 01, 2013
								MMcf
Business Acquisition [Line Items]
Loss on sale of drilling rig	($18,300,000)	($73,100,000)	($87,520,000)	$2,715,000
Drilling Rig [Member]
Business Acquisition [Line Items]
Sale of drilling rig, cash purchase price				7,000,000
Loss on sale of drilling rig				1,200,000
Eagleville Divestiture [Member]
Business Acquisition [Line Items]
Date of acquisition or sale of properties			25-Mar-14
Percentage of original working interest net profits interest in wells is retained on, 2014			50.00%
Percentage of original working interest net profits interest in wells is retained on, 2015			30.00%
Percentage of original working interest net profits interest in wells is retained on, 2016			15.00%
Percentage of original working interest net profits interest in wells is retained on, 2017			0.00%
Percentage of undivided interest in mineral leases and interests included in sale			30.00%
Percentage of working interest in all wells in progress on December 31, 2013 or drilled after January 1, 2014 included in sale			30.00%
Initial cash purchase price for properties sold			173,000,000
Cash purchase price, net of costs of transaction			171,000,000
Gain on sale of oil and gas properties			72,500,000
Operating income from sold oil and gas properties		11,100,000		47,000,000	22,100,000
Eagleville Divestiture [Member] | Barrels of Oil Equivalent [Member]
Business Acquisition [Line Items]
Estimated proved reserves associated with sold property			7,500,000
Hilltop Divestiture 2013 [Member]
Business Acquisition [Line Items]
Date of acquisition or sale of properties			2-Oct-13
Cash purchase price, net of costs of transaction			19,000,000
Gain on sale of oil and gas properties			0
Hilltop Divestiture 2013 [Member] | Natural Gas in MMcf [Member]
Business Acquisition [Line Items]
Estimated proved reserves associated with sold property								11,200
Hilltop Divestiture 2014 [Member]
Business Acquisition [Line Items]
Date of acquisition or sale of properties			19-Sep-14
Cash purchase price, net of costs of transaction			38,900,000			41,600,000
Gain on sale of oil and gas properties			15,000,000
Hilltop Divestiture 2014 [Member] | Natural Gas in MMcf [Member]
Business Acquisition [Line Items]
Estimated proved reserves associated with sold property						29,800
Hilltop Field [Member]
Business Acquisition [Line Items]
Operating income from sold oil and gas properties			7,700,000	6,900,000	53,200,000
Stone [Member]
Business Acquisition [Line Items]
Acquisition effective date			1-Oct-13
Payment towards acquisition of all working interests							$41,841,000
Total estimated net proved reserves acquired			1,800,000
Acquisition effective date			1-Jul-13

Significant_Acquisitions_And_D3

Significant Acquisitions And Divestitures (Summary Of Consideration Paid And The Preliminary Allocation Of Purchase Prices) (Details) (Stone [Member], USD $)	0 Months Ended
In Thousands, unless otherwise specified	Oct. 01, 2013	Oct. 01, 2013
Stone [Member]
Business Acquisition [Line Items]
Cash	$41,841
Fair value of asset retirement obligations assumed	5,311
Total	47,152
Proved oil and natural gas properties	30,279	30,279
Unproved oil and natural gas properties	16,873	16,873
Total	$47,152	$47,152

Significant_Acquisitions_And_D4

Significant Acquisitions And Divestitures (Summary Of Pro Forma Information) (Details) (Stone [Member], USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012
Scenario, Actual [Member]
Business Acquisition [Line Items]
Actual revenue since acquisition	$10,509
Actual income (loss) since acquisition	8,575
Pro Forma [Member]
Business Acquisition [Line Items]
Pro Forma Revenue		376,063	340,103
Pro Forma Income (Loss)		($146,866)	($85,985)

Property_And_Equipment_Propert

Property And Equipment (Property And Equipment) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property And Equipment [Abstract]
Unproved properties	$84,620	$86,721
Accumulated impairment	-3,749	-7,356
Unproved properties, net	80,871	79,365
Proved oil and natural gas properties	1,417,785	1,405,658
Accumulated depreciation, depletion, amortization and impairment	-812,480	-793,253
Proved oil and natural gas properties, net	605,305	612,405
TOTAL OIL AND NATURAL GAS PROPERTIES, net	686,176	691,770
LAND	2,820	1,418
Office furniture and equipment, vehicles	17,302	13,802
Accumulated depreciation	-8,617	-6,120
OTHER PROPERTY AND EQUIPMENT, net	8,685	7,682
TOTAL PROPERTY AND EQUIPMENT, NET	$697,681	$700,870

Property_And_Equipment_Capital

Property And Equipment (Capitalized Exploratory Well Costs) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	item
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves
Capitalized Exploratory Well Costs, Beginning Balance	$18,364,000	$4,627,000
Additions to capitalized well costs pending determination of proved reserves	2,889,000	21,693,000	4,627,000
Capitalized exploratory well costs charged to expense	-16,706,000	-7,956,000
Capitalized Exploratory Well Costs, Ending Balance	4,547,000	18,364,000	4,627,000
Number of wells included in ending balance in deferred capitalized exploratory well costs	5
Number of prospects	2
Capitalized exploratory well costs that have been capitalized for period greater than one year	$2,200,000	$0

Fair_Value_Disclosures_Narrati

Fair Value Disclosures (Narrative) (Details) (USD $)	3 Months Ended					12 Months Ended
	Sep. 30, 2014	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Line Items]
Carrying value of oil and gas properties						$148,400,000	$237,200,000	$363,700,000
Written down fair value of oil and gas properties						73,500,000	94,000,000	267,500,000
Impairment charges to oil and gas properties	8,700,000	18,300,000	114,500,000	19,200,000	7,400,000	74,927,000	143,166,000	96,227,000
Asset retirement obligation measured at fair value						4,100,000	6,500,000
Stone [Member]
Fair Value Disclosures [Line Items]
Fair value of oil and gas properties acquired			$47,200,000				$47,200,000

Fair_Value_Disclosures_Measure

Fair Value Disclosures (Measurement Of Fair Value Of Assets And Liabilities On Recurring Basis) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Financial Assets:
Derivative contracts for oil and natural gas, gross	$140,652	$27,850
Financial Liabilities:
Derivative contracts for oil and natural gas, gross	53,578	27,842
Level 1 [Member]
Financial Assets:
Derivative contracts for oil and natural gas, gross
Financial Liabilities:
Derivative contracts for oil and natural gas, gross
Level 2 [Member]
Financial Assets:
Derivative contracts for oil and natural gas, gross	140,652	27,850
Financial Liabilities:
Derivative contracts for oil and natural gas, gross	53,578	27,842
Level 3 [Member]
Financial Assets:
Derivative contracts for oil and natural gas, gross
Financial Liabilities:
Derivative contracts for oil and natural gas, gross

Derivative_Financial_Instrumen3

Derivative Financial Instruments (Narrative) (Details)	12 Months Ended
	Dec. 31, 2014
Derivative Financial Instruments [Abstract]
Derivative Asset, Setoff Rights, Description	Although our counterparties provide no collateral, the master derivative agreements with each counterparty effectively allow the Company, so long as it is not a defaulting party, after a default or the occurrence of a termination event, to set-off an unpaid hedging agreement receivable against the interest of the counterparty in any outstanding balance under the credit facility. If a counterparty were to default in payment of an obligation under the master derivative agreements, we could be exposed to commodity price fluctuations, and the protection intended by the hedge could be lost. The value of our derivative financial instruments would be impacted.

Derivative_Financial_Instrumen4

Derivative Financial Instruments (Fair Values Of Derivative Contracts) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	$146,666	$27,850
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet	-59,592	-18,873
Derivative Assets, Current	59,803	5,572
Derivative Assets, Noncurrent	27,271	3,405
Derivative assets, net, total	87,074	8,977
Derivative liabilities, Gross Fair Value of Liabilities	59,592	27,842
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet	-59,592	-18,873
Derivative Liabilities, Current		4,483
Derivative Liabilities, Noncurrent		4,486
Derivative liabilities, net, total		8,969
Derivative Assets Current [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	91,341	13,218
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet	-31,538	-7,646
Derivative Assets, Current	59,803	5,572
Derivative Asset Non-Current [Member]
Derivatives, Fair Value [Line Items]
Derivative assets, Gross Fair Value of Assets	55,325	14,632
Derivative assets, Gross, offset against assets for presentation in the Balance Sheet	-28,054	-11,227
Derivative Assets, Noncurrent	27,271	3,405
Derivative Liabilities Current [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, Gross Fair Value of Liabilities	31,538	12,129
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet	-31,538	-7,646
Derivative Liabilities, Current		4,483
Derivative Liabilities Non Current [Member]
Derivatives, Fair Value [Line Items]
Derivative liabilities, Gross Fair Value of Liabilities	28,054	15,713
Derivative liabilities, Gross, offset against liabilities for presentation in the Balance Sheet	-28,054	-11,227
Derivative Liabilities, Noncurrent		$4,486

Derivative_Financial_Instrumen5

Derivative Financial Instruments (Effect Of Derivative Instruments In The Consolidated Statements Of Operations) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	$96,559	($17,150)	$19,751
Total gains (losses) from oil and natural gas commodity contracts	96,559	-17,150	19,714
Oil Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	82,510	-17,715	3,720
Natural Gas Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	14,049	565	16,031
Not Designated As Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts	96,559	-17,150	19,714
Not Designated As Hedging Instrument [Member] | Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total gains (losses) from oil and natural gas commodity contracts			($37)

Derivative_Financial_Instrumen6

Derivative Financial Instruments (Oil Derivative Contracts) (Details) (Oil Derivative Contracts [Member])	12 Months Ended
	Dec. 31, 2014
	bbl
Price Swap Contracts [Member] | 2015 [Member]
Derivative [Line Items]
Volume in Bbls	1,587,000
Weighted Average Swap Price	91.39
Price Swap Contracts [Member] | 2015 [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	95.02
Price Swap Contracts [Member] | 2015 [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	86.45
Price Swap Contracts [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls	366,000
Weighted Average Swap Price	93
Price Swap Contracts [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	94.92
Price Swap Contracts [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	85.35
Short Call Options [Member] | 2015 [Member]
Derivative [Line Items]
Volume in Bbls	392,350
Weighted Average Option Price	114.1
Short Call Options [Member] | 2015 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	135.98
Short Call Options [Member] | 2015 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	95.5
Short Call Options [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls	859,700
Weighted Average Option Price	107.97
Short Call Options [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	130
Short Call Options [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	103.87
Short Call Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls	744,950
Weighted Average Option Price	107.99
Short Call Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	113.83
Short Call Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	104.15
Short Call Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls	307,400
Weighted Average Option Price	104.39
Short Call Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	104.65
Short Call Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	104.15
Long Put Options [Member] | 2015 [Member]
Derivative [Line Items]
Volume in Bbls	1,049,350
Weighted Average Option Price	85.78
Long Put Options [Member] | 2015 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	90
Long Put Options [Member] | 2015 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	85
Long Put Options [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls	859,700
Weighted Average Option Price	85.99
Long Put Options [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	95
Long Put Options [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	80
Long Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls	744,950
Weighted Average Option Price	83.26
Long Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	90
Long Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	80
Long Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls	307,400
Weighted Average Option Price	80
Long Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	80
Long Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	80
Short Put Options [Member] | 2015 [Member]
Derivative [Line Items]
Volume in Bbls	1,998,350
Weighted Average Option Price	70.05
Short Put Options [Member] | 2015 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	75
Short Put Options [Member] | 2015 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60
Short Put Options [Member] | 2016 [Member]
Derivative [Line Items]
Volume in Bbls	1,225,700
Weighted Average Option Price	68.67
Short Put Options [Member] | 2016 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	75
Short Put Options [Member] | 2016 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60
Short Put Options [Member] | 2017 [Member]
Derivative [Line Items]
Volume in Bbls	744,950
Weighted Average Option Price	63.26
Short Put Options [Member] | 2017 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	70
Short Put Options [Member] | 2017 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60
Short Put Options [Member] | 2018 [Member]
Derivative [Line Items]
Volume in Bbls	307,400
Weighted Average Option Price	60
Short Put Options [Member] | 2018 [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	60
Short Put Options [Member] | 2018 [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	60

Derivative_Financial_Instrumen7

Derivative Financial Instruments (Natural Gas Derivative Contracts) (Details) (Natural Gas Derivative Contracts [Member])	12 Months Ended
	Dec. 31, 2014
	MMBTU
2015 [Member] | Price Swap Contracts [Member]
Derivative [Line Items]
Volume in MMbtu	3,832,500
Weighted Average Swap Price	5.07
2015 [Member] | Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	5.91
2015 [Member] | Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	4.31
2015 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu	7,750,000
Weighted Average Option Price	4.59
2015 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.75
2015 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.51
2015 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	8,113,500
Weighted Average Option Price	4.01
2015 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5
2015 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.5
2015 [Member] | Long Call Options [Member]
Derivative [Line Items]
Volume in MMbtu	495,000
Weighted Average Option Price	4.31
2015 [Member] | Long Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.31
2015 [Member] | Long Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.31
2015 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	9,116,000
Weighted Average Option Price	3.34
2015 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.45
2015 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.25
2016 [Member] | Price Swap Contracts [Member]
Derivative [Line Items]
Volume in MMbtu	8,418,000
Weighted Average Swap Price	4.22
2016 [Member] | Price Swap Contracts [Member] | Maximum [Member]
Derivative [Line Items]
Swap Price	4.23
2016 [Member] | Price Swap Contracts [Member] | Minimum [Member]
Derivative [Line Items]
Swap Price	4.22
2016 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu	455,000
Weighted Average Option Price	7.5
2016 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	7.5
2016 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	7.5
2016 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	455,000
Weighted Average Option Price	5.5
2016 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5.5
2016 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	5.5
2016 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	1,681,100
Weighted Average Option Price	3.64
2016 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4
2016 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	3.5
2017 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu	6,570,000
Weighted Average Option Price	5
2017 [Member] | Short Call Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	5
2017 [Member] | Short Call Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.98
2017 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	6,570,000
Weighted Average Option Price	4.5
2017 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.5
2017 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.5
2017 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	6,570,000
Weighted Average Option Price	4
2017 [Member] | Short Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4
2017 [Member] | Short Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4
2018 [Member] | Short Call Options [Member]
Derivative [Line Items]
Volume in MMbtu	5,475,000
Weighted Average Option Price	5.5
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	5.48
2018 [Member] | Long Put Options [Member]
Derivative [Line Items]
Volume in MMbtu	5,475,000
Weighted Average Option Price	4.5
2018 [Member] | Long Put Options [Member] | Maximum [Member]
Derivative [Line Items]
Option Price	4.5
2018 [Member] | Long Put Options [Member] | Minimum [Member]
Derivative [Line Items]
Option Price	4.5
2018 [Member] | Short Put Options [Member]
Derivative [Line Items]
Volume in 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

Asset_Retirement_Obligations_D

Asset Retirement Obligations (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligations [Abstract]
Balance, beginning of year	$56,023,000	$48,593,000	$46,096,000
Liabilities incurred	1,129,000	1,052,000	787,000
Liabilities assumed with acquired producing properties	3,002,000	5,480,000	1,476,000
Liabilities settled	-3,942,000	-1,548,000	-3,562,000
Liabilities transferred in sales of properties	-1,886,000	-606,000
Revisions to estimates	6,348,000	919,000	1,983,000
Accretion expense	2,198,000	2,133,000	1,813,000
Balance, end of period	62,872,000	56,023,000	48,593,000
Less: Current portion	1,136,000	3,844,000	64,000
Long-term portion	61,736,000	52,179,000	48,529,000
Additions To PPE Included In ARO Revisions	$2,900,000	$400,000	$900,000

Related_Party_Transactions_Det

Related Party Transactions (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jan. 02, 2015
Related Party Transaction [Line Items]
Notes payable to founder	$24,500,000	$23,300,000
Total expenditures for land consulting services	150,000	175,000	116,000
Contract termination period without penalty for either party	30 days
Interest rate on note receivable	8.00%
Other Receivable [Member]
Related Party Transaction [Line Items]
Amount recorded for sale of partially constructed pipeline and gas processing plant	25,500,000
Long Term Note Receivable [Member]
Related Party Transaction [Line Items]
Amount recorded for sale of partially constructed pipeline and gas processing plant	8,500,000
Subsequent Event [Member]
Related Party Transaction [Line Items]
Amount of receivable paid				25,500,000
Vice President, Louisiana Region [Member]
Related Party Transaction [Line Items]
Total compensation	450,000	390,000	327,000
Landman [Member]
Related Party Transaction [Line Items]
Total compensation	260,000	125,000	105,000
Founder [Member]
Related Party Transaction [Line Items]
Capital distributions	$516,500	$17,500
Notes Payable To Founder [Member]
Related Party Transaction [Line Items]
Effective rate of interest on senior notes	10.00%	10.00%
ARM Energy Management, LLC [Member]
Related Party Transaction [Line Items]
Marketing fee	1.00%
ARM Energy Management, LLC [Member] | Maximum [Member]
Related Party Transaction [Line Items]
Percentage of ownership interest	10.00%

Long_Term_Debt_Narrative_Detai

Long Term Debt (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]
Letter of credit outstanding	$900,000	$65,000
Face value of senior notes issued	450,000,000
Notes payable to founder	24,540,000	23,331,000
Interest on notes payable to founder	1,209,000	1,208,000	1,212,000
Debt covenants description	The credit facility and senior notes include covenants requiring that we maintain certain financial covenants including a current ratio, leverage ratio, and interest coverage ratio.
Debt covenant compliance description	At DecemberB 31, 2014, we were in compliance with the covenants.
Debt restrictive covenants description	The terms of the credit facility also restrict our ability to make distributions and investments.
Credit Facility [Member]
Debt Instrument [Line Items]
Date of sixth amended and restated credit agreement	13-May-10
Line of Credit Facility, Collateral	The credit facility matures on MayB 23, 2016 and is secured by substantially all of our oil and natural gas properties.
Date of maturity of credit facility	23-May-16
Credit facility borrowing base	375,000,000
Credit facility interest rate	2.89%	2.75%
Minimum Working Capital Ratio	1
Minimum Coverage of Interest Expense Ratio	3
Maximum Leverage Ratio	4
Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description	LIBOR plus applicable margins between 2.00% and 2.75%
Credit Facility [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Credit facility applicable interest rate, description	prime rate of Wells Fargo Bank, N. A., plus a margin ranging from 1.00% to 1.75%
Credit Facility [Member] | Minimum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate	2.00%
Credit Facility [Member] | Minimum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate	1.00%
Credit Facility [Member] | Maximum [Member] | London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Margin interest rate	2.75%
Credit Facility [Member] | Maximum [Member] | Prime Rate [Member]
Debt Instrument [Line Items]
Margin interest rate	1.75%
Senior Notes [Member]
Debt Instrument [Line Items]
Face value of senior notes issued	450,000,000
Maturity Date of Debt	15-Oct-18
Stated interest rate of senior notes	9.63%
Effective rate of interest on senior notes	9.78%
Senior notes interest payable date	Interest is payable semi-annually each AprilB 15th and OctoberB 15th.
Debt instrument collateral	The senior notes are unsecured and are general obligations of the Company, and effectively rank junior to any of our existing or future secured indebtedness, which includes the credit facility. The senior notes are unconditionally guaranteed on a senior unsecured basis by each of our material subsidiaries.
Remaining unamortized discount	1,900,000	2,400,000
Senior Notes [Member] | Twelve Mos Beginning October 15, 2015 [Member]
Debt Instrument [Line Items]
Optional redemption price of Senior Notes	102.41%
Senior Notes [Member] | Twelve Mos Beginning October 15, 2016 [Member]
Debt Instrument [Line Items]
Optional redemption price of Senior Notes	100.00%
Notes Payable To Founder [Member]
Debt Instrument [Line Items]
Maturity Date of Debt	31-Dec-21	31-Dec-18
Effective rate of interest on senior notes	10.00%	10.00%
Debt instrument collateral	These founder notes are unsecured and are subordinate to all debt.
Interest on notes payable to founder	$1,200,000	$1,200,000	$1,200,000

Long_Term_Debt_LongTerm_Debt_D

Long Term Debt (Long-Term Debt) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Long Term Debt [Abstract]
Credit Facility	$319,520	$319,290
Senior Notes, net of discount	448,088	447,578
Total long-term debt	767,608	766,868
Notes payable to founder	$24,540	$23,331

Long_Term_Debt_Summary_Of_Futu

Long Term Debt (Summary Of Future Maturities Of Long-Term Debt) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Summary of future maturities of long-term debt
2015
2016	319,520
2017
2018	450,000
2019
Thereafter	24,540
Total long-term debt	$794,060

Accounts_Payable_And_Accrued_L2

Accounts Payable And Accrued Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounts Payable And Accrued Liabilities [Abstract]
Capital expenditures	$32,990	$18,629
Revenues and royalties payable	7,302	9,699
Operating expenses/taxes	20,716	17,071
Interest	9,136	9,146
Compensation	10,586	8,862
Other	2,605	2,711
Total accrued liabilities	83,335	66,118
Accounts payable	34,225	29,977
Accounts payable and accrued liabilities	$117,560	$96,095

Recovered_Sheet1

Commitments and Contingencies (Details) (USD $)	12 Months Ended			3 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 23, 2015	Jul. 24, 2013
					item
Commitment And Contingencies [Line Items]
Liability for soil contamination	$1.10	$1.10
Vesting period, PARs	5 years
Number of performance appreciation rights granted	271,500
Weighted average stipulated price of PARs granted	$33.19
Payment under contingent commitment towards properties acquired	2.2
Rent expense	5.7	5.3	4.5
Performance Bonds Outstanding	$24.20
Subsequent Event [Member]
Commitment And Contingencies [Line Items]
Number of performance appreciation rights granted				244,000
Weighted average stipulated price of PARs granted				$32.42
Number of performance appreciation rights terminated				27,500
Weighted average price of PARs terminated				$40
Building [Member]
Commitment And Contingencies [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	The lease for our main office will expire in 2022. Any initial rent-free months are amortized over the life of the lease.
Upstream Equipment [Member]
Commitment And Contingencies [Line Items]
Description of Lessee Leasing Arrangements, Operating Leases	Equipment leases are generally for four years or less
Upstream Equipment [Member] | Maximum [Member]
Commitment And Contingencies [Line Items]
Term of leases	4 years
Meridian Resource Company, L L C [Member] | Board Of Commissioners Of Southeast Louisiana Flood Protection Authority - East [Member]
Commitment And Contingencies [Line Items]
Number of wells					32
Number of dredging permits					2
Number of right of way agreements					4

Commitments_And_Contingencies_1

Commitments And Contingencies (Future Base Rentals For Non-Cancelable Leases) (Details) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified
Future base rentals for non-cancelable leases
2015	$2,004
2016	1,562
2017	1,552
2018	1,529
2019	1,580
Thereafter	4,420
Total future base rental	$12,647

Major_Customers_Details

Major Customers (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

customer

customer

customer

Revenue, Major Customer [Line Items]

Revenues

$179,951

[1]

$184,111

[1]

$86,254

[1]

$165,891

[1]

$85,924

$77,759

$123,531

$68,578

$616,207

$355,792

$319,299

Number of customers that accounted for 10% or more of revenues

1

3

3

Minimum percentage of contribution of customers to revenue

10.00%

10.00%

10.00%

Benchmark for determining customer significance

revenues excluding hedging activities

ARM Energy Management, LLC [Member]

Revenue, Major Customer [Line Items]

Marketing fee

1.00%

Term of agreement left until extensions may come into effect

5 years

Revenues

220,900

61,300

Concentration Risk, Percentage

51.10%

16.00%

ARM Energy Management, LLC [Member] | Maximum [Member]

Revenue, Major Customer [Line Items]

Percentage of ownership interest

10.00%

10.00%

Murphy [Member]

Revenue, Major Customer [Line Items]

Revenues

61,200

119,300

50,100

Shell Trading (US) Company [Member]

Revenue, Major Customer [Line Items]

Revenues

53,900

63,300

Plains Marketing And Transportation, Inc. [Member]

Revenue, Major Customer [Line Items]

Revenues

42,000

EnCana [Member]

Revenue, Major Customer [Line Items]

Revenues

$44,800

[1]

Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively.

401k_Savings_Plan_Details

401(k) Savings Plan (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Savings Plan [Abstract]
Percentage of matching contribution by company	50.00%
Maximum percentage of employee's salary deferral contribution	8.00%
Matching contributions to the plan	$683,000	$585,000	$422,000

Significant_Risks_And_Uncertai1

Significant Risks And Uncertainties (Details)	12 Months Ended
	Dec. 31, 2014
Significant Risks And Uncertainties [Abstract]
Risks and uncertainties inherent	Our business makes us vulnerable to changes in wellhead prices of oil and natural gas. Historically, world-wide oil and natural gas prices and markets have been volatile, and may continue to be volatile in the future. In particular, the prices of oil and natural gas were highly volatile in 2014 and declined dramatically in the second half of the year. 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 reserves. Sustained low oil or natural gas prices may require us to further write down the value of our oil and natural gas properties and/or revise our development plans, which may cause certain of our undeveloped well locations to no longer be deemed proved. As a result of the depressed commodity prices and in order to preserve our liquidity, we have reduced our budgeted capital expenditures for 2015. This could cause a reduction in the borrowing base under our credit facility. Low prices may also reduce our cash available for distribution, acquisitions and for servicing our indebtedness.

Partners_Capital_Deficit_Detai

Partners' Capital (Deficit) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
	item
Partners' Capital (Deficit) [Abstract]
Number of classes of limited partners	2
Amount of recapitalization	$350
Number of members added to Board of Directors, nominated by Highbridge	1
Number of members added to Board of Directors, nominated by Class A partners	4

Supplemental_Quarterly_Informa2

Supplemental Quarterly Information (Details) (USD $)	3 Months Ended																12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Quarterly Information [Abstract]
Revenues	$179,951	[1]	$184,111	[1]	$86,254	[1]	$165,891	[1]	$85,924		$77,759		$123,531		$68,578		$616,207	$355,792	$319,299
Income (loss) from operations	35,873	[2]	73,025	[2]	-25,186	[2]	71,461	[2]	-115,469	[3]	-11,915	[3]	29,799	[3]	-1,066	[3]	155,173	-98,651	-55,399
Net income (loss)	21,793		59,326		-38,812		56,893		-129,860		-25,737		16,168		-14,286		99,200	-153,715	-95,875
Gain on sale of asset			18,300				73,100										87,520	-2,715
Impairment expense			$8,700		$18,300				$114,500				$19,200		$7,400		$74,927	$143,166	$96,227
[1]	Includes $73.1 million and $18.3 million gain on sale of asset in March 31, 2014 and September 30, 2014, respectively.
[2]	Includes $18.3 million and $8.7 million of impairment expense in June 30, 2014 and September 30, 2014, respectively.
[3]	Includes $7.4 million, $19.2 million and $114.5 million of impairment expense in March, 31, 2013, June 30, 2013 and December 31, 2013, respectively.

Supplemental_Oil_And_Natural_G2

Supplemental Oil And Natural Gas Disclosures (Estimated Quantities Of Proved Reserves) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls	MBbls
Oil [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	32,517	20,620	16,933
Production	-3,770	-2,897	-2,138
Purchases in place	610	1,462	335
Discoveries and extensions	13,281	14,541	10,173
Sales of reserves in place	-6,298	-13
Revisions of previous quantity estimates and other	-4,996	-1,196	-4,683
Proved Reserves, Ending balance	31,344	32,517	20,620
Developed Reserves	15,182	16,335	10,467
Proved Undeveloped Reserves	16,162	16,182	10,153
Natural Gas in MMcf [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	132,265	152,489	217,266
Production	-14,449	-16,664	-21,372
Purchases in place	327	1,265	6,619
Discoveries and extensions	28,822	29,012	18,870
Sales of reserves in place	-35,857	-10,912
Revisions of previous quantity estimates and other	-7,960	-22,925	-68,894
Proved Reserves, Ending balance	103,148	132,265	152,489
Developed Reserves	63,334	92,640	111,206
Proved Undeveloped Reserves	39,814	39,625	41,283
Natural Gas Liquids [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	5,735	5,695	4,845
Production	-537	-398	-365
Purchases in place			8
Discoveries and extensions	4,119	1,969	1,187
Sales of reserves in place	-949
Revisions of previous quantity estimates and other	20	-1,531	20
Proved Reserves, Ending balance	8,388	5,735	5,695
Developed Reserves	4,028	3,138	4,209
Proved Undeveloped Reserves	4,360	2,597	1,486
Barrels of Oil Equivalent [Member]
Total Proved Reserves:
Proved Reserves, Beginning Balance	60,296	51,731	57,989
Production	-6,715	-6,072	-6,065
Purchases in place	665	1,673	1,446
Discoveries and extensions	22,204	21,345	14,505
Sales of reserves in place	-13,223	-1,832
Revisions of previous quantity estimates and other	-6,304	-6,549	-16,144
Proved Reserves, Ending balance	56,923	60,296	51,731
Developed Reserves	29,765	34,913	33,211
Proved Undeveloped Reserves	27,158	25,383	18,520

Supplemental_Oil_And_Natural_G3

Supplemental Oil And Natural Gas Disclosures (Capitalized Costs Relating To Oil And Natural Gas Producing Activities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Capitalized costs:
Proved properties	$1,417,785	$1,405,658
Unproved properties	84,620	86,721
Total	1,502,405	1,492,379
Accumulated depreciation, depletion, amortization and impairment	-816,229	-800,609
TOTAL OIL AND NATURAL GAS PROPERTIES, net	$686,176	$691,770

Supplemental_Oil_And_Natural_G4

Supplemental Oil And Natural Gas Disclosures (Costs Incurred In Oil And Natural Gas Acquisition, Exploration And Development Activities) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Costs Incurred in Oil and Natural Gas Acquisition, Exploration and Development Activities
Property acquisition costs, unproved properties	$33,787,000		$34,884,000		$31,695,000
Property acquisition costs, proved properties	7,462,000	[1]	35,954,000	[1]	12,192,000	[1]
Costs incurred, exploration	59,201,000		55,300,000		46,559,000
Costs incurred, development	341,594,000	[2]	242,912,000	[2]	200,974,000	[2]
Costs Incurred, Total	442,044,000		369,050,000		291,420,000
Costs Incurred, Additional Information [Abstract]
Development Costs Incurred As Asset Retirement Obligations	4,500,000		1,400,000		1,700,000
Stone [Member]
Costs Incurred, Additional Information [Abstract]
Total cost of Business Acquisition			$30,600,000
[1]	Property acquisition costs for proved properties in 2013 include primarily the proved portion of the Stone acquisition ($30.6 million).
[2]	Includes asset retirement costs of $4.5 million, $1.4 million, and $1.7 million for the years ended DecemberB 31, 2014, 2013, and 2012, respectively.

Supplemental_Oil_And_Natural_G5

Supplemental Oil And Natural Gas Disclosures (Components Of The Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components of the standardized measure of discounted future net cash flows
Future cash flows	$3,737,412	$3,959,938	$2,742,588
Future production costs	-991,149	-1,146,123	-928,398
Future development costs	-450,659	-474,191	-348,042
Future taxes on income
Future net cash flows	2,295,604	2,339,624	1,466,148
Discount to present value at 10 percent per annum	-877,558	-933,350	-551,727
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Total	$1,418,046	$1,406,274	$914,421	$1,070,196
Base price for crude oil, per Bbl, in the above computations was	94.99	96.78	94.71
Base price for natural gas, per Mcf, in the above computations was	4.35	3.67	2.76

Supplemental_Oil_And_Natural_G6

Supplemental Oil And Natural Gas Disclosures (Components Of Changes In Standardized Measure Of Discounted Future Net Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Components of changes in standardized measure of discounted future net cash flows
Balance at beginning of year	$1,406,274	$914,421	$1,070,196
Sales of oil and natural gas, net of production costs	-320,130	-263,952	-189,709
Changes in sales and transfer prices, net of production costs	-153,770	69,609	-291,285
Revisions of previous quantity estimates	-477,377	-150,634	-250,424
Purchases of reserves-in-place	21,633	93,877	10,283
Sales of reserves-in-place	-107,414	-11,193
Current year discoveries and extensions	701,820	621,832	420,496
Changes in estimated future development costs	2,591	11,623	54,493
Development costs incurred during the year	161,357	75,973	49,834
Accretion of discount	140,627	91,442	107,020
Net change in income taxes
Change in production rate (timing) and other	42,435	-46,724	-66,483
Net change	11,772	491,853	-155,775
Balance at end of year	$1,418,046	$1,406,274	$914,421