Mid-Con Energy Partners (MCEP) 10-K 5 Mar 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Mar. 05, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Entity Registrant Name	'Mid-Con Energy Partners, LP	'	'
Entity Central Index Key	'0001527709	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Accelerated Filer	'	'
Document Type	'10-K	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'MCEP	'	'
Amendment Flag	'false	'	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Voluntary Filers	'No	'	'
Entity Current Reporting Status	'Yes	'	'
Entity Common Stock, Shares Outstanding	'	21,066,412	'
Entity Public Float	'	'	$305.40
General Partner Units [Member]	'	'	'
Entity Information [Line Items]	'	'	'
Entity Common Stock, Shares Outstanding	'	360,000	'

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents	$1,434	$1,053
Accounts receivable:	'	'
Oil and natural gas sales	6,778	6,413
Other	104	603
Derivative financial instruments	153	3,679
Prepaids and other	191	25
Total current assets	8,660	11,773
Oil and natural gas properties, successful efforts method:	'	'
Proved properties	216,680	167,036
Accumulated depletion, depreciation and amortization	-36,148	-21,727
Total property and equipment, net	180,532	145,309
DERIVATIVE FINANCIAL INSTRUMENTS	48	858
OTHER ASSETS	843	650
Total assets	190,083	158,590
Accounts payable	'	'
Trade	2,184	2,168
Related parties	2,982	3,036
Derivative financial instruments	1,627	0
Accrued liabilities	432	315
Total current liabilities	7,225	5,519
OTHER LONG-TERM LIABILITIES	128	0
LONG-TERM DEBT	112,000	78,000
ASSET RETIREMENT OBLIGATIONS	3,942	2,890
COMMITMENTS AND CONTINGENCIES	'	'
Partnership equity	'	'
General partner interest	1,716	1,814
Limited partners-19,319,362 and 18,990,849 units issued and outstanding as of December 31, 2013 and 2012, respectively	65,072	70,367
Total equity	66,788	72,181
Total liabilities and equity	$190,083	$158,590

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]	'	'
Limited partners, units issued	19,319,362	18,990,849
Limited partners, units outstanding	19,319,362	18,990,849

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Oil sales	$85,080	$60,887	$36,813
Natural gas sales	656	674	1,218
Net settlements on derivatives	288	3,710	-2,157
Gain (loss) on unsettled derivatives, net	-5,963	2,004	3,437
Total revenues	80,061	67,275	39,311
Operating costs and expenses:	'	'	'
Lease operating expenses	16,366	10,948	8,491
Oil and natural gas production taxes	3,817	1,965	1,869
Impairment of proved oil and natural gas properties	1,578	1,296	0
Dry holes and abandonments of unproved properties	0	0	813
Depreciation, depletion and amortization	14,421	10,324	7,160
Accretion of discount on asset retirement obligations	173	126	78
General and administrative	12,244	11,000	3,767
Total operating costs and expenses	48,599	35,659	22,178
Income from operations	31,462	31,616	17,133
Other income (expense):	'	'	'
Interest income and other	9	10	216
Interest expense	-3,282	-1,764	-578
Gain on sale of assets	0	0	1,621
Other revenue and expenses, net	0	0	576
Total other income (expense)	-3,273	-1,754	1,835
Net income	28,189	29,862	18,968
Computation of net income per limited partner unit:	'	'	'
General partners' interest in net income	518	584	379
Limited partners' interest in net income	$27,671	$29,278	$18,589
Net income per limited partner unit:	'	'	'
Basic (in dollars per share)	$1.44	$1.62	$1.05
Diluted (in dollars per share)	$1.44	$1.62	$1.05
Weighted average limited partner units outstanding:	'	'	'
Common limited partner units (basic)	19,234	18,049	17,640
Common limited partner units (diluted)	19,249	18,049	17,640

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash Flows from Operating Activities:	'	'	'
Net income	$28,189	$29,862	$18,968
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion and amortization	14,421	10,324	7,160
Debt placement fee amortization	168	131	0
Accretion of discount on asset retirement obligations	173	126	78
Impairment of proved oil and natural gas properties	1,578	1,296	0
Dry holes and abandonments of unproved properties	0	0	813
Loss (gain) on unsettled derivative instruments, net	5,963	-2,004	-3,437
Equity-based compensation	6,376	6,323	1,671
Gain on sale of assets	0	0	-1,621
Changes in operating assets and liabilities:	'	'	'
Accounts receivable	-365	-1,395	-4,454
Other receivables	499	-603	0
Prepaid and other	-526	2,159	415
Accounts payable and accrued liabilities	158	1,498	4,608
Revenues payable	0	0	32
Advance billings and other	0	0	-120
Net cash provided by operating activities	56,634	47,717	24,113
Cash Flows from Investing Activities:	'	'	'
Additions to oil and natural gas properties	-22,366	-23,960	-32,654
Acquisitions of oil and natural gas properties	-28,057	-48,579	-16,026
Additions to other property and equipment	0	0	-679
Proceeds from sale of other property and equipment	0	0	1,219
Proceeds from sale of investment in subsidiary, net of cash sold	0	0	2,095
Proceeds from sale of property and equipment to subsidiary, net of cash sold	0	0	4,000
Net cash used in investing activities	-50,423	-72,539	-42,045
Cash Flows from Financing Activities:	'	'	'
Proceeds from line of credit	105,000	80,800	68,564
Payments on line of credit	-71,000	-47,800	-29,385
Distributions paid	-39,830	-27,705	-110,937
Borrowings on note payable	0	0	412
Payments on note payable	0	0	-84
Proceeds from initial public offering, net of discount	0	0	87,397
Repurchase of common units	0	0	-1
Issuance of common units	0	20,352	1,972
Net cash (used in) provided by financing activities	-5,830	25,647	17,938
Net increase in cash and cash equivalents	381	825	6
Beginning cash and cash equivalents	1,053	228	222
Ending cash and cash equivalents	1,434	1,053	228
Supplemental Cash Flow Information:	'	'	'
Cash paid for interest	2,803	1,561	535
Non-Cash Investing and Financing Activities:	'	'	'
Accrued capital expenditures - oil and natural gas properties	926	1,005	3,331
Deferred gain on sale of property and equipment to subsidiary	$0	$0	$1,208

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)	Total	Contributed Capital [Member]	Notes Receivable from Officers, Director and Employees [Member]	Accumulated Earnings/(Deficit) [Member]	General Partner [Member]	Limited Partner [Member]
In Thousands
Balance at Dec. 31, 2010	$43,072	$52,923	($1,833)	($8,018)	'	'
Contributions	1,244	1,350	-106	'	'	'
Repurchase of common units	-1	-4	3	'	'	'
Equity-based compensation	1,671	1,671	'	'	'	'
Net income	17,927	'	'	17,927	'	'
Balance at Nov. 30, 2011	63,913	55,940	-1,936	9,909	'	'
Combination transaction with Mid-Con Energy I, LLC and Mid-Con Energy II, LLC	63,913	'	'	'	1,278	62,635
Combination transaction with Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, Units	'	'	'	'	'	12,240
Issuance of common units in initial public offering	87,395	'	'	'	'	87,395
Issuance of common units in initial public offering, Units	'	'	'	'	'	5,400
Distributions	-109,000	'	'	'	'	-109,000
Net income	1,041	'	'	'	21	1,020
Balance at Dec. 31, 2011	43,349	'	'	'	1,299	42,050
Balance, Units at Dec. 31, 2011	'	'	'	'	'	17,640
Issuance of common units in initial public offering	0	'	'	'	'	'
Distributions	-27,705	'	'	'	-537	-27,168
Equity-based compensation	6,323	'	'	'	119	6,204
Equity-based compensation, Units	'	'	'	'	'	351
Issuance of common units	20,352	'	'	'	378	19,974
Issuance of common units, Units	'	'	'	'	'	1,000
Net income	29,862	'	'	'	555	29,307
Balance at Dec. 31, 2012	72,181	'	'	'	1,814	70,367
Balance, Units at Dec. 31, 2012	'	'	'	'	'	18,991
Issuance of common units in initial public offering	0	'	'	'	'	'
Distributions	-39,830	'	'	'	-731	-39,099
Equity-based compensation	6,248	'	'	'	115	6,133
Equity-based compensation, Units	'	'	'	'	'	328
Net income	28,189	'	'	'	518	27,671
Balance at Dec. 31, 2013	$66,788	'	'	'	$1,716	$65,072
Balance, Units at Dec. 31, 2013	'	'	'	'	'	19,319

Organization_and_Nature_of_Ope

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Organization and Nature of Operations	'
	Organization and Nature of Operations
	Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership,” the "Company") is a publicly held Delaware limited partnership formed in December 2011, that engages in the acquisition, development and production of oil and natural gas properties in North America, with a focus on the Mid-Continent region of the United States. Our common units are traded on the NASDAQ Global Select Market under the symbol “MCEP”. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Summary of Significant Accounting Policies	'
	Summary of Significant Accounting Policies
	Basis of presentation and principles of consolidation
	The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2013, 2012 and 2011.
	The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany transactions and account balances have been eliminated. Additionally, our financial statements for previous periods include certain reclassifications that were made to conform to the current period presentation. Such reclassifications have no impact on previously reported total assets, total liabilities, net income or equity.
	We aggregate all of our oil and natural gas properties into one business segment engaged in the exploration, development and production of oil and natural gas.
	Use of estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant items subject to those estimates and assumptions include: depletion of oil and gas properties which is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of business combinations, fair value of derivative financial instruments, purchase price allocation of business acquisitions and fair value of equity-based compensation.
	Cash and cash equivalents
	We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents. We have not experienced any losses in such accounts.
	Accounts receivable
	Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote. As of December 31, 2013 and 2012, we did not have any reserves for doubtful accounts, and we did not incur any expenses related to bad debts in any period presented.
	Revenue recognition
	We follow the sales method of accounting for crude oil and natural gas revenues. Under this method, revenues are recognized based on our share of actual proceeds from oil and gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. We had no significant natural gas imbalances at December 31, 2013 or 2012.
	Oil and natural gas properties
	We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs relating to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis.
	Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned.
	Costs of significant nonproducing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depreciation until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented.
	Impairment of Long-Lived Assets
	We review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves based on our expectations of future oil and gas prices and costs. We review our oil and gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base.
	For the year ended December 31, 2013 and 2012, we recorded non-cash impairment charges of approximately $1.6 million and $1.3 million, respectively, related to our producing properties within our miscellaneous core areas. For the year ended December 31, 2011 no impairment charge was recorded. These non-cash charges are included in "impairment of proved oil and natural gas properties” line item in the accompanying consolidated statements of operations. The fair value of the properties was measured by utilizing the estimated cash flow reported in the audited reserve report. This report was adjusted for future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs in the fair value hierarchy described in Note 6. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and development costs, future commodity prices and market-based weighted average cost of capital rate. The underlying commodity prices embedded in our estimated cash flow are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes and future expected oil and natural gas prices. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices. The impairments were caused by the decrease in reserves of our oil and natural gas properties in 2013 and 2012. These impairments have no impact on our cash flow, liquidity position, or debt covenants.
	We did not have any abandonment expenses for the years ended December 31, 2013 and 2012, and we recognized approximately $0.8 million as abandonment expense for the year ended December 31, 2011, related to our unproved oil and gas properties.
	Other property and equipment
	Other property and equipment is stated at historical cost and is comprised of software, vehicles, office equipment, and field service equipment. Costs incurred for normal repairs and maintenance are charged to expense as incurred, unless they extend the useful life of the asset. Depreciation is calculated using the straight-line method based on estimated useful lives of the assets ranging from 3 to 15 years and is included in the accumulated depreciation, depletion and amortization totals. All of the other property and equipment was sold to one of our Affiliates at June 30, 2011. Consequently, there was no depreciation expense related to other property and equipment for the years ended December 31, 2013 and 2012. For the year ended December 31, 2011, depreciation expense related to other property and equipment totaled approximately $0.3 million.
	Asset retirement obligations
	We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We are required to record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We typically incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.
	Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the statements of operations.
	Derivatives and hedging
	Our risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations in location differences between published index prices and the NYMEX futures prices. These transactions are primarily in the form of either swaps with fixed settlements or collars (calls and puts). Our policies do not permit the use of derivatives for speculative or trading purposes.
	We do not designate commodity derivative contracts as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings as a non-cash gain or loss. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Net settlement gains or losses on derivative contracts only arise from net payments made or received on monthly settlements or if a commodity derivative contract is terminated prior to its expiration. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis by counterparty.
	Other revenue and expense, net
	Prior to June 30, 2011, we received fees for the operation of jointly-owned oil and gas properties and recorded such reimbursements as reductions of other revenue and expense, net. Such fees totaled approximately $2.1 million for the year ended December 31, 2011. These fees are now received by our affiliate, Mid-Con Energy Operating.
	Equity-based compensation
	The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value of compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. Compensation expense for these awards is recorded upon vesting, based on their grant-date fair value. Generally, no compensation expense is recognized for equity instruments that do not vest. We recorded equity-based compensation expense of $6.6 million, $6.5 million and $1.7 million for the years ended December 31, 2013, 2012 and 2011, respectively, which includes non-cash equity based compensation and cash-based compensation costs for employer taxes reimbursed to Mid-Con Energy Operating. The non-cash equity based compensation portion totaled $6.4 million, $6.3 million and $1.7 million for 2013, 2012 and 2011, respectively. In 2013 and 2012, the cash-based costs for employer taxes totaled approximately $0.2 million per year. There were no employer tax costs associated with the 2011 equity-based compensation recognized as this transaction was part of the contribution, conveyance and merger agreement signed on December 20, 2011. See Note 10 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information.
	Debt placement fee
	Debt placement fees are stated at cost, net of amortization, which is computed using the straight-line method. At December 31, 2013 and 2012, net debt issuance costs of approximately $0.4 million and $0.7 million, respectively, are included in "other assets" on the consolidated balance sheets. When debt is retired before its scheduled maturity date, we write off any remaining issuance costs associated with that debt.
	Income taxes
	We are a partnership that is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, our taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
	Net income per limited partner unit
	Basic and diluted net income per limited partner unit is determined by dividing net income available to the limited partners, after deducting the general partner’s interest in net income, by the weighted average number of outstanding limited partner units during the period.
	Business segment reporting
	We operate in one reportable segment: the exploration, development and production of oil and natural gas properties. All of our operations are located in the United States.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Acquisitions	'
	Acquisitions
	Acquisitions 2013
	In May 2013, we acquired additional working interests in our Cushing properties located in the Northeastern Oklahoma core area and in certain Southern Oklahoma units. The results of operations of these properties have been included in the consolidated financial statements since the acquisition date. We paid approximately $27.4 million in aggregate consideration for the interests and the transaction was accounted for under the acquisition method. The transaction was financed using proceeds from our credit facility. The recognized fair values of the identifiable assets of the Cushing properties acquired and liabilities assumed in connection with the acquisition are as follows (in thousands):
	Fair Value of net assets:
	Oil and natural gas properties	$	28,318
	Total assets acquired	$	28,318
	Fair Value of net liabilities assumed:
	Asset retirement obligation	906
	Net assets acquired	$	27,412
	Acquisitions 2012
	In June 2012, we acquired certain oil properties located in the Northeastern Oklahoma core area, and additional working interests in our existing units in the Southern Oklahoma core area, in unrelated transactions. We paid approximately $16.4 million in aggregate consideration for these properties.
	In October 2012, we acquired additional working interests in our War Party Unit I and War Party Unit II located in the Hugoton Basin core area. We paid approximately $3.7 million for the interests.
	In November 2012, we acquired a 100% working interest in the Clawson Ranch Waterflood Unit (“Clawson Ranch”) in our Hugoton Basin core area from multiple parties. We paid approximately $28.9 million in consideration for the properties and interests. The transactions were financed using proceeds from our credit facility. The purchase price for these properties represented approximately 30% of the total value of Mid-Con Energy Partners, LP assets as of December 31, 2011. The recognized fair values of the identifiable assets of the Clawson Ranch acquired and liabilities assumed in connection with the acquisition are as follows (in thousands):
	Fair Value of net assets:
	Oil and natural gas properties	$	29,105
	Total assets acquired	$	29,105
	Fair Value of net liabilities assumed:
	Asset retirement obligation	249
	Net assets acquired	$	28,856
	The following table reflects pro forma revenues, net income and net income per limited partner unit for the years ended as if the Clawson Ranch acquisition had taken place on January 1, 2011. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future (in thousands):
		2012		2011
	Revenues	73,443		47,677
	Net income	32,112		22,408
	Net income per limited partner unit
	Basic and diluted	$	1.74	$	1.24

Equity_Awards

Equity Awards	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Equity Awards	'
	Equity Awards
	We have a long-term incentive program (the “Long-Term Incentive Program”) for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, LLC. (“Mid-Con Energy Operating”), who perform services for us. The Long-Term Incentive Program allows for the award of unit options, unit appreciation rights, restricted units, phantom units, distribution equivalent rights granted with phantom units, and other types of awards and it is administered by the members of our general partner (the "Founders") and approved by the Board of Directors of the general partner. The Long-Term Incentive Program permits the grant of awards covering an aggregate of 1,764,000 units under the Form S-8 we filed with the SEC on January 25, 2012. If an employee terminates employment prior to the restriction lapse date, the awarded shares are forfeited and canceled and are no longer considered issued and outstanding. The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2013:
			Number of Common Units
	Approved and authorized awards		1,764,000
	Unrestricted units granted, included vested units		(558,773	)
	Restricted units granted, net of forfeitures and vesting		(120,589	)
	Phantom units issued, net of forfeitures		(43,000	)
	Awards available for future grant		1,041,638
	Equity Awards
	We account for restricted units as equity awards since these awards will be settled by issuing common units. These restricted units vest over a three-year period and we assume a 10% forfeiture rate. A summary of our restricted units awarded for the years ended December 31, 2013 and 2012 is presented below:
	Restricted awards:	Number of Restricted Units			Average Grant Date Fair Value per Unit
	Outstanding at December 31, 2011	—
	Units granted	62,658			$21.26
	Units forfeited	(7,509	)		$21.45
	Restricted units outstanding at December 31, 2012	55,149
	Units granted	96,185			$23.86
	Units vested	(18,399	)		$21.24
	Units forfeited	(12,346	)		$22.13
	Outstanding at December 31, 2013	120,589
	Liability Awards
	We account for phantom units issued during 2013 as liability awards due to the Long-Term Incentive Program’s provision allowing the Board of Directors, at its discretion, to settle the award in either cash or common units. The phantom units are an incentive based equity award that will be issued to employees or members of the board of directors over a three-year vesting period subject to attaining certain production target levels. The phantom units are not eligible to receive quarterly distributions until they vest. The fair value of these phantom units is remeasured at the end of each reporting period based on the current market price of our common units discounted for expected forfeitures and distribution payments during the vesting period in addition to an adjustment related to management's expectation of the Partnership's ability to attain the stated production target levels. These costs are reported as a component of general and administrative expense in our consolidated statement of operations and are net of estimated forfeitures. These units are subject to forfeiture and we assume a 10% forfeiture rate. As of December 31, 2013 we recorded approximately $0.1 million of compensation expense associated with the phantom units.
	Activity related to these phantom units is as follows:
			Number of Units
	Nonvested phantom units as of December 31, 2012		—
	Issued in July 2013		50,000
	Forfeited		(7,000	)
	Nonvested phantom units as of December 31, 2013		43,000
	The weighted average grant-date fair value of unrestricted unit grants and restricted units granted was $22.89 during the year ended December 31, 2013. As of December 31, 2013 there was approximately $1.9 million of unrecognized compensation costs related to nonvested units. The cost is expected to be recognized over a weighted average period of approximately 2.12 years. Additionally, there was approximately $0.6 million of unrecognized compensation cost related to the phantom units based on the closing price of our common units at December 31, 2013. The cost is expected to be recognized over the next 2.5 years.
	We recognized $6.6 million, $6.5 million and $1.7 million of equity-based compensation expense for the years ended December 31, 2013, 2012 and 2011, respectively. These costs are reported as a component of general and administrative expense in our consolidated statement of operations.

Derivative_Financial_Instrumen

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Financial Instruments	'
	Derivative Financial Instruments
	Our risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices. Our policies do not permit the use of derivatives for speculative purposes.
	At December 31, 2013 and 2012 our open positions consisted of crude oil price collar (calls and puts) contracts and crude oil price swap contracts. Under commodity swap agreements, we exchange a stream of payments over time according to specified terms with another counterparty. In a typical commodity swap agreement, we agree to pay an adjustable or floating price tied to an agreed upon index for the oil commodity and in return receive a fixed price based on notional quantities. A collar is a combination of a put purchased by a party and a call option sold by the same party. In a typical collar transaction, if the floating price based on a market index is below the floor price, we receive from the counterparty an amount equal to this difference multiplied by the specified volume. If the floating price exceeds the floor price and is less than the ceiling price, no payment is required by either party. If the floating price exceeds the ceiling price, we must pay the counterparty an amount equal to the difference multiplied by the specific quantity.
	We have elected not to designate commodity derivative contracts as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings as a non-cash gain or loss. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Net settlement gains or losses on derivative contracts only arise from net payments made or received on monthly settlements or if a commodity derivative contract is terminated prior to its expiration. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis by counterparty.
	At December 31, 2013 we had the following oil derivative open positions:
	Period Covered	Weighted			Weighted			Weighted			Total	NYMEX
		Average			Average			Average			Bbls	Index
		Fixed			Floor			Ceiling			Hedged/day
		Price			Price			Price
	Swaps - 2014	$	93.56								1,973
	Swaps - 2015	$	90.05								164
	Collars - 2015				$	85		$	95.13		123	WTI
	At December 31, 2013, we recorded the estimated fair value of the derivative contracts as a net liability of $1.4 million.
	At December 31, 2012 we had the following oil derivative open positions:
	Period Covered	Weighted			Weighted			Weighted			Total	NYMEX
		Average			Average			Average			Bbls	Index
		Fixed			Floor			Ceiling			Hedged/day
		Price			Price			Price
	Swaps - 2013	$	98.26								1,545
	Collars - 2013				$	97.67		$	108.08		296	WTI
	Swaps - 2014	$	93.71								1,644
	At December 31, 2012, we recorded the estimated fair value of the derivative contracts as a net asset of $4.5 million.
	Our oil derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our derivative contracts to post collateral, it is our policy to enter into derivative contracts only with counterparties that are major, creditworthy financial institutions deemed by management as competent and competitive market makers. We evaluate the credit standing of such counterparties by reviewing their credit rating. The counterparties to our derivative contracts currently in place are lenders under our credit facility and have investment grade ratings.
	The following tables summarizes the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2013 and 2012 (in thousands):
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2013
	Assets
	Derivative financial instrument - current asset	$	541		$	388		$	153
	Derivative financial instrument - long-term asset	48			—			48
	Total	$	589		$	388		$	201
	Liabilities
	Derivative financial instrument - current liability	$	(2,015	)	$	(388	)	$	(1,627	)
	Derivative financial instrument - long-term liability	—			—			—
	Total	$	(2,015	)	$	(388	)	$	(1,627	)
	Net liability	$	(1,426	)	$	—		$	(1,426	)
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2012
	Assets
	Derivative financial instrument - current asset	$	3,843		$	—		$	3,843
	Derivative financial instrument - long-term asset	1,486			346			1,140
	Total	$	5,329		$	346		$	4,983
	Liabilities
	Derivative financial instrument - current liability	$	(164	)	$	—		$	(164	)
	Derivative financial instrument - long-term liability	(628		)	(346		)	(282		)
	Total	$	(792	)	$	(346	)	$	(446	)
	Net asset	$	4,537		—			$	4,537
	The following table summarizes the gains and losses reported in earnings related to the commodity derivative financial instruments within the consolidated statements of operations:
		December 31,
		2013			2012			2011
	Net settlements on derivatives	$	288		$	3,710		$	(2,157	)
	Gain (loss) on unsettled derivatives, net	(5,963		)	2,004			3,437
	Total gain (loss) on derivatives, net	$	(5,675	)	$	5,714		$	1,280

Fair_Value_Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Disclosures	'
	Fair Value Disclosures
	The carrying amounts reported in the balance sheet for cash, accounts receivable, accounts payable and derivative financial instruments approximate their fair values. The carrying amount of long-term debt under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us.
	We account for our oil and natural gas commodity derivatives at fair value. The fair value of derivative financial instruments is determined utilizing NYMEX closing prices for the contract period.
	Fair value measurements
	Fair value is the price that would be received upon the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP establishes a three-tier fair value hierarchy that is intended to increase consistency and comparability in fair value measurements and related disclosures. The hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3).
	Assets and liabilities recorded in the balance sheet are categorized based on the inputs to the valuation technique as follows:
	Level 1—Financial assets and liabilities for which values are based on unadjusted quoted prices for identical assets or liabilities in an active market that management has the ability to access.
	Level 2—Financial assets and liabilities for which values are based on quoted prices in markets that are not active or model inputs that are observable either directly or indirectly for substantially the full term of the asset or liability.
	Level 3—Financial assets and liabilities for which values are based on prices or valuation techniques that require inputs that are both unobservable and significant to the overall fair value measurement. These inputs reflect management’s own assumptions about the assumptions a market participant would use in pricing the asset or liability.
	When the inputs used to measure fair value fall within different levels of the hierarchy in a liquid environment, the level within which the fair value measurement is categorized is based on the lowest level input that is significant to the fair value measurement in its entirety. Changes in the observability of valuation inputs may result in a reclassification for certain financial assets or liabilities. We had no transfers in or out of Levels 1, 2 or 3 during the years ended December 31, 2013, 2012 and 2011.
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	We account for commodity derivatives at fair value on a recurring basis. We use certain pricing models to determine the fair value of our derivative financial instruments. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 5 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a summary of our derivative financial instruments.
	Assets and liabilities measured at fair value on a nonrecurring basis
	We estimate the fair value of the AROs based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. See Note 7 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a summary of changes in AROs.
	We review our long-lived assets to be held and used, including proved oil and natural gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows is less than the carrying amount of the assets. In this circumstance, we recognize an impairment loss for the amount by which the carrying amount of the asset exceeds the estimated fair value of the asset and reduces the carrying amount of the asset. Estimating future cash flows involves the use of judgments, including estimation of the proved oil and natural gas reserve quantities, timing of development and production, expected future commodity prices, capital expenditures and production costs. For the year ended December 31, 2013, we recorded a non-cash impairment charge of approximately $1.6 million within our miscellaneous core area. For the year ended December 31, 2012 we recorded a non-cash impairment charge of approximately $1.3 million , approximately $1.1 million of the impairment charge related to our natural gas producing properties. For the year ended December 31, 2011 no impairment charge was recorded. All of the impairment charges are due to a decline in estimated proved and probable reserve values.
	The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012:
		Level 1		Level 2			Level 3
		(in thousands)
	December 31, 2013
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	201		$	—
	Derivative financial instruments- liability	—		$	1,627		—
	Net financial assets	$	—	$	(1,426	)	$	—
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Asset retirement obligations	$	—	$	—		$	879
	Impairment of proved oil and gas properties	$	—	$	—		$	1,578
	31-Dec-12
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	4,983		$	—
	Derivative financial instruments- liability	—		446			—
	Net financial assets	$	—	$	4,537		$	—
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Asset retirement obligations	$	—	$	—		$	845
	Impairment of proved oil and gas properties	$	—	$	—		$	1,296
	Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation techniques or related inputs for the years ended December 31, 2013 and 2012.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligations	'
	Asset Retirement Obligations
	Our AROs represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their production lives, in accordance with applicable state laws. We determine our ARO by calculating the present value of estimated cash flow related to the liability. Each year we review and to the extent necessary, revise our ARO estimates.
	AROs are recorded as a liability at their estimated present value at the various assets’ inception, with the offsetting charge to oil and gas properties. Periodic accretion of the discounted estimated liability is recorded in our consolidated statement of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves.
	Changes in our ARO obligations for the periods indicated are presented in the following table:
		Years Ended December 31,
		2013			2012		2011
		(in thousands)
	Asset retirement obligation - beginning of period	$	2,890		$	1,919	$	2,148
	Liabilities incurred for new wells and interest	1,009			636		370
	Disposition of wells	—			—		(1,024		)
	Revision of estimates	(130		)	209		347
	Accretion expense	173			126		78
	Asset retirement obligation - end of period	$	3,942		$	2,890	$	1,919

Debt

Debt	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt	'
	Debt
	Our credit facility consists of a $250.0 million senior secure revolving credit facility that expires in November 2018. Borrowings under the facility are secured by liens on not less than 80% of our assets and the assets of our subsidiaries. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. At December 31, 2013, we had $112.0 million of borrowings outstanding under the revolving credit facility. The facility requires us and our subsidiaries to maintain a leverage ratio of Consolidated Funded Indebtedness to Consolidated EBITDAX (as defined in the facility) of not more than 4.0 to 1.0, and a current ratio of not less than 1.0 to 1.0.
	During the 2013 borrowing base re-determinations, our borrowing base under the credit facility was reaffirmed at $130.0 million, in April, and it was increased from $130.0 million to $150.0 million in November 2013. Effective with this increase, the maturity terms of our credit facility were extended to November 5, 2018 and the Bank of Nova Scotia was added to the lender group. No other material terms of the original credit agreement were amended. During 2013, in connection with the amendments to our credit facility, we incurred financing fees and expenses of approximately $0.4 million, which will be amortized over the life of the credit facility. Such amortized expenses are recorded in "interest expense" on our consolidated statements of operations.
	Borrowings under the facility may not exceed our current borrowing base of $150.0 million. The borrowing base is determined by the lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that may vary. The borrowing base is subject to scheduled redeterminations on or about April 30 and October 31 of each year with an additional redetermination during the period between each scheduled borrowing base determination, either at our request or at the request of the lenders. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract.
	Borrowings under the credit agreement bear interest at a floating rate based on, at our election: (i) the greater of the prime rate of the Royal Bank of Canada, the federal funds effective rate plus 0.50%, and the one month adjusted London Interbank Offered Rate ("LIBOR") plus 1.0% , all of which are subject to a margin that varies from 0.75% to 1.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 1.75% to 2.75% per annum according to the borrowing base usage. For the year ended December 31, 2013, the average effective rate was approximately 2.7%. The unused portion of the borrowing base is subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage.
	The credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and payments. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest could be declared immediately due and payable. We were in compliance with these covenants as of and during the year ended December 31, 2013.

Commitment_and_Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Commitment and Contingencies	'
	Commitment and Contingencies
	We entered into a service agreement with Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating will provide certain services to us, our subsidiaries and our general partner, including management, administrative and operations services, which include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for or on our behalf and other expenses allocated by Mid-Con Energy Operating to us.
	We are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.
	Our general partner has entered into employment agreements with certain executive officers. The employment agreements provide for a term that commenced on August 1, 2011 and expires on August 1, 2014, unless earlier terminated, with automatic one-year renewal terms unless either we or the employee gives written notice of termination at least by February 1 preceding any such August 1. Pursuant to the employment agreements, each employee will serve in his respective position with our general partner, as set forth above, and has duties, responsibilities, and authority as the board of directors of our general partner may specify from time to time, in roles consistent with such positions that are assigned to him. The agreement stipulates that if there is a change of control, termination of employment with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $1.6 million to $1.9 million, including the value of vesting of any outstanding units.

Equity

Equity	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Equity	'
	Equity
	Common Units
	At December 31, 2013 and 2012, Partnership’s equity consisted of 19,319,362 and 18,990,849 common units, respectively, representing approximately a 98% limited partnership interest in us.
	In October 2012, we sold 4,600,000 common units to the public a price of $21.20 per common unit. 1,000,000 common units were sold by us, and 3,600,000 common units were sold by Yorktown Energy Partners, VI, L.P., Yorktown Energy Partners VII, L.P., and Yorktown Energy Partners VIII, L.P. Proceeds from our 1,000,000 common units offering, net of underwriting discounts and expenses, were approximately $20.4 million. We did not receive any proceeds from the 3,600,000 common units sold by Yorktown.
	Cash Distributions
	We intend to continue to make regular cash distributions to unitholders on a quarterly basis, although there is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our credit facility, occurs or would result from the cash distribution.
	Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. Our cash distribution policy reflects a basic judgment that our unitholders will be better served by us distributing our available cash, after expenses and reserves, rather than retaining it.
	The following sets forth the distributions we paid during the years ended December 31, 2013 and 2012:
			Distribution		Total
	Date Paid	Period Covered	per Unit		Distribution
	February 14, 2013	October 1, 2012 - December 31, 2012	$	0.495	$	9,697
	May 14, 2013	January 1, 2013 - March 31, 2013	0.505		9,891
	August 14, 2013	April 1, 2013 - June 30, 2013	0.515		10,123
	November 14, 2013	July 1, 2013 - September 30, 2013	0.515		10,119
					$	39,830
	February 13, 2012	December 21, 2011 - December 31, 2012	$	0.057	$	1,034	-1
	May 14, 2012	January 1, 2012 - March 31, 2012	0.475		8,622
	August 14, 2012	April 1, 2012 - June 30, 2012	0.475		8,692
	November 14, 2012	July 1, 2012 - September 30, 2012	0.485		9,357
					$	27,705
	-1	The distribution represented a proration of initial quarterly distribution of $0.475 per unit.
	On January 22, 2014, the board of directors declared a quarterly cash distribution for the fourth quarter of 2013 of $0.515 per unit, which was paid on February 14, 2014 to unitholders of record at the close of business on February 7, 2014. The aggregate amount of the distribution was approximately $10.3 million.
	Allocations of Net Income (Loss)
	Net income (loss) is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership during the period.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions	'
	Related Party Transactions
	The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm’s length negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner.
	Services Agreement
	We are party to a services agreement with Mid-Con Energy Operating pursuant to which Mid-Con Energy Operating provides certain services to us, including management, administrative and operational services. The operational services include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. During the years ended December 31, 2013, 2012 and 2011, we reimbursed Mid-Con Energy Operating approximately $3.6 million, $2.9 million and $0.2 million, respectively, for direct expenses.
	Assignment, Bill of Sale and Conveyance Agreement
	On December 20, 2011, we entered into an assignment, bill of sale and conveyance agreement pursuant to which J&A Oil Company, a company controlled by Charles R. Olmstead and Jeffrey R. Olmstead, and Charles R. Olmstead, in his individual capacity, contributed to the partnership certain working interests in the Cushing Field and J&A Oil Company contributed to the partnership its interests in certain derivative contracts for aggregate consideration of approximately $6.0 million.
	Contribution, Conveyance, Assumption and Merger Agreement
	On December 20, 2011, we entered into a contribution, conveyance, assumption and merger agreement pursuant to which Mid-Con Energy I, LLC and Mid-Con Energy II, LLC merged into our subsidiary, Mid-Con Energy Properties, and our general partner made a contribution to us. The contribution, conveyance, assumption and merger agreement provided for the Founders, Yorktown, our executive officers, employees and other individual entities, as the owners of Mid-Con Energy I, LLC and Mid-Con Energy II, LLC, to receive consideration that included a combination of common units and cash from the proceeds of our public offering and for our general partner to receive a 2.0% general partner interest in us. All of the transaction expenses incurred in connection with these transactions were paid from proceeds of our Initial Public Offering.
	Other Transactions with Related Persons
	We, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating, are party to standard oil and gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead charges associated with operating our properties (commonly referred to as the Council of Petroleum Accountants Societies, or COPAS, fee). We and those third parties will also pay Mid-Con Energy Operating for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements.
	At December 31, 2013 and 2012, we had payables to Mid-Con Energy Operating of approximately $3.0 million which is comprised of a joint interest billing payable of approximately $2.2 million and a payable for operating services of approximately $0.8 million. These amounts are included in the Accounts payable-related parties in our consolidated balance sheets.

Credit_Risk

Credit Risk	12 Months Ended
	Dec. 31, 2013
Risks and Uncertainties [Abstract]	'
Credit Risk	'
	Credit Risk
	Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. The percentage of revenue derived by customers that accounted for approximately 10% or more of consolidated total revenues is presented below. No other customer accounted for more than 10% of our consolidated total revenues for 2013, 2012 or 2011.
	For the year ended December 31, 2013, sales of oil and natural gas to Enterprise Crude Oil, LLC (“Enterprise”), Coffeyville Resources Refining & Marketing, LLC ("Coffeyville"), Valero Marketing & Supply Co. ("Valero"), and National Cooperative Refinery Association (“National”) accounted for approximately 50%, 23%, 9%, and 8% respectively, of our total sales revenues. These purchasers represent 46%, 30% , 7%, and 10%, respectively, of our outstanding oil and natural gas accounts receivable at December 31, 2013.
	For the year ended December 31, 2012, purchases by Enterprise Crude Oil, LLC (“Enterprise”), Vitol Inc. Crude Oil Marketing (“Vitol”) and Sunoco Logistics accounted for 32%, 28%, and 21%, respectively of our total sales revenues. Vitol represented 52% of our outstanding oil and natural gas accounts receivable at December 31, 2012. Enterprise and Sunoco Logistics did not have any outstanding receivables at the December 31, 2012 because their contracts had expired during the year 2012. We entered into an agreement with Enterprise beginning January 2013 to begin purchasing our oil in the Southern Oklahoma core area.
	For the year ended December 31, 2011 a subsidiary of Sunoco Logistics Partners L.P. (“Sunoco Logistics”), ScissorTail Energy, LLC and Teppco Crude Oil, LLC accounted for 86%, 9% and 3%, respectively of our total sales revenues. These purchasers represented 88%, 2% and 9%, respectively, of our outstanding oil and natural gas accounts receivable at December 31, 2011.
	We believe that the loss of any one purchaser would not have an adverse effect on our ability to sell its oil and gas production because we believe market conditions are such that we could sell to other purchasers at market-based prices. We have not experienced any significant losses due to uncollectible accounts receivable from these purchasers.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Employee Benefit Plans	'
	Employee Benefit Plans
	In 2011, our general partner adopted the Mid-Con Energy Partners, LP Long-Term Incentive Program which is intended to promote the interests of the partnership by providing to employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating, grants of restricted units, phantom units, unit appreciation rights, distribution equivalent rights, and other unit based awards to encourage superior performance, The Long-Term Incentive Program is also intended to enhance the ability of the general partner and our other affiliates, including Mid-Con Energy Operating, to attract and retain the services of individuals who are essential for the growth and profitability of the partnership and to encourage them to devote their best efforts to advancing the business of the partnership.
	The Long-Term Incentive Program is currently administered by a committee consisting of the Founders and approved by the Board of Directors. Except as set forth in the employment agreements of the executive officers of our general partner, we have no set formula for granting awards to our employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating. In determining whether to grant awards and the amount of any awards, the committee takes into consideration discretionary factors such as the individual’s current and expected future performance, level of responsibility, retention considerations and the total compensation package.
	The type of awards that may be granted under the Long-Term Incentive Program are restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights and other unit-based awards. The maximum number of our common units that are currently authorized to be awarded under the Plan is 1,764,000 units. As of December 31, 2013 there were 1,041,638 units available for issuance.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Taxes	'
	Income Taxes
	We do not pay federal income taxes, as our profits or losses are reported to the taxing authorities by our individual partners.

Subsequent_Events

Subsequent Events	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events	'
	Subsequent Events
	On January 22, 2014, the board of directors declared a quarterly cash distribution for the fourth quarter of 2013 of $0.515 per unit, or $2.06 on an annualized basis, which was paid on February 14, 2014 to unitholders of record as of the close of business on February 7, 2014. The aggregate amount of the distribution was approximately $10.3 million.
	Also on January 22, 2014, the board of directors of our general partner authorized the issuance of 247,050 common units to certain employees of our affiliates and certain directors and founders of our general partner.
	On February 28, 2014, we entered into a definitive purchase and sale agreement (the “Purchase Agreement”) with one of our Mid-Con Affiliates, Mid-Con Energy III, LLC to acquire multiple oil properties located in Cimarron, Love and Texas Counties, Oklahoma and Potter County, Texas for an aggregate purchase price of approximately $41.0 million, subject to customary post-closing purchase price adjustments (collectively, the “Acquisition”). The effective date of the Acquisition was January 1, 2014. The Acquisition was closed on the same day of February 28, 2014.  We paid the aggregate purchase price with (i) approximately $7.0 million in cash, financed through borrowings under our revolving credit facility, and (ii) the issuance of 1,500,000 common units representing limited partner interests in the Partnership, having an approximate value of $34.0 million. The value of the common units issued as partial consideration for the Acquisition was based on a 2.5% discount to the trailing twenty day volume weighted average price of the common units.
	The terms of the Purchase Agreement were approved by the Conflicts Committee of the Board of Directors of the General Partner (the “Conflicts Committee”). The Conflicts Committee, which is composed entirely of independent directors, retained independent legal and financial counsel to assist it in evaluating and negotiating the Purchase Agreement and the Acquisition.

Supplementary_Information

Supplementary Information	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Supplementary Information	'
	Supplementary Information
	Quarterly data (unaudited)
		Quarters Ended
		March 31				June 30				September 30			December 31
		(In thousands, except per unit amounts)
	2013
	Oil and natural gas sales	$	20,176			$	21,110			$	22,982		$	21,468
	Net settlements on derivatives	673				709				(1,293		)	199
	Gain (loss) on unsettled derivatives, net	(1,793		)		960				(5,501		)	371
	Total revenues and other	19,056				22,779				16,188			22,038
	Total expenses (1)	14,997				12,241				11,931			12,703
	Net income	4,059				10,538				4,257			9,335
	Limited partners' interest in net income	3,985				10,344				4,179			9,163
	Net income per limited partner unit (basic)	$	0.21			$	0.54			$	0.22		$	0.47
	Net income per limited partner unit (diluted)	$	0.21			$	0.54			$	0.22		$	0.47
	2012
	Oil and natural gas sales	$	15,507			$	13,844			$	15,048		$	17,162
	Net settlements on derivatives	(134		)		903				1,211			1,730
	Gain (loss) on unsettled derivatives, net	(4,773		)		14,514				(6,103		)	(1,634		)
	Total revenues and other	10,600				29,261				10,156			17,258
	Total expenses (1)	8,938				6,833				11,293			10,349
	Net income (loss)	1,662				22,428				(1,137		)	6,909
	Limited partners' interest in net income (loss)	1,629				21,984				(1,115		)	6,774
	Net income (loss) per limited partner unit (basic)	$	0.09			$	1.23			$	(0.06	)	$	0.36
	Net income (loss) per limited partner unit (diluted)	$	0.09			$	1.23			$	(0.06	)	$	0.36
	-1	Includes the following expenses: lease operating, production taxes, dry holes and abandonments, geological and geophysical, depreciation, depletion and amortization, accretion, and general and administrative.
	Supplementary oil and natural gas activities
		Year Ended December 31,
		2013				2012				2011
		(in thousands)
	Property acquisition costs:
	Proved	$	28,057			$	48,578			$	15,729
	Unproved	—				—				—
	Exploration	—				—				—
	Development	22,287				21,639				30,754
	Asset retirement obligations	879				679				686
	Total costs incurred	$	51,223			$	70,896			$	47,169
	Estimated proved oil and natural gas reserves (unaudited)
	The proved oil and gas reserves for the years ended December 31, 2013, 2012, and 2011 were prepared by our reservoir engineers and audited by Cawley, Gillespie & Associates, Inc., independent third party petroleum consultants. These reserve estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, are presented below for the periods indicated:
		Oil			Gas			MBoe (1)
		(MBbls)			(MMcf)
	Proved developed and undeveloped reserves:
	As of December 31, 2010	7,007			1,346			7,231
	Revisions of previous estimates	740			(370	)		678
	Extensions, discoveries and other additions	1,704			—			1,704
	Purchases of minerals in place	971			140			994
	Sales of minerals in place	(79	)		(276	)		(124	)
	Production	(407	)		(164	)		(434	)
	As of December 31, 2011	9,936			676			10,049
	Revisions of previous estimates	(784	)		(143	)		(808	)
	Extensions, discoveries and other additions	1,572			—			1,572
	Purchases of minerals in place	3,028			18			3,031
	Production	(678	)		(122	)		(698	)
	As of December 31, 2012	13,074			429			13,146
	Revisions of previous estimates	264			827			401
	Extensions, discoveries and other additions	76			—			76
	Purchases of minerals in place	1,207			193			1,239
	Production	(907	)		(128	)		(928	)
	As of December 31, 2013	13,714			1,321			13,934
	Proved developed reserves:
	December 31, 2010	3,601			1,346			3,825
	December 31, 2011	6,835			676			6,948
	December 31, 2012	8,727			429			8,799
31-Dec-13	10,397			1,321			10,617
Proved undeveloped reserves:
December 31, 2010	3,406			—			3,406
December 31, 2011	3,101			—			3,101
December 31, 2012	4,347			—			4,347
31-Dec-13	3,317			—			3,317
-1	Estimated quantities of oil and natural gas reserves in Mboe equivalents at a rate of six Mcf per Bbl.
The change in quantities of proved reserves from December 31, 2010 to December 31, 2011 is due to (i) increases in oil prices during this time period, (ii) acquisitions of the War Party I and II Units in the Hugoton Basin, J&A Oil Company interests in the Cushing Field, and third party interests in the Cleveland Field, (iii) infill drilling in our Ardmore West and Twin Forks waterflood units which resulted in an upward revision of oil in place and therefore recoverable reserves, and (iv) revisions of previous estimates for the balance of our properties.
The change in quantities of proved reserves from December 31, 2011 to December 31, 2012 is due to (i) the acquisitions of additional interests in our Southern Oklahoma units; (ii) the acquisition of additional working interest in our War Party I and II Units in the Hugoton Basin area; (iii), the acquisition of the Clawson Ranch Waterflood Unit in the Hugoton Basin area;, and (iv) the acquisition of additional properties in the Northeastern Oklahoma area.
The change in quantities of proved reserves from December 31, 2012 to December 31, 2013 is due to the acquisitions of additional interests in our Southern Oklahoma units and Northeastern Oklahoma properties and revisions on prior estimates.
Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Unaudited)
The standardized measure represents the present value of estimated future cash inflows from proved oil and gas reserves, less future development, production, plugging and abandonment costs, discounted at the rate prescribed by the SEC. The standardized measure of discounted future net cash flow does not purport to be, nor should it be interpreted to represent, the fair market value of our proved oil and natural gas reserves. The following assumptions have been made:
•In the determination of future cash inflows, sales prices used for oil and natural gas for the years ended December 31, 2013, 2012 and 2011, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month in such period.
•Future costs of developing and producing the proved oil and reserves were based on costs determined at each such period-end, assuming the continuation of existing economic conditions, including abandonment costs.
•No future income tax expenses are computed for Mid-Con Energy Partners, LP because we are a non-taxable entity.
•Future net cash flows were discounted at an annual rate of 10%.
The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated:
	Year Ended December 31,
	2013				2012				2011
	(in thousands)
Future cash inflows	$	1,295,435			$	1,191,410			$	930,788
Future production costs	(542,389		)		(417,362		)		(297,490		)
Future development costs, including abandonment costs	(49,458		)		(47,490		)		(34,504		)
Future net cash flow	703,588				726,558				598,794
10% discount for estimated timing of cash flow	(312,325		)		(323,136		)		(270,563		)
Standardized measure of discounted cash flow	$	391,263			$	403,422			$	328,231
The prices utilized in calculating our total proved reserves were $96.78, $94.71, and $96.19 per Bbl of oil and $3.67, $2.75 and $4.11 per MMBtu of natural gas for December 31, 2013, 2012, and 2011, respectively. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions or other factors affecting the price received at the wellhead. Average adjusted prices used were $93.98, $91.03 and $93.20 per Bbl of oil and $5.00, $2.87 and $7.04 per Mcf of natural gas for December 31, 2013, 2012 and 2011, respectively. Adjusted natural gas price includes the sale of associated natural gas liquids. All wellhead prices are held flat over the life of the properties for all reserve categories.
Changes in the standardized measure of discounted future net cash flow relating to proved oil and gas reserves is presented below for the periods indicated:
	Year Ended December 31,
	2013				2012				2011
Standardized measure of discounted future net cash flow, beginning of period	$	403,422			$	328,231			$	183,662
Changes in the year resulting from:
Sales, less production costs	(65,553		)		(48,648		)		(27,671		)
Revisions of previous quantity estimates	12,006				(26,796		)		26,960
Extensions, discoveries and improved recovery	1,863				51,098				26,128
Net change in prices and production costs	(28,324		)		(15,328		)		79,618
Net change in income taxes	—				—				—
Changes in estimated future development costs	(17,155		)		(11,515		)		(30,521		)
Previously estimated development costs incurred during the period	22,257				21,629				31,968
Purchases of minerals in place	38,170				81,602				20,200
Accretion of discount	40,342				32,823				18,366
Timing differences and other	(15,765		)		(9,674		)		(479		)
Standardized measure of discounted future net cash flow, end of year	$	391,263			$	403,422			$	328,231

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis of presentation and principles of consolidation	'
	Basis of presentation and principles of consolidation
	The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2013 and 2012. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2013, 2012 and 2011.
	The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany transactions and account balances have been eliminated. Additionally, our financial statements for previous periods include certain reclassifications that were made to conform to the current period presentation. Such reclassifications have no impact on previously reported total assets, total liabilities, net income or equity.
	We aggregate all of our oil and natural gas properties into one business segment engaged in the exploration, development and production of oil and natural gas
Use of estimates	'
	Use of estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Significant items subject to those estimates and assumptions include: depletion of oil and gas properties which is determined using estimates of proved oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, asset retirement obligations, fair value of business combinations, fair value of derivative financial instruments, purchase price allocation of business acquisitions and fair value of equity-based compensation.
Cash and cash equivalents	'
	Cash and cash equivalents
	We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.
Accounts receivable	'
	Accounts receivable
	Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account–by–account review after all means of collection have been exhausted, and the potential recovery is considered remote.
Revenue recognition	'
	Revenue recognition
	We follow the sales method of accounting for crude oil and natural gas revenues. Under this method, revenues are recognized based on our share of actual proceeds from oil and gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded.
Oil and natural gas properties	'
	Oil and natural gas properties
	We utilize the successful efforts method of accounting for our oil and natural gas properties. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs relating to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis.
	Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned.
	Costs of significant nonproducing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depreciation until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented.
	Impairment of Long-Lived Assets
	We review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. The impairment provision is based on the excess of carrying value over fair value. Fair value is defined as the present value of the estimated future net revenues from production of total proved and risk-adjusted probable and possible oil and gas reserves over the economic life of the reserves based on our expectations of future oil and gas prices and costs. We review our oil and gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base.
	For the year ended December 31, 2013 and 2012, we recorded non-cash impairment charges of approximately $1.6 million and $1.3 million, respectively, related to our producing properties within our miscellaneous core areas. For the year ended December 31, 2011 no impairment charge was recorded. These non-cash charges are included in "impairment of proved oil and natural gas properties” line item in the accompanying consolidated statements of operations. The fair value of the properties was measured by utilizing the estimated cash flow reported in the audited reserve report. This report was adjusted for future oil and natural gas prices, which are based on observable inputs adjusted for basis differentials, which are Level 3 inputs in the fair value hierarchy described in Note 6. The fair values of proved properties are measured using valuation techniques consistent with the income approach, converting future cash flow to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and development costs, future commodity prices and market-based weighted average cost of capital rate. The underlying commodity prices embedded in our estimated cash flow are the product of a process that begins with New York Mercantile Exchange (“NYMEX”) forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that management believes will impact realizable prices. Furthermore, significant assumptions in valuing the proved reserves included the reserve quantities, anticipated drilling and operating costs, anticipated production taxes and future expected oil and natural gas prices. Cash flow estimates for the impairment testing excluded derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices. The impairments were caused by the decrease in reserves of our oil and natural gas properties in 2013 and 2012. These impairments have no impact on our cash flow, liquidity position, or debt covenants.
Other property and equipment	'
	Other property and equipment
	Other property and equipment is stated at historical cost and is comprised of software, vehicles, office equipment, and field service equipment. Costs incurred for normal repairs and maintenance are charged to expense as incurred, unless they extend the useful life of the asset. Depreciation is calculated using the straight-line method based on estimated useful lives of the assets ranging from 3 to 15 years and is included in the accumulated depreciation, depletion and amortization totals.
Asset retirement obligations	'
	Asset retirement obligations
	We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These asset retirement obligations (“ARO”) are primarily associated with plugging and abandoning wells. Determining the future restoration and removal requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. We are required to record the fair value of a liability for an ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We typically incur this liability upon acquiring or drilling a well. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability.
	Inherent to the present value calculation are numerous estimates, assumptions and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the abandonment liability, management will make corresponding adjustments to both the ARO and the related oil and natural gas property asset balance. Increases in the discounted retirement obligation liability and related oil and natural gas assets resulting from the passage of time will be reflected as additional accretion and depreciation expense in the statements of operations.
Derivatives and hedging	'
	Derivatives and hedging
	Our risk management program is intended to reduce our exposure to commodity prices and to assist with stabilizing cash flows. Accordingly, we utilize derivative financial instruments to manage our exposure to commodity price fluctuations in location differences between published index prices and the NYMEX futures prices. These transactions are primarily in the form of either swaps with fixed settlements or collars (calls and puts). Our policies do not permit the use of derivatives for speculative or trading purposes.
	We do not designate commodity derivative contracts as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings as a non-cash gain or loss. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. Net settlement gains or losses on derivative contracts only arise from net payments made or received on monthly settlements or if a commodity derivative contract is terminated prior to its expiration. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of derivative financial instruments on a net basis by counterparty.
Other revenue and expense, net	'
	Other revenue and expense, net
	Prior to June 30, 2011, we received fees for the operation of jointly-owned oil and gas properties and recorded such reimbursements as reductions of other revenue and expense, net.
Equity-based compensation	'
	Equity-based compensation
	The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value of compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. Compensation expense for these awards is recorded upon vesting, based on their grant-date fair value. Generally, no compensation expense is recognized for equity instruments that do not vest.
Debt placement fee	'
	Debt placement fee
	Debt placement fees are stated at cost, net of amortization, which is computed using the straight-line method. At December 31, 2013 and 2012, net debt issuance costs of approximately $0.4 million and $0.7 million, respectively, are included in "other assets" on the consolidated balance sheets. When debt is retired before its scheduled maturity date, we write off any remaining issuance costs associated with that debt.
Income taxes	'
	Income taxes
	We are a partnership that is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, our taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Net income per limited partner unit	'
	Net income per limited partner unit
	Basic and diluted net income per limited partner unit is determined by dividing net income available to the limited partners, after deducting the general partner’s interest in net income, by the weighted average number of outstanding limited partner units during the period.
Business segment reporting	'
	Business segment reporting
	We operate in one reportable segment: the exploration, development and production of oil and natural gas properties. All of our operations are located in the United States.

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2013
Cushing Properties [Member]	'
Business Acquisition [Line Items]	'
Fair Values of Identifiable Assets and Liabilities	'
	Fair Value of net assets:
	Oil and natural gas properties	$	28,318
	Total assets acquired	$	28,318
	Fair Value of net liabilities assumed:
	Asset retirement obligation	906
	Net assets acquired	$	27,412
Clawson Ranch [Member]	'
Business Acquisition [Line Items]	'
Fair Values of Identifiable Assets and Liabilities	'
	The recognized fair values of the identifiable assets of the Clawson Ranch acquired and liabilities assumed in connection with the acquisition are as follows (in thousands):
	Fair Value of net assets:
	Oil and natural gas properties	$	29,105
	Total assets acquired	$	29,105
	Fair Value of net liabilities assumed:
	Asset retirement obligation	249
	Net assets acquired	$	28,856
Summary of Combined Statement of Operation	'
	The following table reflects pro forma revenues, net income and net income per limited partner unit for the years ended as if the Clawson Ranch acquisition had taken place on January 1, 2011. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future (in thousands):
		2012		2011
	Revenues	73,443		47,677
	Net income	32,112		22,408
	Net income per limited partner unit
	Basic and diluted	$	1.74	$	1.24

Equity_Awards_Tables

Equity Awards (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Number of existing awards and awards available under Long-Term Incentive Program	'
	The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2013:
			Number of Common Units
	Approved and authorized awards		1,764,000
	Unrestricted units granted, included vested units		(558,773	)
	Restricted units granted, net of forfeitures and vesting		(120,589	)
	Phantom units issued, net of forfeitures		(43,000	)
	Awards available for future grant		1,041,638
Summary of restricted units awarded	'
	A summary of our restricted units awarded for the years ended December 31, 2013 and 2012 is presented below:
	Restricted awards:	Number of Restricted Units			Average Grant Date Fair Value per Unit
	Outstanding at December 31, 2011	—
	Units granted	62,658			$21.26
	Units forfeited	(7,509	)		$21.45
	Restricted units outstanding at December 31, 2012	55,149
	Units granted	96,185			$23.86
	Units vested	(18,399	)		$21.24
	Units forfeited	(12,346	)		$22.13
	Outstanding at December 31, 2013	120,589
Phantom Share Units (PSUs) [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Activity related to phantom units	'
	Activity related to these phantom units is as follows:
			Number of Units
	Nonvested phantom units as of December 31, 2012		—
	Issued in July 2013		50,000
	Forfeited		(7,000	)
	Nonvested phantom units as of December 31, 2013		43,000

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Commodity Contracts	'
	At December 31, 2013 we had the following oil derivative open positions:
	Period Covered	Weighted			Weighted			Weighted			Total	NYMEX
		Average			Average			Average			Bbls	Index
		Fixed			Floor			Ceiling			Hedged/day
		Price			Price			Price
	Swaps - 2014	$	93.56								1,973
	Swaps - 2015	$	90.05								164
	Collars - 2015				$	85		$	95.13		123	WTI
	At December 31, 2012 we had the following oil derivative open positions:
	Period Covered	Weighted			Weighted			Weighted			Total	NYMEX
		Average			Average			Average			Bbls	Index
		Fixed			Floor			Ceiling			Hedged/day
		Price			Price			Price
	Swaps - 2013	$	98.26								1,545
	Collars - 2013				$	97.67		$	108.08		296	WTI
	Swaps - 2014	$	93.71								1,644
Estimated Fair Value of Derivative Asset and Liabilities	'
	The following tables summarizes the gross fair value by the appropriate balance sheet classification, even when the derivative instruments are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2013 and 2012 (in thousands):
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2013
	Assets
	Derivative financial instrument - current asset	$	541		$	388		$	153
	Derivative financial instrument - long-term asset	48			—			48
	Total	$	589		$	388		$	201
	Liabilities
	Derivative financial instrument - current liability	$	(2,015	)	$	(388	)	$	(1,627	)
	Derivative financial instrument - long-term liability	—			—			—
	Total	$	(2,015	)	$	(388	)	$	(1,627	)
	Net liability	$	(1,426	)	$	—		$	(1,426	)
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2012
	Assets
	Derivative financial instrument - current asset	$	3,843		$	—		$	3,843
	Derivative financial instrument - long-term asset	1,486			346			1,140
	Total	$	5,329		$	346		$	4,983
	Liabilities
	Derivative financial instrument - current liability	$	(164	)	$	—		$	(164	)
	Derivative financial instrument - long-term liability	(628		)	(346		)	(282		)
	Total	$	(792	)	$	(346	)	$	(446	)
	Net asset	$	4,537		—			$	4,537
Impact of Derivative Financial Instruments within Consolidated Statement of Operations	'
	The following table summarizes the gains and losses reported in earnings related to the commodity derivative financial instruments within the consolidated statements of operations:
		December 31,
		2013			2012			2011
	Net settlements on derivatives	$	288		$	3,710		$	(2,157	)
	Gain (loss) on unsettled derivatives, net	(5,963		)	2,004			3,437
	Total gain (loss) on derivatives, net	$	(5,675	)	$	5,714		$	1,280

Fair_Value_Disclosures_Tables

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Assets and Liabilities Measured at Fair Value on Recurring Basis	'
	The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2013 and 2012:
		Level 1		Level 2			Level 3
		(in thousands)
	December 31, 2013
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	201		$	—
	Derivative financial instruments- liability	—		$	1,627		—
	Net financial assets	$	—	$	(1,426	)	$	—
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Asset retirement obligations	$	—	$	—		$	879
	Impairment of proved oil and gas properties	$	—	$	—		$	1,578
	31-Dec-12
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	4,983		$	—
	Derivative financial instruments- liability	—		446			—
	Net financial assets	$	—	$	4,537		$	—
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Asset retirement obligations	$	—	$	—		$	845
	Impairment of proved oil and gas properties	$	—	$	—		$	1,296

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Changes in Asset Retirement Obligations	'
	Changes in our ARO obligations for the periods indicated are presented in the following table:
		Years Ended December 31,
		2013			2012		2011
		(in thousands)
	Asset retirement obligation - beginning of period	$	2,890		$	1,919	$	2,148
	Liabilities incurred for new wells and interest	1,009			636		370
	Disposition of wells	—			—		(1,024		)
	Revision of estimates	(130		)	209		347
	Accretion expense	173			126		78
	Asset retirement obligation - end of period	$	3,942		$	2,890	$	1,919

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Equity [Abstract]	'
Cash distributions	'
	The following sets forth the distributions we paid during the years ended December 31, 2013 and 2012:
			Distribution		Total
	Date Paid	Period Covered	per Unit		Distribution
	February 14, 2013	October 1, 2012 - December 31, 2012	$	0.495	$	9,697
	May 14, 2013	January 1, 2013 - March 31, 2013	0.505		9,891
	August 14, 2013	April 1, 2013 - June 30, 2013	0.515		10,123
	November 14, 2013	July 1, 2013 - September 30, 2013	0.515		10,119
					$	39,830
	February 13, 2012	December 21, 2011 - December 31, 2012	$	0.057	$	1,034	-1
	May 14, 2012	January 1, 2012 - March 31, 2012	0.475		8,622
	August 14, 2012	April 1, 2012 - June 30, 2012	0.475		8,692
	November 14, 2012	July 1, 2012 - September 30, 2012	0.485		9,357
					$	27,705
	-1	The distribution represented a proration of initial quarterly distribution of $0.475 per unit.

Supplementary_Information_Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Schedule of Quarterly Data	'
	Quarterly data (unaudited)
		Quarters Ended
		March 31				June 30				September 30			December 31
		(In thousands, except per unit amounts)
	2013
	Oil and natural gas sales	$	20,176			$	21,110			$	22,982		$	21,468
	Net settlements on derivatives	673				709				(1,293		)	199
	Gain (loss) on unsettled derivatives, net	(1,793		)		960				(5,501		)	371
	Total revenues and other	19,056				22,779				16,188			22,038
	Total expenses (1)	14,997				12,241				11,931			12,703
	Net income	4,059				10,538				4,257			9,335
	Limited partners' interest in net income	3,985				10,344				4,179			9,163
	Net income per limited partner unit (basic)	$	0.21			$	0.54			$	0.22		$	0.47
	Net income per limited partner unit (diluted)	$	0.21			$	0.54			$	0.22		$	0.47
	2012
	Oil and natural gas sales	$	15,507			$	13,844			$	15,048		$	17,162
	Net settlements on derivatives	(134		)		903				1,211			1,730
	Gain (loss) on unsettled derivatives, net	(4,773		)		14,514				(6,103		)	(1,634		)
	Total revenues and other	10,600				29,261				10,156			17,258
	Total expenses (1)	8,938				6,833				11,293			10,349
	Net income (loss)	1,662				22,428				(1,137		)	6,909
	Limited partners' interest in net income (loss)	1,629				21,984				(1,115		)	6,774
	Net income (loss) per limited partner unit (basic)	$	0.09			$	1.23			$	(0.06	)	$	0.36
	Net income (loss) per limited partner unit (diluted)	$	0.09			$	1.23			$	(0.06	)	$	0.36
	-1	Includes the following expenses: lease operating, production taxes, dry holes and abandonments, geological and geophysical, depreciation, depletion and amortization, accretion, and general and administrative.
Supplementary Oil and Natural Gas Activities	'
	Supplementary oil and natural gas activities
		Year Ended December 31,
		2013				2012				2011
		(in thousands)
	Property acquisition costs:
	Proved	$	28,057			$	48,578			$	15,729
	Unproved	—				—				—
	Exploration	—				—				—
	Development	22,287				21,639				30,754
	Asset retirement obligations	879				679				686
	Total costs incurred	$	51,223			$	70,896			$	47,169
Changes in Estimated Proved Oil and Natural Gas Reserves	'
	An analysis of the change in estimated quantities of oil and gas reserves, all of which are located within the United States, are presented below for the periods indicated:
		Oil			Gas			MBoe (1)
		(MBbls)			(MMcf)
	Proved developed and undeveloped reserves:
	As of December 31, 2010	7,007			1,346			7,231
	Revisions of previous estimates	740			(370	)		678
	Extensions, discoveries and other additions	1,704			—			1,704
	Purchases of minerals in place	971			140			994
	Sales of minerals in place	(79	)		(276	)		(124	)
	Production	(407	)		(164	)		(434	)
	As of December 31, 2011	9,936			676			10,049
	Revisions of previous estimates	(784	)		(143	)		(808	)
	Extensions, discoveries and other additions	1,572			—			1,572
	Purchases of minerals in place	3,028			18			3,031
	Production	(678	)		(122	)		(698	)
	As of December 31, 2012	13,074			429			13,146
	Revisions of previous estimates	264			827			401
	Extensions, discoveries and other additions	76			—			76
	Purchases of minerals in place	1,207			193			1,239
	Production	(907	)		(128	)		(928	)
	As of December 31, 2013	13,714			1,321			13,934
	Proved developed reserves:
	December 31, 2010	3,601			1,346			3,825
	December 31, 2011	6,835			676			6,948
	December 31, 2012	8,727			429			8,799
	31-Dec-13	10,397			1,321			10,617
	Proved undeveloped reserves:
	December 31, 2010	3,406			—			3,406
	December 31, 2011	3,101			—			3,101
	December 31, 2012	4,347			—			4,347
	31-Dec-13	3,317			—			3,317
Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves	'
	The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated:
		Year Ended December 31,
		2013				2012				2011
		(in thousands)
	Future cash inflows	$	1,295,435			$	1,191,410			$	930,788
	Future production costs	(542,389		)		(417,362		)		(297,490		)
	Future development costs, including abandonment costs	(49,458		)		(47,490		)		(34,504		)
	Future net cash flow	703,588				726,558				598,794
	10% discount for estimated timing of cash flow	(312,325		)		(323,136		)		(270,563		)
	Standardized measure of discounted cash flow	$	391,263			$	403,422			$	328,231
Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	'
	Changes in the standardized measure of discounted future net cash flow relating to proved oil and gas reserves is presented below for the periods indicated:
		Year Ended December 31,
		2013				2012				2011
	Standardized measure of discounted future net cash flow, beginning of period	$	403,422			$	328,231			$	183,662
	Changes in the year resulting from:
	Sales, less production costs	(65,553		)		(48,648		)		(27,671		)
	Revisions of previous quantity estimates	12,006				(26,796		)		26,960
	Extensions, discoveries and improved recovery	1,863				51,098				26,128
	Net change in prices and production costs	(28,324		)		(15,328		)		79,618
	Net change in income taxes	—				—				—
	Changes in estimated future development costs	(17,155		)		(11,515		)		(30,521		)
	Previously estimated development costs incurred during the period	22,257				21,629				31,968
	Purchases of minerals in place	38,170				81,602				20,200
	Accretion of discount	40,342				32,823				18,366
	Timing differences and other	(15,765		)		(9,674		)		(479		)
	Standardized measure of discounted future net cash flow, end of year	$	391,263			$	403,422			$	328,231

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Segment
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Number of operating segment	1	'	'
Impairment charges	$1,578,000	$1,296,000	$0
Impairment charge relates to our gas producing properties	'	1,100,000	'
Abandonment expenses	0	0	800,000
Reductions of other revenue and expense, net	'	'	2,100,000
Equity-based compensation expense	6,600,000	6,500,000	1,700,000
Non-cash equity based compensation	6,400,000	6,300,000	1,700,000
Debt placement fees, net of amortization	400,000	700,000	'
Number of reportable segments	1	'	'
Cash-based costs for employer taxes	200,000	200,000	'
Other property and equipment [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Depreciation expenses	$0	$0	$300,000
Minimum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Useful life of asset	'3 years	'	'
Maximum [Member]	'	'	'
Summary Of Significant Accounting Policies [Line Items]	'	'	'
Useful life of asset	'15 years	'	'

Acquisitions_Additional_Inform

Acquisitions - Additional Information (Detail) (USD $)	1 Months Ended
In Millions, unless otherwise specified	31-May-13	Jun. 30, 2012	Oct. 31, 2012	Nov. 30, 2012	Dec. 31, 2011
	Cushing Properties [Member]	Northern and southern Oklahoma core area [Member]	Hugoton Basin [Member]	Clawson Ranch [Member]	Clawson Ranch [Member]
Business Acquisition [Line Items]	'	'	'	'	'
Aggregate Consideration for acquired properties	$27.40	$16.40	$3.70	$28.90	'
Percentage of working interest acquired	'	'	'	100.00%	'
Percentage of acquisition to total assets	'	'	'	'	30.00%

Acquisitions_Components_of_Pur

Acquisitions - Components of Purchase Price Allocation (Detail) (USD $)	31-May-13	Nov. 30, 2012
In Thousands, unless otherwise specified	Cushing Properties [Member]	Clawson Ranch [Member]
Fair Value of net assets:	'	'
Oil and gas properties	$28,318	$29,105
Total assets acquired	28,318	29,105
Fair Value of net liabilities assumed:	'	'
Asset retirement obligation	906	249
Net assets acquired	$27,412	$28,856

Acquisitions_Summary_of_Combin

Acquisitions - Summary of Combined Statement of Operation (Detail) (Clawson Ranch [Member], USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Clawson Ranch [Member]	'	'
Business Acquisition [Line Items]	'	'
Revenues	$73,443	$47,677
Net income	$32,112	$22,408
Net income per limited partner unit: Basic and diluted	$1.74	$1.24

Equity_Awards_Additional_Infor

Equity Awards - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Approved and authorized awards	1,764,000	'	'
Equity-based compensation expense	$6.60	$6.50	$1.70
Restricted Common Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period	'3 years	'	'
Forfeiture restricted unit rate	10.00%	'	'
Average grant date fair value per unit	$23.86	$21.26	'
Phantom Share Units (PSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Vesting period	'3 years	'	'
Forfeiture restricted unit rate	10.00%	'	'
Equity-based compensation expense	0.1	'	'
Unrecognized compensation costs	0.6	'	'
Weighted average period over which the unrecognized cost are expected to be recognized	'2 years 6 months	'	'
Restricted and Unrestricted common units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Average grant date fair value per unit	$22.89	'	'
Nonvested Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Unrecognized compensation costs	$1.90	'	'
Weighted average period over which the unrecognized cost are expected to be recognized	'2 years 1 month 12 days	'	'
Long-Term Incentive Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Approved and authorized awards	1,764,000	'	'

Equity_Awards_Awards_Available

Equity Awards - Awards Available for Future Grant (Details)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Approved and authorized awards	1,764,000	'	'
Awards available for future grant	1,041,638	'	'
Restricted Common Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Units granted, net of forfeitures and vesting	-120,589,000	-55,149,000	0
Phantom Share Units (PSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Units granted, net of forfeitures and vesting	-43,000,000	0	'
Long-Term Incentive Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Approved and authorized awards	1,764,000	'	'
Unrestricted units granted, included vested units	-558,773	'	'
Awards available for future grant	1,041,638	'	'
Long-Term Incentive Plan [Member] | Restricted Common Units [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Units granted, net of forfeitures and vesting	-120,589	'	'
Long-Term Incentive Plan [Member] | Phantom Share Units (PSUs) [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Units granted, net of forfeitures and vesting	-43,000	'	'

Equity_Awards_Restricted_Units

Equity Awards - Restricted Units (Details) (Restricted Common Units [Member], USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Restricted Common Units [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'
Outstanding, beginning of period	55,149,000	0
Units granted	96,185,000	62,658,000
Units vested	-18,399,000	'
Units forfeited	-12,346,000	-7,509,000
Outstanding, end of period	120,589,000	55,149,000
Average grant date fair value per unit, granted	$23.86	$21.26
Average grant date fair value per unit, vested	$21.24	'
Average grant date fair value per unit, forfeited	$22.13	$21.45

Equity_Awards_Equity_Awards_Ph

Equity Awards Equity Awards - Phantom Units (Details) (Phantom Share Units (PSUs) [Member])	12 Months Ended
	Dec. 31, 2013
Phantom Share Units (PSUs) [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'
Outstanding, beginning of period	0
Number of units issued	50,000,000
Units forfeited	-7,000,000
Outstanding, end of period	43,000,000

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Additional Information (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Estimated fair value of derivative contracts, net asset (liability)	($1,426)	$4,537

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Commodity Contract (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
	Bbls	Bbls
Swaps [Member] | Period Covered-2013 [Member]	'	'
Derivative [Line Items]	'	'
Weighted Average Fixed Price	'	98.26
Total Bbls Hedged/day	'	1,545
Swaps [Member] | Period Covered-2014 [Member]	'	'
Derivative [Line Items]	'	'
Weighted Average Fixed Price	93.56	93.71
Total Bbls Hedged/day	1,973	1,644
Swaps [Member] | Period Covered-2015 [Member]	'	'
Derivative [Line Items]	'	'
Weighted Average Fixed Price	90.05	'
Total Bbls Hedged/day	164	'
Collars [Member] | Period Covered-2013 [Member]	'	'
Derivative [Line Items]	'	'
Weighted Average Floor Price	'	97.67
Weighted Average Ceiling Price	'	108.08
Total Bbls Hedged/day	'	296
NYMEX Index	'	'WTI
Collars [Member] | Period Covered-2015 [Member]	'	'
Derivative [Line Items]	'	'
Weighted Average Floor Price	85	'
Weighted Average Ceiling Price	95.13	'
Total Bbls Hedged/day	123	'
NYMEX Index	'WTI	'

Derivative_Financial_Instrumen4

Derivative Financial Instruments - Summary of Grosss Fair Value by Approprtiate Balance Sheet Classification (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets [Abstract]	'	'
Gross amounts of recognized assets	$589	$5,329
Gross amounts offset in the Consolidated Balance Sheet	388	346
Net financial assets	201	4,983
Liabilities [Abstract]	'	'
Gross amounts of recognized liabilities	-2,015	-792
Gross amounts offset in the Consolidated Balance Sheet	-388	-346
Net financial liabilities	-1,627	-446
Gross amounts of recognized assets and liabilities	-1,426	4,537
Gross amounts offset in the Consolidated Balance Sheet	0	0
Net amounts presented in the Consolidated Balance Sheet	-1,426	4,537
Current Asset [Member]	'	'
Assets [Abstract]	'	'
Gross amounts of recognized assets	541	3,843
Gross amounts offset in the Consolidated Balance Sheet	388	0
Net financial assets	153	3,843
Long Term Asset [Member]	'	'
Assets [Abstract]	'	'
Gross amounts of recognized assets	48	1,486
Gross amounts offset in the Consolidated Balance Sheet	0	346
Net financial assets	48	1,140
Current Liability [Member]	'	'
Liabilities [Abstract]	'	'
Gross amounts of recognized liabilities	-2,015	-164
Gross amounts offset in the Consolidated Balance Sheet	-388	0
Net financial liabilities	-1,627	-164
Long Term Liability [Member]	'	'
Liabilities [Abstract]	'	'
Gross amounts of recognized liabilities	0	-628
Gross amounts offset in the Consolidated Balance Sheet	0	-346
Net financial liabilities	$0	($282)

Derivative_Financial_Instrumen5

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Consolidated Statement of Operations (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'	'	'	'	'	'	'	'	'	'
Net settlements on derivatives	$199	($1,293)	$709	$673	$1,730	$1,211	$903	($134)	$288	$3,710	($2,157)
Gain (loss) on unsettled derivatives, net	371	-5,501	960	-1,793	-1,634	-6,103	14,514	-4,773	-5,963	2,004	3,437
Total gain (loss) on derivatives, net	'	'	'	'	'	'	'	'	($5,675)	$5,714	$1,280

Fair_Value_Disclosures_Additio

Fair Value Disclosures - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value Disclosures [Abstract]	'	'	'
Impairment charges	$1,578,000	$1,296,000	$0
Impairment charge relates to our gas producing properties	'	$1,100,000	'

Fair_Value_Disclosures_Assets_

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative financial instrument- asset	$589	$5,329
Derivative financial instrument - liability	1,627	446
Level 1 [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative financial instrument- asset	0	0
Derivative financial instrument - liability	0	0
Net financial assets	0	0
Level 1 [Member] | Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Asset retirement obligations	0	0
Impairment of proved oil and gas properties	0	0
Level 2 [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative financial instrument- asset	201	4,983
Derivative financial instrument - liability	1,627	446
Net financial assets	-1,426	4,537
Level 2 [Member] | Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Asset retirement obligations	0	0
Impairment of proved oil and gas properties	0	0
Level 3 [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Derivative financial instrument- asset	0	0
Derivative financial instrument - liability	0	0
Net financial assets	0	0
Level 3 [Member] | Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Asset retirement obligations	879	845
Impairment of proved oil and gas properties	$1,578	$1,296

Asset_Retirement_Obligations_C

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in ARO obligations	'	'	'
Asset retirement obligation - beginning of period	$2,890	$1,919	$2,148
Liabilities incurred for new wells and interests	1,009	636	370
Disposition of wells	0	0	-1,024
Revision of estimates	-130	209	347
Accretion expense	173	126	78
Asset retirement obligation - end of period	$3,942	$2,890	$1,919

Debt_Additional_Information_De

Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Nov. 30, 2013	Apr. 30, 2013	Apr. 30, 2012
Line of Credit Facility [Line Items]	'	'	'	'
Line of credit facility, maximum borrowing capacity	$250,000,000	'	'	'
Senior secured revolving facility, expiring date	5-Nov-18	'	'	'
Borrowings under the facility secured by liens	'not less than 80%	'	'	'
Borrowings under the facility secured by liens, percent of assets	80.00%	'	'	'
Revolving credit facility borrowings, outstanding	112,000,000	'	'	'
Minimum current ratio required under credit facility	1	'	'	'
Line of credit facility, borrowing capacity	150,000,000	150,000,000	130,000,000	130,000,000
Financing fees and expenses	$400,000	'	'	'
Average effective rate	2.70%	'	'	'
Maximum [Member]	'	'	'	'
Line of Credit Facility [Line Items]	'	'	'	'
Leverage ratio required under credit facility	4.00%	'	'	'
Margin	1.75%	'	'	'
Unused portion of borrowing base, percentage fee	0.50%	'	'	'
Minimum [Member]	'	'	'	'
Line of Credit Facility [Line Items]	'	'	'	'
Margin	0.75%	'	'	'
Unused portion of borrowing base, percentage fee	0.38%	'	'	'
Federal Funds Effective Rate [Member]	'	'	'	'
Line of Credit Facility [Line Items]	'	'	'	'
Federal fund effective rate	0.50%	'	'	'
LIBOR [Member]	'	'	'	'
Line of Credit Facility [Line Items]	'	'	'	'
Federal fund effective LIBOR	1.00%	'	'	'
LIBOR [Member] | Maximum [Member]	'	'	'	'
Line of Credit Facility [Line Items]	'	'	'	'
Applicable margin rate	2.75%	'	'	'
LIBOR [Member] | Minimum [Member]	'	'	'	'
Line of Credit Facility [Line Items]	'	'	'	'
Applicable margin rate	1.75%	'	'	'

Commitment_and_Contingencies_A

Commitment and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Commitments Contingencies And Litigation [Line Items]	'
Employment Agreements Expiration Date	1-Aug-14
Employment Agreements [Member]	'
Commitments Contingencies And Litigation [Line Items]	'
Employment Agreements Beginning Date	1-Aug-11
Minimum [Member]	'
Commitments Contingencies And Litigation [Line Items]	'
Employee Agreement Termination Payments	1.6
Maximum [Member]	'
Commitments Contingencies And Litigation [Line Items]	'
Employee Agreement Termination Payments	1.9

Equity_Additional_Information_

Equity - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended			1 Months Ended		0 Months Ended
	Oct. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Oct. 31, 2012	Oct. 31, 2012	Jan. 22, 2014
					Mid Con Energy Partners [Member]	Yorktown [Member]	Subsequent Event [Member]
Equity [Line Items]	'	'	'	'	'	'	'
Owners Equity	'	19,319,362	18,990,849	'	'	'	'
Limited partnership interest	'	98.00%	'	'	'	'	'
Sale of common units	4,600,000	'	'	'	1,000,000	3,600,000	'
Sale of units per unit	21.2	'	'	'	'	'	'
Proceeds from sale of common units	'	$0	$20,352,000	$1,972,000	$20,400,000	$0	'
Cash distribution for the fourth quarter	'	'	'	'	'	'	$0.52
Distribution to holders	'	'	'	'	'	'	$10,300,000

Equity_Cash_Distributions_Deta

Equity - Cash Distributions (Detail) (USD $)	0 Months Ended									12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Nov. 14, 2013	Aug. 14, 2013	14-May-13	Feb. 14, 2013	Nov. 14, 2012	Aug. 14, 2012	14-May-12	Feb. 13, 2012		Dec. 31, 2013	Dec. 31, 2012
Equity [Abstract]	'	'	'	'	'	'	'	'		'	'
Date Paid	14-Nov-13	14-Aug-13	14-May-13	14-Feb-13	14-Nov-12	14-Aug-12	14-May-12	13-Feb-12		'	'
Period Covered	'July 1, 2013 - September 30, 2013	'April 1, 2013 - June 30, 2013	'January 1, 2013 - March 31, 2013	'October 1, 2012 - December 31, 2012	'July 1, 2012 - September 30, 2012	'April 1, 2012 - June 30, 2012	'January 1, 2012 - March 31, 2012	'December 21, 2011 - December 31, 2012		'	'
Distribution per Unit	$0.52	$0.52	$0.51	$0.50	$0.49	$0.48	$0.48	$0.06		'	'
Total Distribution	$10,119	$10,123	$9,891	$9,697	$9,357	$8,692	$8,622	$1,034	[1]	$39,830	$27,705
[1]	The distribution represented a proration of initial quarterly distribution of $0.475 per unit.

Equity_Cash_Distributions_Pare

Equity - Cash Distributions (Parenthetical) (Detail) (USD $)	0 Months Ended
	Feb. 14, 2013
Equity [Abstract]	'
Initial Quarterly distribution	$0.48

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 20, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
		Mid-Con Energy Operating [Member]	Mid-Con Energy Operating [Member]	Mid-Con Energy Operating [Member]
Related Party Transaction [Line Items]	'	'	'	'
Direct administrative expenses incurred and reimbursed to related party	'	$3.60	$2.90	$0.20
Payment for consideration	6	'	'	'
General partner interest	2.00%	'	'	'
Other transactions of related party	'	3	3	'
Payment of joint interest billing	'	2.2	2.2	'
Payment of operating services	'	$0.80	$0.80	'

Credit_Risk_Additional_Informa

Credit Risk - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Minimum [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Revenue derived by customers as percentage of consolidated total revenue	10.00%	10.00%	10.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Enterprise [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	50.00%	32.00%	'
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Coffeyville [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	23.00%	'	'
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Valero [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	9.00%	'	'
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | National [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	8.00%	'	'
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Vitol Inc [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	28.00%	'
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Sunoco Logistics [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	21.00%	86.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | ScissorTail Energy, LLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	'	9.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Teppco Crude Oil, LLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	'	3.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Enterprise [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	46.00%	'	'
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Coffeyville [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	30.00%	'	'
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Valero [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	7.00%	'	'
Accounts Receivable [Member] | Customer Concentration Risk [Member] | National [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	10.00%	'	'
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Vitol Inc [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	52.00%	'
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Sunoco Logistics [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	'	88.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | ScissorTail Energy, LLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	'	2.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Teppco Crude Oil, LLC [Member]	'	'	'
Concentration Risk [Line Items]	'	'	'
Concentration risk, percentage	'	'	9.00%

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail)	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Maximum number of common units awarded	1,764,000
Units available for Issuance	1,041,638

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (Subsequent Event [Member], USD $)	0 Months Ended
In Millions, except Share data, unless otherwise specified	Feb. 28, 2014	Jan. 22, 2014
Subsequent Event [Member]	'	'
Subsequent Event [Line Items]	'	'
Cash distribution for the fourth quarter	'	$0.52
Cash distribution on annualized basis	'	$2.06
Distribution to unitholders	'	$10.30
Common units authorized for issuance to certain employees, directors, and founders	'	247,050
Total consideration transferred	41	'
Number of limited partner units issued	1,500,000	'
Period of weighted average price	'20 days	'
Weighted average price adjustment	2.50%	'
Value of limited partner units issued	34	'
Consideration paid in cash	$7	'

Supplementary_Information_Sche

Supplementary Information - Schedule of Quarterly Data (Detail) (USD $)	1 Months Ended	3 Months Ended												11 Months Ended	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Nov. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'		'		'		'		'	'	'	'	'	'	'	'
Oil and natural gas sales	'	$21,468		$22,982		$21,110		$20,176		$17,162	$15,048	$13,844	$15,507	'	'	'	'
Net settlements on derivatives	'	199		-1,293		709		673		1,730	1,211	903	-134	'	288	3,710	-2,157
Gain (loss) on unsettled derivatives, net	'	371		-5,501		960		-1,793		-1,634	-6,103	14,514	-4,773	'	-5,963	2,004	3,437
Total revenues	'	22,038		16,188		22,779		19,056		17,258	10,156	29,261	10,600	'	80,061	67,275	39,311
Total expenses	'	12,703	[1]	11,931	[1]	12,241	[1]	14,997	[1]	10,349	11,293	6,833	8,938	'	48,599	35,659	22,178
Net income (loss)	1,041	9,335		4,257		10,538		4,059		6,909	-1,137	22,428	1,662	17,927	28,189	29,862	18,968
Limited partners' interest in net income (loss)	'	$9,163		$4,179		$10,344		$3,985		$6,774	($1,115)	$21,984	$1,629	'	$27,671	$29,278	$18,589
Net income (loss) per limited partner unit (basic)	'	$0.47		$0.22		$0.54		$0.21		$0.36	($0.06)	$1.23	$0.09	'	$1.44	$1.62	$1.05
Net income (loss) per limited partner unit (diluted)	'	$0.47		$0.22		$0.54		$0.21		$0.36	($0.06)	$1.23	$0.09	'	$1.44	$1.62	$1.05
[1]	Includes the following expenses: lease operating, production taxes, dry holes and abandonments, geological and geophysical, depreciation, depletion and amortization, accretion, and general and administrative.

Supplementary_Information_Supp

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property acquisition costs:	'	'	'
Proved	$28,057	$48,578	$15,729
Unproved	0	0	0
Exploration	0	0	0
Development	22,287	21,639	30,754
Asset retirement obligations	879	679	686
Total costs incurred	$51,223	$70,896	$47,169

Supplementary_Information_Chan

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
	MBbls		MBbls		MMcf		MBbls
	MMcf		MMcf		MBoe		MBoe
	MBoe		MBoe		MBbls		MMcf
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]	'		'		'		'
Beginning balance, Oil	13,074		9,936		7,007		'
Revisions of previous estimates	264		-784		740		'
Extensions, discoveries and other additions, Oil	76		1,572		1,704		'
Purchases of minerals in place, Oil	1,207		3,028		971		'
Sales of minerals in place, Oil	'		'		-79		'
Production, Oil	-907		-678		-407		'
Ending balance, Oil	13,714		13,074		9,936		'
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]	'		'		'		'
Beginning balance, Gas	429		676		1,346		'
Revisions of previous estimates Gas	827		-143		-370		'
Extensions, discoveries and other additions, Gas	0		0		0		'
Purchases of minerals in place, Gas	193		18		140		'
Sales of minerals in place, Gas	'		'		-276		'
Production, Gas	-128		-122		-164		'
Ending balance, Gas	1,321		429		676		'
Proved Developed and Undeveloped Reserves, Oil and Gas Reserves [Roll Forward]	'		'		'		'
Beginning balance	13,146	[1]	10,049	[1]	7,231	[1]	'
Revisions of previous estimates	401	[1]	-808	[1]	678	[1]	'
Extensions, discoveries and other additions	76	[1]	1,572	[1]	1,704	[1]	'
Purchases of minerals in place	1,239	[1]	3,031	[1]	994	[1]	'
Sales of minerals in place	'		'		-124	[1]	'
Production	-928	[1]	-698	[1]	-434	[1]	'
Ending balance	13,934	[1]	13,146	[1]	10,049	[1]	'
Proved developed reserves, Oil	10,397		8,727		6,835		3,601
Proved undeveloped reserves, Oil	3,317		4,347		3,101		3,406
Proved developed reserves, Gas	1,321		429		676		1,346
Proved undeveloped reserves, Gas	0		0		0		0
Proved developed reserves	10,617	[1]	8,799	[1]	6,948	[1]	3,825	[1]
Proved undeveloped reserves	3,317	[1]	4,347	[1]	3,101	[1]	3,406	[1]
[1]	Estimated quantities of oil and natural gas reserves in Mboe equivalents at a rate of six Mcf per Bbl.

Supplementary_Information_Stan

Supplementary Information - Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Extractive Industries [Abstract]	'	'	'
Future cash inflows	$1,295,435	$1,191,410	$930,788
Future production costs	-542,389	-417,362	-297,490
Future development costs, including abandonment costs	-49,458	-47,490	-34,504
Future net cash flow	703,588	726,558	598,794
10% discount for estimated timing of cash flow	-312,325	-323,136	-270,563
Standardized measure of discounted cash flow	$391,263	$403,422	$328,231

Supplementary_Information_Chan1

Supplementary Information - Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Changes in the year resulting from:	'	'	'
Standardized measure of discounted future net cash flow, beginning of period	$403,422	$328,231	$183,662
Sales, less production costs	-65,553	-48,648	-27,671
Revisions of previous quantity estimates	12,006	-26,796	26,960
Extensions, discoveries and improved recovery	1,863	51,098	26,128
Net change in prices and production costs	-28,324	-15,328	79,618
Net change in income taxes	0	0	0
Changes in estimated future development costs	-17,155	-11,515	-30,521
Previously estimated development costs incurred during the period	22,257	21,629	31,968
Purchases of minerals in place	38,170	81,602	20,200
Accretion of discount	40,342	32,823	18,366
Timing differences and other	-15,765	-9,674	-479
Standardized measure of discounted future net cash flow, end of year	$391,263	$403,422	$328,231

Supplementary_Information_Addi

Supplementary Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Estimated quantities of oil and natural gas reserves, rate	6	'	'
Future net cash flows, annual discount rate	10.00%	'	'
Oil [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Prices utilized in calculating proved reserves	96.78	94.71	96.19
Average adjusted prices utilized in calculating proved reserves	93.98	91.03	93.2
Gas [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Prices utilized in calculating proved reserves	3.67	2.75	4.11
Average adjusted prices utilized in calculating proved reserves	5	2.87	7.04