Mid-Con Energy Partners (MCEP) 10-K 3 Mar 15 2014 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, 2014	Mar. 03, 2015	Jun. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	Mid-Con Energy Partners, LP
Entity Central Index Key	1527709
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
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		29,657,167
Entity Public Float			$307.70
General Partner Units [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		360,000

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
CURRENT ASSETS:
Cash and cash equivalents	$3,232	$1,434
Accounts receivable:
Oil and natural gas sales	8,051	6,778
Other	4,070	104
Derivative financial instruments	26,202	153
Prepaids and other	652	191
Total current assets	42,207	8,660
Oil and natural gas properties, successful efforts method:
Proved properties	501,191	216,680
Accumulated depletion, depreciation, amortization and impairment	-93,896	-36,148
Total property and equipment, net	407,295	180,532
DERIVATIVE FINANCIAL INSTRUMENTS	842	48
OTHER ASSETS	4,284	843
Total assets	454,628	190,083
Accounts payable:
Trade	3,630	2,184
Related parties	3,989	2,982
Derivative financial instruments	0	1,627
Accrued liabilities	397	432
Total current liabilities	8,016	7,225
OTHER LONG-TERM LIABILITIES	107	128
LONG-TERM DEBT	205,000	112,000
ASSET RETIREMENT OBLIGATIONS	7,363	3,942
COMMITMENTS AND CONTINGENCIES
Partnership equity:
General partner interest	1,328	1,716
Limited partners-29,166,112 and 19,319,362 units issued and outstanding as of December 31, 2014 and 2013, respectively	232,814	65,072
Total equity	234,142	66,788
Total liabilities and equity	$454,628	$190,083

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical)	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Limited partners, units issued	29,166,112	19,319,362
Limited partners, units outstanding	29,166,112	19,319,362

Consolidated_Statements_of_Ope

Consolidated Statements of Operations (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Oil sales	$96,127	$85,080	$60,887
Natural gas sales	784	656	674
Net settlements on derivatives	891	288	3,710
Gain (loss) on unsettled derivatives, net	28,470	-5,963	2,004
Total revenues	126,272	80,061	67,275
Operating costs and expenses:
Lease operating expenses	26,091	16,366	10,948
Oil and natural gas production taxes	6,325	3,817	1,965
Impairment of proved oil and natural gas properties	30,206	1,578	1,296
Depreciation, depletion and amortization	21,877	14,421	10,324
Accretion of discount on asset retirement obligations	250	173	126
General and administrative	14,313	12,244	11,000
Total operating costs and expenses	99,062	48,599	35,659
Income from operations	27,210	31,462	31,616
Other income (expense):
Interest income and other	13	9	10
Interest expense	-4,731	-3,282	-1,764
Total other income (expense)	-4,718	-3,273	-1,754
Net income	22,492	28,189	29,862
Computation of net income per limited partner unit:
General partners' interest in net income	354	518	584
Limited partners' interest in net income	$22,138	$27,671	$29,278
Net income per limited partner unit
Basic (in dollars per share)	$0.98	$1.44	$1.62
Diluted (in dollars per share)	$0.98	$1.44	$1.62
Weighted average limited partner units outstanding:
Limited partner units (basic)	22,499	19,234	18,049
Limited partner units (diluted)	22,518	19,249	18,049

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash Flows from Operating Activities:
Net income	$22,492	$28,189	$29,862
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	21,877	14,421	10,324
Debt issuance costs amortization	348	168	131
Accretion of discount on asset retirement obligations	250	173	126
Impairment of proved oil and natural gas properties	30,206	1,578	1,296
(Gain) loss on unsettled derivative instruments, net	-28,470	5,963	-2,004
Non-cash equity-based compensation	7,394	6,376	6,323
Changes in operating assets and liabilities:
Accounts receivable	-1,273	-365	-1,395
Other receivables	-3,966	499	-603
Prepaids and other	-461	-526	2,159
Accounts payable and accrued liabilities	2,067	158	1,498
Net cash provided by operating activities	50,464	56,634	47,717
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	-33,969	-22,366	-23,960
Acquisitions of oil and natural gas properties	-155,354	-28,057	-48,579
Net cash used in investing activities	-189,323	-50,423	-72,539
Cash Flows from Financing Activities:
Proceeds from line of credit	168,000	105,000	80,800
Payments on line of credit	-75,000	-71,000	-47,800
Issuance of common units	-44,564	-39,830	-27,705
Payments of Debt Issuance Costs	-3,789	0	0
Debt issuance costs	96,010	0	20,352
Net cash provided by (used in) financing activities	140,657	-5,830	25,647
Net increase in cash and cash equivalents	1,798	381	825
Beginning cash and cash equivalents	1,434	1,053	228
Ending cash and cash equivalents	3,232	1,434	1,053
Supplemental Cash Flow Information:
Cash paid for interest	4,600	2,803	1,561
Non-Cash Investing and Financing Activities:
Accrued capital expenditures - oil and natural gas properties	1,277	926	1,005
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	$86,001	$0	$0

Consolidated_Statements_of_Cha

Consolidated Statements of Changes in Equity (USD $)	Total	General Partner [Member]	Limited Partner [Member]
Balance at Nov. 30, 2011
Combination transaction with Mid-Con Energy I, LLC and Mid-Con Energy II, LLC		$1,299,000	$42,050,000
Issuance of common units in initial public offering			6,204,000
Distributions			-19,974,000
Net income		555,000	29,307,000
Balance, Units at Dec. 31, 2011			17,640
Balance at Dec. 31, 2011	43,349,000
Debt issuance costs	20,352,000
Distributions	-27,705,000	-537,000	-27,168,000
Equity-based compensation	6,323,000	119,000
Sale of common units, units			1,000
Partners' Capital Account, Acquisitions	20,352,000
Equity-based compensation, Units			351
Issuance of common units		378,000
Net income	29,862,000
Balance at Dec. 31, 2012	72,181,000	1,814,000	70,367,000
Balance, Units at Dec. 31, 2012			18,991
Debt issuance costs	0
Distributions	-39,830,000	-731,000	-39,099,000
Equity-based compensation	6,248,000	115,000	6,133,000
Partners' Capital Account, Acquisitions	0
Equity-based compensation, Units			328
Issuance of common units		0	0
Issuance of common units, Units			0
Net income	28,189,000	518,000	27,671,000
Balance at Dec. 31, 2013	66,788,000	1,716,000	65,072,000
Balance, Units at Dec. 31, 2013			19,319
Debt issuance costs	96,010,000		96,010,000
Issuance of common units in initial public offering, Units			5,800
Distributions	-44,564,000	-742,000	-43,822,000
Equity-based compensation	7,415,000		7,415,000
Partners' Capital Account, Units, Acquisitions			3,715
Partners' Capital Account, Acquisitions	86,001,000		86,001,000
Equity-based compensation, Units			332
Net income	22,492,000	354,000	22,138,000
Balance at Dec. 31, 2014	$234,142,000	$1,328,000	$232,814,000
Balance, Units at Dec. 31, 2014			29,166

Organization_and_Nature_of_Ope

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2014
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 July 2011 that engages in the ownership, acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on enhanced oil recovery. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Our limited partner units ("common units") are traded on the NASDAQ Global Select Market under the symbol “MCEP.”

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2014, 2013 and 2012.
	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.
	We aggregate all of our oil and natural gas properties into one business segment engaged in the exploitation, development and production of oil and natural gas properties.
	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 natural gas properties which is determined using estimates of proved oil and natural 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 assets acquired and liabilities assumed in business combinations, fair value of derivative financial instruments, 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, 2014 and 2013, 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 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, 2014 or 2013.
	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 natural 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 natural 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, 2014, 2013 and 2012, we recorded non-cash impairment charges of approximately $30.2 million, $1.6 million, and $1.3 million, respectively, related to our oil and natural gas properties due to reduced recoverable reserve estimates due to a steep decline in commodity prices. These non-cash charges are included in "Impairment of proved oil and natural gas properties” line item in the accompanying consolidated statements of operations and "Accumulated depletion, depreciation, amortization and impairment" line item in the accompanying consolidated balance sheets. During 2014, we reclassified approximately $5.7 million of impairments recognized in periods prior to 2014 from the 'Proved properties" line item to the "Accumulated depletion, depreciation, amortization and impairment" line item in the consolidated balance sheets in order to conform to 2014 presentation. These impairments have no impact on our cash flow, liquidity position, or debt covenants. 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 net cash flows to a single discounted amount. Significant inputs used to determine the fair values of oil and gas properties 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 oil and natural gas reserves include 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.
	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. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. 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 commodity derivative contracts to manage our exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices. These transactions are primarily in the form of swaps with fixed settlements. 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 gain or loss on unsettled derivatives. 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.
	Equity-based compensation
	The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as 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 $7.7 million, $6.6 million and $6.5 million for the years ended December 31, 2014, 2013 and 2012, 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 $7.4 million, $6.4 million and $6.3 million for 2014, 2013 and 2012, respectively.
	Debt issuance costs
	Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations. At December 31, 2014 and 2013, net debt placement costs of approximately $4.3 million and $0.8 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 common units during the period.
	Business segment reporting
	We operate in one reportable segment: the exploitation, development and production of oil and natural gas properties. All of our operations are located in the United States.
	Recently Issued Accounting Standards
	In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are
	currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures.
	In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (Topics 205 and 360), that changes the criteria for reporting discontinued operations and enhances disclosures in this area. The standard is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company is evaluating the impact of this new guidance and does not expect it to have a significant impact on the consolidated financial statements.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Acquisitions	Acquisitions
	The following acquisitions were accounted for under the acquisition method of accounting. Accordingly, we conducted assessments of net assets acquired and recognized amounts for identifiable assets acquired and liabilities assumed at their estimated fair values on the acquisition dates, while transaction and integration costs associated with the acquisitions were expensed as incurred. The results of all acquisitions have been included in the consolidated financial statements since the acquisition dates.
	Permian acquisition
	During November 2014, we acquired multiple oil properties located in Coke, Coleman, Fisher, Haskell, Jones, Kent, Nolan, Runnels, Stonewall, Taylor, and Tom Green Counties, Texas ("Permian") for an aggregate purchase price of approximately $117.6 million, subject to customary post-closing purchase price adjustments. The transaction was primarily funded with borrowings under our revolving credit facility of approximately $21.6 million in cash and the issuance of 5,800,000 common units having an approximate value of $96.0 million, net of offering costs.
	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
	Fair value of net assets:
	Oil properties	$	119,438
	Total assets acquired	$	119,438
	Fair value of net liabilities assumed:
	Asset retirement obligation	1,851
	Fair value of net assets acquired	$	117,587
	Creek County, Oklahoma acquisition
	During August 2014, we acquired from our affiliate, Mid-Con Energy III, LLC, a certain oil property located in Creek County, Oklahoma for an aggregate purchase price of approximately $56.5 million. The transaction was primarily funded with borrowings under our revolving credit facility of approximately $4.5 million in cash and the issuance of 2,214,659 common units having an approximate value of $52.0 million.
	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
	Fair value of net assets:
	Oil property	$	56,979
	Total assets acquired	$	56,979
	Fair value of net liabilities assumed:
	Asset retirement obligation	479
	Fair value of net assets acquired	$	56,500
	Liberty County, Texas acquisition
	During August 2014, we acquired a waterflood unit in Liberty County, Texas for approximately $18.9 million. The acquisition was financed with borrowings under our revolving credit facility.
	Southern Oklahoma acquisition
	During May 2014, we acquired additional working interest in some of our Southern Oklahoma core area properties for an aggregate purchase price of approximately $7.3 million. The acquisition was financed with borrowings under our revolving credit facility.
	Hugoton acquisition
	During February 2014, we acquired from our affiliate, Mid-Con Energy III, LLC, certain oil properties located in Cimarron, Love and Texas Counties, Oklahoma and Potter County, Texas ("Hugoton") for an aggregate purchase price of approximately $41.0 million. The transaction was primarily funded with borrowings under our revolving credit facility of approximately $7.0 million and the issuance of 1,500,000 common units having an approximate value of $34.0 million.
	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
	Fair value of net assets:
	Oil properties	$	41,589
	Total assets acquired	$	41,589
	Fair value of net liabilities assumed:
	Asset retirement obligation	589
	Fair value of net assets acquired	$	41,000
	Other acquisitions
	During 2014 we had other various other acquisitions that we paid approximately $0.1 million.
	Northeastern Oklahoma acquisition
	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. 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 revolving credit facility.
	The recognized fair values of the assets 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
	Fair value of net assets acquired	$	27,412
	The following table reflects pro forma revenues, net income and net income per limited partner unit for the year ended December 31, 2014 and 2013, as if the acquisitions of the Permian properties, Creek County property and Hugoton properties had taken place on January 1, 2013. The table also reflects incremental depreciation, depletion and amortization expense using the unit-of-production method related to the oil and natural gas properties acquired, incremental accretion expense related to asset retirement obligations on the oil and natural gas properties acquired, and interest expense related to the incremental debt incurred to fund the acquisitions.
	The mid-November and December 2014 values for the Permian properties are reflected in the consolidated statement of operations since we took over operations mid-November. Because we took over the interests at August 1, 2014 for the Creek County property, the values for August and September 2014 are included in the consolidated statement of operations. Because we took over the interests at February 28, 2014 for the Hugoton properties, the values for March 2014 through September 2014 are reflected in the consolidated statement of operations. The unaudited pro forma financial data does not include the results of operations for the Liberty County, Texas, Southern Oklahoma or Northeastern Oklahoma properties, as the results of operations were deemed not to be material. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the period presented or that may be obtained in the future (in thousands):
			Year Ended December 31,
			2014		2013
	Revenues		$	168,765	$	131,230
	Net income attributable to limited partners		$	39,033	$	45,598
	Net income per limited partner unit:
	Basic		$	1.73	$	1.99
	Diluted		$	1.73	$	1.99

Equity_Awards

Equity Awards	12 Months Ended
	Dec. 31, 2014
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, unrestricted units, 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, 2014:
			Number of Common Units
	Approved and authorized awards		1,764,000
	Unrestricted units granted		(838,824	)
	Restricted units granted, net of forfeitures		(172,629	)
	Phantom units issued, net of forfeitures		(24,833	)
	Awards available for future grant		727,714
	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, 2014 and 2013 is presented below:
	Restricted awards:	Number of Restricted Units			Average Grant Date Fair Value per Unit
	Outstanding at December 31, 2012	55,149			$21.78
	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			$23.35
	Units granted	53,375			$23.11
	Units vested	(44,430	)		$23.09
	Units forfeited	(19,734	)		$23.64
	Outstanding at December 31, 2014	109,800			$23.28
	During 2014, we granted 298,450 unrestricted units as equity awards at an average grant date fair value of $21.33 per unit. We account for unrestricted units as equity awards since these awards will be settled by issuing common units.
	As of December 31, 2014, there was approximately $1.5 million of unrecognized compensation costs related to non-vested restricted units. The cost is expected to be recognized over a weighted average period of approximately 1.7 years.
	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. From the initial issuance of the phantom units, we have recorded approximately $0.1 million of compensation expense through December 31, 2014.
	Activity related to these phantom units is as follows:
	Nonvested phantom awards:		Number of Units
	Outstanding at December 31, 2012		—
	Units granted		50,000
	Units forfeited		(7,000	)
	Outstanding at December 31, 2013		43,000
	Units forfeited		(18,167	)
	Outstanding at December 31, 2014		24,833
	Outstanding units not expected to vest		(21,791	)
	We recognized $7.7 million, $6.6 million and $6.5 million of total equity-based compensation expense for the years ended December 31, 2014, 2013, and 2012, 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, 2014
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, 2014 and 2013, 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 gain or loss on unsettled derivatives. 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, 2014 and 2013, we recorded the estimated fair value of the derivative contracts as a net asset of $27.0 million and a net liability of $1.4 million, respectively.
	At December 31, 2014, we had the following oil derivative open positions:
	Period Covered	Weighted			Total
		Average			Bbls
		Fixed			Hedged/day
		Price
	Swaps - 2015	$	93.29		1,932
	Swaps - 2016	$	90.2		82
	At December 31, 2013, we had the following oil derivative positions:
	Period Covered	Weighted			Weighted			Weighted			Total	NYMEX Index
		Average			Average			Average			Bbls
		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
	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 revolving 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, 2014 and 2013 (in thousands):
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2014
	Assets
	Derivative financial instruments - current asset	$	26,202		$	—		$	26,202
	Derivative financial instruments - long-term asset	842			—			842
	Total	$	27,044		$	—		$	27,044
	Liabilities
	Derivative financial instruments - current liability	$	—		$	—		$	—
	Derivative financial instruments - long-term liability	—			—			—
	Total	$	—		$	—		$	—
	Net Asset	$	27,044		$	—		$	27,044
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2013
	Assets
	Derivative financial instruments - current asset	$	541		$	388		$	153
	Derivative financial instruments - long-term asset	48			—			48
	Total	$	589		$	388		$	201
	Liabilities
	Derivative financial instruments - current liability	$	(2,015	)	$	(388	)	$	(1,627	)
	Derivative financial instruments - long-term liability	—			—			—
	Total	$	(2,015	)	$	(388	)	$	(1,627	)
	Net liability	$	(1,426	)	$	—		$	(1,426	)
	The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations:
		December 31,
		2014			2013			2012
	Net settlements on derivatives	$	891		$	288		$	3,710
	Gain (loss) on unsettled derivatives, net	28,470			(5,963		)	2,004
	Total gain (loss) on derivatives, net	$	29,361		$	(5,675	)	$	5,714

Fair_Value_Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Fair Value Disclosures
	Fair Value of Financial Instruments
	The carrying amounts reported in the balance sheet for cash, accounts receivable, and accounts payable approximate their fair values. The carrying amount of long-term debt under our revolving credit facility approximates fair value because the revolving 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, 2014, 2013 and 2012.
	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.
	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.
	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, 2014, we recorded a non-cash impairment charge of approximately $30.2 million primarily in our Hugoton and in our Southern Oklahoma core areas due to reduced recoverable reserve estimates from current forward oil pricing. For the year ended December 31, 2013 we recorded a non-cash impairment charge of approximately $1.6 million within our miscellaneous core area due to reduced recoverable reserve estimates.
	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, 2014 and 2013:
		Level 1		Level 2			Level 3
		(in thousands)
	December 31, 2014
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	27,044		$	—
	Derivative financial instruments- liability	—		—			—
	Net financial assets	$	—	$	27,044		$	—
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Asset retirement obligations	$	—	$	—		$	3,171
	Impairment of proved oil and gas properties	$	—	$	—		$	30,206
	31-Dec-13
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	201		$	—
	Derivative financial instruments- liability	—		(1,627		)	—
	Net financial liabilities	$	—	$	(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
	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, 2014 and 2013.

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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 oil and natural gas 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 natural 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:
		Year Ended December 31,
		2014		2013			2012
		(in thousands)
	Asset retirement obligation - beginning of period	$	3,942	$	2,890		$	1,919
	Liabilities incurred for new wells and interest	3,171		1,009			636
	Revision of estimates	—		(130		)	209
	Accretion expense	250		173			126
	Asset retirement obligation - end of period	$	7,363	$	3,942		$	2,890

Debt

Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Debt	Debt
	At December 31, 2014, our revolving credit facility consists of a $250.0 million senior secured revolving credit facility that expires in November 2018. Borrowings under the facility may not exceed our current borrowing base of $240.0 million as determined at November 17, 2014. 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, 2014, we had $205.0 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.
	Borrowings under the revolving credit facility 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, 2014, the average effective rate was approximately 2.8%. 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 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.
	During 2013, our borrowing base under the revolving credit facility was increased from $130.0 million to $150.0 million and the Bank of Nova Scotia ("Scotiabank") was added to the lender group. Effective with this increase, the maturity terms of our revolving credit facility were extended to November 2018. No other material terms of the original credit agreement were amended. During 2013, in connection with the amendments to our revolving credit facility, we incurred financing fees and expenses of approximately $0.4 million, which will be amortized over the life of the revolving credit facility. Such amortized expenses are recorded in "interest expense" on our consolidated statements of operations.
	During April and August 2014, our borrowing base under the revolving credit facility was increased from $150.0 million to $170.0 million and from $170.0 million to $190.0 million, respectively. No other material terms of the original credit agreement were amended. In connection with this amendment to our revolving credit facility, we incurred financing fees and expenses of approximately $0.2 million, which will be amortized over the life of the revolving credit facility. Such amortized expenses are recorded in "interest expense" on our consolidated statements of operations.
	During November 2014, our borrowing base under the revolving credit facility was increased from $190.0 million to $240.0 million. The amendment added MUFG Union Bank, N.A. and Frost Bank as additional lenders. No other material terms of the original credit agreement were amended. In connection with this amendment to our revolving credit facility, we incurred financing fees and expenses of approximately $3.6 million, which will be amortized over the life of the revolving credit facility. Such amortized expenses are recorded in "interest expense" on our consolidated statements of operations.
	The revolving 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, 2014.

Commitment_and_Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitment and Contingencies	Commitment and Contingencies
	We have 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 the following named employees of our general partner: Jeffrey R. Olmstead, Chief Executive Officer; and Charles R. Olmstead, Executive Chairman of the Board of our general partner. The previous employment agreement with S. Craig George was terminated in August 2014. The employment agreements provide for a term that commenced on August 1, 2011 and automatically renewed on August 1, 2014 for an additional year, unless earlier terminated, and will continue to automatically renew for one-year terms unless either we or the employee gives written notice of termination at least by February 1st preceding any such August 1st. 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, 2014
Equity [Abstract]
Equity	Equity
	Common Units
	At December 31, 2014, the Partnership’s equity consisted of 29,166,112 common units, representing approximately 98.8% in limited partnership interest in us. At December 31, 2013, the Partnership's equity consisted of 19,319,362 common units representing approximately a 98.2% in limited partnership interest in us.
	In February 2014 and August 2014, we issued 1,500,000 and 2,214,659 common units, respectively, related to the acquisition of properties from one of our affiliates. See Note 3 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more detail regarding these acquisitions.
	Public Offering of Additional Units
	During November 2014, we completed a public offering of 5,800,000 common units. The common units were sold to the public at a price of $17.27 per common unit. We received approximately $96.0 million, net of offering costs. These proceeds were used to finance the acquisition of the Permian properties.
	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 revolving credit facility prohibits us from making cash distributions if any potential default or event of default, as defined in our revolving 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, 2014 and 2013:
			Distribution		Total
	Date Paid	Period Covered	per Unit		Distributions
	February 14, 2014	October 1, 2013 - December 31, 2013	$	0.515	$	10,262
	May 15, 2014	January 1, 2014 - March 31, 2014	0.515		11,032
	August 11, 2014	April 1, 2014 - June 30, 2014	0.515		11,066
	November 14, 2014	July 1, 2014 - September 30, 2014	0.515		12,204
					$	44,564
	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
	On January 23, 2015, the Board of Directors of our general partner approved a quarterly cash distribution for the fourth quarter of 2014 of $0.125 per unit, or $0.50 per unit on an annualized basis. The distribution was paid on February 13, 2015 to unitholders of record at the close of business on February 6, 2015. The aggregate amount of the distribution was approximately $3.8 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, 2014
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, 2014, 2013 and 2012, we reimbursed Mid-Con Energy Operating approximately $3.8 million, $3.6 million and $2.9 million, respectively, for direct expenses.
	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 natural 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.
	During February and August, 2014, we acquired from Mid-Con Energy III, LLC, an affiliated company, certain oil
	properties located in Oklahoma and Texas. The terms of the acquisitions 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
	agreements and the acquisitions. The purchase agreements contained representations and warranties, covenants and
	indemnification provisions that are typical for transactions of this nature and that were made or agreed to, among other things,
	to provide the parties thereto with specified rights and obligations and to allocate risk among them. See Note 3 to the Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information regarding these acquisitions.
	At December 31, 2014, we had payables to Mid-Con Energy Operating of approximately $4.0 million which is comprised of a joint interest billing payable of approximately $3.2 million and a payable for operating services of approximately $0.8 million. At December 31, 2013, 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, 2014
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 2014, 2013 or 2012.
	For the year ended December 31, 2014, sales of oil and natural gas to Enterprise Crude Oil, LLC (“Enterprise”), Coffeyville Resources Refining & Marketing, LLC ("Coffeyville") and Plains Marketing, LP ("Plains") accounted for approximately 40%, 26%, and 9%, respectively, of our totals sales revenues. These purchasers represent 14%, 25%, and 6%, respectively, of our outstanding oil and natural gas accounts receivable at December 31, 2014.
	For the year ended December 31, 2013, sales of oil and natural gas to Enterprise, 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 Partners, LP ("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.
	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, 2014
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, 2014 there were 727,714 units available for issuance.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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, 2014
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events
	On January 23, 2015, the Board of Directors of our general partner approved a quarterly cash distribution for the fourth quarter of 2014 of $0.125 per unit, or $0.50 on an annualized basis, which was paid on February 13, 2015 to unitholders of record as of the close of business on February 6, 2015. The aggregate amount of the distribution was approximately $3.8 million.
	Also on January 23, 2015, the Board of Directors of our general partner authorized the issuance of 202,000 unrestricted and 268,000 restricted common units with one-third vesting immediately and the other two thirds vesting over two-years, and 29,800 restricted common units with a three -year vesting period. These units were granted to certain employees of our affiliates and certain directors and founders of our general partner.
	On January 26, 2015, we restructured a significant portion of our existing oil derivatives that were in place at December 31, 2014. This resulted in the early settlement of certain contracts existing at December 31, 2014, and entering into new oil derivative contracts covering a total of: (1) approximately 1,065,000 barrels of future production between January and December 2015 with a weighted average price of $75.62 per barrel and (2) approximately 810,000 barrels of future production between January and September 2016 with a weighted average price of $70.01 per barrel. In connection with the early termination and modifications of our derivative contracts, we received net proceeds of approximately $11.1 million and will have approximately $4.1 million in deferred premiums, of which, $2.0 million and $2.1 million are due in 2015 and 2016, respectively.
	On February 9, 2015, the revolving credit facility was amended to allow our EBITDAX calculation, as defined in section 7.13 of the original revolving credit agreement, to reflect the net cash flows attributable to the restructured commodity derivative contracts that occurred during January 2015 for the periods of the first quarter 2015 through the third quarter of 2016.

Supplementary_Information

Supplementary Information	12 Months Ended
	Dec. 31, 2014
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)
	2014
	Oil and natural gas sales	$	21,807			$	24,335			$	26,173		$	24,596
	Net settlements on derivatives	(921		)		(2,072		)		(760		)	4,644
	Gain (loss) on unsettled derivatives, net	(1,127		)		(2,819		)		10,040			22,376
	Total revenues and other	19,759				19,444				35,453			51,616
	Total expenses (1)	18,198				15,597				18,451			51,534
	Net income	1,561				3,847				17,002			82
	Net income per limited partner unit (basic)	$	0.08			$	0.18			$	0.75		$	—
	Net income per limited partner unit (diluted)	$	0.08			$	0.18			$	0.74		$	—
	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
	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
	-1	Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative, and net other expense.
	Supplementary oil and natural gas activities
	Costs incurred in oil and natural gas property acquisitions and development activities are as follows:
		Year Ended December 31,
		2014				2013				2012
		(in thousands)
	Property acquisition costs:
	Proved	$	241,355			$	28,057			$	48,578
	Unproved	—				—				—
	Exploration	—				—				—
	Development	34,320				22,287				21,639
	Asset retirement obligations	3,171				879				679
	Total costs incurred	$	278,846			$	51,223			$	70,896
	Estimated proved oil and natural gas reserves (unaudited)
	The Company's proved oil and natural gas reserves are all located in the United States. The proved oil and natural gas reserves for the years ended December 31, 2014, 2013, and 2012 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 natural gas reserves are presented below for the periods indicated:
		Oil			Gas			MBoe (1)
		(MBbls)			(MMcf)
	Proved developed and undeveloped reserves:
	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
	Revisions of previous estimates	211			924			364
	Extensions, discoveries and other additions	1,241			52			1,250
	Purchases of minerals in place	8,086			4,402			8,820
	Production	(1,112	)		(157	)		(1,138	)
	As of December 31, 2014	22,140			6,542			23,230
	Proved developed reserves:
	December 31, 2012	8,727			429			8,799
	31-Dec-13	10,397			1,321			10,617
	31-Dec-14	17,046			5,327			17,933
	Proved undeveloped reserves:
	December 31, 2012	4,347			—			4,347
	December 31, 2013	3,317			—			3,317
31-Dec-14	5,094			1,215			5,297
-1	Estimated quantities of oil and natural gas reserves in Mboe equivalents at a rate of six Mcf per Bbl.
Revisions represent changes in the previous reserves estimates, either upward of downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
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. For this period, proved reserve volumes attributed to extensions, discoveries, and other additions changed from 1,704 Mboe in 2011 to 1,572 Mboe in 2012. During 2012, additional reserves were attributed to our Southern Oklahoma and Northeastern Oklahoma areas due to extensions, discoveries, and additions based on drilling and recompletion activities. The majority of this year-end 2012 volume resulted from the extension of the proved acreage in our Southern Oklahoma Highlands waterflood unit. Additional volumes were attributable to the development of behind pipe reserves in the Cleveland Field in Northeastern Oklahoma. These volumes resulted in a year-to-year change in extensions, discoveries, and other additions of approximately eight percent.
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. For this period, proved reserve volumes attributed to extensions, discoveries, and other additions changed from 1,572 Mboe in 2012 to 76 Mboe in 2013. During the period of 2013, there were no significant extensions, discoveries, or other additions except for a small extension in the Hugoton area in our Clawson Ranch waterflood unit due to drilling activity extending the proved reservoir acreage. This is in contrast to the 2012 period, where drilling in our Southern Oklahoma waterflood units extended the proved acreage while recompletion activities in our Northeast Oklahoma properties added proved reserves in new reservoirs in old fields resulting in substantial extensions, discoveries, and other additions.
The change in quantities of proved reserves from December 31, 2013 to December 31, 2014 is due to (i) the acquisitions of additional properties in Oklahoma and Texas from our affiliate Mid-Con Energy III, LLC; (ii) the acquisition of additional working interest in some of our Southern Oklahoma properties; (iii) the acquisition of the waterflood unit in Liberty County, Texas; and (iv) the acquisition of multiple properties located in West Texas within the Eastern Shelf of the Permian. For this period, proved reserve volumes attributed to extensions, discoveries, and other additions changed from 76 Mboe in 2013 to 1,250 Mboe in 2014. During the period of 2014, extensions, discoveries and other additions increased over the prior year primarily from development work in the Northeast Oklahoma area, which increased proved developed producing and proved undeveloped reserves from new reservoirs from portions of older fields.
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 natural 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, 2014, 2013 and 2012, 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 natural gas 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,
	2014				2013				2012
	(in thousands)
Future cash inflows	$	2,084,005			$	1,295,435			$	1,191,410
Future production costs	(825,318		)		(542,389		)		(417,362		)
Future development costs, including abandonment costs	(76,783		)		(49,458		)		(47,490		)
Future net cash flow	1,181,904				703,588				726,558
10% discount for estimated timing of cash flow	(517,627		)		(312,325		)		(323,136		)
Standardized measure of discounted cash flow	$	664,277			$	391,263			$	403,422
The prices utilized in calculating our total proved reserves were $94.99, $96.78, and $94.71 per Bbl of oil and $4.35, $3.67, and $2.75 per MMBtu of natural gas for December 31, 2014, 2013, and 2012, 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 $92.45, $93.98, and $91.03 per Bbl of oil and $5.67, $5.00, and $2.87 per Mcf of natural gas for December 31, 2014, 2013 and 2012, 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 natural gas reserves is presented below for the periods indicated:
	Year Ended December 31,
	2014				2013				2012
Standardized measure of discounted future net cash flow, beginning of period	$	391,263			$	403,422			$	328,231
Changes in the year resulting from:
Sales, less production costs	(64,495		)		(65,553		)		(48,648		)
Revisions of previous quantity estimates	11,712				12,006				(26,796		)
Extensions, discoveries and improved recovery	44,727				1,863				51,098
Net change in prices and production costs	22,068				(28,324		)		(15,328		)
Net change in income taxes	—				—				—
Changes in estimated future development costs	(18,125		)		(17,155		)		(11,515		)
Previously estimated development costs incurred during the period	22,526				22,257				21,629
Purchases of minerals in place	264,921				38,170				81,602
Accretion of discount	39,126				40,342				32,823
Timing differences and other	(49,446		)		(15,765		)		(9,674		)
Standardized measure of discounted future net cash flow, end of year	$	664,277			$	391,263			$	403,422

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2014, 2013 and 2012.
	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.
	We aggregate all of our oil and natural gas properties into one business segment engaged in the exploitation, development and production of oil and natural gas properties.
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 natural gas properties which is determined using estimates of proved oil and natural 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 assets acquired and liabilities assumed in business combinations, fair value of derivative financial instruments, 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. We have not experienced any losses in such accounts.
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. As of December 31, 2014 and 2013, 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	Revenue recognition
	We follow the sales method of accounting for 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, 2014 or 2013.
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 natural 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 natural 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, 2014, 2013 and 2012, we recorded non-cash impairment charges of approximately $30.2 million, $1.6 million, and $1.3 million, respectively, related to our oil and natural gas properties due to reduced recoverable reserve estimates due to a steep decline in commodity prices. These non-cash charges are included in "Impairment of proved oil and natural gas properties” line item in the accompanying consolidated statements of operations and "Accumulated depletion, depreciation, amortization and impairment" line item in the accompanying consolidated balance sheets. During 2014, we reclassified approximately $5.7 million of impairments recognized in periods prior to 2014 from the 'Proved properties" line item to the "Accumulated depletion, depreciation, amortization and impairment" line item in the consolidated balance sheets in order to conform to 2014 presentation. These impairments have no impact on our cash flow, liquidity position, or debt covenants. 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 net cash flows to a single discounted amount. Significant inputs used to determine the fair values of oil and gas properties 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 oil and natural gas reserves include 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.
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. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. 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 commodity derivative contracts to manage our exposure to commodity price fluctuations and fluctuations in location differences between published index prices and the NYMEX futures prices. These transactions are primarily in the form of swaps with fixed settlements. 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 gain or loss on unsettled derivatives. 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.
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 and is recorded as 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 $7.7 million, $6.6 million and $6.5 million for the years ended December 31, 2014, 2013 and 2012, 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 $7.4 million, $6.4 million and $6.3 million for 2014, 2013 and 2012, respectively.
Debt placement fee	Debt issuance costs
	Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations. At December 31, 2014 and 2013, net debt placement costs of approximately $4.3 million and $0.8 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 common units during the period.
Business segment reporting	Business segment reporting
	We operate in one reportable segment: the exploitation, development and production of oil and natural gas properties. All of our operations are located in the United States.
Recent Accounting Pronouncements	Recently Issued Accounting Standards
	In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which provides a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and will supersede most current revenue recognition guidance. The standard is effective for public entities for annual and interim periods beginning after December 15, 2016. Early adoption is not permitted. We are
	currently evaluating the impact the pronouncement will have on our consolidated financial statements and related disclosures.
	In April 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity (Topics 205 and 360), that changes the criteria for reporting discontinued operations and enhances disclosures in this area. The standard is effective for annual and interim periods beginning after December 15, 2014, with early adoption permitted for disposals or for assets classified as held for sale that have not been reported in previously issued financial statements. The Company is evaluating the impact of this new guidance and does not expect it to have a significant impact on the consolidated financial statements.

Acquisitions_Tables

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2014
Cushing Properties [Member]
Business Acquisition [Line Items]
Acquisitions	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
	Fair value of net assets:
	Oil properties	$	119,438
	Total assets acquired	$	119,438
	Fair value of net liabilities assumed:
	Asset retirement obligation	1,851
	Fair value of net assets acquired	$	117,587
	The recognized fair values of the assets 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
	Fair value of net assets acquired	$	27,412
	The following table reflects pro forma revenues, net income and net income per limited partner unit for the year ended December 31, 2014 and 2013, as if the acquisitions of the Permian properties, Creek County property and Hugoton properties had taken place on January 1, 2013. The table also reflects incremental depreciation, depletion and amortization expense using the unit-of-production method related to the oil and natural gas properties acquired, incremental accretion expense related to asset retirement obligations on the oil and natural gas properties acquired, and interest expense related to the incremental debt incurred to fund the acquisitions.
	The mid-November and December 2014 values for the Permian properties are reflected in the consolidated statement of operations since we took over operations mid-November. Because we took over the interests at August 1, 2014 for the Creek County property, the values for August and September 2014 are included in the consolidated statement of operations. Because we took over the interests at February 28, 2014 for the Hugoton properties, the values for March 2014 through September 2014 are reflected in the consolidated statement of operations. The unaudited pro forma financial data does not include the results of operations for the Liberty County, Texas, Southern Oklahoma or Northeastern Oklahoma properties, as the results of operations were deemed not to be material. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the period presented or that may be obtained in the future (in thousands):
			Year Ended December 31,
			2014		2013
	Revenues		$	168,765	$	131,230
	Net income attributable to limited partners		$	39,033	$	45,598
	Net income per limited partner unit:
	Basic		$	1.73	$	1.99
	Diluted		$	1.73	$	1.99
Creek County [Member]
Business Acquisition [Line Items]
Acquisitions	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
	Fair value of net assets:
	Oil property	$	56,979
	Total assets acquired	$	56,979
	Fair value of net liabilities assumed:
	Asset retirement obligation	479
	Fair value of net assets acquired	$	56,500
Hugoton [Member]
Business Acquisition [Line Items]
Acquisitions	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands):
	Fair value of net assets:
	Oil properties	$	41,589
	Total assets acquired	$	41,589
	Fair value of net liabilities assumed:
	Asset retirement obligation	589
	Fair value of net assets acquired	$	41,000

Equity_Awards_Tables

Equity Awards (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014:
			Number of Common Units
	Approved and authorized awards		1,764,000
	Unrestricted units granted		(838,824	)
	Restricted units granted, net of forfeitures		(172,629	)
	Phantom units issued, net of forfeitures		(24,833	)
	Awards available for future grant		727,714
Summary of restricted units awarded	A summary of our restricted units awarded for the years ended December 31, 2014 and 2013 is presented below:
	Restricted awards:	Number of Restricted Units			Average Grant Date Fair Value per Unit
	Outstanding at December 31, 2012	55,149			$21.78
	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			$23.35
	Units granted	53,375			$23.11
	Units vested	(44,430	)		$23.09
	Units forfeited	(19,734	)		$23.64
	Outstanding at December 31, 2014	109,800			$23.28
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:
	Nonvested phantom awards:		Number of Units
	Outstanding at December 31, 2012		—
	Units granted		50,000
	Units forfeited		(7,000	)
	Outstanding at December 31, 2013		43,000
	Units forfeited		(18,167	)
	Outstanding at December 31, 2014		24,833
	Outstanding units not expected to vest		(21,791	)

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Contracts	At December 31, 2014, we had the following oil derivative open positions:
	Period Covered	Weighted			Total
		Average			Bbls
		Fixed			Hedged/day
		Price
	Swaps - 2015	$	93.29		1,932
	Swaps - 2016	$	90.2		82
	At December 31, 2013, we had the following oil derivative positions:
	Period Covered	Weighted			Weighted			Weighted			Total	NYMEX Index
		Average			Average			Average			Bbls
		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
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, 2014 and 2013 (in thousands):
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2014
	Assets
	Derivative financial instruments - current asset	$	26,202		$	—		$	26,202
	Derivative financial instruments - long-term asset	842			—			842
	Total	$	27,044		$	—		$	27,044
	Liabilities
	Derivative financial instruments - current liability	$	—		$	—		$	—
	Derivative financial instruments - long-term liability	—			—			—
	Total	$	—		$	—		$	—
	Net Asset	$	27,044		$	—		$	27,044
		Gross			Gross Amounts			Net Amounts
		Amounts			Offset in the			Presented in  the
		Recognized			Consolidated			Consolidated
					Balance Sheet			Balance Sheet
	2013
	Assets
	Derivative financial instruments - current asset	$	541		$	388		$	153
	Derivative financial instruments - long-term asset	48			—			48
	Total	$	589		$	388		$	201
	Liabilities
	Derivative financial instruments - current liability	$	(2,015	)	$	(388	)	$	(1,627	)
	Derivative financial instruments - long-term liability	—			—			—
	Total	$	(2,015	)	$	(388	)	$	(1,627	)
	Net liability	$	(1,426	)	$	—		$	(1,426	)
Impact of Derivative Financial Instruments within Consolidated Statement of Operations	The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations:
		December 31,
		2014			2013			2012
	Net settlements on derivatives	$	891		$	288		$	3,710
	Gain (loss) on unsettled derivatives, net	28,470			(5,963		)	2,004
	Total gain (loss) on derivatives, net	$	29,361		$	(5,675	)	$	5,714

Fair_Value_Disclosures_Tables

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013:
		Level 1		Level 2			Level 3
		(in thousands)
	December 31, 2014
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	27,044		$	—
	Derivative financial instruments- liability	—		—			—
	Net financial assets	$	—	$	27,044		$	—
	Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
	Asset retirement obligations	$	—	$	—		$	3,171
	Impairment of proved oil and gas properties	$	—	$	—		$	30,206
	31-Dec-13
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	Derivative financial instruments- asset	$	—	$	201		$	—
	Derivative financial instruments- liability	—		(1,627		)	—
	Net financial liabilities	$	—	$	(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

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
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:
		Year Ended December 31,
		2014		2013			2012
		(in thousands)
	Asset retirement obligation - beginning of period	$	3,942	$	2,890		$	1,919
	Liabilities incurred for new wells and interest	3,171		1,009			636
	Revision of estimates	—		(130		)	209
	Accretion expense	250		173			126
	Asset retirement obligation - end of period	$	7,363	$	3,942		$	2,890

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Cash distributions	The following sets forth the distributions we paid during the years ended December 31, 2014 and 2013:
			Distribution		Total
	Date Paid	Period Covered	per Unit		Distributions
	February 14, 2014	October 1, 2013 - December 31, 2013	$	0.515	$	10,262
	May 15, 2014	January 1, 2014 - March 31, 2014	0.515		11,032
	August 11, 2014	April 1, 2014 - June 30, 2014	0.515		11,066
	November 14, 2014	July 1, 2014 - September 30, 2014	0.515		12,204
					$	44,564
	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

Supplementary_Information_Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2014
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)
	2014
	Oil and natural gas sales	$	21,807			$	24,335			$	26,173		$	24,596
	Net settlements on derivatives	(921		)		(2,072		)		(760		)	4,644
	Gain (loss) on unsettled derivatives, net	(1,127		)		(2,819		)		10,040			22,376
	Total revenues and other	19,759				19,444				35,453			51,616
	Total expenses (1)	18,198				15,597				18,451			51,534
	Net income	1,561				3,847				17,002			82
	Net income per limited partner unit (basic)	$	0.08			$	0.18			$	0.75		$	—
	Net income per limited partner unit (diluted)	$	0.08			$	0.18			$	0.74		$	—
	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
	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
	-1	Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative, and net other expense.
Supplementary Oil and Natural Gas Activities	Supplementary oil and natural gas activities
	Costs incurred in oil and natural gas property acquisitions and development activities are as follows:
		Year Ended December 31,
		2014				2013				2012
		(in thousands)
	Property acquisition costs:
	Proved	$	241,355			$	28,057			$	48,578
	Unproved	—				—				—
	Exploration	—				—				—
	Development	34,320				22,287				21,639
	Asset retirement obligations	3,171				879				679
	Total costs incurred	$	278,846			$	51,223			$	70,896
Changes in Estimated Proved Oil and Natural Gas Reserves	An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated:
		Oil			Gas			MBoe (1)
		(MBbls)			(MMcf)
	Proved developed and undeveloped reserves:
	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
	Revisions of previous estimates	211			924			364
	Extensions, discoveries and other additions	1,241			52			1,250
	Purchases of minerals in place	8,086			4,402			8,820
	Production	(1,112	)		(157	)		(1,138	)
	As of December 31, 2014	22,140			6,542			23,230
	Proved developed reserves:
	December 31, 2012	8,727			429			8,799
	31-Dec-13	10,397			1,321			10,617
	31-Dec-14	17,046			5,327			17,933
	Proved undeveloped reserves:
	December 31, 2012	4,347			—			4,347
	December 31, 2013	3,317			—			3,317
	31-Dec-14	5,094			1,215			5,297
Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves	he 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,
		2014				2013				2012
		(in thousands)
	Future cash inflows	$	2,084,005			$	1,295,435			$	1,191,410
	Future production costs	(825,318		)		(542,389		)		(417,362		)
	Future development costs, including abandonment costs	(76,783		)		(49,458		)		(47,490		)
	Future net cash flow	1,181,904				703,588				726,558
	10% discount for estimated timing of cash flow	(517,627		)		(312,325		)		(323,136		)
	Standardized measure of discounted cash flow	$	664,277			$	391,263			$	403,422
Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	hanges in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated:
		Year Ended December 31,
		2014				2013				2012
	Standardized measure of discounted future net cash flow, beginning of period	$	391,263			$	403,422			$	328,231
	Changes in the year resulting from:
	Sales, less production costs	(64,495		)		(65,553		)		(48,648		)
	Revisions of previous quantity estimates	11,712				12,006				(26,796		)
	Extensions, discoveries and improved recovery	44,727				1,863				51,098
	Net change in prices and production costs	22,068				(28,324		)		(15,328		)
	Net change in income taxes	—				—				—
	Changes in estimated future development costs	(18,125		)		(17,155		)		(11,515		)
	Previously estimated development costs incurred during the period	22,526				22,257				21,629
	Purchases of minerals in place	264,921				38,170				81,602
	Accretion of discount	39,126				40,342				32,823
	Timing differences and other	(49,446		)		(15,765		)		(9,674		)
	Standardized measure of discounted future net cash flow, end of year	$	664,277			$	391,263			$	403,422

Summary_of_Significant_Account2

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Segment
Summary Of Significant Accounting Policies [Line Items]
Number of operating segment	1
Impairment charges	$30,206,000	$1,578,000	$1,296,000	$5,655,000
Non-cash equity based compensation	7,400,000	6,400,000	6,300,000
Debt placement fees, net of amortization	$4,300,000	$800,000
Number of reportable segments	1

Acquisitions_Additional_Inform

Acquisitions - Additional Information (Detail) (USD $)	1 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Aug. 31, 2014	31-May-14	Dec. 31, 2014
Liberty County, Texas [Member]
Business Acquisition [Line Items]
Consideration paid in cash	$18.90
Southern Oklahoma [Member]
Business Acquisition [Line Items]
Consideration paid in cash		7.3
Miscellaneous [Member]
Business Acquisition [Line Items]
Consideration paid in cash			$0.10

Acquisitions_Summary_of_Combin

Acquisitions - Summary of Combined Statement of Operation (Detail) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$168,765	$131,230
Net income	$39,033	$45,598
Business Acquisition, Pro Forma Earnings Per Share, Basic	$1.73	$1.99
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$1.73	$1.99

Acquisitions_Acquisitions_1_De

Acquisitions Acquisitions - 1 (Details) (Permian [Member], USD $)	1 Months Ended
	Nov. 30, 2014
Permian [Member]
Business Acquisition [Line Items]
Number of limited partner units issued - acquisitions	5,800,000
Total consideration transferred	$117,600,000
Consideration paid in cash	21,600,000
Value of limited partner units issued	96,000,000
Oil properties	119,438,000
Total assets acquired	119,438,000
Asset retirement obligation	1,851,000
Net assets acquired	$117,587,000

Acquisitions_Acquisitions_2_De

Acquisitions Acquisitions - 2 (Details) (Creek County [Member], USD $)	1 Months Ended
	Aug. 31, 2014
Creek County [Member]
Business Acquisition [Line Items]
Number of limited partner units issued - acquisitions	2,214,659
Total consideration transferred	$56,500,000
Consideration paid in cash	4,500,000
Value of limited partner units issued	52,000,000
Oil property	56,979,000
Total assets acquired	56,979,000
Asset retirement obligation	479,000
Net assets acquired	$56,500,000

Acquisitions_Acquisitions_3_De

Acquisitions Acquisitions - 3 (Details) (Hugoton [Member], USD $)	1 Months Ended
	Feb. 28, 2014
Hugoton [Member]
Business Acquisition [Line Items]
Number of limited partner units issued - acquisitions	1,500,000
Total consideration transferred	$41,000,000
Payments to Acquire Oil and Gas Property	7,000,000
Value of limited partner units issued	34,000,000
Oil properties	41,589,000
Total assets acquired	41,589,000
Asset retirement obligation	589,000
Net assets acquired	$41,000,000

Acquisitions_Acquisition_4_Det

Acquisitions Acquisition - 4 (Details) (USD $)	1 Months Ended
	31-May-13
NE Oklahoma [Member]
Business Acquisition [Line Items]
Consideration paid in cash	$27,400,000
Cushing Properties [Member]
Business Acquisition [Line Items]
Oil properties	28,318,000
Total assets acquired	28,318,000
Asset retirement obligation	906,000
Net assets acquired	$27,412,000

Equity_Awards_Additional_Infor

Equity Awards - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	1,764,000
Unrestricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted	298,450
Average grant date fair value per unit, granted	$21.33
Nonvested Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$1.50
Weighted average period over which the unrecognized cost are expected to be recognized	1 year 8 months 28 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-based compensation expense	$7.70	$6.60	$6.50

Equity_Awards_Awards_Available

Equity Awards - Awards Available for Future Grant (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	1,764,000
Awards available for future grant	727,714
Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted, net of forfeitures and vesting	-109,800	-120,589	-55,149
Phantom Share Units (PSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted, net of forfeitures and vesting	-24,833	-43,000	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	-838,824
Awards available for future grant	727,714
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	-172,629
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	-24,833

Equity_Awards_Restricted_Units

Equity Awards - Restricted Units (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$23.28	$23.35	$21.78
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, beginning of period	120,589	55,149
Units granted	53,375	96,185
Units vested	-44,430	-18,399
Units forfeited	-19,734	-12,346
Outstanding, end of period	109,800	120,589
Average grant date fair value per unit, granted	$23.11	$23.86
Average grant date fair value per unit, vested	$23.09	$21.24
Average grant date fair value per unit, forfeited	$23.64	$22.13
Nonvested Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$1.50
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Weighted average period over which the unrecognized cost are expected to be recognized	1 year 8 months 28 days

Equity_Awards_Equity_Awards_Ph

Equity Awards Equity Awards - Phantom Units (Details) (Phantom Share Units (PSUs) [Member], USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
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	$0.10
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, beginning of period	43,000	0
Number of units issued		50,000
Units forfeited	-18,167	-7,000
Outstanding, end of period	24,833	43,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Awards Not Expected to Vest	-21,791

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Estimated fair value of derivative contracts, net asset (liability)	$27,044	($1,426)

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Commodity Contract (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
	Bbls	Bbls
Swaps [Member] | Period Covered-2014
Derivative [Line Items]
Weighted Average Fixed Price		93.56
Total Bbls Hedged/day		1,973
Swaps [Member] | Period Covered-2015
Derivative [Line Items]
Weighted Average Fixed Price	93.29	90.05
Total Bbls Hedged/day	1,932	164
Swaps [Member] | Period Covered-2016
Derivative [Line Items]
Weighted Average Fixed Price	90.2
Total Bbls Hedged/day	82
Collars [Member] | Period Covered-2015
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, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Assets [Abstract]
Gross amounts of recognized assets	$27,044	$589
Gross amounts offset in the Consolidated Balance Sheet	0	388
Net financial assets	27,044	201
Liabilities [Abstract]
Gross amounts of recognized liabilities	0	2,015
Gross amounts offset in the Consolidated Balance Sheet	0	-388
Net financial liabilities	0	-1,627
Gross amounts of recognized assets and liabilities	27,044	-1,426
Gross amounts offset in the Consolidated Balance Sheet	0	0
Net amounts presented in the Consolidated Balance Sheet	27,044	-1,426
Current Asset [Member]
Assets [Abstract]
Gross amounts of recognized assets	26,202	541
Gross amounts offset in the Consolidated Balance Sheet	0	388
Net financial assets	26,202	153
Long Term Asset [Member]
Assets [Abstract]
Gross amounts of recognized assets	842	48
Gross amounts offset in the Consolidated Balance Sheet	0	0
Net financial assets	842	48
Current Liability [Member]
Liabilities [Abstract]
Gross amounts of recognized liabilities	0	2,015
Gross amounts offset in the Consolidated Balance Sheet	0	-388
Net financial liabilities	0	-1,627
Long Term Liability [Member]
Liabilities [Abstract]
Gross amounts of recognized liabilities	0	0
Gross amounts offset in the Consolidated Balance Sheet	0	0
Net financial liabilities	$0	$0

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net settlements on derivatives	$4,644	($760)	($2,072)	($921)	$199	($1,293)	$709	$673	$891	$288	$3,710
Gain (loss) on unsettled derivatives, net	22,376	10,040	-2,819	-1,127	371	-5,501	960	-1,793	28,470	-5,963	2,004
Total gain (loss) on derivatives, net									$29,361	($5,675)	$5,714

Fair_Value_Disclosures_Additio

Fair Value Disclosures - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value Disclosures [Abstract]
Impairment charges	$30,206	$1,578	$1,296	$5,655

Fair_Value_Disclosures_Assets_

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instrument- asset	$27,044	$589
Derivative financial instrument - liability	0	-1,627
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	27,044	201
Derivative financial instrument - liability	0	-1,627
Net financial assets	27,044	-1,426
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	3,171	879
Impairment of proved oil and gas properties	$30,206	$1,578

Asset_Retirement_Obligations_C

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in ARO obligations
Asset retirement obligation - beginning of period	$3,942	$2,890	$1,919
Liabilities incurred for new wells and interests	3,171	1,009	636
Revision of estimates	0	-130	209
Accretion expense	250	173	126
Asset retirement obligation - end of period	$7,363	$3,942	$2,890

Debt_Additional_Information_De

Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Nov. 17, 2014	Sep. 30, 2014	Jun. 30, 2014	Apr. 11, 2014	Mar. 31, 2014	Nov. 30, 2013	Apr. 30, 2013
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
Line of credit , current borrowing capacity	240,000,000	240,000,000	190,000,000	170,000,000	170,000,000	150,000,000	150,000,000	130,000,000
Financing fees and expenses		3,600,000	200,000				400,000
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	$205,000,000
Minimum current ratio	1
Average effective rate	2.80%
Maximum [Member]
Line of Credit Facility [Line Items]
Leverage ratio	4
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, 2014
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 $)	12 Months Ended			1 Months Ended	0 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Oct. 31, 2012	Jan. 23, 2015	Nov. 30, 2014	Feb. 28, 2014	Aug. 31, 2014
Equity [Line Items]
Owners Equity	29,166,112	19,319,362
Limited partnership interest	98.80%	98.20%
Proceeds from sale of common units	$96,010,000	$0	$20,352,000
Yorktown [Member]
Equity [Line Items]
Proceeds from sale of common units				0
Subsequent Event [Member]
Equity [Line Items]
Cash distribution for the fourth quarter					$0.13
Cash distribution on annualized basis					$0.50
Distribution to holders					3,800,000
Permian [Member]
Equity [Line Items]
Number of limited partner units issued - acquisitions						5,800,000
Sale of units- price per unit						$17.27
Partners' Capital Account, Units, Sold in Public Offering						5,800,000
Proceeds From Issuance Of Common Limited Partner Units						$96,000,000
Hugoton [Member]
Equity [Line Items]
Number of limited partner units issued - acquisitions							1,500,000
Creek County [Member]
Equity [Line Items]
Number of limited partner units issued - acquisitions								2,214,659

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, 2014	Aug. 11, 2014	15-May-14	Feb. 14, 2014	Nov. 14, 2013	Aug. 14, 2013	14-May-13	Feb. 14, 2013	Dec. 31, 2014	Dec. 31, 2013
Equity [Abstract]
Date Paid	14-Nov-14	11-Aug-14	15-May-14	14-Feb-14	14-Nov-13	14-Aug-13	14-May-13	14-Feb-13
Period Covered	July 1, 2014 - September 30, 2014	April 1, 2014 - June 30, 2014	January 1, 2014 - March 31, 2014	October 1, 2013 - December 31, 2013	July 1, 2013 - September 30, 2013	April 1, 2013 - June 30, 2013	January 1, 2013 - March 31, 2013	October 1, 2012 - December 31, 2012
Distribution per Unit	$0.52	$0.52	$0.52	$0.52	$0.52	$0.52	$0.51	$0.50
Total Distribution	$12,204	$11,066	$11,032	$10,262	$10,119	$10,123	$9,891	$9,697	$44,564	$39,830

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (Mid-Con Energy Operating [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Mid-Con Energy Operating [Member]
Related Party Transaction [Line Items]
Direct administrative expenses incurred and reimbursed to related party	$3.80	$3.60	$2.90
Other transactions of related party	4	3
Payment of joint interest billing	3.2	2.2
Payment of operating services	$0.80	$0.80

Credit_Risk_Additional_Informa

Credit Risk - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	40.00%	50.00%	32.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Coffeyville [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	26.00%	23.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	9.00%
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%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Enterprise [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	14.00%	46.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Coffeyville [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	25.00%	30.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Plains Marketing LP [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	6.00%
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%

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail)	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Approved and authorized awards	1,764,000
Units available for Issuance	727,714

Subsequent_Events_Additional_I

Subsequent Events - Additional Information (Detail) (USD $)	0 Months Ended	12 Months Ended
In Millions, except Share data, unless otherwise specified	Jan. 23, 2015	Dec. 31, 2014	Jan. 26, 2015
Subsequent Event [Member]
Subsequent Event [Line Items]
Cash distribution for the fourth quarter	$0.13
Cash distribution on annualized basis	$0.50
Distribution to unitholders	$3.80
Proceeds From Cash Settlements Early Termination of Derivative Commodity Contracts Net	11.1
Derivative Deferred Premium Liability			4.1
Restricted and Unrestricted Common Units | Subsequent Event [Member]
Subsequent Event [Line Items]
Vesting period	2 years
Restricted Common Units [Member]
Subsequent Event [Line Items]
Vesting period		3 years
Restricted Common Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Common units authorized for issuance	29,800
Vesting period	3 years
Period Covered-2015 | Subsequent Event [Member]
Subsequent Event [Line Items]
Total Bbls Hedged/day			1,065,000
Weighted Average Fixed Price	75.62
Derivative Deferred Premium To Be Paid	2
Period Covered-2016 | Subsequent Event [Member]
Subsequent Event [Line Items]
Total Bbls Hedged/day			810,000
Weighted Average Fixed Price	70.01
Derivative Deferred Premium To Be Paid	$2.10
Share-based Compensation Award, Tranche One [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	33.00%
Share-based Compensation Award, Tranche One [Member] | Restricted and Unrestricted Common Units | Subsequent Event [Member]
Subsequent Event [Line Items]
Common units authorized for issuance	202,000
Share-based Compensation Award, Tranche Two [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	66.00%
Share-based Compensation Award, Tranche Two [Member] | Restricted and Unrestricted Common Units | Subsequent Event [Member]
Subsequent Event [Line Items]
Common units authorized for issuance	268,000

Supplementary_Information_Sche

Supplementary Information - Schedule of Quarterly Data (Detail) (USD $)	3 Months Ended												12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Oil and natural gas sales	$24,596		$26,173		$24,335		$21,807		$21,468	$22,982	$21,110	$20,176
Net settlements on derivatives	4,644		-760		-2,072		-921		199	-1,293	709	673	891	288	3,710
Gain (loss) on unsettled derivatives, net	22,376		10,040		-2,819		-1,127		371	-5,501	960	-1,793	28,470	-5,963	2,004
Total revenues	51,616		35,453		19,444		19,759		22,038	16,188	22,779	19,056	126,272	80,061	67,275
Total expenses	51,534	[1]	18,451	[1]	15,597	[1]	18,198	[1]	12,703	11,931	12,241	14,997	99,062	48,599	35,659
Net income (loss)	$82		$17,002		$3,847		$1,561		$9,335	$4,257	$10,538	$4,059	$22,492	$28,189	$29,862
Net income per limited partner unit (basic)	$0		$0.75		$0.18		$0.08		$0.47	$0.22	$0.54	$0.21	$0.98	$1.44	$1.62
Net income per limited partner unit (diluted)	$0		$0.74		$0.18		$0.08		$0.47	$0.22	$0.54	$0.21	$0.98	$1.44	$1.62
[1]	Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative, and net other expense.

Supplementary_Information_Supp

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Property acquisition costs:
Proved	$241,355	$28,057	$48,578
Unproved	0	0	0
Exploration	0	0	0
Development	34,320	22,287	21,639
Asset retirement obligations	3,171	879	679
Total costs incurred	$278,846	$51,223	$70,896

Supplementary_Information_Chan

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
	MBbls		MBbls		MMcf
	MMcf		MMcf		MBoe
	MBoe		MBoe		MBbls
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]
Beginning balance, Oil	13,714		13,074		9,936
Revisions of previous estimates	211		264		-784
Extensions, discoveries and other additions, Oil	1,241		76		1,572
Purchases of minerals in place, Oil	8,086		1,207		3,028
Production, Oil	-1,112		-907		-678
Ending balance, Oil	22,140		13,714		13,074
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Beginning balance, Gas	1,321		429		676
Revisions of previous estimates Gas	924		827		-143
Extensions, discoveries and other additions, Gas	52		0		0
Purchases of minerals in place, Gas	4,402		193		18
Production, Gas	-157		-128		-122
Ending balance, Gas	6,542		1,321		429
Proved Developed and Undeveloped Reserves, Oil and Gas Reserves [Roll Forward]
Beginning balance	13,934	[1]	13,146	[1]	10,049	[1]
Revisions of previous estimates	364	[1]	401	[1]	-808	[1]
Extensions, discoveries and other additions	1,250	[1]	76	[1]	1,572	[1]
Purchases of minerals in place	8,820	[1]	1,239	[1]	3,031	[1]
Production	-1,138	[1]	-928	[1]	-698	[1]
Ending balance	23,230	[1]	13,934	[1]	13,146	[1]
Proved developed reserves, Oil	17,046		10,397		8,727
Proved undeveloped reserves, Oil	5,094		3,317		4,347
Proved developed reserves, Gas	5,327		1,321		429
Proved undeveloped reserves, Gas	1,215		0		0
Proved developed reserves	17,933	[1]	10,617	[1]	8,799	[1]
Proved undeveloped reserves	5,297	[1]	3,317	[1]	4,347	[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 $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Extractive Industries [Abstract]
Future cash inflows	$2,084,005	$1,295,435	$1,191,410
Future production costs	-825,318	-542,389	-417,362
Future development costs, including abandonment costs	-76,783	-49,458	-47,490
Future net cash flow	1,181,904	703,588	726,558
10% discount for estimated timing of cash flow	-517,627	-312,325	-323,136
Standardized measure of discounted cash flow	$664,277	$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, 2014	Dec. 31, 2013	Dec. 31, 2012
Changes in the year resulting from:
Standardized measure of discounted future net cash flow, beginning of period	$391,263	$403,422	$328,231
Sales, less production costs	-64,495	-65,553	-48,648
Revisions of previous quantity estimates	11,712	12,006	-26,796
Extensions, discoveries and improved recovery	44,727	1,863	51,098
Net change in prices and production costs	22,068	-28,324	-15,328
Net change in income taxes	0	0	0
Changes in estimated future development costs	-18,125	-17,155	-11,515
Previously estimated development costs incurred during the period	22,526	22,257	21,629
Purchases of minerals in place	264,921	38,170	81,602
Accretion of discount	39,126	40,342	32,823
Timing differences and other	-49,446	-15,765	-9,674
Standardized measure of discounted future net cash flow, end of year	$664,277	$391,263	$403,422

Supplementary_Information_Addi

Supplementary Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	94.99	96.78	94.71
Average adjusted prices utilized in calculating proved reserves	92.45	93.98	91.03
Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Prices utilized in calculating proved reserves	4.35	3.67	2.75
Average adjusted prices utilized in calculating proved reserves	5.67	5	2.87