Mid-Con Energy Partners (MCEP) 10-K 29 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 29, 2016	Jun. 30, 2015
Entity Information [Line Items]
Entity Registrant Name	Mid-Con Energy Partners, LP
Entity Central Index Key	1,527,709
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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		29,786,710
Entity Public Float			$ 107.8
General Partner Units [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		360,000

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 615	$ 3,232
Accounts receivable:
Oil and natural gas sales	4,551	8,051
Other	5,009	4,070
Derivative financial instruments	24,419	26,202
Prepaids and other	623	652
Total current assets	35,217	42,207
Oil and natural gas properties, successful efforts method:
Proved properties	518,916	501,191
Accumulated depletion, depreciation, amortization and impairment	(232,008)	(93,896)
Total property and equipment, net	286,908	407,295
Derivative financial instruments	1,144	842
Other assets	3,817	4,284
Total assets	327,086	454,628
Accounts payable:
Trade	3,185	3,630
Related parties	559	3,989
Accrued liabilities	165	397
Current maturities of long-term debt	30,000	0
Total current liabilities	33,909	8,016
Other long-term liabilities	0	107
Long-term debt	150,000	205,000
Asset retirement obligations	$ 12,679	$ 7,363
Commitments and contingencies
Partnership equity:
General partner interest	$ 47	$ 1,328
Limited partners-29,724,890 and 29,166,112 units issued and outstanding as of December 31, 2015 and 2014, respectively	130,451	232,814
Total equity	130,498	234,142
Total liabilities and equity	$ 327,086	$ 454,628

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Limited partners, units issued	29,724,890	29,166,112
Limited partners, units outstanding	29,724,890	29,166,112

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Oil sales	$ 72,520	$ 96,127	$ 85,080
Natural gas sales	1,394	784	656
Gain (loss) on derivatives, net	22,366	29,361	(5,675)
Total revenues	96,280	126,272	80,061
Operating costs and expenses:
Lease operating expenses	33,591	26,091	16,366
Oil and natural gas production taxes	3,487	6,325	3,817
Impairment of proved oil and natural gas properties	103,938	30,206	1,578
Depreciation, depletion and amortization	34,174	21,877	14,421
Accretion of discount on asset retirement obligations	432	250	173
General and administrative	9,411	14,313	12,244
Total operating costs and expenses	185,033	99,062	48,599
Income (loss) from operations	(88,753)	27,210	31,462
Other income (expense):
Interest income and other	558	13	9
Interest expense	(7,258)	(4,731)	(3,282)
Loss on settlement of ARO	(42)	0	0
Total other expense	(6,742)	(4,718)	(3,273)
Net income (loss)	(95,495)	22,492	28,189
Computation of net income per limited partner unit:
General partner's interest in net income (loss)	(1,146)	354	518
Limited partners' interest in net income (loss)	$ (94,349)	$ 22,138	$ 27,671
Net income (loss) per limited partner unit:
Basic (in dollars per share)	$ (3.18)	$ 0.98	$ 1.44
Diluted (in dollars per share)	$ (3.18)	$ 0.98	$ 1.44
Weighted average limited partner units outstanding:
Limited partner units (basic)	29,642	22,499	19,234
Limited partner units (diluted)	29,642	22,518	19,249

Consolidated Statements of Cash

Consolidated Statements of Cash Flows $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Cash Flows from Operating Activities:
Net income (loss)	$ (95,495)	$ 22,492	$ 28,189
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, depletion and amortization	34,174	21,877	14,421
Debt issuance costs amortization	1,156	348	168
Accretion of discount on asset retirement obligations	432	250	173
Impairment of proved oil and natural gas properties	103,938	30,206	1,578
Loss on settlement of ARO	42	0	0
Cash paid for settlements of ARO	(82)	0	0
(Gain) loss on derivatives, net	(22,366)	(29,361)	5,675
Cash settlements received for matured derivatives	28,543	891	288
Cash settlements received for early terminations and modifications of derivatives, net	11,069	0	0
Cash premium paid for derivatives, net	(15,765)	0	0
Non-cash equity-based compensation	3,204	7,394	6,376
Changes in operating assets and liabilities:
Accounts receivable	3,500	(1,273)	(365)
Other receivables	(566)	(3,966)	499
Prepaids and other	29	(461)	(526)
Accounts payable and accrued liabilities	(3,388)	2,067	158
Net cash provided by operating activities	48,425	50,464	56,634
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(13,893)	(33,969)	(22,366)
Acquisitions of oil and natural gas properties	(1)	(155,354)	(28,057)
Net cash used in investing activities	(13,894)	(189,323)	(50,423)
Cash Flows from Financing Activities:
Proceeds from line of credit	28,000	168,000	105,000
Payments on line of credit	(53,000)	(75,000)	(71,000)
Issuance of limited partner units, net of offering costs	0	96,010	0
Offering costs	(194)	0	0
Distributions paid	(11,266)	(44,564)	(39,830)
Debt issuance costs	(688)	(3,789)	0
Net cash (used in) provided by financing activities	(37,148)	140,657	(5,830)
Net (decrease) increase in cash and cash equivalents	(2,617)	1,798	381
Beginning cash and cash equivalents	3,232	1,434	1,053
Ending cash and cash equivalents	615	3,232	1,434
Supplemental Cash Flow Information:
Cash paid for interest	6,070	4,600	2,803
Non-Cash Investing and Financing Activities:
Accrued capital expenditures - oil and natural gas properties	716	1,277	926
Common units issued - acquisition of oil properties	$ 0	$ 86,001	$ 0

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Thousands	Total	General Partner [Member]	Limited Partner [Member]
Balance at Dec. 31, 2012	$ 72,181	$ 1,814	$ 70,367
Balance, units at Dec. 31, 2012			18,991
Equity-based compensation	6,248	115	$ 6,133
Equity-based compensation, Units			328
Issuance of limited partner units, net of offering costs	0
Offering costs	0
Distributions	(39,830)	(731)	$ (39,099)
General partner's interest in net income (loss)	518	518
Limited partners' interest in net income (loss)	27,671		27,671
Net income (loss)	28,189
Balance at Dec. 31, 2013	66,788	1,716	$ 65,072
Balance, Units at Dec. 31, 2013			19,319
Equity-based compensation	7,415		$ 7,415
Equity-based compensation, Units			332
Issuance of limited partner units - acquisitions	86,001		$ 86,001
Issuance of limited partner units - acquisitions, Units			3,715
Issuance of limited partner units, net of offering costs	96,010		$ 96,010
Issuance of limited partner units, net of offering costs, Units			5,800
Offering costs	0
Distributions	(44,564)	(742)	$ (43,822)
General partner's interest in net income (loss)	354	354
Limited partners' interest in net income (loss)	22,138		22,138
Net income (loss)	22,492
Balance at Dec. 31, 2014	234,142	1,328	$ 232,814
Balance, Units at Dec. 31, 2014			29,166
Equity-based compensation	3,311		$ 3,311
Equity-based compensation, Units			559
Issuance of limited partner units, net of offering costs	0
Offering costs	(194)		$ (194)
Distributions	(11,266)	(135)	(11,131)
General partner's interest in net income (loss)	(1,146)	(1,146)
Limited partners' interest in net income (loss)	(94,349)		(94,349)
Net income (loss)	(95,495)
Balance at Dec. 31, 2015	$ 130,498	$ 47	$ 130,451
Balance, Units at Dec. 31, 2015			29,725

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2015
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 limited partner units ("common units") are traded on the NASDAQ under the symbol “MCEP.” Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Reclassifications The consolidated financial statements for previous periods include certain reclassifications to the derivative accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported total assets, net income (loss) or total operating cash flows. Liquidity and Capital Resources Our ability to finance our operations, fund our capital expenditures and acquisitions, meet or refinance our debt obligations and meet our collateral requirements will depend on our future cash flows. Our ability to generate cash is subject to a number of factors, some of which are beyond our control, including weather, oil and natural gas prices, operating costs and maintenance capital expenditures, as well as general economic, financial, competitive, legislative, regulatory and other factors. Our primary use of cash has been for debt reduction and to fund capital spending. Oil prices have fallen to twelve-year lows, impacting the way we conduct business. We have implemented a number of adjustments for the upcoming year to strengthen our financial position. In addition to increasing revenue security during 2016 and 2017 by executing additional commodity derivative contracts in November 2015 and restructuring our commodity derivative contracts in January 2015 to provide greater oil price protection over a longer period of time, we suspended our quarterly cash distributions in October 2015. We are also aggressively pursuing costs reductions in order to improve profitability and maximize cash flows. Our primary cost reduction initiatives encompass periodic economic review of each well within our portfolio along with ongoing scrutiny of lease operating expenses and general and administrative expenses. Our liquidity position at December 31, 2015 consisted of approximately $0.6 million of available cash, and $7.5 million of available borrowings under our revolving credit facility. Our borrowing base is re-determined on or about April 30 and October 31 of each year. During the November 2015 redetermination, our borrowing base was reduced from $220.0 million to $190.0 million , consisting of a $165.0 million conforming tranche which requires monthly commitment reductions of $2.5 million each month through May 2016 and a $25.0 million non-conforming tranche. The non-conforming tranche matures May 1, 2016, requiring our outstanding debt balance to be paid down to $150.0 million at that time. As of December 31, 2015, the mark-to-market value of our net derivative financial instruments totaled $25.6 million . If necessary, the value of our net derivative financial instruments could be monetized and or combined with a portion of operating cash flows to satisfy debt maturities in 2016. Preliminary conversations with our lenders suggest the Partnership will not be compelled to monetize hedges to reduce debt during the upcoming spring 2016 bi-annual borrowing base redetermination. At this time, it appears more likely that the Partnership and its lenders will reach an accommodation comparable to the one reached by these same participant parties during our fall 2015 bi-annual borrowing base redetermination. Based on our cash balance, forecasted cash flows from operating activities, ability to monetize our hedges, if necessary, and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures budget, meet our debt service requirements, and fund our other commitments and obligations in 2016. Although we currently expect our sources of cash to be sufficient to meet our near-term liquidity needs, there can be no assurance that the lenders under our revolving credit facility will not reduce the borrowing base to an amount below our outstanding borrowings or that our liquidity requirements will continue to be satisfied, given current oil prices and the discretion of our lenders to decrease our borrowing base. Due to the steep decline in commodity prices, we may not be able to obtain funding in the equity or capital markets on terms we find acceptable. The cost of obtaining money from the credit markets generally has increased as many lenders and institutional investors have increased interest rates, enacted tighter lending standards, and reduced and, in some cases, ceased to provide any new funding.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2015, 2014 and 2013. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our subsidiary is Mid-Con Energy Properties. 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. Depletion and impairment of oil and natural gas properties, in part, are 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 oil and natural 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 and fair value of derivative financial instruments. Cash and cash equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents. Accounts receivable Accounts receivable 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 level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2015 and 2014, 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 natural 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, 2015 or 2014. 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 non-producing 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 depletion until the related project is completed. We had no significant costs excluded from depreciation during any of the periods presented. 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. 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 may be greater than management's estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimate quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. 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. These evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. Cash flow estimates for the impairment testing excludes derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices. 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. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal requires management to make estimates 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. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future asset retirement obligations on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. 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. 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. See Note 7 for additional information. Derivatives and hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives, namely swap, call and put contracts, to manage a portion of our exposure to commodity prices and specific delivery points. We enter into commodity derivative contracts and/or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information. We do not designate derivatives 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. 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. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding Derivative Financial Instruments. 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, net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. No compensation expense is recognized for equity instruments that do not vest. 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. Since our debt consists of a revolving credit facility, net debt placement costs are presented in "Other Assets" in our 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 (loss) per limited partner unit Basic net income (loss) per partner unit is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per partner unit reflects the potential dilution of non-vested restricted stock awards. For the year ended December 31, 2015, this potentially dilutive item was anti-dilutive due to the Company's net loss and, therefore, was excluded from the calculation of diluted net income (loss) per partner unit. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest: Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for annual reporting periods beginning after December 15, 2015, and Management does not believe this pronouncement impacts our consolidated financial statements and related disclosures. The guidance in ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements. The pronouncement confirms that fees related to line-of-credit arrangements are not addressed in ASU 2015-03. Deferred initial up-front commitment fees paid by a borrower to a lender represent the benefit of being able to access capital over the contractual term, and therefore, meet the definition of an asset, while debt issuance costs in the scope of ASU 2015-03 do not. We will continue to present such costs as an asset and subsequently amortize the costs over the term of our revolving credit facility.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
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. 2014 Acquisitions 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 $117.1 million after 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. During 2015, we finalized our acquisition accounting for these properties and adjusted the fair value of the assets acquired and liabilities assumed from $117.6 million to $117.1 million after applying the corresponding post-closing purchase price adjustments. The following table summarize the final calculations of the fair values of the assets acquired and liabilities assumed for these properties (in thousands): Final Estimated At December 31, 2014 Change Fair value of net assets: Oil properties $ 118,906 $ 119,438 $ (532 ) Total assets acquired $ 118,906 $ 119,438 $ (532 ) Fair value of net liabilities assumed: Asset retirement obligation 1,851 1,851 — Fair value of net assets acquired $ 117,055 $ 117,587 $ (532 ) 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 final 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 interests 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 final 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 final 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 statements of operations since we took over operations mid-November. We took over the interests at August 1, 2014 for the Creek County property, therefore the values for August and September 2014 are included in the consolidated statements of operations. We took over the interests at February 28, 2014 for the Hugoton properties, therefore the values for March 2014 through September 2014 are reflected in the consolidated statements 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, 2015
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, 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. 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 Board of Directors of the general partner recommended for approval and, on November 20, 2015, the common unitholders approved an amendment to the Long-Term Incentive Program that increased the number of common units available for issuance under the program from 1,764,000 to 3,514,000 common units. The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2015: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,113,374 ) Restricted units granted, net of forfeitures (433,857 ) Equity-settled phantom units, net of forfeitures (100,500 ) Phantom units issued, net of forfeitures (22,166 ) Awards available for future grant 1,844,103 We recognized $3.2 million, $7.7 million and $6.6 million of total equity-based compensation expense for the years ended December 31, 2015, 2014 and 2013, respectively. These costs are reported as a component of general and administrative expense in our consolidated statements of operations. Unrestricted awards During 2015, we granted 274,550 unrestricted units with an average grant date fair value of $4.85 per unit. We account for unrestricted awards as equity awards since they are settled by issuing common units. Restricted Awards We account for restricted awards as equity awards since they will be settled by issuing common units. These units vest over a two or three year period. The compensation expense we recognize associated with our restricted stock is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. A summary of our restricted units awarded for the years ended December 31, 2015 and 2014 is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit 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 Units granted 294,100 $ 5.04 Units vested (148,195 ) $ 12.43 Units forfeited (32,872 ) $ 9.28 Outstanding at December 31, 2015 222,833 $ 8.49 During 2015, we granted 268,000 restricted common units with one-third vesting immediately and the other two-thirds vesting over two years, with an average grant date fair value of $5.06 per unit. We also granted 26,100 restricted common units with a three year vesting period and average grant date fair value of $4.88 per unit. As of December 31, 2015, there was approximately $0.9 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 1.1 years . Equity-settled phantom awards In July 2015, we granted 69,000 equity-settled phantom units with one-third vesting immediately and the other two-thirds vesting over two years, and 46,500 equity-settled phantom units with a three year vesting period. The equity-settled phantom units do not have any rights or privileges of a common unitholder, including right to distributions, until vesting and the resulting conversion into common units. These equity-settled phantom awards were granted to certain employees of our affiliates and certain directors and founders of our general partner. We account for equity-settled phantom awards as equity awards since they will be settled by issuing common units. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. For the year ended December 31, 2015, we recorded approximately $41,000 of compensation expense. A summary of our equity-settled phantom units awarded for the year ended December 31, 2015 is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 — $ — Units granted 115,500 $ 2.87 Units vested (23,000 ) $ 3.12 Units forfeited (15,000 ) $ 2.81 Outstanding at December 31, 2015 77,500 $ 2.81 As of December 31, 2015, there was approximately $0.2 million of unrecognized compensation costs related to equity-settled phantom units. The cost is expected to be recognized over a weighted average period of approximately 2.0 years. Phantom awards We accounted for phantom units issued in July 2013 as a liability award since these awards could have been settled in either cash or common units. The vesting of the phantom units was subject to the attainment of certain production targets during a period of three years. These units were not eligible to receive quarterly distributions. In December 2015, we wrote-off approximately $0.1 million in deferred liability associated with the phantom units since the remaining production targets are not anticipated to be achieved during the specific vesting period.

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Our risk management program is intended to reduce our exposure to commodity price volatility 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. At December 31, 2015 and 2014, our net commodity derivative contracts were in a net asset position with a fair value of approximately $25.6 million and $27.0 million, respectively. All of our commodity derivative contracts are with major financial institutions that are also members of our banking group. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss. During the three years ended December 31, 2015, all of our counterparties have performed pursuant to their commodity derivative contracts. At December 31, 2015, our commodity derivative contracts had maturities in 2016 and 2017 and were comprised of commodity price swap, call and put contracts. At December 31, 2014, our commodity derivative contracts had maturities in 2015 and 2016 and were comprised of commodity price swap contracts. For commodity price swap contracts, at the time of execution the seller agrees to receive a fixed price at maturity in exchange for any gains or losses that might be realized from allowing the price of the underlying to float with the market until maturity. From the perspective of the seller, these instruments limit exposure to price declines below the price fixed by the swap at the expense of participating in any price increases above the price fixed by the swap. For commodity price call contracts, in return for a premium received at execution the seller is obliged to pay the difference, when positive, between the market price of the underlying at maturity less the strike price. From the perspective of the seller, these instruments provide income via the premium received at the expense of any incremental gains that would have otherwise been received above the strike price. For commodity price put contracts, in return for a premium paid, which can be effected at either execution or settlement, the purchaser has the right to receive the the difference, when positive, between the strike price and the market price of the underlying at maturity. From the perspective of the purchaser, these instruments limit exposure to price declines below the strike price at the expense of premiums paid. A collar is a combination of a put purchased or sold by a party and a call option sold or purchased by the same party. We do not designate derivatives 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. 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. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. Pursuant to the accounting standard that permits netting of assets and liabilities where the right of offset exists, we present the fair value of commodity derivative contracts on a net basis. At December 31, 2015, we had the following oil derivatives net positions: Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2016 $ 79.98 1,598 WTI Collars - 2016 $ 50.00 $ 50.00 328 WTI Puts - 2016 $ 50.00 $ — 1,475 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI At December 31, 2014, we had the following oil derivative net positions: Period Covered Weighted Average Fixed Price Total Bbls Hedged/day NYMEX Index Swaps - 2015 $ 93.29 1,932 WTI Swaps - 2016 $ 90.20 82 WTI During the first quarter of 2015, we restructured a significant portion of our existing commodity derivative contracts 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 commodity derivative contracts which extend through September 2016. In connection with the early termination and modifications of our commodity derivative contracts, we received net proceeds of approximately $11.1 million from the early termination of contracts on January 22 and 23, 2015, received approximately $5.9 million from selling calls and paid out approximately $19.8 million in premiums to extend the contracts through September 2016. The restructuring also resulted in approximately $4.1 million in deferred premium put options. As of December 31, 2015, we had paid $1.9 million of the deferred put premiums in connection with contract settlements. These transactions provided an additional $23.8 million of cash flow for 2015. In connection with the November 2015 semi-annual redetermination of our borrowing base, we entered entered into additional commodity derivative contracts resulting in total commodity derivative contracts covering at least 80% of our 2016 projected monthly production and at least 50% of our 2017 projected monthly production. No cash settlements were required and the contracts included deferred premiums of approximately $10.0 million. Commodity derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require our counterparties to our commodity 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. As of December 31, 2015, the counterparties to our commodity 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 commodity derivative contracts are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2015 and 2014 (in thousands): Gross Gross Amounts Net Amounts 2015 Assets Derivative financial instruments - current asset $ 29,973 $ (5,554 ) $ 24,419 Derivative financial instruments - long-term asset 6,077 (4,933 ) 1,144 Total $ 36,050 $ (10,487 ) $ 25,563 Liabilities Derivative financial instruments - current liability $ (514 ) $ 514 $ — Derivative deferred premium - current liability (5,040 ) 5,040 — Derivative financial instruments - long-term liability — — — Derivative deferred premium - long-term liability (4,933 ) 4,933 — Total $ (10,487 ) $ 10,487 $ — Net asset $ 25,563 $ — $ 25,563 Gross Gross Amounts Net Amounts 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 The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations (in thousands): Year Ended December 31, 2015 2014 2013 Net settlements on matured derivatives $ 28,543 $ 891 $ 288 Net settlements on early terminations and modifications of derivatives 11,069 — — Change in fair value of unsettled derivatives, net (17,246 ) 28,470 (5,963 ) Total gain (loss) on derivatives, net $ 22,366 $ 29,361 $ (5,675 )

Fair Value Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Fair Value Disclosures Fair Value of Financial Instruments The carrying amounts reported in our balance sheet for cash, accounts receivable and accounts payable approximate their fair values. The carrying amount of 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 commodity derivative contracts at fair value. The fair value of our commodity derivative contracts is determined utilizing NYMEX-WTI 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. We consider active markets to be those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an on-going basis. 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 2 instruments primarily include swap, call and put contracts. 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, 2015, 2014 and 2013. Assets and Liabilities Measured at Fair Value on a Recurring Basis We account for commodity derivative contracts and their corresponding deferred premiums at fair value on a recurring basis. We use certain pricing models to determine the fair value of our derivative financial instruments. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. See Note 5 in this section for a summary of our derivative financial instruments. Assets and Liabilities Measured at Fair Value on a Non-recurring Basis We estimate the fair value of ARO based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 7 in this section for a summary of changes in ARO. We calculate the estimated fair values of reserves and properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of: (i) reserves; (ii) future operating and developmental costs; (iii) future commodity prices; (iv) a market-based weighted average cost of capital rate; and (v) the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows are the product of a process that begins with Level 1 NYMEX WTI forward curve pricing, as well as Level 3 assumptions including: pricing adjustments for estimated location and quality differentials, production costs, capital expenditures, production volumes, decline rates and estimated reserves. For the years ended December 31, 2015 and 2014, we recorded non-cash impairment charges of approximately $103.9 million and $30.2 million, respectively, associated with proved oil and natural gas properties throughout our core areas reducing the carrying value of certain properties. The impairment was primarily due to a continued decline in commodity prices. The impairment charges are included in "Impairment of proved oil and natural gas properties" in our consolidated statements of operations. In late 2014, prices for oil, natural gas and NGLs declined precipitously and continued to remain low through December 2015. Forward NYMEX WTI price curves have declined from year ended 2014 to 2015. 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, 2015 and 2014: Level 1 Level 2 Level 3 Fair Value (in thousands) December 31, 2015 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments- asset $ — $ 36,050 $ — $ 36,050 Derivative financial instruments- liability — (514 ) — (514 ) Derivative deferred premiums - liability — — (9,973 ) (9,973 ) Net derivative position $ — $ 35,536 $ (9,973 ) $ 25,563 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Asset retirement obligations $ — $ — $ 4,924 $ 4,924 Impairment of proved oil and gas properties $ — $ — $ 103,938 $ 103,938 December 31, 2014 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments- asset $ — $ 27,044 $ — $ 27,044 Derivative financial instruments- liability — — — — Net derivative position $ — $ 27,044 $ — $ 27,044 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Asset retirement obligations $ — $ — $ 3,171 $ 3,171 Impairment of proved oil and gas properties $ — $ — $ 30,206 $ 30,206 A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, 2015 2014 (in thousands) Balance of Level 3 at beginning of period $ — $ — Derivative deferred premiums - purchases (11,914 ) — Derivative deferred premiums - settlements 1,941 — Balance of Level 3 at end of period $ (9,973 ) $ — 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, 2015 and 2014.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
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 are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well and determine our ARO by calculating the present value of estimated cash flow related to the estimated future liability. Determining the future restoration and removal requires management to make estimates 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. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future asset retirement obligations on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. 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. Over time, the liability is accreted each period toward its future value and is recorded in our consolidated statements 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. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability. Changes in our asset retirement obligations for the periods indicated are presented in the following table: Year Ended December 31, 2015 2014 2013 (in thousands) Asset retirement obligations - beginning of period $ 7,363 $ 3,942 $ 2,890 Liabilities incurred for new wells and interest 42 3,171 1,009 Liabilities settled upon plugging and abandoning wells (40 ) — — Revision of estimates (1) 4,882 — (130 ) Accretion expense 432 250 173 Asset retirement obligations - end of period $ 12,679 $ 7,363 $ 3,942 (1) The revision of estimates that occurred during the year ended December 31, 2015 is primarily due to a change in estimated plugging and abandonment costs based on recent settlements. As of December 31, 2015 and 2014, all of our ARO were classified as long-term and were reported as "Asset Retirement Obligations" in our consolidated balance sheets.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Debt A summary of our debt for the year ended December 31, 2015 is presented below: Year Ended December 31, 2015 2014 (in thousands) Revolving credit facility $ 180,000 $ 205,000 Less: current portion 30,000 — Total long-term debt $ 150,000 $ 205,000 At December 31, 2015, we had $180.0 million of borrowings outstanding under our revolving credit facility. Borrowings under the revolving credit facility did not exceed the borrowing base of $187.5 million at December 31, 2015. Borrowings under the facility are secured by liens on not less than 90% of our assets and the assets of our subsidiaries. Our debt consists of $30.0 million classified as current and $150.0 million classified as long-term. At December 31, 2015, maturities of our debt were as follows: $30.0 million in 2016 and $150.0 million in 2018. The borrowing base of our revolving credit facility is collectively determined by our 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, either at our request or at the request of the lender, during the period between each scheduled borrowing base determinations. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election: (i) the greater of the prime rate of the Wells Fargo Bank, National Association, 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 1.00% to 2.75% 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 2.00% to 3.75% per annum according to the borrowing base usage. For the year ended December 31, 2015, the average effective rate was approximately 3.0% . 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. 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. During February 2015, the revolving credit facility was amended to allow our Consolidated 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. During the semi-annual redetermination in April 2015, the borrowing base under the revolving credit facility was reduced to $220.0 million from $240.0 million. No other material terms of the original credit agreement were amended. During November 2015, the semi-annual redetermination of our borrowing base and amendment of the underlying revolving credit facility was completed. This redetermination resulted in a borrowing base of $190.0 million, consisting of a $165.0 million conforming tranche to which six monthly commitment reductions of $2.5 million each were mandated through May 2016, and a $25.0 million non-conforming tranche that matures on May 1, 2016. The credit facility amendment also designated Wells Fargo Bank, National Association, as our administrative and collateral agent, replacing Royal Bank of Canada. This redetermination also required that by December 10, 2015, we enter into commodity derivative contracts of not less than 80% of our 2016 projected monthly production and not less than 50% of our 2017 projected monthly production. These requirements were satisfied during November 2015 with the execution of additional commodity derivative contracts maturing in 2016 and 2017. As of February 29, 2016, debt has been reduced by $7.0 million, from the December 31, 2015 balance, and the outstanding balance at this date was $173.0 million. 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. In connection with this amendment to our revolving credit facility, we incurred financing fees and expenses of approximately $0.7 million, which will be amortized over the remaining 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, including distributions. 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, 2015.

Commitment and Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2015
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 and our General Counsel, 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, President and Chief Executive Officer and Charles R. Olmstead, Executive Chairman of the Board of our general partner. 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 would 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 $0.3 million to $0.7 million , including the value of vesting of any outstanding units.

Equity

Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity	Equity Common Units At December 31, 2015, the Partnership's equity consisted of 29,724,890 common units, representing approximately 98.8% in limited partnership interest in us. 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. On May 5, 2015, we entered into an Equity Distribution Agreement (the “Agreement”) to sell, from time to time through or to the Managers (as defined in the Agreement), up to $50.0 million in common units representing limited partner interests. The sales, if any, of common units made under the Agreement will be made by any method permitted by law deemed to be an "at-the-market-offering" as defined in Rule 415 under the Securities Act of 1933, as amended (the "Securities Act"), including without limitation, sales made directly on the NASDAQ, on any other existing trading market for our common units or to or through a market maker. From the period of the original agreement to December 31, 2015, we did not sell any common units. Cash Distributions 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. There is not assurance as to the future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors. Our credit agreement stipulates written consent from our lenders is required in order to reinstate distributions and also prohibits us from making cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution. Prolonged declines in commodity prices prompted us to suspend cash distributions in an effort to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. In October 2015 and January 2016, the Board of Directors suspended the quarterly cash distributions for the third and fourth quarter of 2015, respectively. Management and the Board of Directors will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The following sets forth the distributions we paid during the years ended December 31, 2015 and 2014: Distribution Total Date Paid Period Covered per Unit Distributions February 13, 2015 October 1, 2014 - December 31, 2014 $ 0.125 $ 3,752 May 14, 2015 January 1, 2015 - March 31, 2015 $ 0.125 3,752 August 13, 2015 April 1, 2015 - June 30, 2015 $ 0.125 3,762 $ 11,266 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 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, 2015
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, 2015, 2014 and 2013, we reimbursed Mid-Con Energy Operating approximately $3.7 million , $3.8 million and $3.6 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 overhead 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. At December 31, 2015, we had payables to Mid-Con Energy Operating of approximately $0.5 million which is comprised of a joint interest billing payable of approximately $0.1 million and a payable for operating services of approximately $0.4 million . 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. These amounts are included in the Accounts payable-related parties in our consolidated balance sheets.

Credit Risk

Credit Risk	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Credit Risk	Credit Risk Credit risk relates to the risk of loss resulting from non-performance of non-payment by counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. 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 2015, 2014 or 2013. For the year ended December 31, 2015, sales of oil and natural gas to BML, Enterprise and Coffeyville accounted for approximately 31% , 22% and 21% , respectively, of our totals sales revenues. These purchasers represent 32% , 18% and 23% , respectively, of our outstanding oil and natural gas accounts receivable at December 31, 2015. For the year ended December 31, 2014, sales of oil and natural gas to Enterprise, Coffeyville and Plains Marketing, LP accounted for approximately 40% , 26% and 9% , respectively, of our total 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, purchases by Enterprise, Coffeyville and National Cooperative Refinery Association accounted for approximately 50% , 23% and 8% , respectively of our total sales revenues. These purchasers represent 46% , 30% and 10% , respectively, of our outstanding oil and natural gas accounts receivable at December 31, 2013. We believe that the loss of any one purchaser would not have an adverse effect on our ability to sell its oil and natural gas production because we believe 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, 2015
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 Board of Directors of the general partner recommended for approval and, on November 20, 2015, the unitholders approved an amendment to the Long-Term Incentive Program that increased the number of common units available for issuance under the program from 1,764,000 to 3,514,000 common units. As of December 31, 2015 there were 1,844,103 units available for issuance.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
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, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On January 8, 2016, Nathan P. Pekar resigned from his position as General Counsel, Secretary and Vice President. Beginning January 18, 2016, Mr. Pekar began serving our general partner as a third party consultant. On January 21, 2016, the Board of Directors of our general partner reaffirmed the suspension of cash distributions for the fourth quarter of 2015. Also on January 21, 2016, the Board of Directors of our general partner authorized the issuance of 70,000 unrestricted common units, 24,500 equity-settled phantom units with one-third vesting immediately and the other two-thirds vesting over two years . The equity-settled phantom units do not have any rights or privileges of a unitholder, including right to distributions, until vesting and the resulting conversion into common units. These units were granted to certain employees of our affiliates and certain directors and founders of our general partner. As of February 29, 2016, debt has been reduced by $7.0 million from the December 31, 2015 balance, and the outstanding balance was $173.0 million.

Supplementary Information

Supplementary Information	12 Months Ended
	Dec. 31, 2015
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) 2015 Oil and natural gas sales $ 17,571 $ 21,611 $ 18,493 $ 16,239 Gain (loss) on derivatives, net $ 1,644 $ (8,871 ) $ 19,771 $ 9,822 Total revenues and other $ 19,215 $ 12,740 $ 38,264 $ 26,061 Total expenses (1) $ 23,327 $ 20,684 $ 63,742 $ 84,022 Net loss $ (4,112 ) $ (7,944 ) $ (25,478 ) $ (57,961 ) Net loss per limited partner unit (basic) $ (0.14 ) $ (0.26 ) $ (0.85 ) $ (1.93 ) Net loss per limited partner unit (diluted) $ (0.14 ) $ (0.26 ) $ (0.85 ) $ (1.93 ) 2014 Oil and natural gas sales $ 21,807 $ 24,335 $ 26,173 $ 24,596 Gain (loss) on derivatives, net $ (2,048 ) $ (4,891 ) $ 9,280 $ 27,020 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 $ — (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, 2015 2014 2013 (in thousands) Property acquisition costs: Proved $ 1 $ 241,355 $ 28,057 Unproved — — — Exploration — — — Development 13,415 34,320 22,287 Asset retirement obligations 4,924 3,171 879 Total costs incurred $ 18,340 $ 278,846 $ 51,223 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, 2015, 2014 and 2013 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) Proved developed and undeveloped reserves: 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 Revisions of previous estimates (2) 596 856 739 Extensions, discoveries and other additions — — — Purchases of minerals in place 1 — 1 Production (1,623 ) (571 ) (1,718 ) As of December 31, 2015 21,114 6,827 22,252 Proved developed reserves: December 31, 2013 10,397 1,321 10,617 December 31, 2014 17,046 5,327 17,933 December 31, 2015 14,368 4,762 15,162 Proved undeveloped reserves: December 31, 2013 3,317 — 3,317 December 31, 2014 5,094 1,215 5,297 December 31, 2015 6,746 2,065 7,090 (1) Estimated quantities of oil and natural gas reserves in MBoe equivalents at a rate of six Mcf per Bbl. (2) Includes revisions due to price product price changes and added reserves through EOR and infill drilling activities. Revisions represent changes in the previous reserves estimates, either upward or 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, 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. The change in quantities of proved reserves from December 31, 2014 to December 31, 2015 is due to (i) a significant commodity price decrease that resulted in a downward revision of 4,084 MBoe, (ii) improved recovery of 1,417 MBoe from our proved developed reserves in addition to 994 MBoe transferred from proved undeveloped reserves to proved developed reserves, and (iii) the addition of recompletions, infill drilling, new waterflood projects, and expansion of existing waterflood projects in our Hugoton, Northeast Oklahoma, Southern Oklahoma and Permian core areas resulting in a positive revision of proved undeveloped reserves of 3,405 MBoe. The upward revision of our proved developed reserves is largely attributable to a positive oil production response in 2015 to recently established water injection in the Cleveland Unit (Northeast Oklahoma), Ona Morrow Unit (Hugoton) and Midwell Unit (Hugoton). 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, 2015, 2014 and 2013, 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, 2015 2014 2013 (in thousands) Future cash inflows $ 1,011,096 $ 2,084,005 $ 1,295,435 Future production costs (581,314 ) (825,318 ) (542,389 ) Future development costs, including abandonment costs (109,669 ) (76,783 ) (49,458 ) Future net cash flow 320,113 1,181,904 703,588 10% discount for estimated timing of cash flow (128,693 ) (517,627 ) (312,325 ) Standardized measure of discounted cash flow $ 191,420 $ 664,277 $ 391,263 The prices utilized in calculating our total proved reserves were $50.28 , $94.99 and $96.78 per Bbl of oil and $2.58 , $4.35 and $3.67 per MMBtu of natural gas for December 31, 2015, 2014 and 2013, 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 $47.23 , $92.45 and $93.98 per Bbl of oil and $2.02 , $5.67 and $5.00 per Mcf of natural gas for December 31, 2015, 2014 and 2013, 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, 2015 2014 2013 (in thousands) Standardized measure of discounted future net cash flow, beginning of period $ 664,277 $ 391,263 $ 403,422 Changes in the year resulting from: Sales, less production costs (36,836 ) (64,495 ) (65,553 ) Revisions of previous quantity estimates 8,047 11,712 12,006 Extensions, discoveries and improved recovery — 44,727 1,863 Net change in prices and production costs (454,669 ) 22,068 (28,324 ) Net change in income taxes — — — Changes in estimated future development costs (6,080 ) (18,125 ) (17,155 ) Previously estimated development costs incurred during the period 8,103 22,526 22,257 Purchases of minerals in place 19 264,921 38,170 Accretion of discount 66,428 39,126 40,342 Timing differences and other (57,869 ) (49,446 ) (15,765 ) Standardized measure of discounted future net cash flow, end of year $ 191,420 $ 664,277 $ 391,263

Summary of Significant Accoun23

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2015, 2014 and 2013. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). Our subsidiary is Mid-Con Energy Properties. 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. Depletion and impairment of oil and natural gas properties, in part, are 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 oil and natural 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 and fair value of derivative financial instruments.
Cash and cash equivalents	Cash and cash equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.
Accounts receivable	Accounts receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2015 and 2014, 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 natural 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, 2015 or 2014.
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 non-producing 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 depletion until the related project is completed. We had no significant costs excluded from depreciation during any of the periods presented. 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. 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 may be greater than management's estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimate quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. 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. These evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. Cash flow estimates for the impairment testing excludes derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices. 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. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal requires management to make estimates 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. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future asset retirement obligations on an annual basis, or more frequently, if an event or circumstances occur that would impact our assumptions. 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. 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. See Note 7 for additional information.
Derivatives and hedging	Derivatives and hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives, namely swap, call and put contracts, to manage a portion of our exposure to commodity prices and specific delivery points. We enter into commodity derivative contracts and/or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Company nets the fair value of derivatives by counterparty where the right of offset exists. The Company determines the fair value of its derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information. We do not designate derivatives 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. 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. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding Derivative Financial Instruments.
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, net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. No compensation expense is recognized for equity instruments that do not vest.
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. Since our debt consists of a revolving credit facility, net debt placement costs are presented in "Other Assets" in our 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 (loss) per limited partner unit Basic net income (loss) per partner unit is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per partner unit reflects the potential dilution of non-vested restricted stock awards. For the year ended December 31, 2015, this potentially dilutive item was anti-dilutive due to the Company's net loss and, therefore, was excluded from the calculation of diluted net income (loss) per partner unit.
Recent Accounting Pronouncements	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. The Company is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest: Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs. The update requires debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of the related debt liability instead of being presented as an asset. Debt disclosures will include the face amount of the debt liability and the effective interest rate. The update requires retrospective application and represents a change in accounting principle. The update is effective for annual reporting periods beginning after December 15, 2015, and Management does not believe this pronouncement impacts our consolidated financial statements and related disclosures. The guidance in ASU 2015-03 does not address presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Presentation and subsequent measurement of debt issuance costs associated with line-of-credit arrangements. The pronouncement confirms that fees related to line-of-credit arrangements are not addressed in ASU 2015-03. Deferred initial up-front commitment fees paid by a borrower to a lender represent the benefit of being able to access capital over the contractual term, and therefore, meet the definition of an asset, while debt issuance costs in the scope of ASU 2015-03 do not. We will continue to present such costs as an asset and subsequently amortize the costs over the term of our revolving credit facility.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
Creek County [Member]
Business Acquisition [Line Items]
Acquisitions	The final 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 final 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
Cushing Properties [Member]
Business Acquisition [Line Items]
Acquisitions	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 statements of operations since we took over operations mid-November. We took over the interests at August 1, 2014 for the Creek County property, therefore the values for August and September 2014 are included in the consolidated statements of operations. We took over the interests at February 28, 2014 for the Hugoton properties, therefore the values for March 2014 through September 2014 are reflected in the consolidated statements 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 The following table summarize the final calculations of the fair values of the assets acquired and liabilities assumed for these properties (in thousands): Final Estimated At December 31, 2014 Change Fair value of net assets: Oil properties $ 118,906 $ 119,438 $ (532 ) Total assets acquired $ 118,906 $ 119,438 $ (532 ) Fair value of net liabilities assumed: Asset retirement obligation 1,851 1,851 — Fair value of net assets acquired $ 117,055 $ 117,587 $ (532 ) The final 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

Equity Awards (Tables)

Equity Awards (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,113,374 ) Restricted units granted, net of forfeitures (433,857 ) Equity-settled phantom units, net of forfeitures (100,500 ) Phantom units issued, net of forfeitures (22,166 ) Awards available for future grant 1,844,103
Summary of restricted units awarded	A summary of our restricted units awarded for the years ended December 31, 2015 and 2014 is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit 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 Units granted 294,100 $ 5.04 Units vested (148,195 ) $ 12.43 Units forfeited (32,872 ) $ 9.28 Outstanding at December 31, 2015 222,833 $ 8.49
Summary of Equity-Settled units awarded	A summary of our equity-settled phantom units awarded for the year ended December 31, 2015 is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 — $ — Units granted 115,500 $ 2.87 Units vested (23,000 ) $ 3.12 Units forfeited (15,000 ) $ 2.81 Outstanding at December 31, 2015 77,500 $ 2.81

Derivative Financial Instrume26

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Contracts	the fair value of commodity derivative contracts on a net basis. At December 31, 2015, we had the following oil derivatives net positions: Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2016 $ 79.98 1,598 WTI Collars - 2016 $ 50.00 $ 50.00 328 WTI Puts - 2016 $ 50.00 $ — 1,475 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI	At December 31, 2014, we had the following oil derivative net positions: Period Covered Weighted Average Fixed Price Total Bbls Hedged/day NYMEX Index Swaps - 2015 $ 93.29 1,932 WTI Swaps - 2016 $ 90.20 82 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 commodity derivative contracts are subject to netting arrangements and qualify for net presentation in our consolidated balance sheets at December 31, 2015 and 2014 (in thousands): Gross Gross Amounts Net Amounts 2015 Assets Derivative financial instruments - current asset $ 29,973 $ (5,554 ) $ 24,419 Derivative financial instruments - long-term asset 6,077 (4,933 ) 1,144 Total $ 36,050 $ (10,487 ) $ 25,563 Liabilities Derivative financial instruments - current liability $ (514 ) $ 514 $ — Derivative deferred premium - current liability (5,040 ) 5,040 — Derivative financial instruments - long-term liability — — — Derivative deferred premium - long-term liability (4,933 ) 4,933 — Total $ (10,487 ) $ 10,487 $ — Net asset $ 25,563 $ — $ 25,563 Gross Gross Amounts Net Amounts 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
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 (in thousands): Year Ended December 31, 2015 2014 2013 Net settlements on matured derivatives $ 28,543 $ 891 $ 288 Net settlements on early terminations and modifications of derivatives 11,069 — — Change in fair value of unsettled derivatives, net (17,246 ) 28,470 (5,963 ) Total gain (loss) on derivatives, net $ 22,366 $ 29,361 $ (5,675 )

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014: Level 1 Level 2 Level 3 Fair Value (in thousands) December 31, 2015 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments- asset $ — $ 36,050 $ — $ 36,050 Derivative financial instruments- liability — (514 ) — (514 ) Derivative deferred premiums - liability — — (9,973 ) (9,973 ) Net derivative position $ — $ 35,536 $ (9,973 ) $ 25,563 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Asset retirement obligations $ — $ — $ 4,924 $ 4,924 Impairment of proved oil and gas properties $ — $ — $ 103,938 $ 103,938 December 31, 2014 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments- asset $ — $ 27,044 $ — $ 27,044 Derivative financial instruments- liability — — — — Net derivative position $ — $ 27,044 $ — $ 27,044 Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis Asset retirement obligations $ — $ — $ 3,171 $ 3,171 Impairment of proved oil and gas properties $ — $ — $ 30,206 $ 30,206
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, 2015 2014 (in thousands) Balance of Level 3 at beginning of period $ — $ — Derivative deferred premiums - purchases (11,914 ) — Derivative deferred premiums - settlements 1,941 — Balance of Level 3 at end of period $ (9,973 ) $ —

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in our asset retirement obligations for the periods indicated are presented in the following table: Year Ended December 31, 2015 2014 2013 (in thousands) Asset retirement obligations - beginning of period $ 7,363 $ 3,942 $ 2,890 Liabilities incurred for new wells and interest 42 3,171 1,009 Liabilities settled upon plugging and abandoning wells (40 ) — — Revision of estimates (1) 4,882 — (130 ) Accretion expense 432 250 173 Asset retirement obligations - end of period $ 12,679 $ 7,363 $ 3,942 (1) The revision of estimates that occurred during the year ended December 31, 2015 is primarily due to a change in estimated plugging and abandonment costs based on recent settlements.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Debt	A summary of our debt for the year ended December 31, 2015 is presented below: Year Ended December 31, 2015 2014 (in thousands) Revolving credit facility $ 180,000 $ 205,000 Less: current portion 30,000 — Total long-term debt $ 150,000 $ 205,000

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Cash distributions	The following sets forth the distributions we paid during the years ended December 31, 2015 and 2014: Distribution Total Date Paid Period Covered per Unit Distributions February 13, 2015 October 1, 2014 - December 31, 2014 $ 0.125 $ 3,752 May 14, 2015 January 1, 2015 - March 31, 2015 $ 0.125 3,752 August 13, 2015 April 1, 2015 - June 30, 2015 $ 0.125 3,762 $ 11,266 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

Supplementary Information (Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 Oil and natural gas sales $ 17,571 $ 21,611 $ 18,493 $ 16,239 Gain (loss) on derivatives, net $ 1,644 $ (8,871 ) $ 19,771 $ 9,822 Total revenues and other $ 19,215 $ 12,740 $ 38,264 $ 26,061 Total expenses (1) $ 23,327 $ 20,684 $ 63,742 $ 84,022 Net loss $ (4,112 ) $ (7,944 ) $ (25,478 ) $ (57,961 ) Net loss per limited partner unit (basic) $ (0.14 ) $ (0.26 ) $ (0.85 ) $ (1.93 ) Net loss per limited partner unit (diluted) $ (0.14 ) $ (0.26 ) $ (0.85 ) $ (1.93 ) 2014 Oil and natural gas sales $ 21,807 $ 24,335 $ 26,173 $ 24,596 Gain (loss) on derivatives, net $ (2,048 ) $ (4,891 ) $ 9,280 $ 27,020 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 $ — (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, 2015 2014 2013 (in thousands) Property acquisition costs: Proved $ 1 $ 241,355 $ 28,057 Unproved — — — Exploration — — — Development 13,415 34,320 22,287 Asset retirement obligations 4,924 3,171 879 Total costs incurred $ 18,340 $ 278,846 $ 51,223
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) Proved developed and undeveloped reserves: 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 Revisions of previous estimates (2) 596 856 739 Extensions, discoveries and other additions — — — Purchases of minerals in place 1 — 1 Production (1,623 ) (571 ) (1,718 ) As of December 31, 2015 21,114 6,827 22,252 Proved developed reserves: December 31, 2013 10,397 1,321 10,617 December 31, 2014 17,046 5,327 17,933 December 31, 2015 14,368 4,762 15,162 Proved undeveloped reserves: December 31, 2013 3,317 — 3,317 December 31, 2014 5,094 1,215 5,297 December 31, 2015 6,746 2,065 7,090
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, 2015 2014 2013 (in thousands) Future cash inflows $ 1,011,096 $ 2,084,005 $ 1,295,435 Future production costs (581,314 ) (825,318 ) (542,389 ) Future development costs, including abandonment costs (109,669 ) (76,783 ) (49,458 ) Future net cash flow 320,113 1,181,904 703,588 10% discount for estimated timing of cash flow (128,693 ) (517,627 ) (312,325 ) Standardized measure of discounted cash flow $ 191,420 $ 664,277 $ 391,263
Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, 2015 2014 2013 (in thousands) Standardized measure of discounted future net cash flow, beginning of period $ 664,277 $ 391,263 $ 403,422 Changes in the year resulting from: Sales, less production costs (36,836 ) (64,495 ) (65,553 ) Revisions of previous quantity estimates 8,047 11,712 12,006 Extensions, discoveries and improved recovery — 44,727 1,863 Net change in prices and production costs (454,669 ) 22,068 (28,324 ) Net change in income taxes — — — Changes in estimated future development costs (6,080 ) (18,125 ) (17,155 ) Previously estimated development costs incurred during the period 8,103 22,526 22,257 Purchases of minerals in place 19 264,921 38,170 Accretion of discount 66,428 39,126 40,342 Timing differences and other (57,869 ) (49,446 ) (15,765 ) Standardized measure of discounted future net cash flow, end of year $ 191,420 $ 664,277 $ 391,263

Organization and Nature of Op32

Organization and Nature of Operations Organization and Nature of Operations (Details) - USD ($)	1 Months Ended
	Nov. 30, 2015	Dec. 31, 2015	Oct. 31, 2015	Apr. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Nov. 30, 2014	Oct. 31, 2014
Line of Credit Facility [Line Items]
Cash		$ 600,000
Derivative Assets (Liabilities), at Fair Value, Net		25,563,000				$ 27,044,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Available borrowing capacity		7,500,000
Line of credit facility, maximum borrowing capacity	$ 190,000,000	187,500,000	$ 220,000,000	$ 220,000,000	$ 240,000,000		$ 240,000,000	$ 190,000,000
Long-term Line of Credit, Noncurrent		150,000,000				$ 205,000,000
Revolving Credit Facility [Member] | Revolving Credit Facility, Conforming Tranche [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	165,000,000
Monthly commitment reductions	2,500,000
Revolving Credit Facility [Member] | Revolving Credit Facility, Non-conforming Tranche [Member]
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 25,000,000
Derivative Assets (Liabilities), at Fair Value, Net		$ 25,563,000

Summary of Significant Accoun33

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015Segment
Summary Of Significant Accounting Policies [Line Items]
Number of operating segment	1

Acquisitions - Additional Infor

Acquisitions - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Aug. 31, 2014	May. 31, 2014	Dec. 31, 2015
Liberty County, Texas [Member]
Business Acquisition [Line Items]
Consideration paid in cash	$ 18.9
Southern Oklahoma [Member]
Business Acquisition [Line Items]
Consideration paid in cash		$ 7.3
Miscellaneous [Member]
Business Acquisition [Line Items]
Consideration paid in cash			$ 0.1

Acquisitions - Summary of Combi

Acquisitions - Summary of Combined Statement of Operation (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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 (

Acquisitions Acquisitions - 1 (Details) - Permian [Member] - USD ($) $ in Thousands	1 Months Ended
	Nov. 30, 2015	Nov. 30, 2014
Business Acquisition [Line Items]
Number of limited partner units issued - acquisitions		5,800,000
Total consideration transferred	$ 117,100	$ 117,600
Consideration paid in cash		21,600
Value of limited partner units issued		96,000
Oil properties		118,906
Total assets acquired		118,906
Asset retirement obligation		1,851
Net assets acquired		117,055
Pro Forma [Member]
Business Acquisition [Line Items]
Oil properties		119,438
Total assets acquired		119,438
Asset retirement obligation		1,851
Net assets acquired		117,587
Scenario, Adjustment [Member]
Business Acquisition [Line Items]
Oil properties		(532)
Total assets acquired		(532)
Asset retirement obligation		0
Net assets acquired		$ (532)

Acquisitions Acquisitions - 2 (

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

Acquisitions Acquisitions - 3 (

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

Acquisitions Acquisition - 4 (D

Acquisitions Acquisition - 4 (Details) $ in Thousands	1 Months Ended
	May. 31, 2013USD ($)
NE Oklahoma [Member]
Business Acquisition [Line Items]
Consideration paid in cash	$ 27,400
Cushing Properties [Member]
Business Acquisition [Line Items]
Oil properties	28,318
Total assets acquired	28,318
Asset retirement obligation	906
Net assets acquired	$ 27,412

Equity Awards - Additional Info

Equity Awards - Additional Information (Detail) - USD ($)	1 Months Ended		12 Months Ended
	Dec. 31, 2015	Jul. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Nov. 20, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000		3,514,000			1,764,000
Deferred Compensation Liability, Current and Noncurrent	$ 100,000
Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			294,100	53,375
Average grant date fair value per unit, granted			$ 5.04	$ 23.11
Vesting period			3 years
Equity-settled Phantom Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			115,500
Average grant date fair value per unit, granted			$ 2.87
Equity-based compensation expense			$ 41,000
Unrecognized compensation costs	$ 200,000		$ 200,000
Weighted average period over which the unrecognized cost are expected to be recognized			2 years 4 days
Unrestricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			274,550
Average grant date fair value per unit, granted			$ 4.85
Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000		3,514,000
Equity-based compensation expense			$ 3,200,000	$ 7,700,000	$ 6,600,000
Share-based Compensation Award, Tranche Two [Member] | Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Average grant date fair value per unit, granted			$ 4.88
Common units authorized for issuance			26,100
Unrecognized compensation costs	$ 900,000		$ 900,000
Weighted average period over which the unrecognized cost are expected to be recognized			1 year 1 month 13 days
Share-based Compensation Award, Tranche Two [Member] | Equity-settled Phantom Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted		46,500
Vesting period		3 years
Share-based Compensation Award, Tranche One [Member] | Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			268,000
Average grant date fair value per unit, granted			$ 5.06
Share-based Compensation Award, Tranche One [Member] | Equity-settled Phantom Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted		69,000
Vesting period		2 years

Equity Awards - Awards Availabl

Equity Awards - Awards Available for Future Grant (Details) - shares	Dec. 31, 2015	Nov. 20, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000	1,764,000
Shared Based Compensation Arrangement by Share Based Payment Award Equity Instruments, Other than Options Equity Settled Phantom Units Outstanding	(100,500)
Awards available for future grant	1,844,103
Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted, net of forfeitures and vesting	(222,833)		(109,800)	(120,589)
Long-Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000
Unrestricted units granted, included vested units	(1,113,374)
Awards available for future grant	1,844,103
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	(433,857)
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	(22,166)

Equity Awards - Restricted Unit

Equity Awards - Restricted Units (Details) - Restricted Common Units [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 8.49	$ 23.28	$ 23.35
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, beginning of period	109,800	120,589
Units granted	294,100	53,375
Units vested	(148,195)	(44,430)
Units forfeited	(32,872)	(19,734)
Outstanding, end of period	222,833	109,800
Average grant date fair value per unit, granted	$ 5.04	$ 23.11
Average grant date fair value per unit, vested	12.43	23.09
Average grant date fair value per unit, forfeited	$ 9.28	$ 23.64
Share-based Compensation Award, Tranche Two [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.9
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Average grant date fair value per unit, granted	$ 4.88
Common units authorized for issuance	26,100
Weighted average period over which the unrecognized cost are expected to be recognized	1 year 1 month 13 days

Equity Awards Equity Awards - P

Equity Awards Equity Awards - Phantom Awards (Details) - Equity-settled Phantom Awards [Member]	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding, beginning of period | shares	0
Number of units issued | shares	115,500
Units vested | shares	(23,000)
Units forfeited | shares	(15,000)
Outstanding, end of period | shares	77,500
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares	$ 0
Average grant date fair value per unit, granted | $ / shares	2.87
Average grant date fair value per unit, vested | $ / shares	3.12
Average grant date fair value per unit, forfeited | $ / shares	2.81
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares	$ 2.81

Derivative Financial Instrume44

Derivative Financial Instruments - Additional Information (Detail)	Jan. 23, 2015USD ($)	Nov. 30, 2015USD ($)	Dec. 31, 2015USD ($)$ / Bbls	Dec. 31, 2014USD ($)$ / Bbls	Dec. 31, 2013USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash settlements received for early terminations and modifications of derivatives, net			$ 11,069,000	$ 0	$ 0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements		$ 0
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			22,366,000	29,361,000	$ (5,675,000)
Estimated fair value of derivative contracts, net asset (liability)			$ 25,563,000	$ 27,044,000
Period Covered-2016 | Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Bbls Hedged/day | $ / Bbls			1,598	82
Weighted Average Fixed Price Settlement | $ / Bbls			79.98
Period Covered-2016 | Collar [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Bbls Hedged/day | $ / Bbls			328
Weighted Average Floor Price | $ / Bbls			50
Weighted Average Ceiling Price | $ / Bbls			50
Period Covered-2016 | Put Option [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Bbls Hedged/day | $ / Bbls			1,475
Weighted Average Floor Price | $ / Bbls			50
Period Covered-2017 [Member] | Put Option [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Bbls Hedged/day | $ / Bbls			1,932
Weighted Average Floor Price | $ / Bbls			50
Commodity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash settlements received for early terminations and modifications of derivatives, net	$ 11,069,000
cash Received from Derivative Calls	5,900,000
Cash Paid for Premiums	19,800,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	$ 4,100,000
Derivative deferred premiums - settlements			$ 1,900,000
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net			$ 23.8

Derivative Financial Instrume45

Derivative Financial Instruments - Commodity Contract (Detail) $ in Millions	1 Months Ended	12 Months Ended
	Nov. 30, 2015USD ($)	Dec. 31, 2015$ / Bbls	Dec. 31, 2014$ / Bbls
Derivative [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements | $	$ 0
Swap [Member] | Period Covered-2015
Derivative [Line Items]
Weighted Average Fixed Price			93.29
Total Bbls Hedged/day			1,932
NYMEX Index		WTI
Swap [Member] | Period Covered-2016
Derivative [Line Items]
Weighted Average Fixed Price Settlement		79.98
Weighted Average Fixed Price			90.20
Total Bbls Hedged/day		1,598	82
NYMEX Index		WTI
Collar [Member] | Period Covered-2016
Derivative [Line Items]
Weighted Average Floor Price		50
Weighted Average Ceiling Price		50
Total Bbls Hedged/day		328
Put Option [Member] | Period Covered-2016
Derivative [Line Items]
Weighted Average Floor Price		50
Total Bbls Hedged/day		1,475
Put Option [Member] | Period Covered-2017 [Member]
Derivative [Line Items]
Weighted Average Floor Price		50
Total Bbls Hedged/day		1,932

Derivative Financial Instrume46

Derivative Financial Instruments - Summary of Grosss Fair Value by Approprtiate Balance Sheet Classification (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Assets [Abstract]
Gross amounts of recognized assets	$ 36,050	$ 27,044
Gross amounts offset in the Consolidated Balance Sheet	(10,487)	0
Net financial assets	25,563	27,044
Liabilities [Abstract]
Gross amounts of recognized liabilities	(10,487)	0
Gross amounts offset in the Consolidated Balance Sheet	10,487	0
Net financial liabilities	0	0
Gross amounts of recognized assets and liabilities	25,563	27,044
Gross amounts offset in the Consolidated Balance Sheet	0	0
Net amounts presented in the Consolidated Balance Sheet	25,563	27,044
Current Asset [Member]
Assets [Abstract]
Gross amounts of recognized assets	29,973	26,202
Gross amounts offset in the Consolidated Balance Sheet	(5,554)	0
Net financial assets	24,419	26,202
Long Term Asset [Member]
Assets [Abstract]
Gross amounts of recognized assets	6,077	842
Gross amounts offset in the Consolidated Balance Sheet	(4,933)	0
Net financial assets	1,144	842
Current Liability [Member]
Liabilities [Abstract]
Gross amounts of recognized liabilities	(514)	0
Gross amounts offset in the Consolidated Balance Sheet	514	0
Net financial liabilities	0	0
Deferred Premium Gross Liability	(5,040)
Deferred Premium Offset Against Collateral	5,040
Deferred Premium	0
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
Deferred Premium Gross Liability	(4,933)
Deferred Premium Offset Against Collateral	4,933
Deferred Premium	$ 0

Derivative Financial Instrume47

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Consolidated Statement of Operations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash settlements received for matured derivatives	$ 28,543	$ 891	$ 288
Cash settlements received for early terminations and modifications of derivatives, net	11,069	0	0
Change in fair value of unsettled derivatives, net	17,246	(28,470)	5,963
Total gain (loss) on derivatives, net	$ 22,366	$ 29,361	$ (5,675)

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Impairment charges	$ 103,938	$ 30,206	$ 1,578

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instrument- asset	$ 36,050,000	$ 27,044,000
Derivative Asset	25,563,000	27,044,000
Derivative financial instrument - liability	0	0
Impairment charges	103,938,000	30,206,000	$ 1,578,000
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 Asset	36,050,000	27,044,000
Derivative financial instrument - liability	(514,000)	0
Deferred Premium	(9,973,000)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	25,563,000	27,044,000
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	4,924,000	3,171,000
Impairment of proved oil and gas properties	103,938,000	30,206,000
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	36,050,000	27,044,000
Derivative financial instrument - liability	(514,000)	0
Net financial assets	35,536,000	27,044,000
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]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(9,973,000)	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
Deferred Premium	(9,973,000)
Net financial assets	(9,973,000)	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	4,924,000	3,171,000
Impairment of proved oil and gas properties		$ 30,206,000
Impairment charges	$ 103,938,000

Fair Value Disclosures Summary

Fair Value Disclosures Summary of Changes in assets (liabilities) - Level 3 (Details) - Level 3 [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Balance of Lever 3 at beginning of period	$ 0	$ 0
Derivative deferred premiums - purchases	(11,914)	0
Derivative deferred premiums - settlements	1,941	0
Balance of Lever 3 at end of period	$ (9,973)	$ 0

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in ARO obligations
Asset retirement obligation - beginning of period	$ 7,363	$ 3,942	$ 2,890
Liabilities incurred for new wells and interests	42	3,171	1,009
Loss on settlement of ARO	(40)	0	0
Revision of estimates	4,882	0	(130)
Accretion expense	432	250	173
Asset retirement obligation - end of period	$ 12,679	$ 7,363	$ 3,942

Debt Schedule of Debt (Details)

Debt Schedule of Debt (Details) - Revolving Credit Facility [Member] - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Revolving credit facility borrowings, outstanding	$ 180,000	$ 205,000
Line of Credit, Current	30,000	0
Long-term Line of Credit, Noncurrent	$ 150,000	$ 205,000

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($)

1 Months Ended

2 Months Ended

12 Months Ended

Nov. 30, 2015

Nov. 30, 2014

Feb. 29, 2016

Dec. 31, 2015

Oct. 31, 2015

Apr. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Oct. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Apr. 11, 2014

Mar. 31, 2014

Line of Credit Facility [Line Items]

Line of credit , current borrowing capacity

$ 190,000,000

$ 170,000,000

$ 170,000,000

$ 150,000,000

Financing fees and expenses

$ 200,000

Borrowings under the facility secured by liens, percent of assets

90.00%

Average effective rate

3.00%

Maximum [Member]

Line of Credit Facility [Line Items]

Margin

2.75%

Unused portion of borrowing base, percentage fee

0.50%

Minimum [Member]

Line of Credit Facility [Line Items]

Margin

1.00%

Unused portion of borrowing base, percentage fee

0.375%

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

3.75%

LIBOR [Member] | Minimum [Member]

Line of Credit Facility [Line Items]

Applicable margin rate

2.00%

Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Line of credit facility, maximum borrowing capacity

$ 190,000,000

$ 240,000,000

$ 187,500,000

$ 220,000,000

$ 220,000,000

$ 240,000,000

$ 190,000,000

Line of Credit, Current

30,000,000

$ 0

Long-term Line of Credit, Noncurrent

150,000,000

205,000,000

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

30,000,000

Long-term Debt, Maturities, Repayments of Principal in Year Three

150,000,000

Revolving credit facility borrowings, outstanding

$ 180,000,000

$ 205,000,000

Debt Issuance Cost

700,000

$ 3,600,000

Revolving Credit Facility, Conforming Tranche [Member] | Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Line of credit facility, maximum borrowing capacity

165,000,000

Monthly commitment reductions

2,500,000

Revolving Credit Facility, Non-conforming Tranche [Member] | Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Line of credit facility, maximum borrowing capacity

$ 25,000,000

Subsequent Event [Member]

Line of Credit Facility [Line Items]

Repayments of Debt

$ 7,000,000

Long-term Debt

$ 173,000,000

Commitment and Contingencies -

Commitment and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Commitments Contingencies And Litigation [Line Items]
Employment Agreements Expiration Date	Aug. 1, 2014
Employment Agreements [Member]
Commitments Contingencies And Litigation [Line Items]
Employment Agreements Beginning Date	Aug. 1, 2011
Minimum [Member]
Commitments Contingencies And Litigation [Line Items]
Employee Agreement Termination Payments	$ 0.3
Maximum [Member]
Commitments Contingencies And Litigation [Line Items]
Employee Agreement Termination Payments	$ 0.7

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($)	May. 05, 2015	Dec. 31, 2015	Dec. 31, 2014
Equity [Line Items]
Owners Equity		29,724,890	29,166,112
Limited partnership interest		98.80%	98.80%
Maximum Proceeds from Issuance of Common Units Under Equity Distribution Agreement	$ 50

Equity - Cash Distributions (De

Equity - Cash Distributions (Detail) - USD ($) $ / shares in Units, $ in Thousands	Aug. 13, 2015	May. 14, 2015	Feb. 13, 2015	Nov. 14, 2014	Aug. 11, 2014	May. 15, 2014	Feb. 14, 2014	Dec. 31, 2015	Dec. 31, 2014
Distribution Made to Limited Partner [Line Items]
Total Distribution								$ 11,266	$ 44,564
Cash Distributions Period Covered Oct 1, 2014- Dec 31, 2014
Distribution Made to Limited Partner [Line Items]
Date Paid			Feb. 13, 2015
Distribution per Unit			$ 0.125
Total Distribution			$ 3,752
Cash Distributions Period Covered Jan 1, 2015- Mar 31, 2015
Distribution Made to Limited Partner [Line Items]
Date Paid		May 14, 2015
Distribution per Unit		$ 0.125
Total Distribution		$ 3,752
Cash Distributions Period Covered Apr 1, 2015- Jun 30, 2015
Distribution Made to Limited Partner [Line Items]
Date Paid	Aug. 13, 2015
Distribution per Unit	$ 0.125
Total Distribution	$ 3,762
Cash Distributions Period Covered Oct 1, 2013 - Dec 31, 2013 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid							Feb. 14, 2014
Distribution per Unit							$ 0.515
Total Distribution							$ 10,262
Cash Distributions Period Covered Jan 1, 2014 - Mar 31, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid						May 15, 2014
Distribution per Unit						$ 0.515
Total Distribution						$ 11,032
Cash Distributions Period Covered Apr 1, 2014 - Jun 30, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid					Aug. 11, 2014
Distribution per Unit					$ 0.515
Total Distribution					$ 11,066
Cash Distributions Period Covered Jul 1, 2014 - Sep 30, 2014 [Member]
Distribution Made to Limited Partner [Line Items]
Date Paid				Nov. 14, 2014
Distribution per Unit				$ 0.515
Total Distribution				$ 12,204

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - Mid-Con Energy Operating [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Direct administrative expenses incurred and reimbursed to related party	$ 3.7	$ 3.8	$ 3.6
Other transactions of related party	0.5	4
Payment of joint interest billing	0.1	3.2
Payment of operating services	$ 0.4	$ 0.8

Credit Risk - Additional Inform

Credit Risk - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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] | BML [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	31.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Enterprise [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	22.00%	40.00%	50.00%
Sales Revenue, Net [Member] | Customer Concentration Risk [Member] | Coffeyville [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	21.00%	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] | National [Member]
Concentration Risk [Line Items]
Concentration risk, percentage			8.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | BML [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	32.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Enterprise [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	18.00%	14.00%	46.00%
Accounts Receivable [Member] | Customer Concentration Risk [Member] | Coffeyville [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	23.00%	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] | National [Member]
Concentration Risk [Line Items]
Concentration risk, percentage			10.00%

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Detail) - shares	Dec. 31, 2015	Nov. 20, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000	1,764,000
Units available for Issuance	1,844,103

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($) $ in Millions	Jan. 21, 2016	Jul. 31, 2015	Feb. 29, 2016	Dec. 31, 2015
Subsequent Event [Member]
Subsequent Event [Line Items]
Repayments of Debt			$ 7
Long-term Debt			$ 173
Unrestricted Common Units [Member]
Subsequent Event [Line Items]
Units granted				274,550
Unrestricted Common Units [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Units granted	70,000
Equity-settled Phantom Awards [Member]
Subsequent Event [Line Items]
Units granted				115,500
Equity-settled Phantom Awards [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Units granted	24,500
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] | Equity-settled Phantom Awards [Member]
Subsequent Event [Line Items]
Units granted		69,000
Vesting period		2 years
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] | Equity-settled Phantom Awards [Member]
Subsequent Event [Line Items]
Units granted		46,500
Vesting period		3 years
Share-based Compensation Award, Tranche Two [Member] | Equity-settled Phantom Awards [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Vesting period	2 years

Supplementary Information - Sch

Supplementary Information - Schedule of Quarterly Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended												12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Extractive Industries [Abstract]
Oil and natural gas sales	$ 16,239	$ 18,493	$ 21,611	$ 17,571	$ 24,596		$ 26,173		$ 24,335		$ 21,807
Gain (loss) on derivatives, net	9,822	19,771	(8,871)	1,644	27,020		9,280		(4,891)		(2,048)		$ 22,366	$ 29,361	$ (5,675)
Total revenues	26,061	38,264	12,740	19,215	51,616		35,453		19,444		19,759		96,280	126,272	80,061
Total expenses	84,022	63,742	20,684	23,327	51,534	[1]	18,451	[1]	15,597	[1]	18,198	[1]	185,033	99,062	48,599
Net income (loss)	$ (57,961)	$ (25,478)	$ (7,944)	$ (4,112)	$ 82		$ 17,002		$ 3,847		$ 1,561		$ (95,495)	$ 22,492	$ 28,189
Net income per limited partner unit (basic)	$ (1.93)	$ (0.85)	$ (0.26)	$ (0.14)	$ 0		$ 0.75		$ 0.18		$ 0.08		$ (3.18)	$ 0.98	$ 1.44
Net income per limited partner unit (diluted)	$ (1.93)	$ (0.85)	$ (0.26)	$ (0.14)	$ 0		$ 0.74		$ 0.18		$ 0.08		$ (3.18)	$ 0.98	$ 1.44
[1]	Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative and net other expense.

Supplementary Information - Sup

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property acquisition costs:
Proved	$ 1	$ 241,355	$ 28,057
Unproved	0	0	0
Exploration	0	0	0
Development	13,415	34,320	22,287
Asset retirement obligations	4,924	3,171	879
Total costs incurred	$ 18,340	$ 278,846	$ 51,223

Supplementary Information - Cha

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)		12 Months Ended
		Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf	Dec. 31, 2012MBoeMBblsMMcf
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]
Beginning balance, Oil | MBbls		22,140	13,714	13,074
Revisions of previous estimates | MBbls		596	211	264
Extensions, discoveries and other additions, Oil | MBbls		0	1,241	76
Purchases of minerals in place, Oil | MBbls		1	8,086	1,207
Production, Oil | MBbls		(1,623)	(1,112)	(907)
Ending balance, Oil | MBbls		21,114	22,140	13,714	13,074
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Beginning balance, Gas | MMcf		6,542	1,321	429
Revisions of previous estimates Gas | MMcf		856	924	827
Extensions, discoveries and other additions, Gas | MMcf		0	52	0
Purchases of minerals in place, Gas | MMcf		0	4,402	193
Production, Gas | MMcf		(571)	(157)	(128)
Ending balance, Gas | MMcf		6,827	6,542	1,321	429
Proved Developed and Undeveloped Reserves, Oil and Gas Reserves [Roll Forward]
Beginning balance | MBoe	[1]	23,230	13,934	13,146
Revisions of previous estimates | MBoe	[1]	739	364	401
Extensions, discoveries and other additions | MBoe	[1]	0	1,250	76	1,572
Purchases of minerals in place | MBoe	[1]	1	8,820	1,239
Production | MBoe	[1]	(1,718)	(1,138)	(928)
Ending balance | MBoe	[1]	22,252	23,230	13,934	13,146
Proved developed reserves, Oil | MBbls		14,368	17,046	10,397
Proved undeveloped reserves, Oil | MBbls		6,746	5,094	3,317
Proved developed reserves, Gas | MMcf		4,762	5,327	1,321
Proved undeveloped reserves, Gas | MMcf		2,065	1,215	0
Proved developed reserves | MBoe	[1]	15,162	17,933	10,617
Proved undeveloped reserves | MBoe	[1]	7,090	5,297	3,317
[1]	Estimated quantities of oil and natural gas reserves in MBoe equivalents at a rate of six Mcf per Bbl.

Supplementary Information - Sta

Supplementary Information - Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Extractive Industries [Abstract]
Future cash inflows	$ 1,011,096	$ 2,084,005	$ 1,295,435
Future production costs	(581,314)	(825,318)	(542,389)
Future development costs, including abandonment costs	(109,669)	(76,783)	(49,458)
Future net cash flow	320,113	1,181,904	703,588
10% discount for estimated timing of cash flow	(128,693)	(517,627)	(312,325)
Standardized measure of discounted cash flow	$ 191,420	$ 664,277	$ 391,263	$ 403,422

Supplementary Information - C65

Supplementary Information - Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Changes in the year resulting from:
Standardized measure of discounted future net cash flow, beginning of period	$ 664,277	$ 391,263	$ 403,422
Sales, less production costs	(36,836)	(64,495)	(65,553)
Revisions of previous quantity estimates	8,047	11,712	12,006
Extensions, discoveries and improved recovery	0	44,727	1,863
Net change in prices and production costs	(454,669)	22,068	(28,324)
Net change in income taxes	0	0	0
Changes in estimated future development costs	(6,080)	(18,125)	(17,155)
Previously estimated development costs incurred during the period	8,103	22,526	22,257
Purchases of minerals in place	19	264,921	38,170
Accretion of discount	66,428	39,126	40,342
Timing differences and other	(57,869)	(49,446)	(15,765)
Standardized measure of discounted future net cash flow, end of year	$ 191,420	$ 664,277	$ 391,263

Supplementary Information - Add

Supplementary Information - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2015MBoe$ / Bbls$ / Mcf$ / MMBTU	Dec. 31, 2014MBoe$ / Bbls$ / Mcf$ / MMBTU	Dec. 31, 2013MBoe$ / Bbls$ / Mcf$ / MMBTU	Dec. 31, 2012MBoe
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Estimated quantities of oil and natural gas reserves, rate		6
Extensions, discoveries and other additions	[1]	0	1,250	76	1,572
Proved Developed And Undeveloped Reserves, Effect of Commodity Price		4,084
Proved Developed and Undeveloped Reserves, Improved Recovery		1,417
Proved Undeveloped Reserves, Improved Recovery (Energy)		994
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)		3,405
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 | $ / Bbls		50.28	94.99	96.78
Average adjusted prices utilized in calculating proved reserves | $ / Bbls		47.23	92.45	93.98
Gas [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Prices utilized in calculating proved reserves | $ / MMBTU		2.58	4.35	3.67
Average adjusted prices utilized in calculating proved reserves | $ / Mcf		2.02	5.67	5
[1]	Estimated quantities of oil and natural gas reserves in MBoe equivalents at a rate of six Mcf per Bbl.