Mid-Con Energy Partners (MCEP) 10-Q 31 Oct 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 31, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3
Trading Symbol	MCEP
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
Entity Common Stock, Shares Outstanding		29,912,230
General Partner Units [Member]
Document Information [Line Items]
Entity Common Stock, Shares Outstanding		360,000

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 2,115	$ 615
Accounts receivable:
Oil and natural gas sales	4,711	4,551
Other	1,136	5,009
Derivative financial instruments	1,376	24,419
Prepaids and other	297	623
Total current assets	9,635	35,217
Oil and natural gas properties, successful efforts method:
Proved properties	438,873	518,916
Other Property and Equipment	262	0
Accumulated depletion, depreciation, amortization and impairment	(171,027)	(232,008)
Total property and equipment, net	268,108	286,908
Derivative financial instruments	0	1,144
Other assets	2,881	3,817
Total assets	280,624	327,086
Accounts payable:
Trade	2,516	3,185
Related parties	44	559
Derivative Liability, Current	2,307	0
Accrued liabilities	144	165
Current maturities of long-term debt	0	30,000
Total current liabilities	5,011	33,909
Derivative Liability, Noncurrent	1,992	0
Long-term debt	127,900	150,000
Other Liabilities, Noncurrent	99	0
Asset retirement obligations	11,009	12,679
Commitments and contingencies
Class A convertible preferred units - 11,627,906 and 0 issued and outstanding, respectively	19,066	0
Partnership equity:
General partner interest	(209)	47
Limited partners- 29,912,230 and 29,724,890 units issued and outstanding, respectively	115,756	130,451
Total equity	115,547	130,498
Total liabilities, convertible preferred units and equity	$ 280,624	$ 327,086

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Limited partners, units issued	29,912,230	29,724,890
Limited partners, units outstanding	29,912,230	29,724,890

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) shares in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Revenues:
Oil sales	$ 14,012,000	$ 18,137,000	$ 39,565,000	$ 56,675,000
Natural gas sales	398,000	356,000	891,000	1,000,000
(Loss) gain on derivatives, net	(444,000)	19,771,000	(7,964,000)	12,544,000
Total revenues	13,966,000	38,264,000	32,492,000	70,219,000
Operating costs and expenses:
Lease operating expenses	5,709,000	8,761,000	17,551,000	25,293,000
Oil and natural gas production taxes	753,000	206,000	2,077,000	2,634,000
Impairment of proved oil and natural gas properties	0	40,920,000	895,000	40,920,000
Impairment of proved oil and natural gas properties sold	0	0	3,578,000	0
Depreciation, depletion and amortization	5,665,000	9,655,000	17,550,000	25,692,000
Accretion of discount on asset retirement obligations	127,000	91,000	443,000	276,000
General and administrative	1,715,000	2,253,000	5,281,000	7,531,000
Total operating costs and expenses	13,969,000	61,886,000	47,375,000	102,346,000
Gain (Loss) on Disposition of Oil and Gas Property	(530,000)	0	(517,000)	0
Loss from operations	(533,000)	(23,622,000)	(15,400,000)	(32,127,000)
Other income (expense):
Interest income	4,000	2,000	9,000	8,000
Interest expense	(1,728,000)	(1,804,000)	(5,981,000)	(5,361,000)
Other Income (Expense)	(164,000)	0	(131,000)	0
Loss on settlement of ARO	0	(54,000)	0	(54,000)
Total other expense	(1,888,000)	(1,856,000)	(6,103,000)	(5,407,000)
Net loss	(2,421,000)	(25,478,000)	(21,503,000)	(37,534,000)
Less: Distributions to preferred unitholders	440,000	0	440,000	0
Less: General partner's interest in net loss
Less: General partner's interest in net loss	(29,000)	(306,000)	(256,000)	(451,000)
Limited partners' interest in net loss	$ (2,832,000)	$ (25,172,000)	$ (21,687,000)	$ (37,083,000)
Net loss per limited partner unit, basic and diluted (in usd per unit)	$ (0.09)	$ (0.85)	$ (0.73)	$ (1.25)
Weighted average limited partner units outstanding:
Weighted average limited partner units (basic and diluted)	29,868	29,705	29,807	29,614

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash Flows from Operating Activities:
Net loss	$ (21,503)	$ (37,534)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization	17,550	25,692
Debt issuance costs amortization	1,019	839
Accretion of discount on asset retirement obligations	443	276
Impairment of proved oil and natural gas properties	895	40,920
Impairment of proved oil and natural gas properties sold	3,578	0
Loss on settlement of ARO	0	54
Cash paid for settlement of ARO	0	(79)
Loss (gain) on derivatives, net	7,964	(12,544)
Cash settlements received for matured derivatives	18,467	15,566
Cash settlements received for early terminations and modifications of derivatives, net	5,820	11,069
Cash premiums paid for derivatives, net	(3,766)	(15,765)
Loss on sale of oil and natural gas properties	517	0
Non-cash equity-based compensation	961	2,957
Changes in operating assets and liabilities:
Accounts receivable	(160)	1,859
Other receivables	4,805	1,342
Prepaids and other	326	128
Accounts payable and accrued liabilities	(1,288)	(3,446)
Net cash provided by operating activities	35,628	31,334
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(5,111)	(11,250)
Additions to other property and equipment	(124)	0
Acquisitions of oil and natural gas properties	(19,055)	(1)
Proceeds from sale of oil and natural gas properties	17,312	0
Net cash used in investing activities	(6,978)	(11,251)
Cash Flows from Financing Activities:
Proceeds from line of credit	0	28,000
Payments on line of credit	(52,100)	(39,000)
Offering costs	(16)	(88)
Distributions paid	0	(11,266)
Debt issuance costs	(9)	0
Proceeds from sale of convertible preferred units, net of offering costs	24,975	0
Net cash used in financing activities	(27,150)	(22,354)
Net increase (decrease) in cash and cash equivalents	1,500	(2,271)
Beginning cash and cash equivalents	615	3,232
Ending cash and cash equivalents	$ 2,115	$ 961

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Changes in Equity - 9 months ended Sep. 30, 2016 - USD ($) shares in Thousands, $ in Thousands	Total	General Partner [Member]	Limited Partner [Member]
Balance at Dec. 31, 2015	$ 130,498	$ 47	$ 130,451
Balance, Units at Dec. 31, 2015			29,725
Increase (Decrease) in Partners' Capital [Roll Forward]
Equity-based compensation	961		$ 961
Equity-based compensation, Units			187
Offering costs	(16)		$ (16)
Distribution to preferred units	(274)		(274)
Convertible Preferred Units Beneficial Conversion Feature	6,047		6,047
Accretion of beneficial conversion feature of Class A convertible preferred units	(166)		(166)
Net loss	(21,503)	(256)	(21,247)
Balance at Sep. 30, 2016	$ 115,547	$ (209)	$ 115,756
Balance, Units at Sep. 30, 2016			29,912

Organization and Nature of Oper

Organization and Nature of Operations	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations 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 ("EOR"). Our limited partner units ("common units") are traded on the National Association of Securities Dealers Automated Quotation System Global Select Market ("NASDAQ") under the symbol "MCEP." Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Basis of Presentation Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the SEC. These financial statements have not been audited by our independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2015 is derived from the audited financial statements. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015 . All intercompany transactions and account balances have been eliminated. Reclassifications The consolidated statements of income for previous periods include certain reclassifications to the other income (expense) accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss). Non-cash Investing, Financing and Supplemental Cash Flow Information The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Nine Months Ended 2016 2015 (in thousands) Non-cash investing information: Change in accrued capital expenditures-oil and natural gas properties 513 619 Change in accrued capital expenditures-other property and equipment (14 ) — Tenant improvement allowance deferred-other property and equipment (124 ) — Change in accrued receivable-acquisition post-close adjustment 419 — Change in accrued receivable-divestiture post-close adjustment 354 — Non-cash financing information: Change in accrued capital expenditures-offering costs (302 ) — Supplemental cash flow information: Cash paid for interest 5,063 4,606 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. Historically, our primary use of cash has been for debt reduction and to fund capital spending and distributions. Oil prices fell to 13-year lows during 2016, impacting the way we conduct business. We have implemented a number of adjustments to strengthen our financial position. In January 2015, we restructured a significant portion of our hedge portfolio to limit downside and volatility due to the then prevailing commodity price environment. We have since then entered into additional oil commodity derivative contracts covering a portion of our anticipated oil production through 2019. In the third quarter of 2015, we indefinitely suspended our quarterly cash distributions on common units. We are also aggressively pursuing cost reductions 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 September 30, 2016 consisted of approximately $2.1 million of available cash and $12.1 million of available borrowings under our revolving credit facility ( $140.0 million borrowing base less $127.9 million of outstanding borrowings). Our borrowing base is redetermined in the spring and fall of each year. In conjunction with closing the Permian Bolt-On acquisition during the third quarter of 2016, we completed a non-scheduled borrowing base redetermination and executed Amendment No. 10 to the credit agreement on August 11, 2016. As such, our senior lenders unanimously agreed to increase the conforming borrowing base of our revolving credit facility to $140.0 million . See Note 7 in this section for additional information regarding our credit facility. Based on our cash balance, forecasted cash flows from operating activities 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. Although we currently expect our sources of cash to be sufficient to meet our near-term liquidity needs, there can be no assurance 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 volatility of 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.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Acquisitions and Divestitures	Acquisitions and Divestitures Permian Bolt-On Acquisition On August 11, 2016, we acquired multiple oil and natural gas properties located in Nolan County, Texas ("Permian Bolt-On") for an aggregate purchase price of approximately $18.7 million , after estimated post-closing purchase price adjustments. The Permian Bolt-On acquisition was accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the acquisition were recorded in our unaudited condensed consolidated balance sheets at their estimated fair values as of the acquisition date using assumptions that represent Level 3 fair value measurement inputs. See Note 5 in this section for additional discussion of our fair value measurements. Results of operations attributable to the acquisition subsequent to the closing were included in our unaudited condensed consolidated statements of operations. The transaction was funded by a private offering of $25.0 million Class A Convertible Preferred Units ("Preferred Units"). See Note 9 in this section for additional information regarding the issuance of Preferred Units. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands): Fair value of net assets: Oil and natural gas properties $ 19,280 Total assets acquired $ 19,280 Fair value of net liabilities assumed: Asset retirement obligation 622 Net assets acquired $ 18,658 Hugoton Divestiture On July 28, 2016, we sold our properties located in the Hugoton Basin for proceeds of approximately $17.9 million , prior to post-closing adjustments, and recognized a loss of approximately $0.5 million which is included as "Loss on sales of oil and natural gas properties, net" in our unaudited condensed consolidated statements of operations. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited condensed consolidated statements of operations for the periods presented: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in thousands) Oil and natural gas sales $ 632 $ 2,921 $ 3,602 $ 9,294 Expenses (1) $ 591 $ 32,185 $ 7,717 $ 39,428 (1) Expenses include lease operating expenses, production taxes, accretion, depletion and impairment expenses.

Equity Awards

Equity Awards	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Awards	Equity Awards We have a long-term incentive program (the "Long-Term Incentive Program") for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating, LLC ("Mid-Con Energy Operating") and ME3 Oilfield Service, LLC ("ME3 Oilfield Service"), 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. The Long-Term Incentive Program 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 units are forfeited and canceled and are no longer considered issued and outstanding. On November 20, 2015, the Board of Directors of the general partner approved an amendment to the Long-Term Incentive Program that increased the number of common units available for issuance from 1,764,000 to 3,514,000 . The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at September 30, 2016 : Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,187,306 ) Restricted units granted, net of forfeitures (400,424 ) Equity-settled phantom units granted, net of forfeitures (457,500 ) Awards available for future grant 1,468,770 We recognized $0.3 million and $1.0 million of total equity-based compensation expense for the three and nine months ended September 30, 2016, respectively, and we recognized $0.6 million and $3.0 million of total equity-based compensation expense for the three and nine months ended September 30, 2015, respectively. These costs are reported as a component of general and administrative expense in our unaudited condensed consolidated statements of operations. Unrestricted unit awards We account for unrestricted awards as equity awards since they are settled by issuing common units. During the nine months ended September 30, 2016, we granted 73,932 unrestricted units with an average grant date fair value of $1.20 per unit. During the nine months ended September 30, 2015, we granted 274,550 unrestricted units with an average grant date fair value of $4.85 per unit. Restricted unit 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 units is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. We did not issue any restricted units during the nine months ended September 30, 2016. During the nine months ended September 30, 2015, we granted 268,000 restricted units with one-third vesting immediately and the other two-thirds vesting over two years, and 26,100 restricted units with a three year vesting period. A summary of our restricted unit awards for the nine months ended September 30, 2016 is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 222,833 $ 8.49 Units granted — — Units vested (112,478 ) 9.16 Units forfeited (33,433 ) 9.69 Outstanding at September 30, 2016 76,922 $ 5.67 As of September 30, 2016 , there were approximately $0.3 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 eight months . Equity-settled phantom unit awards We account for equity-settled phantom awards as equity awards since they will be settled by issuing common units. These units vest over a two or three year period and do not have any rights or privileges of a common unitholder, including right to distributions, until vesting and the resulting conversion into common units. The compensation expense we recognize associated with our equity-settled phantom units is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. During the nine months ended September 30, 2016, we granted 347,500 equity-settled phantom awards with one-third vesting immediately and the other two-thirds vesting over two years and 27,000 equity-settled phantom awards with a three year vesting period. During the nine months ended September 30, 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. A summary of our equity-settled phantom unit awards for the nine months ended September 30, 2016 is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 77,500 $ 2.81 Units granted 374,500 1.55 Units vested (146,841 ) 2.03 Units forfeited (17,500 ) 2.02 Outstanding at September 30, 2016 287,659 $ 1.64 As of September 30, 2016 , there were approximately $0.4 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 one year, nine months .

Derivative Financial Instrument

Derivative Financial Instruments	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Derivative Financial Instruments Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices and specific delivery points. The commodity derivative contracts that we have entered into generally have the effect of providing us with a fixed price or a floor for a portion of our expected future oil production over a fixed period of time. We enter into commodity derivative contracts 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. These are presented as derivative financial instruments on our unaudited condensed consolidated financial statements. We account for our commodity derivative contracts at fair value. See Note 5 in this section for a description of our fair value measurements. At September 30, 2016, our derivative contracts were in a net liability position with a fair value of approximately $2.9 million. At December 31, 2015, our derivative contracts were in a net asset position with a fair value of approximately $25.6 million. 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 commodity derivative contracts under lower commodity prices and we could incur a loss. As of September 30, 2016, all of our counterparties have performed pursuant to their commodity derivative contracts. At September 30, 2016 and December 31, 2015, our commodity derivative contracts had maturities that extended through December 2018 and December 2017, respectively, and were comprised of commodity price swap, call, put and collar 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 commodity 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, which can be effected at either execution or settlement, the seller is obliged to pay the difference, when positive, between the market price of the underlying commodity at maturity and 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 difference, when positive, between the strike price and the market price of the underlying commodity 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. For commodity price collar contracts, a collar is the combination of a put purchased or sold by a party and a call option sold or purchased by the same party. The collar is defined as costless when the value of the option purchased is approximately offset by the value of the option sold. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of our commodity 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 gains or losses 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 September 30, 2016 , we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls NYMEX Index Swaps - 2016 $ 64.18 1,304 WTI Puts - 2016 $ 50.00 $ — 1,957 WTI Collars - 2017 $ 40.00 $ 50.68 658 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI Collars - 2018 $ 44.38 $ 55.52 1,315 WTI Puts - 2018 $ 45.00 $ — 164 WTI At December 31, 2015, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls 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 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 and entered into new commodity derivative contracts which extended through September 2016. In connection with the early termination of our commodity derivative contracts, we received net proceeds of approximately $11.1 million. We received approximately $5.9 million from selling calls and paid approximately $19.8 million in premiums to extend the contracts through September 2016. The restructuring also resulted in approximately $4.1 million of deferred premium put options. As of September 30, 2016, all deferred premiums related to these restructured contracts have been paid. In connection with the fall 2015 semi-annual redetermination of our borrowing base, we 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, calculated based on Proved Developed Producing reserves. No cash settlements were required and the contracts included deferred premiums of approximately $7.8 million that will be paid through December 2017. As of September 30, 2016, we had paid approximately $1.6 million of the deferred premiums in connection with these contract settlements. In connection with the spring 2016 semi-annual redetermination of our borrowing base, we unwound and early terminated existing hedges covering production from July 2016 through September 2016 and entered into new commodity derivative contracts which extend through June 2018. In connection with the early termination of our commodity derivative contracts, we received proceeds of approximately $5.8 million and paid related deferred premiums of approximately $1.5 million . In connection with the non-scheduled redetermination of our borrowing base and Amendment No.10 to our credit agreement executed in August 2016, we entered into new commodity derivative contracts covering at least 75% of our 2017 projected monthly production and at least 50% of our 2018 projected monthly production, calculated based on Proved Developed Producing reserves. The new contracts extend through December 2018. No cash settlements were required and the contracts included deferred premiums of approximately $0.4 million that will be paid through December 2018. The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments are subject to netting arrangements and qualify for net presentation in our unaudited condensed consolidated balance sheets at September 30, 2016 and December 31, 2015: Gross Amounts Recognized Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheet Net Amounts (in thousands) September 30, 2016: Assets Derivative financial instruments - current asset $ 5,032 $ (3,656 ) $ 1,376 Derivative financial instruments - long-term asset 1,599 (1,599 ) — Total $ 6,631 $ (5,255 ) $ 1,376 Liabilities Derivative financial instruments - current liability $ (899 ) $ (1,408 ) $ (2,307 ) Derivative deferred premium - current liability (5,064 ) 5,064 — Derivative financial instruments - long-term liability (2,048 ) 56 (1,992 ) Derivative deferred premium - long-term liability (1,543 ) 1,543 — Total $ (9,554 ) $ 5,255 $ (4,299 ) Net Liability $ (2,923 ) $ — $ (2,923 ) Gross Gross Amounts Net Amounts (in thousands) December 31, 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 deferred premium - long-term liability (4,933 ) 4,933 — Total $ (10,487 ) $ 10,487 $ — Net Asset $ 25,563 $ — $ 25,563 The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in thousands) Net settlements on matured derivatives $ 1,182 $ 8,383 $ 18,467 $ 15,566 Net settlements on early terminations and modifications of derivatives 5,820 — 5,820 11,069 Net change in fair value of derivatives (7,446 ) 11,388 (32,251 ) (14,091 ) Total (loss) gain on derivatives, net $ (444 ) $ 19,771 $ (7,964 ) $ 12,544

Fair Value Disclosures

Fair Value Disclosures	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Fair Value Disclosures Fair Value of Financial Instruments The carrying amounts reported in our unaudited condensed consolidated balance sheets 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 as discussed in "Assets and Liabilities Measures at Fair Value on a Recurring Basis" below. 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 at September 30, 2016 and December 31, 2015. 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 nine months ended September 30, 2016 and for the year ended December 31, 2015. 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 utilizing certain pricing models. 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 4 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 our Asset Retirement Obligations ("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 6 in this section for a summary of changes in ARO. The estimated fair values of proved oil and natural gas properties assumed in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. The estimated fair values of unevaluated oil and natural gas properties were based on geological studies, historical well performance, location and applicable mineral lease terms. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties assumed is deemed to use Level 3 inputs. See Note 2 in this section for further discussion of the Partnership's acquisitions. 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. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated 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. There were no impairment charges for the three months ended September 30, 2016. During the nine months ended September 30, 2016, we recorded a non-cash impairment charge of approximately $0.9 million resulting from a revision of reserve estimates for a property in our Permian core area. The impairment is included in "Impairment of proved oil and natural gas properties" in our unaudited condensed consolidated statements of operations. During the nine months ended September 30, 2016, we recorded a non-cash impairment charge of approximately $3.6 million related to the Hugoton core area divestiture to reduce the carrying amount of those assets to their fair value. These assets and liabilities were deemed to meet held-for-sale accounting criteria as of June 30, 2016, accordingly, the impairment is included in "Impairment of proved oil and natural gas properties sold" in our unaudited condensed consolidated statements of operations. During the three and nine months ended September 30, 2015, we recorded a non-cash impairment charge of approximately $40.9 million due to a decline in commodity prices and to a lesser degree, reduced reserve estimates. The impairment charges are included in “Impairment of proved oil and natural gas properties" in our unaudited condensed consolidated statements of operations. The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value as of September 30, 2016 and December 31, 2015 : Level 1 Level 2 Level 3 Fair Value (in thousands) September 30, 2016 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments - asset $ — $ 6,631 $ — $ 6,631 Derivative financial instruments - liability $ — $ 2,947 $ — $ 2,947 Derivative deferred premiums - liability $ — $ — $ 6,607 $ 6,607 Assets and Liabilities Measured at Fair Value on a Non-recurring Basis Asset retirement obligations $ — $ — $ 714 $ 714 Impairment of proved oil and natural gas properties $ — $ — $ 895 $ 895 Impairment of proved oil and natural gas properties sold $ — $ — $ 3,578 $ 3,578 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 Assets and Liabilities Measured at Fair Value on a Non-recurring Basis Asset retirement obligations $ — $ — $ 4,924 $ 4,924 Impairment of proved oil and natural gas properties $ — $ — $ 103,938 $ 103,938 A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Nine Months Ended Year Ended (in thousands) Balance of Level 3 at beginning of period $ (9,973 ) $ — Derivative deferred premiums - purchases (400 ) (11,914 ) Derivative deferred premiums - settlements 3,766 1,941 Balance of Level 3 at end of period $ (6,607 ) $ (9,973 )

Asset Retirement Obligations

Asset Retirement Obligations	9 Months Ended
	Sep. 30, 2016
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 ARO 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 removal and future restoration obligation 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 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 unaudited condensed 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. As of September 30, 2016 and December 31, 2015 , our ARO were reported as "Asset retirement obligations" in our unaudited condensed consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table: Nine Months Ended Year Ended (in thousands) Asset retirement obligations - beginning of period $ 12,679 $ 7,363 Liabilities incurred for new wells and interest 714 42 Liabilities settled upon plugging and abandoning wells — (40 ) Liabilities removed upon sale of wells (2,827 ) — Revision of estimates (1) — 4,882 Accretion expense 443 432 Asset retirement obligations - end of period $ 11,009 $ 12,679 (1) The revision of estimates that occurred during the year ended December 31, 2015 was primarily due to a change in estimated plugging and abandonment costs based on 2015 settlements.

Debt

Debt	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Debt	Debt A summary of our debt at September 30, 2016 and year ended December 31, 2015 is presented below: Nine Months Ended Year Ended (in thousands) Revolving credit facility $ 127,900 $ 180,000 Less: current portion — 30,000 Total long-term debt $ 127,900 $ 150,000 At September 30, 2016, we had $127.9 million of borrowings outstanding under our revolving credit facility that matures in November 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 in the spring and fall 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 redetermination. 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 three months ended September 30, 2016, the average effective rate was approximately 3.74% . Any unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. 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. 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 nine months ended September 30, 2016. 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 spring 2015 semi-annual redetermination and amendment to the credit agreement completed 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 the fall 2015 semi-annual redetermination and amendment to the credit agreement completed in November 2015, the borrowing base under the underlying revolving credit facility was reduced to $190.0 million from $220.0 million , consisting of a $165.0 million conforming tranche, which required six monthly commitment reductions of $2.5 million each through May 2016, and a $25.0 million non-conforming tranche that matured 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, calculated based on Proved Developed Producing reserves at the time of the agreement. These requirements were satisfied during November 2015 with the execution of additional commodity derivative contracts maturing in 2016 and 2017. 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 as "interest expense" in our unaudited condensed consolidated statements of operations. During the spring 2016 semi-annual redetermination and amendment to the credit agreement completed in May 2016, the effective borrowing base as of June 1, 2016 was reduced to $163.0 million and was comprised of a $110.0 million conforming tranche and a permitted overadvance of $53.0 million . The permitted overadvance was scheduled to mature on November 1, 2016. In addition, the amendment (i) required the Partnership to provide a monthly excess cash flow report; (ii) required the Partnership to make varied minimum monthly principal payments totaling approximately $1.9 million through October 31, 2016; (iii) reduced the conforming borrowing base to $105.0 million upon the close of the previously announced Hugoton divestiture; (iv) allowed an additional non-scheduled borrowing base redetermination between September 1, 2016 and November 1, 2016 to be requested by any lender; (v) increased the minimum collateral coverage from 90% to 95% of proved reserves (and 100% of PDP reserves); (vi) required the Partnership to unwind and early terminate existing hedges covering production from July 2016 through September 2016 and add new at-the-market swap contracts to replace these hedge terminations; and (vii) required the net proceeds from the previously announced Hugoton sale and from the early termination of hedge contracts to be applied to debt reduction. During August 2016, we completed a non-scheduled redetermination and amendment to the credit agreement in conjunction with our Permian Bolt-On acquisition. Among other changes, the amendment to the credit agreement increased the conforming borrowing base of the Partnership’s revolving credit facility to $140.0 million as of August 11, 2016, modified the definition of “Indebtedness” to exclude the Preferred Units and modified the limitations on restricted payments to specifically provide for the payment of cash distributions on the Preferred Units. The amendment also required that by August 18, 2016, we enter into commodity derivative contracts of not less than 75% of our 2017 projected monthly production and not less than 50% of our 2018 projected monthly production, calculated based on Proved Developed Producing reserves at the time of the agreement. These requirements were satisfied with the execution of additional commodity derivative contracts maturing in 2018. The amendment also required that within 30 days we extend our collateral coverage to include the reserves acquired in the Permian Bolt-On acquisition.

Commitment and Contingencies

Commitment and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitment and Contingencies	Commitments and Contingencies We lease corporate office space in Tulsa, Oklahoma and Abilene, Texas. We are also allocated office rent from Mid-Con Energy Operating. Total lease expenses were approximately $0.1 million each for the three months ended September 30, 2016 and 2015, and approximately $0.3 million each for the nine months ended September 30, 2016 and 2015, respectively. These expenses are included in general and administrative expenses in our unaudited condensed consolidated statements of operations. Future minimum lease payments under the non-cancellable operating leases at September 30, 2016 were as follows (in thousands): Remaining 2016 $ 122 2017 490 2018 490 2019 413 2020 418 2021 423 Total $ 2,356 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. 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. See Note 10 in this section for additional information. 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. The employment agreements automatically renew for one-year terms unless either we or the employee gives written notice of termination by at least February1st 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 them. 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. 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.

Equity

Equity	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Equity	Equity Common Units At September 30, 2016 and December 31, 2015 , the Partnership’s equity consisted of 29,912,230 and 29,724,890 common units, respectively, representing approximately a 98.8% limited partnership interest in us. On May 5, 2015, we entered into an Equity Distribution 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. In connection with the Class A Convertible Preferred Units agreement described below, the Partnership suspended the Equity Distribution Agreement effective as of the closing date until the fifth anniversary of the closing date of the Preferred Units purchase agreement, or the consent of a majority of the holders of the outstanding Preferred Units. Class A Convertible Preferred Units On August 11, 2016, we completed our previously announced private placement of 11,627,906 Class A Convertible Preferred Units for an aggregate offering price of $25.0 million . The Preferred Units were issued at a price of $2.15 per preferred unit (the "Unit Purchase Price"). Proceeds from this issuance were used to fund the Permian Bolt-On acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We will pay holders of the Preferred Units a cumulative, quarterly distribution on all Preferred Units then outstanding (i) in cash at an annual rate of 8.0% , or (ii) in the event that the Partnership's existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Preferred Units), at an annual rate of 10.0% . Such distributions will be paid for each such quarter within 45 days after such quarter end. At any time after the six-month anniversary and prior to the five year anniversary of the closing date, each holder of the Preferred Units shall have the right, subject to certain conditions, to convert all or a portion of their Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis, subject to adjustment for splits, subdivisions, combinations and reclassifications of the common units; provided that any holder electing conversion requests the conversion of at least the lesser of (i) 100% of such holder's remaining Preferred Units or (ii) $1,000,000 of Preferred Units, based on the Unit Purchase Price. On the fifth anniversary of the closing date of the offering, each holder shall have the right to cause the Partnership to redeem all or any portion of their Preferred Units for cash at the Unit Purchase Price, and any remaining Preferred Units will thereafter be converted to common units on a one-for-one basis, subject to adjustment for splits, reverse splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of Preferred Units, the Partnership will pay any distributions (to the extent accrued and unpaid as of the then most recent Preferred Units distribution date) on the converted units in cash. Upon a change of control, each holder will have the right, at its election, to either (i) if the Partnership is the surviving entity of such change of control, continue to hold Preferred Units; or (ii) convert all or any portion of the Preferred Units held by such holder into common units on a one-for-one basis, subject to adjustments for splits, reverse splits, subdivisions, combinations and reclassifications. If any Preferred Units remain outstanding following a change of control in which the Partnership is not the surviving entity, then immediately following effectiveness of such change of control, the Partnership shall redeem in cash all, but not less than all, of the outstanding Preferred Units at a price per Preferred Unit equal to the Unit Purchase Price multiplied by the change of control redemption multiple then in effect. Under the registration rights agreements, we are required to use reasonable best efforts to file, within 90 days of the closing date, a registration statement registering resales of common units issued or to be issued upon conversion of the Preferred Units and have the registration statement declared effective within 180 days after the closing date. We are required to use reasonable best efforts to continue to maintain the effectiveness of the registration statement until all securities have been sold or the third anniversary of the effectiveness deadline. In addition, from and after the first anniversary of the closing date, holders of an aggregate of at least $1,000,000 of Preferred Units (based on the Unit Purchase Price) shall have piggyback registration rights on all Partnership registrations, subject to customary carve backs, and holders of an aggregate of at least $5,000,000 of Preferred Units (based on the Unit Purchase Price) shall have demand registration rights; provided that the holders shall be entitled to a demand registration right not more frequently that once during any twelve month period. In the event of any liquidation, dissolution or winding-up of the Partnership, each preferred unit will receive in preference to the holders of all existing classes or series of equity securities of the Partnership a per unit amount equal to the Unit Purchase Price (subject to any customary anti-dilution adjustments), plus all accrued and unpaid distributions on such Preferred Units (the "liquidation preference"). The Preferred Unit purchase agreement also requires the Partnership to suspend sales of common units pursuant to the Equity Distribution Agreement from the closing date through the fifth anniversary of the closing date and prohibits the Partnership from incurring any indebtedness (other than under the Partnership’s existing revolving credit facility and trade accounts payable arising in the ordinary course of business) without the consent of the majority of the holders of the Preferred Units. We received net proceeds of approximately $24.7 million (net of issuance costs of approximately $0.3 million ) in connection with the issuance of Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units (approximately $18.7 million ) and the beneficial conversion feature (approximately $6.0 million ). A beneficial conversion feature is defined as a non-detachable conversion feature that is in the money at the commitment date. Per accounting guidance, we are required to allocate a portion of the proceeds from the Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and the proceeds attributed to the Preferred Units. We will record the accretion attributed to the beneficial conversion feature as a deemed distribution using the straight line method over the five year period prior to the effective date of the holders conversion right. Accretion of the beneficial conversion feature was approximately $0.2 million for the three months ended September 30, 2016. Our 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 no 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. Preferred Unit holders will receive quarterly distributions in cash at an annual rate of 8.0% or, under certain circumstances, in additional Preferred Units at an annual rate of 10.0% . The holders of the Preferred Units are entitled to certain rights that are senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. No payment or distribution on common units for any quarter is permitted prior to the payment in full of the Preferred Units distribution (including any outstanding arrearages). As announced on October 27, 2016, the Board of Directors of the general partner declared a distribution for the period from August 11, 2016 to September 30, 2016 of approximately $0.3 million to be paid on November 14, 2016 to holders of record as of the close of business on November 7, 2016. As of September 30, 2016, cash distributions to our common units continue to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions and also prohibits us from making common unit cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution. 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 suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. Allocation of Net Income or Loss Net income or loss, net of distributions on the Preferred Units and amortization of the preferred unit beneficial conversion feature (see Class A Convertible Preferred Units section), is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership (exclusive of the Preferred Units limited partnership interest) during the period. The allocation of net income or loss is presented in our unaudited condensed consolidated statements of operations.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Agreements with Affiliates 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. These expenses are included in general and administrative expenses in our unaudited condensed consolidated statements of operations. Operating Agreements . 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. We and those third parties pay Mid-Con Energy Operating for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenses are included in lease operating expenses in our unaudited condensed consolidated statements of operations. Oilfield Services . We are party to operating agreements, pursuant to which Mid-Con Energy Operating bills us for oilfield services performed by our affiliate ME3 Oilfield Service. These amounts are either included in lease operating expenses in our unaudited condensed consolidated statements of operations or are capitalized as part of oil and natural gas properties in our unaudited condensed consolidated balance sheets. The following table summarizes the affiliates' transactions for the periods indicated: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Amounts paid for: (in thousands) Services agreement $ 914 $ 998 $ 2,440 $ 2,676 Operating agreements 1,509 2,067 4,790 6,225 Oilfield services 778 764 2,274 2,677 $ 3,201 $ 3,829 $ 9,504 $ 11,578 At September 30, 2016 and December 31, 2015, we had net payables to Mid-Con Energy Operating of approximately $0.1 million and $0.5 million , respectively, which were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.

New Accounting Standards

New Accounting Standards	9 Months Ended
	Sep. 30, 2016
Accounting Changes and Error Corrections [Abstract]
New Accounting Standards	New 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 Partnership is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard. In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Presentation of Financial Statements - Going Concern (Subtopic 205-40) : Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern. The amendments in ASU 2014-15 are intended to define management's responsibility to evaluate whether there is a substantial doubt about an entity’s ability to continue as a going concern and to provide related footnote disclosures. This standard is effective for the annual periods ending after December 15, 2016, and for interim periods within annual period beginning after December 15, 2016. Early adoption is permitted. As of September 30, 2016, the Partnership has not elected early adoption. In February 2016, the FASB issued ASU No. 2016-02, “ Leases (Topic 842),” which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. As of September 30, 2016, the Partnership has not elected early adoption. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting. The guidance simplifies the accounting for employee stock-based payment transactions including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification of awards as either equity or liabilities, and classification of related amounts within the statement of cash flows. The guidance requires the recognition of the income tax effects of awards in the income statement when the awards vest or are settled, thus eliminating additional paid in capital pools. The guidance also allows for the employer to repurchase more of an employee’s shares for tax withholding purposes without triggering liability accounting. In addition, the guidance allows for a policy election to account for forfeitures as they occur rather than on an estimated basis. The guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and early adoption is permitted. As of September 30, 2016, the Partnership has not elected early adoption. In August, 2016, the FASB issued Accounting Standards Update No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption during an interim period. As of September 30, 2016, the Partnership has not yet adopted this update and is currently evaluating the impact this guidance will have on its consolidated financial statements upon adoption of this standard.

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Class A Convertible Preferred Units As announced on October 27, 2016, the Board of Directors of the general partner declared a distribution for the period from August 11, 2016 to September 30, 2016 of approximately $0.3 million to be paid on November 14, 2016 to holders of record as of the close of business on November 7, 2016. Fall 2016 Borrowing Base Redetermination On October 28, 2016, the Partnership completed its fall 2016 semi-annual borrowing base redetermination under its reserve based revolving credit facility. The lender group agreed to reaffirm the previously existing conforming borrowing base of $140.0 million effective October 28, 2016. There were no changes to the terms or conditions of the credit agreement. The next regularly scheduled borrowing base redetermination will occur on or about May 1, 2017.

Organization and Nature of Op19

Organization and Nature of Operations (Policies)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the SEC. These financial statements have not been audited by our independent registered public accounting firm, except that the condensed consolidated balance sheet at December 31, 2015 is derived from the audited financial statements. Accordingly, certain information and footnote disclosures normally included in the financial statements prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") have been condensed or omitted in this Form 10-Q. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015 . All intercompany transactions and account balances have been eliminated. Reclassifications The consolidated statements of income for previous periods include certain reclassifications to the other income (expense) accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss). Non-cash Investing, Financing and Supplemental Cash Flow Information The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Nine Months Ended 2016 2015 (in thousands) Non-cash investing information: Change in accrued capital expenditures-oil and natural gas properties 513 619 Change in accrued capital expenditures-other property and equipment (14 ) — Tenant improvement allowance deferred-other property and equipment (124 ) — Change in accrued receivable-acquisition post-close adjustment 419 — Change in accrued receivable-divestiture post-close adjustment 354 — Non-cash financing information: Change in accrued capital expenditures-offering costs (302 ) — Supplemental cash flow information: Cash paid for interest 5,063 4,606

Organization and Nature of Op20

Organization and Nature of Operations Organization and Nature of Operations (Tables)	9 Months Ended
	Sep. 30, 2016
Supplemental Cash Flow Elements [Abstract]
Schedule of Cash Flow Supplemental Disclosures	The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Nine Months Ended 2016 2015 (in thousands) Non-cash investing information: Change in accrued capital expenditures-oil and natural gas properties 513 619 Change in accrued capital expenditures-other property and equipment (14 ) — Tenant improvement allowance deferred-other property and equipment (124 ) — Change in accrued receivable-acquisition post-close adjustment 419 — Change in accrued receivable-divestiture post-close adjustment 354 — Non-cash financing information: Change in accrued capital expenditures-offering costs (302 ) — Supplemental cash flow information: Cash paid for interest 5,063 4,606

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Divestiture information	The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying unaudited condensed consolidated statements of operations for the periods presented: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in thousands) Oil and natural gas sales $ 632 $ 2,921 $ 3,602 $ 9,294 Expenses (1) $ 591 $ 32,185 $ 7,717 $ 39,428 (1) Expenses include lease operating expenses, production taxes, accretion, depletion and impairment expenses.
Acquisitions Of Oil Properties	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands): Fair value of net assets: Oil and natural gas properties $ 19,280 Total assets acquired $ 19,280 Fair value of net liabilities assumed: Asset retirement obligation 622 Net assets acquired $ 18,658

Equity Awards (Tables)

Equity Awards (Tables)	9 Months Ended
	Sep. 30, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Summary of awards under Long-Term Incentive Program	The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at September 30, 2016 : Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,187,306 ) Restricted units granted, net of forfeitures (400,424 ) Equity-settled phantom units granted, net of forfeitures (457,500 ) Awards available for future grant 1,468,770
Summary of restricted units awarded	A summary of our restricted unit awards for the nine months ended September 30, 2016 is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 222,833 $ 8.49 Units granted — — Units vested (112,478 ) 9.16 Units forfeited (33,433 ) 9.69 Outstanding at September 30, 2016 76,922 $ 5.67
Summary of equity-settled units	A summary of our equity-settled phantom unit awards for the nine months ended September 30, 2016 is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 77,500 $ 2.81 Units granted 374,500 1.55 Units vested (146,841 ) 2.03 Units forfeited (17,500 ) 2.02 Outstanding at September 30, 2016 287,659 $ 1.64

Derivative Financial Instrume23

Derivative Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Contracts	At September 30, 2016 , we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls NYMEX Index Swaps - 2016 $ 64.18 1,304 WTI Puts - 2016 $ 50.00 $ — 1,957 WTI Collars - 2017 $ 40.00 $ 50.68 658 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI Collars - 2018 $ 44.38 $ 55.52 1,315 WTI Puts - 2018 $ 45.00 $ — 164 WTI At December 31, 2015, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls 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
Estimated Fair Value of Derivative Assets and Liabilities	The following tables summarize the gross fair value by the appropriate balance sheet classification, even when the derivative financial instruments are subject to netting arrangements and qualify for net presentation in our unaudited condensed consolidated balance sheets at September 30, 2016 and December 31, 2015: Gross Amounts Recognized Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheet Net Amounts (in thousands) September 30, 2016: Assets Derivative financial instruments - current asset $ 5,032 $ (3,656 ) $ 1,376 Derivative financial instruments - long-term asset 1,599 (1,599 ) — Total $ 6,631 $ (5,255 ) $ 1,376 Liabilities Derivative financial instruments - current liability $ (899 ) $ (1,408 ) $ (2,307 ) Derivative deferred premium - current liability (5,064 ) 5,064 — Derivative financial instruments - long-term liability (2,048 ) 56 (1,992 ) Derivative deferred premium - long-term liability (1,543 ) 1,543 — Total $ (9,554 ) $ 5,255 $ (4,299 ) Net Liability $ (2,923 ) $ — $ (2,923 ) Gross Gross Amounts Net Amounts (in thousands) December 31, 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 deferred premium - long-term liability (4,933 ) 4,933 — Total $ (10,487 ) $ 10,487 $ — Net Asset $ 25,563 $ — $ 25,563
Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations	The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations: Three Months Ended Nine Months Ended 2016 2015 2016 2015 (in thousands) Net settlements on matured derivatives $ 1,182 $ 8,383 $ 18,467 $ 15,566 Net settlements on early terminations and modifications of derivatives 5,820 — 5,820 11,069 Net change in fair value of derivatives (7,446 ) 11,388 (32,251 ) (14,091 ) Total (loss) gain on derivatives, net $ (444 ) $ 19,771 $ (7,964 ) $ 12,544

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of fair value measurements	The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value as of September 30, 2016 and December 31, 2015 : Level 1 Level 2 Level 3 Fair Value (in thousands) September 30, 2016 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments - asset $ — $ 6,631 $ — $ 6,631 Derivative financial instruments - liability $ — $ 2,947 $ — $ 2,947 Derivative deferred premiums - liability $ — $ — $ 6,607 $ 6,607 Assets and Liabilities Measured at Fair Value on a Non-recurring Basis Asset retirement obligations $ — $ — $ 714 $ 714 Impairment of proved oil and natural gas properties $ — $ — $ 895 $ 895 Impairment of proved oil and natural gas properties sold $ — $ — $ 3,578 $ 3,578 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 Assets and Liabilities Measured at Fair Value on a Non-recurring Basis Asset retirement obligations $ — $ — $ 4,924 $ 4,924 Impairment of proved oil and natural gas properties $ — $ — $ 103,938 $ 103,938
Schedule of changes in Level 3 fair value measurements	A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Nine Months Ended Year Ended (in thousands) Balance of Level 3 at beginning of period $ (9,973 ) $ — Derivative deferred premiums - purchases (400 ) (11,914 ) Derivative deferred premiums - settlements 3,766 1,941 Balance of Level 3 at end of period $ (6,607 ) $ (9,973 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	9 Months Ended
	Sep. 30, 2016
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in our ARO for the periods indicated are presented in the following table: Nine Months Ended Year Ended (in thousands) Asset retirement obligations - beginning of period $ 12,679 $ 7,363 Liabilities incurred for new wells and interest 714 42 Liabilities settled upon plugging and abandoning wells — (40 ) Liabilities removed upon sale of wells (2,827 ) — Revision of estimates (1) — 4,882 Accretion expense 443 432 Asset retirement obligations - end of period $ 11,009 $ 12,679

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of Debt	A summary of our debt at September 30, 2016 and year ended December 31, 2015 is presented below: Nine Months Ended Year Ended (in thousands) Revolving credit facility $ 127,900 $ 180,000 Less: current portion — 30,000 Total long-term debt $ 127,900 $ 150,000

Commitments and Contingencies -

Commitments and Contingencies - Non-Cancellable Operating Leases (Tables)	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Operating leases	Future minimum lease payments under the non-cancellable operating leases at September 30, 2016 were as follows (in thousands): Remaining 2016 $ 122 2017 490 2018 490 2019 413 2020 418 2021 423 Total $ 2,356

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes the affiliates' transactions for the periods indicated: Three Months Ended Nine Months Ended 2016 2015 2016 2015 Amounts paid for: (in thousands) Services agreement $ 914 $ 998 $ 2,440 $ 2,676 Operating agreements 1,509 2,067 4,790 6,225 Oilfield services 778 764 2,274 2,677 $ 3,201 $ 3,829 $ 9,504 $ 11,578

Organization and Nature of Op29

Organization and Nature of Operations (Details) - USD ($)	Oct. 28, 2016	Sep. 30, 2016	Jul. 28, 2016	May 31, 2016	Dec. 31, 2015	Nov. 30, 2015	Nov. 29, 2015	Jun. 30, 2015	Apr. 30, 2015
Debt Instrument [Line Items]
Revolving credit facility		$ 127,900,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Cash		2,100,000
Line of Credit Facility, Remaining Borrowing Capacity		12,100,000
Line of credit facility, maximum borrowing capacity		140,000,000	$ 105,000,000	$ 163,000,000		$ 190,000,000	$ 220,000,000	$ 240,000,000	$ 220,000,000
Revolving credit facility		$ 127,900,000			$ 180,000,000
Revolving Credit Facility [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 140,000,000
Revolving Credit Facility [Member] | Revolving Credit Facility, Conforming Tranche [Member]
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 110,000,000		$ 165,000,000

Organization and Nature of Op30

Organization and Nature of Operations Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Non-cash investing information:
Change in accrued capital expenditures-oil and natural gas properties	$ 513	$ 619
Change in accrued capital expenditures-other property and equipment	(14)	0
Tenant improvement allowance deferred-other property and equipment	(124)	0
Change in accrued receivable-acquisition post-close adjustment	419	0
Change in accrued receivable-divestiture post-close adjustment	354	0
Non-cash financing information:
Change in accrued capital expenditures-offering costs	(302)	0
Supplemental Cash Flow Information:
Cash paid for interest	$ 5,063	$ 4,606

Acquisitions and Divestitures31

Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	Aug. 11, 2016	Jul. 28, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Business Combinations [Abstract]
Oil and natural gas sales			$ 632	$ 2,921	$ 3,602	$ 9,294
Expenses			591	32,185	7,717	39,428
Aggregate purchase price, net	$ 18,700
Proceeds from Issuance of Preferred Stock, Gross	25,000				24,975	0
Business Acquisition Purchase Price Allocation Oil And Gas Properties	19,280
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	19,280
Business Acquisition Purchase Price Allocation Asset Retirement Obligations	622
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 18,658
Proceeds from sale of oil and natural gas properties		$ 17,900			17,312	0
Gain (Loss) on Disposition of Oil and Gas Property		$ 500	$ (530)	$ 0	$ (517)	$ 0

Equity Awards - Additional Info

Equity Awards - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Nov. 20, 2015
Unrestricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			73,932	274,550
Average grant date fair value per unit, granted			$ 1.20	$ 4.85
Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			0
Average grant date fair value per unit, granted			$ 0
Unrecognized compensation costs	$ 0.3		$ 0.3
Weighted average period - unrecognized cost			8 months
Equity-Settled Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			374,500
Average grant date fair value per unit, granted			$ 1.55
Unrecognized compensation costs	$ 0.4		$ 0.4
Weighted average period - unrecognized cost			1 year 9 months
Equity-Settled Phantom Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			2 years
Equity-Settled Phantom Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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
Vesting period			2 years
Vesting percentage			33.33%
Share-based Compensation Award, Tranche One [Member] | Equity-Settled Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			347,500	69,000
Vesting percentage			33.00%
Share-based Compensation Award, Tranche Two [Member] | Restricted Common Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period			3 years
Vesting percentage			66.66%
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized				26,100
Share-based Compensation Award, Tranche Two [Member] | Equity-Settled Phantom Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted			27,000	46,500
Vesting period			2 years
Vesting percentage			66.00%
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		1,764,000
Equity-based compensation expense	$ 0.3	$ 0.6	$ 1	$ 3

Equity Awards - Awards availabl

Equity Awards - Awards available for future grant (Details) - Long-Term Incentive Plan [Member] - shares	Sep. 30, 2016	Nov. 20, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000	1,764,000
Unrestricted units granted	(1,187,306)
Restricted units granted, net of forfeitures	(400,424)
Equity settled phantom units granted, net of forfeitures	(457,500)
Awards available for future grant	1,468,770

Equity Awards - Restricted Unit

Equity Awards - Restricted Units (Details) - Restricted Common Units [Member] - $ / shares	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Number of units
Outstanding, beginning of period	222,833
Units granted	0
Units vested	(112,478)
Units forfeited	(33,433)
Outstanding, end of period	76,922
Weighted Average Grant Date Fair Value per Phantom Unit
Average fair value per unit, outstanding	$ 8.49
Average grant date fair value per unit, granted	0
Average grant date fair value per unit, vested	9.16
Average grant date fair value per unit, forfeited	9.69
Average fair value per unit, outstanding	$ 5.67
Share-based Compensation Award, Tranche One [Member]
Number of units
Units granted		268,000
Share-based Compensation Award, Tranche Two [Member]
Weighted Average Grant Date Fair Value per Phantom Unit
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized		26,100

Equity Awards - Equity-Settled

Equity Awards - Equity-Settled Phantom Units (Details) - Equity-Settled Phantom Units [Member]	9 Months Ended
	Sep. 30, 2016$ / sharesshares
Number of units
Outstanding, beginning of period | shares	77,500
Units granted | shares	374,500
Units vested | shares	(146,841)
Units forfeited | shares	(17,500)
Outstanding, end of period | shares	287,659
Weighted Average Grant Date Fair Value per Phantom Unit
Average fair value per unit, outstanding | $ / shares	$ 2.81
Average grant date fair value per unit, granted | $ / shares	1.55
Average grant date fair value per unit, vested | $ / shares	2.03
Average grant date fair value per unit, forfeited | $ / shares	2.02
Average fair value per unit, outstanding | $ / shares	$ 1.64

Derivative Financial Instrume36

Derivative Financial Instruments Derivative Financial Instruments - Additional information (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value	$ (2,923)	$ 25,563

Derivative Financial Instrume37

Derivative Financial Instruments - Commodity Contracts (Details) - $ / Bbls	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Swap [Member] | Period Covered-2016 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	64.18	79.98
Total Bbls Hedged/day	1,304	1,598
Derivative, Underlying Basis	WTI	WTI
Put Option [Member] | Period Covered-2016 [Member]
Derivative [Line Items]
Weighted Average Floor Price	50	50
Total Bbls Hedged/day	1,957	1,475
Derivative, Underlying Basis	WTI	WTI
Put Option [Member] | Period Covered-2017 [Member]
Derivative [Line Items]
Weighted Average Floor Price	50	50
Total Bbls Hedged/day	1,932	1,932
Derivative, Underlying Basis	WTI	WTI
Put Option [Member] | Period Covered-2018 [Member] [Domain]
Derivative [Line Items]
Weighted Average Floor Price	45
Total Bbls Hedged/day	164
Derivative, Underlying Basis	WTI
Collar [Member] | Period Covered-2016 [Member]
Derivative [Line Items]
Weighted Average Floor Price		50
Weighted Average Ceiling Price		50
Total Bbls Hedged/day		328
Derivative, Underlying Basis		WTI
Collar [Member] | Period Covered-2017 [Member]
Derivative [Line Items]
Weighted Average Floor Price	40
Weighted Average Ceiling Price	50.68
Total Bbls Hedged/day	658
Derivative, Underlying Basis	WTI
Collar [Member] | Period Covered-2018 [Member] [Domain]
Derivative [Line Items]
Weighted Average Floor Price	44.38
Weighted Average Ceiling Price	55.52
Total Bbls Hedged/day	1,315
Derivative, Underlying Basis	WTI

Derivative Financial Instrume38

Derivative Financial Instruments Restructured Commodity Contracts (Details) - USD ($) $ in Thousands

Aug. 11, 2016

Jul. 01, 2016

Jan. 23, 2015

Nov. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2015

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Cash settlements received for early terminations and modifications of derivatives, net

$ 5,800

$ 5,820

$ 0

$ 5,820

$ 11,069

Derivative deferred premiums - settlements

$ 3,766

$ 1,941

Commodity Contract [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Cash settlements received for early terminations and modifications of derivatives, net

$ 11,100

Cash Received from Derivative - Calls

5,900

Cash paid for premiums

19,800

Fair Value of deferred premiums put option

$ 4,100

$ 7,800

Derivative deferred premiums - settlements

$ 1,500

$ 1,600

Commodity Contract [Member] | August 2016 Amended Credit Agreement [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of deferred premiums put option

$ 400

Scenario, Forecast [Member] | Commodity Contract [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Minimum coverage of projected production (percent)

50.00%

80.00%

Scenario, Forecast [Member] | Commodity Contract [Member] | August 2016 Amended Credit Agreement [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Minimum coverage of projected production (percent)

50.00%

75.00%

Derivative Financial Instrume39

Derivative Financial Instruments - Summary of Gross Fair Value by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Assets [Abstract]
Gross Amounts of Recognized Assets	$ 6,631	$ 36,050
Gross Amounts Offset	(5,255)	(10,487)
Net Amount presented - Balance Sheet	1,376	25,563
Liabilities [Abstract]
Gross Amounts of Recognized Liabilities	(9,554)	(10,487)
Gross Amounts Offset	5,255	10,487
Net Amount presented - Balance Sheet	(4,299)	0
Gross Amount of Recognized Assets and Liabilities	(2,923)	25,563
Gross Amounts Offset	0	0
Net Assets Presented - Balance Sheet	(2,923)	25,563
Current Asset [Member]
Assets [Abstract]
Gross Amounts of Recognized Assets	5,032	29,973
Gross Amounts Offset	(3,656)	(5,554)
Net Amount presented - Balance Sheet	1,376	24,419
Long Term Asset [Member]
Assets [Abstract]
Gross Amounts of Recognized Assets	1,599	6,077
Gross Amounts Offset	(1,599)	(4,933)
Net Amount presented - Balance Sheet	0	1,144
Current Liability [Member]
Liabilities [Abstract]
Gross Amounts of Recognized Liabilities	(899)	(514)
Gross Amounts Offset	(1,408)	514
Net Amount presented - Balance Sheet	(2,307)	0
Gross Amount Deferred premium	(5,064)	(5,040)
Deferred Premium Offset Against Collateral	5,064	5,040
Deferred Premium	0	0
Long Term Liability [Member]
Liabilities [Abstract]
Gross Amounts of Recognized Liabilities	(2,048)
Gross Amounts Offset	56
Net Amount presented - Balance Sheet	(1,992)
Gross Amount Deferred premium	(1,543)	(4,933)
Deferred Premium Offset Against Collateral	1,543	4,933
Deferred Premium	$ 0	$ 0

Derivative Financial Instrume40

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands	Jul. 01, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Net settlements on matured derivatives		$ 1,182	$ 8,383	$ 18,467	$ 15,566
Net settlements on early terminations and modifications of derivatives	$ 5,800	5,820	0	5,820	11,069
Net change in fair value of derivatives		(7,446)	11,388	(32,251)	(14,091)
Total (loss) gain on derivatives, net		$ (444)	$ 19,771	$ (7,964)	$ 12,544

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair value measurement, discount rate (percent)			10.00%
Asset impairment charges	$ 0	$ 40,920,000	$ 895,000	$ 40,920,000
Impairment of proved oil and natural gas properties sold	$ 0	$ 0	$ 3,578,000	$ 0

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis and Nonrecurring Basis (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	$ 1,376	$ 25,563
Derivative financial instruments - liability	4,299	0
Fair Value [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 instruments - asset	6,631	36,050
Derivative financial instruments - liability	2,947	514
Derivative deferred premiums - liability	6,607	9,973
Fair Value [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	714	4,924
Impairment of proved oil and natural gas properties	895	103,938
Impairment of proved oil and natural gas properties sold	3,578
Fair Value [Member] | 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 instruments - asset	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	0	0
Fair Value [Member] | 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 natural gas properties	0	0
Impairment of proved oil and natural gas properties sold	0
Fair Value [Member] | 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 instruments - asset	6,631	36,050
Derivative financial instruments - liability	2,947	514
Derivative deferred premiums - liability	0	0
Fair Value [Member] | 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 natural gas properties	0	0
Impairment of proved oil and natural gas properties sold	0
Fair Value [Member] | 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 instruments - asset	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	6,607	9,973
Fair Value [Member] | 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	714	4,924
Impairment of proved oil and natural gas properties	895	$ 103,938
Impairment of proved oil and natural gas properties sold	$ 3,578

Fair Value Disclosures - Summar

Fair Value Disclosures - Summary of Changes in assets (liabilities) - Level 3 (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance of Level 3 at beginning of period	$ (9,973)	$ 0
Derivative deferred premiums - purchases	(400)	(11,914)
Derivative deferred premiums - settlements	3,766	1,941
Balance of Level 3 at end of period	$ (6,607)	$ (9,973)

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Asset Retirement Obligation [Roll Forward]
Asset retirement obligation - beginning of period			$ 12,679	$ 7,363	$ 7,363
Liabilities incurred for new wells and interest			714		42
Liabilities settled upon plugging and abandoning wells			0		(40)
Asset Retirement Obligations Related To Sale Of Wells			(2,827)		0
Revision of estimates			0		4,882
Accretion expense	$ 127	$ 91	443	$ 276	432
Asset Retirement Obligation Non Current	$ 11,009		$ 11,009		12,679
Asset retirement obligation - end of period					$ 12,679

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Revolving credit facility	$ 127,900
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility	127,900	$ 180,000
Current portion	0	30,000
Long-term debt	$ 127,900	$ 150,000

Debt - Borrowings Outstanding (

Debt - Borrowings Outstanding (Details) - USD ($) $ in Thousands	Sep. 30, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Revolving credit facility	$ 127,900
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Revolving credit facility	$ 127,900	$ 180,000

Debt - Credit Facility Effectiv

Debt - Credit Facility Effective Rates (Details) - Revolving Credit Facility [Member]	9 Months Ended
	Sep. 30, 2016
Line of Credit Facility [Line Items]
Average effective rate	3.74%
Federal Funds Effective Swap Rate [Member]
Line of Credit Facility [Line Items]
Federal funds effective rate	0.50%
LIBOR [Member]
Line of Credit Facility [Line Items]
Federal funds effective LIBOR	1.00%
Minimum [Member]
Line of Credit Facility [Line Items]
Margin	1.00%
Unused portion of borrowing base, percentage fee	0.375%
Minimum [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Applicable margin rate	2.00%
Maximum [Member]
Line of Credit Facility [Line Items]
Margin	2.75%
Unused portion of borrowing base, percentage fee	0.50%
Maximum [Member] | LIBOR [Member]
Line of Credit Facility [Line Items]
Applicable margin rate	3.75%

Debt - Redetermination Details

Debt - Redetermination Details (Details) - USD ($)

May 31, 2016

May 31, 2016

Nov. 30, 2015

Sep. 30, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Aug. 11, 2016

Jul. 28, 2016

Nov. 29, 2015

Jun. 30, 2015

Apr. 30, 2015

Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Line of credit facility, maximum borrowing capacity

$ 163,000,000

$ 163,000,000

$ 190,000,000

$ 140,000,000

$ 105,000,000

$ 220,000,000

$ 240,000,000

$ 220,000,000

Debt Issuance Cost

700,000

LIne of credit overadvance

$ 53,000,000

53,000,000

Required monthly principal payments

1,900,000

Percentage of collateral coverage of proved reserves

90.00%

95.00%

Percentage of PDP reserves

100.00%

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

Line of Credit Facility [Line Items]

Line of credit facility, maximum borrowing capacity

$ 110,000,000

$ 110,000,000

165,000,000

Debt Instrument, Periodic Payment

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

August 2016 Amended Credit Agreement [Member] | Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Line of credit facility, maximum borrowing capacity

$ 140,000,000

Period to extend collateral coverage

30 days

Commodity Contract [Member] | Scenario, Forecast [Member]

Line of Credit Facility [Line Items]

Minimum coverage of projected production (percent)

50.00%

80.00%

Commodity Contract [Member] | Scenario, Forecast [Member] | Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Minimum coverage of projected production (percent)

50.00%

80.00%

Commodity Contract [Member] | Scenario, Forecast [Member] | August 2016 Amended Credit Agreement [Member]

Line of Credit Facility [Line Items]

Minimum coverage of projected production (percent)

50.00%

75.00%

Commodity Contract [Member] | Scenario, Forecast [Member] | August 2016 Amended Credit Agreement [Member] | Revolving Credit Facility [Member]

Line of Credit Facility [Line Items]

Minimum coverage of projected production (percent)

50.00%

75.00%

Commitment and Contingencies -

Commitment and Contingencies - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other Commitments [Line Items]
Lease expenses	$ 100	$ 100	$ 300	$ 300
Remaining 2,016	122		122
2,017	490		490
2,018	490		490
2,019	413		413
2,020	418		418
2,021	423		423
Total	$ 2,356		2,356
Minimum [Member]
Other Commitments [Line Items]
Employee agreement termination payments			300
Maximum [Member]
Other Commitments [Line Items]
Employee agreement termination payments			$ 700

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ in Millions	May 05, 2015	Sep. 30, 2016	Dec. 31, 2015
Equity [Line Items]
Limited partners, units outstanding		29,912,230	29,724,890
Limited partnership interest		98.80%
Maximum Proceeds Under Equity Distribution Agreement	$ 50

Equity Equity Class A Convertib

Equity Equity Class A Convertible Preferred Units (Details)	Aug. 11, 2016USD ($)$ / sharesshares	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Oct. 19, 2016USD ($)
Class of Stock [Line Items]
Preferred Units, Issued | shares	11,627,906
Proceeds from Issuance of Preferred Stock, Gross	$ 25,000,000	$ 24,975,000	$ 0
Convertible Preferred Units Initial Conversion Price | $ / shares	$ 2.15
Days after quarter end distribution paid	45 days
Preferred Stock Conversion Period	5 years
Preferred Stock, Conversion Basis, Percent		100.00%
Preferred Units Conversion Request	$ 1,000,000
Number of Days Within Closing Date To Registration Statement Required to File Within	90 days
Number of Days After Closing Date Registration Statement Declared Effective	180 days
Threshold for piggyback registration rights		$ 1,000,000
Threshold for demand registration rights		5,000,000
Proceeds from Issuance of Preferred Stock and Preference Stock, Net Of Issuance Costs	$ 24,700,000
Net proceeds allocated, fair value basis, to Preferred Units	18,700,000
Payments of Stock Issuance Costs	300,000
Convertible Preferred Units Beneficial Conversion Feature	6,000,000	6,047,000
Accretion of beneficial conversion feature of Class A convertible preferred units	$ 200,000	$ 166,000
Accretion period for beneficial conversion		5 years
Subsequent Event [Member]
Class of Stock [Line Items]
Preferred Units Distributions Declared				$ 300,000
Cash Dividends [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	8.00%
In Kind Dividends [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	10.00%
Preferred Units to Common Units [Member]
Class of Stock [Line Items]
Conversion ratio		1

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Net receivable from Mid-Con Energy Operating	$ 100		$ 100		$ 500
Mid-Con Energy Operating [Member]
Related Party Transaction [Line Items]
Direct administrative expenses paid	914	$ 998	2,440	$ 2,676
Related party op agreement fee paid	1,509	2,067	4,790	6,225
Related party oil field services	778	764	2,274	2,677
Costs and Expenses, Related Party	$ 3,201	$ 3,829	$ 9,504	$ 11,578

Subsequent Events (Details)

Subsequent Events (Details) - USD ($)	Oct. 28, 2016	Oct. 19, 2016	Sep. 30, 2016	Jul. 28, 2016	May 31, 2016	Nov. 30, 2015	Nov. 29, 2015	Jun. 30, 2015	Apr. 30, 2015
Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity Reaffirmed			$ 140,000,000	$ 105,000,000	$ 163,000,000	$ 190,000,000	$ 220,000,000	$ 240,000,000	$ 220,000,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Preferred Units Distributions Declared		$ 300,000
Subsequent Event [Member] | Revolving Credit Facility [Member]
Subsequent Event [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity Reaffirmed	$ 140,000,000