Mid-Con Energy Partners (MCEP) 10-Q 2 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 02, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
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	Smaller Reporting Company
Entity Common Stock, Shares Outstanding		30,305,628

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 612	$ 1,832
Accounts receivable
Oil and natural gas sales	5,028	5,262
Other	469	103
Prepaid expenses and other	497	166
Assets held for sale, net	430	2,058
Total current assets	7,036	9,421
Oil and natural gas properties, successful efforts method
Proved properties	352,822	335,796
Unproved properties	397	369
Other property and equipment	427	427
Accumulated depletion, depreciation, amortization and impairment	(141,294)	(129,101)
Total property and equipment, net	212,352	207,491
Other assets	1,947	2,451
Total assets	221,335	219,363
Accounts payable
Trade	799	593
Related parties	1,406	1,631
Derivative financial instruments	5,652	4,252
Accrued liabilities	384	603
Liabilities related to assets held for sale		77
Total current liabilities	8,241	7,156
Derivative financial instruments	1,325	666
Long-term debt	89,238	99,000
Other long-term liabilities	64	70
Asset retirement obligations	16,001	10,249
Commitments and contingencies
General partner	(695)	(572)
Limited partners - 30,305,628 and 30,090,463 units issued and outstanding, respectively	71,874	82,260
Total equity	71,179	81,688
Total liabilities, convertible preferred units and equity	221,335	219,363
Class A Convertible Preferred Units [Member]
Accounts payable
Convertible preferred units	20,819	$ 20,534
Class B Convertible Preferred Units [Member]
Accounts payable
Convertible preferred units	$ 14,468

Condensed Consolidated Balance3

Condensed Consolidated Balance Sheets (Parenthetical) - shares	Mar. 31, 2018	Dec. 31, 2017
Limited partners, units issued	30,305,628	30,090,463
Limited partners, units outstanding	30,305,628	30,090,463
Class A Convertible Preferred Units [Member]
Convertible Preferred Units, shares issued	11,627,906	11,627,906
Convertible Preferred Units, shares outstanding	11,627,906	11,627,906
Class B Convertible Preferred Units [Member]
Convertible Preferred Units, shares issued	9,803,921	0
Convertible Preferred Units, shares outstanding	9,803,921	0

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Revenues
Oil sales	$ 14,544	$ 14,955
Natural gas sales	168	396
(Loss) gain on derivatives, net	(3,382)	3,132
Total revenues	11,330	18,483
Operating costs and expenses
Lease operating expenses	4,801	4,992
Oil and natural gas production taxes	872	802
Impairment of proved oil and natural gas properties	8,751	0
Depreciation, depletion and amortization	3,441	4,869
Dry holes and abandonments of unproved properties	88
Accretion of discount on asset retirement obligations	153	108
General and administrative	1,894	1,826
Total operating costs and expenses	20,000	12,597
Loss on sales of oil and natural gas properties, net	(400)
(Loss) income from operations	(9,070)	5,886
Other (expense) income
Interest income	2	3
Interest expense	(1,339)	(1,450)
(Loss) gain on settlements of asset retirement obligations	(11)	3
Total other expense	(1,348)	(1,444)
Net (loss) income	(10,418)	4,442
Less: Distributions to preferred unitholders	1,016	798
Less: General partner's interest in net (loss) income	(123)	53
Limited partners' interest in net (loss) income	$ (11,311)	$ 3,591
Limited partners' interest in net (loss) income per unit
Basic	$ (0.37)	$ 0.12
Diluted	$ (0.37)	$ 0.11
Weighted average limited partner units outstanding
Limited partner units (basic)	30,176	29,927
Limited partner units (diluted)	30,176	41,837

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Cash Flows from Operating Activities
Net (loss) income	$ (10,418)	$ 4,442
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	3,441	4,869
Debt issuance costs amortization	154	336
Accretion of discount on asset retirement obligations	153	108
Impairment of proved oil and natural gas properties	8,751	0
Dry holes and abandonments of unproved properties	88
Loss (gain) on settlements of asset retirement obligations	11	(3)
Cash paid for settlements of asset retirement obligations	(27)	(9)
Loss (gain) on derivatives, net	3,382	(3,132)
Cash settlements paid for matured derivatives	(1,324)	(156)
Cash premiums paid for derivatives		(1,274)
Loss on sales of oil and natural gas properties	400
Non-cash equity-based compensation	239	165
Changes in operating assets and liabilities
Accounts receivable	234	427
Other receivables	(280)	233
Prepaids and other	(331)	99
Accounts payable - trade and accrued liabilities	319	617
Accounts payable - related parties	(357)	(1,904)
Net cash provided by operating activities	4,435	4,818
Cash Flows from Investing Activities
Acquisitions of oil and natural gas properties	(8,899)	(134)
Additions to oil and natural gas properties	(1,465)	(2,167)
Additions to other property and equipment		(7)
Proceeds from sales of oil and natural gas properties	1,151
Net cash used in investing activities	(9,213)	(2,308)
Cash Flows from Financing Activities
Proceeds from line of credit	2,000
Payments on line of credit	(11,762)	(1,500)
Offering costs		(70)
Debt issuance costs	(651)
Net cash provided by (used in) financing activities	3,558	(2,070)
Net (decrease) increase in cash and cash equivalents	(1,220)	440
Beginning cash and cash equivalents	1,832	2,359
Ending cash and cash equivalents	612	2,799
Class B Convertible Preferred Units [Member]
Cash Flows from Financing Activities
Proceeds from sale of Class B convertible preferred units, net of offering costs	14,971
Class A Convertible Preferred Units [Member]
Cash Flows from Financing Activities
Distributions to Class A convertible preferred units	$ (1,000)	$ (500)

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Changes in Equity - 3 months ended Mar. 31, 2018 - USD ($) shares in Thousands, $ in Thousands	Total	Class A Convertible Preferred Units [Member]	Class B Convertible Preferred Units [Member]	General Partner [Member]	Limited Partners [Member]	Limited Partners [Member]Class A Convertible Preferred Units [Member]	Limited Partners [Member]Class B Convertible Preferred Units [Member]
Balance at Dec. 31, 2017	$ 81,688			$ (572)	$ 82,260
Balance, Units at Dec. 31, 2017					30,091
Increase (Decrease) in Partners' Capital [Roll Forward]
Equity-based compensation	239				$ 239
Equity-based compensation, Units					215
Distributions to convertible preferred units		$ (500)	$ (200)			$ (500)	$ (200)
Allocation of value to beneficial conversion feature of Class B convertible preferred units			686				686
Accretion of beneficial conversion feature of convertible preferred units		$ (285)	$ (31)			$ (285)	$ (31)
Net loss	(10,418)			(123)	$ (10,295)
Balance at Mar. 31, 2018	$ 71,179			$ (695)	$ 71,874
Balance, Units at Mar. 31, 2018					30,306

Organization and Nature of Oper

Organization and Nature of Operations	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Organization and Nature of Operations	Note 1. Organization and Nature of Operations Nature of Operations Mid-Con Energy Partners, LP (“we,” “our,” “us,” the “Partnership,” or the “Company”) is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition 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 listed under the symbol “MCEP” on the NASDAQ. Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Basis of Presentation Our unaudited condensed consolidated financial statements are 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, 2017, 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 made are adequate to make the information not misleading. The unaudited condensed consolidated financial statements include 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. All intercompany transactions and account balances have been eliminated. Non-cash Investing and Supplemental Cash Flow Information The following presents the non-cash investing and supplemental cash flow information for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Non-cash investing information Change in oil and natural gas properties - accrued capital expenditures $ 132 $ 89 Change in oil and natural gas properties - accrued acquisition $ (86 ) $ — Change in oil and natural gas properties - acquisition deposit paid in prior year $ 1,000 $ — Supplemental cash flow information Cash paid for interest $ 892 $ 1,118

Acquisitions, Divestitures and

Acquisitions, Divestitures and Assets Held for Sale	3 Months Ended
	Mar. 31, 2018
Business Combinations [Abstract]
Acquisitions, Divestitures and Assets Held for Sale	Note 2. Acquisitions, Divestitures and Assets Held for Sale Acquisitions We adopted ASU No. 2017-01, “ Business Combinations Powder River Basin In January 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming, through two separate transactions collectively referred to as Powder River Basin (“PRB”). The House Creek Sussex Unit (“HCSU”) transaction qualified as an asset acquisition and the Pine Tree acquisition was accounted for as a business combination. We acquired Pine Tree for cash consideration of $8.5 million, after preliminary post-closing purchase price adjustments. The recognized fair values of the Pine Tree assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Oil and natural gas properties $ 9,380 Total assets acquired 9,380 Fair value of net liabilities assumed Asset retirement obligation 862 Net assets acquired $ 8,518 The following table presents revenues and expenses of the acquired oil and natural gas properties included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ 130 $ — Expenses (1) $ 120 $ — (1) Wheatland In June 2017, we acquired multiple oil and natural gas properties located in Oklahoma and Cleveland Counties, Oklahoma, for cash consideration of $4.0 million, after final post-closing purchase price adjustments. The recognized fair values of the assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Oil and natural gas properties $ 4,305 Other property and equipment 132 Total assets acquired 4,437 Fair value of net liabilities assumed Asset retirement obligation 407 Net assets acquired $ 4,030 The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ 722 $ — Expenses (1) $ 547 $ — (1) Divestitures Effective at closing, the operations and cash flows of the following divested properties were eliminated from the ongoing operations of the Partnership and the Partnership has no continuing involvement in these properties. The divestitures did not represent a strategic shift and did not have a major effect on the Partnership’s operations or financial results. Nolan County In January 2018, we completed the sale of certain oil and natural gas proved properties in Nolan County, Texas, for $1.5 million, prior to post-closing purchase price adjustments. These properties were deemed to meet held-for-sale accounting criteria as of December 31, 2017, and impairment of $0.3 million was recorded to reduce the carrying value of these assets to their estimated fair value of $1.5 million at December 31, 2017; therefore, no gain or loss was realized on the sale in 2018. The following table presents revenues and expenses of the divested oil and natural gas properties that were included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ — $ 177 Expenses (1) $ — $ 179 (1) Southern Oklahoma In December 2017, we sold the properties located in Southern Oklahoma for cash proceeds, net of expenses, of $21.7 million, prior to final post-closing purchase price adjustments, and recognized a loss of $4.6 million. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ (5 ) $ 2,641 Expenses (1) $ (17 ) $ 2,046 (1) Assets Held for Sale Land in Southern Oklahoma met held-for-sale criteria as of March 31, 2018, and December 31, 2017. The carrying value of $0.4 million was presented in “Assets held for sale, net” in our unaudited condensed consolidated balance sheets.

Equity Awards

Equity Awards	3 Months Ended
	Mar. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity Awards	Note 3. 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 Charles R. Olmstead, Executive Chairman of the Board, and Jeffrey R. Olmstead, President and Chief Executive Officer, and approved by the Board of Directors of our general partner (the “Board”). 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. The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at March 31, 2018: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,300,538 ) Restricted units granted, net of forfeitures (399,424 ) Equity-settled phantom units granted, net of forfeitures (830,669 ) Awards available for future grant 983,369 We recognized $0.2 million of total equity-based compensation expense for both three months ended March 31, 2018, and 2017. These costs are reported as a component of general and administrative expenses (“G&A”) in our unaudited condensed consolidated statements of operations. Unrestricted Unit Awards During the three months ended March 31, 2018, we granted 87,832 unrestricted units with an average grant date fair value of $1.79 per unit. During the three months ended March 31, 2017, we granted 25,400 unrestricted units with an average grant date fair value of $2.65 per unit. Restricted Unit Awards Restricted units vest over a period of two or three years. As of March 31, 2018, there were no unrecognized compensation costs related to non-vested restricted units. A summary of our restricted unit awards for the three months ended March 31, 2018, is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2017 6,362 $ 5.42 Units granted — — Units vested (6,362 ) 5.42 Units forfeited — — Outstanding at March 31, 2018 — $ — Equity-Settled Phantom Unit Awards Equity-settled phantom units vest over a period of two or three years 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. During the three months ended March 31, 2018, we granted 381,000 equity-settled phantom units with a two-year vesting period and 8,500 equity-settled phantom units with a three-year vesting period. During the three months ended March 31, 2017, we granted 9,000 equity-settled phantom units with a three-year vesting period A summary of our equity-settled phantom unit awards for the three months ended March 31, 2018, is presented below: Number of Equity- Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2017 117,495 $ 1.45 Units granted 389,500 1.75 Units vested (127,333 ) 1.75 Units forfeited — — Outstanding at March 31, 2018 379,662 $ 1.66

Derivative Financial Instrument

Derivative Financial Instruments	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Note 4. 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. 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. We account for our commodity derivative contracts at fair value. See Note 5 in this section for a description of our fair value measurements. 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 amounts paid or received on monthly settlements, proceeds from 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 March 31, 2018, and at December 31, 2017, our commodity derivative contracts were in a net liability position with a fair value of $7.0 million and $4.9 million, respectively. All of our commodity derivative contracts are with major financial institutions that are also lenders under our revolving credit facility. 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 March 31, 2018, all of our counterparties have performed pursuant to the terms of their commodity derivative contracts. 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 March 31, 2018, and December 31, 2017: (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheets Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheets March 31, 2018 Assets Derivative financial instruments - current asset $ 20 $ (20 ) $ — Total 20 (20 ) — Liabilities Derivative financial instruments - current liability (5,271 ) (381 ) (5,652 ) Derivative deferred premium - current liability (401 ) 401 — Derivative financial instruments - long-term liability (1,325 ) — (1,325 ) Total (6,997 ) 20 (6,977 ) Net Liability $ (6,977 ) $ — $ (6,977 ) (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheets Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheets December 31, 2017 Assets Derivative financial instruments - current asset $ 39 $ (39 ) $ — Total 39 (39 ) — Liabilities Derivative financial instruments - current liability (3,890 ) (362 ) (4,252 ) Derivative deferred premium - current liability (401 ) 401 — Derivative financial instruments - long-term liability (666 ) — (666 ) Total (4,957 ) 39 (4,918 ) Net Liability $ (4,918 ) $ — $ (4,918 ) The following table presents the impact of derivative financial instruments and their location within the unaudited condensed consolidated statements of operations: Three Months Ended March 31, (in thousands) 2018 2017 Net settlements on matured derivatives (1) $ (1,324 ) $ (156 ) Net change in fair value of derivatives (2,058 ) 3,288 Total (loss) gain on derivatives, net $ (3,382 ) $ 3,132 (1) At March 31, 2018, and December 31, 2017, our commodity derivative contracts had maturities at various dates through September 2020 and were comprised of commodity price swap, put and collar contracts. At March 31, 2018, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2018 $ 53.45 $ — $ — 513 WTI Puts - 2018 $ — $ 45.00 $ — 218 WTI Collars - 2018 $ — $ 44.13 $ 54.79 1,255 WTI Swaps - 2019 $ 56.14 $ — $ — 1,779 WTI Swaps - 2020 $ 54.81 $ — $ — 1,199 WTI At December 31, 2017, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2018 $ 51.33 $ — $ — 444 WTI Puts - 2018 $ — $ 45.00 $ — 164 WTI Collars - 2018 $ — $ 44.38 $ 55.52 1,315 WTI Swaps - 2019 $ 51.48 $ — $ — 427 WTI

Fair Value Disclosures

Fair Value Disclosures	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Note 5. 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 Measured 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, put and collar contracts. Level 3 - Financial assets and liabilities for which values are based on prices or valuation approaches 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 for the three months ended March 31, 2018, and for the year ended December 31, 2017. 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 material changes in valuation approach or related inputs for the three months ended March 31, 2018, and for the year ended December 31, 2017. 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. The Partnership’s deferred premiums associated with its commodity derivative contracts are categorized as Level 3, as the Partnership utilizes a net present value calculation to determine the valuation. See Note 4 in this section for a summary of our derivative financial instruments. The following sets forth, by level within the hierarchy, the value of our assets and liabilities measured at fair value on a recurring basis as of March 31, 2018, and December 31, 2017: (in thousands) Level 1 Level 2 Level 3 Fair Value March 31, 2018 Derivative financial instruments - asset $ — $ 20 $ — $ 20 Derivative financial instruments - liability $ — $ 6,596 $ — $ 6,596 Derivative deferred premiums - liability $ — $ — $ 401 $ 401 December 31, 2017 Derivative financial instruments - asset $ — $ 39 $ — $ 39 Derivative financial instruments - liability $ — $ 4,556 $ — $ 4,556 Derivative deferred premiums - liability $ — $ — $ 401 $ 401 A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: (in thousands) Three Months Ended March 31, 2018 Year Ended December 31, 2017 Balance of Level 3 at beginning of period $ (401 ) $ (5,449 ) Derivative deferred premiums - settlements — 5,048 Balance of Level 3 at end of period $ (401 ) $ (401 ) Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Asset Retirement Obligations 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. Acquisitions The estimated fair values of proved oil and natural gas properties acquired 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. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3 inputs. See Note 2 in this section for further discussion of the Partnership’s acquisitions. Reserves 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 reserves, future operating and developmental costs, future commodity prices, a market-based weighted average cost of capital rate and 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 begin with Level 1 NYMEX-WTI forward curve pricing, less Level 3 assumptions that include location, pricing adjustments and quality differentials. Impairment The need to test oil and natural gas assets 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 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. For the three months ended March 31, 2018, we recorded non-cash impairment of $8.8 million. There were no impairment charges for the three months ended March 31, 2017

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 6. 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 operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or successfully 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 ARO 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. 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 March 31, 2018, and December 31, 2017, 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: (in thousands) Three Months Ended March 31, 2018 Year Ended December 31, 2017 Asset retirement obligations - beginning of period $ 10,326 $ 11,331 Liabilities incurred for new wells and interest 5,623 759 Liabilities settled upon plugging and abandoning wells (16 ) (57 ) Liabilities removed upon sale of wells (77 ) (2,152 ) Revision of estimates (8 ) (75 ) Accretion expense 153 520 Asset retirement obligations - end of period $ 16,001 $ 10,326

Debt

Debt	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Debt	Note 7. Debt We had outstanding borrowings under our revolving credit facility of $89.2 million and $99.0 million at March 31, 2018, and December 31, 2017, respectively. Our current revolving credit facility matures in November 2020. 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 variables. 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 lenders, 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, the greater of the prime rate of 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 1.75% 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 the applicable LIBOR plus a margin that varies from 2.75% to 3.75% per annum according to the borrowing base usage. For the three months ended March 31, 2018, the average effective rate was 4.91% 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, leverage ratios and 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. During the spring 2017 semi-annual borrowing base redetermination of our revolving credit facility completed in May 2017, the lender group reaffirmed the Partnership’s $140.0 million conforming borrowing base effective May 24, 2017. There were no changes to the terms or conditions of the credit agreement. During the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnership received a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. On December 22, 2017, Amendment 11 to the credit agreement was finalized. The amendment extended the waiver of the leverage ratio default until January 31, 2018. This amendment decreased the Partnership’s borrowing base to $115.0 million effective December 22, 2017, and required the facility usage not exceed $100.0 million. The amendment also required that the cash proceeds received from the Southern Oklahoma divestiture on December 22, 2017, and the Nolan County divestiture on January 9, 2018, be applied to the borrowings outstanding. See Note 2 in this section for more information regarding these divestitures. On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 until November 2020 and increasing the borrowing base of the Partnership’s revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of the Partnership’s failure to maintain the required leverage ratios for the quarter ended September 30, 2017. The amendment also required the Partnership to have a minimum liquidity of 20% to make cash distributions to the Preferred Unitholders. As of March 31, 2018, we were in compliance with our financial covenants.

Commitment and Contingencies

Commitment and Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitment and Contingencies	Note 8. Commitments and Contingencies Leases We lease corporate office space in Tulsa, Oklahoma and Abilene, Texas. Total lease expenses were $0.1 million Future minimum lease payments under the non-cancellable operating leases are presented in the following table: (in thousands) Remaining 2018 $ 365 2019 413 2020 418 2021 423 Total $ 1,619 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. 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. Employment Agreements Our general partner has entered into employment agreements with Charles R. Olmstead, Executive Chairman of the Board and Jeffrey R. Olmstead, President and Chief Executive Officer. The employment agreements automatically renew for one-year terms on August 1st of each year unless either we or the employee gives written notice of termination by at least the preceding February. 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 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 $0.6 million, including the value of vesting of any outstanding units. Legal 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	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Equity	Note 9. Equity Common Units At March 31, 2018, and December 31, 2017, the Partnership’s equity consisted of 30,305,628 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 Preferred Units agreements described below, the Partnership suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until the fifth anniversary of the closing date of the Class A Preferred Units purchase agreement, without the consent of a majority of the holders of the outstanding Preferred Units. 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. As of March 31, 2018, cash distributions to our common units continued to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions. Management and the Board 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. There is no assurance as to future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors. Preferred Units The Partnership has issued two classes of Preferred Units. Per accounting guidance, we were required to allocate a portion of the proceeds from Preferred Units to a 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 class of Preferred Units. The beneficial conversion feature is accreted using the effective yield method over the period from the closing date to the effective date of the holder’s conversion right. The holders of our 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. We pay holders of Preferred Units a cumulative, quarterly cash distribution on Preferred Units then outstanding at an annual rate of 8.0%, or 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 Class A or Class B 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, or as otherwise permitted to accumulate pursuant to the Partnership Agreement. Prior to August 11, 2021, each holder of Preferred Units has 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. Upon conversion of the 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. Class A Preferred Units On August 11, 2016, we completed a private placement of 11,627,906 Class A Preferred Units for an aggregate offering price of $25.0 million. The Class A Preferred Units were issued at a price of $2.15 per Class A Preferred Unit (the “Class A 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 received net proceeds of $24.6 million (net of issuance costs of $0.4 million) in connection with the issuance of these Class A Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million) and the beneficial conversion feature ($6.0 million). Accretion of the beneficial conversion feature was $0.3 for the three months ended March 31, 2018, and 2017. At March 31, 2018, the Partnership had accrued $0.5 million for the first quarter 2018 distribution that will be paid in cash in May 2018. The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2018 July 1, 2017 - December 31, 2017 $ 0.086 $ 1,000 The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2017: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2017 October 1, 2016 - December 31, 2016 $ 0.043 $ 500 The registration statement registering resales of common units issued or to be issued upon conversion of the Class A Preferred Units was declared effective by the SEC on June 14, 2017. Class B Preferred Units On January 31, 2018, we completed a private placement of 9,803,921 Class B Preferred Units for an aggregate offering price of $15.0 million. The Class B Preferred Units were issued at a price of $1.53 per Class B Preferred Unit (the “Class B Unit Purchase Price”). Proceeds from this issuance were used to fund the acquisition of certain oil and natural gas properties located in Campbell and Converse Counties, Wyoming, and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $14.9 million in connection with the issuance of these Class B Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class B Preferred Units ($14.2 million) and the beneficial conversion feature ($0.7 million). Accretion of the beneficial conversion feature was $0.03 million for the three months ended March 31, 2018. At March 31, 2018, the Partnership had accrued $0.2 million for the prorated first quarter 2018 distribution that will be paid in cash in May 2018. Under the registration rights agreements, we were 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 Class B Preferred Units and have the registration statement declared effective within 180 days after the closing date. As of May 2, 2018, the common units to be issued were pending effectiveness of registration under a previously filed shelf registration statement on Form S-3. Allocation of Net Income or Loss Net income or loss is allocated to our general partner in proportion to its pro rata ownership during the period. The remaining net income or loss is allocated to the limited partner unitholders net of Preferred Unit distributions, including accretion of the Preferred Unit beneficial conversion feature. In the event of net income, diluted net income per partner unit reflects the potential dilution of non-vested restricted stock awards and the conversion of Preferred Units.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Note 10. 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 our affiliate, 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 G&A in our unaudited condensed consolidated statements of operations. Operating Agreements We, along with various third parties with an ownership interest in the same property, are parties to standard oil and natural gas joint operating agreements with our affiliate, Mid-Con Energy Operating. We and those third parties pay Mid-Con Energy Operating overhead associated with operating our properties and for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenses were included in lease operating expenses (“LOE”) in our unaudited condensed consolidated statements of operations. Oilfield Services We are party to operating agreements, pursuant to which our affiliate, Mid-Con Energy Operating, bills us for oilfield services performed by our affiliates, ME3 Oilfield Service and ME2 Well Services, LLC. These amounts are either included in LOE 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 March 31, (in thousands) 2018 2017 Services agreement $ 530 $ 641 Operating agreements 1,326 1,403 Oilfield services 911 810 $ 2,767 $ 2,854 At March 31, 2018, we had a net payable to our affiliate, Mid-Con Energy Operating, of $1.4 million, comprised of a joint interest billing payable of $1.2 million and a payable for operating services of $0.2 million. At December 31, 2017, we had a net payable to our affiliate, Mid-Con Energy Operating, of $1.6 million, comprised of a joint interest billing payable of $1.4 million and a payable for operating services of $0.2 million. These amounts were included in accounts payable-related parties in our unaudited condensed consolidated balance sheets.

New Accounting Standards

New Accounting Standards	3 Months Ended
	Mar. 31, 2018
Accounting Changes And Error Corrections [Abstract]
New Accounting Standards	Note 11. New Accounting Standards In February 2016, the FASB issued ASU No. 2016-02, “ Leases

Revenue Recognition

Revenue Recognition	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue Recognition	Note 12. Revenue Recognition We adopted ASC 606 effective January 1, 2018, using the modified retrospective approach. ASC 606 supersedes previous revenue recognition requirements in ASC 605 and includes a five-step revenue recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration to which we expect to be entitled in exchange for those goods or services. Under ASC 605, we followed the sales method of accounting for oil and natural gas sales revenues in which revenues were recognized on our share of actual proceeds from oil and natural gas sold to purchasers. Revenue recognition required for our oil and natural gas sales contracts by ASC 606 does not differ from revenue recognition required under ASC 605 to account for such contracts. Therefore, we concluded that there was no change in our revenue recognition under ASC 606 and the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, did not result in an adjustment to retained earnings. Revenue from Contracts with Customers Under our oil and natural gas sales contracts, enforceable rights and obligations arise at the time production occurs on dedicated leases as the Partnership promises to deliver goods in the form of oil or natural gas production on contractually-specified leases to the purchasers. Sales of oil and natural gas are recognized at the point that control of the product is transferred to the customer; title and risk of loss to the product generally transfers at the delivery point specified in the contract. The Partnership commits and dedicates for sale all of the crude oil or natural gas production from contractually agreed-upon leases to the purchaser. Our oil contract pricing provisions are tied to a market index, with certain marketing adjustments, including location and quality differentials as well as certain embedded marketing fees. Our natural gas sales revenues are a percentage of the proceeds received by the purchaser for selling the volume of gas produced by the Partnership on a monthly basis. The purchaser sells the volume of natural gas at index rates per Mcf. Transaction Price Allocated to Remaining Performance Obligations Our product sales are generally short-term in nature, with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14, exempting the Partnership from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. We have utilized the practical expedient in ASC 606-10-50-14(a), which states the Partnership is not required to disclose the transaction price allocated to remaining performance obligations for specific situations in which the Partnership does not need to estimate variable consideration to recognize revenue. For our crude oil sales and natural gas sales contracts, the variable consideration related to variable production in not estimated because the uncertainty related to the consideration is resolved as the barrels of oil and Mcf of natural gas are transferred to the customer each day. Contract Balances Our product sales contracts do not give rise to contract assets or liabilities under ASC 606.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 13. Subsequent Events Distributions The Board declared Preferred Unit distributions for the first quarter of 2018, according to terms outlined in the Partnership Agreement. Distributions will be paid on May 15, 2018, to holders of record as of the close of business on May 7, 2018. The Class A Preferred Unit cash distributions will be $0.043 per Class A Preferred Unit, or $0.5 million in aggregate. Additionally, the Class B Preferred Unit cash distributions will be $0.020 per Class B Preferred Unit, or $0.2 million in aggregate for the prorated period. Class B Preferred Unit Shelf Registration On May 1, 2018, we filed a shelf registration statement on Form S-3, registering resales of common units issued or to be issued upon conversion of the Class B Preferred Units.

Organization and Nature of Op20

Organization and Nature of Operations (Policies)	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation Our unaudited condensed consolidated financial statements are 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, 2017, 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 made are adequate to make the information not misleading. The unaudited condensed consolidated financial statements include 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. All intercompany transactions and account balances have been eliminated.

Organization and Nature of Op21

Organization and Nature of Operations (Tables)	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Schedule of Cash Flow Supplemental Disclosures	The following presents the non-cash investing and supplemental cash flow information for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Non-cash investing information Change in oil and natural gas properties - accrued capital expenditures $ 132 $ 89 Change in oil and natural gas properties - accrued acquisition $ (86 ) $ — Change in oil and natural gas properties - acquisition deposit paid in prior year $ 1,000 $ — Supplemental cash flow information Cash paid for interest $ 892 $ 1,118

Acquisitions, Divestitures an22

Acquisitions, Divestitures and Assets Held for Sale, Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2018
Pine Tree [Member]
Acquisitions of Oil Properties	The recognized fair values of the Pine Tree assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Oil and natural gas properties $ 9,380 Total assets acquired 9,380 Fair value of net liabilities assumed Asset retirement obligation 862 Net assets acquired $ 8,518
Summary of Revenues and Expenses of Properties Acquired	The following table presents revenues and expenses of the acquired oil and natural gas properties included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ 130 $ — Expenses (1) $ 120 $ — (1)
Wheatland [Member]
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 acquired Oil and natural gas properties $ 4,305 Other property and equipment 132 Total assets acquired 4,437 Fair value of net liabilities assumed Asset retirement obligation 407 Net assets acquired $ 4,030
Summary of Revenues and Expenses of Properties Acquired	The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ 722 $ — Expenses (1) $ 547 $ — (1)

Acquisitions, Divestitures an23

Acquisitions, Divestitures and Assets Held for Sale, Divestitures (Tables)	3 Months Ended
	Mar. 31, 2018
Nolan County [Member]
Divestiture [Line Items]
Divestiture Information	The following table presents revenues and expenses of the divested oil and natural gas properties that were included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ — $ 177 Expenses (1) $ — $ 179 (1)
Southern Oklahoma [Member]
Divestiture [Line Items]
Divestiture Information	The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: Three Months Ended March 31, (in thousands) 2018 2017 Oil and natural gas sales $ (5 ) $ 2,641 Expenses (1) $ (17 ) $ 2,046 (1)

Equity Awards (Tables)

Equity Awards (Tables)	3 Months Ended
	Mar. 31, 2018
Disclosure Of Compensation Related Costs Sharebased 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 March 31, 2018: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,300,538 ) Restricted units granted, net of forfeitures (399,424 ) Equity-settled phantom units granted, net of forfeitures (830,669 ) Awards available for future grant 983,369
Summary of restricted units awarded	A summary of our restricted unit awards for the three months ended March 31, 2018, is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2017 6,362 $ 5.42 Units granted — — Units vested (6,362 ) 5.42 Units forfeited — — Outstanding at March 31, 2018 — $ —
Summary of equity-settled units	A summary of our equity-settled phantom unit awards for the three months ended March 31, 2018, is presented below: Number of Equity- Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2017 117,495 $ 1.45 Units granted 389,500 1.75 Units vested (127,333 ) 1.75 Units forfeited — — Outstanding at March 31, 2018 379,662 $ 1.66

Derivative Financial Instrume25

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 March 31, 2018, and December 31, 2017: (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheets Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheets March 31, 2018 Assets Derivative financial instruments - current asset $ 20 $ (20 ) $ — Total 20 (20 ) — Liabilities Derivative financial instruments - current liability (5,271 ) (381 ) (5,652 ) Derivative deferred premium - current liability (401 ) 401 — Derivative financial instruments - long-term liability (1,325 ) — (1,325 ) Total (6,997 ) 20 (6,977 ) Net Liability $ (6,977 ) $ — $ (6,977 ) (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Unaudited Condensed Consolidated Balance Sheets Net Amounts Presented in the Unaudited Condensed Consolidated Balance Sheets December 31, 2017 Assets Derivative financial instruments - current asset $ 39 $ (39 ) $ — Total 39 (39 ) — Liabilities Derivative financial instruments - current liability (3,890 ) (362 ) (4,252 ) Derivative deferred premium - current liability (401 ) 401 — Derivative financial instruments - long-term liability (666 ) — (666 ) Total (4,957 ) 39 (4,918 ) Net Liability $ (4,918 ) $ — $ (4,918 )
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 March 31, (in thousands) 2018 2017 Net settlements on matured derivatives (1) $ (1,324 ) $ (156 ) Net change in fair value of derivatives (2,058 ) 3,288 Total (loss) gain on derivatives, net $ (3,382 ) $ 3,132 (1)
Commodity Contracts	At March 31, 2018, and December 31, 2017, our commodity derivative contracts had maturities at various dates through September 2020 and were comprised of commodity price swap, put and collar contracts. At March 31, 2018, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2018 $ 53.45 $ — $ — 513 WTI Puts - 2018 $ — $ 45.00 $ — 218 WTI Collars - 2018 $ — $ 44.13 $ 54.79 1,255 WTI Swaps - 2019 $ 56.14 $ — $ — 1,779 WTI Swaps - 2020 $ 54.81 $ — $ — 1,199 WTI At December 31, 2017, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2018 $ 51.33 $ — $ — 444 WTI Puts - 2018 $ — $ 45.00 $ — 164 WTI Collars - 2018 $ — $ 44.38 $ 55.52 1,315 WTI Swaps - 2019 $ 51.48 $ — $ — 427 WTI

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of fair value measurements	The following sets forth, by level within the hierarchy, the value of our assets and liabilities measured at fair value on a recurring basis as of March 31, 2018, and December 31, 2017: (in thousands) Level 1 Level 2 Level 3 Fair Value March 31, 2018 Derivative financial instruments - asset $ — $ 20 $ — $ 20 Derivative financial instruments - liability $ — $ 6,596 $ — $ 6,596 Derivative deferred premiums - liability $ — $ — $ 401 $ 401 December 31, 2017 Derivative financial instruments - asset $ — $ 39 $ — $ 39 Derivative financial instruments - liability $ — $ 4,556 $ — $ 4,556 Derivative deferred premiums - liability $ — $ — $ 401 $ 401
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: (in thousands) Three Months Ended March 31, 2018 Year Ended December 31, 2017 Balance of Level 3 at beginning of period $ (401 ) $ (5,449 ) Derivative deferred premiums - settlements — 5,048 Balance of Level 3 at end of period $ (401 ) $ (401 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	As of March 31, 2018, and December 31, 2017, 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: (in thousands) Three Months Ended March 31, 2018 Year Ended December 31, 2017 Asset retirement obligations - beginning of period $ 10,326 $ 11,331 Liabilities incurred for new wells and interest 5,623 759 Liabilities settled upon plugging and abandoning wells (16 ) (57 ) Liabilities removed upon sale of wells (77 ) (2,152 ) Revision of estimates (8 ) (75 ) Accretion expense 153 520 Asset retirement obligations - end of period $ 16,001 $ 10,326

Commitments and Contingencies -

Commitments and Contingencies - Non-Cancellable Operating Leases (Tables)	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Operating leases	Future minimum lease payments under the non-cancellable operating leases are presented in the following table: (in thousands) Remaining 2018 $ 365 2019 413 2020 418 2021 423 Total $ 1,619

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Cash Distributions - Preferred Unitholders	The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2018 July 1, 2017 - December 31, 2017 $ 0.086 $ 1,000 The following table summarizes cash distributions paid on our Class A Preferred Units during the three months ended March 31, 2017: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2017 October 1, 2016 - December 31, 2016 $ 0.043 $ 500

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes the affiliates’ transactions for the periods indicated: Three Months Ended March 31, (in thousands) 2018 2017 Services agreement $ 530 $ 641 Operating agreements 1,326 1,403 Oilfield services 911 810 $ 2,767 $ 2,854

Organization and Nature of Op31

Organization and Nature of Operations - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Non-cash investing information
Change in oil and natural gas properties - accrued capital expenditures	$ 132	$ 89
Change in oil and natural gas properties - accrued acquisition	(86)	0
Change in oil and natural gas properties - acquisition deposit paid in prior year	1,000	0
Supplemental cash flow information
Cash paid for interest	$ 892	$ 1,118

Acquisitions, Divestitures an32

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions - Additional Information (Details) $ in Millions	1 Months Ended
	Jan. 31, 2018USD ($)Transaction	Jun. 30, 2017USD ($)
Powder River Basin [Member]
Business Acquisition [Line Items]
Number of transactions in acquisitions | Transaction	2
Pine Tree [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net	$ 8.5
Wheatland [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net		$ 4

Acquisitions, Divestitures an33

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions of Oil Properties (Details) - USD ($) $ in Thousands	Jan. 31, 2018	Jun. 30, 2017
Pine Tree [Member]
Business Acquisition [Line Items]
Oil and natural gas properties	$ 9,380
Total assets acquired	9,380
Asset retirement obligation	862
Net assets acquired	$ 8,518
Wheatland [Member]
Business Acquisition [Line Items]
Oil and natural gas properties		$ 4,305
Other property and equipment		132
Total assets acquired		4,437
Asset retirement obligation		407
Net assets acquired		$ 4,030

Acquisitions, Divestitures an34

Acquisitions, Divestitures and Assets Held for Sale - Summary of Revenues and Expenses of Properties Acquired (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired	$ 11,330	$ 18,483
Expenses of oil and natural gas properties acquired	20,000	$ 12,597
Pine Tree [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired	130
Expenses of oil and natural gas properties acquired	120
Wheatland [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired	722
Expenses of oil and natural gas properties acquired	$ 547

Acquisitions, Divestitures an35

Acquisitions, Divestitures and Assets Held for Sale - Divestitures - Additional Information (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2017	Mar. 31, 2018	Jan. 31, 2018
Divestiture [Line Items]
Gain (loss) on sales of oil and natural gas properties, net			$ (400,000)
Cash proceeds, net of expenses from sale of oil and natural gas properties			1,151,000
Nolan County [Member]
Divestiture [Line Items]
Aggregate sale price				$ 1,500,000
Impairment of proved oil and natural gas properties held for sale	$ 300,000
Assets held-for-sale, fair value	$ 1,500,000	$ 1,500,000
Gain (loss) on sales of oil and natural gas properties, net			$ 0
Southern Oklahoma [Member]
Divestiture [Line Items]
Gain (loss) on sales of oil and natural gas properties, net		(4,600,000)
Cash proceeds, net of expenses from sale of oil and natural gas properties		$ 21,700,000

Acquisitions, Divestitures an36

Acquisitions, Divestitures and Assets Held for Sale - Divestiture Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Nolan County [Member]
Divestiture [Line Items]
Divestiture oil and gas revenue		$ 177
Divestiture oil and gas expense		179
Southern Oklahoma [Member]
Divestiture [Line Items]
Divestiture oil and gas revenue	$ (5)	2,641
Divestiture oil and gas expense	$ (17)	$ 2,046

Acquisitions, Divestitures an37

Acquisitions, Divestitures and Assets Held for Sale - Assets Held for Sale - Additional Information (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Divestiture [Line Items]
Assets held for sale, net	$ 430	$ 2,058
Southern Oklahoma [Member]
Divestiture [Line Items]
Assets held for sale, net	$ 400

Equity Awards - Awards availabl

Equity Awards - Awards available for future grant (Details) - Long-Term Incentive Plan [Member]	Mar. 31, 2018shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Approved and authorized awards	3,514,000
Unrestricted units granted	(1,300,538)
Restricted units granted, net of forfeitures	(399,424)
Equity-settled phantom units granted, net of forfeitures	(830,669)
Awards available for future grant	983,369

Equity Awards - Additional Info

Equity Awards - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Long-Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation expense	$ 0.2	$ 0.2

Equity Awards - Unrestricted Un

Equity Awards - Unrestricted Units - Additional Information (Details) - Unrestricted Common Units [Member] - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units granted	87,832	25,400
Average grant date fair value per unit, granted	$ 1.79	$ 2.65

Equity Awards - Restricted Unit

Equity Awards - Restricted Units - Additional Information (Details) - Restricted Common Units [Member] $ in Thousands	3 Months Ended
	Mar. 31, 2018USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation costs	$ 0
Tranche One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years

Equity Awards - Restricted Un42

Equity Awards - Restricted Units (Details) - Restricted Common Units [Member]	3 Months Ended
	Mar. 31, 2018$ / sharesshares
Number of units
Outstanding, beginning of period | shares	6,362
Units granted | shares	0
Units vested | shares	(6,362)
Units forfeited | shares	0
Outstanding, end of period | shares	0
Weighted Average Grant Date Fair Value per Restricted Unit
Average fair value per unit, outstanding, beginning of period | $ / shares	$ 5.42
Average grant date fair value per unit, granted | $ / shares	0
Average grant date fair value per unit, vested | $ / shares	5.42
Average grant date fair value per unit, forfeited | $ / shares	0
Average fair value per unit, outstanding, end of period | $ / shares	$ 0

Equity Awards - Equity-Settled

Equity Awards - Equity-Settled Phantom Units - Additional Information (Details) - Equity-Settled Phantom Units [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.7
Weighted average period, unrecognized costs	22 months
Units granted	389,500
Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years
Units granted	381,000
Tranche Three [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Units granted	8,500	9,000
Minimum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years
Maximum [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years

Equity Awards - Equity-Settle44

Equity Awards - Equity-Settled Phantom Units (Details) - Equity-Settled Phantom Units [Member]	3 Months Ended
	Mar. 31, 2018$ / sharesshares
Number of units
Outstanding, beginning of period | shares	117,495
Units granted | shares	389,500
Units vested | shares	(127,333)
Outstanding, end of period | shares	379,662
Weighted Average Grant Date Fair Value per Phantom Unit
Average fair value per unit, outstanding, beginning of period | $ / shares	$ 1.45
Average grant date fair value per unit, granted | $ / shares	1.75
Average grant date fair value per unit, vested | $ / shares	1.75
Average fair value per unit, outstanding, end of period | $ / shares	$ 1.66

Derivative Financial Instrume45

Derivative Financial Instruments - Additional information (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value	$ (6,977)	$ (4,918)

Derivative Financial Instrume46

Derivative Financial Instruments - Summary of Gross Fair Value by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Assets
Derivative Asset, Fair Value, Gross Asset	$ 20	$ 39
Gross Amounts Offset	(20)	(39)
Net Amount presented - Balance Sheet	0	0
Liabilities
Gross Amounts of Recognized Liabilities	(6,997)	(4,957)
Gross Amounts Offset	20	39
Net Amount presented - Balance Sheet	(6,977)	(4,918)
Gross Amount of Recognized Assets and Liabilities	(6,977)	(4,918)
Gross Amounts Offset	0	0
Net Assets (Liability) Presented - Balance Sheet	(6,977)	(4,918)
Current Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset	20	39
Gross Amounts Offset	(20)	(39)
Net Amount presented - Balance Sheet	0	0
Current Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(5,271)	(3,890)
Gross Amount Deferred premium	(401)	(401)
Gross Amounts Offset	(381)	(362)
Deferred Premium Offset	401	401
Net Amount presented - Balance Sheet	(5,652)	(4,252)
Deferred Premium	0	0
Long Term Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(1,325)	(666)
Gross Amounts Offset	0	0
Net Amount presented - Balance Sheet	$ (1,325)	$ (666)

Derivative Financial Instrume47

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net settlements on matured derivatives	[1]	$ (1,324)	$ (156)
Net change in fair value of derivatives		(2,058)	3,288
Total (loss) gain on derivatives, net		$ (3,382)	$ 3,132
[1]	The settlement amount does not include premiums paid attributable to contracts that matured or early terminated during the respective period.

Derivative Financial Instrume48

Derivative Financial Instruments - Commodity Contracts (Details) - $ / bbl	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Swap [Member] | Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	53.45	51.33
Total Bbls Hedged/day	513	444
Derivative, Underlying Basis	WTI	WTI
Swap [Member] | Period Covered-2019 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	56.14	51.48
Total Bbls Hedged/day	1,779	427
Derivative, Underlying Basis	WTI	WTI
Swap [Member] | Period Covered-2020 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	54.81
Total Bbls Hedged/day	1,199
Derivative, Underlying Basis	WTI
Put Option [Member] | Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Floor Price	45	45
Total Bbls Hedged/day	218	164
Derivative, Underlying Basis	WTI	WTI
Collar [Member] | Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Floor Price	44.13	44.38
Weighted Average Ceiling Price	54.79	55.52
Total Bbls Hedged/day	1,255	1,315
Derivative, Underlying Basis	WTI	WTI

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis and Nonrecurring Basis (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	$ 0	$ 0
Derivative financial instruments - liability	6,977	4,918
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	20	39
Derivative financial instruments - liability	6,596	4,556
Derivative deferred premiums - liability	401	401
Level 1 [Member] | 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	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	0	0
Level 2 [Member] | 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	20	39
Derivative financial instruments - liability	6,596	4,556
Derivative deferred premiums - liability	0	0
Level 3 [Member] | 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	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	$ 401	$ 401

Fair Value Disclosures - Summar

Fair Value Disclosures - Summary of Changes in assets (liabilities) - Level 3 (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance of Level 3 at beginning of period	$ (401)	$ (5,449)
Derivative deferred premiums - settlements	0	5,048
Balance of Level 3 at end of period	$ (401)	$ (401)

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Inputs, Discount Rate	10.00%
Impairment expense	$ 8,751	$ 0

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Asset Retirement Obligation [Roll Forward]
Asset retirement obligations - beginning of period	$ 10,326	$ 11,331	$ 11,331
Liabilities incurred for new wells and interest	5,623		759
Liabilities settled upon plugging and abandoning wells	(16)		(57)
Liabilities removed upon sale of wells	(77)		(2,152)
Revision of estimates	(8)		(75)
Accretion expense	153	$ 108	520
Asset retirement obligations - end of period	$ 16,001		$ 10,326

Debt - Additional Information (

Debt - Additional Information (Details) - Revolving Credit Facility [Member] - USD ($)	Jan. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 22, 2017	May 24, 2017
Line of Credit Facility Line Items
Revolving credit facility		$ 89,200,000	$ 99,000,000
Revolving credit facility maturity date		Nov. 30, 2020
Average effective rate		4.91%
Line of credit facility, maximum borrowing capacity	$ 125,000,000			$ 115,000,000	$ 140,000,000
Line of credit facility, Current borrowing capacity				$ 100,000,000
Minimum liquidity percentage for cash distributions to the preferred unit holders	20.00%
Federal Funds Effective Swap Rate [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate		0.50%
LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate		1.00%
Minimum [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate		1.75%
Unused portion of borrowing base, percentage fee		2.75%
Minimum [Member] | LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate		2.75%
Maximum [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate		2.75%
Unused portion of borrowing base, percentage fee		3.75%
Maximum [Member] | LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate		3.75%

Commitment and Contingencies -

Commitment and Contingencies - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Commitments Contingencies And Litigation [Line Items]
Lease expense	$ 0.1	$ 0.1
Minimum [Member]
Commitments Contingencies And Litigation [Line Items]
Employee Termination Expenses	0.3
Maximum [Member]
Commitments Contingencies And Litigation [Line Items]
Employee Termination Expenses	$ 0.6

Commitment and Contingencies 55

Commitment and Contingencies - Operating Leases (Details) $ in Thousands	Mar. 31, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
Remaining 2,018	$ 365
2,019	413
2,020	418
2,021	423
Total	$ 1,619

Equity - Additional Information

Equity - Additional Information (Details) - USD ($)	May 05, 2015	Mar. 31, 2018	Dec. 31, 2017
Equity [Abstract]
Limited partners, units outstanding		30,305,628	30,090,463
Limited partnership interest		98.80%
Maximum proceeds under equity distribution agreement - suspended	$ 50,000,000

Equity - Preferred Units - Addi

Equity - Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands	Jan. 31, 2018USD ($)$ / sharesshares	Aug. 11, 2016USD ($)$ / sharesshares	Mar. 31, 2018USD ($)Class	Mar. 31, 2017USD ($)
Preferred Units [Member]
Class of Stock [Line Items]
Number of class of preferred units issued | Class			2
Days after quarter end distribution paid			45 days
Preferred Units [Member] | Cash Dividends [Member]
Class of Stock [Line Items]
Dividend rate (percentage)			8.00%
Preferred Units [Member] | In Kind Dividends [Member]
Class of Stock [Line Items]
Dividend rate (percentage)			10.00%
Class A Preferred Units [Member]
Class of Stock [Line Items]
Preferred Units, Issued | shares		11,627,906
Proceeds from sale of convertible preferred units, gross		$ 25,000
Price per share for preferred units (in dollars per share) | $ / shares		$ 2.15
Proceeds from sale of convertible preferred units, net of offering costs		$ 24,600
Issuance costs		400
Net proceeds allocated, fair value basis, to Preferred Units		18,600
Allocation of value to beneficial conversion feature of convertible preferred units		$ 6,000
Accretion of beneficial conversion			$ 300	$ 300
Preferred units distribution accrued			500
Class B Preferred Units [Member]
Class of Stock [Line Items]
Proceeds from sale of convertible preferred units, net of offering costs			14,971
Allocation of value to beneficial conversion feature of convertible preferred units			686
Preferred units distribution accrued			200
Class B Preferred Units [Member] | Private Placement [Member]
Class of Stock [Line Items]
Preferred Units, Issued | shares	9,803,921
Proceeds from sale of convertible preferred units, gross	$ 15,000
Proceeds from sale of convertible preferred units, net of offering costs	14,900
Net proceeds allocated, fair value basis, to Preferred Units	14,200
Allocation of value to beneficial conversion feature of convertible preferred units	$ 700
Accretion of beneficial conversion			$ 30
Price per share for preferred units | $ / shares	$ 1.53
Number of days within closing date	90 days
Number of days after closing date	180 days

Equity - Cash Distributions Pre

Equity - Cash Distributions Preferred Unitholders (Details) - Class A Preferred Units [Member] - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Preferred Units [Line Items]
Date Paid	Feb. 14, 2018	Feb. 14, 2017
Distribution per Unit	$ 0.086	$ 0.043
Total Distributions	$ 1,000	$ 500

Related Party Transactions Rela

Related Party Transactions Related Party Transactions- Affiliate Transactions (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Related Party Transaction [Line Items]
Services agreement	$ 530	$ 641
Operating agreements	1,326	1,403
Oilfield services	911	810
Costs and expenses, Related Party	$ 2,767	$ 2,854

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Other transactions of related party	$ 1.4	$ 1.6
Joint interest billing payable	1.2	1.4
Operating services payable	$ 0.2	$ 0.2

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue, performance obligation, description of timing	one year or less
Revenue, remaining performance obligation, expected timing of satisfaction	one year or less

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	May 02, 2018	Mar. 31, 2018	Mar. 31, 2017
Class A Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit		$ 0.086	$ 0.043
Subsequent Event [Member] | Class A Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit	$ 0.043
Preferred Units Distributions Declared	$ 0.5
Subsequent Event [Member] | Class B Preferred Units [Member] | Additional Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit	$ 0.020
Preferred Units Distributions Declared	$ 0.2