Mid-Con Energy Partners (MCEP) 10-K13 Mar 192018 FY Annual reportFinancial data

Company Profile

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
Document and Entity Information - USD ($) $ in Millions	Dec. 31, 2018	Feb. 28, 2019	Jun. 30, 2018
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	MCEP
Entity Registrant Name	Mid-Con Energy Partners, LP
Entity Central Index Key	0001527709
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 40.4
Entity Common Stock, Shares Outstanding		30,658,958

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 467	$ 1,832
Accounts receivable
Oil and natural gas sales	3,691	5,262
Other	503	103
Derivative financial instruments	5,666
Prepaid expenses and other	118	166
Assets held for sale, net	430	2,058
Total current assets	10,875	9,421
Oil and natural gas properties, successful efforts method
Proved properties	379,441	335,796
Unproved properties	2,928	369
Other property and equipment	427	427
Accumulated depletion, depreciation, amortization and impairment	(175,948)	(129,101)
Total property and equipment, net	206,848	207,491
Derivative financial instruments	2,418
Other assets	1,563	2,451
Total assets	221,704	219,363
Accounts payable
Trade	141	593
Related parties	3,732	1,631
Derivative financial instruments		4,252
Accrued liabilities	2,024	603
Liabilities related to assets held for sale		77
Total current liabilities	5,897	7,156
Derivative financial instruments		666
Long-term debt	93,000	99,000
Other long-term liabilities	47	70
Asset retirement obligations	26,001	10,249
Commitments and contingencies
General partner	(786)	(572)
Limited partners- 30,436,124 and 30,090,463 units issued and outstanding, respectively	61,195	82,260
Total equity	60,409	81,688
Total liabilities, convertible preferred units and equity	221,704	219,363
Class A Convertible Preferred Units [Member]
Accounts payable
Convertible preferred units	21,715	$ 20,534
Class B Convertible Preferred Units [Member]
Accounts payable
Convertible preferred units	$ 14,635

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2018	Dec. 31, 2017
Limited partners, units issued	30,436,124	30,090,463
Limited partners, units outstanding	30,436,124	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

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenues
Gain (loss) on derivatives, net	$ 5,674	$ (1,945)
Total revenues	72,788	56,984
Operating costs and expenses
Lease operating expenses	22,537	20,805
Production and ad valorem taxes	5,483	4,130
Other operating expenses	945
Impairment of proved oil and natural gas properties	31,160	24,746
Impairment of proved oil and natural gas properties held for sale		296
Depreciation, depletion and amortization	16,751	17,713
Dry holes and abandonments of unproved properties	612
Accretion of discount on asset retirement obligations	721	520
General and administrative	6,311	5,719
Total operating costs and expenses	84,520	73,929
Loss on sales of oil and natural gas properties, net	(509)	(3,950)
Loss from operations	(12,241)	(20,895)
Other (expense) income
Interest income	3	11
Interest expense	(6,010)	(6,472)
Other (expense) income	(15)	60
Gain (loss) on settlements of asset retirement obligations	10	(37)
Total other expense	(6,012)	(6,438)
Net loss	(18,253)	(27,333)
Less: Distributions to preferred unitholders	4,456	3,063
Less: General partner's interest in net loss	(214)	(324)
Limited partners' interest in net loss	$ (22,495)	$ (30,072)
Limited partners' interest in net loss per unit
Basic and diluted	$ (0.74)	$ (0.99)
Weighted average limited partner units outstanding
Limited partner units (basic and diluted)	30,328	30,002
Oil Sales [Member]
Revenues
Revenue	$ 65,206	$ 57,689
Natural Gas Sales [Member]
Revenues
Revenue	1,130	$ 1,240
Other Operating Revenues [Member]
Revenues
Revenue	$ 778

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Cash Flows from Operating Activities
Net loss	$ (18,253)	$ (27,333)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	16,751	17,713
Debt issuance costs amortization	678	1,384
Accretion of discount on asset retirement obligations	721	520
Impairment of proved oil and natural gas properties	31,160	24,746
Impairment of proved oil and natural gas properties held for sale		296
Dry holes and abandonments of unproved properties	612
(Gain) loss on settlements of asset retirement obligations	(10)	37
Cash paid for settlements of asset retirement obligations	(128)	(95)
(Gain) loss on derivatives, net	(5,674)	1,945
Cash settlements paid for matured derivatives	(6,928)	(369)
Cash settlements received from early termination of derivatives		582
Cash premiums paid for derivatives, net	(401)	(5,048)
Loss on sales of oil and natural gas properties	509	3,950
Non-cash equity-based compensation	744	434
Changes in operating assets and liabilities
Accounts receivable	1,571	40
Other receivables	(204)	150
Prepaids and other	(61)	(655)
Accounts payable - trade and accrued liabilities	(210)	427
Accounts payable - related parties	1,708	(1,478)
Net cash provided by operating activities	22,585	17,246
Cash Flows from Investing Activities
Acquisitions of oil and natural gas properties	(21,243)	(5,034)
Additions to oil and natural gas properties	(8,617)	(9,947)
Additions to other property and equipment		(137)
Proceeds from sales of oil and natural gas properties	1,044	22,115
Net cash (used in) provided by investing activities	(28,816)	6,997
Cash Flows from Financing Activities
Proceeds from line of credit	22,000	6,000
Payments on line of credit	(28,000)	(29,000)
Offering costs		(99)
Debt issuance costs	(681)	(171)
Net cash provided by (used in) financing activities	4,866	(24,770)
Net decrease in cash and cash equivalents	(1,365)	(527)
Beginning cash and cash equivalents	1,832	2,359
Ending cash and cash equivalents	467	1,832
Class B Convertible Preferred Units [Member]
Cash Flows from Financing Activities
Proceeds from sale of Class B convertible preferred units, net of offering costs	14,847
Distributions to convertible preferred units	(800)
Class A Convertible Preferred Units [Member]
Cash Flows from Financing Activities
Distributions to convertible preferred units	$ (2,500)	$ (1,500)

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) shares in Thousands, $ in Thousands	Total	Class A Convertible Preferred Units [Member]	Class B Convertible Preferred Units [Member]	General Partner [Member]	Limited Partner [Member]	Limited Partner [Member]Class A Convertible Preferred Units [Member]	Limited Partner [Member]Class B Convertible Preferred Units [Member]
Balance at Dec. 31, 2016	$ 111,650			$ (248)	$ 111,898
Balance, Units at Dec. 31, 2016					29,912
Increase (Decrease) in Partners' Capital [Roll Forward]
Equity-based compensation	434				$ 434
Equity-based compensation, Units					179
Distributions to convertible preferred units		$ (2,000)				$ (2,000)
Accretion of beneficial conversion feature of convertible preferred units		(1,063)				(1,063)
Net loss	(27,333)			(324)	$ (27,009)
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	744				$ 744
Equity-based compensation, Units					345
Distributions to convertible preferred units		(2,000)	$ (1,100)			(2,000)	$ (1,100)
Allocation of value to beneficial conversion feature of Class B convertible preferred units			686				686
Accretion of beneficial conversion feature of convertible preferred units		$ (1,181)	$ (175)			$ (1,181)	$ (175)
Net loss	(18,253)			(214)	$ (18,039)
Balance at Dec. 31, 2018	$ 60,409			$ (786)	$ 61,195
Balance, Units at Dec. 31, 2018					30,436

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
Organization and Nature of Operations	Dec. 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 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 EOR. Our limited partner units (“common units”) are listed under the symbol “MCEP” on the NASDAQ. Our general partner is Mid-Con Energy GP, a Delaware limited liability company.

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of Presentation and Summary of Significant Accounting Policies	Note 2. Basis of Presentation and Summary of Significant Accounting Policies Basis of presentation and principles of consolidation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2018 and 2017, and the results of operations, cash flows and changes in equity for the years then ended December 31, 2018 and 2017. Reclassifications The consolidated statements of operations for the prior year includes reclassifications from lease operating expenses to production and ad valorem taxes to conform to the current presentation. Such reclassifications have no impact on previously reported net loss. Use of estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, in part, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not Cash and cash equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents. Accounts receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2018 and 2017, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in any period presented. Revenue recognition We 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. We had no significant natural gas imbalances at December 31, 2018 and 2017. During the years ended December 31, 2018 and 2017, we did not extract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. Therefore, we do not report NGLs in our production or proved reserves. 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. Payment is typically received 30 to 60 days after the date production is delivered. 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. For our crude oil sales and natural gas sales contracts, the variable consideration related to variable production is not estimated because the uncertainty related to the consideration is resolved as the Bbl of oil and Mcf of natural gas are transferred to the customer each day. Therefore, 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. Contract Balances . Our product sales contracts do not give rise to contract assets or liabilities under ASC 606. Oil and natural gas properties Our oil and natural gas development and production activities are accounted for using the successful efforts method. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs of proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. Costs associated with unproved properties are excluded from depletion until proved reserves are established or impairment determined. When proven reserves are established any unproved property costs associated with the project are transferred to proved properties and included in depletion. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on the estimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. Costs of significant proved non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We 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. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted Derivatives and hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives (commodity price and differential 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 or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. We net the fair value of derivatives by counterparty where the right of offset exists and determine the fair value of our derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding Derivative Financial Instruments. Equity-based compensation The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. On January 1, 2017, we adopted ASU 2016-09 Compensation – Stock Compensation Improvements to Employee Share-Based Payment Accounting Debt issuance costs Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations over the remaining life of the agreement. Since our debt consists of a revolving credit facility, net debt placement costs are presented in “Other Assets” in our consolidated balance sheets. When debt is retired before its scheduled maturity date, any remaining issuance costs associated with that debt are expensed. Income taxes The Partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities. 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 to common units. Non-cash Investing and Supplemental Cash Flow Information The following presents the non-cash investing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2018 2017 Non-cash investing information Change in oil and natural gas properties - accrued capital expenditures $ 348 $ (310 ) Change in oil and natural gas properties - accrued acquisitions $ 1,506 $ — Supplemental cash flow information Cash paid for interest $ 5,052 $ 5,041 Recently Issued Accounting Standards Leases . In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASCs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The primary effect on the Partnership's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. As of December 31, 2018, we estimate that the adoption and implementation of ASC 842 will not result in a material increase in assets and liabilities on the consolidated balance sheet or to the consolidated statement of operations. The Partnership has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption and establish a balance sheet recognition capitalization threshold. We will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted, January 1, 2019. We will utilize the transition package of expedients to leases that commenced before the effective date. The Partnership expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component . Codification Improvements . In July 2018, the FASB issued ASU 2018-09, “Codification Improvements,” (“ASU 2018-09”) which makes amendments to multiple codification topics to clarify, correct errors in, or make minor improvements to the accounting standards codification. The effective date of the standard is dependent on the facts and circumstances of each amendment. Some amendments do not require transition guidance and will be effective upon the issuance of this standard. Many of the amendments in ASU 2018-09 will be effective in annual periods beginning after December 15, 2018. We will adopt this standard in the first quarter of 2019. We are still evaluating the impact of this standard. On August 17, 2018, the SEC issued a final rule that amends certain of its disclosure requirement that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends to interim periods the annual disclosure requirement in the SEC Regulation S-X, rule 3-04, of presenting changes in stockholders’ equity. The registrants will be required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. The final rule became effective for all filings submitted on or after November 5, 2018.

Acquisitions, Divestitures and

Acquisitions, Divestitures and Assets Held for Sale	12 Months Ended
Acquisitions, Divestitures and Assets Held for Sale	Dec. 31, 2018
Business Combinations [Abstract]
Acquisitions, Divestitures and Assets Held for Sale	Note 3. Acquisitions, Divestitures and Assets Held for Sale Acquisitions We adopted ASU 2017-01, “ Business Combinations Acquisitions – Asset Acquisitions During the year ended December 31, 2018, through multiple transactions, we acquired 122,180 net acres of additional leasehold and additional working interests in 352 producing wells (as of December 31, 2018), in Oklahoma and Wyoming, for aggregate purchase price of $15.4 million, net of post-closing adjustments. These acquisitions were accounted for as asset acquisitions. Acquisitions – Business Combinations The assets and liabilities assumed in the acquisitions of business combinations 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. Pine Tree In January 2018, we acquired multiple oil and gas properties located in Campbell and Converse Counties, Wyoming. The Pine Tree acquisition was accounted for as a business combination. We acquired Pine Tree for cash consideration of $8.4 million, after final 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 Proved oil and natural gas properties $ 8,833 Total assets acquired 8,833 Fair value of net liabilities assumed Asset retirement obligation 463 Net assets acquired $ 8,370 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: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ 1,116 $ — Expenses (1) $ 714 $ — (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 Wheatland acquisition was accounted for as a business combination. The recognized fair values of the assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Proved 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 acquired oil and natural gas properties included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ 2,774 $ 1,373 Expenses (1) $ 2,085 $ 1,009 (1) Divestitures Effective at closing, the operations and cash flows of the following divested properties were eliminated from our ongoing operations, and we have no continuing involvement in these properties. The divestitures did not represent a strategic shift and did not have a major effect on our 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, after final 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: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ — $ 564 Expenses (1) $ — $ 770 (1) Southern Oklahoma In December 2017, we sold the properties located in Southern Oklahoma for cash proceeds, net of expenses, of $21.5 million, after final post-closing purchase price adjustments, and we recognized a loss on the sale of $0.5 million and $4.2 million for the years ended December 31, 2018, and December 31, 2017, respectively. 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: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ (4 ) $ 9,252 Expenses (1) $ (17 ) $ 7,419 (1) Assets Held for Sale Land in Southern Oklahoma met held-for-sale criteria as of December 31, 2018, and December 31, 2017. The carrying value of $0.4 million was presented in “Assets held for sale, net” on our consolidated balance sheet. As of December 31, 2017, certain oil and natural gas properties in Nolan County, Texas, were deemed to meet held-for-sale criteria. The net asset value of the Nolan County divestiture of $1.6 million was presented in “Assets held for sale, net” and a net liability of $0.1 million was presented in “Liabilities related to assets held for sale” on our consolidated balance sheet.

Equity Awards

Equity Awards	12 Months Ended
Equity Awards	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Equity Awards	Note 4. 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 and 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. 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 December 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 (932,669 ) Awards available for future grant 881,369 We recognized $0.7 million and $0.4 million of total equity-based compensation expense for the years ended December 31, 2018 and 2017, respectively. These costs are reported as a component of G&A in our consolidated statements of operations. Unrestricted Unit Awards During the year ended December 31, 2018, we granted 87,832 unrestricted units with an average grant date fair value of $1.79 per unit. During the year ended December 31, 2017, we granted 25,400 unrestricted units with an average grant date fair value of $2.65 per unit. Restricted Unit Awards All restricted units were vested as of December 31, 2018. A summary of our restricted unit awards for the years ended December 31, 2018 and 2017, is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2016 76,922 5.67 Units granted — — Units vested (69,560 ) 6.39 Units forfeited (1,000 ) 5.42 Outstanding at December 31, 2017 6,362 5.42 Units granted — — Units vested (6,362 ) 5.42 Units forfeited — — Outstanding at December 31, 2018 — $ — Equity-Settled Phantom Unit Awards Equity-settled phantom units vest over a period of two or three years. During the year ended December 31, 2018, we granted 450,000 equity-settled phantom units with a two-year vesting period and 44,500 equity-settled phantom units with a three-year vesting period. During the year ended December 31, 2017, we granted 27,000 equity-settled phantom awards with a two-year vesting period and 14,500 equity-settled phantom awards with a three-year vesting period. As of December 31, 2018, there were $0.4 million of unrecognized compensation costs related to equity-settled phantom units. These costs are expected to be recognized over a weighted average period of seventeen months. A summary of our equity-settled phantom unit awards for the years ended December 31, 2018 and 2017, is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2016 287,659 1.64 Units granted 41,500 1.60 Units vested (153,833 ) 1.70 Units forfeited (57,831 ) 1.96 Outstanding at December 31, 2017 117,495 1.45 Units granted 494,500 1.74 Units vested (257,829 ) 1.63 Units forfeited (3,000 ) 1.31 Outstanding at December 31, 2018 351,166 $ 1.73

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
Derivative Financial Instruments	Dec. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Note 5. 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 (commodity price and differential 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 or as required by our lenders. We account for our commodity derivative contracts at fair value. See Note 6 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 December 31, 2018, our commodity derivative contracts were in a net asset position with a fair value of $8.1 million, whereas at December 31, 2017, our commodity derivative contracts were in a net liability position with a fair value of $4.9 million. 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. During the two years ended December 31, 2018 and 2017, all of our counterparties have performed pursuant to 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 consolidated balance sheets at December 31, 2018 and 2017: (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2018 Assets Derivative financial instruments - current asset $ 5,705 $ (39 ) $ 5,666 Derivative financial instruments - long-term asset 2,418 — 2,418 Total 8,123 (39 ) 8,084 Liabilities Derivative financial instruments - current liability (39 ) 39 — Total (39 ) 39 — Net Asset $ 8,084 $ — $ 8,084 (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet 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 consolidated statements of operations: Year Ended December 31, (in thousands) 2018 2017 Net settlements on matured derivatives (1) $ (6,928 ) $ (369 ) Net settlements on early terminations of derivatives (1) — 582 Net change in fair value of derivatives 12,602 (2,158 ) Total gain (loss) on derivatives, net $ 5,674 $ (1,945 ) (1) At December 31, 2018 and 2017, our commodity derivative contracts had maturities at various dates through September 2020 and were comprised of commodity price and differential swaps, put and collar contracts. At December 31, 2018, we had the following oil derivatives net positions: Period Covered Differential Fixed Price Weighted Average Fixed Price Total Bbls Hedged/day Index Swaps - 2019 $ — $ 56.14 1,779 NYMEX-WTI Swaps - 2019 $ (20.15 ) $ — 137 WCS-CRUDE-OIL Swaps - 2020 $ — $ 54.81 1,199 NYMEX-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 Index Swaps - 2018 $ 51.33 $ — $ — 444 NYMEX-WTI Puts - 2018 $ — $ 45.00 $ — 164 NYMEX-WTI Collars - 2018 $ — $ 44.38 $ 55.52 1,315 NYMEX-WTI Swaps - 2019 $ 51.48 $ — $ — 427 NYMEX-WTI

Fair Value Disclosures

Fair Value Disclosures	12 Months Ended
Fair Value Disclosures	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value Disclosures	Note 6. Fair Value Disclosures Fair Value of Financial Instruments The carrying amounts reported in our 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, 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 during the years ended December 31, 2018 and 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 changes in valuation approach or related inputs for the years ended December 31, 2018 and 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 5 in this section for a summary of our derivative financial instruments. The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2018 and 2017: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2018 Derivative financial instruments - asset $ — $ 8,123 $ — $ 8,123 Derivative financial instruments - liability $ — $ 39 $ — $ 39 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: Year Ended December 31, (in thousands) 2018 2017 Balance of Level 3 at beginning of period $ (401 ) $ (5,449 ) Derivative deferred premiums - settlements 401 5,048 Balance of Level 3 at end of period $ — $ (401 ) Assets and Liabilities Measured at Fair Value on a Non-Recurring Basis Asset Retirement Obligations We estimate the fair value of our ARO based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 7 in this section for a summary of changes in ARO. 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 at the acquisition date. 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 3 in this section for further discussion of our 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 are the product of a process that begins with Level 1 NYMEX-WTI forward curve pricing, less Level 3 assumptions that include location, pricing adjustments and quality differentials. See Note 16 in this section for additional information regarding our oil and natural gas reserves. 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 years ended December 31, 2018 and 2017, we recorded non-cash impairment of $31.2 million and $24.7 million, respectively. When oil and natural gas properties are deemed to meet held-for-sale accounting criteria, non-cash impairment expense is recorded to reduce the carrying amount of those assets to their fair value. For the year ended December 31, 2017, we recorded non-cash impairment of $0.3 million related to certain oil and natural gas properties located in Nolan County, Texas, deemed to meet held-for-sale accounting criteria as of December 31, 2017. See Note 3 in this section for additional information regarding the divestiture.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
Asset Retirement Obligations	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 7. 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 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. 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. For the years ended December 31, 2018 and 2017, our ARO were reported as “Asset retirement obligations” in our consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table: Year Ended December 31, (in thousands) 2018 2017 Asset retirement obligations - beginning of period $ 10,326 $ 11,331 Liabilities incurred for new wells and interest 15,497 759 Liabilities settled upon plugging and abandoning wells (138 ) (57 ) Liabilities removed upon sale of wells (399 ) (2,152 ) Revision of estimates (6 ) (75 ) Accretion expense 721 520 Asset retirement obligations - end of period $ 26,001 $ 10,326

Debt

Debt	12 Months Ended
Debt	Dec. 31, 2018
Debt Disclosure [Abstract]
Debt	Note 8. Debt At December 31, 2018 and 2017, we had outstanding borrowings under our revolving credit facility of $93.0 million and $99.0 million, respectively. Borrowings under the facility are secured by liens on not less than 90% of the value of our proved reserves. 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. The next regularly scheduled semi-annual redetermination is expected to occur before or during the second quarter of 2019. 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 year ended December 31, 2018, the average effective rate was 5.39%. Any unused portion of the borrowing base will be subject to a commitment fee of 0.50% per annum. Letters of credit are subject to a letter of credit fee that varies from 2.75% to 3.75% according to 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, and requires us to maintain hedges covering projected production. 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 our 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 3 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 our revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of our failure to maintain the required leverage ratios for the quarter ended September 30, 2017. The amendment also required us to have a minimum liquidity of 20% to make cash distributions to the Preferred Unitholders. During the fall 2018 semi-annual borrowing base redetermination of our revolving credit facility completed in December 2018, the lender group increased our borrowing base to $135.0 million effective December 19, 2018. There were no changes to the terms or conditions of the credit agreement. As of December 31, 2018, we were in compliance with our financial covenants.

Commitment and Contingencies

Commitment and Contingencies	12 Months Ended
Commitment and Contingencies	Dec. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Commitment and Contingencies	Note 9. Commitment and Contingencies Leases We lease corporate office space in Tulsa, Oklahoma, Abilene, Texas, and Gillette, Wyoming. For the years ended December 31, 2018 and 2017, total lease expenses were $0.3 million. These expenses are included in general and administrative expenses in our consolidated statements of operations. Future minimum lease payments under the non-cancellable operating leases are presented in the following table: (in thousands) 2019 $ 484 2020 469 2021 471 Total $ 1,424 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 11 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 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 agreements stipulate 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 Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any material legal proceedings. In addition, we are not aware of any significant legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject.

Equity

Equity	12 Months Ended
Equity	Dec. 31, 2018
Equity [Abstract]
Equity	Note 10. Equity Common Units At December 31, 2018 and 2017, the Partnership’s equity consisted of 30,436,124 and 30,090,463 common units, respectively, representing 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 purchase agreement for the Class A Preferred Units described below, we suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until August 11, 2021, 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 December 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. Proceeds from this issuance were used to fund an acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $24.6 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 $1.2 million and $1.1 million for the years ended December 31, 2018 and 2017, respectively. 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. At December 31, 2018, the Partnership had accrued $0.5 million for the fourth quarter 2018 distributions that will be paid in cash in February 2019. The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2018 July 1, 2017 - December 31, 2017 $ 0.0860 $ 1,000 May 15, 2018 January 1, 2018 - March 31, 2018 $ 0.0430 $ 500 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0430 $ 500 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0430 $ 500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2017: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2017 October 1, 2016 - December 31, 2016 $ 0.0430 $ 500 May 15, 2017 January 1, 2017 - March 31, 2017 $ 0.0430 $ 500 August 14, 2017 April 1, 2017 - June 30, 2017 $ 0.0430 $ 500 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. 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 $0.2 million for the twelve months ended December 31, 2018. The registration statement registering resales of common units issued or to be issued upon conversion of the Class B Preferred Units was declared effective by the SEC on May 25, 2018. At December 31, 2018, the Partnership had accrued $0.3 million for the fourth quarter 2018 distribution that will be paid in cash in February 2019. The following table summarizes cash distributions paid on our Class B Preferred Units during the twelve months ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) May 15, 2018 February 1, 2018 - March 31, 2018 $ 0.0204 $ 200 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0306 $ 300 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0306 $ 300 Allocations 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	12 Months Ended
Related Party Transactions	Dec. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Note 11. 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 managerial, 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 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 LOE in our 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. These amounts are either included in LOE in our consolidated statements of operations or are capitalized as part of oil and natural gas properties in our consolidated balance sheets. Other Agreements We are party to monitoring fee agreements with Bonanza Fund Management, Inc. (“Bonanza”), a Class A Preferred Unitholder, and Goff Focused Strategies, LLC (“GFS”), a Class B Preferred Unitholder, pursuant to which we pay Bonanza and GFS a quarterly monitoring fee in connection with monitoring the purchasers’ investments in the Preferred Units. These expenses were included in G&A in our consolidated statements of operations. The following table summarizes the related party transactions for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Services agreement $ 2,685 $ 2,443 Operating agreements 8,849 6,509 Oilfield services 3,941 3,377 Other Agreements 310 200 Total $ 15,785 $ 12,529 At December 31, 2018, we had a net payable to our affiliate, Mid-Con Energy Operating, of $3.7 million, comprised of a joint interest billing payable of $3.7 million and a payable for operating services and other miscellaneous items of $1.2 million, offset by an oil and natural gas revenue receivable of $1.2 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 consolidated balance sheets.

Credit Risk

Credit Risk	12 Months Ended
Credit Risk	Dec. 31, 2018
Risks And Uncertainties [Abstract]
Credit Risk	Note 12. Credit Risk Credit risk relates to the risk of loss resulting from non-performance of non-payment by counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. For the year ended December 31, 2018, sales of oil and natural gas to three purchasers accounted for 83% of our sales. At December 31, 2018, these purchasers accounted for 89% of our outstanding oil and natural gas accounts receivable. For the year ended December 31, 2017, sales of oil and natural gas to four purchasers accounted for 99% of our sales. At December 31, 2017, these purchasers accounted for 98% of our outstanding oil and natural gas accounts receivable. We believe that the loss of any one purchaser would not have a material adverse effect on our ability to sell our oil and natural gas production as other purchasers would be accessible. We have not experienced any significant losses due to uncollectible accounts receivable from these purchasers.

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
Employee Benefit Plans	Dec. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Employee Benefit Plans	Note 13. Employee Benefit Plans In 2011, our general partner adopted the Long-Term Incentive Program which is intended to promote the interests of the Partnership by providing to employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating and ME3 Oilfield Service, grants of restricted units, phantom units, unit appreciation rights, distribution equivalent rights and other unit based awards to encourage superior performance. The Long-Term Incentive Program is also intended to enhance the ability of the general partner and our affiliates, to attract and retain the services of individuals who are essential for the growth and profitability of the Partnership and to encourage them to devote their best efforts to advancing the business of the Partnership. The Long-Term Incentive Program is administered by Charles R. Olmstead and Jeffrey R. Olmstead, the voting members of our general partner, and awards are approved by the Board. Except as set forth in the employment agreements of the executive officers of our general partner, there is no set formula for granting awards to our employees, officers, consultants and directors of our general partner and our affiliates. In determining whether to grant awards and the amount of any awards, the administrators take into consideration the performance of the Partnership along with discretionary factors such as the individual’s current and expected future performance, level of responsibility, retention considerations and the total compensation package. See Note 4 in this section for additional information regarding awards granted under the Long-Term Incentive Program.

Income Taxes

Income Taxes	12 Months Ended
Income Taxes	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Note 14. Income Taxes We do not pay federal income taxes, as our profits or losses are reported to the taxing authorities by our individual partners.

Subsequent Events

Subsequent Events	12 Months Ended
Subsequent Events	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 15. Subsequent Events Equity Awards On January 21, 2019, the Board authorized the issuance of 50,000 unrestricted common units and 573,000 equity-settled phantom units. Distributions A cash distribution of $0.0430 per Class A Preferred Unit, or $0.5 million in aggregate, and a cash distribution of $0.0306 per Class B Preferred Unit, or $0.3 million in aggregate, was paid on February 14, 2019, to holders of record as of the close of business on February 7, 2019. Strategic Transaction In February 2019, we entered into definitive agreements to sell substantially all of our Texas assets for $60.0 million, subject to customary purchase price adjustments, and to acquire producing properties in Caddo, Grady and Osage Counties, Oklahoma for $27.5 million, subject to customary purchase price adjustments. These agreements are conditioned to close simultaneously on, or about, March 28, 2019, with an effective date the same as the closing date. Net cash proceeds from this transaction will be used to reduce outstanding borrowings on our revolving credit facility. Commodity Derivative Contracts On February 28, 2019, we entered into new oil derivative contracts covering a total 758,300 barrels of future production which extend from January 2020 through December 2021.

Supplementary Information

Supplementary Information	12 Months Ended
Supplementary Information	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Supplementary Information	Note 16. Supplementary Information Supplementary Oil and Natural Gas Activities Costs incurred in oil and natural gas property acquisitions and development activities are presented below for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Property acquisition costs: Proved $ 20,158 $ 4,665 Unproved 1,085 369 Exploration — — Development 8,617 9,947 Asset retirement obligations 15,491 684 Total costs incurred $ 45,351 $ 15,665 Estimated Proved Oil and Natural Gas Reserves (Unaudited) The Partnership’s proved oil and natural gas reserves are all located in the United States. The proved oil and natural gas reserves for the years ended December 31, 2018 and 2017, were prepared by our reservoir engineers and audited by CG&A, independent third party petroleum consultants. These reserve estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated: Oil (MBbls) Natural Gas (MMcf) MBoe Proved developed and undeveloped reserves: As of December 31, 2016 18,210 6,124 19,231 Revisions of previous estimates (1) 2,355 168 2,383 Extensions, discoveries and other additions (2) 69 — 69 Purchases of reserves in place (3) 1,607 459 1,684 Sales of reserves in place (4) (2,522 ) (38 ) (2,529 ) Production (1,209 ) (431 ) (1,281 ) As of December 31, 2017 18,510 6,282 19,557 Revisions of previous estimates (1) 1,484 (1,045 ) 1,310 Extensions, discoveries and other additions (5) 72 — 72 Purchases of reserves in place (6) 4,968 1,713 5,253 Sales of reserves in place (7) (133 ) (172 ) (162 ) Production (1,112 ) (457 ) (1,188 ) As of December 31, 2018 23,789 6,321 24,842 Proved developed reserves: December 31, 2017 13,512 4,586 14,276 December 31, 2018 17,634 6,059 18,643 Proved undeveloped reserves: December 31, 2017 4,998 1,696 5,281 December 31, 2018 6,155 262 6,199 (1) ( 2 ) (3 ) (4 ) ( 5 ) (6) (7) The increase in quantities of proved reserves from December 31, 2016, to December 31, 2017, was due in part to commodity price increases of 1,309 MBoe which extended the economic lives of certain producing properties, offset in part by downward revisions from certain recent results and development plans. Increased oil production was seen as a response to water injection in our Oklahoma and Texas core areas resulting in upward revisions to our proved reserves of 1,074 MBoe. Positive outcomes from step out drilling locations in the Texas core area resulted in an extension within our Hardrock Field and generated an increase in proved reserves of 69 MBoe. During 2017, the acquisition of the Wheatland properties resulted in a positive revision of 1,684 MBoe, and the divestiture of our Southern Oklahoma properties resulted in a decrease in proved reserves of 2,529 MBoe. The increase in quantities of proved reserves from December 31, 2017, to December 31, 2018, was due in part to commodity price increases of 1,975 MBoe which extended the economic lives of certain producing properties, offset in part by net downward revisions of 1,169 MBoe from certain recent results and development modifications. Increased oil production was seen as a response to water injection in our Oklahoma and Texas core areas, resulting in upward revisions to our proved reserves of 504 MBoe. Positive outcomes from step out drilling locations in the Texas core area resulted in an extension within our Hardrock Field and generated an increase in proved reserves of 72 MBoe. During 2018, the acquisition of the Oklahoma and Wyoming waterflood properties resulted in a positive revision of 5,253 MBoe, and the divestiture of several small properties in the Texas core area resulted in a decrease in proved reserves of 162 MBoe. Estimates of economically recoverable oil and natural gas reserves and of future net revenues are based upon a number of variable factors and assumptions, all of which are to some degree subjective and may vary considerably from actual results. Therefore, actual production, revenues, development and operating expenditures may not occur as estimated. The reserve data are estimates only, are subject to many uncertainties and are based on data gained from production histories and on assumptions as to geologic formations and other matters. Actual quantities of oil and natural gas may differ materially from the amounts estimated. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (Unaudited) The standardized measure represents the present value of estimated future cash inflows from proved oil and natural gas reserves, less future development, production, plugging and abandonment costs, discounted at the rate prescribed by the SEC. The standardized measure of discounted future net cash flow does not purport to be, nor should it be interpreted to represent, the fair market value of our proved oil and natural gas reserves. The following assumptions have been made: • in the determination of future cash inflows, sales prices used for oil and natural gas for the years ended December 31, 2018 and 2017, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month in such period; • future costs of developing and producing the proved oil and natural gas reserves were based on costs determined at each such period-end, assuming the continuation of existing economic conditions, including abandonment costs; • no future income tax expenses are computed for the Partnership, because we are a non-taxable entity; and • future net cash flows were discounted at an annual rate of 10%. The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Future cash inflows $ 1,494,349 $ 927,473 Future production costs (694,862 ) (444,673 ) Future development costs, including abandonment costs (92,973 ) (50,868 ) Future net cash flow 706,514 431,932 10% discount for estimated timing of cash flow (358,261 ) (224,719 ) Standardized measure of discounted cash flow $ 348,253 $ 207,213 The prices utilized in calculating our total proved reserves were $65.56 and $51.34 per Bbl of oil and $3.10 and $2.98 per MMBtu of natural gas for December 31, 2018 and 2017, respectively. These prices were adjusted by lease for quality, transportation fees, location differentials, marketing bonuses or deductions or other factors affecting the price received at the wellhead. Average adjusted prices used were $62.17 and $49.34 per Bbl of oil and $2.43 and $2.27 per Mcf of natural gas for December 31, 2018 and 2017, respectively. Adjusted natural gas price includes the sale of associated NGLs. During the years ended December 31, 2018 and 2017, we did not extract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. Therefore, we do not report NGLs in our production or proved reserves. All wellhead prices are held flat over the life of the properties for all reserve categories. Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Standardized measure of discounted future net cash flow, beginning of year $ 207,213 $ 157,285 Changes in the year resulting from: Sales, less production costs (38,316 ) (33,994 ) Revisions of previous quantity estimates 24,035 28,132 Extensions, discoveries and improved recovery 2,398 3,168 Net change in prices and production costs 102,480 61,504 Net change in income taxes — — Changes in estimated future development costs 4,534 5,173 Previously estimated development costs incurred during the year 8,428 9,726 Purchases of reserves in place 50,242 13,826 Sales of reserves in place (2,714 ) (10,420 ) Accretion of discount 20,721 15,729 Timing differences and other (30,768 ) (42,916 ) Standardized measure of discounted future net cash flow, end of year $ 348,253 $ 207,213

Basis of Presentation and Sum_2

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Basis of presentation and principles of consolidation	Basis of presentation and principles of consolidation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2018 and 2017, and the results of operations, cash flows and changes in equity for the years then ended December 31, 2018 and 2017.
Reclassifications	Reclassifications The consolidated statements of operations for the prior year includes reclassifications from lease operating expenses to production and ad valorem taxes to conform to the current presentation. Such reclassifications have no impact on previously reported net loss.
Use of estimates	Use of estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, in part, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not
Cash and cash equivalents	Cash and cash equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.
Accounts receivable	Accounts receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2018 and 2017, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in any period presented.
Revenue recognition	Revenue recognition We 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. We had no significant natural gas imbalances at December 31, 2018 and 2017. During the years ended December 31, 2018 and 2017, we did not extract NGLs from our natural gas production prior to the sale and transfer of title of the natural gas stream to our purchasers. While some of our purchasers extracted NGLs from the natural gas stream sold by us to them, we had no ownership in such NGLs. Therefore, we do not report NGLs in our production or proved reserves. 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. Payment is typically received 30 to 60 days after the date production is delivered. 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. For our crude oil sales and natural gas sales contracts, the variable consideration related to variable production is not estimated because the uncertainty related to the consideration is resolved as the Bbl of oil and Mcf of natural gas are transferred to the customer each day. Therefore, 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. Contract Balances . Our product sales contracts do not give rise to contract assets or liabilities under ASC 606.
Oil and natural gas properties	Oil and natural gas properties Our oil and natural gas development and production activities are accounted for using the successful efforts method. Under this method all costs associated with productive wells and nonproductive development wells are capitalized, while nonproductive exploration costs are expensed. Capitalized costs of proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. Costs associated with unproved properties are excluded from depletion until proved reserves are established or impairment determined. When proven reserves are established any unproved property costs associated with the project are transferred to proved properties and included in depletion. Unproved properties are assessed at least annually to ascertain whether impairment has occurred. In addition, impairment assessments are made for interim reporting periods if facts and circumstances exist that suggest impairment may have occurred. The impairment test for unproved properties is not based on the estimated fair value of the unproved properties. The impairment assessment includes consideration of our intent to fully develop our unproved properties, remaining lease terms, geological and geophysical evaluations, our drilling results, potential drilling locations, availability of capital, assignment of proved reserves, expected divestitures, anticipated future capital expenditures and economic considerations, among others. Costs of significant proved non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We 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. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted
Derivatives and hedging	Derivatives and hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives (commodity price and differential 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 or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. We net the fair value of derivatives by counterparty where the right of offset exists and determine the fair value of our derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding Derivative Financial Instruments.
Equity-based compensation	Equity-based compensation The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. On January 1, 2017, we adopted ASU 2016-09 Compensation – Stock Compensation Improvements to Employee Share-Based Payment Accounting
Debt placement fee	Debt issuance costs Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations over the remaining life of the agreement. Since our debt consists of a revolving credit facility, net debt placement costs are presented in “Other Assets” in our consolidated balance sheets. When debt is retired before its scheduled maturity date, any remaining issuance costs associated with that debt are expensed.
Income taxes	Income taxes The Partnership is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Allocation of Net Income or Loss	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 to common units.
Recently Issued Accounting Standards	Recently Issued Accounting Standards Leases . In February 2016, the FASB issued new guidance in ASC 842, Leases ("ASC 842"), which will supersede the current guidance in ASC 840, Leases ("ASC 840"). The core principle of the new guidance is that a lessee should recognize in the statement of financial position a liability to make lease payments and a right-of-use asset representing its right to use the underlying asset for the lease term for leases currently classified as operating leases. For leases with a term of 12 months or less, a lessee is permitted to make an accounting policy election, by class of underlying asset, not to recognize lease assets and lease liabilities. In January 2018, the FASB issued new guidance in ASC 842 to provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under ASC 840. In July 2018, the FASB issued new guidance in ASC 842 to provide entities with an additional (and optional) transition method to adopt the new leases standard. Under this new transition method, an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. Consequently, an entity's reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with ASC 840. An entity that elects this transition method must provide the required ASC 840 disclosures for all periods that continue to be reported in accordance with ASC 840. The amendments in these ASCs are effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The primary effect on the Partnership's consolidated financial statements will be to record assets and obligations for contracts currently recognized as operating leases with a term greater than 12 months and to evaluate operating leases with a term less than or equal to 12 months for accounting policy election. As of December 31, 2018, we estimate that the adoption and implementation of ASC 842 will not result in a material increase in assets and liabilities on the consolidated balance sheet or to the consolidated statement of operations. The Partnership has made certain accounting policy decisions including that it plans to adopt the short-term lease recognition exemption and establish a balance sheet recognition capitalization threshold. We will utilize the modified retrospective approach to adopting the new standard that will be applied at the beginning of the period adopted, January 1, 2019. We will utilize the transition package of expedients to leases that commenced before the effective date. The Partnership expects for certain lessee asset classes to elect the practical expedient and not separate lease and non-lease components. For these asset classes, the agreements will be accounted for as a single lease component . Codification Improvements . In July 2018, the FASB issued ASU 2018-09, “Codification Improvements,” (“ASU 2018-09”) which makes amendments to multiple codification topics to clarify, correct errors in, or make minor improvements to the accounting standards codification. The effective date of the standard is dependent on the facts and circumstances of each amendment. Some amendments do not require transition guidance and will be effective upon the issuance of this standard. Many of the amendments in ASU 2018-09 will be effective in annual periods beginning after December 15, 2018. We will adopt this standard in the first quarter of 2019. We are still evaluating the impact of this standard. On August 17, 2018, the SEC issued a final rule that amends certain of its disclosure requirement that have become redundant, duplicative, overlapping, outdated or superseded, in light of other disclosure requirements, U.S. GAAP or changes in the information environment. The amendments are intended to facilitate the disclosure of information to investors and simplify compliance without significantly altering the total mix of information provided to investors. The final rule amends numerous SEC rules, items and forms covering a diverse group of topics, including, but not limited to, changes in stockholders’ equity. The final rule extends to interim periods the annual disclosure requirement in the SEC Regulation S-X, rule 3-04, of presenting changes in stockholders’ equity. The registrants will be required to analyze changes in stockholders’ equity in the form of a reconciliation for the current quarter and year-to-date interim periods and comparative periods in the prior year. The final rule became effective for all filings submitted on or after November 5, 2018.

Basis of Presentation and Sum_3

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Schedule of Non-cash Investing and Cash Flow Supplemental Disclosures	The following presents the non-cash investing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2018 2017 Non-cash investing information Change in oil and natural gas properties - accrued capital expenditures $ 348 $ (310 ) Change in oil and natural gas properties - accrued acquisitions $ 1,506 $ — Supplemental cash flow information Cash paid for interest $ 5,052 $ 5,041

Acquisitions, Divestitures an_2

Acquisitions, Divestitures and Assets Held for Sale, Acquisitions (Tables)	12 Months Ended
	Dec. 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 Proved oil and natural gas properties $ 8,833 Total assets acquired 8,833 Fair value of net liabilities assumed Asset retirement obligation 463 Net assets acquired $ 8,370
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: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ 1,116 $ — Expenses (1) $ 714 $ — (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 Proved 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 acquired oil and natural gas properties included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ 2,774 $ 1,373 Expenses (1) $ 2,085 $ 1,009 (1)

Acquisitions, Divestitures an_3

Acquisitions, Divestitures and Assets Held for Sale, Divestitures (Tables)	12 Months Ended
	Dec. 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: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ — $ 564 Expenses (1) $ — $ 770 (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: Year Ended December 31, (in thousands) 2018 2017 Oil and natural gas sales $ (4 ) $ 9,252 Expenses (1) $ (17 ) $ 7,419 (1)

Equity Awards (Tables)

Equity Awards (Tables)	12 Months Ended
Equity Awards (Tables)	Dec. 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 December 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 (932,669 ) Awards available for future grant 881,369
Summary of restricted units awarded	All restricted units were vested as of December 31, 2018. A summary of our restricted unit awards for the years ended December 31, 2018 and 2017, is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2016 76,922 5.67 Units granted — — Units vested (69,560 ) 6.39 Units forfeited (1,000 ) 5.42 Outstanding at December 31, 2017 6,362 5.42 Units granted — — Units vested (6,362 ) 5.42 Units forfeited — — Outstanding at December 31, 2018 — $ —
Summary of equity-settled units	A summary of our equity-settled phantom unit awards for the years ended December 31, 2018 and 2017, is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2016 287,659 1.64 Units granted 41,500 1.60 Units vested (153,833 ) 1.70 Units forfeited (57,831 ) 1.96 Outstanding at December 31, 2017 117,495 1.45 Units granted 494,500 1.74 Units vested (257,829 ) 1.63 Units forfeited (3,000 ) 1.31 Outstanding at December 31, 2018 351,166 $ 1.73

Derivative Financial Instrume_2

Derivative Financial Instruments (Tables)	12 Months Ended
Derivative Financial Instruments (Tables)	Dec. 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 consolidated balance sheets at December 31, 2018 and 2017: (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2018 Assets Derivative financial instruments - current asset $ 5,705 $ (39 ) $ 5,666 Derivative financial instruments - long-term asset 2,418 — 2,418 Total 8,123 (39 ) 8,084 Liabilities Derivative financial instruments - current liability (39 ) 39 — Total (39 ) 39 — Net Asset $ 8,084 $ — $ 8,084 (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet 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 consolidated statements of operations: Year Ended December 31, (in thousands) 2018 2017 Net settlements on matured derivatives (1) $ (6,928 ) $ (369 ) Net settlements on early terminations of derivatives (1) — 582 Net change in fair value of derivatives 12,602 (2,158 ) Total gain (loss) on derivatives, net $ 5,674 $ (1,945 ) (1)
Commodity Contracts	At December 31, 2018 and 2017, our commodity derivative contracts had maturities at various dates through September 2020 and were comprised of commodity price and differential swaps, put and collar contracts. At December 31, 2018, we had the following oil derivatives net positions: Period Covered Differential Fixed Price Weighted Average Fixed Price Total Bbls Hedged/day Index Swaps - 2019 $ — $ 56.14 1,779 NYMEX-WTI Swaps - 2019 $ (20.15 ) $ — 137 WCS-CRUDE-OIL Swaps - 2020 $ — $ 54.81 1,199 NYMEX-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 Index Swaps - 2018 $ 51.33 $ — $ — 444 NYMEX-WTI Puts - 2018 $ — $ 45.00 $ — 164 NYMEX-WTI Collars - 2018 $ — $ 44.38 $ 55.52 1,315 NYMEX-WTI Swaps - 2019 $ 51.48 $ — $ — 427 NYMEX-WTI

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	12 Months Ended
Fair Value Disclosures (Tables)	Dec. 31, 2018
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 on a recurring basis as of December 31, 2018 and 2017: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2018 Derivative financial instruments - asset $ — $ 8,123 $ — $ 8,123 Derivative financial instruments - liability $ — $ 39 $ — $ 39 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: Year Ended December 31, (in thousands) 2018 2017 Balance of Level 3 at beginning of period $ (401 ) $ (5,449 ) Derivative deferred premiums - settlements 401 5,048 Balance of Level 3 at end of period $ — $ (401 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
Asset Retirement Obligations (Tables)	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	For the years ended December 31, 2018 and 2017, our ARO were reported as “Asset retirement obligations” in our consolidated balance sheets. Changes in our ARO for the periods indicated are presented in the following table: Year Ended December 31, (in thousands) 2018 2017 Asset retirement obligations - beginning of period $ 10,326 $ 11,331 Liabilities incurred for new wells and interest 15,497 759 Liabilities settled upon plugging and abandoning wells (138 ) (57 ) Liabilities removed upon sale of wells (399 ) (2,152 ) Revision of estimates (6 ) (75 ) Accretion expense 721 520 Asset retirement obligations - end of period $ 26,001 $ 10,326

Commitments and Contingencies (

Commitments and Contingencies (Tables)	12 Months Ended
Commitments and Contingencies (Tables)	Dec. 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) 2019 $ 484 2020 469 2021 471 Total $ 1,424

Equity (Tables)

Equity (Tables)	12 Months Ended
Equity (Tables)	Dec. 31, 2018
Class A Preferred Units [Member]
Cash Distributions - Preferred Unitholders	The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2018 July 1, 2017 - December 31, 2017 $ 0.0860 $ 1,000 May 15, 2018 January 1, 2018 - March 31, 2018 $ 0.0430 $ 500 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0430 $ 500 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0430 $ 500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2017: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) February 14, 2017 October 1, 2016 - December 31, 2016 $ 0.0430 $ 500 May 15, 2017 January 1, 2017 - March 31, 2017 $ 0.0430 $ 500 August 14, 2017 April 1, 2017 - June 30, 2017 $ 0.0430 $ 500
Class B Preferred Units [Member]
Cash Distributions - Preferred Unitholders	The following table summarizes cash distributions paid on our Class B Preferred Units during the twelve months ended December 31, 2018: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) May 15, 2018 February 1, 2018 - March 31, 2018 $ 0.0204 $ 200 August 22, 2018 April 1, 2018 - June 30, 2018 $ 0.0306 $ 300 November 14, 2018 July 1, 2018 - September 30, 2018 $ 0.0306 $ 300

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
Related Party Transactions (Tables)	Dec. 31, 2018
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes the related party transactions for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Services agreement $ 2,685 $ 2,443 Operating agreements 8,849 6,509 Oilfield services 3,941 3,377 Other Agreements 310 200 Total $ 15,785 $ 12,529

Supplementary Information (Tabl

Supplementary Information (Tables)	12 Months Ended
Supplementary Information (Tables)	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Supplementary Oil and Natural Gas Activities	Costs incurred in oil and natural gas property acquisitions and development activities are presented below for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Property acquisition costs: Proved $ 20,158 $ 4,665 Unproved 1,085 369 Exploration — — Development 8,617 9,947 Asset retirement obligations 15,491 684 Total costs incurred $ 45,351 $ 15,665
Changes in Estimated Proved Oil and Natural Gas Reserves	An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated: Oil (MBbls) Natural Gas (MMcf) MBoe Proved developed and undeveloped reserves: As of December 31, 2016 18,210 6,124 19,231 Revisions of previous estimates (1) 2,355 168 2,383 Extensions, discoveries and other additions (2) 69 — 69 Purchases of reserves in place (3) 1,607 459 1,684 Sales of reserves in place (4) (2,522 ) (38 ) (2,529 ) Production (1,209 ) (431 ) (1,281 ) As of December 31, 2017 18,510 6,282 19,557 Revisions of previous estimates (1) 1,484 (1,045 ) 1,310 Extensions, discoveries and other additions (5) 72 — 72 Purchases of reserves in place (6) 4,968 1,713 5,253 Sales of reserves in place (7) (133 ) (172 ) (162 ) Production (1,112 ) (457 ) (1,188 ) As of December 31, 2018 23,789 6,321 24,842 Proved developed reserves: December 31, 2017 13,512 4,586 14,276 December 31, 2018 17,634 6,059 18,643 Proved undeveloped reserves: December 31, 2017 4,998 1,696 5,281 December 31, 2018 6,155 262 6,199 (1) ( 2 ) (3 ) (4 ) ( 5 ) (6) (7)
Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves	The standardized measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Future cash inflows $ 1,494,349 $ 927,473 Future production costs (694,862 ) (444,673 ) Future development costs, including abandonment costs (92,973 ) (50,868 ) Future net cash flow 706,514 431,932 10% discount for estimated timing of cash flow (358,261 ) (224,719 ) Standardized measure of discounted cash flow $ 348,253 $ 207,213
Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves	Changes in the standardized measure of discounted future net cash flow relating to proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, (in thousands) 2018 2017 Standardized measure of discounted future net cash flow, beginning of year $ 207,213 $ 157,285 Changes in the year resulting from: Sales, less production costs (38,316 ) (33,994 ) Revisions of previous quantity estimates 24,035 28,132 Extensions, discoveries and improved recovery 2,398 3,168 Net change in prices and production costs 102,480 61,504 Net change in income taxes — — Changes in estimated future development costs 4,534 5,173 Previously estimated development costs incurred during the year 8,428 9,726 Purchases of reserves in place 50,242 13,826 Sales of reserves in place (2,714 ) (10,420 ) Accretion of discount 20,721 15,729 Timing differences and other (30,768 ) (42,916 ) Standardized measure of discounted future net cash flow, end of year $ 348,253 $ 207,213

Basis of Presentation and Sum_4

Basis of Presentation and Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018USD ($)Segment	Dec. 31, 2017USD ($)Segment
Summary Of Significant Accounting Policies [Line Items]
Number of operating segment \| Segment	1	1
Reserves for doubtful accounts	$ 0	$ 0
Bad debts expenses	0	0
Significant natural gas imbalances	$ 0	0
Revenue, performance obligation, description of timing	one year or less
Revenue, remaining performance obligation, expected timing of satisfaction	one year or less
Revenue, practical expedient, initial application and transition, nondisclosure of transaction price allocation to remaining performance obligation	true
Interest capitalized during period	$ 0	$ 0
Minimum [Member]
Summary Of Significant Accounting Policies [Line Items]
Payments collection period after date of production delivered	30 days
Maximum [Member]
Summary Of Significant Accounting Policies [Line Items]
Payments collection period after date of production delivered	60 days

Basis of Presentation and Sum_5

Basis of Presentation and Summary of Significant Accounting Policies - Non-cash Investing and Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Non-cash investing information
Change in oil and natural gas properties - accrued capital expenditures	$ 348	$ (310)
Change in oil and natural gas properties - accrued acquisitions	1,506	0
Supplemental cash flow information
Cash paid for interest	$ 5,052	$ 5,041

Acquisitions, Divestitures an_4

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions - Additional Information (Details) $ in Millions	1 Months Ended		12 Months Ended
	Jan. 31, 2018USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2018USD ($)awell
Pine Tree [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net	$ 8.4
Wheatland [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net		$ 4
Oklahoma and Wyoming [Member]
Business Acquisition [Line Items]
Number of acres acquired of additional leasehold \| a			122,180
Number of producing wells acquired \| well			352
Aggregate purchase price			$ 15.4

Acquisitions, Divestitures an_5

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]
Proved oil and natural gas properties	$ 8,833
Total assets acquired	8,833
Asset retirement obligation	463
Net assets acquired	$ 8,370
Wheatland [Member]
Business Acquisition [Line Items]
Proved 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 an_6

Acquisitions, Divestitures and Assets Held for Sale - Summary of Revenues and Expenses of Properties Acquired (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired		$ 72,788	$ 56,984
Expenses of oil and natural gas properties acquired		84,520	73,929
Pine Tree [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired		1,116
Expenses of oil and natural gas properties acquired	[1]	714
Wheatland [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired		2,774	1,373
Expenses of oil and natural gas properties acquired	[2]	$ 2,085	$ 1,009

[1]	Expenses include LOE, production and ad valorem taxes, accretion and depletion.
[2]	Expenses include LOE, production and ad valorem taxes, accretion and depletion.

Acquisitions, Divestitures an_7

Acquisitions, Divestitures and Assets Held for Sale - Divestitures - Additional Information (Details) - USD ($)	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Jan. 31, 2018
Divestiture [Line Items]
Impairment of proved oil and natural gas properties held for sale				$ 296,000
Gain (loss) on sales of oil and natural gas properties, net			$ (509,000)	(3,950,000)
Cash proceeds, net of expenses from sale of oil and natural gas properties			1,044,000	22,115,000
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		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			$ (500,000)	$ (4,200,000)
Cash proceeds, net of expenses from sale of oil and natural gas properties		$ 21,500,000

Acquisitions, Divestitures an_8

Acquisitions, Divestitures and Assets Held for Sale - Divestiture Information (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Nolan County [Member]
Divestiture [Line Items]
Divestiture oil and gas revenue			$ 564
Divestiture oil and gas expense	[1]		770
Southern Oklahoma [Member]
Divestiture [Line Items]
Divestiture oil and gas revenue		$ (4)	9,252
Divestiture oil and gas expense	[2]	$ (17)	$ 7,419

[1]	Expenses include LOE, production and ad valorem taxes, accretion, depletion, and impairment.
[2]	Expenses include LOE, production and ad valorem taxes, accretion and depletion.

Acquisitions, Divestitures an_9

Acquisitions, Divestitures and Assets Held for Sale - Assets Held for Sale - Additional Information (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Divestiture [Line Items]
Assets held for sale, net	$ 430	$ 2,058
Liabilities related to assets held for sale		77
Southern Oklahoma [Member]
Divestiture [Line Items]
Assets held for sale, net	$ 400
Nolan County [Member]
Divestiture [Line Items]
Assets held for sale, net		1,600
Liabilities related to assets held for sale		$ 100

Equity Awards - Awards availabl

Equity Awards - Awards available for future grant (Details) - Long-Term Incentive Plan [Member]	Dec. 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	(932,669)
Awards available for future grant	881,369

Equity Awards - Additional Info

Equity Awards - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Long-Term Incentive Plan [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation expense	$ 0.7	$ 0.4

Equity Awards - Unrestricted Un

Equity Awards - Unrestricted Units - Additional Information (Details) - Unrestricted Common Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 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 (Details) - Restricted Common Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Number of units
Outstanding, beginning of period	6,362	76,922
Units granted	0	0
Units vested	(6,362)	(69,560)
Units forfeited	0	(1,000)
Outstanding, end of period	0	6,362
Weighted Average Grant Date Fair Value per Restricted Unit
Average fair value per unit, outstanding, beginning of period	$ 5.42	$ 5.67
Average grant date fair value per unit, granted	0	0
Average grant date fair value per unit, vested	5.42	6.39
Average grant date fair value per unit, forfeited	0	5.42
Average fair value per unit, outstanding, end of period	$ 0	$ 5.42

Equity Awards - Equity-Settled

Equity Awards - Equity-Settled Phantom Units - Additional Information (Details) - Equity-Settled Phantom Units [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.4
Weighted average period, unrecognized costs	17 months
Units granted	494,500	41,500
Tranche Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years	2 years
Units granted	450,000	27,000
Tranche Three [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years	3 years
Units granted	44,500	14,500
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-Settle_2

Equity Awards - Equity-Settled Phantom Units (Details) - Equity-Settled Phantom Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Number of units
Outstanding, beginning of period	117,495	287,659
Units granted	494,500	41,500
Units vested	(257,829)	(153,833)
Units forfeited	(3,000)	(57,831)
Outstanding, end of period	351,166	117,495
Weighted Average Grant Date Fair Value per Phantom Unit
Average fair value per unit, outstanding, beginning of period	$ 1.45	$ 1.64
Average grant date fair value per unit, granted	1.74	1.60
Average grant date fair value per unit, vested	1.63	1.70
Average grant date fair value per unit, forfeited	1.31	1.96
Average fair value per unit, outstanding, end of period	$ 1.73	$ 1.45

Derivative Financial Instrume_3

Derivative Financial Instruments - Additional information (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value	$ 8,084	$ (4,918)

Derivative Financial Instrume_4

Derivative Financial Instruments - Summary of Gross Fair Value by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Assets
Derivative Asset, Fair Value, Gross Asset	$ 8,123	$ 39
Gross Amounts Offset	(39)	(39)
Net Amount presented - Balance Sheet	8,084	0
Liabilities
Gross Amounts of Recognized Liabilities	(39)	(4,957)
Gross Amounts Offset	39	39
Net Amount presented - Balance Sheet	0	(4,918)
Gross Amount of Recognized Assets and Liabilities	8,084	(4,918)
Gross Amounts Offset	0	0
Net Assets (Liability) Presented - Balance Sheet	8,084	(4,918)
Current Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset	5,705	39
Gross Amounts Offset	(39)	(39)
Net Amount presented - Balance Sheet	5,666	0
Long Term Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset	2,418
Gross Amounts Offset	0
Net Amount presented - Balance Sheet	2,418
Current Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(39)	(3,890)
Gross Amount Deferred premium		(401)
Gross Amounts Offset	39	(362)
Deferred Premium Offset		401
Net Amount presented - Balance Sheet	$ 0	(4,252)
Deferred Premium		0
Long Term Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities		(666)
Gross Amounts Offset		0
Net Amount presented - Balance Sheet		$ (666)

Derivative Financial Instrume_5

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net settlements on matured derivatives	[1]	$ (6,928)	$ (369)
Net settlements on early terminations of derivatives	[1]		582
Net change in fair value of derivatives		12,602	(2,158)
Total gain (loss) on derivatives, net		$ 5,674	$ (1,945)

[1]	The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.

Derivative Financial Instrume_6

Derivative Financial Instruments - Commodity Contracts (Details) - $ / bbl	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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	NYMEX-WTI	NYMEX-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	NYMEX-WTI
Swap [Member] \| Period Covered-2019 [Member]
Derivative [Line Items]
Differential Fixed Price	(20.15)
Total Bbls Hedged/day	137
Derivative, Underlying Basis	WCS-CRUDE-OIL
Swap [Member] \| Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Fixed Price		51.33
Total Bbls Hedged/day		444
Derivative, Underlying Basis		NYMEX-WTI
Put Option [Member] \| Period Covered-2018 [Member]
Derivative [Line Items]
Total Bbls Hedged/day		164
Derivative, Underlying Basis		NYMEX-WTI
Weighted Average Floor Price		45
Collar \| Period Covered-2018 [Member]
Derivative [Line Items]
Total Bbls Hedged/day		1,315
Derivative, Underlying Basis		NYMEX-WTI
Weighted Average Floor Price		44.38
Weighted Average Ceiling Price		55.52

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis and Nonrecurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	$ 8,084	$ 0
Derivative financial instruments - liability	0	4,918
Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	8,123	39
Derivative financial instruments - liability	39	4,556
Derivative deferred premiums - liability		401
Level 1 [Member] \| Fair Value [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
Level 2 [Member] \| Fair Value [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	8,123	39
Derivative financial instruments - liability	39	4,556
Derivative deferred premiums - liability		0
Level 3 [Member] \| Fair Value [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

Fair Value Disclosures - Summar

Fair Value Disclosures - Summary of Changes in assets (liabilities) - Level 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 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	401	5,048
Balance of Level 3 at end of period	$ 0	$ (401)

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Impairment expense	$ 31,160	$ 24,746
Impairment of proved oil and natural gas properties held for sale		$ 296
Measurement Input, Discount Rate [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Fair Value Inputs, Discount Rate	10

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation [Roll Forward]
Asset retirement obligations - beginning of period	$ 10,326	$ 11,331
Liabilities incurred for new wells and interest	15,497	759
Liabilities settled upon plugging and abandoning wells	(138)	(57)
Liabilities removed upon sale of wells	(399)	(2,152)
Revision of estimates	(6)	(75)
Accretion expense	721	520
Asset retirement obligations - end of period	$ 26,001	$ 10,326

Debt - Additional Information (

Debt - Additional Information (Details) - Revolving Credit Facility [Member] - USD ($)	Jan. 31, 2018	Dec. 31, 2018	Dec. 19, 2018	Dec. 31, 2017	Dec. 22, 2017	May 24, 2017
Line of Credit Facility Line Items
Revolving credit facility		$ 93,000,000		$ 99,000,000
Minimum secured loan percentage on lien proved reserves		90.00%
Average effective rate		5.39%
Unused portion of borrowing base, percentage fee		0.50%
Line of credit facility, maximum borrowing capacity	$ 125,000,000		$ 135,000,000		$ 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	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Commitments Contingencies And Litigation [Line Items]
Lease expense	$ 0.3	$ 0.3
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 _2

Commitment and Contingencies - Operating Leases (Details) $ in Thousands	Dec. 31, 2018USD ($)
Commitments And Contingencies Disclosure [Abstract]
2019	$ 484
2020	469
2021	471
Total	$ 1,424

Equity - Additional Information

Equity - Additional Information (Details) - USD ($)	May 05, 2015	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Limited partners, units outstanding		30,436,124	30,090,463
Maximum proceeds under equity distribution agreement - suspended	$ 50,000,000
Mid-Con Energy Partners LP [Member]
Class of Stock [Line Items]
Limited partnership interest		98.80%	98.80%

Equity - Preferred Units - Addi

Equity - Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands	Jan. 31, 2018USD ($)$ / sharesshares	Aug. 11, 2016USD ($)$ / sharesshares	Dec. 31, 2018USD ($)Class	Dec. 31, 2017USD ($)
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
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			$ 1,200	$ 1,100
Preferred units distribution accrued			$ 500
Preferred units distribution payable date to be paid month and year			2019-02
Class B Preferred Units [Member]
Class of Stock [Line Items]
Proceeds from sale of convertible preferred units, net of offering costs			$ 14,847
Allocation of value to beneficial conversion feature of convertible preferred units			686
Preferred units distribution accrued			$ 300
Preferred units distribution payable date to be paid month and year			2019-02
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			$ 200
Price per share for preferred units \| $ / shares	$ 1.53

Equity - Cash Distributions Pre

Equity - Cash Distributions Preferred Unitholders (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 14, 2018	Aug. 22, 2018	May 15, 2018	Feb. 14, 2018	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017	Dec. 31, 2018	Dec. 31, 2017
Class A Preferred Units [Member] \| July 1, 2017 - December 31, 2017 [Member]
Preferred Units [Line Items]
Date Paid								Feb. 14, 2018
Distribution per Unit				$ 0.0860
Total Distributions				$ 1,000
Class A Preferred Units [Member] \| January 1, 2018 - March 31, 2018 [Member]
Preferred Units [Line Items]
Date Paid								May 15, 2018
Distribution per Unit			$ 0.0430
Total Distributions			$ 500
Class A Preferred Units [Member] \| April 1, 2018 - June 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid								Aug. 22, 2018
Distribution per Unit		$ 0.0430
Total Distributions		$ 500
Class A Preferred Units [Member] \| July 1, 2018 - September 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid								Nov. 14, 2018
Distribution per Unit	$ 0.0430
Total Distributions	$ 500
Class A Preferred Units [Member] \| October 1, 2016 - December 31, 2016 [Member]
Preferred Units [Line Items]
Date Paid									Feb. 14, 2017
Distribution per Unit							$ 0.0430
Total Distributions							$ 500
Class A Preferred Units [Member] \| January 1, 2017 - March 31, 2017 [Member]
Preferred Units [Line Items]
Date Paid									May 15, 2017
Distribution per Unit						$ 0.0430
Total Distributions						$ 500
Class A Preferred Units [Member] \| April 1, 2017 - June 30, 2017 [Member]
Preferred Units [Line Items]
Date Paid									Aug. 14, 2017
Distribution per Unit					$ 0.0430
Total Distributions					$ 500
Class B Preferred Units [Member] \| April 1, 2018 - June 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid								Aug. 22, 2018
Distribution per Unit		$ 0.0306
Total Distributions		$ 300
Class B Preferred Units [Member] \| July 1, 2018 - September 30, 2018 [Member]
Preferred Units [Line Items]
Date Paid								Nov. 14, 2018
Distribution per Unit	$ 0.0306
Total Distributions	$ 300
Class B Preferred Units [Member] \| February 1, 2018 - March 31, 2018 [Member]
Preferred Units [Line Items]
Date Paid								May 15, 2018
Distribution per Unit			$ 0.0204
Total Distributions			$ 200

Related Party Transactions Rela

Related Party Transactions Related Party Transactions- Affiliate Transactions (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Services agreement	$ 2,685	$ 2,443
Operating agreements	8,849	6,509
Oilfield services	3,941	3,377
Other Agreements	310	200
Total	$ 15,785	$ 12,529

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Other transactions of related party	$ 3.7	$ 1.6
Joint interest billing payable	3.7	$ 1.4
Operating services and other miscellaneous items payable	1.2
Oil and natural gas revenue receivable	1.2
Operating services payable	$ 0.2

Credit Risk - Additional Inform

Credit Risk - Additional Information (Detail) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	83.00%	99.00%
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	89.00%	98.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) $ / shares in Units, $ in Thousands	Feb. 28, 2019USD ($)bbl	Feb. 14, 2019USD ($)$ / shares	Feb. 28, 2019USD ($)	Dec. 31, 2018USD ($)	Jan. 21, 2019shares	Dec. 31, 2017USD ($)
Subsequent Event [Line Items]
Assets Held-for-sale				$ 430		$ 2,058
Extended derivative maturity period				2021-12
Derivative, maturity period				2020-01
Subsequent Event [Member]
Subsequent Event [Line Items]
Distributions, date to be paid		Feb. 14, 2019
Distributions payable, date of record		Feb. 7, 2019
Production of oil derivative contracts \| bbl	758,300
Subsequent Event [Member] \| Texas [Member] \| Definitive Agreements [Member]
Subsequent Event [Line Items]
Assets Held-for-sale	$ 60,000		$ 60,000
Subsequent Event [Member] \| Oklahoma [Member] \| Definitive Agreements [Member]
Subsequent Event [Line Items]
Assets to be purchased from definitive agreements			$ 27,500
Subsequent Event [Member] \| Class A Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit \| $ / shares		$ 0.0430
Preferred Units Distributions Declared		$ 500
Subsequent Event [Member] \| Class B Preferred Units [Member]
Subsequent Event [Line Items]
Distribution per Unit \| $ / shares		$ 0.0306
Preferred Units Distributions Declared		$ 300
Unrestricted Common Units [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Units authorized \| shares					50,000
Equity-Settled Phantom Units [Member] \| Subsequent Event [Member]
Subsequent Event [Line Items]
Units authorized \| shares					573,000

Supplementary Information - Sup

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property acquisition costs:
Proved	$ 20,158	$ 4,665
Unproved	1,085	369
Exploration	0	0
Development	8,617	9,947
Asset retirement obligations	15,491	684
Total costs incurred	$ 45,351	$ 15,665

Supplementary Information - Cha

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)		12 Months Ended
		Dec. 31, 2018MBoeMBblsMMcf		Dec. 31, 2017MBoeMBblsMMcf
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Beginning balance \| MBoe		19,557		19,231
Revisions of previous estimates \| MBoe	[1]	1,310		2,383
Extensions, discoveries and other additions \| MBoe		72	[2]	69	[3]
Purchases of reserves in place \| MBoe		5,253	[4]	1,684	[5]
Sales of reserves in place \| MBoe		(162)	[6]	(2,529)	[7]
Production \| MBoe		(1,188)		(1,281)
Ending balance \| MBoe		24,842		19,557
Proved developed reserves, MBoe \| MBoe		18,643		14,276
Proved developed reserves, MBoe \| MBoe		6,199		5,281
Oil
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]
Beginning balance \| MBbls		18,510		18,210
Revisions of previous estimates \| MBbls	[1]	1,484		2,355
Extensions, discoveries and other additions \| MBbls		72	[2]	69	[3]
Purchases of reserves in place \| MBbls		4,968	[4]	1,607	[5]
Sales of reserves in place \| MBbls		(133)	[6]	(2,522)	[7]
Production \| MBbls		(1,112)		(1,209)
Ending balance \| MBbls		23,789		18,510
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Proved developed reserves, Oil \| MBbls		17,634		13,512
Proved undeveloped reserves, Oil \| MBbls		6,155		4,998
Natural Gas
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Proved developed reserves, Gas \| MMcf		6,059		4,586
Proved developed reserves, Gas \| MMcf		262		1,696
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Beginning balance \| MMcf		6,282		6,124
Revisions of previous estimates \| MMcf	[1]	(1,045)		168
Purchases of reserves in place \| MMcf		1,713	[4]	459	[5]
Sales of reserves in place \| MMcf		(172)	[6]	(38)	[7]
Production \| MMcf		(457)		(431)
Ending balance \| MMcf		6,321		6,282

[1]	Revisions represent changes in the previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such a commodity prices, operating costs or development costs.
[2]	Extension of our Hardrock Field in the Texas core area as a result of drilling one successful step out well in 2018.
[3]	Extension of our Hardrock Field in the Texas core area as a result of drilling two successful step out wells in 2017.
[4]	Represents the purchase of proved reserves as part of our Oklahoma and Wyoming acquisitions.
[5]	Represents the purchase of proved reserves as part of our Wheatland acquisition.
[6]	Decrease due to the sale of several small properties in the Texas core area.
[7]	Decrease due to the sale of our Southern Oklahoma properties.

Supplementary Information - Add

Supplementary Information - Additional Information (Detail)	12 Months Ended
Supplementary Information - Additional Information (Detail)	Dec. 31, 2018MBoe$ / bbl$ / MMBTU$ / Mcf		Dec. 31, 2017MBoe$ / bbl$ / MMBTU$ / Mcf
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Proved Developed and Undeveloped Reserves, Effect of Commodity Price	1,975		1,309
Proved Developed and Undeveloped Reserves, Improved Recovery	72		69
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate	504		1,074
Sales of reserves in place	162	[1]	2,529	[2]
Purchases of reserves in place	5,253	[3]	1,684	[4]
Proved Developed and Undeveloped Reserve Net Downward Revision of Previous Estimate Energy	1,169
Future net cash flows, annual discount rate	10.00%
Oil
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Representative SEC Price \| $ / bbl	65.56		51.34
Average adjusted prices utilized in calculating proved reserves \| $ / bbl	62.17		49.34
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Representative SEC Price \| $ / MMBTU	3.10		2.98
Average adjusted prices utilized in calculating proved reserves \| $ / Mcf	2.43		2.27

[1]	Decrease due to the sale of several small properties in the Texas core area.
[2]	Decrease due to the sale of our Southern Oklahoma properties.
[3]	Represents the purchase of proved reserves as part of our Oklahoma and Wyoming acquisitions.
[4]	Represents the purchase of proved reserves as part of our Wheatland acquisition.

Supplementary Information - Sta

Supplementary Information - Standardized Measure of Discounted Future Net Cash Flow Relating to Estimated Proved Oil and Natural Gas Reserves (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Future cash inflows	$ 1,494,349	$ 927,473
Future production costs	(694,862)	(444,673)
Future development costs, including abandonment costs	(92,973)	(50,868)
Future net cash flow	706,514	431,932
10% discount for estimated timing of cash flow	(358,261)	(224,719)
Standardized measure of discounted cash flow	$ 348,253	$ 207,213	$ 157,285

Supplementary Information - C_2

Supplementary Information - Changes in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flow, beginning of year	$ 207,213	$ 157,285
Changes in the year resulting from:
Sales, less production costs	(38,316)	(33,994)
Revisions of previous quantity estimates	24,035	28,132
Extensions, discoveries and improved recovery	2,398	3,168
Net change in prices and production costs	102,480	61,504
Net change in income taxes	0	0
Changes in estimated future development costs	4,534	5,173
Previously estimated development costs incurred during the year	8,428	9,726
Purchases of reserves in place	50,242	13,826
Sales of reserves in place	(2,714)	(10,420)
Accretion of discount	20,721	15,729
Timing differences and other	(30,768)	(42,916)
Standardized measure of discounted future net cash flow, end of year	$ 348,253	$ 207,213