Mid-Con Energy Partners (MCEP) 10-K 28 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Feb. 28, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	MCEP
Entity Registrant Name	Mid-Con Energy Partners, LP
Entity Central Index Key	1,527,709
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Smaller Reporting Company
Entity Public Float			$ 33
Entity Common Stock, Shares Outstanding		30,116,560

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents	$ 1,832	$ 2,359
Accounts receivable
Oil and natural gas sales	5,262	5,302
Other	103	233
Prepaid expenses and other	166	512
Assets held for sale, net	2,058
Total current assets	9,421	8,406
Oil and natural gas properties, successful efforts method
Proved properties	335,796	441,479
Unproved properties	369
Other property and equipment	427	289
Accumulated depletion, depreciation, amortization and impairment	(129,101)	(176,551)
Total property and equipment, net	207,491	265,217
Other assets	2,451	2,663
Total assets	219,363	276,286
Accounts payable
Trade	593	256
Related parties	1,631	3,431
Derivative financial instruments	4,252	5,314
Accrued liabilities	603	146
Liabilities related to assets held for sale	77
Total current liabilities	7,156	9,147
Derivative financial instruments	666	2,495
Long-term debt	99,000	122,000
Other long-term liabilities	70	93
Asset retirement obligations	10,249	11,331
Commitments and contingencies
Class A convertible preferred units - 11,627,906 issued and outstanding, respectively	20,534	19,570
General partner	(572)	(248)
Limited partners- 30,090,463 and 29,912,230 units issued and outstanding, respectively	82,260	111,898
Total equity	81,688	111,650
Total liabilities, convertible preferred units and equity	$ 219,363	$ 276,286

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Statement Of Financial Position [Abstract]
Limited partners, units issued	30,090,463	29,912,230
Limited partners, units outstanding	30,090,463	29,912,230
Class A Convertible Preferred Units, shares issued	11,627,906	11,627,906
Class A Convertible Preferred Units, shares outstanding	11,627,906	11,627,906

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Revenues
Oil sales	$ 57,689	$ 54,773
Natural gas sales	1,240	1,325
Loss on derivatives, net	(1,945)	(12,202)
Total revenues	56,984	43,896
Operating costs and expenses
Lease operating expenses	21,614	22,692
Oil and natural gas production taxes	3,321	2,893
Impairment of proved oil and natural gas properties	24,746	895
Impairment of proved oil and natural gas properties held for sale	296	3,578
Depreciation, depletion and amortization	17,713	23,074
Accretion of discount on asset retirement obligations	520	577
General and administrative	5,719	6,890
Total operating costs and expenses	73,929	60,599
Loss on sales of oil and natural gas properties, net	(3,950)	(560)
Loss from operations	(20,895)	(17,263)
Other (expense) income
Interest income	11	12
Interest expense	(6,472)	(7,487)
Other income (expense)	60	(76)
Loss on settlements of asset retirement obligations	(37)
Total other expense	(6,438)	(7,551)
Net loss	(27,333)	(24,814)
Less: Distributions to preferred unitholders	3,063	1,249
Less: General partner's interest in net loss	(324)	(295)
Limited partners’ interest in net loss	$ (30,072)	$ (25,768)
Limited partners’ interest in net loss per unit
Basic and diluted	$ (0.99)	$ (0.86)
Weighted average limited partner units outstanding
Limited partner units (basic and diluted)	30,002	29,834

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Cash Flows from Operating Activities
Net loss	$ (27,333)	$ (24,814)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation, depletion and amortization	17,713	23,074
Debt issuance costs amortization	1,384	1,372
Accretion of discount on asset retirement obligations	520	577
Impairment of proved oil and natural gas properties	24,746	895
Impairment of proved oil and natural gas properties held for sale	296	3,578
Loss on settlements of asset retirement obligations	37
Cash paid for settlements of asset retirement obligations	(95)
Loss on derivatives, net	1,945	12,202
Cash settlements (paid) received for matured derivatives	(369)	20,511
Cash settlements received for early terminations and modifications of derivatives, net	582	5,820
Cash premiums paid for derivatives, net	(5,048)	(5,161)
Loss on sales of oil and natural gas properties, net	3,950	560
Non-cash equity-based compensation	434	1,184
Changes in operating assets and liabilities
Accounts receivable	40	(751)
Other receivables	150	4,935
Prepaid expenses and other	(655)	(39)
Accounts payable - trade and accrued liabilities	427	69
Accounts payable - related parties	(1,478)	(76)
Net cash provided by operating activities	17,246	43,936
Cash Flows from Investing Activities
Acquisitions of oil and natural gas properties	(5,034)	(18,722)
Additions to oil and natural gas properties	(9,947)	(7,223)
Additions to other property and equipment	(137)	(165)
Proceeds from sales of oil and natural gas properties	22,115	17,635
Net cash provided by (used in) investing activities	6,997	(8,475)
Cash Flows from Financing Activities
Proceeds from line of credit	6,000
Payments on line of credit	(29,000)	(58,000)
Offering costs	(99)	(16)
Debt issuance costs	(171)	(68)
Proceeds from sale of Class A convertible preferred units, net of offering costs		24,646
Distributions to Class A convertible preferred units	(1,500)	(279)
Net cash used in financing activities	(24,770)	(33,717)
Net (decrease) increase in cash and cash equivalents	(527)	1,744
Beginning cash and cash equivalents	2,359	615
Ending cash and cash equivalents	$ 1,832	$ 2,359

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) shares in Thousands, $ in Thousands	Total	General Partner [Member]	Limited Partner [Member]
Balance at Dec. 31, 2015	$ 130,498	$ 47	$ 130,451
Balance, Units at Dec. 31, 2015			29,725
Increase (Decrease) in Partners' Capital [Roll Forward]
Equity-based compensation	1,184		$ 1,184
Equity-based compensation, Units			187
Offering costs	(16)		$ (16)
Distributions to Class A convertible preferred units	(779)		(779)
Allocation of value to beneficial conversion feature of Class A convertible preferred units	6,047		6,047
Accretion of beneficial conversion feature of Class A convertible preferred units	(470)		(470)
Net loss	(24,814)	(295)	(24,519)
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
Offering costs	(99)
Distributions to Class A convertible preferred units	(2,000)		$ (2,000)
Accretion of beneficial conversion feature of Class A 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

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2017
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. Reclassifications Certain amounts in the consolidated balance sheets for the prior year have been reclassified to conform to the 2017 presentation. The line items impacted were prepaid expenses and other assets, accounts payable - trade and accounts payable - related parties. These reclassifications have no impact on previously reported total assets, total liabilities, net income (loss) or total operating cash flows. Non-cash Investing, Financing and Supplemental Cash Flow Information The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Non-cash investing and financing information Change in oil and natural gas properties - accrued capital expenditures $ (310 ) $ (259 ) Tenant improvement allowance deferred - other property and equipment $ — $ 124 Supplemental cash flow information Cash paid for interest $ 5,041 $ 6,198

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Note 2. 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, 2017, and 2016, and the results of operations, cash flows and changes in equity for the years then ended December 31, 2017, and 2016. 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, 2017, and 2016, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in any period presented. Revenue recognition We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on our share of actual proceeds from oil and natural gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. We had no significant natural gas imbalances at December 31, 2017, and 2016. We do 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 extract NGLs from the natural gas stream sold by us to them, we have no ownership in such NGLs. Therefore we do not report NGLs in our production or proved reserves. 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 relating to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. 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 (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Partnership nets the fair value of derivatives by counterparty where the right of offset exists and determines the fair value of its derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding Derivative Financial Instruments. Equity-based compensation The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. 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. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (“FASB”) issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, Extractive Activities-Oil and Gas-Revenue Recognition Revenue from Contracts with Customers In February 2016, the FASB issued ASU No. 2016-02, “ Leases In January 2017, the FASB issued ASU No. 2017-01, “ Business Combinations

Acquisitions, Divestitures and

Acquisitions, Divestitures and Assets Held for Sale	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions, Divestitures and Assets Held for Sale	Note 3. Acquisitions, Divestitures and Assets Held for Sale Acquisitions Acquisitions are accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in acquisitions are recorded in our 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 are included in our consolidated statements of operations. Wheatland In June 2017, we acquired multiple oil and natural gas properties located in Oklahoma County and Cleveland County, Oklahoma for cash consideration of $4.1 million, after preliminary post-closing purchase price adjustments. The recognized fair values of the assets acquired and liabilities assumed are as follows: (in thousands) Fair value of net assets acquired Proved oil and natural gas properties $ 4,399 Other property and equipment 132 Total assets acquired 4,531 Fair value of net liabilities assumed Asset retirement obligation 407 Net assets acquired $ 4,124 The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $ 1,373 $ — Expenses (1) $ 1,009 $ — (1) Permian Bolt-On In August 2016, we acquired multiple oil and natural gas properties located in Nolan County, Texas (the “Permian Bolt-On”) for cash consideration of $18.7 million, after post-closing purchase price adjustments. The transaction was funded by a private offering of $25.0 million Class A Convertible Preferred Units (“Class A Preferred Units”). See Note 10 in this section for additional information regarding the issuance of the Class A Preferred Units. 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 $ 19,323 Total assets acquired 19,323 Fair value of net liabilities assumed Asset retirement obligation 622 Net assets acquired $ 18,701 The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $ 8,511 $ 2,673 Expenses (1) $ 5,717 $ 1,640 (1) Divestitures Effective at closing, the operations and cash flows of the divested properties were eliminated from the ongoing operations of the Partnership and the Partnership has no continuing involvement in these properties. The divestitures did not represent a strategic shift and did not have a major effect on the Partnership’s operations or financial results. Southern Oklahoma In December 2017, we sold the properties located in the Southern Oklahoma for cash proceeds of $22.0 million, prior to post-closing purchase price adjustments, and recognized a loss of $4.2 million. The following table presents revenues and expenses of the oil and natural gas properties sold included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $ 9,252 $ 10,273 Expenses (1) $ 7,419 $ 8,897 (1) Hugoton In July 2016, we sold the properties located in the Hugoton region for cash proceeds of $17.6 million, after post-closing purchase price adjustments and recognized a loss of $0.6 million. Additionally, we recorded impairment of proved oil and natural gas properties of $3.6 million when these properties were originally reported as held for sale. 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) 2017 2016 Oil and natural gas sales $ — $ 3,602 Expenses (1) $ — $ 7,717 (1) Assets Held for Sale Certain oil and natural gas proved properties in Nolan County, Texas, were deemed to meet held-for-sale accounting criteria as of December 31, 2017. As a result, 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. The net asset value of $1.6 million was presented in “Assets held for sale, net” and a net liability of $0.1 million was presented as “Liabilities related to assets held for sale” on our consolidated balance sheet. In January 2018, we completed the sale of these assets for $1.6 million, subject to customary post-closing sales price adjustments. In addition to the Nolan County properties, land in Southern Oklahoma met held-for-sale criteria as of December 31, 2017. The carrying value of $0.4 million was presented in “Assets held for sale, net” on our consolidated balance sheet.

Equity Awards

Equity Awards	12 Months Ended
	Dec. 31, 2017
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 awards are 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. On January 1, 2017, we adopted ASU 2016-09 and elected to recognize forfeitures of equity awards as they occur. The cumulative effect of adopting ASU 2016-09 was determined to be immaterial and no adjustment to retained earnings was made. The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2017: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,212,706 ) Restricted units granted, net of forfeitures (399,424 ) Equity-settled phantom units granted, net of forfeitures (441,169 ) Awards available for future grant 1,460,701 We recognized $0.4 million and $1.2 million of total equity-based compensation expense for the years ended December 31, 2017, and 2016, 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, 2017, we granted 25,400 unrestricted units with an average grant date fair value of $2.65 per unit. During the year ended December 31, 2016, we granted 73,932 unrestricted units with an average grant date fair value of $1.20 per unit. Restricted Unit Awards Restricted units vest over two or three years. We did not issue any restricted units during the years ended December 31, 2017, and 2016. A summary of our restricted unit awards for the years ended December 31, 2017, and 2016, is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 222,833 $ 8.49 Units granted — — Units vested (112,478 ) 9.16 Units forfeited (33,433 ) 9.69 Outstanding at 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 Equity-Settled Phantom Unit Awards Equity-settled phantom units vest over two or three years and do not have any rights or privileges of a common unitholder, including the right to distributions, until vesting and the resulting conversion into common units. During the year ended December 31, 2017, we granted 27,000 equity-settled phantom units with a two-year vesting period and 14,500 equity-settled phantom units with a three-year vesting period. During the year ended December 31, 2016, we granted 347,500 equity-settled phantom awards with one-third vesting immediately and the other two-thirds vesting over two years and 27,000 equity-settled phantom awards with a three-year vesting period. As of December 31, 2017, there were $0.1 million of unrecognized compensation costs related to equity-settled phantom units. These costs are expected to be recognized over a weighted average period of ten months. A summary of our equity-settled phantom unit awards for the years ended December 31, 2017, and 2016, is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 77,500 $ 2.81 Units granted 374,500 1.55 Units vested (146,841 ) 2.03 Units forfeited (17,500 ) 2.02 Outstanding at 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

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2017
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 (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. We account for our commodity derivative contracts at fair value. See Note 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, 2017, and 2016, our commodity derivative contracts were in a net liability position with a fair value of $4.9 million and $7.8 million, respectively. All of our commodity derivative contracts are with major financial institutions that are also lenders under our revolving credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our commodity derivative contracts under lower commodity prices and we could incur a loss. During the two years ended December 31, 2017, and 2016, 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, 2017, and 2016: (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 ) (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2016 Assets Derivative financial instruments - current asset $ 1,570 $ (1,570 ) $ — Derivative financial instruments - long-term asset 406 (406 ) — Total 1,976 (1,976 ) — Liabilities Derivative financial instruments - current liability (1,836 ) (3,478 ) (5,314 ) Derivative deferred premium - current liability (5,048 ) 5,048 — Derivative financial instruments - long-term liability (2,500 ) 5 (2,495 ) Derivative deferred premium - long-term liability (401 ) 401 — Total (9,785 ) 1,976 (7,809 ) Net Liability $ (7,809 ) $ — $ (7,809 ) 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) 2017 2016 Net settlements on matured derivatives (1) $ (369 ) $ 20,511 Net settlements on early terminations of derivatives (1) 582 5,820 Net change in fair value of derivatives (2,158 ) (38,533 ) Total loss on derivatives, net $ (1,945 ) $ (12,202 ) (1) At December 31, 2017, and 2016, our commodity derivative contracts had maturities at various dates through December 2019 and were comprised of commodity price swap, put and collar contracts. At December 31, 2017, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2018 $ 51.33 $ — $ — 444 WTI Collars - 2018 $ — $ 44.38 $ 55.52 1,315 WTI Puts - 2018 $ — $ 45.00 $ — 164 WTI Swaps - 2019 $ 51.48 $ — $ — 427 WTI At December 31, 2016, we had the following oil derivatives net positions: Period Covered Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Collars - 2017 $ 43.75 $ 50.68 658 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI Collars - 2018 $ 44.38 $ 55.52 1,315 WTI Puts - 2018 $ 45.00 $ — 164 WTI Collars - 2019 $ 50.00 $ 60.52 427 WTI

Fair Value Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2017
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, 2017, and 2016. 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, 2017, and 2016. 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, 2017, and 2016: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2017 Derivative financial instruments - asset $ — $ 39 $ — $ 39 Derivative financial instruments - liability $ — $ 4,556 $ — $ 4,556 Derivative deferred premiums - liability $ — $ — $ 401 $ 401 December 31, 2016 Derivative financial instruments - asset $ — $ 1,976 $ — $ 1,976 Derivative financial instruments - liability $ — $ 4,336 $ — $ 4,336 Derivative deferred premiums - liability $ — $ — $ 5,449 $ 5,449 A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, (in thousands) 2017 2016 Balance of Level 3 at beginning of period $ (5,449 ) $ (9,973 ) Derivative deferred premiums - purchases — (516 ) Derivative deferred premiums - settlements 5,048 5,040 Balance of Level 3 at end of period $ (401 ) $ (5,449 ) 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 the Partnership’s acquisitions. Reserves We calculate the estimated fair values of reserves and properties using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. Significant inputs used to determine the fair values of proved properties include estimates of reserves, future operating and developmental costs, future commodity prices, a market-based weighted average cost of capital rate and the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows 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, 2017, and 2016, we recorded non-cash impairment of $24.7 million and $0.9 million, respectively. The majority of the 2017 non-cash impairment expense was due to margin compression over the reserve life caused by lower future oil pricing and a higher cost profile on one of our Northeastern Oklahoma projects. Additional 2017 non-cash impairment expense occurred on one of our Permian projects where late-stage waterflood efforts in select wells in the field have longer than anticipated response times to injection. The 2016 non-cash impairment resulted from a revision of reserve estimates for a property located in the Permian. 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 15 in this section for additional information regarding the divestiture. For the year ended December 31, 2016, we recorded non-cash impairment of $3.6 million related to the Hugoton divestiture that was deemed to meet held-for-sale accounting criteria as of June 30, 2016.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
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, 2017, and 2016, 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) 2017 2016 Asset retirement obligations - beginning of period $ 11,331 $ 12,679 Liabilities incurred for new wells and interest 759 747 Liabilities settled upon plugging and abandoning wells (57 ) — Liabilities removed upon sale of wells (2,152 ) (2,827 ) Revision of estimates (75 ) 155 Accretion expense 520 577 Asset retirement obligations - end of period $ 10,326 $ 11,331

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Note 8. Debt At December 31, 2017, and 2016, we had outstanding borrowings under our revolving credit facility of $99.0 million and $122.0 million, respectively. 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 bi-annual redetermination is expected to occur in or around April 2018. 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 1.00% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or the applicable LIBOR plus a margin that varies from 2.00% to 3.75% per annum according to the borrowing base usage. For the year ended December 31, 2017, the average effective rate was 3.99%. Any unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The revolving credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and payments, including distributions, 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 2016 semi-annual redetermination and amendment to the credit agreement completed in May 2016, the effective borrowing base as of June 1, 2016, was reduced to $163.0 million and was comprised of a $110.0 million conforming tranche and a permitted overadvance of $53.0 million. The permitted overadvance was scheduled to mature on November 1, 2016. In addition, the amendment (i) required the Partnership to provide a monthly excess cash flow report; (ii) required the Partnership to make varied minimum monthly principal payments totaling $1.9 million through October 31, 2016; (iii) reduced the conforming borrowing base to $105.0 million upon the close of the Hugoton divestiture; (iv) allowed an additional non-scheduled borrowing base redetermination between September 1, 2016 and November 1, 2016 to be requested by any lenders; (v) increased the minimum collateral coverage from 90% to 95% of proved reserves (and 100% of Proved Developed Producing reserves); (vi) required the Partnership to unwind and early terminate existing hedges covering production from July 2016 through September 2016 and add new at-the-market swap contracts to replace these hedge terminations; and (vii) required the net proceeds from the Hugoton divestiture and from the early termination of hedge contracts to be applied to debt reduction. During August 2016, we completed a non-scheduled redetermination and amendment to the credit agreement in conjunction with our Permian Bolt-On acquisition. Among other changes, the amendment to the credit agreement increased the conforming borrowing base of the Partnership’s revolving credit facility to $140.0 million as of August 11, 2016, modified the definition of “Indebtedness” to exclude the Preferred Units and modified the limitations on restricted payments to specifically provide for the payment of cash distributions on the Preferred Units. During the fall 2016 semi-annual borrowing base redetermination of our revolving credit facility completed in October 2016, the lender group reaffirmed the existing conforming borrowing base of $140.0 million effective October 28, 2016. There were no changes to the terms or conditions of the credit agreement. During the spring 2017 semi-annual borrowing base redetermination of our revolving credit facility completed in May 2017, the lender group reaffirmed the Partnership’s $140.0 million conforming borrowing base effective May 24, 2017. There were no changes to the terms or conditions of the credit agreement. During the quarter ended September 30, 2017, we were not in compliance with our leverage ratio calculation. On November 10, 2017, the Partnership received a waiver from the Administrative Agent and the Lenders of our revolving credit facility waiving the noncompliance through December 15, 2017. On December 22, 2017, Amendment 11 to the credit agreement was finalized. The amendment extended the waiver of the leverage ratio default until January 31, 2018. This amendment decreased the Partnership’s borrowing base to $115.0 million effective December 22, 2017, and required the facility usage not exceed $100.0 million. The amendment also required that the cash proceeds received from the Southern Oklahoma divestiture on December 22, 2017, and the Nolan County divestiture on January 9, 2018, be applied to the borrowings outstanding. See Note 3 and 15 in this section for more information regarding these divestitures. On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 until November 2020, and increasing the borrowing base of the Partnership’s revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of the Partnership’s failure to maintain the required leverage ratios for the quarter ended September 30, 2017. The amendment also required the Partnership to have a minimum liquidity of 20% prior to making any distributions to the Preferred Unitholders.

Commitment and Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitment and Contingencies	Note 9. Commitment and Contingencies Leases We lease corporate office space in Tulsa, Oklahoma, and Abilene, Texas. We were also allocated office rent from Mid-Con Energy Operating through August 2016 for office space in Dallas, Texas. For the years ended December 31, 2017, and 2016, total lease expenses were $0.3 million and $0.4 million, respectively. 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) 2018 $ 489 2019 413 2020 418 2021 423 Total $ 1,743 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 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 agreement stipulates that if there is a change of control, termination of employment, with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $0.3 million to $0.6 million, including the value of vesting of any outstanding units. Legal We are party to various claims, legal actions and complaints arising in the ordinary course of business. In the opinion of management and our General Counsel, the ultimate resolution of all claims, legal actions and complaints after consideration of amounts accrued, insurance coverage or other indemnification arrangements will not have a material adverse effect on our financial position, results of operations or cash flows.

Equity

Equity	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity	Note 10. Equity Common Units At December 31, 2017, and 2016, the Partnership’s equity consisted of 30,090,463 and 29,912,230 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 Preferred Units agreement described below, the Partnership suspended sales of common units pursuant to the Equity Distribution Agreement effective as of the closing date until the fifth anniversary of the closing date of the Preferred Units purchase agreement, without the consent of a majority of the holders of the outstanding Preferred Units. Our Partnership Agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. As of December 31, 2017, 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. There were no common unit distributions for the years ended December 31, 2017, and 2016. Class A Preferred Units On August 11, 2016, we completed a private placement of 11,627,906 Class A Preferred Units for an aggregate offering price of $25.0 million. The Class A Preferred Units were issued at a price of $2.15 per Class A Preferred Unit (the “Class A Unit Purchase Price”). Proceeds from this issuance were used to fund the Permian Bolt-On acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We received net proceeds of $24.6 million (net of issuance costs of $0.4 million) in connection with the issuance of these Class A Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Class A Preferred Units ($18.6 million) and the beneficial conversion feature ($6.0 million). A beneficial conversion feature is defined as a non-detachable conversion feature that is in the money at the commitment date. Per accounting guidance, we are required to allocate a portion of the proceeds from the Class A Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and the proceeds attributed to the Class A Preferred Units. We record the accretion attributed to the beneficial conversion feature as a deemed distribution using the effective yield method over the five year period prior to the effective date of the holders conversion right. Accretion of the beneficial conversion feature was $1.1 million and $0.5 million for the years ended December 31, 2017, and 2016, respectively. The holders of our Class A 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 the Class A Preferred Units a cumulative, quarterly cash distribution on all Class A 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 Class A Preferred Units, in kind (additional Class A 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. As of December 31, 2017, all Class A Preferred Unit distributions have been paid in cash. No payment or distribution on common units for any quarter is permitted prior to the payment in full of the Class A Preferred Units distribution (including any outstanding arrearages). At December 31, 2017, the Partnership had accrued $1.0 million for the third and fourth quarter 2017 distributions that are to be paid in February 2018. 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 $ 0.043 $ 500 May 15, 2017 January 1, 2017 - March 31, 2017 $ 0.043 $ 500 August 14, 2017 April 1, 2017 - June 30, 2017 $ 0.043 $ 500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2016: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) November 14, 2016 August 11, 2016 - September 30, 2016 $ 0.024 $ 279 Prior to the five year anniversary of the closing date, each holder of the Class A Preferred Units has the right, subject to certain conditions, to convert all or a portion of their Class A 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 Class A Preferred Units, the Partnership will pay any distributions (to the extent accrued and unpaid as of the then most recent Class A Preferred Units distribution date) on the converted units in cash. 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. 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
	Dec. 31, 2017
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, were not the result of arm’s length negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner. Services Agreement We are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certain services to us, including management, administrative and operational services. The operational services include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses were included in general and administrative expenses 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 lease operating expenses 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 were either included in lease operating expenses in our consolidated statements of operations or were capitalized as part of oil and natural gas properties in our consolidated balance sheets. The following table summarizes the affiliates’ transactions for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 Services agreement $ 2,443 $ 3,403 Operating agreements 6,509 6,221 Oilfield services 3,377 3,058 $ 12,329 $ 12,682 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. At December 31, 2016, we had a net payable to our affiliate Mid-Con Energy Operating of $3.4 million, comprised of a joint interest billing payable of $2.8 million and a payable for operating services of $0.6 million. These amounts were included in accounts payable-related parties in our consolidated balance sheets.

Credit Risk

Credit Risk	12 Months Ended
	Dec. 31, 2017
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, 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. For the year ended December 31, 2016, sales of oil and natural gas to four purchasers accounted for 94% of our sales. At December 31, 2016, these purchasers accounted for 95% 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
	Dec. 31, 2017
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
	Dec. 31, 2017
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
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 15. Subsequent Events Nolan County Divestiture On January 9, 2018, we entered a binding letter agreement to sell certain Permian oil and natural gas proved properties in Nolan County, Texas, for cash consideration of $1.6 million, subject to customary post-closing sale price adjustments. Per the agreement, the effective date of the sale was November 1, 2017. Proceeds from the divestiture were used to reduce borrowings outstanding under the Partnership’s revolving credit facility. House Creek Acquisition On January 16, 2018, we acquired multiple oil and natural gas properties located in Campbell County, Wyoming, for cash consideration of $1.5 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017. Credit Facility Amendment On January 31, 2018, Amendment 12 to the credit agreement was executed, extending the maturity of our credit facility from November 2018 until November 2020, and increasing the borrowing base of the Partnership’s revolving credit facility to $125.0 million. The lenders also waived any default or event of default that occurred as a result of the Partnership’s failure to maintain the required leverage ratios for the quarter ended September 30, 2017. Class B Preferred Units Offering On January 31, 2018, we closed the private placement of 9,803,921 Class B Preferred Units for an aggregate offering price of $15.0 million. We received cash proceeds of $15.0 million in connection with the issuance of these Class B Preferred Units. The Partnership used a portion of the proceeds from the offering to fund the acquisition of certain properties in Campbell and Converse Counties, Wyoming, and any excess was used to reduce borrowings under our revolving credit facility. The Class B Preferred Units were issued at a price of $1.53 per Preferred Unit. The Partnership will pay holders of the Class B Preferred Units a cumulative, quarterly distribution in cash at an annual rate of 8.0%, or under certain circumstances, in additional Class B Preferred Units, at an annual rate of 10.0%. At any time after the six month anniversary and prior to August 11, 2021, each holder of the Preferred Units may elect to convert all or any portion of their Class B Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis. On August 11, 2021, each holder may elect to cause the Partnership to redeem all or any portion of their Class B Preferred Units for cash at the Class B Unit Purchase Price, and any remaining Class B Preferred Units will thereafter be converted to common units on a one-for-one basis. Pine Tree Acquisition On January 31, 2018, we acquired multiple oil and natural gas properties located in Campbell and Converse Counties, Wyoming, for cash consideration of $8.6 million, subject to customary post-closing sale price adjustments. The effective date of the acquisition was September 1, 2017. The purchase price was funded by the Class B Preferred Unit Offering described above. Distributions On January 31, 2018, the Partnership announced that the Board declared a Class A Preferred Unit cash distribution for the third and fourth quarters of 2017, according to terms outlined in the Partnership Agreement. A cash distribution of $0.086 per Class A Preferred Unit, or $1.0 million in aggregate, was paid on February 14, 2018 to holders of record as of the close of business on February 7, 2018. Equity Awards During the first quarter of 2018, the Board authorized the issuance of 87,832 unrestricted common units and 389,500 equity-settled phantom units.

Supplementary Information

Supplementary Information	12 Months Ended
	Dec. 31, 2017
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 as follows: Year Ended December 31, (in thousands) 2017 2016 Property acquisition costs: Proved $ 4,665 $ 18,722 Unproved 369 — Exploration — — Development 9,947 6,963 Asset retirement obligations 684 902 Total costs incurred $ 15,665 $ 26,587 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, 2017, and 2016, were prepared by our reservoir engineers and audited by Cawley, Gillespie & Associates, Inc., independent third party petroleum consultants. These reserve estimates have been prepared in compliance with the rules of the SEC. We emphasize that reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of producing oil and natural gas properties. Accordingly, the estimates are expected to change as future information becomes available. An analysis of the change in estimated quantities of oil and natural gas reserves are presented below for the periods indicated: Oil (MBbls) Natural Gas (MMcf) MBoe Proved developed and undeveloped reserves: As of December 31, 2015 21,114 6,827 22,252 Revisions of previous estimates (1) 58 (262 ) 14 Extensions, discoveries and other additions — — — Purchases of reserves in place (2) 1,517 211 1,552 Sales of reserves in place (3) (3,093 ) (98 ) (3,109 ) Production (1,386 ) (554 ) (1,478 ) 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 (4) 69 — 69 Purchases of reserves in place (5) 1,607 459 1,684 Sales of reserves in place (6) (2,522 ) (38 ) (2,529 ) Production (1,209 ) (431 ) (1,281 ) As of December 31, 2017 18,510 6,282 19,557 Proved developed reserves: December 31, 2016 11,733 4,141 12,423 December 31, 2017 13,512 4,586 14,276 Proved undeveloped reserves: December 31, 2016 6,477 1,983 6,808 December 31, 2017 4,998 1,696 5,281 (1) (2) (3) (4) (5) (6) The change in quantities of proved reserves from December 31, 2015, to December 31, 2016, was due in part to commodity price decreases which shortened the economic lives of certain producing properties and caused certain development projects to become uneconomic which had an adverse impact on our proved reserves estimates, resulting in downward reserve revisions of 1,801 MBoe in 2016. In response to the continued decrease in commodity prices throughout 2016, we further refined our development plans to concentrate on our Northeastern Oklahoma and Permian areas. This included infill drills and recompletions resulting in positive revisions in production performance of 569 MBoe. In addition, we saw positive oil production responses to water injection in our Northeastern Oklahoma and Permian areas, resulting in upward revisions to our proved reserves of 1,246 MBoe. During 2016, the acquisition of the Permian Bolt-On properties resulted in a positive revision of 1,552 MBoe, and the divestiture of our Hugoton area properties resulted in a downward revision of 3,109 MBoe. 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. 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, 2017, and 2016, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month in such period; • future costs of developing and producing the proved oil and natural gas reserves were based on costs determined at each such period-end, assuming the continuation of existing economic conditions, including abandonment costs; • no future income tax expenses are computed for Mid-Con Energy Partners, 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) 2017 2016 Future cash inflows $ 927,473 $ 741,077 Future production costs (444,673 ) (389,138 ) Future development costs, including abandonment costs (50,868 ) (65,195 ) Future net cash flow 431,932 286,744 10% discount for estimated timing of cash flow (224,719 ) (129,459 ) Standardized measure of discounted cash flow $ 207,213 $ 157,285 The prices utilized in calculating our total proved reserves were $51.34 and $42.75 per Bbl of oil and $2.98 and $2.49 per MMBtu of natural gas for December 31, 2017, and 2016, 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 $49.34 and $40.03 per Bbl of oil and $2.27 and $1.99 per Mcf of natural gas for December 31, 2017, and 2016, respectively. Adjusted natural gas price includes the sale of associated NGLs. We do 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 extract NGLs from the natural gas stream sold by us to them, we have 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) 2017 2016 Standardized measure of discounted future net cash flow, beginning of year $ 157,285 $ 191,420 Changes in the year resulting from: Sales, less production costs (33,994 ) (30,513 ) Revisions of previous quantity estimates 28,132 133 Extensions, discoveries and improved recovery 3,168 — Net change in prices and production costs 61,504 (16,138 ) Net change in income taxes — — Changes in estimated future development costs 5,173 22,685 Previously estimated development costs incurred during the year 9,726 3,526 Purchases of reserves in place 13,826 22,223 Sales of reserves in place (10,420 ) (11,124 ) Accretion of discount 15,729 19,142 Timing differences and other (42,916 ) (44,069 ) Standardized measure of discounted future net cash flow, end of year $ 207,213 $ 157,285

Organization and Nature of Op23

Organization and Nature of Operations (Policies)	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Reclassifications	Reclassifications Certain amounts in the consolidated balance sheets for the prior year have been reclassified to conform to the 2017 presentation. The line items impacted were prepaid expenses and other assets, accounts payable - trade and accounts payable - related parties. These reclassifications have no impact on previously reported total assets, total liabilities, net income (loss) or total operating cash flows.

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
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, 2017, and 2016, and the results of operations, cash flows and changes in equity for the years then ended December 31, 2017, and 2016.
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, 2017, and 2016, we did not have any reserves for doubtful accounts and we did not incur any expenses related to bad debts in any period presented.
Revenue recognition	Revenue recognition We follow the sales method of accounting for oil and natural gas revenues. Under this method, revenues are recognized based on our share of actual proceeds from oil and natural gas sold to purchasers. Natural gas revenues would not have been significantly altered for the period presented had the entitlements method of recognizing natural gas revenues been utilized. If reserves are not sufficient to recover natural gas overtake positions, a liability is recorded. We had no significant natural gas imbalances at December 31, 2017, and 2016. We do 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 extract NGLs from the natural gas stream sold by us to them, we have no ownership in such NGLs. Therefore we do not report NGLs in our production or proved reserves.
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 relating to proved properties are depleted using the units-of-production method based on proved reserves on a field basis. The depreciation of capitalized production equipment is based on the units-of-production method using proved developed reserves on a field basis. 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 (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. Derivatives are recorded at fair value and are presented on a net basis on the consolidated balance sheets as assets or liabilities. The Partnership nets the fair value of derivatives by counterparty where the right of offset exists and determines the fair value of its derivatives by utilizing certain pricing models to validate the data provided by third parties. See Note 6 Fair Value Disclosures for more information. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of unsettled derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash income or expenses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds or payments for termination of contracts prior to their expiration and premiums paid or received for new contracts. Any deferred premiums are recorded as a liability and recognized in earnings as the related contracts mature. Gains and losses on derivatives are included in cash flows from operating activities. See Note 5 for discussion regarding Derivative Financial Instruments.
Equity-based compensation	Equity-based compensation The cost of employee services received in exchange for equity instruments is measured based on the grant-date fair value and is recorded as compensation expense over the requisite service period (often the vesting period). Awards subject to performance criteria vest when it is probable that the performance criteria will be met. 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 In May 2014, the Financial Accounting Standards Board (“FASB”) issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, Extractive Activities-Oil and Gas-Revenue Recognition Revenue from Contracts with Customers In February 2016, the FASB issued ASU No. 2016-02, “ Leases In January 2017, the FASB issued ASU No. 2017-01, “ Business Combinations

Organization and Nature of Op25

Organization and Nature of Operations (Tables)	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Schedule of Cash Flow Supplemental Disclosures	The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Non-cash investing and financing information Change in oil and natural gas properties - accrued capital expenditures $ (310 ) $ (259 ) Tenant improvement allowance deferred - other property and equipment $ — $ 124 Supplemental cash flow information Cash paid for interest $ 5,041 $ 6,198

Acquisitions, Divestitures an26

Acquisitions, Divestitures and Assets Held for Sale, Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2017
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 $ 4,399 Other property and equipment 132 Total assets acquired 4,531 Fair value of net liabilities assumed Asset retirement obligation 407 Net assets acquired $ 4,124
Summary of Revenues and Expenses of Properties Acquired	The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $ 1,373 $ — Expenses (1) $ 1,009 $ — (1)
Permian Bolt On [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 $ 19,323 Total assets acquired 19,323 Fair value of net liabilities assumed Asset retirement obligation 622 Net assets acquired $ 18,701
Summary of Revenues and Expenses of Properties Acquired	The following table presents revenues and expenses of the oil and natural gas properties acquired included in the accompanying consolidated statements of operations for the periods presented: Year Ended December 31, (in thousands) 2017 2016 Oil and natural gas sales $ 8,511 $ 2,673 Expenses (1) $ 5,717 $ 1,640 (1)

Acquisitions, Divestitures an27

Acquisitions, Divestitures and Assets Held for Sale, Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2017 2016 Oil and natural gas sales $ 9,252 $ 10,273 Expenses (1) $ 7,419 $ 8,897 (1)
Hugoton [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) 2017 2016 Oil and natural gas sales $ — $ 3,602 Expenses (1) $ — $ 7,717 (1)

Equity Awards (Tables)

Equity Awards (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,212,706 ) Restricted units granted, net of forfeitures (399,424 ) Equity-settled phantom units granted, net of forfeitures (441,169 ) Awards available for future grant 1,460,701
Summary of restricted units awarded	A summary of our restricted unit awards for the years ended December 31, 2017, and 2016, is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 222,833 $ 8.49 Units granted — — Units vested (112,478 ) 9.16 Units forfeited (33,433 ) 9.69 Outstanding at 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
Summary of equity-settled units	A summary of our equity-settled phantom unit awards for the years ended December 31, 2017, and 2016, is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2015 77,500 $ 2.81 Units granted 374,500 1.55 Units vested (146,841 ) 2.03 Units forfeited (17,500 ) 2.02 Outstanding at 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

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017, and 2016: (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 ) (in thousands) Gross Amounts Recognized Gross Amounts Offset in the Consolidated Balance Sheet Net Amounts Presented in the Consolidated Balance Sheet December 31, 2016 Assets Derivative financial instruments - current asset $ 1,570 $ (1,570 ) $ — Derivative financial instruments - long-term asset 406 (406 ) — Total 1,976 (1,976 ) — Liabilities Derivative financial instruments - current liability (1,836 ) (3,478 ) (5,314 ) Derivative deferred premium - current liability (5,048 ) 5,048 — Derivative financial instruments - long-term liability (2,500 ) 5 (2,495 ) Derivative deferred premium - long-term liability (401 ) 401 — Total (9,785 ) 1,976 (7,809 ) Net Liability $ (7,809 ) $ — $ (7,809 )
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) 2017 2016 Net settlements on matured derivatives (1) $ (369 ) $ 20,511 Net settlements on early terminations of derivatives (1) 582 5,820 Net change in fair value of derivatives (2,158 ) (38,533 ) Total loss on derivatives, net $ (1,945 ) $ (12,202 ) (1)
Commodity Contracts	At December 31, 2017, and 2016, our commodity derivative contracts had maturities at various dates through December 2019 and were comprised of commodity price swap, put and collar contracts. At December 31, 2017, we had the following oil derivatives net positions: Period Covered Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2018 $ 51.33 $ — $ — 444 WTI Collars - 2018 $ — $ 44.38 $ 55.52 1,315 WTI Puts - 2018 $ — $ 45.00 $ — 164 WTI Swaps - 2019 $ 51.48 $ — $ — 427 WTI At December 31, 2016, we had the following oil derivatives net positions: Period Covered Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Collars - 2017 $ 43.75 $ 50.68 658 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI Collars - 2018 $ 44.38 $ 55.52 1,315 WTI Puts - 2018 $ 45.00 $ — 164 WTI Collars - 2019 $ 50.00 $ 60.52 427 WTI

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2017
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, 2017, and 2016: (in thousands) Level 1 Level 2 Level 3 Fair Value December 31, 2017 Derivative financial instruments - asset $ — $ 39 $ — $ 39 Derivative financial instruments - liability $ — $ 4,556 $ — $ 4,556 Derivative deferred premiums - liability $ — $ — $ 401 $ 401 December 31, 2016 Derivative financial instruments - asset $ — $ 1,976 $ — $ 1,976 Derivative financial instruments - liability $ — $ 4,336 $ — $ 4,336 Derivative deferred premiums - liability $ — $ — $ 5,449 $ 5,449
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) 2017 2016 Balance of Level 3 at beginning of period $ (5,449 ) $ (9,973 ) Derivative deferred premiums - purchases — (516 ) Derivative deferred premiums - settlements 5,048 5,040 Balance of Level 3 at end of period $ (401 ) $ (5,449 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	For the years ended December 31, 2017, and 2016, 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) 2017 2016 Asset retirement obligations - beginning of period $ 11,331 $ 12,679 Liabilities incurred for new wells and interest 759 747 Liabilities settled upon plugging and abandoning wells (57 ) — Liabilities removed upon sale of wells (2,152 ) (2,827 ) Revision of estimates (75 ) 155 Accretion expense 520 577 Asset retirement obligations - end of period $ 10,326 $ 11,331

Commitments and Contingencies -

Commitments and Contingencies - Non-Cancellable Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2017
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) 2018 $ 489 2019 413 2020 418 2021 423 Total $ 1,743

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Cash Distributions - Preferred Unitholders	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 $ 0.043 $ 500 May 15, 2017 January 1, 2017 - March 31, 2017 $ 0.043 $ 500 August 14, 2017 April 1, 2017 - June 30, 2017 $ 0.043 $ 500 The following table summarizes cash distributions paid on our Class A Preferred Units during the year ended December 31, 2016: Date Paid Period Covered Distribution per Unit Total Distributions (in thousands) November 14, 2016 August 11, 2016 - September 30, 2016 $ 0.024 $ 279

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	The following table summarizes the affiliates’ transactions for the periods indicated: Year Ended December 31, (in thousands) 2017 2016 Services agreement $ 2,443 $ 3,403 Operating agreements 6,509 6,221 Oilfield services 3,377 3,058 $ 12,329 $ 12,682

Supplementary Information (Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Supplementary Oil and Natural Gas Activities	Costs incurred in oil and natural gas property acquisitions and development activities are as follows: Year Ended December 31, (in thousands) 2017 2016 Property acquisition costs: Proved $ 4,665 $ 18,722 Unproved 369 — Exploration — — Development 9,947 6,963 Asset retirement obligations 684 902 Total costs incurred $ 15,665 $ 26,587
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, 2015 21,114 6,827 22,252 Revisions of previous estimates (1) 58 (262 ) 14 Extensions, discoveries and other additions — — — Purchases of reserves in place (2) 1,517 211 1,552 Sales of reserves in place (3) (3,093 ) (98 ) (3,109 ) Production (1,386 ) (554 ) (1,478 ) 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 (4) 69 — 69 Purchases of reserves in place (5) 1,607 459 1,684 Sales of reserves in place (6) (2,522 ) (38 ) (2,529 ) Production (1,209 ) (431 ) (1,281 ) As of December 31, 2017 18,510 6,282 19,557 Proved developed reserves: December 31, 2016 11,733 4,141 12,423 December 31, 2017 13,512 4,586 14,276 Proved undeveloped reserves: December 31, 2016 6,477 1,983 6,808 December 31, 2017 4,998 1,696 5,281 (1) (2) (3) (4) (5) (6)
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) 2017 2016 Future cash inflows $ 927,473 $ 741,077 Future production costs (444,673 ) (389,138 ) Future development costs, including abandonment costs (50,868 ) (65,195 ) Future net cash flow 431,932 286,744 10% discount for estimated timing of cash flow (224,719 ) (129,459 ) Standardized measure of discounted cash flow $ 207,213 $ 157,285
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) 2017 2016 Standardized measure of discounted future net cash flow, beginning of year $ 157,285 $ 191,420 Changes in the year resulting from: Sales, less production costs (33,994 ) (30,513 ) Revisions of previous quantity estimates 28,132 133 Extensions, discoveries and improved recovery 3,168 — Net change in prices and production costs 61,504 (16,138 ) Net change in income taxes — — Changes in estimated future development costs 5,173 22,685 Previously estimated development costs incurred during the year 9,726 3,526 Purchases of reserves in place 13,826 22,223 Sales of reserves in place (10,420 ) (11,124 ) Accretion of discount 15,729 19,142 Timing differences and other (42,916 ) (44,069 ) Standardized measure of discounted future net cash flow, end of year $ 207,213 $ 157,285

Organization and Nature of Op36

Organization and Nature of Operations - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Non-cash investing and financing information
Change in oil and natural gas properties - accrued capital expenditures	$ (310)	$ (259)
Tenant improvement allowance deferred - other property and equipment		124
Supplemental cash flow information
Cash paid for interest	$ 5,041	$ 6,198

Summary of Significant Accoun37

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)Segment
Accounting Policies [Abstract]
Number of operating segment | Segment	1	1
Reserves for doubtful accounts	$ 0	$ 0
Bad debts expenses	0	0
Significant natural gas imbalances	0	0
Interest capitalized during period	$ 0	$ 0

Acquisitions, Divestitures an38

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions - Additional Information (Details) - USD ($) $ in Millions	Aug. 11, 2016	Jun. 30, 2017
Class A Preferred Units [Member]
Business Acquisition [Line Items]
Proceeds from sale of convertible preferred units, gross	$ 25
Wheatland [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net		$ 4.1
Permian Bolt On [Member]
Business Acquisition [Line Items]
Aggregate purchase price, net	18.7
Permian Bolt On [Member] | Class A Preferred Units [Member]
Business Acquisition [Line Items]
Proceeds from sale of convertible preferred units, gross	$ 25

Acquisitions, Divestitures an39

Acquisitions, Divestitures and Assets Held for Sale - Acquisitions of Oil Properties (Details) - USD ($) $ in Thousands	Jun. 30, 2017	Aug. 11, 2016
Wheatland [Member]
Business Acquisition [Line Items]
Proved oil and natural gas properties	$ 4,399
Other property and equipment	132
Total assets acquired	4,531
Asset retirement obligation	407
Net assets acquired	$ 4,124
Permian Bolt On [Member]
Business Acquisition [Line Items]
Proved oil and natural gas properties		$ 19,323
Total assets acquired		19,323
Asset retirement obligation		622
Net assets acquired		$ 18,701

Acquisitions, Divestitures an40

Acquisitions, Divestitures and Assets Held for Sale - Summary of Revenues and Expenses of Properties Acquired (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired	$ 56,984	$ 43,896
Expenses of oil and natural gas properties acquired	73,929	60,599
Wheatland [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired	1,373
Expenses of oil and natural gas properties acquired	1,009
Permian Bolt On [Member]
Business Acquisition [Line Items]
Revenues from oil and natural gas properties acquired	8,511	2,673
Expenses of oil and natural gas properties acquired	$ 5,717	$ 1,640

Acquisitions, Divestitures an41

Acquisitions, Divestitures and Assets Held for Sale - Divestitures - Additional Information (Details) - USD ($) $ in Thousands	Jul. 28, 2016	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016
Divestiture [Line Items]
Proceeds from sales of oil and natural gas properties			$ 22,115	$ 17,635
Loss on sales of oil and natural gas properties, net			3,950	560
Impairment of proved oil and natural gas properties held for sale			$ 296	$ 3,578
Southern Oklahoma [Member]
Divestiture [Line Items]
Proceeds from sales of oil and natural gas properties		$ 22,000
Loss on sales of oil and natural gas properties, net		$ 4,200
Hugoton [Member]
Divestiture [Line Items]
Proceeds from sales of oil and natural gas properties	$ 17,600
Loss on sales of oil and natural gas properties, net	600
Impairment of proved oil and natural gas properties held for sale	$ 3,600

Acquisitions, Divestitures an42

Acquisitions, Divestitures and Assets Held for Sale - Divestiture Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Southern Oklahoma [Member]
Divestiture [Line Items]
Divestiture oil and gas revenue	$ 9,252	$ 10,273
Divestiture oil and gas expense	$ 7,419	8,897
Hugoton [Member]
Divestiture [Line Items]
Divestiture oil and gas revenue		3,602
Divestiture oil and gas expense		$ 7,717

Acquisitions, Divestitures an43

Acquisitions, Divestitures and Assets Held for Sale - Assets Held for Sale - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Jan. 09, 2018
Divestiture [Line Items]
Impairment of proved oil and natural gas properties held for sale	$ 296	$ 3,578
Assets held for sale, net	2,058
Liabilities related to assets held for sale	77
Nolan County [Member]
Divestiture [Line Items]
Impairment of proved oil and natural gas properties held for sale	300
Assets held-for-sale, fair value	1,500
Assets held for sale, net	1,600
Liabilities related to assets held for sale	100
Southern Oklahoma [Member]
Divestiture [Line Items]
Assets held for sale, net	$ 400
Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Nolan County [Member] | Subsequent Event [Member]
Divestiture [Line Items]
Aggregate sale price			$ 1,600

Equity Awards - Awards availabl

Equity Awards - Awards available for future grant (Details) - Long-Term Incentive Plan	Dec. 31, 2017shares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Approved and authorized awards	3,514,000
Unrestricted units granted	(1,212,706)
Restricted units granted, net of forfeitures	(399,424)
Equity-settled phantom units granted, net of forfeitures	(441,169)
Awards available for future grant	1,460,701

Equity Awards - Additional Info

Equity Awards - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Long-Term Incentive Plan
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Equity-based compensation expense	$ 0.4	$ 1.2

Equity Awards - Unrestricted Un

Equity Awards - Unrestricted Units - Additional Information (Details) - Unrestricted Common Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units granted	25,400	73,932
Average grant date fair value per unit, granted	$ 2.65	$ 1.20

Equity Awards - Restricted Unit

Equity Awards - Restricted Units - Additional Information (Details) - Restricted Common Units [Member]	12 Months Ended
	Dec. 31, 2017
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years

Equity Awards - Restricted Un48

Equity Awards - Restricted Units (Details) - Restricted Common Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Number of units
Outstanding, beginning of period	76,922	222,833
Units granted	0	0
Units vested	(69,560)	(112,478)
Units forfeited	(1,000)	(33,433)
Outstanding, end of period	6,362	76,922
Weighted Average Grant Date Fair Value per Restricted Unit
Average fair value per unit, outstanding, beginning of period	$ 5.67	$ 8.49
Average grant date fair value per unit, granted	0	0
Average grant date fair value per unit, vested	6.39	9.16
Average grant date fair value per unit, forfeited	5.42	9.69
Average fair value per unit, outstanding, end of period	$ 5.42	$ 5.67

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, 2017	Dec. 31, 2016
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.1
Weighted average period, unrecognized costs	10 months
Units granted	41,500	374,500
Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		33.00%
Tranche Two
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		66.00%
Vesting period	2 years
Units granted	27,000	347,500
Tranche Three
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years
Units granted	14,500	27,000
Minimum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	2 years
Maximum
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Vesting period	3 years

Equity Awards - Equity-Settle50

Equity Awards - Equity-Settled Phantom Units (Details) - Equity-Settled Phantom Units [Member] - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Number of units
Outstanding, beginning of period	287,659	77,500
Units granted	41,500	374,500
Units vested	(153,833)	(146,841)
Units forfeited	(57,831)	(17,500)
Outstanding, end of period	117,495	287,659
Weighted Average Grant Date Fair Value per Restricted Unit
Average fair value per unit, outstanding, beginning of period	$ 1.64	$ 2.81
Average grant date fair value per unit, granted	1.60	1.55
Average grant date fair value per unit, vested	1.70	2.03
Average grant date fair value per unit, forfeited	1.96	2.02
Average fair value per unit, outstanding, end of period	$ 1.45	$ 1.64

Derivative Financial Instrume51

Derivative Financial Instruments - Additional information (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Fair value	$ (4,918)	$ (7,809)

Derivative Financial Instrume52

Derivative Financial Instruments - Summary of Gross Fair Value by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Assets
Derivative Asset, Fair Value, Gross Asset	$ 39	$ 1,976
Gross Amounts Offset	(39)	(1,976)
Net Amount presented - Balance Sheet	0	0
Liabilities
Gross Amounts of Recognized Liabilities	(4,957)	(9,785)
Gross Amounts Offset	39	1,976
Net Amount presented - Balance Sheet	(4,918)	(7,809)
Gross Amount of Recognized Assets and Liabilities	(4,918)	(7,809)
Gross Amounts Offset	0	0
Net Assets (Liability) Presented - Balance Sheet	(4,918)	(7,809)
Current Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset	39	1,570
Gross Amounts Offset	(39)	(1,570)
Net Amount presented - Balance Sheet	0	0
Long Term Asset [Member]
Assets
Derivative Asset, Fair Value, Gross Asset		406
Gross Amounts Offset		(406)
Net Amount presented - Balance Sheet		0
Current Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(3,890)	(1,836)
Gross Amount Deferred premium	(401)	(5,048)
Gross Amounts Offset	(362)	(3,478)
Deferred Premium Offset	401	5,048
Net Amount presented - Balance Sheet	(4,252)	(5,314)
Deferred Premium	0	0
Long Term Liability [Member]
Liabilities
Gross Amounts of Recognized Liabilities	(666)	(2,500)
Gross Amount Deferred premium		(401)
Gross Amounts Offset	0	5
Deferred Premium Offset		401
Net Amount presented - Balance Sheet	$ (666)	(2,495)
Deferred Premium		$ 0

Derivative Financial Instrume53

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Net settlements on matured derivatives	[1]	$ (369)	$ 20,511
Net settlements on early terminations of derivatives	[1]	582	5,820
Net change in fair value of derivatives		(2,158)	(38,533)
Total loss on derivatives, net		$ (1,945)	$ (12,202)
[1]	The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.

Derivative Financial Instrume54

Derivative Financial Instruments - Commodity Contracts (Details) - $ / bbl	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Swap | Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	51.33
Total Bbls Hedged/day	444
Derivative, Underlying Basis	WTI
Swap | Period Covered-2019 [Member]
Derivative [Line Items]
Weighted Average Fixed Price	51.48
Total Bbls Hedged/day	427
Derivative, Underlying Basis	WTI
Collar [Member] | Period Covered-2017 [Member]
Derivative [Line Items]
Weighted Average Floor Price		43.75
Weighted Average Ceiling Price		50.68
Total Bbls Hedged/day		658
Derivative, Underlying Basis		WTI
Collar [Member] | Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Floor Price	44.38	44.38
Weighted Average Ceiling Price	55.52	55.52
Total Bbls Hedged/day	1,315	1,315
Derivative, Underlying Basis	WTI	WTI
Collar [Member] | Period Covered-2019 [Member]
Derivative [Line Items]
Weighted Average Floor Price		50
Weighted Average Ceiling Price		60.52
Total Bbls Hedged/day		427
Derivative, Underlying Basis		WTI
Put Option [Member] | Period Covered-2017 [Member]
Derivative [Line Items]
Weighted Average Floor Price		50
Total Bbls Hedged/day		1,932
Derivative, Underlying Basis		WTI
Put Option [Member] | Period Covered-2018 [Member]
Derivative [Line Items]
Weighted Average Floor Price	45	45
Total Bbls Hedged/day	164	164
Derivative, Underlying Basis	WTI	WTI

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis and Nonrecurring Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	$ 0	$ 0
Derivative financial instruments - liability	4,918	7,809
Fair Value [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	39	1,976
Derivative financial instruments - liability	4,556	4,336
Derivative deferred premiums - liability	401	5,449
Level 1 [Member] | Fair Value [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	0	0
Level 2 [Member] | Fair Value [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	39	1,976
Derivative financial instruments - liability	4,556	4,336
Derivative deferred premiums - liability	0	0
Level 3 [Member] | Fair Value [Member] | Assets and Liabilities Measured at Fair Value on a Recurring Basis [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments - asset	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	$ 401	$ 5,449

Fair Value Disclosures - Summar

Fair Value Disclosures - Summary of Changes in assets (liabilities) - Level 3 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance of Level 3 at beginning of period	$ (5,449)	$ (9,973)
Derivative deferred premiums - purchases	0	(516)
Derivative deferred premiums - settlements	5,048	5,040
Balance of Level 3 at end of period	$ (401)	$ (5,449)

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Inputs, Discount Rate	10.00%
Impairment expense	$ 24,746	$ 895
Impairment of proved oil and natural gas properties held for sale	$ 296	$ 3,578

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation [Roll Forward]
Asset retirement obligations - beginning of period	$ 11,331	$ 12,679
Liabilities incurred for new wells and interest	759	747
Liabilities settled upon plugging and abandoning wells	(57)	0
Liabilities removed upon sale of wells	(2,152)	(2,827)
Revision of estimates	(75)	155
Accretion expense	520	577
Asset retirement obligations - end of period	$ 10,326	$ 11,331

Debt - Additional Information (

Debt - Additional Information (Details) - Revolving Credit Facility [Member] - USD ($)	Jan. 31, 2018	May 31, 2016	May 31, 2016	Dec. 31, 2017	Dec. 22, 2017	May 24, 2017	Dec. 31, 2016	Oct. 28, 2016	Aug. 11, 2016	Jul. 28, 2016
Line of Credit Facility Line Items
Revolving credit facility				$ 99,000,000			$ 122,000,000
Average effective rate				3.99%
Line of credit facility, maximum borrowing capacity		$ 163,000,000	$ 163,000,000		$ 115,000,000	$ 140,000,000		$ 140,000,000	$ 140,000,000	$ 105,000,000
Line of credit over advance		$ 53,000,000	53,000,000
Required monthly principal payments			$ 1,900,000
Percentage of collateral coverage of proved reserves		90.00%	95.00%
Percentage of PDP reserves		100.00%
Line of credit facility, Current borrowing capacity					$ 100,000,000
Subsequent Event [Member]
Line of Credit Facility Line Items
Line of credit facility, maximum borrowing capacity	$ 125,000,000
Minimum liquidity percentage for distributions to the preferred unit holders	20.00%
Revolving Credit Facility, Conforming Tranche [Member]
Line of Credit Facility Line Items
Line of credit facility, maximum borrowing capacity		$ 110,000,000	$ 110,000,000
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
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate				1.00%
Unused portion of borrowing base, percentage fee				0.375%
Minimum | LIBOR [Member]
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate				2.00%
Maximum
Line of Credit Facility Line Items
Debt instrument, percentage points added to reference rate				2.75%
Unused portion of borrowing base, percentage fee				0.50%
Maximum | 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, 2017	Dec. 31, 2016
Commitments Contingencies And Litigation [Line Items]
Lease expense	$ 0.3	$ 0.4
Minimum
Commitments Contingencies And Litigation [Line Items]
Employee Termination Expenses	0.3
Maximum
Commitments Contingencies And Litigation [Line Items]
Employee Termination Expenses	$ 0.6

Commitment and Contingencies 61

Commitment and Contingencies - Operating Leases (Details) $ in Thousands	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
2,018	$ 489
2,019	413
2,020	418
2,021	423
Total	$ 1,743

Equity - Additional Information

Equity - Additional Information (Details) - USD ($)	May 05, 2015	Dec. 31, 2017	Dec. 31, 2016
Class of Stock [Line Items]
Limited partners, units outstanding		30,090,463	29,912,230
Limited partnership interest		98.80%
Maximum proceeds under equity distribution agreement - suspended	$ 50,000,000
Limited partners, Common unit distributions		30,090,463	29,912,230
Common Units [Member]
Class of Stock [Line Items]
Limited partners, Common unit distributions		0	0

Equity - Preferred Units - Addi

Equity - Preferred Units - Additional Information (Details) $ / shares in Units, $ in Thousands	Aug. 11, 2016USD ($)$ / sharesshares	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Class of Stock [Line Items]
Proceeds from sale of Class A convertible preferred units, net of offering costs			$ 24,646
Allocation of value to beneficial conversion feature of Class A convertible preferred units			6,047
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 Class A convertible preferred units, net of offering costs	$ 24,600
Issuance costs	400
Net proceeds allocated, fair value basis, to Preferred Units	18,600
Allocation of value to beneficial conversion feature of Class A convertible preferred units	$ 6,000
Accretion period for beneficial conversion		5 years
Accretion of beneficial conversion		$ 1,100	$ 500
Days after quarter end distribution paid	45 days
Preferred units distribution accrued		$ 1,000
Conversion period	5 years
Class A Preferred Units [Member] | Cash Dividends [Member]
Class of Stock [Line Items]
Dividend rate (percentage)	8.00%
Class A Preferred Units [Member] | In Kind Dividends [Member]
Class of Stock [Line Items]
Dividend rate (percentage)	10.00%
Class A Preferred Units [Member] | Preferred Units [Member]
Class of Stock [Line Items]
Conversion ratio		1

Equity - Cash Distributions Pre

Equity - Cash Distributions Preferred Unitholders (Details) - Class A Preferred Units [Member] - USD ($) $ / shares in Units, $ in Thousands	2 Months Ended	3 Months Ended
	Sep. 30, 2016	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016
Preferred Units [Line Items]
Date Paid	Nov. 14, 2016	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017
Distribution per Unit	$ 0.024	$ 0.043	$ 0.043	$ 0.043
Total Distributions	$ 279	$ 500	$ 500	$ 500

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, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Services agreement	$ 2,443	$ 3,403
Operating agreements	6,509	6,221
Oilfield services	3,377	3,058
Costs and expenses, Related Party	$ 12,329	$ 12,682

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - Mid-Con Energy Operating [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Other transactions of related party	$ 1.6	$ 3.4
Joint interest billing payable	1.4	2.8
Operating services payable	$ 0.2	$ 0.6

Credit Risk - Additional Inform

Credit Risk - Additional Information (Detail) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Sales Revenue, Net [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	99.00%	94.00%
Accounts Receivable [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	98.00%	95.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Details) - USD ($)

Feb. 14, 2018

Jan. 31, 2018

Jan. 16, 2018

Aug. 11, 2016

Sep. 30, 2016

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2016

Dec. 31, 2017

Mar. 31, 2018

Jan. 09, 2018

Dec. 22, 2017

May 24, 2017

Oct. 28, 2016

Jul. 28, 2016

May 31, 2016

Subsequent Event [Line Items]

Class B Preferred Units into common units

one-for-one

Class A Preferred Units [Member]

Subsequent Event [Line Items]

Preferred Units, Issued

11,627,906

Proceeds from sale of convertible preferred units, gross

$ 25,000,000

Distribution per Unit

$ 0.024

$ 0.043

$ 0.043

$ 0.043

Class A Preferred Units [Member] | Cash Dividends [Member]

Subsequent Event [Line Items]

Dividend rate (percentage)

8.00%

Revolving Credit Facility [Member]

Subsequent Event [Line Items]

Line of credit facility, maximum borrowing capacity

$ 140,000,000

$ 115,000,000

$ 140,000,000

$ 140,000,000

$ 105,000,000

$ 163,000,000

Subsequent Event [Member] | Unrestricted Common Units [Member]

Subsequent Event [Line Items]

Units authorized

87,832

Subsequent Event [Member] | Equity-Settled Phantom Units [Member]

Subsequent Event [Line Items]

Units authorized

389,500

Subsequent Event [Member] | Class B Preferred Units [Member] | Private Placement [Member]

Subsequent Event [Line Items]

Preferred Units, Issued

9,803,921

Proceeds from sale of convertible preferred units, gross

$ 15,000,000

Price per share for preferred units

$ 1.53

Subsequent Event [Member] | Class B Preferred Units [Member] | Cash Dividends [Member]

Subsequent Event [Line Items]

Dividend rate (percentage)

8.00%

Subsequent Event [Member] | Class B Preferred Units [Member] | Additional Preferred Units [Member]

Subsequent Event [Line Items]

Dividend rate (percentage)

10.00%

Subsequent Event [Member] | Class A Preferred Units [Member]

Subsequent Event [Line Items]

Distribution per Unit

$ 0.086

Preferred Units Distributions Declared

$ 1,000,000

Subsequent Event [Member] | Revolving Credit Facility [Member]

Subsequent Event [Line Items]

Line of credit facility, maximum borrowing capacity

$ 125,000,000

Minimum liquidity percentage for distributions to the preferred unit holders

20.00%

Subsequent Event [Member] | House Creek [Member]

Subsequent Event [Line Items]

Aggregate purchase price, net

$ 1,500,000

Effective date of the acquisition

Sep. 1, 2017

Subsequent Event [Member] | Pine Tree [Member]

Subsequent Event [Line Items]

Aggregate purchase price, net

$ 8,600,000

Effective date of the acquisition

Sep. 1, 2017

Subsequent Event [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Nolan County [Member]

Subsequent Event [Line Items]

Aggregate sale price

$ 1,600,000

Supplementary Information - Sup

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property acquisition costs:
Proved	$ 4,665	$ 18,722
Unproved	369	0
Exploration	0	0
Development	9,947	6,963
Asset retirement obligations	684	902
Total costs incurred	$ 15,665	$ 26,587

Supplementary Information - Cha

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)		12 Months Ended
		Dec. 31, 2017MBoeMBblsMMcf		Dec. 31, 2016MBoeMBblsMMcf
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Beginning balance | MBoe		19,231		22,252
Revisions of previous estimates | MBoe	[1]	2,383		14
Extensions, discoveries and other additions | MBoe	[2]	69
Purchases of reserves in place | MBoe		1,684	[3]	1,552	[4]
Sales of reserves in place | MBoe		(2,529)	[5]	(3,109)	[6]
Production | MBoe		(1,281)		(1,478)
Ending balance | MBoe		19,557		19,231
Proved developed reserves, MBoe | MBoe		14,276		12,423
Proved developed reserves, MBoe | MBoe		5,281		6,808
Oil
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]
Beginning balance | MBbls		18,210		21,114
Revisions of previous estimates | MBbls	[1]	2,355		58
Extensions, discoveries and other additions | MBbls	[2]	69
Purchases of reserves in place | MBbls		1,607	[3]	1,517	[4]
Sales of reserves in place | MBbls		(2,522)	[5]	(3,093)	[6]
Production | MBbls		(1,209)		(1,386)
Ending balance | MBbls		18,510		18,210
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Proved developed reserves, Oil | MBbls		13,512		11,733
Proved undeveloped reserves, Oil | MBbls		4,998		6,477
Natural Gas
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Proved developed reserves, Gas | MMcf		4,586		4,141
Proved developed reserves, Gas | MMcf		1,696		1,983
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Beginning balance | MMcf		6,124		6,827
Revisions of previous estimates | MMcf	[1]	168		(262)
Purchases of reserves in place | MMcf		459	[3]	211	[4]
Sales of reserves in place | MMcf		(38)	[5]	(98)	[6]
Production | MMcf		(431)		(554)
Ending balance | MMcf		6,282		6,124
[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 two successful step out wells in 2017.
[3]	Represents the purchase of proved reserves as part of our Oklahoma Wheatland acquisition.
[4]	Represents the purchase of proved reserves as part of our Permian Bolt-On acquisition.
[5]	Decrease due to the sale of our Southern Oklahoma oil and natural gas properties.
[6]	Decrease due to the sale of our Hugoton oil and natural gas properties.

Supplementary Information - Add

Supplementary Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2017MBoe$ / bbl$ / MMBTU$ / Mcf		Dec. 31, 2016MBoe$ / 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	1,309		(1,801)
Proved Developed and Undeveloped Reserves, Improved Recovery	69		569
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate	1,074		1,246
Sales of reserves in place	2,529	[1]	3,109	[2]
Purchases of reserves in place	1,684	[3]	1,552	[4]
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	51.34		42.75
Average adjusted prices utilized in calculating proved reserves | $ / bbl	49.34		40.03
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Representative SEC Price | $ / MMBTU	2.98		2.49
Average adjusted prices utilized in calculating proved reserves | $ / Mcf	2.27		1.99
[1]	Decrease due to the sale of our Southern Oklahoma oil and natural gas properties.
[2]	Decrease due to the sale of our Hugoton oil and natural gas properties.
[3]	Represents the purchase of proved reserves as part of our Oklahoma Wheatland acquisition.
[4]	Represents the purchase of proved reserves as part of our Permian Bolt-On 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, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Future cash inflows	$ 927,473	$ 741,077
Future production costs	(444,673)	(389,138)
Future development costs, including abandonment costs	(50,868)	(65,195)
Future net cash flow	431,932	286,744
10% discount for estimated timing of cash flow	(224,719)	(129,459)
Standardized measure of discounted cash flow	$ 207,213	$ 157,285	$ 191,420

Supplementary Information - C73

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, 2017	Dec. 31, 2016
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	$ 157,285	$ 191,420
Changes in the year resulting from:
Sales, less production costs	(33,994)	(30,513)
Revisions of previous quantity estimates	28,132	133
Extensions, discoveries and improved recovery	3,168	0
Net change in prices and production costs	61,504	(16,138)
Net change in income taxes	0	0
Changes in estimated future development costs	5,173	22,685
Previously estimated development costs incurred during the year	9,726	3,526
Purchases of reserves in place	13,826	22,223
Sales of reserves in place	(10,420)	(11,124)
Accretion of discount	15,729	19,142
Timing differences and other	(42,916)	(44,069)
Standardized measure of discounted future net cash flow, end of year	$ 207,213	$ 157,285