Mid-Con Energy Partners (MCEP) 10-K 28 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Feb. 28, 2017	Jun. 30, 2016
Entity Information [Line Items]
Entity Registrant Name	Mid-Con Energy Partners, LP
Entity Central Index Key	1,527,709
Current Fiscal Year End Date	--12-31
Entity Filer Category	Smaller Reporting Company
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	MCEP
Amendment Flag	false
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Common Stock, Shares Outstanding		30,000,127
Entity Public Float			$ 45.7
General Partner Units
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		360,000

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 2,359	$ 615
Accounts receivable:
Oil and natural gas sales	5,302	4,551
Other	233	5,009
Derivative financial instruments, Current	0	24,419
Prepaids and other	662	623
Total current assets	8,556	35,217
Oil and natural gas properties, successful efforts method:
Proved properties	441,479	518,916
Other property and equipment	289	0
Accumulated depletion, depreciation, amortization and impairment	(176,551)	(232,008)
Total property and equipment, net	265,217	286,908
Derivative financial instruments, Non-current	0	1,144
Other assets	2,513	3,817
Total assets	276,286	327,086
Accounts payable:
Trade	2,554	3,185
Related parties	1,133	559
Derivative financial instruments, Current	5,314	0
Accrued liabilities	146	165
Current maturities of long-term debt	0	30,000
Total current liabilities	9,147	33,909
Derivative financial instruments, Non-current	2,495	0
Other long-term liabilities	93	0
Long-term debt	122,000	150,000
Asset retirement obligations	11,331	12,679
Commitments and contingencies
Class A convertible preferred units - 11,627,906 and 0 issued and outstanding, respectively	19,570	0
Partnership equity:
General partner interest	(248)	47
Limited partners - 29,912,230 and 29,724,890 units issued and outstanding, respectively	111,898	130,451
Total equity	111,650	130,498
Total liabilities, convertible preferred units and equity	$ 276,286	$ 327,086

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Limited partners, units issued	29,912,230	29,724,890
Limited partners, units outstanding	29,912,230	29,724,890
Preferred Units [Member]
Class of Stock [Line Items]
Class A Convertible Preferred Units, shares issued	11,627,906	0
Class A Convertible Preferred Units, shares outstanding	11,627,906	0

Consolidated Statements of Oper

Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Revenues:
Oil sales	$ 54,773	$ 72,520	$ 96,127
Natural gas sales	1,325	1,394	784
(Loss) gain on derivatives, net	(12,202)	22,366	29,361
Total revenues	43,896	96,280	126,272
Operating costs and expenses:
Lease operating expenses	22,692	33,591	26,091
Oil and natural gas production taxes	2,893	3,487	6,325
Impairment of proved oil and natural gas properties	895	103,938	30,206
Impairment of proved oil and natural gas properties sold	3,578	0	0
Depreciation, depletion and amortization	23,074	34,174	21,877
Accretion of discount on asset retirement obligations	577	432	250
General and administrative	6,890	9,411	14,313
Total operating costs and expenses	60,599	185,033	99,062
Loss on sales of oil and natural gas properties, net	(560)	0	0
(Loss) income from operations	(17,263)	(88,753)	27,210
Other income (expense):
Interest income	12	11	13
Interest expense	(7,487)	(7,258)	(4,731)
Other (expense) income	(76)	547	0
Loss on settlement of ARO	0	(42)	0
Total other expense	(7,551)	(6,742)	(4,718)
Net (loss) income	(24,814)	(95,495)	22,492
Less: Distributions to preferred unitholders	1,249	0	0
Less: General partner's interest in net (loss) income	(295)	(1,146)	354
Limited partners' interest in net (loss) income	$ (25,768)	$ (94,349)	$ 22,138
Net (loss) income per limited partner unit:
Basic (in dollars per share)	$ (0.86)	$ (3.18)	$ 0.98
Diluted (in dollars per share)	$ (0.86)	$ (3.18)	$ 0.98
Weighted average limited partner units outstanding:
Limited partner units (basic)	29,834	29,642	22,499
Limited partner units (diluted)	29,834	29,642	22,518

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flows from Operating Activities:
Net (loss) income	$ (24,814)	$ (95,495)	$ 22,492
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation, depletion and amortization	23,074	34,174	21,877
Debt issuance costs amortization	1,372	1,156	348
Accretion of discount on asset retirement obligations	577	432	250
Impairment of proved oil and natural gas properties	895	103,938	30,206
Impairment of proved oil and natural gas properties sold	3,578	0	0
Loss on settlement of ARO	0	42	0
Cash paid for settlements of ARO	0	(82)	0
Loss (gain) on derivatives, net	12,202	(22,366)	(29,361)
Cash settlements received for matured derivatives	20,511	28,543	891
Cash settlements received for early terminations and modifications of derivatives, net	5,820	11,069	0
Cash premiums paid for derivatives, net	(5,161)	(15,765)	0
Loss on sales of oil and natural gas properties, net	560	0	0
Non-cash equity-based compensation	1,184	3,204	7,394
Changes in operating assets and liabilities:
Accounts receivable	(751)	3,500	(1,273)
Other receivables	4,935	(566)	(3,966)
Prepaids and other	(39)	29	(461)
Accounts payable and accrued liabilities	(7)	(3,388)	2,067
Net cash provided by operating activities	43,936	48,425	50,464
Cash Flows from Investing Activities:
Additions to oil and natural gas properties	(7,223)	(13,893)	(33,969)
Additions to other property and equipment	(165)	0	0
Acquisitions of oil and natural gas properties	(18,722)	(1)	(155,354)
Proceeds from sales of oil and natural gas properties	17,635	0	0
Net cash used in investing activities	(8,475)	(13,894)	(189,323)
Cash Flows from Financing Activities:
Proceeds from line of credit	0	28,000	168,000
Payments on line of credit	(58,000)	(53,000)	(75,000)
Issuance of common units	0	0	96,010
Offering costs	(16)	(194)	0
Distributions to common units	0	(11,266)	(44,564)
Debt issuance costs	(68)	(688)	(3,789)
Proceeds from sale of convertible preferred units, net of offering costs	24,646	0	0
Distributions to preferred units	(279)	0	0
Net cash (used in) provided by financing activities	(33,717)	(37,148)	140,657
Net increase (decrease) in cash and cash equivalents	1,744	(2,617)	1,798
Beginning cash and cash equivalents	615	3,232	1,434
Ending cash and cash equivalents	$ 2,359	$ 615	$ 3,232

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Thousands	Total	General Partner	Limited Partner
Balance at Dec. 31, 2013	$ 66,788	$ 1,716	$ 65,072
Balance, units at Dec. 31, 2013			19,319
Equity-based compensation	7,415		$ 7,415
Equity-based compensation, Units			332
Offering costs	0
Issuance of limited partner units - acquisitions	86,001		$ 86,001
Issuance of limited partner units - acquisitions, Units			3,715
Issuance of limited partner units, net of offering costs	96,010		$ 96,010
Issuance of limited partner units, net of offering costs, Units			5,800
Distributions to common units	(44,564)	(742)	$ (43,822)
Net (loss) income	22,492	354	22,138
Balance at Dec. 31, 2014	234,142	1,328	$ 232,814
Balance, Units at Dec. 31, 2014			29,166
Equity-based compensation	3,311		$ 3,311
Equity-based compensation, Units			559
Offering costs	(194)		$ (194)
Issuance of limited partner units, net of offering costs	0
Distributions to common units	(11,266)	(135)	(11,131)
Net (loss) income	(95,495)	(1,146)	(94,349)
Balance at Dec. 31, 2015	130,498	47	$ 130,451
Balance, Units at Dec. 31, 2015			29,725
Equity-based compensation	1,184		$ 1,184
Equity-based compensation, Units			187
Offering costs	(16)		$ (16)
Issuance of limited partner units, net of offering costs	0
Distributions to 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) income	(24,814)	(295)	(24,519)
Balance at Dec. 31, 2016	$ 111,650	$ (248)	$ 111,898
Balance, Units at Dec. 31, 2016			29,912

Organization and Nature of Oper

Organization and Nature of Operations	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Nature of Operations	Organization and Nature of Operations Nature of Operations Mid-Con Energy Partners, LP is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on EOR. Our limited partner units ("common units") are listed on the NASDAQ Global Select Market under the symbol "MCEP." Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Reclassifications The consolidated statements of operations for previous periods include certain reclassifications to the other income (expense) accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss). Non-cash Investing, Financing and Supplemental Cash Flow Information The following presents the non-cash investing, financing and supplemental cash flow information for the periods presented: Year Ended December 31, 2016 2015 2014 (in thousands) Non-cash investing and financing information: Change in oil and natural gas properties - accrued capital expenditures $ (259 ) $ (560 ) $ 351 Tenant improvement allowance deferred - other property and equipment $ 124 $ — $ — Cash paid for interest $ 6,198 $ 6,070 $ 4,600 Common units issued - acquisition of oil properties $ — $ — $ 86,001

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	Summary of Significant Accounting Policies Basis of presentation and principles of consolidation The accompanying financial statements and related notes present our consolidated financial position as of December 31, 2016 and 2015. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2016, 2015 and 2014. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our subsidiary is Mid-Con Energy Properties. All intercompany transactions and account balances have been eliminated. We aggregate all of our oil and natural gas properties into one business segment engaged in the exploitation, development and production of oil and natural gas properties. Use of estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, in part, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, ARO, fair value of assets acquired and liabilities assumed in business combinations and fair value of derivative financial instruments. Cash and cash equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents. Accounts receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2016 and 2015, 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, 2016 or 2015. 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 exploitation 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. Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned. Costs of significant non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We had no significant costs excluded from depreciation during any of the periods presented. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value may be greater than management's estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimate quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. We review our oil and natural gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base. These evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. Cash flow estimates for the impairment testing excludes derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices. We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future 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. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability. See Note 7 for additional information. Derivatives and hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices and specific delivery points. 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. Compensation expense for awards is recorded upon vesting, based on their grant-date fair value, net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. No compensation expense is recognized for equity instruments that do not vest. Debt issuance costs Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations 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, we write off any remaining issuance costs associated with that debt. Income taxes We are a partnership that is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, our taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities. Allocation of Net Income (Loss) Net income (loss), net of distributions on the Preferred Units and amortization of the preferred unit beneficial conversion feature, is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership during the period. The allocation of net income (loss) is presented in our consolidated statements of operations. Diluted net income (loss) per partner unit reflects the potential dilution of non-vested restricted stock awards. For the years ended December 31, 2016, and 2015, this potentially dilutive item was anti-dilutive due to the Partnership's net loss and, therefore, was excluded from the calculation of diluted net income (loss) per partner unit. Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We plan to adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, as an adjustment to opening retained earnings. We do not expect our revenue recognition under the new guidance to materially differ from our current revenue recognition practice. We do not expect the cumulative effect adjustment to opening retained earnings to be significant. In February 2016, the FASB issued ASU No. 2016-02, " Leases (Topic 842)," which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. As of December 31, 2016, the Partnership has not elected early adoption. We believe the primary impact of adopting this standard will be the recognition of assets and liabilities on our balance sheet for current operating leases. We are still evaluating the impact of this standard. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting. The guidance simplifies the accounting for employee stock-based payment transactions including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification of awards as either equity or liabilities, and classification of related amounts within the statement of cash flows. The guidance requires the recognition of the income tax effects of awards in the income statement when the awards vest or are settled, thus eliminating additional paid in capital pools. The guidance also allows for the employer to repurchase more of an employee's shares for tax withholding purposes without triggering liability accounting. In addition, the guidance allows for a policy election to account for forfeitures as they occur rather than on an estimated basis. The guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and early adoption is permitted. As of December 31, 2016, the Partnership has not elected early adoption. Based on our initial evaluation, we do not anticipate a material impact to our consolidated financial statements upon adoption of this standard. In August, 2016, the FASB issued Accounting Standards Update No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption during an interim period. Based on our initial evaluation, we do not anticipate a material impact to our consolidated financial statements upon adoption of this standard.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisitions	Acquisitions and Divestitures Permian Bolt-On Acquisition On August 11, 2016, we acquired multiple oil and natural gas properties located in Nolan County, Texas for cash consideration of approximately $18.7 million , after estimated post-closing purchase price adjustments. The Permian Bolt-On acquisition was accounted for under the acquisition method of accounting. The assets acquired and liabilities assumed in the acquisition were recorded in our consolidated balance sheets at their estimated fair values as of the acquisition date using assumptions that represent Level 3 fair value measurement inputs. The estimated fair values as of the acquisition date were based on a reserve report prepared by our reservoir engineering staff and audited by CG&A. See Note 6 in this section for additional discussion of our fair value measurements. The results of operations of the acquired properties have been included in our consolidated financial statements since the acquisition closed on August 11, 2016. The consolidated statement of operations for the year ended December 31, 2016, includes revenues of approximately $2.7 million and lease operating expenses of approximately $0.6 million . The transaction was funded by a private offering of $25.0 million Preferred Units. See Note 10 in this section for additional information regarding the issuance of Preferred Units. The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands): Fair value of net assets: Oil and natural gas properties $ 19,323 Total assets acquired 19,323 Fair value of net liabilities assumed: Asset retirement obligation 622 Net assets acquired $ 18,701 Hugoton Core Area Divestiture On July 28, 2016, we sold our properties located in our Hugoton core area for cash proceeds of approximately $17.6 million , including post-closing adjustments. We recognized a loss of approximately $0.6 million which is included as "Loss on sales of oil and natural gas properties, net" in our consolidated statements of operations. Additionally, we recorded impairment of proved oil and natural gas properties of approximately $3.6 million of that was recorded 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, 2016 2015 2014 (in thousands) Oil and natural gas sales $ 3,602 $ 11,744 $ 23,708 Expenses (1) $ 7,717 $ 51,505 $ 43,384 (1) Expenses include lease operating expenses, production taxes, accretion, depletion and impairment expenses. Effective at closing, the operations and cash flows of these properties were eliminated from the ongoing operations of the Partnership and the Partnership has no continuing involvement in these properties. This divestiture does not represent a strategic shift and will not have a major effect on the Partnership's operations or financial results.

Equity Awards

Equity Awards	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity Awards	Equity Awards We have a long-term incentive program (the "Long-Term Incentive Program") for employees, officers, consultants and directors of our general partner and its affiliates, including Mid-Con Energy Operating 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 the controlling members of our general partner, Charles R. Olmstead, Executive Chairman of the Board, and Jeffrey R. Olmstead, Chief Executive Officer, and approved by the Board of Directors of the general partner. If an employee terminates employment prior to the restriction lapse date, the awarded units are forfeited and canceled and are no longer considered issued and outstanding. On November 20, 2015, the Board of Directors of the general partner recommended, and the common unitholders approved, an amendment to the Long-Term Incentive Program that increased the number of common units available for issuance from 1,764,000 to 3,514,000 . The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2016: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,187,306 ) Restricted units granted, net of forfeitures (400,424 ) Equity-settled phantom units granted, net of forfeitures (457,500 ) Awards available for future grant 1,468,770 We recognized approximately $1.2 million , $3.2 million and $7.7 million of total equity-based compensation expense for the years ended December 31, 2016, 2015 and 2014, respectively. These costs are reported as a component of general and administrative expense in our consolidated statements of operations. Unrestricted unit awards We account for unrestricted awards as equity awards since they are settled by issuing common units. During the year ended December 31, 2016, we granted 73,932 unrestricted units with an average grant date fair value of $1.20 per unit. During the year ended December 31, 2015, we granted 274,550 unrestricted units with an average grant date fair value of $4.85 per unit. Restricted unit awards We account for restricted awards as equity awards since they will be settled by issuing common units. These units vest over a two -or three -year period. The compensation expense we recognize associated with our restricted units is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. We did not issue any restricted units during the year ended December 31, 2016. During the year ended December 31, 2015, we granted 268,000 restricted units with one-third vesting immediately and the other two-thirds vesting over two years, and 26,100 restricted units with a three -year vesting period. As of December 31, 2016, there were approximately $0.1 million of unrecognized compensation costs related to non-vested restricted units. These costs are expected to be recognized over a weighted average period of approximately eight months . A summary of our restricted unit awards for the years ended December 31, 2016, and 2015 is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 109,800 $ 23.28 Units granted 294,100 5.04 Units vested (148,195 ) 12.43 Units forfeited (32,872 ) 9.28 Outstanding at December 31, 2015 222,833 $ 8.49 Units granted — — Units vested (112,478 ) 9.16 Units forfeited (33,433 ) 9.69 Outstanding at December 31, 2016 76,922 $ 5.67 Equity-settled phantom unit awards We account for equity-settled phantom awards as equity awards since they will be settled by issuing common units. These units vest over a two or three year period and do not have any rights or privileges of a common unitholder, including the right to distributions, until vesting and the resulting conversion into common units. The compensation expense we recognize associated with our equity-settled phantom units is net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. During the 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. During the year ended December 31, 2015, we granted 69,000 equity-settled phantom units with one-third vesting immediately and the other two-thirds vesting over two years and 46,500 equity-settled phantom units with a three -year vesting period. As of December 31, 2016, there were approximately $0.3 million of unrecognized compensation costs related to equity-settled phantom units. These costs are expected to be recognized over a weighted average period of approximately one year, six months . A summary of our equity-settled phantom unit awards for the years ended December 31, 2016, and 2015 is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 — $ — Units granted 115,500 2.87 Units vested (23,000 ) 3.12 Units forfeited (15,000 ) 2.81 Outstanding at December 31, 2015 77,500 2.81 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

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial Instruments	Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivative contracts (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices and specific delivery points. The commodity derivative contracts that we have entered into generally have the effect of providing us with a fixed price or a floor for a portion of our expected future oil production over a fixed period of time. We enter into commodity derivative contracts or modify our portfolio of existing commodity derivative contracts when we believe market conditions or other circumstances suggest that it is prudent to do so, or as required by our lenders. These contracts are presented as derivative financial instruments on our consolidated financial statements. We account for our commodity derivative contracts at fair value. See Note 6 in this section for a description of our fair value measurements. At December 31, 2016, our commodity derivative contracts were in a net liability position with a fair value of approximately $7.8 million and at December 31, 2015, a net asset position with a fair value of approximately $25.6 million. All of our commodity derivative contracts are with major financial institutions that are also members of our banking group. Should one of these financial counterparties not perform, we may not realize the benefit of some of our commodity derivative contracts under lower commodity prices and we could incur a loss. During the three years ended December 31, 2016, all of our counterparties have performed pursuant to their commodity derivative contracts. At December 31, 2016, and 2015, our commodity derivative contracts had maturities at various dates through December 2019 and December 2017, respectively, and were comprised of commodity price swaps, call, put and collar contracts. For commodity price swap contracts, at the time of execution the seller agrees to receive a fixed price at maturity in exchange for any gains or losses that might be realized from allowing the price of the underlying commodity to float with the market until maturity. From the perspective of the seller, these instruments limit exposure to price declines below the price fixed by the swap at the expense of participating in any price increases above the price fixed by the swap. For commodity price call contracts, in return for a premium received, which can be effected at either execution or settlement, the seller is obliged to pay the difference, when positive, between the market price of the underlying commodity at maturity less the strike price. From the perspective of the seller, these instruments provide income via the premium received at the expense of any incremental gains that would have otherwise been received above the strike price. For commodity price put contracts, in return for a premium paid, which can be effected at either execution or settlement, the purchaser has the right to receive the difference, when positive, between the strike price and the market price of the underlying commodity at maturity. From the perspective of the purchaser, these instruments limit exposure to price declines below the strike price at the expense of premiums paid. For commodity price collar contracts, a collar is the combination of a put purchased or sold by a party and a call option sold or purchased by the same party. The collar is defined as costless when the value of the option purchased is approximately offset by the value of the option sold. We do not designate derivatives as hedges for accounting purposes; therefore, the mark-to-market adjustment reflecting the change in the fair value of our commodity derivative contracts is recorded in current period earnings. When prices for oil are volatile, a significant portion of the effect of our hedging activities consists of non-cash gains or losses due to changes in the fair value of our commodity derivative contracts. In addition to mark-to-market adjustments, gains or losses arise from net payments made or received on monthly settlements, proceeds 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, 2016, we had the following oil derivatives net positions: Period Covered Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls 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 At December 31, 2015, we had the following oil derivatives net positions: Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2016 $ 79.98 1,598 WTI Collars - 2016 $ 50.00 $ 50.00 328 WTI Puts - 2016 $ 50.00 $ — 1,475 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI During the first quarter of 2015, we restructured a significant portion of our existing commodity derivative contracts that were in place at December 31, 2014 and entered into new commodity derivative contracts which extended through September 2016. In connection with the early termination of our commodity derivative contracts, we received net proceeds of approximately $11.1 million . We received approximately $5.9 million from selling calls and paid approximately $19.8 million in premiums to extend and enhance the contracts through September 2016. The restructuring also resulted in approximately $4.1 million of deferred premium put options which have been paid as of December 31, 2016. In connection with the fall 2015 semi-annual redetermination of our borrowing base, we entered into additional commodity derivative contracts covering at least 80% of our 2016 projected monthly production and at least 50% of our 2017 projected monthly production, calculated based on Proved Developed Producing reserves. No cash settlements were required and the contracts included deferred premiums of approximately $7.8 million that will be paid through December 2017. As of December 31, 2016, we had paid approximately $2.9 million of the deferred premiums in connection with these contract settlements. In connection with the spring 2016 semi-annual redetermination of our borrowing base, we unwound and early terminated existing hedges covering production from July 2016 through September 2016 and entered into new commodity derivative contracts which extend through June 2018. In connection with the early termination of our commodity derivative contracts, we received proceeds of approximately $5.8 million and paid related deferred premiums of approximately $1.5 million. In connection with the non-scheduled redetermination of our borrowing base and Amendment No.10 to our credit agreement executed in August 2016, we entered into new commodity derivative contracts covering at least 75% of our 2017 projected monthly production and at least 50% of our 2018 projected monthly production, calculated based on Proved Developed Producing reserves. The new contracts extend through December 2018. No cash settlements were required and the contracts included deferred premiums of approximately $0.4 million that will be paid July 2018 through December 2018. During the fourth quarter of 2016, we entered into commodity derivative contracts covering production from April 2017 through December 2019. In connection with the new commodity derivative contracts, we paid approximately $0.1 million in premiums at inception and deferred approximately $0.1 million of premiums that will be paid from April 2017 through December 2017. 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, 2016 and 2015 : Gross Gross Amounts Net Amounts (in thousands) 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 ) Gross Gross Amounts Net Amounts (in thousands) December 31, 2015 Assets Derivative financial instruments - current asset $ 29,973 $ (5,554 ) $ 24,419 Derivative financial instruments - long-term asset 6,077 (4,933 ) 1,144 Total 36,050 (10,487 ) 25,563 Liabilities Derivative financial instruments - current liability (514 ) 514 — Derivative deferred premium - current liability (5,040 ) 5,040 — Derivative deferred premium - long-term liability (4,933 ) 4,933 — Total (10,487 ) 10,487 — Net Asset $ 25,563 $ — $ 25,563 The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations: Year Ended December 31, 2016 2015 2014 (in thousands) Net settlements on matured derivatives (1) $ 20,511 $ 28,543 $ 891 Net settlements on early terminations and modifications of derivatives (1) 5,820 11,069 — Net change in fair value of derivatives (38,533 ) (17,246 ) 28,470 Total (loss) gain on derivatives, net $ (12,202 ) $ 22,366 $ 29,361 (1) The settlement amount does not include premiums paid attributable to contracts that matured during the respective period.

Fair Value Disclosures

Fair Value Disclosures	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value Disclosures	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, 2016, and 2015. Our estimates of fair value have been determined at discrete points in time based on relevant market data. These estimates involve uncertainty and cannot be determined with precision. There were no changes in valuation approach or related inputs for the years ended December 31, 2016, and 2015. Assets and Liabilities Measured at Fair Value on a Recurring Basis We account for commodity derivative contracts and their corresponding deferred premiums at fair value on a recurring basis utilizing certain pricing models. Inputs to the pricing models include publicly available prices from a compilation of data gathered from third parties and brokers. We validate the data provided by third parties by understanding the pricing models used, obtaining market values from other pricing sources, analyzing pricing data in certain situations and confirming that those securities trade in active markets. 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. Assets and Liabilities Measured at Fair Value on a Non-recurring Basis ARO We estimate the fair value of ARO based on discounted cash flow projections using numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for ARO, amounts and timing of settlements, the credit-adjusted risk-free rate to be used and inflation rates. See Note 7 in this section for a summary of changes in ARO. Acquisitions The estimated fair values of proved oil and natural gas properties acquired in business combinations are based on a discounted cash flow model and market assumptions as to future commodity prices, projections of estimated quantities of oil and natural gas reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk-adjusted discount rates. Based on the unobservable nature of certain of the inputs, the estimated fair value of the oil and natural gas properties acquired is deemed to use Level 3 inputs. See Note 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: (i) reserves; (ii) future operating and developmental costs; (iii) future commodity prices; (iv) a market-based weighted average cost of capital rate; and (v) the rate at which future cash flows are discounted to estimate present value. We discount future values by a per annum rate of 10% because we believe this amount approximates our long-term cost of capital and accordingly, is well aligned with our internal business decisions. The underlying commodity prices embedded in our estimated cash flows are the product of a process that begins with Level 1 NYMEX-WTI forward curve pricing, as well as Level 3 assumptions including: pricing adjustments for estimated location and quality differentials, production costs, capital expenditures, production volumes, decline rates and estimated reserves. See Note 16 in this section for additional information regarding our oil and natural gas reserves. Impairment The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimated quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. For the years ended December 31, 2016, and 2015, we recorded non-cash impairment of approximately $0.9 million and $103.9 million , respectively. The 2016 non-cash impairment resulted from a revision of reserve estimates for a property in our Permian core area. The non-cash impairment in 2015 resulted from a decline in commodity prices and to a lesser degree, reduced reserve estimates. These non-cash transactions are included in "Impairment of proved oil and natural gas properties" in our consolidated statements of operations. During the year ended December 31, 2016, we recorded non-cash impairment of approximately $3.6 million related to the Hugoton core area divestiture to reduce the carrying amount of those assets to their fair value. These assets and liabilities were deemed to meet held-for-sale accounting criteria as of June 30, 2016, accordingly, the impairment is included in "Impairment of proved oil and natural gas properties sold" in our consolidated statements of operations. The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2016, and 2015: Level 1 Level 2 Level 3 Fair Value (in thousands) December 31, 2016 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments - asset $ — $ 1,976 $ — $ 1,976 Derivative financial instruments - liability $ — $ 4,336 $ — $ 4,336 Derivative deferred premiums - liability $ — $ — $ 5,449 $ 5,449 December 31, 2015 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments - asset $ — $ 36,050 $ — $ 36,050 Derivative financial instruments - liability $ — $ 514 $ — $ 514 Derivative deferred premiums - liability $ — $ — $ 9,973 $ 9,973 A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, 2016 2015 (in thousands) Balance of Level 3 at beginning of period $ (9,973 ) $ — Derivative deferred premiums - purchases (516 ) (11,914 ) Derivative deferred premiums - settlements 5,040 1,941 Balance of Level 3 at end of period $ (5,449 ) $ (9,973 )

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well and determine our ARO by calculating the present value of estimated cash flow related to the estimated future liability. Determining the removal and future restoration obligation requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future 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. Over time, the liability is accreted each period toward its future value and is recorded in our consolidated statements of operations. The discounted capitalized cost is amortized to expense through the depreciation calculation over the life of the assets based on proved developed reserves. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability. For the years ended December 31, 2016, and 2015, 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, 2016 2015 (in thousands) Asset retirement obligations - beginning of period $ 12,679 $ 7,363 Liabilities incurred for new wells and interest 747 42 Liabilities settled upon plugging and abandoning wells — (40 ) Liabilities removed upon sale of wells (2,827 ) — Revision of estimates 155 4,882 Accretion expense 577 432 Asset retirement obligations - end of period $ 11,331 $ 12,679

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Debt A summary of our debt for the years ended December 31, 2016, and 2015 is presented below: Year Ended December 31, 2016 2015 (in thousands) Revolving credit facility (matures November 2018) $ 122,000 $ 180,000 Less: current portion — 30,000 Total long-term debt $ 122,000 $ 150,000 The borrowing base of our revolving credit facility is collectively determined by our lenders based on the value of our proved oil and natural gas reserves using assumptions regarding future prices, costs and other matters that may vary. The borrowing base is subject to scheduled redeterminations in the spring and fall of each year with an additional redetermination, either at our request or at the request of the lenders, during the period between each scheduled borrowing base redetermination. An additional borrowing base redetermination may be made at the request of the lenders in connection with a material disposition of our properties or a material liquidation of a hedge contract. Borrowings under the revolving credit facility bear interest at a floating rate based on, at our election: (i) the greater of the prime rate of the Wells Fargo Bank, National Association, the federal funds effective rate plus 0.50% and the one month adjusted London Interbank Offered Rate ("LIBOR") plus 1.0% , all of which are subject to a margin that varies from 1.00% to 2.75% per annum according to the borrowing base usage (which is the ratio of outstanding borrowings and letters of credit to the borrowing base then in effect), or (ii) the applicable LIBOR plus a margin that varies from 2.00% to 3.75% per annum according to the borrowing base usage. For the year ended December 31, 2016, the average effective rate was approximately 3.92% . Any unused portion of the borrowing base will be subject to a commitment fee that varies from 0.375% to 0.50% per annum according to the borrowing base usage. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general partnership purposes and for funding distributions to our unitholders. The revolving credit facility includes customary affirmative and negative covenants, such as limitations on the creation of new indebtedness and on certain liens, restrictions on certain transactions and payments, including distributions. If we fail to perform our obligations under these and other covenants, the revolving credit commitments may be terminated and any outstanding indebtedness under the credit agreement, together with accrued interest, could be declared immediately due and payable. We were in compliance with these covenants as of and during the year ended December 31, 2016. During February 2015, the revolving credit facility was amended to allow our Consolidated EBITDAX calculation, as defined in section 7.13 of the original revolving credit agreement, to reflect the net cash flows attributable to the restructured commodity derivative contracts that occurred during January 2015 for the periods of the first quarter 2015 through the third quarter of 2016. During the spring 2015 semi-annual redetermination and amendment to the credit agreement completed in April 2015, the borrowing base under the revolving credit facility was reduced to $220.0 million from $240.0 million . No other material terms of the original credit agreement were amended. During the fall 2015 semi-annual redetermination and amendment to the credit agreement completed in November 2015, the borrowing base under the underlying revolving credit facility was reduced to $190.0 million from $220.0 million , consisting of a $165.0 million conforming tranche, which required six monthly commitment reductions of $2.5 million each through May 2016, and a $25.0 million non-conforming tranche that matured on May 1, 2016. The revolving credit facility amendment also designated Wells Fargo Bank, National Association, as our administrative and collateral agent, replacing Royal Bank of Canada. This amendment also required that by December 10, 2015 we enter into commodity derivative contracts of not less than 80% of our 2016 projected monthly production and not less than 50% of our 2017 projected monthly production, calculated based on Proved Developed Producing reserves at the time of the agreement. These requirements were satisfied during November 2015 with the execution of additional commodity derivative contracts maturing in 2016 and 2017. In connection with this amendment to our revolving credit facility, we incurred financing fees and expenses of approximately $0.7 million , which will be amortized over the remaining life of the revolving credit facility. Such amortized expenses are recorded as "interest expense" in our consolidated statements of operations. During the spring 2016 semi-annual redetermination and amendment to the credit agreement completed in May 2016, the effective borrowing base as of June 1, 2016 was reduced to $163.0 million and was comprised of a $110.0 million conforming tranche and a permitted overadvance of $53.0 million . The permitted overadvance was scheduled to mature on November 1, 2016. In addition, the amendment (i) required the Partnership to provide a monthly excess cash flow report; (ii) required the Partnership to make varied minimum monthly principal payments totaling approximately $1.9 million through October 31, 2016; (iii) reduced the conforming borrowing base to $105.0 million upon the close of the Hugoton core area 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 core area 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. The amendment also required that by August 18, 2016, we enter into commodity derivative contracts of not less than 75% of our 2017 projected monthly production and not less than 50% of our 2018 projected monthly production, calculated based on Proved Developed Producing reserves at the time of the agreement. These requirements were satisfied with the execution of additional commodity derivative contracts maturing in 2018. The amendment also required that within 30 days we extend our collateral coverage to include the reserves acquired in the Permian Bolt-On acquisition. 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. The next regularly scheduled borrowing base redetermination will occur on or about April 30, 2017.

Commitment and Contingencies

Commitment and Contingencies	12 Months Ended
	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitment and Contingencies	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, 2016, 2015 and 2014, total lease expenses were approximately $0.4 million , $0.4 million , and $0.3 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): 2017 $ 490 2018 490 2019 413 2020 418 2021 423 Total $ 2,234 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 at least February1st preceding any such August 1st. Pursuant to the employment agreements, each employee will serve in his respective position with our general partner, as set forth above, and has duties, responsibilities and authority as the Board of Directors of our general partner may specify from time to time, in roles consistent with such positions that are assigned to them. The agreement stipulates that if there is a change of control, termination of employment, with cause or without cause, or death of the executive certain payments will be made to the executive officer. These payments, depending on the reason for termination, currently range from $0.4 million to $0.8 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, 2016
Equity [Abstract]
Equity	Equity Common Units At December 31, 2016, and 2015, the Partnership's equity consisted of 29,912,230 and 29,724,890 common units, respectively, representing approximately a 98.8% limited partnership interest in us. On May 5, 2015, we entered into an Equity Distribution Agreement to sell, from time to time through or to the Managers (as defined in the agreement), up to $50.0 million in common units representing limited partner interests. In connection with the 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. Preferred Units On August 11, 2016, we completed a private placement of 11,627,906 Preferred Units for an aggregate offering price of $25.0 million . The Preferred Units were issued at a price of $2.15 per Preferred Unit (the "Unit Purchase Price"). Proceeds from this issuance were used to fund the Permian Bolt-On acquisition and for general partnership purposes, including the reduction of borrowings under our revolving credit facility. We pay holders of the Preferred Units a cumulative, quarterly distribution on all Preferred Units then outstanding (i) in cash at an annual rate of 8.0% , or (ii) in the event that the Partnership's existing secured indebtedness prevents the payment of a cash distribution to all holders of the Preferred Units, in kind (additional Preferred Units), at an annual rate of 10.0% . Such distributions will be paid for each such quarter within 45 days after such quarter end. At any time after the six-month anniversary and prior to the five year anniversary of the closing date, each holder of the Preferred Units shall have the right, subject to certain conditions, to convert all or a portion of their Preferred Units into common units representing limited partner interests in the Partnership on a one-for-one basis, subject to adjustment for splits, subdivisions, combinations and reclassifications of the common units; provided that any holder electing conversion requests the conversion of at least the lesser of (i) 100% of such holder's remaining Preferred Units or (ii) $1.0 million of Preferred Units, based on the Unit Purchase Price. At any time after the fifth anniversary of the closing date of the offering, each holder shall have the right to cause the Partnership to redeem all or any portion of their Preferred Units for cash at the Unit Purchase Price, and any remaining Preferred Units will thereafter be converted to common units on a one-for-one basis, subject to adjustment for splits, reverse splits, subdivisions, combinations and reclassifications of the common units. Upon conversion of Preferred Units, the Partnership will pay any distributions (to the extent accrued and unpaid as of the then most recent Preferred Units distribution date) on the converted units in cash. Upon a change of control, each holder will have the right, at its election, to either (i) if the Partnership is the surviving entity of such change of control, continue to hold Preferred Units; or (ii) convert all or any portion of the Preferred Units held by such holder into common units on a one-for-one basis, subject to adjustments for splits, reverse splits, subdivisions, combinations and reclassifications. If any Preferred Units remain outstanding following a change of control in which the Partnership is not the surviving entity, then immediately following effectiveness of such change of control, the Partnership shall redeem in cash all, but not less than all, of the outstanding Preferred Units at a price per Preferred Unit equal to the Unit Purchase Price multiplied by the change of control redemption multiple then in effect. Under the registration rights agreements, we were required to use reasonable best efforts to file, within 90 days of the closing date, a registration statement registering resales of common units issued or to be issued upon conversion of the Preferred Units and have the registration statement declared effective within 180 days after the closing date. The common units to be issued are pending effectiveness of registration under a previously filed shelf registration statement on Form S-3. We are required to use reasonable best efforts to continue to maintain the effectiveness of the registration statement until all securities have been sold or the third anniversary of the effectiveness deadline. In addition, from and after the first anniversary of the closing date, holders of an aggregate of at least $1.0 million of Preferred Units (based on the Unit Purchase Price) shall have piggyback registration rights on all Partnership registrations, subject to customary carve backs, and holders of an aggregate of at least $5.0 million of Preferred Units (based on the Unit Purchase Price) shall have demand registration rights; provided that the holders shall be entitled to a demand registration right not more frequently that once during any twelve month period. In the event of any liquidation, dissolution or winding-up of the Partnership, each preferred unit will receive in preference to the holders of all existing classes or series of equity securities of the Partnership a per unit amount equal to the Unit Purchase Price (subject to any customary anti-dilution adjustments), plus all accrued and unpaid distributions on such Preferred Units (the "liquidation preference"). The Preferred Unit purchase agreement also required the Partnership to suspend sales of common units pursuant to the Equity Distribution Agreement from the closing date through the fifth anniversary of the closing date and prohibits the Partnership from incurring any indebtedness (other than under the Partnership’s existing revolving credit facility and trade accounts payable arising in the ordinary course of business) without the consent of the majority of the holders of the Preferred Units. We received net proceeds of approximately $24.6 million (net of issuance costs of approximately $0.4 million ) in connection with the issuance of Preferred Units. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units (approximately $18.6 million ) and the beneficial conversion feature (approximately $6.0 million ). A beneficial conversion feature is defined as a non-detachable conversion feature that is in the money at the commitment date. Per accounting guidance, we are required to allocate a portion of the proceeds from the Preferred Units to the beneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date based on the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per-share value of our common units at the issuance date) and the proceeds attributed to the Preferred Units. We will record the accretion attributed to the beneficial conversion feature as a deemed distribution using the straight line method over the five year period prior to the effective date of the holders conversion right. Accretion of the beneficial conversion feature was approximately $0.5 million for the year ended December 31, 2016. Our Distributions Our partnership agreement requires us to distribute all of our available cash on a quarterly basis. Our available cash is our cash on hand at the end of a quarter after the payment of our expenses and the establishment of reserves for future capital expenditures and operational needs, including cash from working capital borrowings. There is no assurance of future cash distributions since they are dependent upon our projections for future earnings, cash flows, capital requirements, financial conditions and other factors. As of December 31, 2016, cash distributions to our common units continue to be indefinitely suspended. Our credit agreement stipulates written consent from our lenders is required in order to reinstate common unit distributions and also prohibits us from making common unit cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution. Management and the Board of Directors will continue to evaluate, on a quarterly basis, the appropriate level of cash reserves in determining future distributions. The suspension of common unit cash distributions is designed to preserve liquidity and reallocate excess cash flow towards capital expenditure projects and debt reduction to maximize long-term value for our unitholders. The following table summarizes cash distributions paid to our common units for the year ended December 31, 2015: Total Distribution Distributions Date Paid Period Covered per Unit (in thousands) February 13, 2015 October 1, 2014 - December 31, 2014 $ 0.125 $ 3,752 May 14, 2015 January 1, 2015 - March 31, 2015 $ 0.125 3,752 August 13, 2015 April 1, 2015 - June 30, 2015 $ 0.125 3,762 $ 11,266 The holders of the Preferred Units are entitled to certain rights that are senior to the rights of holders of common units, such as rights to distributions and rights upon liquidation of the Partnership. Preferred unitholders receive quarterly distributions in cash at an annual rate of 8.0% or, under certain circumstances, in additional Preferred Units, rather than cash, at an annual rate of 10.0% . As of December 31, 2016, all 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 Preferred Units distribution (including any outstanding arrearages). At December 31, 2016, the Partnership had accrued approximately $0.5 million for the fourth quarter 2016 dividends that are to be paid in February 2017. The following table summarizes cash distributions paid on our Preferred Units for the year ended December 31, 2016: Total Distribution Distributions Date Paid Period Covered per Unit (in thousands) November 14, 2016 August 11, 2016 - September 30, 2016 $ 0.024 $ 279 Allocations of Net Income (Loss) Net income (loss), net of distributions on the Preferred Units and amortization of the preferred unit beneficial conversion feature (see Preferred Units section), is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership (exclusive of the Preferred Units limited partnership interest) during the period. The allocation of net income (loss) is presented in our consolidated statements of operations. Diluted net income (loss) per partner unit reflects the potential dilution of non-vested restricted stock awards. For the years ended December 31, 2016, and 2015, this potentially dilutive item was anti-dilutive due to the Partnership's net loss and, therefore, was excluded from the calculation of diluted net income (loss) per partner unit.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Agreements with Affiliates The following agreements were negotiated among affiliated parties and, consequently, are not the result of arm's length negotiations. The following is a description of those agreements that have been entered into with the affiliates of our general partner and with our general partner. Services Agreement We are party to a services agreement with our affiliate, Mid-Con Energy Operating, pursuant to which Mid-Con Energy Operating provides certain services to us, including management, administrative and operational services. The operational services include marketing, geological and engineering services. Under the services agreement, we reimburse Mid-Con Energy Operating, on a monthly basis, for the allocable expenses it incurs in its performance under the services agreement. These expenses include, among other things, salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and other expenses allocated by Mid-Con Energy Operating to us. These expenses are included in general and administrative expenses in our consolidated statements of operations. Operating Agreements We, various third parties with an ownership interest in the same property and our affiliate, Mid-Con Energy Operating, are parties to standard oil and natural gas joint operating agreements, pursuant to which we and those third parties pay Mid-Con Energy Operating overhead associated with operating our properties. We and those third parties also pay Mid-Con Energy Operating for its direct and indirect expenses that are chargeable to the wells under their respective operating agreements. The majority of these expenses are included in lease operating expenses in our 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 affiliate, ME3 Oilfield Service. These amounts are either included in lease operating expenses in our consolidated statements of operations or are 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, 2016 2015 2014 Amounts paid for: (in thousands) Services agreement $ 3,403 $ 3,654 $ 3,775 Operating agreements 6,221 8,332 6,120 Oilfield services 3,058 3,653 3,749 $ 12,682 $ 15,639 $ 13,644 At December 31, 2016, we had payables to our affiliate, Mid-Con Energy Operating, of approximately $1.1 million , comprised of a joint interest billing payable of approximately $0.5 million and a payable for operating services of approximately $0.6 million . At December 31, 2015, we had payables to our affiliate Mid-Con Energy Operating of approximately $0.5 million , comprised of a joint interest billing payable of approximately $0.1 million and a payable for operating services of approximately $0.4 million . These amounts were included in accounts payable-related parties in our consolidated balance sheets.

Credit Risk

Credit Risk	12 Months Ended
	Dec. 31, 2016
Risks and Uncertainties [Abstract]
Credit Risk	Credit Risk Credit risk relates to the risk of loss resulting from non-performance of non-payment by counterparties under the terms of their contractual obligations, thereby impacting the amount and timing of expected cash flows. Financial instruments which potentially subject us to credit risk consist principally of cash balances, accounts receivable and derivative financial instruments. We maintain cash and cash equivalents in bank deposit accounts which, at times, may exceed the federally insured limits. We have not experienced any significant losses from such investments. 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. For the year ended December 31, 2015, sales of oil and natural gas to three purchasers accounted for 75% of our sales and at December 31, 2015, accounted for 73% of our oil and natural gas receivables. For the year ended December 31, 2014, we had three purchasers that accounted for 74% of our sales and at December 31, 2014, accounted for 45% of our oil and natural gas receivables. 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, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Employee Benefit Plans	Employee Benefit Plans In 2011, our general partner adopted the Mid-Con Energy Partners, LP Long-Term Incentive Program which is intended to promote the interests of the partnership by providing to employees, officers, consultants and directors of our general partner and our other affiliates, including Mid-Con Energy Operating 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 controlling members of our general partner, and approved by the Board of Directors of the general partner. 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 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, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes We do not pay federal income taxes, as our profits or losses are reported to the taxing authorities by our individual partners.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Distributions The Board of Directors of the general partner declared a Preferred Unit cash distribution for the fourth quarter of 2016, according to terms outlined in the Partnership Agreement. A cash distribution of $0.043 per Preferred Unit, or approximately $0.5 million in aggregate, was paid on February 14, 2017 to holders of record as of the close of business on February 7, 2017. Appointment and Departure of Certain Officers Mr. S. Craig George resigned from the Board of Directors of the general partner effective January 31, 2017. Mr. Wilkie S. Colyer Jr. was appointed to the Board of Directors of the general partner effective February 1, 2017. Equity Awards On February 22, 2017, the Board of Directors of our general partner authorized the issuance of 25,400 unrestricted common units and 9,000 equity-settled phantom units.

Supplementary Information

Supplementary Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Supplementary Information	Supplementary Information Quarterly data (unaudited) Quarters Ended March 31 June 30 September 30 December 31 (In thousands, except per unit amounts) 2016 Oil and natural gas sales $ 11,269 $ 14,777 $ 14,410 $ 15,642 Gain (loss) on derivatives, net $ 2,568 $ (10,088 ) $ (444 ) $ (4,238 ) Total revenues and other $ 13,837 $ 4,689 $ 13,966 $ 11,404 Gain (loss) on sale of properties $ — $ 13 $ (530 ) $ (43 ) Total expenses (1) $ 17,150 $ 20,471 $ 15,857 $ 14,672 Net loss $ (3,313 ) $ (15,769 ) $ (2,421 ) $ (3,311 ) Net loss per limited partner unit (basic and diluted) $ (0.11 ) $ (0.52 ) $ (0.09 ) $ (0.14 ) 2015 Oil and natural gas sales $ 17,571 $ 21,611 $ 18,493 $ 16,239 Gain (loss) on derivatives, net $ 1,644 $ (8,871 ) $ 19,771 $ 9,822 Total revenues and other $ 19,215 $ 12,740 $ 38,264 $ 26,061 Total expenses (1) $ 23,327 $ 20,684 $ 63,742 $ 84,022 Net loss $ (4,112 ) $ (7,944 ) $ (25,478 ) $ (57,961 ) Net loss per limited partner unit (basic and diluted) $ (0.14 ) $ (0.26 ) $ (0.85 ) $ (1.93 ) (1) Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative and net other income (expense). Supplementary oil and natural gas activities Costs incurred in oil and natural gas property acquisitions and development activities are as follows: Year Ended December 31, 2016 2015 2014 (in thousands) Property acquisition costs: Proved $ 18,722 $ 1 $ 241,355 Unproved — — — Exploration — — — Development 6,963 13,415 34,320 Asset retirement obligations 902 4,924 3,171 Total costs incurred $ 26,587 $ 18,340 $ 278,846 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, 2016, 2015 and 2014 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 Natural Gas MBoe Proved developed and undeveloped reserves: As of December 31, 2013 13,714 1,321 13,934 Revisions of previous estimates (1) 211 924 364 Extensions, discoveries and other additions 1,241 52 1,250 Purchases of reserves in place 8,086 4,402 8,820 Production (1,112 ) (157 ) (1,138 ) As of December 31, 2014 22,140 6,542 23,230 Revisions of previous estimates (1) 596 856 739 Extensions, discoveries and other additions — — — Purchases of reserves in place 1 — 1 Production (1,623 ) (571 ) (1,718 ) 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 Proved developed reserves: December 31, 2014 17,046 5,327 17,933 December 31, 2015 14,368 4,762 15,162 December 31, 2016 11,733 4,141 12,423 Proved undeveloped reserves: December 31, 2014 5,094 1,215 5,297 December 31, 2015 6,746 2,065 7,090 December 31, 2016 6,477 1,983 6,808 (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) Represents the purchase of proved reserves as part of our Permian Bolt-On acquisition. (3) Decrease due to the sale of our Hugoton core area oil and natural gas properties. The change in quantities of proved reserves from December 31, 2013 to December 31, 2014, was due to the acquisitions of additional properties in Oklahoma and Texas from our affiliate Mid-Con Energy III, LLC, the acquisition of additional working interest in some of our Southern Oklahoma properties, the acquisition of the waterflood unit in Liberty County, Texas and the acquisition of multiple properties located in West Texas within the Eastern Shelf of the Permian. For this period, proved reserve volumes attributed to extensions, discoveries and other additions changed from 76 MBoe in 2013 to 1,250 MBoe in 2014. During the period of 2014, extensions, discoveries and other additions increased over the prior year primarily from development work in the Northeastern Oklahoma area, which increased proved developed producing and proved undeveloped reserves from new reservoirs from portions of older fields. The change in quantities of proved reserves from December 31, 2014 to December 31, 2015, was due to a significant commodity price decrease that resulted in a downward revision of 4,084 MBoe, improved recovery of 1,417 MBoe from our proved developed reserves in addition to 994 MBoe transferred from proved undeveloped reserves to proved developed reserves and the addition of recompletions, infill drilling, new waterflood projects, and expansion of existing waterflood projects in our Hugoton, Northeastern Oklahoma, Southern Oklahoma and Permian core areas resulting in a positive revision of proved undeveloped reserves of 3,405 MBoe. The upward revision of our proved developed reserves is largely attributable to a positive oil production response in 2015 to recently established water injection in the Cleveland Unit (Northeastern Oklahoma), Ona Morrow Unit (Hugoton) and Midwell Unit (Hugoton). 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 core 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 core areas, resulting in upward revisions to our proved reserves of 1,246 MBoe. During 2016, the divestiture of our Hugoton core area properties resulted in a downward revision of 3,109 MBoe and the acquisition of the Permian Bolt-On properties resulted in a positive revision of 1,552 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, 2016, 2015 and 2014, were estimated using the average price during the 12-month period, determined as the unweighted arithmetic average of the first-day-of-the-month price for each month in such period. • Future costs of developing and producing the proved oil and natural gas reserves were based on costs determined at each such period-end, assuming the continuation of existing economic conditions, including abandonment costs. • No future income tax expenses are computed for Mid-Con Energy Partners, LP because we are a non-taxable entity. • Future net cash flows were discounted at an annual rate of 10% . The Standardized Measure of discounted future net cash flow relating to estimated proved oil and natural gas reserves is presented below for the periods indicated: Year Ended December 31, 2016 2015 2014 (in thousands) Future cash inflows $ 741,077 $ 1,011,096 $ 2,084,005 Future production costs (389,138 ) (581,314 ) (825,318 ) Future development costs, including abandonment costs (65,195 ) (109,669 ) (76,783 ) Future net cash flow 286,744 320,113 1,181,904 10% discount for estimated timing of cash flow (129,459 ) (128,693 ) (517,627 ) Standardized measure of discounted cash flow $ 157,285 $ 191,420 $ 664,277 The prices utilized in calculating our total proved reserves were $42.75 , $50.28 and $94.99 per Bbl of oil and $2.49 , $2.58 and $4.35 per MMBtu of natural gas for December 31, 2016, 2015 and 2014, 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 $40.03 , $47.23 and $92.45 per Bbl of oil and $1.99 , $2.02 and $5.67 per Mcf of natural gas for December 31, 2016, 2015 and 2014, 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, 2016 2015 2014 (in thousands) Standardized measure of discounted future net cash flow, beginning of period $ 191,420 $ 664,277 $ 391,263 Changes in the year resulting from: Sales, less production costs (30,513 ) (36,836 ) (64,495 ) Revisions of previous quantity estimates 133 8,047 11,712 Extensions, discoveries and improved recovery — — 44,727 Net change in prices and production costs (16,138 ) (454,669 ) 22,068 Net change in income taxes — — — Changes in estimated future development costs 22,685 (6,080 ) (18,125 ) Previously estimated development costs incurred during the period 3,526 8,103 22,526 Purchases of reserves in place 22,223 19 264,921 Sales of reserves in place (11,124 ) — — Accretion of discount 19,142 66,428 39,126 Timing differences and other (44,069 ) (57,869 ) (49,446 ) Standardized measure of discounted future net cash flow, end of year $ 157,285 $ 191,420 $ 664,277

Organization and Nature of Op23

Organization and Nature of Operations Organization and Nature of Operations (Policies)	12 Months Ended
	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Nature of Operations Mid-Con Energy Partners, LP is a publicly held Delaware limited partnership formed in July 2011 that engages in the ownership, acquisition, exploitation and development of producing oil and natural gas properties in North America, with a focus on EOR. Our limited partner units ("common units") are listed on the NASDAQ Global Select Market under the symbol "MCEP." Our general partner is Mid-Con Energy GP, LLC, a Delaware limited liability company. Reclassifications The consolidated statements of operations for previous periods include certain reclassifications to the other income (expense) accounts that were made to conform to current presentation. Such reclassifications have no impact on previously reported net income (loss).

Summary of Significant Accoun24

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
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, 2016 and 2015. These financial statements also include the results of our operations, cash flows and changes in equity for the years ended December 31, 2016, 2015 and 2014. The accompanying consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). Our subsidiary is Mid-Con Energy Properties. All intercompany transactions and account balances have been eliminated. We aggregate all of our oil and natural gas properties into one business segment engaged in the exploitation, development and production of oil and natural gas properties.
Use of estimates	Use of estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Depletion and impairment of oil and natural gas properties, in part, are determined using estimates of proved oil and natural gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved oil and natural gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Other significant estimates include, but are not limited to, ARO, fair value of assets acquired and liabilities assumed in business combinations and fair value of derivative financial instruments.
Cash and cash equivalents	Cash and cash equivalents We consider all cash on hand, depository accounts held by banks and money market accounts with an original maturity of three months or less to be cash equivalents.
Accounts receivable	Accounts receivable Accounts receivable are generated from the sale of oil and natural gas to various customers. We routinely assess the financial strength of our customers and bad debts are recorded based on an account level review after all means of collection have been exhausted, and the potential recovery is considered remote. At December 31, 2016 and 2015, 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, 2016 or 2015. 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 exploitation 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. Capitalized costs of individual properties abandoned or retired are charged to accumulated depletion, depreciation and amortization. Proceeds from sales of individual properties are credited to property costs. No gain or loss is recognized until the entire amortization base (field) is sold or abandoned. Costs of significant non-producing properties and wells in the process of being drilled are excluded from depletion until such time as the proved reserves are established or impairment is determined. Costs of significant development projects are excluded from depletion until the related project is completed. We had no significant costs excluded from depreciation during any of the periods presented. We capitalize interest, if debt is outstanding, on expenditures for significant development projects until such projects are ready for their intended use. We had no capitalized interest during any of the periods presented. We review our long-lived assets to be held and used, including proved oil and natural gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value may be greater than management's estimates of its future net cash flows, including cash flows from proved reserves and risk-adjusted probable and possible reserves. The need to test an asset for impairment may result from significant declines in sales prices or downward revisions in estimate quantities of oil and natural gas reserves. If the carrying value of the long-lived assets exceeds the sum of estimated undiscounted future net cash flows, an impairment loss is recognized for the difference between the estimated fair value and the carrying value of the assets. We review our oil and natural gas properties by amortization base (field) or by individual well for those wells not constituting part of an amortization base. These evaluations involve a significant amount of judgment since the results are based on estimated future events, such as future sales prices for oil and natural gas, future costs to produce these products, estimates of future oil and natural gas reserves to be recovered and the timing thereof, the economic and regulatory climates and other factors. Cash flow estimates for the impairment testing excludes derivative instruments used to mitigate the price risk related to lower future oil and natural gas prices. We have obligations under our lease agreements and federal regulations to remove equipment and restore land at the end of oil and natural gas production operations. These ARO are primarily associated with plugging and abandoning wells. We typically incur this liability upon acquiring or drilling a well. Determining the future restoration and removal requires management to make estimates and judgments, including the ultimate settlement amounts, inflation factors, credit adjusted risk-free rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. We estimate the future plugging and abandonment costs of wells, the ultimate productive life of the properties, a risk adjusted discount rate and an inflation factor in order to determine the current present value of this obligation. We are required to record the fair value of a liability for the ARO in the period in which it is incurred with a corresponding increase in the carrying amount of the related long-lived asset. We review our assumptions and estimates of future 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. Over time, the liability is accreted each period toward its future value and the capitalized cost is depleted as a component of development costs. Upon settlement of the liability, a gain or loss is recognized to the extent the actual costs differ from the recorded liability. See Note 7 for additional information.
Derivatives and hedging	Derivatives and hedging Our risk management program is intended to reduce our exposure to commodity price volatility and to assist with stabilizing cash flows. Accordingly, we utilize commodity derivatives (swaps, calls, puts and collars) to manage a portion of our exposure to commodity prices and specific delivery points. 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. Compensation expense for awards is recorded upon vesting, based on their grant-date fair value, net of estimated forfeitures. We estimate our forfeiture rate based on prior experience and adjust it as circumstances warrant. No compensation expense is recognized for equity instruments that do not vest.
Debt placement fee	Debt issuance costs Debt placement costs are stated at cost, net of amortization, which is computed using the straight-line method and recognized as interest expense in the consolidated statements of operations 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, we write off any remaining issuance costs associated with that debt.
Income taxes	Income taxes We are a partnership that is not taxable for federal income tax purposes. As such, we do not directly pay federal income tax. As appropriate, our taxable income or loss is includable in the federal income tax returns of our unitholders. Earnings or losses for financial statement purposes may differ significantly from those reported to the individual unitholders for income tax purposes as a result of differences between the tax basis and financial reporting basis of assets and liabilities.
Allocation of net income (loss)	Allocation of Net Income (Loss) Net income (loss), net of distributions on the Preferred Units and amortization of the preferred unit beneficial conversion feature, is allocated between our general partner and the limited partner unitholders in proportion to their pro rata ownership during the period. The allocation of net income (loss) is presented in our consolidated statements of operations. Diluted net income (loss) per partner unit reflects the potential dilution of non-vested restricted stock awards. For the years ended December 31, 2016, and 2015, this potentially dilutive item was anti-dilutive due to the Partnership's net loss and, therefore, was excluded from the calculation of diluted net income (loss) per partner unit.
Recent Accounting Pronouncements	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board ("FASB") issued a comprehensive new revenue recognition standard that supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition . The core principle of the new guidance is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for transferring those goods or services. The new standard also requires significantly expanded disclosure regarding the qualitative and quantitative information of an entity's nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. The standard creates a five-step model that requires companies to exercise judgment when considering the terms of a contract and all relevant facts and circumstances. The standard allows for several transition methods: (a) a full retrospective adoption in which the standard is applied to all of the periods presented, or (b) a modified retrospective adoption in which the standard is applied only to the most current period presented in the financial statements, including additional disclosures of the standard's application impact to individual financial statement line items. This standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period. We plan to adopt ASU 2014-09 effective January 1, 2018, using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018, as an adjustment to opening retained earnings. We do not expect our revenue recognition under the new guidance to materially differ from our current revenue recognition practice. We do not expect the cumulative effect adjustment to opening retained earnings to be significant. In February 2016, the FASB issued ASU No. 2016-02, " Leases (Topic 842)," which supersedes current lease guidance. The new lease standard requires all leases with a term greater than one year to be recognized on the balance sheet while maintaining substantially similar classifications for finance and operating leases. Lease expense recognition on the income statement will be effectively unchanged. This guidance is effective for reporting periods beginning after December 15, 2018 and early adoption is permitted. As of December 31, 2016, the Partnership has not elected early adoption. We believe the primary impact of adopting this standard will be the recognition of assets and liabilities on our balance sheet for current operating leases. We are still evaluating the impact of this standard. In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Improvements to Employee Share-Based Payment Accounting. The guidance simplifies the accounting for employee stock-based payment transactions including the accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as classification of awards as either equity or liabilities, and classification of related amounts within the statement of cash flows. The guidance requires the recognition of the income tax effects of awards in the income statement when the awards vest or are settled, thus eliminating additional paid in capital pools. The guidance also allows for the employer to repurchase more of an employee's shares for tax withholding purposes without triggering liability accounting. In addition, the guidance allows for a policy election to account for forfeitures as they occur rather than on an estimated basis. The guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period and early adoption is permitted. As of December 31, 2016, the Partnership has not elected early adoption. Based on our initial evaluation, we do not anticipate a material impact to our consolidated financial statements upon adoption of this standard. In August, 2016, the FASB issued Accounting Standards Update No. 2016-15, Classification of Certain Cash Receipts and Cash Payments (a consensus of the Emerging Issues Task Force). The amendments in ASU 2016-15 address eight specific cash flow issues and apply to all entities that are required to present a statement of cash flows under FASB Accounting Standards Codification (FASB ASC) 230, Statement of Cash Flows. The amendments in ASU 2016-15 are effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. Early adoption is permitted, including adoption during an interim period. Based on our initial evaluation, we do not anticipate a material impact to our consolidated financial statements upon adoption of this standard.

Organization and Nature of Op25

Organization and Nature of Operations (Tables)	12 Months Ended
	Dec. 31, 2016
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, 2016 2015 2014 (in thousands) Non-cash investing and financing information: Change in oil and natural gas properties - accrued capital expenditures $ (259 ) $ (560 ) $ 351 Tenant improvement allowance deferred - other property and equipment $ 124 $ — $ — Cash paid for interest $ 6,198 $ 6,070 $ 4,600 Common units issued - acquisition of oil properties $ — $ — $ 86,001

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2016
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	The recognized fair values of the assets acquired and liabilities assumed are as follows (in thousands): Fair value of net assets: Oil and natural gas properties $ 19,323 Total assets acquired 19,323 Fair value of net liabilities assumed: Asset retirement obligation 622 Net assets acquired $ 18,701

Acquisitions and Divestitures D

Acquisitions and Divestitures Divestiture (Tables)	12 Months Ended
	Dec. 31, 2016
Hugoton
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, 2016 2015 2014 (in thousands) Oil and natural gas sales $ 3,602 $ 11,744 $ 23,708 Expenses (1) $ 7,717 $ 51,505 $ 43,384

Equity Awards (Tables)

Equity Awards (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Number of existing awards and awards available under Long-Term Incentive Program	The following table shows the number of existing awards and awards available under the Long-Term Incentive Program at December 31, 2016: Number of Common Units Approved and authorized awards 3,514,000 Unrestricted units granted (1,187,306 ) Restricted units granted, net of forfeitures (400,424 ) Equity-settled phantom units granted, net of forfeitures (457,500 ) Awards available for future grant 1,468,770
Summary of restricted units awarded	A summary of our restricted unit awards for the years ended December 31, 2016, and 2015 is presented below: Number of Restricted Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 109,800 $ 23.28 Units granted 294,100 5.04 Units vested (148,195 ) 12.43 Units forfeited (32,872 ) 9.28 Outstanding at December 31, 2015 222,833 $ 8.49 Units granted — — Units vested (112,478 ) 9.16 Units forfeited (33,433 ) 9.69 Outstanding at December 31, 2016 76,922 $ 5.67
Summary of Equity-Settled units awarded	A summary of our equity-settled phantom unit awards for the years ended December 31, 2016, and 2015 is presented below: Number of Equity-Settled Phantom Units Average Grant Date Fair Value per Unit Outstanding at December 31, 2014 — $ — Units granted 115,500 2.87 Units vested (23,000 ) 3.12 Units forfeited (15,000 ) 2.81 Outstanding at December 31, 2015 77,500 2.81 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

Derivative Financial Instrume29

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Commodity Contracts	At December 31, 2015, we had the following oil derivatives net positions: Weighted Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls Hedged/day NYMEX Index Swaps - 2016 $ 79.98 1,598 WTI Collars - 2016 $ 50.00 $ 50.00 328 WTI Puts - 2016 $ 50.00 $ — 1,475 WTI Puts - 2017 $ 50.00 $ — 1,932 WTI At December 31, 2016, we had the following oil derivatives net positions: Period Covered Weighted Average Floor Price Weighted Average Ceiling Price Total Bbls 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
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, 2016 and 2015 : Gross Gross Amounts Net Amounts (in thousands) 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 ) Gross Gross Amounts Net Amounts (in thousands) December 31, 2015 Assets Derivative financial instruments - current asset $ 29,973 $ (5,554 ) $ 24,419 Derivative financial instruments - long-term asset 6,077 (4,933 ) 1,144 Total 36,050 (10,487 ) 25,563 Liabilities Derivative financial instruments - current liability (514 ) 514 — Derivative deferred premium - current liability (5,040 ) 5,040 — Derivative deferred premium - long-term liability (4,933 ) 4,933 — Total (10,487 ) 10,487 — Net Asset $ 25,563 $ — $ 25,563
Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations	The following table presents the impact of derivative financial instruments and their location within the consolidated statements of operations: Year Ended December 31, 2016 2015 2014 (in thousands) Net settlements on matured derivatives (1) $ 20,511 $ 28,543 $ 891 Net settlements on early terminations and modifications of derivatives (1) 5,820 11,069 — Net change in fair value of derivatives (38,533 ) (17,246 ) 28,470 Total (loss) gain on derivatives, net $ (12,202 ) $ 22,366 $ 29,361

Fair Value Disclosures (Tables)

Fair Value Disclosures (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Assets and Liabilities Measured at Fair Value on Recurring Basis	The following sets forth, by level within the hierarchy, the fair value of our assets and liabilities measured at fair value on a recurring basis as of December 31, 2016, and 2015: Level 1 Level 2 Level 3 Fair Value (in thousands) December 31, 2016 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments - asset $ — $ 1,976 $ — $ 1,976 Derivative financial instruments - liability $ — $ 4,336 $ — $ 4,336 Derivative deferred premiums - liability $ — $ — $ 5,449 $ 5,449 December 31, 2015 Assets and Liabilities Measured at Fair Value on a Recurring Basis Derivative financial instruments - asset $ — $ 36,050 $ — $ 36,050 Derivative financial instruments - liability $ — $ 514 $ — $ 514 Derivative deferred premiums - liability $ — $ — $ 9,973 $ 9,973
Level 3 Reconciliation [Table Text Block]	A summary of the changes in Level 3 fair value measurements for the periods presented are as follows: Year Ended December 31, 2016 2015 (in thousands) Balance of Level 3 at beginning of period $ (9,973 ) $ — Derivative deferred premiums - purchases (516 ) (11,914 ) Derivative deferred premiums - settlements 5,040 1,941 Balance of Level 3 at end of period $ (5,449 ) $ (9,973 )

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Changes in Asset Retirement Obligations	Changes in our ARO for the periods indicated are presented in the following table: Year Ended December 31, 2016 2015 (in thousands) Asset retirement obligations - beginning of period $ 12,679 $ 7,363 Liabilities incurred for new wells and interest 747 42 Liabilities settled upon plugging and abandoning wells — (40 ) Liabilities removed upon sale of wells (2,827 ) — Revision of estimates 155 4,882 Accretion expense 577 432 Asset retirement obligations - end of period $ 11,331 $ 12,679

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt	A summary of our debt for the years ended December 31, 2016, and 2015 is presented below: Year Ended December 31, 2016 2015 (in thousands) Revolving credit facility (matures November 2018) $ 122,000 $ 180,000 Less: current portion — 30,000 Total long-term debt $ 122,000 $ 150,000

Commitment and Contingencies No

Commitment and Contingencies Non-Cancellable Operating Leases (Tables)	12 Months Ended
	Dec. 31, 2016
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): 2017 $ 490 2018 490 2019 413 2020 418 2021 423 Total $ 2,234

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Cash Distributions - Common Unitholders	The following table summarizes cash distributions paid to our common units for the year ended December 31, 2015: Total Distribution Distributions Date Paid Period Covered per Unit (in thousands) February 13, 2015 October 1, 2014 - December 31, 2014 $ 0.125 $ 3,752 May 14, 2015 January 1, 2015 - March 31, 2015 $ 0.125 3,752 August 13, 2015 April 1, 2015 - June 30, 2015 $ 0.125 3,762 $ 11,266
Cash Distributions - Preferred Unitholders	The following table summarizes cash distributions paid on our Preferred Units for the year ended December 31, 2016: Total Distribution Distributions Date Paid Period Covered per Unit (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, 2016
Related Party Transactions [Abstract]
Related Party	The following table summarizes the affiliates' transactions for the periods indicated: Year Ended December 31, 2016 2015 2014 Amounts paid for: (in thousands) Services agreement $ 3,403 $ 3,654 $ 3,775 Operating agreements 6,221 8,332 6,120 Oilfield services 3,058 3,653 3,749 $ 12,682 $ 15,639 $ 13,644

Supplementary Information (Tabl

Supplementary Information (Tables)	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Schedule of Quarterly Data	Quarters Ended March 31 June 30 September 30 December 31 (In thousands, except per unit amounts) 2016 Oil and natural gas sales $ 11,269 $ 14,777 $ 14,410 $ 15,642 Gain (loss) on derivatives, net $ 2,568 $ (10,088 ) $ (444 ) $ (4,238 ) Total revenues and other $ 13,837 $ 4,689 $ 13,966 $ 11,404 Gain (loss) on sale of properties $ — $ 13 $ (530 ) $ (43 ) Total expenses (1) $ 17,150 $ 20,471 $ 15,857 $ 14,672 Net loss $ (3,313 ) $ (15,769 ) $ (2,421 ) $ (3,311 ) Net loss per limited partner unit (basic and diluted) $ (0.11 ) $ (0.52 ) $ (0.09 ) $ (0.14 ) 2015 Oil and natural gas sales $ 17,571 $ 21,611 $ 18,493 $ 16,239 Gain (loss) on derivatives, net $ 1,644 $ (8,871 ) $ 19,771 $ 9,822 Total revenues and other $ 19,215 $ 12,740 $ 38,264 $ 26,061 Total expenses (1) $ 23,327 $ 20,684 $ 63,742 $ 84,022 Net loss $ (4,112 ) $ (7,944 ) $ (25,478 ) $ (57,961 ) Net loss per limited partner unit (basic and diluted) $ (0.14 ) $ (0.26 ) $ (0.85 ) $ (1.93 ) (1) Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative and net other income (expense).
Supplementary Oil and Natural Gas Activities	Costs incurred in oil and natural gas property acquisitions and development activities are as follows: Year Ended December 31, 2016 2015 2014 (in thousands) Property acquisition costs: Proved $ 18,722 $ 1 $ 241,355 Unproved — — — Exploration — — — Development 6,963 13,415 34,320 Asset retirement obligations 902 4,924 3,171 Total costs incurred $ 26,587 $ 18,340 $ 278,846
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 Natural Gas MBoe Proved developed and undeveloped reserves: As of December 31, 2013 13,714 1,321 13,934 Revisions of previous estimates (1) 211 924 364 Extensions, discoveries and other additions 1,241 52 1,250 Purchases of reserves in place 8,086 4,402 8,820 Production (1,112 ) (157 ) (1,138 ) As of December 31, 2014 22,140 6,542 23,230 Revisions of previous estimates (1) 596 856 739 Extensions, discoveries and other additions — — — Purchases of reserves in place 1 — 1 Production (1,623 ) (571 ) (1,718 ) 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 Proved developed reserves: December 31, 2014 17,046 5,327 17,933 December 31, 2015 14,368 4,762 15,162 December 31, 2016 11,733 4,141 12,423 Proved undeveloped reserves: December 31, 2014 5,094 1,215 5,297 December 31, 2015 6,746 2,065 7,090 December 31, 2016 6,477 1,983 6,808 (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) Represents the purchase of proved reserves as part of our Permian Bolt-On acquisition. (3) Decrease due to the sale of our Hugoton core area oil and natural gas properties.
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, 2016 2015 2014 (in thousands) Future cash inflows $ 741,077 $ 1,011,096 $ 2,084,005 Future production costs (389,138 ) (581,314 ) (825,318 ) Future development costs, including abandonment costs (65,195 ) (109,669 ) (76,783 ) Future net cash flow 286,744 320,113 1,181,904 10% discount for estimated timing of cash flow (129,459 ) (128,693 ) (517,627 ) Standardized measure of discounted cash flow $ 157,285 $ 191,420 $ 664,277
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, 2016 2015 2014 (in thousands) Standardized measure of discounted future net cash flow, beginning of period $ 191,420 $ 664,277 $ 391,263 Changes in the year resulting from: Sales, less production costs (30,513 ) (36,836 ) (64,495 ) Revisions of previous quantity estimates 133 8,047 11,712 Extensions, discoveries and improved recovery — — 44,727 Net change in prices and production costs (16,138 ) (454,669 ) 22,068 Net change in income taxes — — — Changes in estimated future development costs 22,685 (6,080 ) (18,125 ) Previously estimated development costs incurred during the period 3,526 8,103 22,526 Purchases of reserves in place 22,223 19 264,921 Sales of reserves in place (11,124 ) — — Accretion of discount 19,142 66,428 39,126 Timing differences and other (44,069 ) (57,869 ) (49,446 ) Standardized measure of discounted future net cash flow, end of year $ 157,285 $ 191,420 $ 664,277

Organization and Nature of Op37

Organization and Nature of Operations Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Change in oil and natural gas properties - accrued capital expenditures	$ (259)	$ (560)	$ 351
Tenant improvement allowance deferred - other property and equipment	124	0	0
Cash paid for interest	6,198	6,070	4,600
Common units issued - acquisition of oil properties	$ 0	$ 0	$ 86,001

Summary of Significant Accoun38

Summary of Significant Accounting Policies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016Segment
Summary Of Significant Accounting Policies [Line Items]
Number of operating segment	1

Acquisitions and Divestitures A

Acquisitions and Divestitures Acquisitions 1 (Details) - USD ($) $ in Thousands	Aug. 11, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Business Acquisitions Total Sales for the Period		$ 2,700
Business Acquisition Total Expenses for the Period		600
Proceeds from sale of convertible preferred units, net of offering costs	$ 25,000	$ 24,646	$ 0	$ 0
Permian Bolt-On
Business Acquisition [Line Items]
Aggregate purchase price, net	18,700
Proceeds from sale of convertible preferred units, net of offering costs	25,000
Oil and natural gas properties	19,323
Total assets acquired	19,323
Asset retirement obligations assumed	622
Net assets acquired	$ 18,701

Acquisitions and Divestitures40

Acquisitions and Divestitures Divestiture (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Divestiture [Line Items]
Proceeds from sales of oil and natural gas properties					$ 17,635	$ 0	$ 0
Loss on sales of oil and natural gas properties, net	$ (43)	$ (530)	$ 13	$ 0	(560)	0	0
Impairment of proved oil and natural gas properties sold					3,578	0	0
Hugoton
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 sold					3,600
Divestiture oil and gas revenue					3,602	11,744	23,708
Divestiture oil and gas expense					$ 7,717	$ 51,505	$ 43,384

Equity Awards - Additional Info

Equity Awards - Additional Information (Detail) - Long-Term Incentive Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Nov. 20, 2015	Nov. 19, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000			3,514,000	1,764,000
Equity-based compensation expense	$ 1.2	$ 3.2	$ 7.7

Equity Awards - Awards Availabl

Equity Awards - Awards Available for Future Grant (Details) - Long-Term Incentive Plan - shares	Dec. 31, 2016	Nov. 20, 2015	Nov. 19, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Approved and authorized awards	3,514,000	3,514,000	1,764,000
Unrestricted units granted	(1,187,306)
Restricted units granted, net of forfeitures	(400,424)
Equity-settled phantom units granted, net of forfeitures	(457,500)
Awards available for future grant	1,468,770

Equity Awards Equity Awards - U

Equity Awards Equity Awards - Unrestricted Units (Details) - Unrestricted Common Units - $ / shares	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Units granted	73,932	274,550
Average grant date fair value per unit, granted	$ 1.20	$ 4.85

Equity Awards - Restricted Unit

Equity Awards - Restricted Units (Details) - Restricted Common Units - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years
Unrecognized compensation costs	$ 0.1
Weighted average period, unrecognized cost	8 months
Number of units
Outstanding, beginning of period	222,833	109,800
Units granted	0	294,100
Units vested	(112,478)	(148,195)
Units forfeited	(33,433)	(32,872)
Outstanding, end of period	76,922	222,833
Weighted Average Grant Date Fair Value per Restricted Unit
Average fair value per unit, outstanding, beginning of period	$ 8.49	$ 23.28
Average grant date fair value per unit, granted	0	5.04
Average grant date fair value per unit, vested	9.16	12.43
Average grant date fair value per unit, forfeited	9.69	9.28
Average fair value per unit, outstanding, end of period	$ 5.67	$ 8.49
Share-based Compensation Award, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	2 years	2 years
Award Vesting Rights, Percentage	33.33%
Number of units
Units granted	0	268,000
Share-based Compensation Award, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period		3 years
Award Vesting Rights, Percentage	66.66%
Common units authorized for issuance		26,100

Equity Awards Equity Awards - E

Equity Awards Equity Awards - Equity Settled Phantom Units (Details) - Equity-Settled Phantom Units - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation costs	$ 0.3
Weighted average period, unrecognized cost	1 year 6 months
Number of units
Outstanding, beginning of period	77,500	0
Units granted	374,500	115,500
Units vested	(146,841)	(23,000)
Units forfeited	(17,500)	(15,000)
Outstanding, end of period	287,659	77,500
Weighted Average Grant Date Fair Value per Phantom Unit
Average fair value per unit, outstanding, beginning of period	$ 2.81	$ 0
Average grant date fair value per unit, granted	1.55	2.87
Average grant date fair value per unit, vested	2.03	3.12
Average grant date fair value per unit, forfeited	2.02	2.81
Average fair value per unit, outstanding, end of period	$ 1.64	$ 2.81
Share-based Compensation Award, Tranche One
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Rights, Percentage	33.33%
Number of units
Units granted	347,500	69,000
Share-based Compensation Award, Tranche Two
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award Vesting Rights, Percentage	66.66%
Number of units
Units granted	27,000	46,500
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	2 years	2 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period	3 years	3 years

Derivative Financial Instrume46

Derivative Financial Instruments - Additional information (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Fair value	$ (7,809)	$ 25,563

Derivative Financial Instrume47

Derivative Financial Instruments - Commodity Contracts (Details) - $ / Bbls	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Period Covered-2016 | Swap
Derivative [Line Items]
Weighted Average Fixed Price		79.98
Total Bbls Hedged/day		1,598
Derivative, Underlying Basis	WTI
Period Covered-2016 | Put Option
Derivative [Line Items]
Weighted Average Floor Price		50
Total Bbls Hedged/day		1,475
Derivative, Underlying Basis		WTI
Period Covered-2016 | Collar
Derivative [Line Items]
Weighted Average Floor Price		50
Weighted Average Ceiling Price		50
Total Bbls Hedged/day		328
Derivative, Underlying Basis		WTI
Period Covered-2017 | Put Option
Derivative [Line Items]
Weighted Average Floor Price	50	50
Total Bbls Hedged/day	1,932	1,932
Derivative, Underlying Basis	WTI	WTI
Period Covered-2017 | Collar
Derivative [Line Items]
Weighted Average Floor Price	43.75
Weighted Average Ceiling Price	50.68
Total Bbls Hedged/day	658
Derivative, Underlying Basis	WTI
Period Covered-2018 | Put Option
Derivative [Line Items]
Weighted Average Floor Price	45
Total Bbls Hedged/day	164
Derivative, Underlying Basis	WTI
Period Covered-2018 | Collar
Derivative [Line Items]
Weighted Average Floor Price	44.38
Weighted Average Ceiling Price	55.52
Total Bbls Hedged/day	1,315
Derivative, Underlying Basis	WTI
Period Covered-2019 | Collar
Derivative [Line Items]
Weighted Average Floor Price	50
Weighted Average Ceiling Price	60.52
Total Bbls Hedged/day	427
Derivative, Underlying Basis	WTI

Derivative Financial Instrume48

Derivative Financial Instruments - Restructured Commodity Contracts (Details) - USD ($) $ in Thousands	Oct. 31, 2016	Aug. 11, 2016	Jul. 01, 2016	Jan. 23, 2015	Nov. 30, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash settlements received for early terminations and modifications of derivatives, net						$ 5,820	$ 11,069	$ 0
Commodity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash settlements received for early terminations and modifications of derivatives, net			$ 5,800	$ 11,100
Cash Received from Derivative - Calls				5,900
Cash paid for premiums	$ 100			$ 19,800
Fair Value of deferred premiums put option	$ 100				$ 7,800	$ 4,100
Derivative deferred premiums - settlements			$ 1,500		$ 2,900
Minimum coverage of projected production (percent)						80.00%
Commodity Contract | August 2016 Amended Credit Agreement
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair Value of deferred premiums put option		$ 400
2017 Projected monthly production | Commodity Contract | August 2016 Amended Credit Agreement
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Minimum coverage of projected production (percent)						75.00%
2018 Projected monthly production | Commodity Contract | August 2016 Amended Credit Agreement
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Minimum coverage of projected production (percent)						50.00%

Derivative Financial Instrume49

Derivative Financial Instruments - Summary of Gross Fair Value by Appropriate Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	$ 1,976	$ 36,050
Gross Amounts Offset	(1,976)	(10,487)
Net Amount presented - Balance Sheet	0	25,563
Liabilities [Abstract]
Gross Amounts of Recognized Liabilities	(9,785)	(10,487)
Gross Amounts Offset	1,976	10,487
Net Amount presented - Balance Sheet	(7,809)	0
Gross Amount of Recognized Assets and Liabilities	(7,809)	25,563
Gross Amounts Offset	0	0
Net Assets Presented - Balance Sheet	(7,809)	25,563
Current Asset
Assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	1,570	29,973
Gross Amounts Offset	(1,570)	(5,554)
Net Amount presented - Balance Sheet	0	24,419
Long Term Asset
Assets [Abstract]
Derivative Asset, Fair Value, Gross Asset	406	6,077
Gross Amounts Offset	(406)	(4,933)
Net Amount presented - Balance Sheet	0	1,144
Current Liability
Liabilities [Abstract]
Gross Amounts of Recognized Liabilities	(1,836)	(514)
Gross Amounts Offset	(3,478)	514
Net Amount presented - Balance Sheet	(5,314)	0
Gross Amount Deferred premium	(5,048)	(5,040)
Deferred Premium Offset	5,048	5,040
Deferred Premium	0	0
Long Term Liability
Liabilities [Abstract]
Gross Amounts of Recognized Liabilities	(2,500)
Gross Amounts Offset	5
Net Amount presented - Balance Sheet	(2,495)
Gross Amount Deferred premium	(401)	(4,933)
Deferred Premium Offset	401	4,933
Deferred Premium	$ 0	$ 0

Derivative Financial Instrume50

Derivative Financial Instruments - Impact of Derivative Financial Instruments within Condensed Consolidated Statement of Operations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash settlements received for matured derivatives	$ 20,511	$ 28,543	$ 891
Cash settlements received for early terminations and modifications of derivatives, net	5,820	11,069	0
Net change in fair value of derivatives	(38,533)	(17,246)	28,470
Total (loss) gain on derivatives, net	$ (12,202)	$ 22,366	$ 29,361

Fair Value Disclosures - Additi

Fair Value Disclosures - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Inputs, Discount Rate	10.00%
Impairment charges	$ 895	$ 103,938	$ 30,206
Impairment of proved oil and natural gas properties sold	$ 3,578	$ 0	$ 0

Fair Value Disclosures - Assets

Fair Value Disclosures - Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Fair Value
Derivative financial instruments - asset	$ 0	$ 25,563
Derivative financial instruments - liability	7,809	0
Level 3
Fair Value
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs	(5,449)	(9,973)	$ 0
Estimate of Fair Value Measurement | Assets and Liabilities Measured at Fair Value on a Recurring Basis
Fair Value
Derivative financial instruments - asset	1,976	36,050
Derivative financial instruments - liability	4,336	514
Derivative deferred premiums - liability	5,449	9,973
Estimate of Fair Value Measurement | Level 1 | Assets and Liabilities Measured at Fair Value on a Recurring Basis
Fair Value
Derivative financial instruments - asset	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	0	0
Estimate of Fair Value Measurement | Level 2 | Assets and Liabilities Measured at Fair Value on a Recurring Basis
Fair Value
Derivative financial instruments - asset	1,976	36,050
Derivative financial instruments - liability	4,336	514
Derivative deferred premiums - liability	0	0
Estimate of Fair Value Measurement | Level 3 | Assets and Liabilities Measured at Fair Value on a Recurring Basis
Fair Value
Derivative financial instruments - asset	0	0
Derivative financial instruments - liability	0	0
Derivative deferred premiums - liability	$ 5,449	$ 9,973

Fair Value Disclosures Summary

Fair Value Disclosures Summary of Changes in assets (liabilities) - Level 3 (Details) - Level 3 - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Balance of Lever 3 at beginning of period	$ (9,973)	$ 0
Derivative deferred premiums - purchases	(516)	(11,914)
Derivative deferred premiums - settlements	5,040	1,941
Balance of Lever 3 at end of period	$ (5,449)	$ (9,973)

Asset Retirement Obligations -

Asset Retirement Obligations - Changes in Asset Retirement Obligations (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in ARO obligations
Asset retirement obligation - beginning of period	$ 12,679	$ 7,363
Liabilities incurred for new wells and interest	747	42
Liabilities settled upon plugging and abandoning wells	0	(40)
Liabilities removed upon sale of wells	(2,827)	0
Revision of estimates	155	4,882
Accretion expense	577	432	$ 250
Asset retirement obligation - end of period	$ 11,331	$ 12,679	$ 7,363

Debt - Schedule of Debt (Detail

Debt - Schedule of Debt (Details) - Revolving Credit Facility - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Revolving credit facility (matures November 2018)	$ 122,000	$ 180,000
Current portion	0	30,000
Long-term debt	$ 122,000	$ 150,000

Debt - Borrowings Outstanding (

Debt - Borrowings Outstanding (Details) - USD ($) $ in Thousands	Dec. 31, 2016	Dec. 31, 2015
Revolving Credit Facility
Line of Credit Facility [Line Items]
Revolving credit facility (matures November 2018)	$ 122,000	$ 180,000

Debt - Credit Facility Effectiv

Debt - Credit Facility Effective Rates (Details) - Revolving Credit Facility	12 Months Ended
	Dec. 31, 2016
Line of Credit Facility [Line Items]
Average effective rate	3.92%
Federal Funds Effective Swap Rate
Line of Credit Facility [Line Items]
Federal funds effective rate	0.50%
LIBOR
Line of Credit Facility [Line Items]
Federal funds effective LIBOR	1.00%
Minimum
Line of Credit Facility [Line Items]
Margin	1.00%
Unused portion of borrowing base, percentage fee	0.375%
Minimum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin rate	2.00%
Maximum
Line of Credit Facility [Line Items]
Margin	2.75%
Unused portion of borrowing base, percentage fee	0.50%
Maximum | LIBOR
Line of Credit Facility [Line Items]
Applicable margin rate	3.75%

Debt - Redetermination Details

Debt - Redetermination Details (Details) - USD ($)	Aug. 11, 2016	May 31, 2016	May 31, 2016	Nov. 30, 2015	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jul. 28, 2016	Oct. 31, 2015	Apr. 30, 2015	Mar. 31, 2015
Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity	$ 140,000,000	$ 163,000,000	$ 163,000,000	$ 190,000,000			$ 140,000,000	$ 105,000,000	$ 220,000,000	$ 220,000,000	$ 240,000,000
Debt Issuance Cost				700,000
LIne of credit overadvance		53,000,000	$ 53,000,000
Required monthly principal payments		$ 1,900,000
Percentage of collateral coverage of proved reserves		90.00%	95.00%
Percentage of PDP reserves		100.00%
Revolving Credit Facility, Conforming Tranche | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity		$ 110,000,000	$ 110,000,000	165,000,000
Monthly commitment payment				2,500,000
Revolving Credit Facility, Non-conforming Tranche | Revolving Credit Facility
Line of Credit Facility [Line Items]
Line of credit facility, maximum borrowing capacity				$ 25,000,000
August 2016 Amended Credit Agreement | Revolving Credit Facility
Line of Credit Facility [Line Items]
Period to extend collateral coverage	30 days
Commodity Contract
Line of Credit Facility [Line Items]
Minimum coverage of projected production (percent)							80.00%
Commodity Contract | Scenario, Forecast
Line of Credit Facility [Line Items]
Minimum coverage of projected production (percent)						50.00%
Commodity Contract | Scenario, Forecast | August 2016 Amended Credit Agreement | Revolving Credit Facility
Line of Credit Facility [Line Items]
Minimum coverage of projected production (percent)					50.00%	75.00%
2016 Projected monthly production | Commodity Contract | Revolving Credit Facility
Line of Credit Facility [Line Items]
Minimum coverage of projected production (percent)							80.00%
2017 Projected monthly production | Commodity Contract | Revolving Credit Facility
Line of Credit Facility [Line Items]
Minimum coverage of projected production (percent)							50.00%
2017 Projected monthly production | Commodity Contract | August 2016 Amended Credit Agreement
Line of Credit Facility [Line Items]
Minimum coverage of projected production (percent)							75.00%

Commitment and Contingencies Re

Commitment and Contingencies Rent Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Lease expense	$ 0.4	$ 0.4	$ 0.3

Commitment and Contingencies -

Commitment and Contingencies - Additional Information (Detail) $ in Thousands	Dec. 31, 2016USD ($)
Other Commitments
2,017	$ 490
2,018	490
2,019	413
2,020	418
2,021	423
Total	$ 2,234

Commitment and Contingencies Em

Commitment and Contingencies Employment agreements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Minimum
Other Commitments
Employee termination payments	$ 0.4
Maximum
Other Commitments
Employee termination payments	$ 0.8

Equity - Common Units (Details)

Equity - Common Units (Details) - USD ($) $ in Millions	May 05, 2015	Dec. 31, 2016	Dec. 31, 2015
Equity [Abstract]
Limited partners, units outstanding (in shares)		29,912,230	29,724,890
Limited partnership interest		98.80%
Maximum proceeds under equity distribution agreement - suspended	$ 50

Equity - Preferred Units (Detai

Equity - Preferred Units (Details)	Aug. 11, 2016USD ($)$ / sharesshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Class of Stock [Line Items]
Preferred units issued (in shares) | shares	11,627,906
Proceeds from sale of convertible preferred units, net of offering costs	$ 25,000,000	$ 24,646,000	$ 0	$ 0
Price per share for preferred units (in dollars per share) | $ / shares	$ 2.15
Days after quarter end distribution paid	45 days
Conversion period	5 years
Conversion basis (percent)	100.00%
Preferred units conversion request	$ 1,000,000
Number of days within closing date	90 days
Number of days after closing date	180 days
Threshold for piggyback registration rights (at least)	$ 1,000,000
Threshold for demand registration rights (at least)	$ 5,000,000
Proceeds from issuance of preferred stock		24,600,000
Issuance costs		400,000
Net proceeds allocated, fair value basis, to Preferred Units		18,600,000
Allocation of value to beneficial conversion feature of Class A convertible preferred units		$ 6,047,000
Accretion period for beneficial conversion		5 years
Accretion of beneficial conversion feature of Class A convertible preferred units		$ (470,000)
Preferred Units [Member]
Class of Stock [Line Items]
Conversion ratio		1
Cash Dividends
Class of Stock [Line Items]
Dividend rate (percent)	8.00%
In Kind Dividends
Class of Stock [Line Items]
Dividend rate (percent)	10.00%

Equity - Cash Distributions Com

Equity - Cash Distributions Common Unitholders (Detail) - USD ($) $ / shares in Units, $ in Thousands	Aug. 13, 2015	May 14, 2015	Feb. 13, 2015	Dec. 31, 2015
Distribution Made to Limited Partner [Line Items]
Total Distributions				$ 11,266
Cash Distributions Period Covered Oct 1, 2014- Dec 31, 2014
Distribution Made to Limited Partner [Line Items]
Date Paid			Feb. 13, 2015
Distribution per Unit			$ 0.125
Total Distributions			$ 3,752
Cash Distributions Period Covered Jan 1, 2015- Mar 31, 2015
Distribution Made to Limited Partner [Line Items]
Date Paid		May 14, 2015
Distribution per Unit		$ 0.125
Total Distributions		$ 3,752
Cash Distributions Period Covered Apr 1, 2015- Jun 30, 2015
Distribution Made to Limited Partner [Line Items]
Date Paid	Aug. 13, 2015
Distribution per Unit	$ 0.125
Total Distributions	$ 3,762

Equity - Cash Distributions Pre

Equity - Cash Distributions Preferred Unitholders (Details) - USD ($) $ / shares in Units, $ in Thousands	Nov. 14, 2016	Aug. 11, 2016	Dec. 31, 2016
Preferred Units [Line Items]
Preferred units distribution accrued			$ 500
Cash Distributions Period Covered Aug 11, 2016 - Sep 30, 2016
Preferred Units [Line Items]
Date Paid	Nov. 14, 2016
Distribution per Unit	$ 0.024
Total Distributions	$ 279
Cash Dividends
Preferred Units [Line Items]
Dividend rate (percent)		8.00%
In Kind Dividends
Preferred Units [Line Items]
Dividend rate (percent)		10.00%

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - Mid-Con Energy Operating - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Services agreement	$ 3,403	$ 3,654	$ 3,775
Operating agreements	6,221	8,332	6,120
Oilfield services	3,058	3,653	3,749
Costs and Expenses, Related Party	$ 12,682	$ 15,639	$ 13,644

Related Party Transactions Affi

Related Party Transactions Affiliate Transactions (Details) - Affiliated Entity - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Other transactions of related party	$ 1.1	$ 0.5
Joint interest billing payable	0.5	0.1
Operating services payable	$ 0.6	$ 0.4

Credit Risk - Additional Inform

Credit Risk - Additional Information (Detail) - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Sales Revenue, Net
Concentration Risk [Line Items]
Concentration risk, percentage	94.00%	75.00%	74.00%
Accounts Receivable
Concentration Risk [Line Items]
Concentration risk, percentage	95.00%	73.00%	45.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Feb. 22, 2017	Jan. 25, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsequent Event
Subsequent Event [Line Items]
Preferred Stock, Dividends, Per Share, Cash Paid		$ 0.043
Preferred Units Distributions Paid		$ 0.5
Unrestricted Common Units
Subsequent Event [Line Items]
Units granted			73,932	274,550
Unrestricted Common Units | Subsequent Event
Subsequent Event [Line Items]
Units granted	25,400
Equity-Settled Phantom Units
Subsequent Event [Line Items]
Units granted			374,500	115,500
Equity-Settled Phantom Units | Subsequent Event
Subsequent Event [Line Items]
Units granted	9,000
Share-based Compensation Award, Tranche One | Equity-Settled Phantom Units
Subsequent Event [Line Items]
Units granted			347,500	69,000
Share-based Compensation Award, Tranche Two | Equity-Settled Phantom Units
Subsequent Event [Line Items]
Units granted			27,000	46,500

Supplementary Information - Sch

Supplementary Information - Schedule of Quarterly Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Oil and natural gas sales	$ 15,642		$ 14,410		$ 14,777		$ 11,269		$ 16,239		$ 18,493		$ 21,611		$ 17,571
Gain (loss) on derivatives, net	(4,238)		(444)		(10,088)		2,568		9,822		19,771		(8,871)		1,644		$ (12,202)	$ 22,366	$ 29,361
Total revenues	11,404		13,966		4,689		13,837		26,061		38,264		12,740		19,215		43,896	96,280	126,272
Gain (loss) on sale of properties	(43)		(530)		13		0										(560)	0	0
Total expenses	14,672	[1]	15,857	[1]	20,471	[1]	17,150	[1]	84,022	[1]	63,742	[1]	20,684	[1]	23,327	[1]	60,599	185,033	99,062
Net loss	$ (3,311)		$ (2,421)		$ (15,769)		$ (3,313)		$ (57,961)		$ (25,478)		$ (7,944)		$ (4,112)		$ (24,814)	$ (95,495)	$ 22,492
Net loss per limited partner unit (basic and diluted) (in dollars per share)	$ (0.14)		$ (0.09)		$ (0.52)		$ (0.11)		$ (1.93)		$ (0.85)		$ (0.26)		$ (0.14)		$ (0.86)	$ (3.18)	$ 0.98
[1]	Includes the following expenses: lease operating, production taxes, impairment, depreciation, depletion and amortization, accretion, general and administrative and net other income (expense).

Supplementary Information - Sup

Supplementary Information - Supplementary Oil and Natural Gas Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property acquisition costs:
Proved	$ 18,722	$ 1	$ 241,355
Unproved	0	0	0
Exploration	0	0	0
Development	6,963	13,415	34,320
Asset retirement obligations	902	4,924	3,171
Total costs incurred	$ 26,587	$ 18,340	$ 278,846

Supplementary Information - Cha

Supplementary Information - Changes in Estimated Proved Oil and Natural Gas Reserves (Detail)		12 Months Ended
		Dec. 31, 2016MBoeMBblsMMcf		Dec. 31, 2015MBoeMBblsMMcf		Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Beginning balance | MBoe		22,252		23,230		13,934
Revisions of previous estimates(1) | MBoe		14	[1]	739	[1]	364
Extensions, discoveries and other additions | MBoe		0		0		1,250	76
Purchases of reserves in place | MBoe		1,552	[2]	1		8,820
Sales of reserves in place | MBoe	[3]	(3,109)
Production | MBoe		(1,478)		(1,718)		(1,138)
Ending balance | MBoe		19,231		22,252		23,230	13,934
Proved developed reserves, MBoe | MBoe		12,423		15,162		17,933
Proved undeveloped reserves, MBoe | MBoe		6,808		7,090		5,297
Oil
Proved Developed and Undeveloped Reserves, Oil [Roll Forward]
Beginning balance | MBbls		21,114		22,140		13,714
Revisions of previous estimates(1) | MBbls		58	[1]	596	[1]	211
Extensions, discoveries and other additions | MBbls		0		0		1,241
Purchases of reserves in place | MBbls		1,517	[2]	1		8,086
Sales of reserves in place | MBbls	[3]	(3,093)
Production | MBbls		(1,386)		(1,623)		(1,112)
Ending balance | MBbls		18,210		21,114		22,140	13,714
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Proved developed reserves, Oil | MBbls		11,733		14,368		17,046
Proved undeveloped reserves, Oil | MBbls		6,477		6,746		5,094
Natural Gas
Proved Developed and Undeveloped Reserves, Gas [Roll Forward]
Beginning balance | MMcf		6,827		6,542		1,321
Revisions of previous estimates(1) | MMcf		(262)	[1]	856	[1]	924
Extensions, discoveries and other additions | MMcf		0		0		52
Purchases of reserves in place | MMcf		211	[2]	0		4,402
Sales of reserves in place | MMcf	[3]	(98)
Production | MMcf		(554)		(571)		(157)
Ending balance | MMcf		6,124		6,827		6,542	1,321
Proved Developed and Undeveloped Reserves, MBoe [Roll Forward]
Proved developed reserves, Gas | MMcf		4,141		4,762		5,327
Proved undeveloped reserves, Gas | MMcf		1,983		2,065		1,215
[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]	Represents the purchase of proved reserves as part of our Permian Bolt-On acquisition.
[3]	Decrease due to the sale of our Hugoton core area oil and natural gas properties.

Supplementary Information - Add

Supplementary Information - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2016MBoe$ / Bbls$ / MMBTU$ / Mcf		Dec. 31, 2015MBoe$ / Bbls$ / MMBTU$ / Mcf	Dec. 31, 2014MBoe$ / Bbls$ / MMBTU$ / Mcf	Dec. 31, 2013MBoe
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Extensions, discoveries and other additions		0		0	1,250	76
Proved Developed and Undeveloped Reserves, Effect of Commodity Price		1,801		4,084
Proved Developed and Undeveloped Reserves, Improved Recovery		569		1,417
Proved Undeveloped Reserves, Transfers				994
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate		1,246		3,405
Purchases of reserves in place		1,552	[1]	1	8,820
Sales of reserves in place	[2]	(3,109)
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 | $ / Bbls		42.75		50.28	94.99
Average adjusted prices utilized in calculating proved reserves | $ / Bbls		40.03		47.23	92.45
Natural Gas
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Representative SEC Price | $ / MMBTU		2.49		2.58	4.35
Average adjusted prices utilized in calculating proved reserves | $ / Mcf		1.99		2.02	5.67
[1]	Represents the purchase of proved reserves as part of our Permian Bolt-On acquisition.
[2]	Decrease due to the sale of our Hugoton core area oil and natural gas properties.

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, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Future cash inflows	$ 741,077	$ 1,011,096	$ 2,084,005
Future production costs	(389,138)	(581,314)	(825,318)
Future development costs, including abandonment costs	(65,195)	(109,669)	(76,783)
Future net cash flow	286,744	320,113	1,181,904
10% discount for estimated timing of cash flow	(129,459)	(128,693)	(517,627)
Standardized measure of discounted cash flow	$ 157,285	$ 191,420	$ 664,277	$ 391,263

Supplementary Information - C75

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, 2016	Dec. 31, 2015	Dec. 31, 2014
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 period	$ 191,420	$ 664,277	$ 391,263
Changes in the year resulting from:
Sales, less production costs	(30,513)	(36,836)	(64,495)
Revisions of previous quantity estimates	133	8,047	11,712
Extensions, discoveries and improved recovery	0	0	44,727
Net change in prices and production costs	(16,138)	(454,669)	22,068
Net change in income taxes	0	0	0
Changes in estimated future development costs	22,685	(6,080)	(18,125)
Previously estimated development costs incurred during the period	3,526	8,103	22,526
Purchases of reserves in place	22,223	19	264,921
Sales of reserves in place	(11,124)	0	0
Accretion of discount	19,142	66,428	39,126
Timing differences and other	(44,069)	(57,869)	(49,446)
Standardized measure of discounted future net cash flow, end of year	$ 157,285	$ 191,420	$ 664,277