Evolve Transition Infrastructure (SNMP) 10-Q 8 Aug 19 2019 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2019	Aug. 08, 2019
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2019
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Entity Registrant Name	Sanchez Midstream Partners LP
Entity Central Index Key	0001362705
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Ex Transition Period	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		20,089,827
Entity Current Reporting Status	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Revenues
Gathering and transportation lease revenues	$ 15,969	$ 13,168	$ 32,226	$ 25,486
Total revenues	21,855	17,039	39,345	35,575
Operating expenses:
Lease operating expenses	2,065	2,007	3,780	3,978
Transportation operating expenses	3,048	3,071	5,724	5,918
Production taxes	141	287	324	609
General and administrative expenses	4,171	6,919	8,920	12,084
Unit-based compensation expense	175	1,347	810	2,785
Gain on sale of assets		(2,388)		(2,388)
Depreciation, depletion and amortization	6,174	6,545	12,603	13,173
Asset impairments	0	0	0	0
Accretion expense	126	123	259	249
Total operating expenses	15,900	17,911	32,420	36,408
Other (income) expense
Interest expense, net	2,814	2,780	5,600	5,379
Earnings from equity investments	(791)	(3,111)	(2,233)	(7,383)
Other (income) expense	(21)	1,254	(67)	1,524
Total other (income) expenses	2,002	923	3,300	(480)
Total expenses	17,902	18,834	35,720	35,928
Income (loss) before income taxes	3,953	(1,795)	3,625	(353)
Income tax expense	76		122
Net income (loss)	3,877	(1,795)	3,503	(353)
Less:
Preferred unit paid-in-kind distributions	(10,605)	(3,500)	(10,605)	(3,500)
Preferred unit distributions		(7,000)	(8,838)	(15,750)
Preferred unit amortization	(745)	(568)	(1,442)	(1,099)
Net loss attributable to common unitholders	$ (7,473)	$ (12,863)	$ (17,382)	$ (20,702)
Net loss per unit
Common units - Basic and Diluted (in dollars per share)	$ (0.42)	$ (0.85)	$ (1.02)	$ (1.38)
Weighted Average Units Outstanding, Common Units - Basic and Diluted (in units)	17,684,563	15,199,779	16,968,736	14,997,058
Common units
Other (income) expense
Net income (loss)	$ 3,877	$ (1,795)
Natural gas sales
Revenues
Revenues	256	226	$ 366	$ 699
Oil sales
Revenues
Revenues	3,811	1,584	3,072	5,046
Natural gas liquid product
Revenues
Revenues	117	400	296	995
Gathering and transportation
Revenues
Revenues	$ 1,702	$ 1,661	$ 3,385	$ 3,349

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 1,253	$ 2,934
Accounts receivable	167	277
Accounts receivable - related entities	6,520	6,700
Prepaid expenses	1,432	931
Fair value of commodity derivative instruments	661	3,044
Total current assets	10,033	13,886
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,449	112,173
Gathering and transportation assets	186,845	186,406
Less: accumulated depreciation, depletion, amortization and impairment	(106,094)	(100,245)
Oil and natural gas properties and equipment, net	193,200	198,334
Other assets
Intangible assets, net	151,976	158,706
Fair value of commodity derivative instruments	59	876
Equity investments	108,776	114,465
Other non-current assets	352	418
Total assets	464,396	486,685
Current liabilities
Accounts payable and accrued liabilities	3,964	4,678
Accounts payable and accrued liabilities - related entities	5,821	5,641
Royalties payable	359	359
Short-term debt, net of debt issuance costs	171,153
Fair value of commodity derivative instruments	541	6
Other liabilities	139	125
Total current liabilities	181,977	10,809
Other liabilities
Asset retirement obligation	6,631	6,200
Long-term debt, net of debt issuance costs		178,582
Fair value of commodity derivative instruments	157
Other liabilities	5,802	5,857
Total other liabilities	12,590	190,639
Total liabilities	194,567	201,448
Commitments and contingencies (See Note 12)
Mezzanine equity
Class B preferred units, 31,310,896 units issued and outstanding as of March 31, 2019 and December 31, 2018	353,067	349,857
Partners' deficit
Common units, 19,188,086 and 16,486,239 units issued and outstanding as of June 30, 2019 and December 31, 2018, respectively	(83,238)	(64,620)
Total partners' deficit	(83,238)	(64,620)
Total liabilities and partners' capital	$ 464,396	$ 486,685

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - shares	Jun. 30, 2019	Dec. 31, 2018
Condensed Consolidated Balance Sheets
Class B preferred units, issued	31,310,896	31,310,896
Class B preferred units, outstanding	31,310,896	31,310,896
Units, issued	19,188,086	16,486,239
Units, outstanding	19,188,086	16,486,239

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Cash flows from operating activities:
Net income (loss)	$ 3,503	$ (353)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	5,873	6,443
Amortization of debt issuance costs	578	265
Accretion expense	259	249
Distributions from equity investments	8,164	13,101
Equity earnings in affiliate	(2,233)	(7,383)
Gain on sale of assets		(2,388)
Net loss on commodity derivative contracts	3,524	5,653
Net cash settlements received (paid) on commodity derivative contracts	469	(706)
Unit-based compensation	810	2,785
(Gain) loss on earnout derivative	(63)	1,524
Amortization of intangible assets	6,730	6,730
Changes in Operating Assets and Liabilities:
Accounts receivable	23	185
Accounts receivable - related entities	176	6,541
Prepaid expenses	(501)	83
Other assets	42	43
Accounts payable and accrued liabilities	2,585	7,687
Accounts payable and accrued liabilities- related entities	176	(3,376)
Other long-term liabilities	22	(1)
Net cash provided by operating activities	30,137	37,082
Cash flows from investing activities:
Development of oil and natural gas properties	(103)	(205)
Proceeds from sale of assets		5,896
Construction of gathering and transportation assets	(357)	(1,700)
Purchases of and contributions to equity affiliates	(242)	(2,713)
Net cash used in investing activities	(702)	1,278
Cash flows from financing activities:
Payments for offering costs		(50)
Repayment of debt	(8,000)	(5,000)
Distributions to common unitholders	(5,216)	(13,614)
Class B preferred unit cash distributions	(17,675)	(17,500)
Units tendered by SOG employees for tax withholdings	(218)
Debt issuance costs	(7)	(33)
Net cash used in financing activities	(31,116)	(36,197)
Net increase (decrease) in cash and cash equivalents	(1,681)	2,163
Cash and cash equivalents, beginning of period	2,934	321
Cash and cash equivalents, end of period	1,253	2,484
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	82	341
Cash paid during the period for interest	$ 5,070	$ 4,788

Consolidated Statements of Chan

Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
Partner's Deficit at Dec. 31, 2017	$ (29,308)	$ (29,308)
Partner's Deficit (in shares) at Dec. 31, 2017	14,965,134
Unit-based compensation programs	$ 738	738
Unit-based compensation programs (in shares)	(4,166)
Issuance of common units, net of offering costs	$ 2,292	2,292
Issuance of common units, net of offering costs (in shares)	210,978
Cash distributions to common unit holders	$ (6,746)	(6,746)
Distributions - Class B preferred units	(9,281)	(9,281)
Net (loss) income	1,442	1,442
Partner's Deficit at Mar. 31, 2018	$ (40,863)	(40,863)
Partner's Deficit (in shares) at Mar. 31, 2018	15,171,946
Partner's Deficit at Dec. 31, 2017	$ (29,308)	(29,308)
Partner's Deficit (in shares) at Dec. 31, 2017	14,965,134
Net (loss) income		(353)
Partner's Deficit at Jun. 30, 2018	$ (56,267)	(56,267)
Partner's Deficit (in shares) at Jun. 30, 2018	16,000,554
Partner's Deficit at Mar. 31, 2018	$ (40,863)	(40,863)
Partner's Deficit (in shares) at Mar. 31, 2018	15,171,946
Unit-based compensation programs	$ 2,047	2,047
Unit-based compensation programs (in shares)	608,394
Issuance of common units, net of offering costs	$ 2,280	2,280
Issuance of common units, net of offering costs (in shares)	220,214
Cash distributions to common unit holders	$ (6,868)	(6,868)
Distributions - Class B preferred units	(11,068)	(11,068)
Net (loss) income	(1,795)	(1,795)
Partner's Deficit at Jun. 30, 2018	$ (56,267)	(56,267)
Partner's Deficit (in shares) at Jun. 30, 2018	16,000,554
Partner's Deficit at Dec. 31, 2018	$ (64,620)	(64,620)
Partner's Deficit (in shares) at Dec. 31, 2018	16,486,239
Unit-based compensation programs	$ 815	815
Unit-based compensation programs (in shares)	978,076
Issuance of common units, net of offering costs	$ 1,355	1,355
Issuance of common units, net of offering costs (in shares)	787,750
Cash distributions to common unit holders	$ (2,471)	(2,471)
Distributions - Class B preferred units	(9,535)	(9,535)
Net (loss) income	(374)	(374)
Partner's Deficit at Mar. 31, 2019	$ (75,011)	(75,011)
Partner's Deficit (in shares) at Mar. 31, 2019	18,252,065
Partner's Deficit at Dec. 31, 2018	$ (64,620)	(64,620)
Partner's Deficit (in shares) at Dec. 31, 2018	16,486,239
Net (loss) income		3,503
Partner's Deficit at Jun. 30, 2019	$ (83,238)	(83,238)
Partner's Deficit (in shares) at Jun. 30, 2019	19,188,086
Adoption of accounting standards	$ (181)	(181)
Partner's Deficit at Mar. 31, 2019	$ (75,011)	(75,011)
Partner's Deficit (in shares) at Mar. 31, 2019	18,252,065
Units tendered by SOG employees for tax withholding	$ (218)	(218)
Units tendered by SOG employees for tax withholding (in shares)	(84,711)
Unit-based compensation programs	$ 175	175
Unit-based compensation programs (in shares)	133,463
Issuance of common units, net of offering costs	$ 2,034	2,034
Issuance of common units, net of offering costs (in shares)	887,269
Cash distributions to common unit holders	$ (2,745)	(2,745)
Distributions - Class B preferred units	(11,350)	(11,350)
Net (loss) income	3,877	3,877
Partner's Deficit at Jun. 30, 2019	$ (83,238)	$ (83,238)
Partner's Deficit (in shares) at Jun. 30, 2019	19,188,086

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Partners’ Capital (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2018	Mar. 31, 2018
Consolidated Statements of Changes in Partners’ Capital
Offering costs	$ 0.1	$ 0.1

Organization And Business

Organization And Business	6 Months Ended
	Jun. 30, 2019
Organization And Business
Organization And Business	1. ORGANIZATION AND BUSINESS Organization We are a growth-oriented publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other energy-related assets in North America. We have ownership stakes in oil and natural gas gathering systems, natural gas pipelines and natural gas processing facilities, all located in the Western Eagle Ford in South Texas. We also own production assets in Texas and Louisiana. We have entered into a shared services agreement (the “Services Agreement”) with Manager, pursuant to which Manager provides services we require to conduct our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, acquisition, disposition and financing services. On June 2, 2017, we changed our name to Sanchez Midstream Partners LP from Sanchez Production Partners LP. Manager owns our general partner and all of our incentive distribution rights. Our common units are currently listed on the NYSE American under the symbol “SNMP.”

Basis Of Presentation And Summa

Basis Of Presentation And Summary Of Significant Accounting Policies	6 Months Ended
	Jun. 30, 2019
Basis Of Presentation And Summary Of Significant Accounting Policies
Basis of Presentation and Significant Accounting Policies	2. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP”). These unaudited condensed consolidated financial statements include the accounts of us and our wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Our business consists of two reportable segments: Production and Midstream. Our Midstream segment includes Western Catarina Midstream (defined in Note 10 “Intangible Assets”), the Carnero JV (defined in Note 11 “Investments”) and Seco Pipeline. Our Production segment consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments. These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the SEC. Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with GAAP, have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on March 7, 2019. Recent Accounting Pronouncements In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In June 2018, the FASB issued ASU 2018-07 “Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of Topic 718, Compensation – Stock Compensation, to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted this ASU effective January 1, 2019, which resulted in the remeasurement of our outstanding unvested awards as of January 1, 2019 and will change the expense recorded for equity awards going forward. The adoption of this standard resulted in an approximately $0.2 million charge to retained earnings. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in more timely recognition of losses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018. Additionally, in July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842 (Leases),” which provides narrow amendments to clarify how to apply certain aspects of ASU 2016-02. The Partnership elected the practical expedients disclosed in ASU 2018-10. The effective date in ASU 2018-10 is the same as that of ASU 2016-02. The standards update the previous lease guidance by requiring the recognition of a right-of-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. The Partnership adopted this standard effective January 1, 2019. The adoption of this standard did not have a material impact on our condensed consolidated financial statements. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. Estimates The condensed consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes therein. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Revenue Recognition

Revenue Recognition	6 Months Ended
	Jun. 30, 2019
Revenue Recognition
Revenue Recognition	3. REVENUE RECOGNITION Revenue from Contracts with Customers We account for revenue from contracts with customers in accordance with ASC 606. The unit of account in ASC 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. ASC 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) the performance obligation is satisfied. Disaggregation of Revenue We disaggregate revenue based on type of revenue and product type. In selecting the disaggregation categories, we considered a number of factors, including disclosures presented outside the financial statements, such as in our earnings release and investor presentations, information reviewed internally for evaluating performance, and other factors used by the Partnership or the users of its financial statements to evaluate performance or allocate resources. We have concluded that disaggregating revenue by type of revenue and product type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. Midstream Segment The Seco Pipeline Transportation Agreement is the only contract that we account for under ASC 606. The Catarina Midstream Gathering Agreement is classified as an operating lease and is accounted for under ASC 842, Leases, and is reported as gathering and transportation lease revenue in our condensed consolidated statements of operations. Both of these contracts are further discussed in Note 13 “Related Party Transactions.” We account for income from our unconsolidated equity method investments as earnings from equity investments in our condensed consolidated statements of operations. Earnings from these equity method investments are further discussed in Note 11 “Investments.” Production Segment Our oil, natural gas and NGL revenue is marketed and sold on our behalf by the respective asset operators. We are not party to the contracts with the third-party customers. However, we are party to joint operating agreements, which we account for under ASC 808, and revenue for these arrangements is recognized based on the information provided to us by the operators. We additionally recognize and present changes in the fair value of our commodity derivative instruments within natural gas sales and oil sales in the condensed consolidated statements of operations. As this income is accounted for under ASC 815, Derivatives and Hedging, it is not subject to ASC 606. We recognized aggregate revenue of $21.9 million for the three months ended June 30, 2019. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Three Months Ended June 30, 2019 Production Midstream Total Revenues: Natural gas sales $ 256 $ — $ 256 Oil sales 3,811 — 3,811 Natural gas liquid sales 117 — 117 Gathering and transportation sales — 1,702 1,702 Gathering and transportation lease revenues — 15,969 15,969 Total revenues $ 4,184 $ 17,671 $ 21,855 We recognized aggregate revenue of $39.3 million for the six months ended June 30, 2019. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Six Months Ended June 30, 2019 Production Midstream Total Revenues: Natural gas sales $ 366 $ — $ 366 Oil sales 3,072 — 3,072 Natural gas liquid sales 296 — 296 Gathering and transportation sales — 3,385 3,385 Gathering and transportation lease revenues — 32,226 32,226 Total revenues $ 3,734 $ 35,611 $ 39,345 Performance Obligations Under the Seco Pipeline Transportation Agreement, we agreed to provide transportation services of certain quantities of natural gas from the receipt point to the delivery point. Each MMBtu of natural gas transported is distinct and the transportation services performed on each distinct molecule of product is substantially the same in nature. As such, we applied the series guidance and treat these services as a single performance obligation satisfied over time using volumes delivered as the measure of progress. The Seco Pipeline Transportation Agreement requires payment within 30 days following the calendar month of delivery. The Seco Pipeline Transportation Agreement contains variable consideration in the form of volume variability. As the distinct goods or services (rather than the series) are considered for the purpose of allocating variable consideration, we have taken the optional exception under ASC 606 which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606 have been met. Under this exception, neither estimation of variable consideration nor disclosure of the transaction price allocated to the remaining performance obligations is required. Revenue is alternatively recognized in the period that control is transferred to the customer and the respective variable component of the total transaction price is resolved. For forms of variable consideration that are not associated with a specific volume (such as late payment fees) and thus do not meet allocation exception, estimation is required. These fees, however, are immaterial to our condensed consolidated financial statements and have a low probability of occurrence. As significant reversals of revenue due to this variability are not probable, no estimation is required. Contract Balances Under our sales contracts, we invoice customers after performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under

Acquisitions and Divestitures

Acquisitions and Divestitures	6 Months Ended
	Jun. 30, 2019
Acquisitions and Divestitures
Acquisitions and Divestitures	4. ACQUISITIONS AND DIVESTITURES Louisiana Divestiture In September 2018, we entered into a purchase and sale agreement to sell certain non-operated production assets located in Louisiana for cash consideration of approximately $1.3 million (the “Louisiana Divestiture”). The Louisiana Divestiture closed on October 22, 2018, and we recorded a gain of approximately $0.6 million on the sale. Briggs Divestiture In April 2018, we entered into a purchase and sale agreement to sell specified wellbores and related assets and interests in La Salle County Texas (the “Briggs Assets”) for cash consideration of approximately $4.2 million (the “Briggs Divestiture”). In addition, other than limited obligations that we retained, the buyer of the Briggs Assets agreed to assume all obligations relating to the Briggs Assets, including all plugging and abandonment costs that may arise on or after March 1, 2018. The Briggs Divestiture closed April 30, 2018, and we recorded a gain of approximately $1.8 million on the sale. Cola Divestiture In April 2018, we entered into multiple purchase and sale agreements to sell certain non-operated production assets located in Oklahoma for total cash consideration of approximately $1.0 million (collectively, the “Cola Divestiture”). Each of the divestitures closed by May 8, 2018, and we recorded a total gain of approximately $1.1 million on the sales.

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2019
Fair Value Measurements
Fair Value Measurements	5. FAIR VALUE MEASUREMENTS Measurements of fair value of derivative instruments are classified according to the fair value hierarchy, which prioritizes the inputs to the valuation techniques used to measure fair value. 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. Fair value measurements are classified and disclosed in one of the following categories: Level 1: Measured based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Active markets are considered those in which transactions for the assets or liabilities occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2: Measured based on quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Substantially all of these inputs are observable in the marketplace throughout the term of the instrument, can be derived from observable data, or supported by observable levels at which transactions are executed in the marketplace. Level 3: Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement . Management's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels. The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2019 (in thousands): Fair Value Measurements at June 30, 2019 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 22 $ — $ 22 Midstream derivative instrument Earnout derivative liability — — (5,793) (5,793) Total $ — $ 22 $ (5,793) $ (5,771) The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2018 (in thousands): Fair Value Measurements at December 31, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 3,914 $ — $ 3,914 Midstream derivative instrument Earnout derivative liability — — (5,856) (5,856) Total $ — $ 3,914 $ (5,856) $ (1,942) As of June 30, 2019 and December 31, 2018, the estimated fair value of cash and cash equivalents, accounts receivable, other current assets and current liabilities approximated their carrying value due to their short-term nature. Fair Value on a Non-Recurring Basis The Partnership follows the provisions of Topic 820-10 for nonfinancial assets and liabilities measured at fair value on a non-recurring basis. The fair value measurements of assets acquired and liabilities assumed are based on inputs that are not observable in the market and therefore represent Level 3 inputs under the fair value hierarchy. We periodically review oil and natural gas properties and related equipment for impairment when facts and circumstances indicate that their carrying values may not be recoverable. A reconciliation of the beginning and ending balances of the Partnership’s asset retirement obligations is presented in Note 9 “Asset Retirement Obligation.” We had no non-recurring fair value measurements of our assets as of June 30, 2019 and December 31, 2018. The fair values of oil and natural gas properties and related equipment were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties and related equipment include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; (v) estimated throughput; and (vi) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Fair Value of Financial Instruments The estimated fair value amounts of financial instruments have been determined using available market information and valuation methodologies described below. We prioritize the use of the highest level inputs available in determining fair value such that fair value measurements are determined using the highest and best use as determined by market participants and the assumptions that they would use in determining fair value. Credit Agreement – We believe that the carrying value of our Credit Agreement (defined in Note 7 “Long-Term Debt”) approximates its fair value because the interest rates on the debt approximate market interest rates for debt with similar terms. The debt is classified as a Level 2 input in the fair value hierarchy and represents the amount at which the instrument could be valued in an exchange during a current transaction between willing parties. The Credit Agreement is discussed further in Note 7 “Long-Term Debt.” Derivative Instruments – The income valuation approach, which involves discounting estimated cash flows, is primarily used to determine recurring fair value measurements of our derivative instruments classified as Level 2 inputs. Our commodity derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of oil and natural gas prices and an appropriate discount rate. Our interest rate derivatives are valued using the terms of the individual derivative contracts with our counterparties, expected future levels of the LIBOR interest rates and an appropriate discount rate. We did not have any interest rate derivatives as of June 30, 2019. Earnout Derivative – As part of the Carnero Gathering Transaction (defined in Note 11 “Investments”), we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. The earnout derivative was valued through the use of a Monte Carlo simulation model which utilized observable inputs such as the earnout price and volume commitment, as well as unobservable inputs related to the weighted probabilities of various throughput scenarios. We have therefore classified the fair value measurements of the earnout derivative as Level 3 and is presented within other liabilities on the condensed consolidated balance sheets. The following table sets forth a reconciliation of changes in the fair value of the Partnership’s earnout derivative liability classified as Level 3 in the fair value hierarchy (in thousands): Six Months Ended Year Ended June 30, 2019 December 31, 2018 Beginning balance $ (5,856) $ (6,402) Gain on earnout derivative 63 546 Ending balance $ (5,793) $ (5,856) Gain included in earnings related to derivatives still held as of June 30, 2019 and December 31, 2018, respectively $ 63 $ 546

Derivative And Financial Instru

Derivative And Financial Instruments	6 Months Ended
	Jun. 30, 2019
Derivative And Financial Instruments
Derivative And Financial Instruments	6. DERIVATIVE AND FINANCIAL INSTRUMENTS To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we periodically enter into derivative contracts with respect to a portion of our projected oil and natural gas production through various transactions that fix or modify the future prices to be realized. These hedging activities are intended to support oil and natural gas prices at targeted levels and to manage exposure to oil and natural gas price fluctuations. It is never our intention to enter into derivative contracts for speculative trading purposes. Under Topic 815, “Derivatives and Hedging,” all derivative instruments are recorded on the condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil sales in the condensed consolidated statements of operations. As of June 30, 2019, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities: Fixed Price Basis Swaps – West Texas Intermediate (WTI) Three Months Ended (volume in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2019 — $ — — $ — 57,024 $ 60.48 54,824 $ 60.52 111,848 $ 60.50 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 312,432 Fixed Price Swaps – NYMEX (Henry Hub) Three Months Ended (volume in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2019 — $ — — $ — 112,032 $ 2.85 108,552 $ 2.85 220,584 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 623,032 The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the six months ended June 30, 2019 and the year ended December 31, 2018 (in thousands): Six Months Ended Year Ended June 30, 2019 December 31, 2018 Beginning fair value of commodity derivatives $ 3,914 $ 1,231 Net gains (losses) on crude oil derivatives (3,677) 1,400 Net gains (losses) on natural gas derivatives 153 (84) Net settlements paid (received) on derivative contracts: Oil (381) 1,330 Natural gas 13 37 Ending fair value of commodity derivatives $ 22 $ 3,914 The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, Derivative Type in Income 2019 2018 2019 2018 Commodity – Mark-to-Market Oil sales $ 807 $ (3,717) $ (3,677) $ (5,657) Commodity – Mark-to-Market Natural gas sales 193 2 153 4 $ 1,000 $ (3,715) $ (3,524) $ (5,653) Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with three counterparties. We generally execute commodity derivative instruments under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. We include a measure of counterparty credit risk in our estimates of the fair values of derivative instruments. As of June 30, 2019 and December 31, 2018, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. Earnout Derivative Refer to Note 5 “Fair Value Measurements.”

Long-Term Debt

Long-Term Debt	6 Months Ended
	Jun. 30, 2019
Long-Term Debt
Long-Term Debt	7. LONG-TERM DEBT We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (“Credit Agreement”). The Credit Agreement provides a maximum commitment of $500.0 million and has a maturity date of March 31, 2020. Borrowings under the Credit Agreement are secured by various mortgages of oil and natural gas properties that we own, as well as various security and pledge agreements among us, certain of our subsidiaries and the administrative agent. Our Credit Agreement is a current liability that matures on March 31, 2020. We expect to refinance or extend the maturity of our Credit Agreement prior to its maturity date. However, we may not be able to refinance or extend the maturity of our Credit Agreement or, if we are able to refinance or extend the maturity, we may not be able to do so with borrowing and debt issue costs, terms, covenants, restrictions, commitment amount or a borrowing base favorable to us. The amount available for borrowing at any one time under the Credit Agreement is limited to the borrowing base for our midstream assets and our oil and natural gas properties. Borrowings under the Credit Agreement are available for direct investment in oil and natural gas properties, acquisitions and working capital and general business purposes. The Credit Agreement has a sub-limit of $15.0 million which may be used for the issuance of letters of credit. The initial borrowing base under the Credit Agreement was $200.0 million. The borrowing base for the credit available for the upstream oil and gas properties is re-determined semi-annually in the second and fourth quarters of the year, and may be re-determined at our request more frequently and by the lenders, in their sole discretion, based on reserve reports as prepared by petroleum engineers, using, among other things, the oil and natural gas pricing prevailing at such time. The borrowing base for the credit available for our midstream properties is generally equal to the rolling four quarter Adjusted EBITDA of our midstream operations, together with the amount of distributions received from the Carnero JV (defined in Note 11 “Investments”) multiplied by 4.5. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. As of June 30, 2019, the borrowing base under the Credit Agreement was $303.1 million, with an elected commitment amount of $210.0 million, and w e had $172.0 million of debt outstanding under the facility, leaving us with $38.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of June 30, 2019. At our election, interest for borrowings under the Credit Agreement are determined by reference to (i) the London interbank rate (“LIBOR”) plus an applicable margin between 2.25% and 3.25% per annum based on utilization or (ii) a domestic bank rate (“ABR”) plus an applicable margin between 1.25% and 2.25% per annum based on utilization plus (iii) a commitment fee of 0.500% per annum based on the unutilized borrowing base. Interest on the borrowings for ABR loans and the commitment fee are generally payable quarterly. Interest on the borrowings for LIBOR loans are generally payable at the applicable maturity date. The Credit Agreement contains various covenants that limit, among other things, our ability to incur certain indebtedness, grant certain liens, merge or consolidate, sell all or substantially all of our assets, make certain loans, acquisitions, capital expenditures and investments, and pay distributions. In addition, we are required to maintain the following financial covenants: · current assets to current liabilities ratio of at least 1.0 to 1.0 at all times; · senior secured net debt to consolidated Adjusted EBITDA ratio for the last twelve months, as of the last day of any fiscal quarter, of not greater than 4.5 to 1.0 if the Adjusted EBITDA of our midstream operations equals or exceeds one-third of total Adjusted EBITDA or 4.0 to 1.0 if the Adjusted EBITDA of our midstream operations is less than one-third of total Adjusted EBITDA; and · minimum interest coverage ratio of at least 2.5 to 1.0 if the Adjusted EBITDA of our midstream operations is greater than one-third of our total Adjusted EBITDA. The Credit Agreement also includes customary events of default, including events of default relating to non-payment of principal, interest or fees, inaccuracy of representations and warranties when made or when deemed to be made, violation of covenants, cross-defaults, bankruptcy and insolvency events, certain unsatisfied judgments, loan documents not being valid and a change in control. A change in control is generally defined as the occurrence of one of the following events: (i) our existing general partner ceases to be our sole general partner or (ii) certain specified persons shall cease to own more than 50% of the equity interests of our general partner or shall cease to control our general partner. If an event of default occurs, the lenders will be able to accelerate the maturity of the Credit Agreement and exercise other rights and remedies. The Credit Agreement limits our ability to pay distributions to unitholders. We have the ability to pay distributions to unitholders from available cash, including cash from borrowings under the Credit Agreement , as long as no event of default exists and provided that no distributions to unitholders may be made if the borrowings outstanding, net of available cash, under the Credit Agreement exceed 90% of the borrowing base, after giving effect to the proposed distribution. Our available cash is reduced by any cash reserves established by the Board for the proper conduct of our business and the payment of fees and expenses. At June 30, 2019 , we were in compliance with the financial covenants contained in the Credit Agreement . We monitor compliance on an ongoing basis. If we are unable to remain in compliance with the financial covenants contained in our Credit Agreement or maintain the required ratios discussed above, the lenders could call an event of default and accelerate the outstanding debt under the terms of the Credit Agreement , such that our outstanding debt under the Credit Agreement could become then due and payable. We may request waivers of compliance for any violation of a financial covenant from the lenders, but there is no assurance that such waivers would be granted. Debt Issuance Costs As of June 30, 2019 and December 31, 2018 , our unamortized debt issuance costs were $0.8 million and $1.4 million, respectively. These costs are amortized to interest expense in our condensed consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the three months ended June 30, 2019 and 2018 was $0.3 million and $0.1 million, respectively. Amortization of debt issuance costs recorded during the six months ended June 30, 2019 and 2018 was $0.6 million and $0.3 million, respectively.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	6 Months Ended
	Jun. 30, 2019
Oil And Natural Gas Properties And Related Equipment.
Oil And Natural Gas Properties And Related Equipment	8. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT Gathering and transportation assets consisted of the following (in thousands): June 30, December 31, 2019 2018 Gathering and transportation assets Midstream assets $ 186,845 $ 186,406 Less: Accumulated depreciation and amortization (38,549) (34,598) Total gathering and transportation assets, net $ 148,296 $ 151,808 Oil and natural gas properties and related equipment consisted of the following (in thousands): June 30, December 31, 2019 2018 Oil and natural gas properties and related equipment Proved property $ 112,449 $ 112,173 Less: Accumulated depreciation, depletion, amortization and impairments (67,545) (65,647) Total oil and natural gas properties and equipment, net $ 44,904 $ 46,526 Oil and Natural Gas Properties. We follow the successful efforts method of accounting for our oil and natural gas production activities. Under this method of accounting, costs relating to leasehold acquisition, property acquisition and the development of proved areas are capitalized when incurred. If proved reserves are found on an undeveloped property, leasehold cost is transferred to proved properties. Depreciation, Depletion and Amortization . Depreciation and depletion of producing oil and natural gas properties is recorded at the field level, based on the units-of-production method. Unit rates are computed for unamortized drilling and development costs using proved developed reserves and for unamortized leasehold costs using all proved reserves. All other properties, including the gathering and transportation assets, are stated at historical acquisition cost, net of any impairments, and are depreciated using the straight-line method over the useful lives of the assets, which range from 3 to 15 years for furniture and equipment, and up to 36 years for gathering facilities. Depreciation, depletion and amortization consisted of the following (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 Depreciation, depletion and amortization of oil and natural gas-related assets $ 828 $ 1,251 $ 1,923 $ 2,614 Depreciation and amortization of gathering and transportation related assets 1,981 1,929 3,950 3,829 Amortization of intangible assets 3,365 3,365 6,730 6,730 Total Depreciation, depletion and amortization $ 6,174 $ 6,545 $ 12,603 $ 13,173 Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for impairment testing exclude derivative instruments. The recoverability of gathering and transportation assets is evaluated when facts or circumstances indicate that their carrying value may not be recoverable. Asset recoverability is measured by comparing the carrying value of the asset or asset group with its expected future pre-tax undiscounted cash flows. These cash flow estimates require us to make projections and assumptions for many years into the future for pricing, demand, competition, operating cost and other factors. If the carrying amount exceeds the expected future undiscounted cash flows, we recognize an impairment equal to the excess of net book value over fair value. The determination of the fair value using present value techniques requires us to make projections and assumptions regarding the probability of a range of outcomes and the rates of interest used in the present value calculations. Any changes we make to these projections and assumptions could result in significant revisions to our evaluation of recoverability of our gathering and transportation assets and the recognition of additional impairments. Upon disposition or retirement of gathering and transportation assets, any gain or loss is recorded to operations. For each of the three and six months ended June 30, 2019 and 2018, we recorded no impairment charges.

Asset Retirement Obligation

Asset Retirement Obligation	6 Months Ended
	Jun. 30, 2019
Asset Retirement Obligation
Asset Retirement Obligation	9. ASSET RETIREMENT OBLIGATION We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells and decommissioning of oil and natural gas gathering and other facilities. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas properties, equipment and facilities or gathering and transportation assets. The following table is a reconciliation of changes in ARO for the six months ended June 30, 2019 and the year ended December 31, 2018 (in thousands): Six Months Ended Year Ended June 30, 2019 December 31, 2018 Asset retirement obligation, beginning balance $ 6,200 $ 6,074 Liabilities added from escalating working interests 172 288 Sales — (613) Revisions to cost estimates — (46) Accretion expense 259 497 Asset retirement obligation, ending balance $ 6,631 $ 6,200 Additional AROs increase the liability associated with new oil and natural gas wells and other facilities as these obligations are incurred. Abandonments of oil and natural gas wells and other facilities reduce the liability for AROs. During the six months ended June 30, 2019 and the year ended December 31, 2018, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2018, obligations were sold as part of the Briggs Divestiture, Louisiana Divestiture and Cola Divestiture.

Intangible Assets

Intangible Assets	6 Months Ended
	Jun. 30, 2019
Intangible Assets
Intangible Assets	10. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $152.0 million related to the Gathering Agreement (defined in Note 13 “Related Party Transactions”) with Sanchez Energy that was entered into as part of the acquisition of the Western Catarina gathering system (“Western Catarina Midstream”). Pursuant to the 15-year agreement, Sanchez Energy tenders all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina area of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15-year life of the agreement. Amortization expense for each of the six months ended June 30, 2019 and 2018 was approximately $6.7 million. These costs are amortized to depreciation, depletion, and amortization expense in our condensed consolidated statements of operations. The following table is a reconciliation of changes in intangible assets (in thousands): June 30, December 31, 2019 2018 Beginning balance $ 158,706 $ 172,166 Amortization (6,730) (13,460) Ending balance $ 151,976 $ 158,706

Investments

Investments	6 Months Ended
	Jun. 30, 2019
Investments
Investments	11. INVESTMENTS In July 2016, we completed a transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Gathering, LLC (“Carnero Gathering”), a joint venture that was 50% owned and operated by Targa Resources Corp. (NYSE: TRGP) (“Targa”), for an initial payment of approximately $37.0 million and the assumption of remaining capital commitments to Carnero Gathering, estimated at approximately $7.4 million as of the acquisition date (the “Carnero Gathering Transaction”). The fair value of the intangible asset for the contractual customer relationship related to Carnero Gathering was valued at approximately $13.0 million. This amount is being amortized over a contract term of 15 years and decreases e arnings from equity investments in our condensed consolidated statements of operations. As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. See Note 5 “Fair Value Measurements” for further discussion of the earnout derivative. In November 2016, we completed a transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, LLC (“Carnero Processing”), a joint venture that was 50% owned and operated by Targa, for aggregate cash consideration of approximately $55.5 million and the assumption of remaining capital contribution commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of acquisition (the “Carnero Processing Transaction”). In May 2018, we executed a series of agreements with Targa and other parties pursuant to which, among other things: (1) the parties merged their respective 50% interests in Carnero Gathering and Carnero Processing (the “Carnero JV Transaction”) to form an expanded 50 / 50 joint venture in South Texas within Carnero G&P, LLC (the “Carnero JV”), (2) Targa contributed 100% of the equity interest in the Silver Oak II Gas Processing Plant (“Silver Oak II”), located in Bee County, Texas, to the Carnero JV, which expands the processing capacity of the Carnero JV from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the 45 miles of high pressure natural gas gathering pipelines owned by Carnero Gathering that connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility (the “Carnero Gathering Line”) to the Carnero JV resulting in the Carnero JV owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the Carnero JV received a new dedication from Sanchez Energy and its working interest partners of over 315,000 Comanche acres in the Western Eagle Ford pursuant to a new long-term firm gas gathering and processing agreement. The agreement with Sanchez Energy, which was approved by all of the unaffiliated Comanche working interest partners, establishes commercial terms for the gathering of gas on the Carnero Gathering Line and processing at the Raptor Gas Processing Facility and Silver Oak II. Prior to execution of the agreement, Comanche volumes were gathered and processed on an interruptible basis, with the processing capabilities of the Carnero JV limited by the capacity of the Raptor Gas Processing Facility. As a result of the Carnero JV Transaction, we now record our share of earnings and losses from the Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting. The HLBV is a balance-sheet approach that calculates the amount we would have received if the Carnero JV were liquidated at book value at the end of each measurement period. The change in our allocated amount during the period is recognized in our condensed consolidated statements of operations. In the event of liquidation of the Carnero JV, available proceeds are first distributed to any priority return and unpaid capital associated with Silver Oak II, and then to members in accordance with their capital accounts. As of June 30, 2019, the Partnership had paid approximately $124.1 million for its investment in the Carnero JV related to the initial payments and contributed capital. The Partnership has accounted for this investment using the equity method. Targa is the operator of the Carnero JV and has significant influence with respect to the normal day-to-day construction and operating decisions. We have included the investment balance in the equity investments caption on our condensed consolidated balance sheets. For the three months ended June 30, 2019, the Partnership recorded earnings of approximately $1.1 million in equity investments from the Carnero JV, which was offset by approximately $0.3 million related to the amortization of the contractual customer intangible asset. For the six months ended June 30, 2019, the Partnership recorded earnings of approximately $2.8 million in equity investments from the Carnero JV, which was offset by approximately $0.6 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in earnings from equity investments within the condensed consolidated statements of operations. Cash distributions of approximately $8.2 million were received during the six months ended June 30, 2019. Summarized financial information of unconsolidated entities is as follows (in thousands): Six Months Ended June 30, 2019 2018 Sales $ 97,061 $ 179,798 Total expenses 88,647 163,091 Net income $ 8,414 $ 16,707

Commitments And Contingencies

Commitments And Contingencies	6 Months Ended
	Jun. 30, 2019
Commitments And Contingencies
Commitments And Contingencies	12. COMMITMENTS AND CONTINGENCIES As part of the Carnero Gathering Transaction, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at designated delivery points from Sanchez Energy and other producers. This earnout has an approximate value of $5.8 million and is recorded as other liabilities on our condensed consolidated balance sheet . For the six months ended June 30, 2019, we paid Sanchez Energy $32.1 thousand related to the earnout. For the six months ended June 30, 2018, the natural gas the Carnero JV received did not exceed the aforementioned threshold, which resulted in no payment to Sanchez Energy related to the earnout.

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2019
Related Party Transactions
Related Party Transactions	13. RELATED PARTY TRANSACTIONS Please read the disclosure under the headings “Sanchez-Related Agreements” and “Sanchez-Related Transactions” in Note 14 “Related Party Transactions” of our Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2018 for a more complete description of certain related party transactions that were entered into prior to 2019. The following is an update to such disclosure: In conjunction with the acquisition of Western Catarina Midstream, we entered into a 15-year gas gathering agreement with Sanchez Energy pursuant to which Sanchez Energy agreed to tender all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on approximately 35,000 dedicated acres in the Western Catarina area of the Eagle Ford Shale in South Texas for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by a subsidiary of Sanchez Energy based on water that is delivered through the gathering system through March 31, 2018. Subsequent to the conclusion of the incremental infrastructure fee amendment, the parties have agreed to continue the incremental infrastructure fee on a month-to-month basis. On January 1, 2019 and April 1, 2019, the Partnership increased the Western Catarina Midstream tariff rate for throughput volumes which are outside of the dedicated acreage under the Gathering Agreement. As of June 30, 2019 and December 31, 2018, the Partnership had a net receivable from related parties of approximately $6.5 million, and $6.7 million, respectively, which are included in accounts receivable – related entities on the condensed consolidated balance sheets. As of June 30, 2019 and December 31, 2018, the Partnership also had a net payable to related parties of approximately $5.8 million, and $5.6 million, respectively, which are included in accounts payable – related entities on the condensed consolidated balance sheets. The net receivable/payable as of June 30, 2019 and December 31, 2018 consist primarily of revenues receivable from oil and natural gas production and transportation, offset by costs associated with that production and transportation and obligations for general and administrative costs.

Unit-Based Compensation

Unit-Based Compensation	6 Months Ended
	Jun. 30, 2019
Unit-Based Compensation
Unit-Based Compensation	14. UNIT-BASED COMPENSATION The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “LTIP”) allows for grants of restricted common units. Restricted common unit activity under the LTIP during the period is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2018 513,694 $ 12.31 Granted 1,129,173 2.35 Vested (381,729) 8.49 Returned/Cancelled (102,345) 12.05 Outstanding at June 30, 2019 1,158,793 $ 3.88 In April 2019, the Partnership issued 137,613 restricted common units pursuant to the LTIP to certain directors of the Partnership’s general partner that vested immediately on the date of grant. In March 2019, the Partnership issued 991,560 restricted common units pursuant to the LTIP to certain officers and directors of the Partnership’s general partner that vest over three years from the date of grant. The unit based compensation expense for the awards was based on the fair value on the day before the grant date. As of June 30, 2019, 703,185 common units remained available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	6 Months Ended
	Jun. 30, 2019
Distributions To Unitholders
Distributions To Unitholders	15. DISTRIBUTIONS TO UNITHOLDERS The table below reflects the payment of cash distributions on common units related to the six months ended June 30, 2019 and each of the three month periods ended during the year ended December 31, 2018. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2018 $ 0.4508 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 $ 0.4508 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.1500 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.1500 February 7, 2019 February 20, 2019 February 28, 2019 March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 2019 June 30, 2019 (a) $ — August 8, 2019 — — (a) In connection with the second-quarter 2019 distribution, the Board determined to establish a cash reserve to pay down a portion of the Partnership’s debt outstanding under the Credit Agreement. Following the establishment of the cash reserve, the Board determined that the Partnership did not have any available cash and, as a result, no cash distribution was declared for the common units with respect to the second-quarter 2019. See Note 19 “Subsequent Events.” The table below reflects the payment of distributions on Class B Preferred Units (defined below) related to the six months ended June 30, 2019 and each of the three month periods ended during the year ended December 31, 2018. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (a) $ August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.28225 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.28225 February 7, 2019 February 20, 2019 February 28, 2019 March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019 June 30, 2019 (b) $ — — — — (a) The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part in Class B Preferred PIK Units. Accordingly, the Partnership declared a cash distribution of $0.22580 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred PIK Units, each distribution was paid on August 31, 2018 to holders of record on August 21, 2018. (b) On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units (the “Class C Preferred Units”). As a result, no distribution was declared with respect to the Class B Preferred Units. See Note 19 “Subsequent Events.” The table below reflects the payment of distributions on Class C Preferred Units related to the three months ended June 30, 2019. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution June 30, 2019 (a) $ — August 8, 2019 August 20, 2019 August 30, 2019 (a) The Board determined that the Partnership did not have any available cash with respect to the second-quarter 2019 and, as a result, the Amended Partnership Agreement (defined below) requires that the Partnership pay the second-quarter 2019 distribution on the Class C Preferred Units 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 939,327 Class C Preferred PIK Units, payable on August 30, 2019 to holders of record on August 20, 2019. See Note 19 “Subsequent Events.”

Partners' Capital

Partners' Capital	6 Months Ended
	Jun. 30, 2019
Partners' Capital
Partners' Capital	16. PARTNERS’ CAPITAL Outstanding Units As of June 30, 2019, we had 31, 310,896 Class B Preferred Units outstanding, and 19,188,086 common units outstanding, which included 1,158,793 unvested restricted common units issued under the LTIP. Common Unit Issuances The following table shows the common units issued by the Partnership in 2018 and 2019 to Manager in connection with providing services under the Services Agreement: Common Date of Three months ended units issuance December 31, 2017 210,978 March 15, 2018 March 31, 2018 220,214 May 31, 2018 June 30, 2018 224,342 September 10, 2018 September 30, 2018 334,010 November 30, 2018 December 31, 2018 787,750 March 8, 2019 March 31, 2019 887,269 May 23, 2019 Class B Preferred Unit Offering On October 14, 2015, pursuant to the Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately negotiated transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of Western Catarina Midstream, along with the payment to Stonepeak of a fee equal to 2.25% of the consideration paid for the Class B Preferred Units. Under the terms of the Second Amended and Restated Agreement of Limited Partnership of the Partnership (as amended by Amendment No. 1 and Amendment No. 2 thereto, the “Second Partnership Agreement”), holders of the Class B Preferred Units receive a quarterly distribution, at the election of the Board, of 10.0% per annum if paid in full in cash or 12.0% per annum if paid in part cash (8.0% per annum) and in part Class B Preferred PIK Units (4.0% per annum), as defined in the Second Partnership Agreement. Distributions are to be paid on or about the last day of each of February, May, August and November after the end of each quarter. In accordance with the Second Partnership Agreement, on December 6, 2016 the Partnership issued an additional 9,851,996 Class B Preferred Units to Stonepeak. On January 25, 2017, the Partnership and Stonepeak entered into a Settlement Agreement and Mutual Release (the “Settlement Agreement”) to settle a dispute arising from the calculation of an adjustment to the number of Class B Preferred Units pursuant to Section 5.10(g) of the Second Partnership Agreement. Pursuant to the Settlement Agreement, and in accordance with Section 5.4 of the Second Partnership Agreement, the Partnership issued 1,704,446 Class B Preferred Units to Stonepeak in a privately negotiated transaction as partial consideration for the Settlement Agreement, with the “Class B Preferred Unit Price” being established at $11.29 per Class B Preferred Unit. Pursuant to the terms of the Second Partnership Agreement, the Class B Preferred Units are convertible at any time, at the option of Stonepeak, into common units of the Partnership, subject to the requirement to convert a minimum of $17.5 million of Class B Preferred Units. The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part Class B Preferred PIK Units in accordance with the Second Partnership Agreement. Accordingly, the Partnership issued 310,009 Class B Preferred PIK Units on August 31, 2018, to Stonepeak. The Class B Preferred Units are accounted for as mezzanine equity on the condensed consolidated balance sheets. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands): June 30, December 31, 2019 2018 Mezzanine equity, beginning balance $ 349,857 $ 343,912 Amortization of discount 1,442 2,358 Distributions 19,443 36,925 Distributions paid (17,675) (33,338) Mezzanine equity, ending balance $ 353,067 $ 349,857 On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”). See Note 19 “Subsequent Events.” Earnings per Unit Net income (loss) per common unit for the period is based on any distributions that are made to the unitholders (common units) plus an allocation of undistributed net income (loss) based on provisions of the Second Partnership Agreement , divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the net income for the period had been distributed in accordance with the Second Partnership Agreement . Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the Second Partnership Agreement . Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. The Partnership’s general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income.

Reporting Segments

Reporting Segments	6 Months Ended
	Jun. 30, 2019
Reporting Segments
Reporting Segments	17. REPORTING SEGMENTS “Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of crude oil, natural gas and NGLs. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries. These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker (“CODM”) to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses. The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Three Months Ended June 30, 2019 2018 Production Midstream Production Midstream Segment revenues Natural gas sales $ 256 $ — $ 226 $ — Oil sales 3,811 — 1,584 — Natural gas liquid sales 117 — 400 — Gathering and transportation sales — 1,702 — 1,661 Gathering and transportation lease revenues — 15,969 — 13,168 Total segment revenues 4,184 17,671 2,210 14,829 Segment operating costs Lease operating expenses 1,688 377 1,644 363 Transportation operating expenses — 3,048 — 3,071 Production taxes 141 — 287 — Gain on sale of assets — — (2,388) — Depreciation, depletion and amortization 828 5,346 1,251 5,294 Accretion expense 46 80 49 74 Total segment operating costs 2,703 8,851 843 8,802 Segment other income Earnings from equity investments — 791 — 3,111 Total segment other income — 791 — 3,111 Segment operating income $ 1,481 $ 9,611 $ 1,367 $ 9,138 Six Months Ended June 30, 2019 2018 Production Midstream Production Midstream Segment revenues Natural gas sales $ 366 $ — $ 699 $ — Oil sales 3,072 — 5,046 — Natural gas liquid sales 296 — 995 — Gathering and transportation sales — 3,385 — 3,349 Gathering and transportation lease revenues — 32,226 — 25,486 Total segment revenues 3,734 35,611 6,740 28,835 Segment operating costs Lease operating expenses 3,007 773 3,396 582 Transportation operating expenses — 5,724 — 5,918 Production taxes 324 — 609 — Gain on sale of assets — — (2,388) — Depreciation, depletion and amortization 1,923 10,680 2,614 10,559 Accretion expense 100 159 103 146 Total segment operating costs 5,354 17,336 4,334 17,205 Segment other income Earnings from equity investments — 2,233 — 7,383 Total segment other income — 2,233 — 7,383 Segment operating income (loss) $ (1,620) $ 20,508 $ 2,406 $ 19,013 Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 Reconciliation of segment operating income (loss) to net income (loss) Total production operating income (loss) $ 1,481 $ 1,367 $ (1,620) $ 2,406 Total midstream operating income 9,611 9,138 20,508 19,013 Total segment operating income 11,092 10,505 18,888 21,419 General and administrative expense (4,171) (6,919) (8,920) (12,084) Unit-based compensation expense (175) (1,347) (810) (2,785) Interest expense, net (2,814) (2,780) (5,600) (5,379) Other income (expense) 21 (1,254) 67 (1,524) Income tax expense (76) — (122) — Net income (loss) $ 3,877 $ (1,795) $ 3,503 $ (353) The following table summarizes the total assets by operating segment as of June 30, 2019 and December 31, 2018 and total capital expenditures for the six months ended June 30, 2019 and the year ended December 31, 2018 (in thousands): June 30, 2019 Production Midstream Corporate (a) Total Other financial information Total assets $ 48,162 $ 414,129 $ 2,105 $ 464,396 Capital expenditures (b) $ 103 $ 679 $ — $ 782 December 31, 2018 Production Midstream Corporate (a) Total Other financial information Total assets $ 53,556 $ 429,523 $ 3,606 $ 486,685 Capital expenditures (b) $ 11 $ 4,856 $ — $ 4,867 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture, and other assets. (b) Inclusive of capital contributions made to equity method investments.

Variable Interest Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2019
Variable Interest Entities
Variable Interest Entities	18. VARIABLE INTEREST ENTITIES The Partnership’s investment in the Carnero JV represents a variable interest entity (“VIE”) that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero JV is limited to the capital investment of approximately $108.8 million. As of June 30, 2019, the Partnership had invested approximately $124.1 million in the Carnero JV and no debt has been incurred by the Carnero JV. We have included this VIE in other assets, equity investments on the balance sheet. Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of June 30, 2019 and December 31, 2018 (in thousands): June 30, December 31, 2019 2018 Acquisitions, earnout and capital investments $ 128,140 $ 127,899 Earnings in equity investments 25,378 23,144 Distributions received (44,742) (36,578) Maximum exposure to loss $ 108,776 $ 114,465

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2019
Subsequent Events
Subsequent Events	19. SUBSEQUENT EVENTS On July 9, 2019, the Partnership received notification that, pursuant to the terms of the Credit Agreement, its lenders have completed both their quarterly review of the borrowing base for the Partnership’s midstream assets (the “midstream component”) and their semi-annual review of the borrowing base for the Partnership’s oil and natural gas properties (the “RBL component”). Based on this review, the midstream component has been set at $262.0 million and the RBL component has been set at $20.0 million, resulting in a total borrowing base of $282.0 million. On July 29, 2019, the Partnership paid $4.0 million in principal outstanding under the Credit Agreement resulting in debt outstanding of $168.0 million under the Credit Agreement as of that date. On August 2, 2019, the Partnership’s general partner entered into Executive Services Agreements with each of Gerald F. Willinger, Chief Executive Officer of the Partnership’s general partner, and Charles C. Ward, Chief Financial Officer and Secretary of the Partnership’s general partner (collectively, the “Executive Agreements”). The Executive Agreements were approved by the Board on August 2, 2019. Copies of the Executive Agreements are filed as exhibits to this Form 10-Q. On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units and a warrant exercisable for junior securities (the “Warrant”) in a privately negotiated transaction (the “Exchange”). In connection with the Exchange, the Partnership entered into (i) the Third Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended Partnership Agreement) to set forth the terms of the Class C Preferred Units, (ii) the Amended and Restated Registration Rights Agreement with Stonepeak relating to the registered resale of common units issuable upon the exercise of the Warrant, and (iii) the Amended and Restated Board Representation and Standstill Agreement with Stonepeak . In addition, on August 2, 2019, the Partnership’s general partner entered into Amendment No. 3 to its Limited Liability Company Agreement to provide certain changes necessary in connection with the Exchange. On August 8, 2019, the Board declared that after establishing a cash reserve for the payment of certain amounts outstanding under the Credit Agreement, the Partnership did not have any available cash and, as a result, there would be no cash distribution on the Partnership’s common units. As required by the Amended Partnership Agreement, the Board declared a second quarter distribution on the Class C Preferred Units payable 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 939,327 Class C Preferred PIK Units, payable on August 30, 2019 to holders of record on August 20, 2019.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 30, 2019
Basis Of Presentation And Summary Of Significant Accounting Policies
Basis of Presentation	Basis of Presentation Accounting policies used by us conform to accounting principles generally accepted in the United States of America (“GAAP”). These unaudited condensed consolidated financial statements include the accounts of us and our wholly owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. Our business consists of two reportable segments: Production and Midstream. Our Midstream segment includes Western Catarina Midstream (defined in Note 10 “Intangible Assets”), the Carnero JV (defined in Note 11 “Investments”) and Seco Pipeline. Our Production segment consists of our oil and natural gas properties in Texas and Louisiana. Our management evaluates performance based on these two business segments. These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the SEC. Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with GAAP, have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on March 7, 2019.
Recent Accounting Pronouncements	Recent Accounting Pronouncements In August 2018, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2018-13 “Fair Value Measurement (ASC 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurements,” which modifies the disclosure requirements on fair value measurements. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In June 2018, the FASB issued ASU 2018-07 “Compensation - Stock Compensation (Topic 718) - Improvements to Nonemployee Share-Based Payment Accounting,” which expands the scope of Topic 718, Compensation – Stock Compensation, to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted this ASU effective January 1, 2019, which resulted in the remeasurement of our outstanding unvested awards as of January 1, 2019 and will change the expense recorded for equity awards going forward. The adoption of this standard resulted in an approximately $0.2 million charge to retained earnings. In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology in place of the currently used incurred loss methodology, which will result in more timely recognition of losses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2019, and earlier adoption is permitted. We are currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018. Additionally, in July 2018, the FASB issued ASU 2018-10, “Codification Improvements to Topic 842 (Leases),” which provides narrow amendments to clarify how to apply certain aspects of ASU 2016-02. The Partnership elected the practical expedients disclosed in ASU 2018-10. The effective date in ASU 2018-10 is the same as that of ASU 2016-02. The standards update the previous lease guidance by requiring the recognition of a right-of-use asset and lease liability on the statement of financial position for those leases previously classified as operating leases under the old guidance. In addition, ASU 2016-02 updates the criteria for a lessee’s classification of a finance lease. The Partnership adopted this standard effective January 1, 2019. The adoption of this standard did not have a material impact on our condensed consolidated financial statements. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows.
Use of Estimates	Estimates The condensed consolidated financial statements are prepared in conformity with GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying notes therein. These estimates and the underlying assumptions affect the amounts of assets and liabilities reported, disclosures about contingent assets and liabilities and reported amounts of revenues and expenses. The estimates that are particularly significant to our financial statements include estimates of our reserves of natural gas, NGLs and oil; future cash flows from oil and natural gas properties; depreciation, depletion and amortization; asset retirement obligations; certain revenues and operating expenses; fair values of derivatives; and fair values of assets and liabilities. As fair value is a market-based measurement, it is determined based on the assumptions that market participants would use. These estimates and assumptions are based on management’s best judgment using the data available. Management evaluates its estimates and assumptions on an on-going basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. Such estimates and assumptions are adjusted when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ from the estimates. Any changes in estimates resulting from continuing changes in the economic environment will be reflected in the financial statements in future periods.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	6 Months Ended
	Jun. 30, 2019
Revenue Recognition
Schedule of disaggregation of revenue	We recognized aggregate revenue of $21.9 million for the three months ended June 30, 2019. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Three Months Ended June 30, 2019 Production Midstream Total Revenues: Natural gas sales $ 256 $ — $ 256 Oil sales 3,811 — 3,811 Natural gas liquid sales 117 — 117 Gathering and transportation sales — 1,702 1,702 Gathering and transportation lease revenues — 15,969 15,969 Total revenues $ 4,184 $ 17,671 $ 21,855 We recognized aggregate revenue of $39.3 million for the six months ended June 30, 2019. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Six Months Ended June 30, 2019 Production Midstream Total Revenues: Natural gas sales $ 366 $ — $ 366 Oil sales 3,072 — 3,072 Natural gas liquid sales 296 — 296 Gathering and transportation sales — 3,385 3,385 Gathering and transportation lease revenues — 32,226 32,226 Total revenues $ 3,734 $ 35,611 $ 39,345

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2019
Fair Value Measurements
Schedule of fair value of assets and liabilities on a recurring basis	The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2019 (in thousands): Fair Value Measurements at June 30, 2019 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 22 $ — $ 22 Midstream derivative instrument Earnout derivative liability — — (5,793) (5,793) Total $ — $ 22 $ (5,793) $ (5,771) The following table summarizes the fair value of our assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2018 (in thousands): Fair Value Measurements at December 31, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 3,914 $ — $ 3,914 Midstream derivative instrument Earnout derivative liability — — (5,856) (5,856) Total $ — $ 3,914 $ (5,856) $ (1,942)
Schedule of reconciliation of changes in fair value of derivatives	The following table sets forth a reconciliation of changes in the fair value of the Partnership’s earnout derivative liability classified as Level 3 in the fair value hierarchy (in thousands): Six Months Ended Year Ended June 30, 2019 December 31, 2018 Beginning balance $ (5,856) $ (6,402) Gain on earnout derivative 63 546 Ending balance $ (5,793) $ (5,856) Gain included in earnings related to derivatives still held as of June 30, 2019 and December 31, 2018, respectively $ 63 $ 546

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2019
Derivative And Financial Instruments
Summary Of Derivative Contracts In Place	Fixed Price Basis Swaps – West Texas Intermediate (WTI) Three Months Ended (volume in Bbls) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2019 — $ — — $ — 57,024 $ 60.48 54,824 $ 60.52 111,848 $ 60.50 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 312,432 Fixed Price Swaps – NYMEX (Henry Hub) Three Months Ended (volume in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2019 — $ — — $ — 112,032 $ 2.85 108,552 $ 2.85 220,584 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 623,032
Reconciliation Of Changes In Fair Value Of Derivatives	Three Months Ended (volume in MMBtu) March 31, June 30, September 30, December 31, Total Average Average Average Average Average Volume Price Volume Price Volume Price Volume Price Volume Price 2019 — $ — — $ — 112,032 $ 2.85 108,552 $ 2.85 220,584 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 623,032 The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the six months ended June 30, 2019 and the year ended December 31, 2018 (in thousands): Six Months Ended Year Ended June 30, 2019 December 31, 2018 Beginning fair value of commodity derivatives $ 3,914 $ 1,231 Net gains (losses) on crude oil derivatives (3,677) 1,400 Net gains (losses) on natural gas derivatives 153 (84) Net settlements paid (received) on derivative contracts: Oil (381) 1,330 Natural gas 13 37 Ending fair value of commodity derivatives $ 22 $ 3,914
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	Six Months Ended Year Ended June 30, 2019 December 31, 2018 Beginning fair value of commodity derivatives $ 3,914 $ 1,231 Net gains (losses) on crude oil derivatives (3,677) 1,400 Net gains (losses) on natural gas derivatives 153 (84) Net settlements paid (received) on derivative contracts: Oil (381) 1,330 Natural gas 13 37 Ending fair value of commodity derivatives $ 22 $ 3,914 The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Location of Gain (Loss) Three Months Ended June 30, Six Months Ended June 30, Derivative Type in Income 2019 2018 2019 2018 Commodity – Mark-to-Market Oil sales $ 807 $ (3,717) $ (3,677) $ (5,657) Commodity – Mark-to-Market Natural gas sales 193 2 153 4 $ 1,000 $ (3,715) $ (3,524) $ (5,653)

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	6 Months Ended
	Jun. 30, 2019
Oil And Natural Gas Properties And Related Equipment.
Schedule of gathering and transportation assets	Gathering and transportation assets consisted of the following (in thousands): June 30, December 31, 2019 2018 Gathering and transportation assets Midstream assets $ 186,845 $ 186,406 Less: Accumulated depreciation and amortization (38,549) (34,598) Total gathering and transportation assets, net $ 148,296 $ 151,808
Schedule of oil and natural gas properties	June 30, December 31, 2019 2018 Gathering and transportation assets Midstream assets $ 186,845 $ 186,406 Less: Accumulated depreciation and amortization (38,549) (34,598) Total gathering and transportation assets, net $ 148,296 $ 151,808 Oil and natural gas properties and related equipment consisted of the following (in thousands): June 30, December 31, 2019 2018 Oil and natural gas properties and related equipment Proved property $ 112,449 $ 112,173 Less: Accumulated depreciation, depletion, amortization and impairments (67,545) (65,647) Total oil and natural gas properties and equipment, net $ 44,904 $ 46,526
Schedule of depreciation, depletion, and amortization	Depreciation, depletion and amortization consisted of the following (in thousands): Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 Depreciation, depletion and amortization of oil and natural gas-related assets $ 828 $ 1,251 $ 1,923 $ 2,614 Depreciation and amortization of gathering and transportation related assets 1,981 1,929 3,950 3,829 Amortization of intangible assets 3,365 3,365 6,730 6,730 Total Depreciation, depletion and amortization $ 6,174 $ 6,545 $ 12,603 $ 13,173

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	6 Months Ended
	Jun. 30, 2019
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of changes in ARO for the six months ended June 30, 2019 and the year ended December 31, 2018 (in thousands): Six Months Ended Year Ended June 30, 2019 December 31, 2018 Asset retirement obligation, beginning balance $ 6,200 $ 6,074 Liabilities added from escalating working interests 172 288 Sales — (613) Revisions to cost estimates — (46) Accretion expense 259 497 Asset retirement obligation, ending balance $ 6,631 $ 6,200

Intangible Assets (Tables)

Intangible Assets (Tables)	6 Months Ended
	Jun. 30, 2019
Intangible Assets
Schedule of Intangible assets	The following table is a reconciliation of changes in intangible assets (in thousands): June 30, December 31, 2019 2018 Beginning balance $ 158,706 $ 172,166 Amortization (6,730) (13,460) Ending balance $ 151,976 $ 158,706

Investments (Tables)

Investments (Tables)	6 Months Ended
	Jun. 30, 2019
Investments
Summarized financial information of unconsolidated entities	Summarized financial information of unconsolidated entities is as follows (in thousands): Six Months Ended June 30, 2019 2018 Sales $ 97,061 $ 179,798 Total expenses 88,647 163,091 Net income $ 8,414 $ 16,707

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	6 Months Ended
	Jun. 30, 2019
Unit-Based Compensation
Schedule of units activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2018 513,694 $ 12.31 Granted 1,129,173 2.35 Vested (381,729) 8.49 Returned/Cancelled (102,345) 12.05 Outstanding at June 30, 2019 1,158,793 $ 3.88

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	6 Months Ended
	Jun. 30, 2019
Common units
Schedule of payment of cash distributions	Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2018 $ 0.4508 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 $ 0.4508 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.1500 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.1500 February 7, 2019 February 20, 2019 February 28, 2019 March 31, 2019 $ 0.1500 May 3, 2019 May 22, 2019 May 31, 2019 June 30, 2019 (a) $ — August 8, 2019 — — In connection with the second-quarter 2019 distribution, the Board determined to establish a cash reserve to pay down a portion of the Partnership’s debt outstanding under the Credit Agreement. Following the establishment of the cash reserve, the Board determined that the Partnership did not have any available cash and, as a result, no cash distribution was declared for the common units with respect to the second-quarter 2019. See Note 19 “Subsequent Events.”
Class B preferred units
Schedule of payment of cash distributions	Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (a) $ August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.28225 November 9, 2018 November 20, 2018 November 30, 2018 December 31, 2018 $ 0.28225 February 7, 2019 February 20, 2019 February 28, 2019 March 31, 2019 $ 0.28225 May 3, 2019 May 22, 2019 May 31, 2019 June 30, 2019 (b) $ — — — — (a) The Partnership elected to pay the second-quarter 2018 distribution on the Class B Preferred Units in part cash and part in Class B Preferred PIK Units. Accordingly, the Partnership declared a cash distribution of $0.22580 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred PIK Units, each distribution was paid on August 31, 2018 to holders of record on August 21, 2018. On August 2, 2019, Stonepeak exchanged all of the issued and outstanding Class B Preferred Units for newly issued Class C Preferred Units (the “Class C Preferred Units”). As a result, no distribution was declared with respect to the Class B Preferred Units. See Note 19 “Subsequent Events.”
Class C preferred units
Schedule of payment of cash distributions	Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution June 30, 2019 (a) $ — August 8, 2019 August 20, 2019 August 30, 2019 The Board determined that the Partnership did not have any available cash with respect to the second-quarter 2019 and, as a result, the Amended Partnership Agreement (defined below) requires that the Partnership pay the second-quarter 2019 distribution on the Class C Preferred Units 100% in Class C Preferred PIK Units. Accordingly, the Partnership declared an aggregate distribution of 939,327 Class C Preferred PIK Units, payable on August 30, 2019 to holders of record on August 20, 2019. See Note 19 “Subsequent Events.”

Partners' Capital (Tables)

Partners' Capital (Tables)	6 Months Ended
	Jun. 30, 2019
Partners' Capital
Schedule of common unit issuances	Common Date of Three months ended units issuance December 31, 2017 210,978 March 15, 2018 March 31, 2018 220,214 May 31, 2018 June 30, 2018 224,342 September 10, 2018 September 30, 2018 334,010 November 30, 2018 December 31, 2018 787,750 March 8, 2019 March 31, 2019 887,269 May 23, 2019
Schedule of class B preferred units accounted for as mezzanine equity in the consolidated balance sheet	The Class B Preferred Units are accounted for as mezzanine equity on the condensed consolidated balance sheets. The following table sets forth a reconciliation of the changes in mezzanine equity (in thousands): June 30, December 31, 2019 2018 Mezzanine equity, beginning balance $ 349,857 $ 343,912 Amortization of discount 1,442 2,358 Distributions 19,443 36,925 Distributions paid (17,675) (33,338) Mezzanine equity, ending balance $ 353,067 $ 349,857

Reporting Segments (Tables)

Reporting Segments (Tables)	6 Months Ended
	Jun. 30, 2019
Reporting Segments
Schedule of segment information	The following tables present financial information for each operating segment for the periods indicated based on our operating segments (in thousands): Three Months Ended June 30, 2019 2018 Production Midstream Production Midstream Segment revenues Natural gas sales $ 256 $ — $ 226 $ — Oil sales 3,811 — 1,584 — Natural gas liquid sales 117 — 400 — Gathering and transportation sales — 1,702 — 1,661 Gathering and transportation lease revenues — 15,969 — 13,168 Total segment revenues 4,184 17,671 2,210 14,829 Segment operating costs Lease operating expenses 1,688 377 1,644 363 Transportation operating expenses — 3,048 — 3,071 Production taxes 141 — 287 — Gain on sale of assets — — (2,388) — Depreciation, depletion and amortization 828 5,346 1,251 5,294 Accretion expense 46 80 49 74 Total segment operating costs 2,703 8,851 843 8,802 Segment other income Earnings from equity investments — 791 — 3,111 Total segment other income — 791 — 3,111 Segment operating income $ 1,481 $ 9,611 $ 1,367 $ 9,138 Six Months Ended June 30, 2019 2018 Production Midstream Production Midstream Segment revenues Natural gas sales $ 366 $ — $ 699 $ — Oil sales 3,072 — 5,046 — Natural gas liquid sales 296 — 995 — Gathering and transportation sales — 3,385 — 3,349 Gathering and transportation lease revenues — 32,226 — 25,486 Total segment revenues 3,734 35,611 6,740 28,835 Segment operating costs Lease operating expenses 3,007 773 3,396 582 Transportation operating expenses — 5,724 — 5,918 Production taxes 324 — 609 — Gain on sale of assets — — (2,388) — Depreciation, depletion and amortization 1,923 10,680 2,614 10,559 Accretion expense 100 159 103 146 Total segment operating costs 5,354 17,336 4,334 17,205 Segment other income Earnings from equity investments — 2,233 — 7,383 Total segment other income — 2,233 — 7,383 Segment operating income (loss) $ (1,620) $ 20,508 $ 2,406 $ 19,013
Summary of assets and capital expenditures by operating segment	Three Months Ended Six Months Ended June 30, June 30, 2019 2018 2019 2018 Reconciliation of segment operating income (loss) to net income (loss) Total production operating income (loss) $ 1,481 $ 1,367 $ (1,620) $ 2,406 Total midstream operating income 9,611 9,138 20,508 19,013 Total segment operating income 11,092 10,505 18,888 21,419 General and administrative expense (4,171) (6,919) (8,920) (12,084) Unit-based compensation expense (175) (1,347) (810) (2,785) Interest expense, net (2,814) (2,780) (5,600) (5,379) Other income (expense) 21 (1,254) 67 (1,524) Income tax expense (76) — (122) — Net income (loss) $ 3,877 $ (1,795) $ 3,503 $ (353) The following table summarizes the total assets by operating segment as of June 30, 2019 and December 31, 2018 and total capital expenditures for the six months ended June 30, 2019 and the year ended December 31, 2018 (in thousands): June 30, 2019 Production Midstream Corporate (a) Total Other financial information Total assets $ 48,162 $ 414,129 $ 2,105 $ 464,396 Capital expenditures (b) $ 103 $ 679 $ — $ 782 December 31, 2018 Production Midstream Corporate (a) Total Other financial information Total assets $ 53,556 $ 429,523 $ 3,606 $ 486,685 Capital expenditures (b) $ 11 $ 4,856 $ — $ 4,867 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, certain prepaid expenses, office furniture, and other assets. Inclusive of capital contributions made to equity method investments.

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2019
Variable Interest Entities
Schedule of carrying amounts of assets and liabilities of variable interest entity	Below is a tabular comparison of the carrying amounts of the assets and liabilities of the VIE and the Partnership’s maximum exposure to loss as of June 30, 2019 and December 31, 2018 (in thousands): June 30, December 31, 2019 2018 Acquisitions, earnout and capital investments $ 128,140 $ 127,899 Earnings in equity investments 25,378 23,144 Distributions received (44,742) (36,578) Maximum exposure to loss $ 108,776 $ 114,465

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2019segment	Mar. 31, 2019USD ($)
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Number of business segments | segment	2
Adoption of accounting standard		$ 181
Common units
Basis Of Presentation And Summary Of Significant Accounting Policies [Line Items]
Adoption of accounting standard		$ 181

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Gathering and transportation lease revenues	$ 15,969	$ 13,168	$ 32,226	$ 25,486
Total revenues	21,855	17,039	39,345	35,575
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	256	226	366	699
Oil sales
Disaggregation of Revenue [Line Items]
Revenues	3,811	1,584	3,072	5,046
Natural gas liquid product
Disaggregation of Revenue [Line Items]
Revenues	117	400	296	995
Gathering and transportation
Disaggregation of Revenue [Line Items]
Revenues	1,702	1,661	3,385	3,349
Production
Disaggregation of Revenue [Line Items]
Total revenues	4,184	2,210	3,734	6,740
Production | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenues	256	226	366	699
Production | Oil sales
Disaggregation of Revenue [Line Items]
Revenues	3,811	1,584	3,072	5,046
Production | Natural gas liquid product
Disaggregation of Revenue [Line Items]
Revenues	117	400	296	995
Midstream
Disaggregation of Revenue [Line Items]
Gathering and transportation lease revenues	15,969	13,168	32,226	25,486
Total revenues	17,671	14,829	35,611	28,835
Midstream | Gathering and transportation
Disaggregation of Revenue [Line Items]
Revenues	$ 1,702	$ 1,661	$ 3,385	$ 3,349

Revenue Recognition (Contract B

Revenue Recognition (Contract Balances) (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Revenue Recognition
Payment term (in days)	30 days
Receivables	$ 0.6	$ 0.6

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) - USD ($) $ in Millions	Oct. 22, 2018	Apr. 30, 2018	Jun. 30, 2018	Dec. 31, 2018
Louisiana Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture	$ 1.3
Gain on sale				$ 0.6
Briggs Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture after purchase price adjustments		$ 4.2
Gain on sale			$ 1.8
Cola Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture		$ 1
Gain on sale			$ 1.1

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) $ in Thousands	Jun. 30, 2019USD ($)derivative	Dec. 31, 2018USD ($)
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Number of interest rate derivatives | derivative	0
Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		$ 3,914
Derivative liability	$ 22	(5,856)
Earnout derivative liability	(5,793)
Total net assets	(5,771)	(1,942)
Fair Value, Inputs, Level 2 | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		3,914
Derivative liability	22
Total net assets	22	3,914
Fair Value, Inputs, Level 3 | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative liability		(5,856)
Earnout derivative liability	(5,793)
Total net assets	$ (5,793)	$ (5,856)

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded and Earnout Derivative) (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Fair Value Measurements
Beginning Balance	$ (5,856)	$ (6,402)	$ (6,402)
Gain (loss) on earnout derivative	63	$ (1,524)	546
Ending Balance	$ (5,793)		$ (5,856)

Derivative And Financial Inst_3

Derivative And Financial Instruments (Hedges In Place) (Details)	6 Months Ended
	Jun. 30, 2019MMBTU$ / bbl$ / MMBTUbbl
West Texas Intermediate 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	57,024
Average Price | $ / bbl	60.48
West Texas Intermediate 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	54,824
Average Price | $ / bbl	60.52
West Texas Intermediate 2019
Derivative [Line Items]
Volume (in Bbls) | bbl	111,848
Average Price | $ / bbl	60.50
West Texas Intermediate 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	52,776
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	50,960
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in Bbls) | bbl	49,224
Average Price | $ / bbl	53.50
West Texas Intermediate 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	47,624
Average Price | $ / bbl	53.50
West Texas Intermediate 2020
Derivative [Line Items]
Volume (in Bbls) | bbl	200,584
Average Price | $ / bbl	53.50
West Texas Intermediate
Derivative [Line Items]
Volume (in Bbls) | bbl	312,432
NYMEX 2019 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	112,032
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	108,552
Average Price | $ / MMBTU	2.85
NYMEX 2019
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	220,584
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	105,104
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	102,008
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 3
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	99,136
Average Price | $ / MMBTU	2.85
NYMEX 2020 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	96,200
Average Price | $ / MMBTU	2.85
NYMEX 2020
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	402,448
Average Price | $ / MMBTU	2.85
NYMEX
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	623,032

Derivative And Financial Inst_4

Derivative And Financial Instruments (Changes In Fair Value) (Details) - Commodity Contract $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)item	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives			$ 3,914	$ 1,231	$ 1,231
Net gains (losses) on derivatives	$ 1,000	$ (3,715)	(3,524)	(5,653)
Ending fair value of commodity derivatives	22		$ 22		3,914
Number of counterparties | item			3
Oil reserves
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	807	(3,717)	$ (3,677)	(5,657)	1,400
Net settlements paid (received) on derivative contracts					1,330
Net settlements paid (received) on derivative contracts			(381)
Natural gas
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives	$ 193	$ 2	153	$ 4	(84)
Net settlements paid (received) on derivative contracts			$ 13		$ 37

Derivative And Financial Inst_5

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - Commodity Contract - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	$ 1,000	$ (3,715)	$ (3,524)	$ (5,653)
Oil reserves
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	807	(3,717)	(3,677)	(5,657)	$ 1,400
Natural gas
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	$ 193	$ 2	$ 153	$ 4	$ (84)

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)	May 19, 2016USD ($)
Line of Credit Facility [Line Items]
Letters of credit outstanding	$ 0		$ 0
Amortization of debt issuance costs	300	$ 100	578	$ 265
Unamortized debt issue costs	800		800		$ 1,400
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	303,100		303,100
Credit agreement available	38,000		38,000
Sub-limit which may be used for issuance of letters of credit	15,000		$ 15,000
Borrowing base amount						$ 200,000
Commitment fee on unutilized borrowing base			0.50%
Credit agreement, outstanding	$ 172,000		$ 172,000
Credit Agreement | Thereafter
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5		4.5
Credit Facility Maturing March 31, 2020
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 500,000		$ 500,000
Lender loan
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 210,000		$ 210,000
Minimum | Credit Agreement
Line of Credit Facility [Line Items]
Consolidated current asset ratio			1
Required interest coverage ratio			2.5
Distribution limitation, credit facility excess over borrowing base (as a percent)			90.00%
Ownership percentage by subsidiary			50
Minimum | Credit Agreement | Scenario One
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4.5		4.5
Minimum | Credit Agreement | Scenario Two
Line of Credit Facility [Line Items]
Debt to Adjusted EBITDA ratio	4		4
Minimum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate			2.25%
Minimum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate			1.25%
Maximum | Credit Agreement | London Interbank Offered Rate (LIBOR)
Line of Credit Facility [Line Items]
Variable interest rate			3.25%
Maximum | Credit Agreement | ABR
Line of Credit Facility [Line Items]
Variable interest rate			2.25%

Oil And Natural Gas Propertie_3

Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Midstream assets	$ 186,845	$ 186,406
Less: Accumulated depreciation and amortization	(67,545)	(65,647)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	186,845	186,406
Less: Accumulated depreciation and amortization	(38,549)	(34,598)
Total gathering and transportation assets, net	$ 148,296	$ 151,808

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Jun. 30, 2019	Dec. 31, 2018
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,449	$ 112,173
Less: Accumulated depreciation, depletion, amortization and impairments	(67,545)	(65,647)
Oil and natural gas properties and equipment, net	$ 44,904	$ 46,526

Oil And Natural Gas Propertie_5

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 3,365	$ 3,365	$ 6,730	$ 6,730
Depreciation, depletion and amortization			5,873	6,443
Asset impairments	0	0	$ 0	0
Gathering Facilities
Property, Plant and Equipment [Line Items]
Useful lives			36 years
Oil and Natural Gas-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	828	1,251	$ 1,923	2,614
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	1,981	1,929	$ 3,950	3,829
Gathering and Transportation Related Assets | Minimum
Property, Plant and Equipment [Line Items]
Useful lives			3 years
Gathering and Transportation Related Assets | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			15 years
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	$ 6,174	$ 6,545	$ 12,603	$ 13,173

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Asset Retirement Obligation
Asset retirement obligation, beginning balance			$ 6,200	$ 6,074	$ 6,074
Liabilities added from escalating working interests			172		288
Sales					(613)
Revisions to cost estimates					(46)
Accretion expense	$ 126	$ 123	259	$ 249	497
Asset retirement obligation, ending balance	6,631		6,631		6,200
Legally restricted assets	$ 0		$ 0		$ 0

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2019USD ($)a	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Finite-Lived Intangible Assets [Line Items]
Beginning balance	$ 158,706	$ 172,166	$ 172,166
Amortization	(6,730)	$ 6,700	(13,460)
Ending balance	$ 151,976		$ 158,706
Customer Contracts
Finite-Lived Intangible Assets [Line Items]
Agreement term (in years)	15 years
Dedicated acreage | a	35,000
Useful life	15 years
Ending balance	$ 152,000

Investments (Details)

Investments (Details) $ in Thousands	1 Months Ended				3 Months Ended		6 Months Ended
	May 31, 2018amiMMcf	Apr. 30, 2018MMcf	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)
Schedule of Equity Method Investments [Line Items]
Acquisitions, earnout and capital investments					$ 128,140		$ 128,140		$ 127,899
Earnings (loss) from equity investments					791	$ 3,111	2,233	$ 7,383
Amortization of intangible assets					3,365	$ 3,365	6,730	6,730
Distributions received							8,164	13,101
Carnero Gathering, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)				50.00%
Payments to acquire interest in joint venture				$ 37,000			124,100
Assumption of capital commitments in joint venture				7,400
Daily processing capacity | MMcf	400
Acres dedicated for gathering | a	315,000
Carnero Gathering, Joint Venture | Customer Relationships
Schedule of Equity Method Investments [Line Items]
Intangible asset, fair value				$ 13,000
Agreement term (in years)				15 years
Carnero Processing, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			50.00%
Payments to acquire interest in joint venture			$ 55,500
Assumption of capital commitments in joint venture			$ 24,500
Carnero G&P, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%
Payments to acquire interest in joint venture							124,100
Daily processing capacity | MMcf	460	260
Number of miles of high pressure natural gas gathering pipelines | mi	45
Earnings (loss) from equity investments					1,100		2,800
Amortization of intangible assets					$ 300		600
Distributions received							8,200
Sanchez Energy | Carnero Gathering, Joint Venture
Schedule of Equity Method Investments [Line Items]
Earnout payments							$ 32,100	$ 0
Targa | Carnero Gathering, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)				50.00%
Targa | Carnero Processing, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)			50.00%
Targa | Carnero G&P, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	100.00%

Investments (Unconsolidated Ent

Investments (Unconsolidated Entities) (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Investments
Sales	$ 97,061	$ 179,798
Total expenses	88,647	163,091
Net income	$ 8,414	$ 16,707

Commitments And Contingencies (

Commitments And Contingencies (Details) - Carnero Gathering, Joint Venture - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 5.8
Sanchez Energy
Variable Interest Entity [Line Items]
Earnout payments	$ 32.1	$ 0

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019USD ($)a	Dec. 31, 2018USD ($)
Related Party Transaction [Line Items]
Related parties, net receivable	$ 6.5	$ 6.7
Related parties, net payable	$ 5.8	$ 5.6
Western Catarina Midstream | Sanchez Energy
Related Party Transaction [Line Items]
Agreement term (in years)	15 years
Acres dedicated for gathering | a	35,000

Unit-Based Compensation (Restri

Unit-Based Compensation (Restricted Units Activity) (Details) - LTIP - $ / shares	1 Months Ended		6 Months Ended
	Apr. 30, 2019	Mar. 31, 2019	Jun. 30, 2019
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Units available for issuance			703,185
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			513,694
Number of Restricted Units, Granted			1,129,173
Number of Restricted Units, Vested			(381,729)
Number of Restricted Units, Returned/Cancelled			(102,345)
Number of Restricted Units, Outstanding			1,158,793
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 12.31
Weighted Averaged Grant Date Fair Value Per Unit, Granted			2.35
Weighted Averaged Grant Date Fair Value Per Unit, Vested			8.49
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			12.05
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 3.88
Restricted Stock Units (RSUs) | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	137,613	991,560

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	Aug. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018
Common units
Distribution paid per unit		$ 0.1500	$ 0.1500	$ 0.1500	$ 0.4508	$ 0.4508
Class B preferred units
Distribution paid per unit		$ 0.28225	$ 0.28225	$ 0.28225	$ 0.2258	$ 0.28225
Aggregate distribution of units					310,009
Class C preferred units | Subsequent event
Class C Preferred Units payable in Class C Preferred PIK Units (as a percent)	100.00%
Aggregate distribution of units	939,327

Partners' Capital (Details)

Partners' Capital (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 25, 2017	Oct. 14, 2015	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2017	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2015	Aug. 31, 2018	Dec. 06, 2016
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding				31,310,896				31,310,896
Common units, outstanding				16,486,239				19,188,086
Units, issued				16,486,239				19,188,086
Class B preferred units, issued				31,310,896				31,310,896
Class B preferred units
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding								31,310,896
Units sold (in units)		19,444,445
Price per unit sold		$ 18
Proceeds from preferred units sold		$ 350
Percent of consideration paid		2.25%
Paid in full in cash, per annum										10.00%
Paid in part cash, per annum										12.00%
Dividend per annum										8.00%
Paid-in kind units per annum										4.00%
Class B preferred units, issued											310,009	9,851,996
Class B preferred units | Settlement Agreement with Stonepeak Catarina Holdings LLC
Limited Partners' Capital Account [Line Items]
Class B preferred units, issued	1,704,446
Class B preferred units, unit price	$ 11.29
Common units
Limited Partners' Capital Account [Line Items]
Common units, outstanding								19,188,086
Units sold (in units)			887,269	787,750	334,010	224,342	210,978		220,214
Unvested restricted common units | LTIP
Limited Partners' Capital Account [Line Items]
Common units, outstanding								1,158,793
Minimum | Class B preferred units
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount								$ 17.5

Partners' Capital (Class B Pref

Partners' Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Mezzanine equity, beginning balance	$ 349,857
Distributions	17,675	$ 17,500
Mezzanine equity, ending balance	353,067		$ 349,857
Class B preferred units
Mezzanine equity, beginning balance	349,857	$ 343,912	343,912
Amortization of discount	1,442		2,358
Distributions	19,443		36,925
Distributions paid	(17,675)		(33,338)
Mezzanine equity, ending balance	$ 353,067		$ 349,857

Reporting Segments (Segment Inf

Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Segment operating revenues:
Gathering and transportation lease revenues	$ 15,969	$ 13,168	$ 32,226	$ 25,486
Total revenues	21,855	17,039	39,345	35,575
Segment operating costs:
Lease operating expenses	2,065	2,007	3,780	3,978
Transportation operating expenses	3,048	3,071	5,724	5,918
Production taxes	141	287	324	609
Gain on sale of assets		(2,388)		(2,388)
Depreciation, depletion and amortization	6,174	6,545	12,603	13,173
Asset impairments	0	0	0	0
Accretion expense	126	123	259	249	$ 497
Total operating expenses	15,900	17,911	32,420	36,408
Segment other income (loss)
Earnings (loss) from equity investments	791	3,111	2,233	7,383
Segment operating income	11,092	10,505	18,888	21,419
Production
Segment operating revenues:
Total revenues	4,184	2,210	3,734	6,740
Segment operating costs:
Lease operating expenses	1,688	1,644	3,007	3,396
Production taxes	141	287	324	609
Gain on sale of assets		(2,388)		(2,388)
Depreciation, depletion and amortization	828	1,251	1,923	2,614
Accretion expense	46	49	100	103
Total operating expenses	2,703	843	5,354	4,334
Segment other income (loss)
Segment operating income	1,481	1,367	(1,620)	2,406
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	15,969	13,168	32,226	25,486
Total revenues	17,671	14,829	35,611	28,835
Segment operating costs:
Lease operating expenses	377	363	773	582
Transportation operating expenses	3,048	3,071	5,724	5,918
Depreciation, depletion and amortization	5,346	5,294	10,680	10,559
Accretion expense	80	74	159	146
Total operating expenses	8,851	8,802	17,336	17,205
Segment other income (loss)
Earnings (loss) from equity investments	791	3,111	2,233	7,383
Total segment other income (loss)	791	3,111	2,233	7,383
Segment operating income	9,611	9,138	20,508	19,013
Natural gas sales
Segment operating revenues:
Revenues	256	226	366	699
Natural gas sales | Production
Segment operating revenues:
Revenues	256	226	366	699
Oil sales
Segment operating revenues:
Revenues	3,811	1,584	3,072	5,046
Oil sales | Production
Segment operating revenues:
Revenues	3,811	1,584	3,072	5,046
Natural gas liquid product
Segment operating revenues:
Revenues	117	400	296	995
Natural gas liquid product | Production
Segment operating revenues:
Revenues	117	400	296	995
Gathering and transportation
Segment operating revenues:
Revenues	1,702	1,661	3,385	3,349
Gathering and transportation | Midstream
Segment operating revenues:
Revenues	$ 1,702	$ 1,661	$ 3,385	$ 3,349

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Reconciliation of segment operating income (loss) to net income (loss)
Segment operating income	$ 11,092		$ 10,505		$ 18,888	$ 21,419
General and administrative expense	(4,171)		(6,919)		(8,920)	(12,084)
Unit-based compensation expense	(175)		(1,347)		(810)	(2,785)
Interest expense, net	(2,814)		(2,780)		(5,600)	(5,379)
Other income (expense)	21		(1,254)		67	(1,524)
Income tax expense	(76)				(122)
Net income (loss)	3,877	$ (374)	(1,795)	$ 1,442	3,503	(353)
Production
Reconciliation of segment operating income (loss) to net income (loss)
Segment operating income	1,481		1,367		(1,620)	2,406
Midstream
Reconciliation of segment operating income (loss) to net income (loss)
Segment operating income	$ 9,611		$ 9,138		$ 20,508	$ 19,013

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 464,396	$ 486,685
Capital expenditures	782	4,867
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	48,162	53,556
Capital expenditures	103	11
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	414,129	429,523
Capital expenditures	679	4,856
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 2,105	$ 3,606

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	6 Months Ended	12 Months Ended
	Jul. 31, 2016	Jun. 30, 2019	Dec. 31, 2018
Variable Interest Entity [Line Items]
Acquisitions, earnout and capital investments		$ 128,140	$ 127,899
Earnings in equity investments		25,378	23,144
Distributions received		(44,742)	(36,578)
Maximum exposure to loss		108,776	$ 114,465
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	124,100
Debt incurred		$ 0

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent event - USD ($) $ in Millions	Aug. 30, 2019	Jul. 29, 2019	Jul. 09, 2019
Subsequent Event [Line Items]
Maximum borrowing capacity			$ 282
Payment of principal		$ 4
Outstanding debt on credit facility		$ 168
Class C preferred units
Subsequent Event [Line Items]
Class C Preferred Units payable in Class C Preferred PIK Units (as a percent)	100.00%
Distribution Made to Limited Partner, Unit Distribution	939,327
Production
Subsequent Event [Line Items]
Maximum borrowing capacity			20
Midstream
Subsequent Event [Line Items]
Maximum borrowing capacity			$ 262