Evolve Transition Infrastructure (SNMP) 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Nov. 07, 2018
Document And Entity Information
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Entity Registrant Name	Sanchez Midstream Partners LP
Entity Central Index Key	1,362,705
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding		16,188,926
Entity Current Reporting Status	Yes

Condensed Consolidated Statemen

Condensed Consolidated Statements of Operations - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Revenues
Gathering and transportation lease revenues	$ 13,148		$ 38,634
Total revenues	18,152	$ 18,596	53,727	$ 69,432
Operating expenses:
Lease operating expenses	1,905	1,735	5,883	10,599
Transportation operating expenses	3,061	2,661	8,979	8,989
Cost of sales				77
Production taxes	292	340	901	1,166
General and administrative expenses	5,109	5,614	17,193	17,576
Unit-based compensation expense	155	631	2,940	1,951
Gain on sale of assets	(238)	(2,546)	(2,626)	(2,546)
Depreciation, depletion and amortization	6,507	6,899	19,680	28,017
Asset impairments				4,688
Accretion expense	123	149	372	647
Total operating expenses	16,914	15,483	53,322	71,164
Other (income) expense
Interest expense, net	2,786	2,215	8,165	5,994
Earnings from equity investments	(2,313)	(2,873)	(9,696)	(4,397)
Other expense	352		1,876
Total other (income) expenses	825	(658)	345	1,597
Total expenses	17,739	14,825	53,667	72,761
Income (loss) before income taxes	413	3,771	60	(3,329)
Net income (loss)	413	3,771	60	(3,329)
Less:
Preferred unit paid-in-kind distributions			(3,500)	(2,625)
Preferred unit distributions	(8,838)	(8,750)	(24,588)	(24,500)
Preferred unit amortization	(608)	(463)	(1,707)	(1,300)
Net loss attributable to common unitholders	$ (9,033)	$ (5,442)	$ (29,735)	$ (31,754)
Net loss per unit
Common units - Basic and Diluted (in dollars per share)	$ (0.59)	$ (0.38)	$ (1.97)	$ (2.29)
Weighted Average Units Outstanding, Common Units - Basic and Diluted (in units)	15,398,453	14,313,999	15,114,671	13,888,057
Common units
Other (income) expense
Net income (loss)			$ 60	$ (3,329)
Natural gas sales
Revenues
Revenue from contracts with customers	$ 166	$ 787	865	5,818
Oil sales
Revenues
Revenue from contracts with customers	2,848	3,061	7,894	22,520
Natural gas liquid product
Revenues
Revenue from contracts with customers	408	514	1,403	1,473
Gathering and transportation
Revenues
Revenue from contracts with customers	$ 1,582	$ 14,234	$ 4,931	$ 39,621

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 2,311	$ 321
Accounts receivable	65	495
Accounts receivable - related entities	6,682	13,099
Prepaid expenses	1,001	2,670
Fair value of commodity derivative instruments	13	942
Assets held for sale	914
Total current assets	10,986	17,527
Oil and natural gas properties and related equipment
Oil and natural gas properties, equipment and facilities (successful efforts method)	112,516	170,750
Gathering and transportation assets	185,953	184,969
Less: accumulated depreciation, depletion, amortization and impairment	(97,472)	(142,574)
Oil and natural gas properties and equipment, net	200,997	213,145
Other assets
Intangible assets, net	162,071	172,166
Fair value of derivative instruments	85	1,318
Equity investments	117,677	123,715
Other non-current assets	452	552
Total assets	492,268	528,423
Current liabilities
Accounts payable and accrued liabilities	4,253	1,782
Accounts payable and accrued liabilities - related entities	5,570	10,353
Royalties payable	370	371
Fair value of derivative instruments	2,710	756
Other liabilities	444	151
Total current liabilities	13,347	13,413
Other liabilities
Asset retirement obligation	6,386	6,074
Long-term debt, net of debt issuance costs	182,300	187,808
Fair value of derivative instruments	2,894	273
Other liabilities	7,834	6,251
Total other liabilities	199,414	200,406
Total liabilities	212,761	213,819
Commitments and contingencies (See Note 12)
Mezzanine equity
Class B preferred units, 31,310,896 and 31,000,887 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively	349,207	343,912
Partners' deficit
Common units, 16,195,816 and 14,965,134 units issued and outstanding as of September 30, 2018 and December 31, 2017, respectively	(69,700)	(29,308)
Total partners' deficit	(69,700)	(29,308)
Total liabilities and partners' capital	$ 492,268	$ 528,423

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Parenthetical) - shares	Sep. 30, 2018	Dec. 31, 2017
Condensed Consolidated Balance Sheets
Class B preferred units, issued	31,310,896	31,000,887
Class B preferred units, outstanding	31,310,896	31,000,887
Units, issued	16,195,816	14,965,134
Units, outstanding	16,195,816	14,965,134

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Cash flows from operating activities:
Net income (loss)	$ 60	$ (3,329)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion and amortization	9,585	17,813
Amortization of debt issuance costs	498	391
Asset impairments		4,688
Accretion expense	372	647
Distributions from equity investments	18,572	5,329
Equity earnings in affiliate	(9,696)	(4,397)
Gain on sale of assets	(2,626)	(2,386)
Net (gains) losses on commodity derivative contracts	8,083	(7,584)
Net cash settlements received (paid) on commodity derivative contracts	(1,306)	5,093
Cash settlements on terminated commodity derivative contracts		3,602
Unit-based compensation	2,940	2,646
Loss on earnout derivative	1,876
Amortization of intangible assets	10,095	10,204
Costs for plug and abandon activities		(46)
Changes in Operating Assets and Liabilities:
Accounts receivable	196	159
Accounts receivable - related entities	6,364	(1,042)
Prepaid expenses	1,669	(348)
Other assets	62	124
Accounts payable and accrued liabilities	10,307	6,416
Accounts payable and accrued liabilities- related entities	(4,932)	(1,033)
Royalties payable	(1)	(301)
Net cash provided by operating activities	52,118	36,646
Cash flows from investing activities:
Final settlement of oil and natural gas properties acquisition		1,468
Development of oil and natural gas properties	(169)	(148)
Proceeds from sale of assets	6,209	5,510
Construction of gathering and transportation assets	(1,959)	(29,058)
Purchases of and contributions to equity affiliates	(2,838)	(10,380)
Net cash provided by (used in) investing activities	1,243	(32,608)
Cash flows from financing activities:
Payments for offering costs	(50)	(611)
Proceeds from issuance of debt	2,000	45,500
Repayment of debt	(7,000)	(9,500)
Issuance of common units		1,290
Distributions to common unitholders	(20,815)	(18,530)
Class B preferred unit cash distributions	(24,500)	(22,750)
Debt issuance costs	(1,006)	(27)
Net cash used in financing activities	(51,371)	(4,628)
Net increase (decrease) in cash and cash equivalents	1,990	(590)
Cash and cash equivalents, beginning of period	321	957
Cash and cash equivalents, end of period	2,311	367
Supplemental disclosures of cash flow information:
Change in accrued capital expenditures	450	2,414
Asset retirement obligation	288	198
Earnout derivative		221
Cash paid during the period for interest	$ 7,316	$ 5,494

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands	Common units	Total
Partner's Capital (Deficit) at Dec. 31, 2016	$ 16,744	$ 16,744
Partner's Capital (Deficit) (in shares) at Dec. 31, 2016	13,447,749
Unit-based compensation programs	$ 2,648	2,648
Unit-based compensation programs (in shares)	212,481
Issuance of common units, net of offering costs	$ 9,124	9,124
Issuance of common units, net of offering costs (in shares)	719,671
Cash distributions to common unit holders	$ (18,530)	(18,530)
Common units issued as Class B Preferred distributions	$ 5,250	5,250
Common units issued as Class B Preferred distributions (in shares)	393,291
Distributions - Class B preferred units	$ (28,425)	(28,425)
Net income (loss)	(3,329)	(3,329)
Partner's Deficit at Sep. 30, 2017	$ (16,518)	(16,518)
Partner's Deficit (in shares) at Sep. 30, 2017	14,773,192
Partner's Capital (Deficit) at Dec. 31, 2017	$ (29,308)	(29,308)
Partner's Capital (Deficit) (in shares) at Dec. 31, 2017	14,965,134
Unit-based compensation programs	$ 2,940	2,940
Unit-based compensation programs (in shares)	575,148
Issuance of common units, net of offering costs	$ 7,218	7,218
Issuance of common units, net of offering costs (in shares)	655,534
Cash distributions to common unit holders	$ (20,815)	(20,815)
Distributions - Class B preferred units	(29,795)	(29,795)
Net income (loss)	60	60
Partner's Deficit at Sep. 30, 2018	$ (69,700)	$ (69,700)
Partner's Deficit (in shares) at Sep. 30, 2018	16,195,816

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Changes in Partners’ Capital (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Sep. 30, 2017
Condensed Consolidated Statements of Changes in Partners’ Capital
Offering costs	$ 0.1	$ 0.6

Organization And Business

Organization And Business	9 Months Ended
	Sep. 30, 2018
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. The Partnership has 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, the sole member of our general partner, pursuant to which Manager provides services that the Partnership requires to operate its 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. Manager owns the general partner of SNMP and all of SNMP’s 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	9 Months Ended
	Sep. 30, 2018
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 (“U.S. 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. Midstream includes Western Catarina Midstream (defined in Note 10 “Intangible Assets”), the Carnero JV (defined in Note 11 “Investments”) and Seco Pipeline (defined in Note 13 “Related Party Transactions”). Our management evaluates performance based on these two 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 U.S. 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 the audited consolidated financial statements and notes thereto of SNMP and its subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2017, which was filed with the SEC on March 12, 2018. Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. In August 2018, the 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. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements. In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805) - Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The Partnership adopted this ASU on January 1, 2018, using a prospective method. In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is now effective for public business entities beginning after December 15, 2017. The Partnership does not currently have restricted cash. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and is now effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The adoption of ASU 2016-16 did not have an impact on the Partnership’s unaudited condensed consolidated financial statements and related disclosures. 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 the 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 plans on electing 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-to-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 will not early adopt this standard and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Partnership is currently evaluating the impact of these rules on its consolidated financial statements and has identified the population of leases under the revised definition. The Partnership is also in the process of implementing a lease accounting software to properly account for lease data upon adoption. Concurrent with the software implementation, the Partnership is implementing necessary updates to its business processes and controls. The adoption of this standard will result in an increase in the assets and liabilities on the Partnership’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, May and December of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Partnership adopted the standard effective January 1, 2018. For more information, see Note 3 “Revenue Recognition.” 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 U.S. GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. 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	9 Months Ended
	Sep. 30, 2018
Revenue Recognition
Revenue Recognition	3. REVENUE RECOGNITION Adoption of Topic 606 Effective January 1, 2018, the Partnership adopted the new Accounting Standards Codification (“ASC”) 606, Revenue from Contracts with Customers, and all the related amendments (collectively referred to as “Topic 606”) to all open contracts using the modified retrospective approach. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. For contracts that have a contract term of one year or less, we elected to utilize the practical expedient permitted under the rules of adoption whereby a Company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Adoption of this guidance resulted in financial statement presentation changes whereby revenue from the Gathering Agreement and revenue from the Seco Pipeline Transportation Agreement (as each term is defined in Note 13 “Related Party Transactions”) are shown as separate line items within our condensed consolidated statements of operations. There was no cumulative adjustment to retained earnings or any other changes to our January 1, 2018 condensed consolidated balance sheet. Revenue from Contracts with Customers Beginning in 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 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. Topic 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 our only contract that we account for under Topic 606. The Catarina Midstream Gathering Agreement was classified as an operating lease at inception and is accounted for under ASC 840, 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 Topic 606. We recognized revenue of $18.2 million for three months ended September 30, 2018. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Three Months Ended September 30, 2018 Production Midstream Total Revenues: Natural gas sales $ 166 $ — $ 166 Oil sales 2,848 — 2,848 Natural gas liquid sales 408 — 408 Gathering and transportation sales — 1,582 1,582 Gathering and transportation lease revenues — 13,148 13,148 Total revenues $ 3,422 $ 14,730 $ 18,152 We recognized revenue of $53.7 million for nine months ended September 30, 2018. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Nine Months Ended September 30, 2018 Production Midstream Total Revenues: Natural gas sales $ 865 $ — $ 865 Oil sales 7,894 — 7,894 Natural gas liquid sales 1,403 — 1,403 Gathering and transportation sales — 4,931 4,931 Gathering and transportation lease revenues — 38,634 38,634 Total revenues $ 10,162 $ 43,565 $ 53,727 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 606-10-50-14A(b) which is available only for wholly unsatisfied performance obligations for which the criteria in ASC 606-10-32-40 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 our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our contracts do not give rise to contract assets or liabilities under Reconciliation of Statements of Operations The impact of adopting Topic 606 on our condensed consolidated statements of operations is as follows (in thousands): Three Months Ended September 30, 2018 As reported Balances without Adoption Topic 606 Effect of change Higher/(Lower) Statement of Operations Gathering and transportation sales $ 1,582 $ 14,730 $ (13,148) Gathering and transportation lease revenues 13,148 — 13,148 Net earnings $ 14,730 $ 14,730 $ — Nine Months Ended September 30, 2018 As reported Balances without Adoption Topic 606 Effect of change Higher/(Lower) Statement of Operations Gathering and transportation sales $ 4,931 $ 43,565 $ (38,634) Gathering and transportation lease revenues 38,634 — 38,634 Net earnings $ 43,565 $ 43,565 $ — We expect the impact of the adoption of Topic 606 to be immaterial to our net income (loss) on an ongoing basis.

Acquisitions and Divestitures

Acquisitions and Divestitures	9 Months Ended
	Sep. 30, 2018
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 divestiture closed on October 22, 2018, and we anticipate recording a gain on the sale. As of September 30, 2018, we reclassified $0.9 million of oil and natural gas properties to assets held for sale on the condensed consolidated balance sheet related to the carrying amount of these assets. Briggs Divestiture In April 2018, we entered into a purchase and sale agreement to sell specified wellbores and other associated assets and interests in La Salle County Texas (the “Briggs Assets”) for a base purchase price of approximately $4.5 million which, after giving effect to purchase price adjustments, was reduced to approximately $4.2 million (the “Briggs Divestiture”). In addition, other than a limited amount of retained obligations, the buyer 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 a purchase and sale agreement to sell certain non-operated production assets located in Oklahoma for cash consideration of approximately $1.0 million. The divestiture closed on April 30, 2018, and we recorded a gain of approximately $1.1 million on the sale. Texas Production Divestiture In October 2017, we entered into a purchase and sale agreement to sell specified oil and gas wells, leases and other associated assets and interests located in Texas (the “Texas Production Assets”) for cash consideration of approximately $6.3 million (the “Texas Production Divestiture”). In addition, the buyer agreed to assume all obligations relating to the Texas Production Assets, including all plugging and abandonment costs, that may arise on or after October 1, 2017. The Texas Production Divestiture closed on November 13, 2017, and we recorded a gain of approximately $1.4 million on the sale. Oklahoma Non-Operated Production Divestiture In July 2017, we entered into an agreement to assign our interest in certain non-operated production assets located in Oklahoma, as well as our equity interests in the entities that owned such assets, in exchange for agreeing upon the apportionment of certain shared litigation costs. The assignment became effective as of July 14, 2017. Oklahoma Production Divestiture In May 2017, we entered into a purchase and sale agreement to sell all of the Partnership’s equity interests in the entities that owned our remaining operated Oklahoma production assets for cash consideration of $5.5 million, and assumption by the buyer of all obligations relating to such assets arising after the closing date and all plugging and abandonment costs relating to the assets arising prior to the closing date (the “Oklahoma Production Divestiture”). The Oklahoma Production Divestiture closed on July 17, 2017, and we recorded a gain of $2.4 million on the sale.

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 (in thousands): Fair Value Measurements at September 30, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative liability $ — $ (5,506) $ — $ (5,506) Midstream derivative instrument Earnout derivative liability — — (8,278) (8,278) Total $ — $ (5,506) $ (8,278) $ (13,784) 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, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 1,231 $ — $ 1,231 Midstream derivative instrument Earnout derivative liability — — (6,402) (6,402) Total $ — $ 1,231 $ (6,402) $ (5,171) As of September 30, 2018 and December 31, 2017, 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 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 September 30, 2018. However, the following table summarizes the non-recurring fair value measurements of our assets as of December 31, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 7,277 Total net assets $ — $ — $ 7,277 (a) During the year ended December 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties. The carrying values of the impaired properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement. 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. Credit Agreement – We believe that the carrying value of long-term debt for 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. Our 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 September 30, 2018. 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. 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 our earnout derivative as Level 3 and currently present it within the other liabilities lines 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 classified as Level 3 in the fair value hierarchy (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Beginning balance $ (6,402) $ (4,270) Initial fair value of earnout derivative — 221 Loss on earnout derivative (1,876) (2,353) Ending balance $ (8,278) $ (6,402) Loss included in earnings related to derivatives still held as of September 30, 2018 and December 31, 2017, respectively $ (1,876) $ (2,353)

Derivative And Financial Instru

Derivative And Financial Instruments	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018, 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 2018 — $ — — $ — — $ — 59,704 $ 59.84 59,704 $ 59.84 2019 62,528 $ 60.41 59,552 $ 60.44 57,024 $ 60.48 54,824 $ 60.52 233,928 $ 60.46 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 494,216 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 2018 — $ — — $ — — $ — 117,040 $ 3.00 117,040 $ 3.00 2019 119,832 $ 2.85 115,784 $ 2.85 112,032 $ 2.85 108,552 $ 2.85 456,200 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 975,688 The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the nine months ended September 30, 2018 and the year ended December 31, 2017 (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Beginning fair value of commodity derivatives $ 1,231 $ 6,436 Net gains (losses) on crude oil derivatives (8,110) 3,284 Net gains on natural gas derivatives 27 663 Net settlements paid (received) on derivative contracts: Oil 1,383 (6,422) Natural gas (37) (2,730) Ending fair value of commodity derivatives $ (5,506) $ 1,231 The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Amount of Gain (Loss) in Income Location of Gain(Loss) Three Months Ended September 30, Nine Months Ended September 30, Derivative Type in Income 2018 2017 2018 2017 Commodity – Mark-to-Market Oil sales $ (2,454) $ (1,456) $ (8,110) $ 7,087 Commodity – Mark-to-Market Natural gas sales 23 (228) 27 497 $ (2,431) $ (1,684) $ (8,083) $ 7,584 Derivative instruments expose us to counterparty credit risk. Our commodity derivative instruments are currently contracted with four 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. In August 2017, we repositioned certain of our crude oil and natural gas hedges in anticipation of the sale of the Texas Production Assets and, in the process, received $3.6 million in net cash from the counterparties on those hedges. As of September 30, 2018 and December 31, 2017, 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	9 Months Ended
	Sep. 30, 2018
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 (the “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 the Partnership, certain of its subsidiaries and the administrative agent. 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 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 September 30, 2018, the borrowing base under the Credit Agreement was $310.0 million, with an elected commitment amount of $210.0 million, and w e had $184.0 million of debt outstanding under the facility, leaving us with $26.0 million in unused borrowing capacity. There were no letters of credit outstanding under our Credit Agreement as of September 30, 2018. Our Credit Agreement matures on March 31, 2020. 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 of at least 1.0 to 1.0 at all times; · senior secured net debt to consolidated adjusted EBITDA 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 of directors of our general partner for the proper conduct of our business and the payment of fees and expenses. At September 30, 2018 , 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 September 30, 2018 and December 31, 2017 , our unamortized debt issuance costs were $ 1.7 million and $1.2 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 September 30, 2018 was $0.2 million and $0.1 million for the three months ended September 30, 2017. Amortization of debt issuance costs recorded during the nine months ended September 30, 2018 was $0.5 million and $0.4 million for the nine months ended September 30, 2017.

Oil And Natural Gas Properties

Oil And Natural Gas Properties And Related Equipment	9 Months Ended
	Sep. 30, 2018
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): September 30, December 31, 2018 2017 Gathering and transportation assets Midstream assets $ 185,953 $ 184,969 Less: Accumulated depreciation and amortization (32,639) (26,870) Total gathering and transportation assets $ 153,314 $ 158,099 Oil and natural gas properties consisted of the following (in thousands): September 30, December 31, 2018 2017 Oil and natural gas properties and related equipment Proved property $ 112,516 $ 170,750 Less: Accumulated depreciation, depletion, amortization and impairments (64,833) (115,704) Oil and natural gas properties and equipment, net $ 47,683 $ 55,046 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, amortization and impairments consisted of the following (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Depreciation, depletion and amortization of oil and natural gas-related assets $ 1,202 $ 1,739 $ 3,816 $ 7,850 Depreciation and amortization of gathering and transportation related assets 1,940 1,780 5,769 9,963 Amortization of intangible assets 3,365 3,380 10,095 10,204 Total Depreciation, depletion and amortization 6,507 6,899 19,680 28,017 Asset impairments — — — 4,688 Total $ 6,507 $ 6,899 $ 19,680 $ 32,705 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 the three months and nine months ended September 30, 2018, we recorded no impairment charges. For the three months ended September 30, 2017, we recorded no impairment charges. For the nine months ended September 30, 2017 we recorded non-cash charges of $4.7 million to impair certain of our producing oil and natural gas properties in Texas.

Asset Retirement Obligation

Asset Retirement Obligation	9 Months Ended
	Sep. 30, 2018
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 (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Asset retirement obligation, beginning balance $ 6,074 $ 13,579 Liabilities added from escalating working interests 288 198 Sales (348) (8,416) Settlements — (60) Accretion expense 372 773 Asset retirement obligation, ending balance $ 6,386 $ 6,074 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 nine months ended September 30, 2018 and the year ended December 31, 2017, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the nine months ended September 30, 2018, obligations were sold as part of the Briggs Divestiture and during the year ended December 31, 2017, obligations were sold as part of the Oklahoma Production Divestiture and the Texas Production Divestiture.

Investments

Investments	9 Months Ended
	Sep. 30, 2018
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 the e arnings from equity investments line within the 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 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, Carnero G&P, LLC (“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 Carnero JV, which expands the processing capacity of the joint venture from 260 MMcf/d to 460 MMcf/d, (3) Targa contributed certain capacity in the Carnero Gathering Line to Carnero JV resulting in the joint venture owning all of the capacity in the Carnero Gathering Line, which has a design limit (without compression) of 400 MMcf/d, (4) the joint venture received a new dedication of over 315,000 Comanche acres in the Western Eagle Ford, operated by Sanchez Energy. As a result of the Carnero JV Transaction we now record our share of earnings and losses from Carnero JV using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting, beginning with the three months ended June 30, 2018. The HLBV is a balance-sheet approach that calculates the amount we would have received if 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 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 September 30, 2018, the Partnership had paid approximately $123. 8 million for its investment in 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 joint venture 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 September 30, 2018, the Partnership recorded earnings of approximately $ 2.6 million in equity investments from Carnero JV, which was offset by approximately $0.3 million related to the amortization of the contractual customer intangible asset. For the nine months ended September 30, 2018, the Partnership recorded earnings of approximately $ 10.6 million in equity investments from Carnero JV, which was offset by approximately $0.9 million related to the amortization of the contractual customer intangible asset. We have included these equity method earnings in the earnings from equity investments line within the condensed consolidated statements of operations. Cash distributions of approximately $18.6 million were received during the nine months ended September 30, 2018. Summarized financial information of unconsolidated entities is as follows (in thousands): Nine Months Ended September 30, 2018 2017 Sales $ 257,470 $ 57,406 Total expenses 234,341 46,734 Net income $ 23,129 $ 10,672 September 30, December 31, 2018 2017 Current assets $ 38,501 $ 38,344 Noncurrent assets 292,253 193,748 Current liabilities 26,387 24,710

Commitments And Contingencies

Commitments And Contingencies	9 Months Ended
	Sep. 30, 2018
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 $8.3 million and was recorded on the balance sheet as other liabilities as of September 30, 2018. For the three and nine months ended September 30, 2018 and 2017, natural gas received did not exceed the threshold.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions
Related Party Transactions	13. RELATED PARTY TRANSACTIONS See our Annual Report on Form 10-K for a more complete description of our Sanchez-Related Agreements and Sanchez-Related Transactions that were entered into prior to 2018. The following are updates 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. In May 2018, we executed the Carnero JV Transaction with Targa. In connection with the Carnero JV Transaction, effective April 1, 2018, a subsidiary of Sanchez Energy and Carnero JV entered into a Firm Gas Gathering, Processing and Purchase Agreement (the “Carnero Gas Gathering Agreement”) and other related documentation providing for certain gas gathering, treating and processing services in exchange for an approximately 315,000 gross acreage dedication from the subsidiary of Sanchez Energy and its working interest partners. Additionally, effective April 1, 2018, and in connection with the Carnero JV Transaction, another subsidiary of Sanchez Energy and an affiliate of Targa also amended their Firm Gas Gathering Agreement (the “Amended Gathering Agreement”) and Firm Gas Processing Agreement (the “Amended Processing Agreement”) which were subsequently assigned by the Targa counterparty to Carnero JV. As of September 30, 2018 and December 31, 2017, the Partnership had a net receivable from related parties of approximately $6.7 million, and $13.1 million, respectively, which are included in accounts receivable – related entities on the condensed consolidated balance sheets. As of September 30, 2018 and December 31, 2017, the Partnership also had a net payable to related parties of approximately $ 5.6 million, and $10.4 million, respectively, which are included in accounts payable – related entities on the condensed consolidated balance sheets. The net receivable/payable as of September 30, 2018 and December 31, 2017 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	9 Months Ended
	Sep. 30, 2018
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, 2017 283,138 $ 14.64 Granted 622,534 11.94 Vested (236,495) 13.62 Returned/Cancelled (47,386) 12.50 Outstanding at September 30, 2018 621,791 $ 12.49 In April 2018, the Partnership issued 63,630 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 April 2018, the Partnership issued 244,813 and 314,091 restricted common units pursuant to the LTIP to executives that vest on the first anniversary of the date of grant and to non-executive employees that vest over three years from the date of grant, respectively. In March 2017, the Partnership issued 171,231 restricted common units pursuant to the LTIP to executives of the Partnership’s general partner that vested on the first anniversary of the date of grant in March 2018. The unit-based compensation expense for the award was based on the fair value on the day before the date of grant. As of September 30, 2018, 1,215,697 common units remained available for future issuance to participants under the LTIP.

Distributions To Unitholders

Distributions To Unitholders	9 Months Ended
	Sep. 30, 2018
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 nine months ended September 30, 2018 and the year ended December 31, 2017. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2017 $ 0.4375 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.4441 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.4508 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.4508 February 8, 2018 February 20, 2018 February 28, 2018 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 $ 0.15 November 9, 2018 November 20, 2018 November 30, 2018 The table below reflects the payment of distributions on Class B Preferred Units (defined below) related to the nine months ended September 30, 2018, and the year ended December 31, 2017. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2017 (a) $ 0.2258 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.28225 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.28225 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.28225 February 8, 2018 February 20, 2018 February 28, 2018 March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (b) $ 0.2258 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.28225 November 9, 2018 November 20, 2018 November 30, 2018 (a) The Partnership elected to pay the first quarter 2017 distribution on the Class B Preferred Units in part cash and, with consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B Preferred Units). Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017. (b) 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 Units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred Units, each payable on August 31, 2018 to holders of record on August 21, 2018.

Partners' Capital

Partners' Capital	9 Months Ended
	Sep. 30, 2018
Partners' Capital
Partners' Capital	16. PARTNERS’ CAPITAL Outstanding Units As of September 30, 2018, we had 31, 310,896 Class B Preferred Units outstanding, and 16,195,816 common units outstanding, which included 621,791 unvested restricted common units issued under the LTIP. Common Unit Issuances The following table shows the common units issued by the Partnership in 2017 and 2018 to SP Holdings in connection with providing services under the Services Agreement: Common Date of Three months ended units issuance September 30, 2016 170,750 March 6, 2017 December 31, 2016 154,737 March 6, 2017 March 31, 2017 139,110 June 30, 2017 June 30, 2017 170,497 August 31, 2017 September 30, 2017 186,942 November 30, 2017 December 31, 2017 210,978 March 15, 2018 March 31, 2018 220,214 May 31, 2018 June 30, 2018 224,342 September 10, 2018 The Partnership elected to pay the first quarter 2017 distribution on the Class B Preferred Units in part cash and, with the consent of Stonepeak Catarina Holdings LLC (“Stonepeak”), the holder of our Class B Preferred Units, in part common units (in lieu of additional Class B Preferred Units). Accordingly, the Partnership issued 184,697 common units on May 22, 2017, to Stonepeak. In April 2017, we issued 84,577 common units in registered offerings for gross proceeds of approximately $1.3 million pursuant to a shelf registration statement originally filed with the SEC on March 6, 2015 as updated by that certain prospectus supplement filed with the SEC on April 6, 2017 (the “Shelf Registration Statement”). The Shelf Registration Statement allows the Partnership to sell up to $50.0 million of common units by any method deemed an “at the market offering” (as such term is defined in Rule 415 of the Securities Act of 1933, as amended). Proceeds from such sales are expected to be used to fund general limited partnership purposes, including possible acquisitions. Proceeds from the 2017 at-the-market equity issuance were used for general limited partnership purposes. Class B Preferred Unit Offering On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and 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 our partnership agreement, holders of the Class B Preferred Units receive a quarterly distribution, at the election of the board of directors of our general partner, 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 Amended and Restated Agreement of Limited Partnership of the Partnership (the “Amended 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 partnership agreement, on December 6, 2016 we 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 Amended Partnership Agreement. Pursuant to the Settlement Agreement, and in accordance with Section 5.4 of the Amended 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 Amended 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 issuance of the Class B Preferred Units pursuant to the Settlement Agreement was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof. 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 partnership agreement. Accordingly, the Partnership issued 310,009 Class B Preferred 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): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Mezzanine equity, beginning balance $ 343,912 $ 342,991 Amortization of discount 1,707 1,796 Distributions 28,088 35,875 Distributions paid (24,500) (36,750) Mezzanine equity, ending balance $ 349,207 $ 343,912 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 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 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 (loss) 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 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. Our 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	9 Months Ended
	Sep. 30, 2018
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. Three Months Ended September 30, 2018 2017 Production Midstream Production Midstream Segment revenues Natural gas sales $ 166 $ — $ 787 $ — Oil sales 2,848 — 3,061 — Natural gas liquid sales 408 — 514 — Gathering and transportation sales — 1,582 — 14,234 Gathering and transportation lease revenues — 13,148 — — Total segment revenues 3,422 14,730 4,362 14,234 Segment operating costs Lease operating expenses 1,597 308 1,585 150 Transportation operating expenses — 3,061 — 2,661 Production taxes 292 — 340 — Gain on sale of assets (238) — (2,546) — Depreciation, depletion and amortization 1,202 5,305 1,756 5,143 Accretion expense 48 75 80 69 Total segment operating costs 2,901 8,749 1,215 8,023 Segment other income Earnings from equity investments — 2,313 8 2,865 Total segment other income — 2,313 8 2,865 Segment operating income $ 521 $ 8,294 $ 3,155 $ 9,076 Nine Months Ended September 30, 2018 2017 Production Midstream Production Midstream Segment revenues Natural gas sales $ 865 $ — $ 5,818 $ — Oil sales 7,894 — 22,520 — Natural gas liquid sales 1,403 — 1,473 — Gathering and transportation sales — 4,931 — 39,621 Gathering and transportation lease revenues — 38,634 — — Total segment revenues 10,162 43,565 29,811 39,621 Segment operating costs Lease operating expenses 4,993 890 9,957 642 Transportation operating expenses — 8,979 — 8,989 Cost of sales — — 77 — Production taxes 901 — 1,166 — Gain on sale of assets (2,626) — (2,546) — Depreciation, depletion and amortization 3,816 15,864 7,961 20,056 Asset impairments — — 4,688 — Accretion expense 151 221 444 203 Total segment operating costs 7,235 25,954 21,747 29,890 Segment other income (loss) Earnings (loss) from equity investments — 9,696 (101) 4,498 Total segment other income (loss) — 9,696 (101) 4,498 Segment operating income $ 2,927 $ 27,307 $ 7,963 $ 14,229 Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Reconciliation of segment operating income to net income (loss) Total production operating income $ 521 $ 3,155 $ 2,927 $ 7,963 Total midstream operating income 8,294 9,076 27,307 14,229 Total segment operating income 8,815 12,231 30,234 22,192 General and administrative expense (5,109) (5,614) (17,193) (17,576) Unit-based compensation expense (155) (631) (2,940) (1,951) Interest expense, net (2,786) (2,215) (8,165) (5,994) Other expense (a) (352) — (1,876) — Net income (loss) $ 413 $ 3,771 $ 60 $ (3,329) (a) Other expense in 2017 excludes earnout rebate. As the rebate is reviewed by the CODM at the segment level, it was included in the Midstream segment operating costs. The following table summarizes the total assets and capital expenditures by operating segment based on the segment realignment as of September 30, 2018 and December 31, 2017 (in thousands): September 30, 2018 Production Midstream Corporate (a) Total Other financial information Total assets $ 51,927 $ 437,374 $ 2,967 $ 492,268 Capital expenditures (b) $ 169 $ 4,403 $ — $ 4,572 December 31, 2017 Production Midstream Corporate (a) Total Other financial information Total assets $ 58,623 $ 468,656 $ 1,144 $ 528,423 Capital expenditures (b) $ 441 $ 46,452 $ — $ 46,893 (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	9 Months Ended
	Sep. 30, 2018
Variable Interest Entities
Variable Interest Entities	18. VARIABLE INTEREST ENTITIES The Partnership’s investment in 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 Carnero JV is limited to the capital investment of approximately $117.7 million. As of September 30, 2018, the Partnership had invested approximately $123.8 million in Carnero JV and no debt has been incurred by Carnero JV. We have included this VIE in the equity investments long-term asset line 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 September 30, 2018 and December 31, 2017 (in thousands): September 30, 2018 December 31, 2017 Acquisitions and capital investments $ 127,899 $ 125,059 Earnings in equity investments 19,982 10,288 Distributions received (30,204) (11,632) Maximum exposure to loss $ 117,677 $ 123,715

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2018
Subsequent Events
Subsequent Events	19. SUBSEQUENT EVENTS On November 8, 2018, the board of directors of our general partner declared a third quarter 2018 cash distribution on the Partnership’s common units of $0.15 per unit ($0.60 per unit annualized) payable on November 30, 2018 to the holders of record on November 20, 2018. The Partnership also declared a third quarter distribution on the Class B Preferred Units and elected to pay the distribution in cash. Accordingly, the Partnership declared a cash distribution of $0.28225 per Class B Preferred Unit payable on November 30, 2018 to holders of record on November 20, 2018. On October 22, 2018, we completed the sale of certain non-operated production assets located in Louisiana for a purchase price of approximately $1.3 million, after giving effect to customary closing adjustments. In addition, the buyer agreed to assume all obligations that arise on or after August 1, 2018.

Basis Of Presentation And Sum_2

Basis Of Presentation And Summary Of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
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 (“U.S. 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. Midstream includes Western Catarina Midstream (defined in Note 10 “Intangible Assets”), the Carnero JV (defined in Note 11 “Investments”) and Seco Pipeline (defined in Note 13 “Related Party Transactions”). Our management evaluates performance based on these two 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 U.S. 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 the audited consolidated financial statements and notes thereto of SNMP and its subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2017, which was filed with the SEC on March 12, 2018.
Recent Accounting Pronouncements	Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. In August 2018, the 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. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2018. We are currently in the process of evaluating the impact of adoption of this guidance on our condensed consolidated financial statements. In January 2017, the FASB issued ASU 2017-01 “Business Combinations (Topic 805) - Clarifying the Definition of a Business,” which provides a new framework for determining whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. This ASU is effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The Partnership adopted this ASU on January 1, 2018, using a prospective method. In November 2016, the FASB issued ASU 2016-18 “Statement of Cash Flows (Topic 230): Restricted Cash,” which requires companies to include cash and cash equivalents that have restrictions on withdrawal or use in total cash and cash equivalents on the statement of cash flows. This ASU is now effective for public business entities beginning after December 15, 2017. The Partnership does not currently have restricted cash. In October 2016, the FASB issued ASU 2016-16 “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory,” which eliminates a current exception in U.S. GAAP to the recognition of the income tax effects of temporary differences that result from intra-entity transfers of non-inventory assets. The intra-entity exception is being eliminated under the ASU. The standard is required to be applied on a modified retrospective basis and is now effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. The adoption of ASU 2016-16 did not have an impact on the Partnership’s unaudited condensed consolidated financial statements and related disclosures. 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 the 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 plans on electing 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-to-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 will not early adopt this standard and will apply the revised lease rules for our interim and annual reporting periods starting January 1, 2019. The Partnership is currently evaluating the impact of these rules on its consolidated financial statements and has identified the population of leases under the revised definition. The Partnership is also in the process of implementing a lease accounting software to properly account for lease data upon adoption. Concurrent with the software implementation, the Partnership is implementing necessary updates to its business processes and controls. The adoption of this standard will result in an increase in the assets and liabilities on the Partnership’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” In March, April, May and December of 2016, the FASB issued rules clarifying several aspects of the new revenue recognition standard. The new guidance is effective for fiscal years and interim periods beginning after December 15, 2017. This guidance outlines a new, single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. This new revenue recognition model provides a five-step analysis in determining when and how revenue is recognized. The new model will require revenue recognition to depict the transfer of promised goods or services to customers in an amount that reflects the consideration a company expects to receive in exchange for those goods and services. The new standard also requires more detailed disclosures related to the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. The Partnership adopted the standard effective January 1, 2018. For more information, see Note 3 “Revenue Recognition.” 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	Estimates The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the amounts reported in the condensed consolidated financial statements and accompanying footnotes. 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)	9 Months Ended
	Sep. 30, 2018
Schedule of disaggregation of revenue	We recognized revenue of $18.2 million for three months ended September 30, 2018. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Three Months Ended September 30, 2018 Production Midstream Total Revenues: Natural gas sales $ 166 $ — $ 166 Oil sales 2,848 — 2,848 Natural gas liquid sales 408 — 408 Gathering and transportation sales — 1,582 1,582 Gathering and transportation lease revenues — 13,148 13,148 Total revenues $ 3,422 $ 14,730 $ 18,152 We recognized revenue of $53.7 million for nine months ended September 30, 2018. The following table displays revenue disaggregated by type of revenue and product type (in thousands): Nine Months Ended September 30, 2018 Production Midstream Total Revenues: Natural gas sales $ 865 $ — $ 865 Oil sales 7,894 — 7,894 Natural gas liquid sales 1,403 — 1,403 Gathering and transportation sales — 4,931 4,931 Gathering and transportation lease revenues — 38,634 38,634 Total revenues $ 10,162 $ 43,565 $ 53,727
Accounting Standards Update 2014-09
Schedule of cumulative effect of adoption of ASC 606	The impact of adopting Topic 606 on our condensed consolidated statements of operations is as follows (in thousands): Three Months Ended September 30, 2018 As reported Balances without Adoption Topic 606 Effect of change Higher/(Lower) Statement of Operations Gathering and transportation sales $ 1,582 $ 14,730 $ (13,148) Gathering and transportation lease revenues 13,148 — 13,148 Net earnings $ 14,730 $ 14,730 $ — Nine Months Ended September 30, 2018 As reported Balances without Adoption Topic 606 Effect of change Higher/(Lower) Statement of Operations Gathering and transportation sales $ 4,931 $ 43,565 $ (38,634) Gathering and transportation lease revenues 38,634 — 38,634 Net earnings $ 43,565 $ 43,565 $ —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Measurements
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 September 30, 2018 (in thousands): Fair Value Measurements at September 30, 2018 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative liability $ — $ (5,506) $ — $ (5,506) Midstream derivative instrument Earnout derivative liability — — (8,278) (8,278) Total $ — $ (5,506) $ (8,278) $ (13,784) 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, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Commodity derivative instrument Derivative assets $ — $ 1,231 $ — $ 1,231 Midstream derivative instrument Earnout derivative liability — — (6,402) (6,402) Total $ — $ 1,231 $ (6,402) $ (5,171)
Non-Recurring Fair Value Measurements Of Assets And Liabilities	We had no non-recurring fair value measurements of our assets as of September 30, 2018. However, the following table summarizes the non-recurring fair value measurements of our assets as of December 31, 2017 (in thousands): Fair Value Measurements at December 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 7,277 Total net assets $ — $ — $ 7,277 During the year ended December 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties. The carrying values of the impaired properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement.
Reconciliation Of Changes In Fair Value Of Derivatives Classified As Level 3	The following table sets forth a reconciliation of changes in the fair value of the Partnership's earnout derivative classified as Level 3 in the fair value hierarchy (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Beginning balance $ (6,402) $ (4,270) Initial fair value of earnout derivative — 221 Loss on earnout derivative (1,876) (2,353) Ending balance $ (8,278) $ (6,402) Loss included in earnings related to derivatives still held as of September 30, 2018 and December 31, 2017, respectively $ (1,876) $ (2,353)

Derivative And Financial Inst_2

Derivative And Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
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 2018 — $ — — $ — — $ — 59,704 $ 59.84 59,704 $ 59.84 2019 62,528 $ 60.41 59,552 $ 60.44 57,024 $ 60.48 54,824 $ 60.52 233,928 $ 60.46 2020 52,776 $ 53.50 50,960 $ 53.50 49,224 $ 53.50 47,624 $ 53.50 200,584 $ 53.50 494,216 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 2018 — $ — — $ — — $ — 117,040 $ 3.00 117,040 $ 3.00 2019 119,832 $ 2.85 115,784 $ 2.85 112,032 $ 2.85 108,552 $ 2.85 456,200 $ 2.85 2020 105,104 $ 2.85 102,008 $ 2.85 99,136 $ 2.85 96,200 $ 2.85 402,448 $ 2.85 975,688
Reconciliation Of Changes In Fair Value Of Derivatives	The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the nine months ended September 30, 2018 and the year ended December 31, 2017 (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Beginning fair value of commodity derivatives $ 1,231 $ 6,436 Net gains (losses) on crude oil derivatives (8,110) 3,284 Net gains on natural gas derivatives 27 663 Net settlements paid (received) on derivative contracts: Oil 1,383 (6,422) Natural gas (37) (2,730) Ending fair value of commodity derivatives $ (5,506) $ 1,231
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations	The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Amount of Gain (Loss) in Income Location of Gain(Loss) Three Months Ended September 30, Nine Months Ended September 30, Derivative Type in Income 2018 2017 2018 2017 Commodity – Mark-to-Market Oil sales $ (2,454) $ (1,456) $ (8,110) $ 7,087 Commodity – Mark-to-Market Natural gas sales 23 (228) 27 497 $ (2,431) $ (1,684) $ (8,083) $ 7,584

Oil And Natural Gas Propertie_2

Oil And Natural Gas Properties And Related Equipment (Tables)	9 Months Ended
	Sep. 30, 2018
Oil And Natural Gas Properties And Related Equipment.
Gathering and Transportation Assets	Gathering and transportation assets consisted of the following (in thousands): September 30, December 31, 2018 2017 Gathering and transportation assets Midstream assets $ 185,953 $ 184,969 Less: Accumulated depreciation and amortization (32,639) (26,870) Total gathering and transportation assets $ 153,314 $ 158,099
Oil and Natural Gas Properties	September 30, December 31, 2018 2017 Gathering and transportation assets Midstream assets $ 185,953 $ 184,969 Less: Accumulated depreciation and amortization (32,639) (26,870) Total gathering and transportation assets $ 153,314 $ 158,099 Oil and natural gas properties consisted of the following (in thousands): September 30, December 31, 2018 2017 Oil and natural gas properties and related equipment Proved property $ 112,516 $ 170,750 Less: Accumulated depreciation, depletion, amortization and impairments (64,833) (115,704) Oil and natural gas properties and equipment, net $ 47,683 $ 55,046
Depreciation, Depletion, Amortization and Impairments	Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Depreciation, depletion and amortization of oil and natural gas-related assets $ 1,202 $ 1,739 $ 3,816 $ 7,850 Depreciation and amortization of gathering and transportation related assets 1,940 1,780 5,769 9,963 Amortization of intangible assets 3,365 3,380 10,095 10,204 Total Depreciation, depletion and amortization 6,507 6,899 19,680 28,017 Asset impairments — — — 4,688 Total $ 6,507 $ 6,899 $ 19,680 $ 32,705

Asset Retirement Obligation (Ta

Asset Retirement Obligation (Tables)	9 Months Ended
	Sep. 30, 2018
Asset Retirement Obligation
Reconciliation of changes in asset retirement obligation	The following table is a reconciliation of changes in ARO (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Asset retirement obligation, beginning balance $ 6,074 $ 13,579 Liabilities added from escalating working interests 288 198 Sales (348) (8,416) Settlements — (60) Accretion expense 372 773 Asset retirement obligation, ending balance $ 6,386 $ 6,074

Intangible Assets (Tables)

Intangible Assets (Tables)	9 Months Ended
	Sep. 30, 2018
Intangible Assets
Schedule of Intangible assets	The following table is a reconciliation of changes in intangible assets (in thousands): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Beginning balance $ 172,166 $ 185,766 Disposals — (32) Amortization (10,095) (13,568) Ending balance $ 162,071 $ 172,166

Investments (Tables)

Investments (Tables)	9 Months Ended
	Sep. 30, 2018
Investments
Summarized financial information of unconsolidated entities	Summarized financial information of unconsolidated entities is as follows (in thousands): Nine Months Ended September 30, 2018 2017 Sales $ 257,470 $ 57,406 Total expenses 234,341 46,734 Net income $ 23,129 $ 10,672 September 30, December 31, 2018 2017 Current assets $ 38,501 $ 38,344 Noncurrent assets 292,253 193,748 Current liabilities 26,387 24,710

Unit-Based Compensation (Tables

Unit-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2018
Unit-Based Compensation
Schedule Of Units Activity	Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2017 283,138 $ 14.64 Granted 622,534 11.94 Vested (236,495) 13.62 Returned/Cancelled (47,386) 12.50 Outstanding at September 30, 2018 621,791 $ 12.49

Distributions To Unitholders (T

Distributions To Unitholders (Tables)	9 Months Ended
	Sep. 30, 2018
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, 2017 $ 0.4375 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.4441 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.4508 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.4508 February 8, 2018 February 20, 2018 February 28, 2018 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 $ 0.15 November 9, 2018 November 20, 2018 November 30, 2018
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, 2017 (a) $ 0.2258 May 10, 2017 May 22, 2017 May 31, 2017 June 30, 2017 $ 0.28225 August 9, 2017 August 22, 2017 August 31, 2017 September 30, 2017 $ 0.28225 November 7, 2017 November 20, 2017 November 30, 2017 December 31, 2017 $ 0.28225 February 8, 2018 February 20, 2018 February 28, 2018 March 31, 2018 $ 0.28225 May 8, 2018 May 22, 2018 May 31, 2018 June 30, 2018 (b) $ 0.2258 August 8, 2018 August 21, 2018 August 31, 2018 September 30, 2018 $ 0.28225 November 9, 2018 November 20, 2018 November 30, 2018 (a) The Partnership elected to pay the first quarter 2017 distribution on the Class B Preferred Units in part cash and, with consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B Preferred Units). Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017. 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 Units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B Preferred Unit and an aggregate distribution of 310,009 Class B Preferred Units, each payable on August 31, 2018 to holders of record on August 21, 2018.

Partners' Capital (Tables)

Partners' Capital (Tables)	9 Months Ended
	Sep. 30, 2018
Partners' Capital
Schedule of common unit issuances	Common Date of Three months ended units issuance September 30, 2016 170,750 March 6, 2017 December 31, 2016 154,737 March 6, 2017 March 31, 2017 139,110 June 30, 2017 June 30, 2017 170,497 August 31, 2017 September 30, 2017 186,942 November 30, 2017 December 31, 2017 210,978 March 15, 2018 March 31, 2018 220,214 May 31, 2018 June 30, 2018 224,342 September 10, 2018
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): Nine Months Ended Year Ended September 30, 2018 December 31, 2017 Mezzanine equity, beginning balance $ 343,912 $ 342,991 Amortization of discount 1,707 1,796 Distributions 28,088 35,875 Distributions paid (24,500) (36,750) Mezzanine equity, ending balance $ 349,207 $ 343,912

Reporting Segments (Tables)

Reporting Segments (Tables)	9 Months Ended
	Sep. 30, 2018
Reporting Segments
Schedule of segment information	Three Months Ended September 30, 2018 2017 Production Midstream Production Midstream Segment revenues Natural gas sales $ 166 $ — $ 787 $ — Oil sales 2,848 — 3,061 — Natural gas liquid sales 408 — 514 — Gathering and transportation sales — 1,582 — 14,234 Gathering and transportation lease revenues — 13,148 — — Total segment revenues 3,422 14,730 4,362 14,234 Segment operating costs Lease operating expenses 1,597 308 1,585 150 Transportation operating expenses — 3,061 — 2,661 Production taxes 292 — 340 — Gain on sale of assets (238) — (2,546) — Depreciation, depletion and amortization 1,202 5,305 1,756 5,143 Accretion expense 48 75 80 69 Total segment operating costs 2,901 8,749 1,215 8,023 Segment other income Earnings from equity investments — 2,313 8 2,865 Total segment other income — 2,313 8 2,865 Segment operating income $ 521 $ 8,294 $ 3,155 $ 9,076 Nine Months Ended September 30, 2018 2017 Production Midstream Production Midstream Segment revenues Natural gas sales $ 865 $ — $ 5,818 $ — Oil sales 7,894 — 22,520 — Natural gas liquid sales 1,403 — 1,473 — Gathering and transportation sales — 4,931 — 39,621 Gathering and transportation lease revenues — 38,634 — — Total segment revenues 10,162 43,565 29,811 39,621 Segment operating costs Lease operating expenses 4,993 890 9,957 642 Transportation operating expenses — 8,979 — 8,989 Cost of sales — — 77 — Production taxes 901 — 1,166 — Gain on sale of assets (2,626) — (2,546) — Depreciation, depletion and amortization 3,816 15,864 7,961 20,056 Asset impairments — — 4,688 — Accretion expense 151 221 444 203 Total segment operating costs 7,235 25,954 21,747 29,890 Segment other income (loss) Earnings (loss) from equity investments — 9,696 (101) 4,498 Total segment other income (loss) — 9,696 (101) 4,498 Segment operating income $ 2,927 $ 27,307 $ 7,963 $ 14,229
Schedule of reconciliation of segment operating income to net income (loss)	Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 Reconciliation of segment operating income to net income (loss) Total production operating income $ 521 $ 3,155 $ 2,927 $ 7,963 Total midstream operating income 8,294 9,076 27,307 14,229 Total segment operating income 8,815 12,231 30,234 22,192 General and administrative expense (5,109) (5,614) (17,193) (17,576) Unit-based compensation expense (155) (631) (2,940) (1,951) Interest expense, net (2,786) (2,215) (8,165) (5,994) Other expense (a) (352) — (1,876) — Net income (loss) $ 413 $ 3,771 $ 60 $ (3,329) (a) Other expense in 2017 excludes earnout rebate. As the rebate is reviewed by the CODM at the segment level, it was included in the Midstream segment operating costs.
Summary of assets and capital expenditures by operating segment	The following table summarizes the total assets and capital expenditures by operating segment based on the segment realignment as of September 30, 2018 and December 31, 2017 (in thousands): September 30, 2018 Production Midstream Corporate (a) Total Other financial information Total assets $ 51,927 $ 437,374 $ 2,967 $ 492,268 Capital expenditures (b) $ 169 $ 4,403 $ — $ 4,572 December 31, 2017 Production Midstream Corporate (a) Total Other financial information Total assets $ 58,623 $ 468,656 $ 1,144 $ 528,423 Capital expenditures (b) $ 441 $ 46,452 $ — $ 46,893 (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)	9 Months Ended
	Sep. 30, 2018
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 September 30, 2018 and December 31, 2017 (in thousands): September 30, 2018 December 31, 2017 Acquisitions and capital investments $ 127,899 $ 125,059 Earnings in equity investments 19,982 10,288 Distributions received (30,204) (11,632) Maximum exposure to loss $ 117,677 $ 123,715

Basis Of Presentation And Sum_3

Basis Of Presentation And Summary Of Significant Accounting Policies (Details)	9 Months Ended
	Sep. 30, 2018segment
Basis Of Presentation And Summary Of Significant Accounting Policies
Number of operating segments	2

Revenue Recognition (Disaggrega

Revenue Recognition (Disaggregation) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Disaggregation of Revenue [Line Items]
Gathering and transportation lease revenues	$ 13,148		$ 38,634
Total revenues	18,152	$ 18,596	53,727	$ 69,432
Natural gas sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	166	787	865	5,818
Oil sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,848	3,061	7,894	22,520
Natural gas liquid product
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	408	514	1,403	1,473
Gathering and transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	1,582	14,234	4,931	39,621
Production
Disaggregation of Revenue [Line Items]
Total revenues	3,422	4,362	10,162	29,811
Production | Natural gas sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	166	787	865	5,818
Production | Oil sales
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	2,848	3,061	7,894	22,520
Production | Natural gas liquid product
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	408	514	1,403	1,473
Midstream
Disaggregation of Revenue [Line Items]
Gathering and transportation lease revenues	13,148		38,634
Total revenues	14,730	14,234	43,565	39,621
Midstream | Gathering and transportation
Disaggregation of Revenue [Line Items]
Revenue from contracts with customers	$ 1,582	$ 14,234	$ 4,931	$ 39,621

Revenue Recognition (Contract B

Revenue Recognition (Contract Balances) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Jan. 01, 2018
Revenue Recognition
Payment term (in days)	30 days
Receivables	$ 0.7	$ 1.1

Revenue Recognition (ASC 606) (

Revenue Recognition (ASC 606) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gathering and transportation lease revenues	$ 13,148		$ 38,634
Total revenues	18,152	$ 18,596	53,727	$ 69,432
Natural gas liquid product
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	408	514	1,403	1,473
Oil sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	2,848	3,061	7,894	22,520
Natural gas sales
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	166	787	865	5,818
Gathering and transportation
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	1,582	14,234	4,931	39,621
Midstream
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gathering and transportation lease revenues	13,148		38,634
Total revenues	14,730	14,234	43,565	39,621
Midstream | Accounting Standards Update 2014-09 | Balances without Adoption Topic 606
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Total revenues	14,730		43,565
Midstream | Accounting Standards Update 2014-09 | Effect of change Higher/(Lower)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Gathering and transportation lease revenues	13,148		38,634
Midstream | Gathering and transportation
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	1,582	$ 14,234	4,931	$ 39,621
Midstream | Gathering and transportation | Accounting Standards Update 2014-09 | Balances without Adoption Topic 606
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	14,730		43,565
Midstream | Gathering and transportation | Accounting Standards Update 2014-09 | Effect of change Higher/(Lower)
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Revenue from contracts with customers	$ (13,148)		$ (38,634)

Acquisitions and Divestitures (

Acquisitions and Divestitures (Details) - USD ($) $ in Thousands	Oct. 22, 2018	Apr. 30, 2018	Oct. 31, 2017	May 31, 2017	Jun. 30, 2018	Dec. 31, 2017	Sep. 30, 2017	Sep. 30, 2018
Business Acquisition [Line Items]
Assets held for sale								$ 914
Louisiana Divestiture | Subsequent event
Business Acquisition [Line Items]
Proceeds from divestiture	$ 1,300
Oklahoma Production Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture				$ 5,500
Gain on sale							$ 2,400
Briggs Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture		$ 4,500
Proceeds from divestiture after purchase price adjustments		4,200
Gain on sale					$ 1,800
Texas Production Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture			$ 6,300
Gain on sale						$ 1,400
Cola Divestiture
Business Acquisition [Line Items]
Proceeds from divestiture		$ 1,000
Gain on sale					$ 1,100

Fair Value Measurements (Recurr

Fair Value Measurements (Recurring) (Details) $ in Thousands	Sep. 30, 2018USD ($)derivative	Dec. 31, 2017USD ($)
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		$ 1,231
Derivative liability	$ (5,506)	(6,402)
Earnout derivative liability	(8,278)
Total net assets	(13,784)	(5,171)
Fair Value, Inputs, Level 2 | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative assets		1,231
Derivative liability	(5,506)
Total net assets	(5,506)	1,231
Fair Value, Inputs, Level 3 | Recurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative liability		(6,402)
Earnout derivative liability	(8,278)
Total net assets	$ (8,278)	$ (6,402)

Fair Value Measurements (Non-Re

Fair Value Measurements (Non-Recurring) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2017	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Asset impairments	$ 4,688
Fair Value, Inputs, Level 3 | Nonrecurring
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Impairment		$ 7,277
Total net assets		$ 7,277

Fair Value Measurements (Embedd

Fair Value Measurements (Embedded and Earnout Derivative) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Fair Value Measurements
Beginning Balance	$ (6,402)	$ (4,270)
Initial fair value of earnout derivative		221
Loss on earnout derivative	(1,876)	(2,353)
Ending Balance	$ (8,278)	$ (6,402)

Derivative And Financial Inst_3

Derivative And Financial Instruments (Hedges In Place) (Details)	9 Months Ended
	Sep. 30, 2018MMBTU$ / bbl$ / MMBTUbbl
West Texas Intermediate 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in Bbls) | bbl	59,704
Average Price | $ / bbl	59.84
West Texas Intermediate 2018
Derivative [Line Items]
Volume (in Bbls) | bbl	59,704
Average Price | $ / bbl	59.84
West Texas Intermediate 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in Bbls) | bbl	62,528
Average Price | $ / bbl	60.41
West Texas Intermediate 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in Bbls) | bbl	59,552
Average Price | $ / bbl	60.44
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	233,928
Average Price | $ / bbl	60.46
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	494,216
NYMEX 2018 Swap Quarter 4
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	117,040
Average Price | $ / MMBTU	3
NYMEX 2,018
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	117,040
Average Price | $ / MMBTU	3
NYMEX 2019 Swap Quarter 1
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	119,832
Average Price | $ / MMBTU	2.85
NYMEX 2019 Swap Quarter 2
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	115,784
Average Price | $ / MMBTU	2.85
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 2,019
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	456,200
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 2,020
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	402,448
Average Price | $ / MMBTU	2.85
NYMEX
Derivative [Line Items]
Volume (in MMBtu) | MMBTU	975,688

Derivative And Financial Inst_4

Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands	1 Months Ended	3 Months Ended		9 Months Ended		12 Months Ended
	Aug. 31, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)item	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Derivative Instruments Gain Loss [Line Items]
Early termination of hedges	$ 3,600
Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Beginning fair value of commodity derivatives				$ 1,231	$ 6,436	$ 6,436
Net gains (losses) on derivatives		$ (2,431)	$ (1,684)	(8,083)	7,584
Ending fair value of commodity derivatives		(5,506)		$ (5,506)		1,231
Number of counterparties | item				4
Oil reserves | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		(2,454)	(1,456)	$ (8,110)	7,087	3,284
Net settlements paid (received) on derivative contracts						(6,422)
Net settlements paid (received) on derivative contracts				1,383
Natural gas sales | Commodity Contract
Derivative Instruments Gain Loss [Line Items]
Net gains (losses) on derivatives		$ 23	$ (228)	27	$ 497	663
Net settlements paid (received) on derivative contracts				$ (37)		$ (2,730)

Derivative And Financial Inst_5

Derivative And Financial Instruments (Effect On Statement Of Operations) (Details) - Commodity Contract - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	$ (2,431)	$ (1,684)	$ (8,083)	$ 7,584
Oil reserves
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	(2,454)	(1,456)	(8,110)	7,087	$ 3,284
Natural gas sales
Embedded Derivative [Line Items]
Net gains (losses) on derivatives	$ 23	$ (228)	$ 27	$ 497	$ 663

Long-Term Debt (Details)

Long-Term Debt (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)	May 19, 2016USD ($)
Line of Credit Facility [Line Items]
Letters of credit outstanding	$ 0		$ 0
Amortization of debt issuance costs	200	$ 100	498	$ 391
Unamortized debt issue costs	1,700		1,700		$ 1,200
Credit Agreement
Line of Credit Facility [Line Items]
Maximum borrowing capacity	310,000		310,000
Credit agreement available	26,000		26,000
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	$ 184,000		$ 184,000
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	Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Midstream assets	$ 185,953	$ 184,969
Less: Accumulated depreciation and amortization	(64,833)	(115,704)
Midstream
Property, Plant and Equipment [Line Items]
Midstream assets	185,953	184,969
Less: Accumulated depreciation and amortization	(32,639)	(26,870)
Total gathering and transportation assets	$ 153,314	$ 158,099

Oil And Natural Gas Propertie_4

Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Oil And Natural Gas Properties And Related Equipment.
Proved property	$ 112,516	$ 170,750
Less: Accumulated depreciation, depletion, amortization and impairments	(64,833)	(115,704)
Oil and natural gas properties and equipment, net	$ 47,683	$ 55,046

Oil And Natural Gas Propertie_5

Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Property, Plant and Equipment [Line Items]
Amortization of intangible assets	$ 3,365	$ 3,380	$ 10,095	$ 10,204
Depreciation, depletion and amortization			9,585	17,813
Asset impairments				4,688
Total	6,507	6,899	$ 19,680	32,705
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	1,202	1,739	$ 3,816	7,850
Gathering and Transportation Related Assets
Property, Plant and Equipment [Line Items]
Depreciation, depletion and amortization	1,940	1,780	$ 5,769	9,963
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	$ 6,507	$ 6,899	$ 19,680	$ 28,017

Asset Retirement Obligation (De

Asset Retirement Obligation (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Asset Retirement Obligation
Asset retirement obligation, beginning balance			$ 6,074	$ 13,579	$ 13,579
Liabilities added from escalating working interests			288		198
Sales			(348)		(8,416)
Settlements					(60)
Accretion expense	$ 123	$ 149	372	$ 647	773
Asset retirement obligation, ending balance	6,386		6,386		6,074
Legally restricted assets	$ 0		$ 0		$ 0

Intangible Assets (Details)

Intangible Assets (Details) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2018USD ($)a	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Finite-Lived Intangible Assets [Line Items]
Beginning balance	$ 172,166	$ 185,766	$ 185,766
Disposals			(32)
Amortization	(10,095)	$ 10,200	(13,568)
Ending balance	$ 162,071		$ 172,166
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	$ 162,100

Investments (Details)

Investments (Details) $ in Thousands	1 Months Ended			3 Months Ended		4 Months Ended	9 Months Ended
	May 31, 2018aMMcf	Nov. 30, 2016USD ($)	Jul. 31, 2016USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Apr. 30, 2018MMcf	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Capital investments				$ 127,899			$ 127,899		$ 125,059
Earnings (loss) from equity investments				2,313	$ 2,873		9,696	$ 4,397
Amortization of intangible assets				3,365	$ 3,380		10,095	10,204
Distributions received							18,572	$ 5,329
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				123,800
Assumption of capital commitments in joint venture			7,400
Daily processing capacity | MMcf	400
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 P&G, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%
Payments to acquire interest in joint venture							123,800
Daily processing capacity | MMcf	460					260
Acres dedicated for gathering | a	315,000
Earnings (loss) from equity investments				2,600			10,600
Amortization of intangible assets				$ 300			$ 900
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 P&G, Joint Venture
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%
Equity interests in plant transferred to joint venture (as a percent)	100.00%

Investments (Unconsolidated Ent

Investments (Unconsolidated Entities) (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Investments
Sales	$ 257,470	$ 57,406
Total expenses	234,341	46,734
Net income	23,129	$ 10,672
Current assets	38,501		$ 38,344
Noncurrent assets	292,253		193,748
Current liabilities	$ 26,387		$ 24,710

Commitments And Contingencies (

Commitments And Contingencies (Details) $ in Millions	Sep. 30, 2018USD ($)
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Earnout derivative liability	$ 8.3

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)a	May 31, 2018a	Dec. 31, 2017USD ($)
Related Party Transaction [Line Items]
Related parties, net receivable | $	$ 6.7		$ 13.1
Related parties, net payable | $	$ 5.6		$ 10.4
Carnero P&G, Joint Venture
Related Party Transaction [Line Items]
Acres dedicated for gathering | a		315,000
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		9 Months Ended
	Apr. 30, 2018	Mar. 31, 2017	Sep. 30, 2018
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	314,091
Units available for issuance			1,215,697
Vesting period			3 years
Executives
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	244,813
Restricted Stock Units (RSUs)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Outstanding			283,138
Number of Restricted Units, Granted		171,231	622,534
Number of Restricted Units, Vested			(236,495)
Number of Restricted Units, Returned/Cancelled			(47,386)
Number of Restricted Units, Outstanding			621,791
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 14.64
Weighted Averaged Grant Date Fair Value Per Unit, Granted			11.94
Weighted Averaged Grant Date Fair Value Per Unit, Vested			13.62
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled			12.50
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding			$ 12.49
Restricted Stock Units (RSUs) | Director
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of Restricted Units, Granted	63,630

Distributions To Unitholders (D

Distributions To Unitholders (Details) - $ / shares	3 Months Ended							9 Months Ended
	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Sep. 30, 2018	Sep. 30, 2017
Common units
Distribution paid per unit	$ 0.15	$ 0.4508	$ 0.4508	$ 0.4508	$ 0.4508	$ 0.4441	$ 0.4375
Aggregate distribution of units									393,291
Class B preferred units
Distribution paid per unit	$ 0.28225	$ 0.2258	$ 0.28225	$ 0.28225	$ 0.28225	$ 0.28225	$ 0.2258
Aggregate distribution of units							184,697	310,009

Partners' Capital (Details)

Partners' Capital (Details) - USD ($) $ / shares in Units, $ in Thousands	May 22, 2017	Jan. 25, 2017	Oct. 14, 2015	Apr. 30, 2017	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2015	Sep. 30, 2018	Sep. 30, 2017	Aug. 31, 2018	Dec. 06, 2016
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding							31,000,887							31,310,896
Common units, outstanding							14,965,134							16,195,816
Units, issued							14,965,134							16,195,816
Proceeds from common units sold															$ 1,290
Class B preferred units, issued							31,000,887							31,310,896
Class B preferred units
Limited Partners' Capital Account [Line Items]
Class B preferred units, outstanding														31,310,896
Units, issued																310,009	9,851,996
Units sold (in units)	184,697		19,444,445
Price per unit sold			$ 18
Proceeds from preferred units sold			$ 350,000
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 | 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														16,195,816
Units, issued				84,577
Units sold (in units)					224,342	220,214	210,978	186,942	170,497	139,110	154,737	170,750
Proceeds from common units sold				$ 1,300
Common units authorized for sale, value				$ 50,000
Unvested restricted common units | LTIP
Limited Partners' Capital Account [Line Items]
Common units, outstanding														621,791
Minimum | Class B preferred units
Limited Partners' Capital Account [Line Items]
Preferred unit conversion, amount														$ 17,500

Partners' Capital (Class B Pref

Partners' Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Mezzanine equity, beginning balance	$ 343,912
Distributions	24,500	$ 22,750
Mezzanine equity, ending balance	349,207		$ 343,912
Class B preferred units
Mezzanine equity, beginning balance	343,912	$ 342,991	342,991
Amortization of discount	1,707		1,796
Distributions	28,088		35,875
Distributions paid	(24,500)		(36,750)
Mezzanine equity, ending balance	$ 349,207		$ 343,912

Reporting Segments (Segment Inf

Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment operating revenues:
Gathering and transportation lease revenues	$ 13,148		$ 38,634
Total revenues	18,152	$ 18,596	53,727	$ 69,432
Segment operating costs:
Lease operating expenses	1,905	1,735	5,883	10,599
Transportation operating expenses	3,061	2,661	8,979	8,989
Cost of sales				77
Production taxes	292	340	901	1,166
Gain on sale of assets	(238)	(2,546)	(2,626)	(2,546)
Depreciation, depletion and amortization	6,507	6,899	19,680	28,017
Asset impairments				4,688
Accretion expense	123	149	372	647	$ 773
Total operating expenses	16,914	15,483	53,322	71,164
Segment other income (loss)
Earnings (loss) from equity investments	2,313	2,873	9,696	4,397
Segment operating income	8,815	12,231	30,234	22,192
Production
Segment operating revenues:
Total revenues	3,422	4,362	10,162	29,811
Segment operating costs:
Lease operating expenses	1,597	1,585	4,993	9,957
Cost of sales				77
Production taxes	292	340	901	1,166
Gain on sale of assets	(238)	(2,546)	(2,626)	(2,546)
Depreciation, depletion and amortization	1,202	1,756	3,816	7,961
Asset impairments				4,688
Accretion expense	48	80	151	444
Total operating expenses	2,901	1,215	7,235	21,747
Segment other income (loss)
Earnings (loss) from equity investments		8		(101)
Total segment other income		8		(101)
Segment operating income	521	3,155	2,927	7,963
Midstream
Segment operating revenues:
Gathering and transportation lease revenues	13,148		38,634
Total revenues	14,730	14,234	43,565	39,621
Segment operating costs:
Lease operating expenses	308	150	890	642
Transportation operating expenses	3,061	2,661	8,979	8,989
Depreciation, depletion and amortization	5,305	5,143	15,864	20,056
Accretion expense	75	69	221	203
Total operating expenses	8,749	8,023	25,954	29,890
Segment other income (loss)
Earnings (loss) from equity investments	2,313	2,865	9,696	4,498
Total segment other income	2,313	2,865	9,696	4,498
Segment operating income	8,294	9,076	27,307	14,229
Natural gas sales
Segment operating revenues:
Revenue from contracts with customers	166	787	865	5,818
Natural gas sales | Production
Segment operating revenues:
Revenue from contracts with customers	166	787	865	5,818
Oil sales
Segment operating revenues:
Revenue from contracts with customers	2,848	3,061	7,894	22,520
Oil sales | Production
Segment operating revenues:
Revenue from contracts with customers	2,848	3,061	7,894	22,520
Natural gas liquid product
Segment operating revenues:
Revenue from contracts with customers	408	514	1,403	1,473
Natural gas liquid product | Production
Segment operating revenues:
Revenue from contracts with customers	408	514	1,403	1,473
Gathering and transportation
Segment operating revenues:
Revenue from contracts with customers	1,582	14,234	4,931	39,621
Gathering and transportation | Midstream
Segment operating revenues:
Revenue from contracts with customers	$ 1,582	$ 14,234	$ 4,931	$ 39,621

Reporting Segments - Reconcilia

Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Reconciliation of segment operating income to net income (loss):
Segment operating income	$ 8,815	$ 12,231	$ 30,234	$ 22,192
General and administrative expense	(5,109)	(5,614)	(17,193)	(17,576)
Unit-based compensation expense	(155)	(631)	(2,940)	(1,951)
Interest expense, net	(2,786)	(2,215)	(8,165)	(5,994)
Other expense	(352)		(1,876)
Net income (loss)	413	3,771	60	(3,329)
Production
Reconciliation of segment operating income to net income (loss):
Segment operating income	521	3,155	2,927	7,963
Midstream
Reconciliation of segment operating income to net income (loss):
Segment operating income	$ 8,294	$ 9,076	$ 27,307	$ 14,229

Reporting Segments (Assets by S

Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 492,268	$ 528,423
Capital expenditures	4,572	46,893
Production
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	51,927	58,623
Capital expenditures	169	441
Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	437,374	468,656
Capital expenditures	4,403	46,452
Corporate
Segment Reporting, Asset Reconciling Item [Line Items]
Total assets	$ 2,967	$ 1,144

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands	1 Months Ended	9 Months Ended	12 Months Ended
	Jul. 31, 2016	Sep. 30, 2018	Dec. 31, 2017
Variable Interest Entity [Line Items]
Capital investments		$ 127,899	$ 125,059
Earnings in equity investments		19,982	10,288
Distributions received		(30,204)	(11,632)
Maximum exposure to loss		117,677	$ 123,715
Carnero Gathering, Joint Venture
Variable Interest Entity [Line Items]
Payments to acquire interest in joint venture	$ 37,000	123,800
Debt incurred		$ 0

Subsequent Events (Details)

Subsequent Events (Details) - Subsequent event - USD ($) $ / shares in Units, $ in Millions	Nov. 08, 2018	Oct. 22, 2018
Common units
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.1500
Annual distribution declared per unit	0.60
Class B preferred units
Subsequent Event [Line Items]
Distribution declared per unit	$ 0.28225
Louisiana Divestiture
Subsequent Event [Line Items]
Proceeds from divestiture		$ 1.3