Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2017 | Mar. 06, 2018 | Jun. 30, 2017 | |
Document And Entity Information | |||
Document Type | 10-K | ||
Amendment Flag | false | ||
Document Period End Date | Dec. 31, 2017 | ||
Document Fiscal Year Focus | 2,017 | ||
Document Fiscal Period Focus | FY | ||
Entity Registrant Name | Sanchez Midstream Partners LP | ||
Entity Central Index Key | 1,362,705 | ||
Current Fiscal Year End Date | --12-31 | ||
Entity Filer Category | Smaller Reporting Company | ||
Entity Common Stock, Shares Outstanding | 14,965,134 | ||
Entity Public Float | $ 136,104,424 | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Current Reporting Status | Yes | ||
Entity Voluntary Filers | No |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenues | ||
Natural gas sales | $ 6,626 | $ 10,408 |
Oil sales | 23,701 | 5,138 |
Natural gas liquid sales | 1,997 | 1,167 |
Gathering and transportation sales | 55,825 | 53,972 |
Total revenues | 88,149 | 70,685 |
Operating expenses: | ||
Lease operating expenses | 12,994 | 14,981 |
Transportation operating expenses | 11,600 | 12,478 |
Cost of sales | 77 | 328 |
Production taxes | 1,476 | 1,167 |
General and administrative | 22,655 | 22,901 |
Unit-based compensation expense | 3,373 | 1,941 |
(Gain) loss on sale of assets | (4,150) | 219 |
Depreciation, depletion and amortization | 34,830 | 33,799 |
Asset impairments | 4,688 | 7,646 |
Accretion expense | 773 | 1,127 |
Total operating expenses | 88,316 | 96,587 |
Other (income) expense | ||
Interest expense, net | 8,341 | 5,093 |
Gain on embedded derivatives | (47,794) | |
Earnings from equity investments | (7,885) | (2,382) |
Other (income) expense | 2,417 | (50) |
Total other (income) expenses | 2,873 | (45,133) |
Total expenses | 91,189 | 51,454 |
Income (loss) before income taxes | (3,040) | 19,231 |
Income tax expense | 0 | 0 |
Net income (loss) | (3,040) | 19,231 |
Less: | ||
Preferred unit paid-in-kind distributions | (2,625) | |
Preferred unit distributions | (33,250) | (39,375) |
Preferred unit amortization | (1,796) | (24,340) |
Net loss attributable to common unitholders | $ (40,711) | $ (44,484) |
Net loss per unit | ||
Weighted Common Units - Basic and Diluted (in units) | 14,039,726 | 4,658,970 |
Common units | ||
Other (income) expense | ||
Net income (loss) | $ (3,040) | $ 19,231 |
Less: | ||
Net loss attributable to common unitholders | $ (40,711) | $ (44,484) |
Net loss per unit | ||
Common units - Basic and Diluted (in dollars per share) | $ (2.90) | $ (9.55) |
Weighted Common Units - Basic and Diluted (in units) | 14,039,726 | 4,658,970 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 321 | $ 957 |
Accounts receivable | 495 | 1,212 |
Accounts receivable - related entities | 13,099 | 5,987 |
Prepaid expenses | 2,670 | 2,041 |
Fair value of derivative instruments | 942 | 4,568 |
Total current assets | 17,527 | 14,765 |
Oil and natural gas properties and related equipment | ||
Oil and natural gas properties, equipment and facilities (successful efforts method) | 170,750 | 758,913 |
Gathering and transportation assets | 184,969 | 152,209 |
Material and supplies | 1,056 | |
Less: accumulated depreciation, depletion, amortization and impairment | (142,574) | (689,358) |
Oil and natural gas properties and equipment, net | 213,145 | 222,820 |
Other assets | ||
Intangible assets, net | 172,166 | 185,766 |
Fair value of derivative instruments | 1,318 | 3,964 |
Equity investments | 123,715 | 111,614 |
Other non-current assets | 552 | 776 |
Total assets | 528,423 | 539,705 |
Current liabilities | ||
Accounts payable and accrued liabilities | 1,782 | 951 |
Accounts payable and accrued liabilities - related entities | 10,353 | 7,046 |
Royalties payable | 371 | 706 |
Fair value of derivative instruments | 756 | 740 |
Other liabilities | 151 | |
Total current liabilities | 13,413 | 9,443 |
Other liabilities | ||
Asset retirement obligation | 6,074 | 13,579 |
Long-term debt, net of debt issuance costs | 187,808 | 151,322 |
Fair value of derivative instruments | 273 | 1,356 |
Other liabilities | 6,251 | 4,270 |
Total other liabilities | 200,406 | 170,527 |
Total liabilities | 213,819 | 179,970 |
Commitments and contingencies (See Note 12) | ||
Mezzanine equity | ||
Class B preferred units, 31,000,887 and 29,296,441 units issued and outstanding as of December 31, 2017 and 2016, respectively | 343,912 | 342,991 |
Partners' capital (deficit) | ||
Common units, 14,965,134 and 13,447,749 units issued and outstanding as of December 31, 2017 and 2016, respectively | (29,308) | 16,744 |
Total partners' capital (deficit) | (29,308) | 16,744 |
Total liabilities and partners' capital | $ 528,423 | $ 539,705 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - shares | Dec. 31, 2017 | Dec. 31, 2016 |
Consolidated Balance Sheets | ||
Class B preferred units, issued | 31,000,887 | 29,296,441 |
Class B preferred units, outstanding | 31,000,887 | 29,296,441 |
Units, issued | 14,965,134 | 13,447,749 |
Units, outstanding | 14,965,134 | 13,447,749 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Cash flows from operating activities: | ||
Net income (loss) | $ (3,040) | $ 19,231 |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||
Depreciation, depletion and amortization | 21,262 | 21,901 |
Amortization of debt issuance costs | 524 | 507 |
Revisions to asset retirement obligation included in DD&A | (1,858) | |
Asset impairments | 4,688 | 7,646 |
Accretion of plugging and abandonment liability | 773 | 1,127 |
Distributions (return on investment) from equity investments | 8,720 | 2,950 |
Equity earnings in affiliate | (7,885) | (2,382) |
Bad debt expense | 35 | |
(Gain) loss from disposition of property and equipment | (4,150) | 210 |
Total mark-to-market on commodity derivative contracts | (3,947) | 7,239 |
Cash settlements on commodity derivative contracts | 5,487 | 18,780 |
Cash settlements on terminated commodity derivatives | 3,602 | |
Unit-based compensation | 3,373 | 2,044 |
Loss on earnout derivative | 2,353 | |
Gain on embedded derivative | (47,794) | |
Amortization of intangible assets | 13,568 | 13,756 |
Costs for plug and abandon activities | (60) | (183) |
Changes in Operating Assets and Liabilities: | ||
Accounts receivable | 644 | (159) |
Accounts receivable - related entities | (6,590) | (4,472) |
Prepaid expenses | (629) | (1,297) |
Other assets | 144 | 730 |
Accounts payable and accrued liabilities | 9,997 | (3,876) |
Accounts payable and accrued liabilities- related entities | 3,566 | 6,011 |
Royalties payable | (300) | 17 |
Net cash provided by operating activities | 52,100 | 40,163 |
Cash flows from investing activities: | ||
Cash paid for acquisitions | 1,468 | (25,622) |
Development of oil and natural gas properties | (441) | (939) |
Proceeds from sale of assets | 11,665 | 38 |
Construction of gathering and transportation assets | (31,693) | (4,730) |
Purchases of and contributions to equity affiliates | (13,684) | (107,271) |
Net cash used in investing activities | (32,685) | (138,524) |
Cash flows from financing activities: | ||
Payments for offering costs | (611) | (5,403) |
Proceeds from issuance of debt | 48,000 | 72,000 |
Repayment of debt | (12,000) | (26,000) |
Issuance of common units | 1,290 | 99,196 |
Repurchase of common units under repurchase program | (2,948) | |
Units tendered by employees for tax withholdings | (140) | |
Distributions to common unitholders | (25,192) | (6,696) |
Class B preferred unit cash distributions | (31,500) | (37,168) |
Debt issuance costs | (38) | (94) |
Net cash provided by (used in) financing activities | (20,051) | 92,747 |
Net decrease in cash and cash equivalents | (636) | (5,614) |
Cash and cash equivalents, beginning of period | 957 | 6,571 |
Cash and cash equivalents, end of period | 321 | 957 |
Supplemental disclosures of cash flow information: | ||
Change in accrued capital expenditures | 1,064 | 1,119 |
Cash paid during the period for interest | $ 7,643 | 4,449 |
Transfer of embedded derivative to Class B preferred units | $ 145,283 |
Consolidated Statements of Chan
Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands | Class A preferred units | Common units | Total |
Partner's Deficit at Dec. 31, 2015 | $ 17,112 | $ (45,285) | $ (28,173) |
Partner's Deficit (in shares) at Dec. 31, 2015 | 11,694,364 | 3,240,813 | |
Units tendered by employees for tax withholding | $ (140) | (140) | |
Units tendered by employees for tax withholding (in shares) | (12,227) | ||
Units forfeited by employees (in shares) | (2,000) | ||
Unit-based compensation programs | $ 2,044 | 2,044 | |
Unit-based compensation programs (in shares) | 67,627 | ||
Issuance of common units, net of offering costs | $ 96,278 | 96,278 | |
Issuance of common units, net of offering costs (in shares) | 9,226,595 | ||
Class A Preferred Units converted to common units | $ (17,112) | $ 17,112 | |
Class A Preferred Units converted to common units (in shares) | (11,694,364) | 1,169,441 | |
Common units retired via unit repurchase program | $ (2,948) | (2,948) | |
Common units retired via unit repurchase program (in shares) | (242,500) | ||
Cash distributions to common unit holders | $ (6,696) | (6,696) | |
Distributions - Class B preferred units | (62,852) | (62,852) | |
Net income | 19,231 | 19,231 | |
Partner's Deficit at Dec. 31, 2016 | $ 16,744 | 16,744 | |
Partner's Deficit (in shares) at Dec. 31, 2016 | 13,447,749 | ||
Unit-based compensation programs | $ 3,373 | 3,373 | |
Unit-based compensation programs (in shares) | 217,481 | ||
Issuance of common units, net of offering costs | $ 11,228 | 11,228 | |
Issuance of common units, net of offering costs (in shares) | 906,613 | ||
Cash distributions to common unit holders | $ (25,192) | (25,192) | |
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 | $ (37,671) | (37,671) | |
Net income | (3,040) | (3,040) | |
Partner's Deficit at Dec. 31, 2017 | $ (29,308) | $ (29,308) | |
Partner's Deficit (in shares) at Dec. 31, 2017 | 14,965,134 |
Consolidated Statements of Cha7
Consolidated Statements of Changes in Partners’ Capital (Parenthetical) - USD ($) $ in Millions | Dec. 31, 2017 | Dec. 31, 2016 |
Consolidated Statements of Changes in Partners’ Capital | ||
Offering costs | $ 0.6 | $ 5.3 |
Organization And Business
Organization And Business | 12 Months Ended |
Dec. 31, 2017 | |
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 a natural gas processing facility, all located in the Western Eagle Ford in South Texas. We also own production assets in Texas, Louisiana and Oklahoma. We have entered into a shared services agreement with SP Holdings, LLC, the sole member of our general partner, pursuant to which the 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, Sanchez Production Partners LP changed its 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 | 12 Months Ended |
Dec. 31, 2017 | |
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. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. We conduct our business activities as two operating segments: the production of oil and natural gas and the midstream business, which include Western Catarina Midstream. Our management evaluates performance based on these two business segments. 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 consolidated financial statements upon adoption. In January 2017, the FASB issued Accounting Standards Update (“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. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU applies to all reporting entities within the scope of the affected accounting guidance. Most amendments were effective upon issuance (December 2016). 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 effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. 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 became effective beginning with the first quarter of 2018. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments” effective for annual and interim periods beginning after December 15, 2017. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. Early adoption is permitted including adoption in an interim period. We chose to adopt ASU 2016-15 for the year ended December 31, 2016 on a retrospective basis. 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, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates 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 started the assessment process by evaluating the population of leases under the revised definition. 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, and May 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 will apply the modified retrospective approach. As part of the assessment, the Partnership formed an implementation work team, completed trainings on the new revenue recognition model and gathered our material revenue contracts covering current revenue streams for which the impacts to the consolidated financial statements under the revised standards were evaluated. Upon adoption of the standard, while we do not anticipate material changes to our current revenue processes, we could be required to present revenue from the Gathering Agreement and revenue from the SECO Pipeline Transportation Agreement as separate line items within the statement of operations. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the 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 commodity 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 estimates and judgment. 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. Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents. Restricted Cash We had no restricted cash as of December 31, 2017 and 2016. Accounts Receivable, Net Our accounts receivable are primarily from our contractual agreements with Sanchez Energy and its subsidiaries, operators of our oil and natural gas properties and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2017 and 2016. Concentration of Credit Risk and Accounts Receivable Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our Credit Agreement and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.4 million as of December 31, 2017 and 2016. We have no off-balance-sheet credit exposure related to our operations or customers. Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 63% and 76% of total revenue for the years ended December 31, 2017 and 2016, respectively. Derivatives and Hedging Activities We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheets as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets as either short-term or long-term assets or liabilities based on their anticipated settlement date. We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales.” Revenue Recognition Sales are recognized when natural gas, NGLs and oil have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas, NGLs and oil are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of natural gas, NGLs and oil, and prevailing supply and demand conditions, so that the price of the natural gas, NGLs and oil fluctuates to remain competitive with other available natural gas, NGLs and oil supplies. As a result, revenues from the sale of natural gas, NGLs and oil will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas, NGLs and oil contracts are customary in the industry. Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no material gas imbalance positions at December 31, 2017 and 2016. Revenues relating to the gathering and transportation sales of oil and natural gas are recognized in the period service is provided. Under these arrangements, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems. Income Taxes SNMP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. 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), 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). 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. 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. Environmental Cost We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the federal Environmental Protection Agency (“EPA”) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods. For the years ended December 31, 2017 and 2016, we had no environmental liabilities recorded, as no liabilities were deemed necessary. Unit-Based Compensation The Partnership records unit-based compensation expense for awards granted to the directors of its general partner (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Unit-based compensation granted to employees of SOG (including those employees who also serve as the officers of our general partner) and consultants in exchange for services are considered awards to non-employees, and the Partnership records unit-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Partnership records compensation expenses equal to the fair value of the unit-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the unit-based award. Unit-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to those awards without market performance acceleration conditions. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award. Other Contingencies We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions and Divestitures | |
Acquisitions and Divestitures | 3. ACQUISITIONS AND DIVESTITURES 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 assets, including all plugging and abandonment costs relating to the assets, that arise on or after October 1, 2017. The Texas Production Divestiture closed November 13, 2017, and we recorded a gain of approximately $1.4 million on the sale during the fourth quarter of 2017. Non-Operated Production Divestiture In July 2017, we entered into an agreement to assign certain non-operated production assets located in Oklahoma, as well as our equity interests in the entities that owned the assets, in exchange for agreeing upon the apportionment of certain shared litigation costs. The assignment was 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 Oklahoma production assets for cash consideration of $5.5 million, and assumption by the buyer of all obligations relating to the 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 July 17, 2017, and we recorded a gain of $2.4 million on the sale during the third quarter of 2017. Carnero Processing Acquisition In November 2016, we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 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. Carnero Processing owns a 260 MMcf/d cryogenic natural gas processing plant in La Salle County, Texas (the “Raptor Gas Processing Facility”), that receives wet gas from dedicated acres in Western Catarina with capacity to accommodate further throughput from Sanchez Energy and third parties. The Partnership made capital contributions to Carnero Processing totaling $18.8 million between November 22, 2016 and December 31, 2017. Production Acquisition In November 2016, we completed the acquisition from SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy, of working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas together with escalating working interests in an additional 11 producing wellbores located in the Palmetto Field in Gonzales County, Texas (together, the “Production Acquisition”) for aggregate cash consideration of $24.2 million after $2.8 million in normal and customary closing adjustments. The effective date of the transaction was July 1, 2016. The Production Acquisition included initial conveyed working interests and net revenue interests for each property which escalate on January 1 for 2017 and 2018, at which point, SNMP’s interests in the Production Acquisition properties will stay constant for the remainder of the respective lives of the assets. The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved developed reserves $ 25,016 Fair value of assets acquired 25,016 Asset retirement obligations (832) Fair value of net assets acquired $ 24,184 Carnero Gathering Transaction In July 2016, we acquired from Sanchez Energy a 50% interest in Carnero Gathering, a joint venture that is 50% owned and operated by 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”). In addition, we are required to pay Sanchez Energy an earnout based on natural gas received above a threshold volume and tariff at Carnero Gathering’s delivery points from Sanchez Energy and other producers. Carnero Gathering owns a total of approximately 45 miles of high pressure natural gas gathering pipelines that currently connect Western Catarina Midstream to nearby pipelines and the Raptor Gas Processing Facility in South Texas (the “Carnero Gathering Line”). The Carnero Gathering Line is designed to directly connect to the Raptor Gas Processing Facility. Sanchez Energy has entered into a 15-year gathering agreement with Carnero Gathering pursuant to which Sanchez Energy is required to maintain a minimum quarterly volume delivery commitment for the first five years after the Raptor Gas Processing Facility’s in-service date . See Note 11. “Investments” for additional information relating to the Carnero Gathering Transaction. The Partnership made capital contributions to Carnero Gathering totaling $8.8 million between July 5, 2016 and December 31, 2017. Mid-Continent Divestiture In June 2016, certain wholly-owned subsidiaries of the Partnership entered into an agreement to sell substantially all of our operated oil and natural gas wells, leases and other associated assets and interests in Oklahoma and Kansas (other than those arising under or related to a concession agreement with the Osage Nation) (the “Mid-Continent Divestiture”) for cash consideration of $7,120, effective as of August 1, 2016 (the “Effective Time”). In addition, the buyer agreed to assume all obligations relating to the assets arising after the Effective Time and all plugging and abandonment costs relating to the assets arising prior to the Effective Time. The sale closed on July 15, 2016, and we recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from a 2007 acquisition which were included in the Mid-Continent Divestiture. |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2017 | |
Fair Value Measurements | |
Fair Value Measurements | 4. 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. This category includes those derivative instruments that can be valued using observable market data. Substantially all of these inputs are observable in the marketplace throughout the term of the derivative 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 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 Oil 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) 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, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Oil derivative instrument Derivative assets $ — $ 6,436 $ — $ 6,436 Midstream derivative instrument Earnout derivative liability — — (4,270) (4,270) Total $ — $ 6,436 $ (4,270) $ 2,166 As of December 31, 2017 and 2016, 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 ASC 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.’’ The following table summarizes the non-recurring fair value measurements of our assets and liabilities 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 acquired in the Production Acquisition. The carrying values of the impaired proved properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement. The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 10,733 Acquisitions (b) — — 24,184 Total net assets $ — $ — $ 34,917 (a) For the year ended December 31, 2016, we recorded a non-cash impairment charge of $7.6 million to impair our producing oil and natural gas properties in Texas and Louisiana (acquired prior to the Eagle Ford Acquisition) and in Oklahoma. The carrying values of the impaired proved properties were reduced to a fair value of $10.7 million, estimated using inputs characteristic of a Level 3 fair value measurement. (b) During the year ended December 31, 2016, we acquired oil and natural gas properties with a fair value of $24.2 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation The fair values of oil and natural gas properties 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 include estimates of: (i) reserves; (ii) future operating and development costs; (iii) future commodity prices; (iv) estimated future cash flows; and (v) 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 Fair value guidance requires certain fair value disclosures, such as those on our debt and derivatives, to be presented in both interim and annual reports. 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 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 6, “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 December 31, 2017. 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. Embedded Derivative – The Partnership entered into a contract for the sale of preferred units in October 2015 which contained provisions that were required to be bifurcated from the contract and valued as a derivative. The embedded derivative was valued through the use of a Monte Carlo model which utilized observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. We have therefore classified the fair value measurements of our embedded derivative as Level 3 inputs. In November 2016, we completed a public offering and private placement of common units. As a result of these equity issuances, the Class B conversion rate was fixed and the provisions that required the bifurcation were removed. At that time, the fair value of the derivative was transferred to mezzanine equity. Earnout Derivative – 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 Carnero Gathering’s delivery points from Sanchez Energy and other producers. The earnout derivative was valued through the use of a Monte Carlo 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 inputs. The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded and earnout derivatives classified as Level 3 in the fair value hierarchy (in thousands): December 31, 2017 2016 Beginning balance $ (4,270) $ (193,077) Initial fair value of earnout derivative 221 (4,270) Gain on embedded derivative — 47,794 Loss on earnout derivative (2,353) — Transfer to mezzanine equity — 145,283 Ending balance $ (6,402) $ (4,270) Loss included in earnings related to derivatives still held as of December 31, 2017 and 2016 respectively $ (2,353) $ — |
Derivative And Financial Instru
Derivative And Financial Instruments | 12 Months Ended |
Dec. 31, 2017 | |
Derivative And Financial Instruments | |
Derivative And Financial Instruments | 5. 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 ASC Topic 815, “ Derivatives and Hedging ,” all derivative instruments are recorded on the 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 as realized and unrealized gains (losses) on derivative instruments in the consolidated statements of operations. As of December 31, 2017, we had the following derivative contracts in place for the periods indicated, all of which are accounted for as mark-to-market activities: MTM Fixed Price Swaps – NYMEX (Henry Hub) For the Year Ended December 31, (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 132,088 $ 3.00 126,600 $ 3.00 121,600 $ 3.00 117,040 $ 3.00 497,328 $ 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 1,355,976 MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) For the Year Ended December 31, (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 70,600 $ 59.63 66,432 $ 59.71 62,840 $ 59.78 59,704 $ 59.84 259,576 $ 59.74 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 $ 53.50 694,088 The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Beginning fair value of commodity derivatives $ 6,436 $ 31,018 Net gains (losses) on crude oil derivatives 3,284 (8,355) Net gains on natural gas derivatives 663 1,116 Net settlements on derivative contracts: Oil (6,422) (13,622) Natural gas (2,730) (6,919) Net premiums on derivative contracts — 3,198 Ending fair value of commodity derivatives $ 1,231 $ 6,436 The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Location of Gain(Loss) Year Ended December 31, Derivative Type in Income 2017 2016 Commodity – Mark-to-Market Oil sales $ 3,284 $ (8,355) Commodity – Mark-to-Market Natural gas sales 663 1,116 $ 3,947 $ (7,239) 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 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 December 31, 2017 and 2016, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. Embedded Derivatives The Partnership entered into a contract for the sale of preferred units in October 2015 which contained provisions that were required to be bifurcated from the contract and valued as a derivative. The embedded derivative was valued through the use of a Monte Carlo model which utilized observable inputs, the Partnership’s unit prices at various timelines, as well as unobservable inputs related to the weighted probabilities of certain redemption scenarios. In November 2016, we completed a public offering and private placement of common units. As a result of these equity issuances, the Class B conversion rate was determined and the provisions that were required to bifurcate were removed. At that time, the fair value of the derivative was transferred to mezzanine equity. Earnout Derivative 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 Carnero Gathering’s delivery points from Sanchez Energy and other producers. The earnout derivative was valued through the use of a Monte Carlo 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. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded and earnout derivatives for the years ended December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Beginning fair value of embedded derivative $ (4,270) $ (193,077) Initial fair value of earnout derivative 221 (4,270) Gain on embedded derivative — 47,794 Loss on earnout derivative (2,353) — Transfer to mezzanine equity — 145,283 Ending fair value of embedded derivative $ (6,402) $ (4,270) |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2017 | |
Long-Term Debt | |
Long-Term Debt | 6. LONG-TERM DEBT Credit Agreement We have entered into a credit agreement 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 and 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. 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 equal to the rolling four quarter EBITDA of our midstream operations and the amount of distributions received from joint ventures multiplied by 5.0 initially, 4.75 for the second full quarter after the acquisition of Western Catarina Midstream and 4.5 thereafter. 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 December 31, 2017, the borrowing base under the Credit Agreement was $249.3 million, with an elected commitment amount of $200.0 million. 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 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 December 31, 2017, 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 could become then due and payable. We may request waivers of compliance from the violated financial covenants from the lenders, but there is no assurance that such waivers would be granted. Debt Issuance Costs As of December 31, 2017 and 2016, our unamortized debt issuance costs were $1.2 million and $1.7 million, respectively. These costs are amortized to interest expense in our consolidated statements of operations over the life of our Credit Agreement. Amortization of debt issuance costs recorded during the year ended December 31, 2017 and 2016 were $0.5 million. |
Oil And Natural Gas Properties
Oil And Natural Gas Properties And Related Equipment | 12 Months Ended |
Dec. 31, 2017 | |
Oil And Natural Gas Properties And Related Equipment. | |
Oil And Natural Gas Properties And Related Equipment | 7. OIL AND NATURAL GAS PROPERTIES AND RELATED EQUIPMENT Gathering and transportation assets consist of the following (in thousands): December 31, 2017 2016 Gathering and transportation assets Midstream assets $ 184,969 $ 152,209 Less: Accumulated depreciation and amortization (26,870) (15,020) Total gathering and transportation assets $ 158,099 $ 137,189 Oil and natural gas properties consist of the following (in thousands): December 31, 2017 2016 Oil and natural gas properties and related equipment Property costs Proved property $ 170,750 $ 758,366 Unproved property — 46 Land — 501 Total property costs 170,750 758,913 Materials and supplies — 1,056 Total 170,750 759,969 Less: Accumulated depreciation, depletion, amortization and impairments (115,704) (674,338) Oil and natural gas properties and equipment, net $ 55,046 $ 85,631 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. Proved Reserves Accounting rules require that we price our oil and natural gas proved reserves at the preceding twelve-month average of the first-day-of-the-month reference prices as adjusted for location and quality differentials. Such SEC-required prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Our proved reserve estimates exclude the effect of any derivatives we have in place. Our estimate of proved reserves is based on the quantities of natural gas, NGLs, and oil that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Proved reserves are calculated based on various factors, including consideration of an independent reserve engineers’ report on proved reserves and an economic evaluation of all of our properties on a well-by-well basis. The process used to complete the estimates of proved reserves at December 31, 2017 and 2016 is described in detail in Note 19, “Supplemental Information on Oil and Natural Gas Producing Activities.” Reserves and their relation to estimated future net cash flows impact depletion and impairment calculations. As a result, adjustments to depletion and impairments are made concurrently with changes to reserve estimates. The accuracy of reserve estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the estimates. Proved reserve estimates are a function of many assumptions, all of which could deviate significantly from actual results. As such, reserve estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered. 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. Acquisition costs of proved properties are amortized on the basis of all proved reserves, developed and undeveloped, and capitalized development costs (including wells and related equipment and facilities) are amortized on the basis of proved developed 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): Year Ended December 31, 2017 2016 Depreciation, depletion and amortization of oil and natural gas-related assets $ 9,413 $ 6,722 Depreciation, depletion and amortization of gathering and transportation related assets 11,849 13,320 Amortization of intangible assets 13,568 13,757 Total Depreciation, depletion and amortization 34,830 33,799 Asset impairments 4,688 7,646 Total $ 39,518 $ 41,445 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 third-party 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 year ended December 31, 2017, we recorded non-cash charges of $4.7 million, to impair certain producing oil and natural gas properties in Texas acquired as part of the Production Acquisition. For the year ended December 31, 2016, we recorded non-cash charges of $7.6 million, with $1.3 million from our Texas and Louisiana properties and $6.3 million from our Oklahoma properties. Asset Retirement Obligation As described in Note 9, “Asset Retirement Obligations,” estimated asset retirement costs are recognized when the asset is acquired or placed in service, and are amortized over proved developed reserves using the units-of-production method. Asset retirement costs are estimated by our engineers using existing regulatory requirements and anticipated future inflation rates. Exploration and Dry Hole Costs Exploration and dry hole costs represent abandonments of drilling locations, dry hole costs, delay rentals, geological and geophysical costs and the impairment, amortization and abandonment associated with leases on our unproved properties. All such costs on oil and natural gas properties relating to unsuccessful exploratory wells are charged to expense as incurred. We recorded no exploration or dry hole costs for the years ended December 31, 2017 and 2016. Materials and Supplies Materials and supplies consist of well equipment, parts and supplies. They are valued at the lower of cost or market, using either the specific identification or first-in first-out method, depending on the inventory type. Materials and supplies are capitalized as used in the development or support of our oil and natural gas properties. |
Provision For Income Taxes
Provision For Income Taxes | 12 Months Ended |
Dec. 31, 2017 | |
Provision For Income Taxes | |
Provision For Income Taxes | 8. PROVISION FOR INCOME TAXES Publicly traded partnerships like ours are treated as corporations unless they have 90% or more in qualifying income (as that term is defined in the Internal Revenue Code). We satisfied this requirement in each of the years ended December 31, 2017 and 2016 and, as a result, are not subject to federal income tax. However, our partners are individually responsible for paying federal income taxes on their share of our taxable income. Net earnings for financial reporting purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and financial reporting basis of certain assets and liabilities and other factors. We do not have access to information regarding each partner's individual tax basis in our limited partner interests. Provision for income taxes reflects franchise tax obligations in the state of Texas (the "Texas Margin Tax"). Deferred income tax assets and liabilities are recognized for temporary differences between the assets and liabilities of our tax paying entities for financial reporting and tax purposes. For the years ended December 31, 2017 and 2016, we had no federal or state income tax provision or benefit. A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands): For the Years Ended December 31, 2017 2016 Pre-tax net book income (loss) $ (3,040) $ 19,231 Texas Margin Tax (a) (438) 255 Return to accrual — — Valuation allowance 438 (255) Provision for income taxes $ — $ — Effective income tax rate % % (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): December 31, 2017 2016 Deferred tax assets (liabilities): Derivative assets $ 7 $ (230) Depreciable, depletable property, plant and equipment 78 753 Other 1 2 Deferred tax assets: 86 525 Valuation allowance (86) (525) Total deferred tax assets $ — $ — As of December 31, 2017 and 2016, the Partnership had no material uncertain tax positions. The Partnership files income tax returns in the U.S. and various state jurisdictions. The Partnership is no longer subject to examination by federal income tax authorities prior to 2014. State statutes vary by jurisdiction. |
Asset Retirement Obligation
Asset Retirement Obligation | 12 Months Ended |
Dec. 31, 2017 | |
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. Subsequently, the ARC is depreciated using the units-of-production method or straight line 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 property balance. The following table is a reconciliation of the ARO (in thousands): December 31, 2017 2016 Asset retirement obligation, beginning balance $ 13,579 $ 20,364 Liabilities added from acquisitions 198 912 Sold (8,416) (6,291) Revisions to cost estimates — (2,399) Settlements (60) (134) Accretion expense 773 1,127 Asset retirement obligation, ending balance $ 6,074 $ 13,579 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 reduce the liability for AROs. In 2017 and 2016, there were no significant expenditures for abandonments and there were no assets legally restricted for purposes of settling existing AROs. During the year ended December 31, 2017, obligations were sold as part of the Oklahoma Production Divestiture and Texas Production Divestiture and during the year ended December 31, 2016 as part of the Mid-Continent Divestiture that significantly lowered the Partnership’s future abandonment obligations. |
Intangible Assets
Intangible Assets | 12 Months Ended |
Dec. 31, 2017 | |
Intangible Assets | |
Intangible Assets | 10. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $172.2 million related to the Gathering Agreement with Sanchez Energy that was entered into as part of the Western Catarina Midstream transaction. Pursuant to the 15-year agreement, Sanchez Energy tenders all of its petroleum, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through Western Catarina Midstream, with a right to tender additional volumes outside of the dedicated acreage. These intangible assets are being amortized using the straight-line method over the 15 year life of the agreement. Amortization expense for the years ended December 31, 2017 and 2016 was $13.6 million and $ 13.8 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of December 31, 2017 and 2016 are detailed below (in thousands): December 31, 2017 2016 Beginning balance $ 185,766 $ 199,741 Disposals (32) (219) Amortization (13,568) (13,756) Ending balance $ 172,166 $ 185,766 |
Investments
Investments | 12 Months Ended |
Dec. 31, 2017 | |
Investments | |
Investments | 11. INVESTMENTS In July 2016, we completed the Carnero Gathering Transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Gathering, a joint venture that is 50% owned and operated by 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. During the year ended December 31, 2017, the Partnership made approximately $5.4 million of capital contributions to Carnero Gathering. Prior to the sale, Sanchez Energy, though a wholly owned subsidiary, had invested approximately $26.0 million in Carnero Gathering. 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 fifteen years and decreases earnings from Carnero Gathering. 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 Carnero Gathering’s delivery points from Sanchez Energy and other producers. This earnout is considered as contingent consideration and its estimated fair value of $6.4 million was recorded on the balance sheet as a deferred liability as of December 31, 2017. No earnout payments were made in the year ended December 31, 2017. As of December 31, 2017, the Partnership has paid approximately $46.2 million for the Carnero Gathering Transaction related to the initial payment and contributed capital. The Partnership has accounted for this investment as an equity method investment. 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 in our consolidated balance sheet. For the year ended December 31, 2017, the Partnership recorded earnings of approximately $6.6 million in equity investments from Carnero Gathering, which was offset by $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 consolidated statements of operations. Cash distributions of approximately $7.6 million were received during the year ended December 31, 2017. In November 2016, we completed the Carnero Processing Transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 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. During the year ended December 31, 2017, the Partnership made approximately $8.2 million of capital contributions to the joint venture. Prior to the sale, Sanchez Energy, though a wholly owned subsidiary, had invested approximately $48.0 million in Carnero Processing. As of December 31, 2017, the Partnership has paid approximately $74.7 million for the Carnero Processing Transaction related to the initial payment and contributed capital. The Partnership has accounted for this investment as an equity method investment. 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 in our consolidated balance sheet. The Partnership recorded earnings of approximately $2.2 million in the “Earnings from equity investments” line within our consolidated statements of operation for the year ended December 31, 2017. Cash distributions of approximately $1.1 million were received during the year ended December 31, 2017. Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2017 2016 Sales $ 136,178 $ 12,465 Total expenses 118,077 2,677 Net income $ 18,101 $ 9,788 As of December 31, 2017 2016 Current assets $ 38,344 $ 27,779 Noncurrent assets 193,748 152,112 Current liabilities 24,710 16,577 |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2017 | |
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 Carnero Gathering’s delivery points from Sanchez Energy and other producers. This earnout has an approximate value of $6.4 million and was recorded on the balance sheet as a deferred liability as of December 31, 2017. We did not have any other material commitments and contingencies and no earnout payments were made as of December 31, 2017 or 2016. |
Related Party Transactions
Related Party Transactions | 12 Months Ended |
Dec. 31, 2017 | |
Related Party Transactions | |
Related Party Transactions | 13. RELATED PARTY TRANSACTIONS Sanchez-Related Agreements We are controlled by our general partner. The sole member of our general partner is Manager, which has no officers. In May 2014, we entered into the Services Agreement with Manager pursuant to which Manager provides services that we require to operate our business, including overhead, technical, administrative, marketing, accounting, operational, information systems, financial, compliance, insurance, and acquisition, disposition and financing services. In connection with providing services under the Services Agreement, Manager receives compensation consisting of: (i) a quarterly fee equal to 0.375% of the value of our properties other than our assets located in the Mid-Continent region, (ii) reimbursement for all allocated overhead costs as well as any direct third-party costs incurred and (iii) for each asset acquisition, asset disposition and financing, a fee not to exceed 2% of the value of such transaction. Each of these fees, not including the reimbursement of costs, is paid in cash unless Manager elects for such fee to be paid in our equity. The Services Agreement has a ten-year term and will be automatically renewed for an additional ten years unless both Manager and the Partnership provide notice of termination to the other with at least 180 days’ notice. During the years ended December 31, 2017 and 2016, we incurred costs of approximately $8.8 million and $7.5 million, respectively, to Manager under the Services Agreement. Manager utilizes SOG to provide the services under the Services Agreement. In May 2014, we entered into a Contract Operating Agreement with SOG pursuant to which SOG either provides services to operate, develop and produce our oil and natural gas properties or engages a third-party operator to do so, other than with respect to our properties in the Mid-Continent Region. We also have entered into the Geophysical Seismic Data Use License Agreement with SOG pursuant to which SOG provides us a non-exclusive, royalty-free license to use seismic, geophysical and geological information relating to our oil and natural gas properties that is proprietary to SOG and not restricted by agreements that SOG has with landowners or seismic data vendors. SOG, headquartered in Houston, Texas, is a private full-service oil and natural gas company engaged in the exploration and development of oil and natural gas primarily in the South Texas and onshore Gulf Coast areas on behalf of its affiliates. The Chairman of the board of directors of our general partner, Antonio R. Sanchez, III, the President and Chief Operating Officer of our general partner as well as one of our directors, Patricio D. Sanchez, one of our directors, Eduardo A. Sanchez, along with their immediate family members Ana Lee Sanchez Jacobs and Antonio R. Sanchez, Jr., collectively, either directly or indirectly, own a majority of the equity interests of SOG. In addition, Antonio R. Sanchez, Jr. is a member of the board of directors of SOG, and such other individuals, as well as Ana Lee Sanchez Jacobs, are officers of SOG. Sanchez-Related Transactions We have entered into several transactions with Sanchez Energy since January 1, 2016. Antonio R. Sanchez, Jr. is a director and Executive Chairman of the Board of Sanchez Energy, and Antonio R. Sanchez, III, is a director and Chief Executive Officer of Sanchez Energy. In addition, Eduardo Sanchez is the President of Sanchez Energy and Patricio Sanchez is an Executive Vice President of Sanchez Energy. The employees of SOG, including Kirsten A. Hink, our Chief Accounting Officer, provide common services to both us and Sanchez Energy. In conjunction with the acquisition of Western Catarina Midstream, we entered into the 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 Texas for processing and transportation through Western Catarina Midstream, with the potential to tender additional volumes outside of the dedicated acreage (the “Gathering Agreement”). During the first five years of the term of the Gathering Agreement, Sanchez Energy is required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. Sanchez Energy is required to pay gathering and processing fees of $0.96 per barrel for crude oil and condensate and $0.74 per Mcf for natural gas that are tendered through Western Catarina Midstream, in each case, subject to an annual escalation for a positive increase in the consumer price index. For the years ended December 31, 2017 and 2016, Sanchez Energy paid us approximately $52.8 million and $50.1 million, respectively, pursuant to the terms of the gathering and processing agreement. On June 30, 2017, the Gathering Agreement was amended to add an incremental infrastructure fee to be paid by SN Catarina based on water that is delivered through the gathering system through March 31, 2018. 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 Carnero Gathering’s delivery points from Sanchez Energy and other producers. For the years ended December 31, 2017 and 2016, we did not make any earnout payments to Sanchez Energy. However, we had a payable of $0.1 million to Sanchez Energy at year end December 31, 2017 related to the earnout. In November 2016, in conjunction with our public offering of common units, the Partnership entered into a Common Unit Purchase Agreement with SN UR Holdings, LLC, a wholly-owned subsidiary of Sanchez Energy, whereby we issued to the Purchaser 2,272,727 common units for proceeds of approximately $25.0 million. In November 2016, we completed the Carnero Processing Transaction pursuant to which we acquired from Sanchez Energy a 50% interest in Carnero Processing, a joint venture that is 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. Also in November 2016, the Partnership consummated a Purchase and Sale Agreement with SN Cotulla Assets, LLC and SN Palmetto, LLC, each a wholly-owned subsidiary of Sanchez Energy , to purchase working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas as well as escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas for approximately $24.2 million. In October 2016, we entered into an agreement with Sanchez Energy providing us an option to acquire a ground lease, which the parties mutually terminated in September 2017. In September 2017, we entered into the SECO Pipeline Transportation Agreement. For the year ended December 31, 2017, SN Catarina paid us approximately $0.9 million pursuant to the terms of that agreement. As of December 31, 2017 and 2016, the Partnership had a net receivable from related parties of approximately $13.1 million, and $6.0 million, respectively, which are included in “Accounts receivable – related entities” in the consolidated balance sheets. As of December 31, 2017 and 2016, the Partnership also had a net payable to related parties of approximately $10.4 million, and $7.0 million, respectively. The net receivable/payable as of December 31, 2016 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. Sanchez Energy is an independent exploration and production company focused on the acquisition and development of U.S. onshore unconventional oil and natural gas resources, with a current focus on the horizontal development of significant resource potential from the Eagle Ford Shale in South Texas where it has assembled approximately 487,000 gross leasehold acres (285,000 net acres). The Chairman of the board of directors of our general partner, Antonio R. Sanchez, III, is Sanchez Energy’s Chief Executive Officer and a member of its board of directors. A member of the board of directors of our general partner, Eduardo A. Sanchez, is the former President of Sanchez Energy. The President and Chief Operating Officer of our general partner, Patricio D. Sanchez, who is also a member of the board of directors of our general partner, is an Executive Vice President of Sanchez Energy. Antonio R. Sanchez, Jr., the father of Antonio R. Sanchez, III, Eduardo A. Sanchez, and Patricio D. Sanchez, is the Executive Chairman of the board of directors of Sanchez Energy. Antonio R. Sanchez, Jr., Antonio R. Sanchez, III, Eduardo A. Sanchez and Patricio D. Sanchez was 6.8%, 3.0%, 1.4% and 1.2%, respectively , of Sanchez Energy’s shares outstanding as of March 5, 2018. As of March 6, 2018, Sanchez Energy indirectly, through one of its wholly owned subsidiaries, beneficially owns approximately 15.2% of the outstanding common units of SNMP. |
Unit-Based Compensation
Unit-Based Compensation | 12 Months Ended |
Dec. 31, 2017 | |
Unit-Based Compensation | |
Unit-Based Compensation | 14. UNIT-BASED COMPENSATION The Sanchez Midstream Partners LP Long-Term Incentive Plan (the “Plan”) allows for restricted common unit grants. Restricted common unit activity under the Plan 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, 2015 361,357 $ 14.18 Granted 67,627 10.35 Vested (195,613) 12.69 Returned/Cancelled (14,227) 15.81 Outstanding at December 31, 2016 219,144 $ 14.22 Granted 220,814 14.73 Vested (153,487) 14.20 Returned/Cancelled (3,333) 13.59 Outstanding at December 31, 2017 283,138 $ 14.64 In March 2017, the Partnership issued 171,231 restricted common units pursuant to the Plan to executives of the Partnership’s general partner that vest on the first anniversary of grant. In April 2017, the Partnership issued 44,583 restricted common units pursuant to the Plan to certain directors of the Partnership’s general partner that vested immediately on the date of grant. The unit-based compensation expense for the award was based on the fair value on the day before the date of grant. During the year ended December 31, 2016, the Partnership issued 67,627 restricted common units pursuant to the Plan to certain directors of the Partnership’s general partner that vested immediately on the date of the grant . The unit-based compensation expense for the award was based on the fair value on the day before the date of grant. As of December 31, 2017, 1,599,135 common units remain available for future issuance to participants under the LTIP. |
Distributions To Unitholders
Distributions To Unitholders | 12 Months Ended |
Dec. 31, 2017 | |
Distributions To Unitholders | |
Distributions To Unitholders | 15. DISTRIBUTIONS TO UNITHOLDERS The table below reflects the payment of cash distributions on common units relating to the years ended December 31, 2017 and 2016. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2016 $ 0.4121 May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ 0.4183 August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ 0.4246 October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 $ 0.4310 February 9, 2017 February 20, 2017 February 28, 2017 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 The table below reflects the payment of distributions on Class B preferred units during the years ended December 31, 2017 and 2016. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2016 $ 0.4500 May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ 0.4500 August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ 0.4500 October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 (a) $ 0.2258 February 9, 2017 February 20, 2017 February 28, 2017 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 (a) The Partnership elected to pay the fourth quarter 2016 and first quarter 2017 distributions on the Class B preferred units in part cash and, with the 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 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017, and the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each paid on May 31, 2017 to holders of record on May 22, 2017. |
Members' Equity_Partners' Capit
Members' Equity/Partners' Capital | 12 Months Ended |
Dec. 31, 2017 | |
Members' Equity/Partners' Capital | |
MEMBERS' EQUITY/PARTNERS' CAPITAL | 16. MEMBERS’ EQUITY/PARTNERS’ CAPITAL Outstanding Units As of December 31, 2017, we had 31,000,887 Class B preferred Units outstanding and 14,965,134 common units outstanding, which included 283,138 unvested restricted common units issued under LTIP. Common Unit Issuances In connection with providing services under the Services Agreement for the first, second and third quarters of 2017, the Partnership issued 139,110, 170,497 and 186,942 common units, respectively, to SP Holdings, LLC on June 30, 2017, August 31, 2017 and November 30, 2017, respectively. In connection with providing services under the Services Agreement for the third and fourth quarters of 2016, the Partnership issued 170,750 and 154,737 common units, respectively, to SP Holdings, LLC on March 6, 2017. See Note 12, “Related Party Transactions” for additional information related to the Services Agreement. The Partnership elected to pay the first quarter 2017 distribution on the Class B preferred units in part cash and, with the consent of the Class B preferred unitholder, 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 the holder of Class B preferred units. 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 at-the-market to fund general limited partnership purposes, including possible acquisitions. Proceeds from the at-the-market equity issuance were used for general limited partnership purposes. The Partnership elected to pay the fourth quarter 2016 distribution on the Class B preferred units in part cash and, with the consent of the Class B preferred unitholder, in part common units (in lieu of additional Class B preferred units). Accordingly, the Partnership issued 208,594 common units on February 20, 2017 to the holder of Class B preferred units. In November 2016, we completed a public offering and private placement of common units. The public offering consisted of 6,745,107 common units (which includes partial exercise of the underwriters’ overallotment of 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses. The private placement consisted of 2,272,727 common units issued to the Purchaser for net proceeds of approximately $25.0 million. Class A Preferred Unit Offering On March 31, 2016, the Partnership converted all remaining outstanding Class A preferred Units into common units of the Partnership on a one-for-one basis. Class B Preferred Unit Offering On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 (the “Preferred Unit Purchase Agreement”) between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately negotiated transaction (the “Private Placement”) for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of $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 paid-in-kind units (4.0% per annum). 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 Second Amended and Restated Agreement of Limited Partnership of the Partnership (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 pursuant to Section 4(a)(2) thereof. The Class B preferred units are accounted for as mezzanine equity in the consolidated balance sheet consisting of the following (in thousands): December 31, 2017 2016 Mezzanine equity beginning balance $ 342,991 $ 172,111 Discount — (87) Amortization of discount 1,796 23,477 Distributions 35,875 39,375 Distributions paid (36,750) (37,168) Transfer embedded derivative to Class B preferred units — 145,283 Total mezzanine equity $ 343,912 $ 342,991 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), 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). 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. 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. The following table presents the weighted average basic and diluted units outstanding for the periods indicated: December 31, 2017 2016 Common units - Basic and Diluted 14,039,726 4,658,970 Weighted Common units - Basic and Diluted 14,039,726 4,658,970 At December 31, 2017 and 2016, we had 283,138 and 219,144 common units that were restricted unvested common units granted and outstanding, respectively. No losses were allocated to participating restricted unvested units because such securities do not have a contractual obligation to share in the Partnership’s losses. The following table presents our basic and diluted loss per unit for the year ended December 31, 2017 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (40,711) $ (40,711) Basic and diluted loss per unit $ (2.90) The following table presents our basic and diluted loss per unit for the year ended December 31, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (44,484) $ (44,484) Basic and diluted loss per unit $ (9.55) |
Reporting Segments
Reporting Segments | 12 Months Ended |
Dec. 31, 2017 | |
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 reportable 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 natural gas, NGLs and oil. 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. We realigned the composition of our operating segments to reflect management's view of the operating results during the fourth quarter 2017. The following tables present financial information for each operating segment for the periods indicated based on the realignment of our operating segments (in thousands): For the Year Ended December 31, 2017 Production Midstream Total Segment operating revenues: Natural gas sales $ 6,626 $ — $ 6,626 Oil sales 23,701 — 23,701 Natural gas liquid sales 1,997 — 1,997 Gathering and transportation sales — 55,825 55,825 Earnings (losses) from equity investments (101) 7,986 7,885 Total segment operating revenues 32,223 63,811 96,034 Segment operating costs: Lease operating expenses 12,066 928 12,994 Transportation operating expenses — 11,600 11,600 Earnout rebate — 64 64 Cost of sales 77 — 77 Production taxes 1,476 — 1,476 Gain on sale of assets (4,150) — (4,150) Depreciation, depletion and amortization 9,522 25,308 34,830 Asset impairments 4,688 — 4,688 Accretion expense 499 274 773 Total segment operating costs 24,178 38,174 62,352 Segment operating income $ 8,045 $ 25,637 $ 33,682 For the Year Ended December 31, 2016 Production Midstream Total Segment operating revenues: Natural gas sales $ 10,408 $ — $ 10,408 Oil sales 5,138 — 5,138 Natural gas liquid sales 1,167 — 1,167 Gathering and transportation sales — 53,972 53,972 Earnings from equity investments 81 2,301 2,382 Total segment operating revenues 16,794 56,273 73,067 Segment operating costs: Lease operating expenses 14,327 654 14,981 Transportation operating expenses — 12,478 12,478 Cost of sales 328 — 328 Production taxes 1,167 — 1,167 Loss on sale of assets 219 — 219 Depreciation, depletion and amortization 6,722 27,077 33,799 Asset impairments 7,646 — 7,646 Accretion expense 875 252 1,127 Total segment operating costs 31,284 40,461 71,745 Segment operating income (loss) $ (14,490) $ 15,812 $ 1,322 For the Years Ended December 31, 2017 2016 Reconciliation of segment operating income to net income (loss): Total segment operating income $ 33,682 $ 1,322 General and administrative (22,655) (22,901) Unit-based compensation expense (3,373) (1,941) Interest expense, net (8,341) (5,093) Gain on embedded derivative — 47,794 Other income (expense) (a) (2,353) 50 Net income (loss) $ (3,040) $ 19,231 (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 December 31, 2017 and 2016 (in thousands): 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 December 31, 2016 Production Midstream Corporate (a) Total Other financial information Total assets $ 96,262 $ 440,675 $ 2,768 $ 539,705 Capital expenditures (b) $ 939 $ 18,595 $ — $ 19,534 (b) Corporate assets not reviewed by the CODM on a segment basis consists of cash, some prepaids, and other assets. (a) Inclusive of capital contributions made to equity method investments. The following table summarizes the percentage of revenue earned from those customers in the Midstream segment that exceed 10% of the Partnership's consolidated revenue for the periods presented below. Because all remaining production properties are non-operated, there are no customers in the Production segment that exceed 10% of the Partnership’s consolidated revenue. For the Years Ended December 31, 2017 2016 Midstream Sanchez Energy 63 % 76 % Total 63 % 76 % |
Variable Interest Entities
Variable Interest Entities | 12 Months Ended |
Dec. 31, 2017 | |
Variable Interest Entities | |
Variable Interest Entities | 18. VARIABLE INTEREST ENTITIES During the year ended December 31, 2016, the Partnership adopted ASU 2015-02, “Consolidation—Amendments to the Consolidation Analysis,” which introduces a separate analysis for determining if limited partnerships and similar entities are variable interest entities (“VIEs”) and clarifies the steps a reporting entity would have to take to determine whether the voting rights of stockholders in a corporation or similar entity are substantive. As noted above in Note 11, “Investments,” the Partnership purchased a 50% membership interest in Carnero Gathering from Sanchez Energy 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 date of the acquisition. The Partnership determined that the Carnero Gathering joint venture is more similar to a limited partnership than a corporation. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if a partner is able to exercise kick-out rights over the general partner(s) or is able to exercise substantive participating rights. We concluded that the Carnero Gathering joint venture is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIE regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIE’s economic performance. The Partnership’s investment in Carnero Gathering represents a VIE that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero Gathering joint venture is limited to the capital investment of approximately $47.9 million. As of December 31, 2017, the Partnership had invested approximately $46.2 million in Carnero Gathering. As of December 31, 2017, no debt has been incurred by Carnero Gathering. We have included this VIE in the “Equity investments” long-term asset line on the balance sheet. As noted above in Note 11, “Investments,” the Partnership purchased a 50% membership interest in Carnero Processing from Sanchez Energy for an initial payment of approximately $55.5 million and the assumption of remaining capital commitments to Carnero Processing, estimated at approximately $24.5 million as of the date of the acquisition. The Partnership determined that the Carnero Processing joint venture is more similar to a limited partnership than a corporation. Under the revised guidance of ASU 2015-02, a limited partnership or similar entity with equity at risk will not be a VIE if a limited partner is able to exercise kick-out rights over the general partner(s) or is able to exercise substantive participating rights. We concluded that the Carnero Processing joint venture is a VIE under the revised guidance because we cannot remove Targa as operator and we do not have substantive participating rights. In addition, Targa has the discretion to direct activities of the VIE regarding the risks associated with price, operations, and capital investment which have the most significant impact on the VIE’s economic performance. Similar to the Partnership’s investment in Carnero Gathering, the Partnership’s investment in Carnero Processing represents a VIE that could expose the Partnership to losses. The amount of losses the Partnership could be exposed to from the Carnero Processing joint venture is limited to the capital investment of approximately $75.8 million. As of December 31, 2017, the Partnership had invested approximately $74.7 million in Carnero Processing. As of December 31, 2017, no debt has been incurred by Carnero Processing. 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 December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Capital investments $ 121,010 $ 107,320 Earnings in equity investments 10,288 2,301 Distributions received (11,632) (2,950) Estimated earnout accrued 4,049 4,270 Equity in equity investments $ 123,715 $ 110,941 December 31, 2017 2016 Equity in equity investments $ 123,715 $ 110,941 Guarantees of capital investments — 17,584 Maximum exposure to loss $ 123,715 $ 128,525 |
Supplemental Information On Oil
Supplemental Information On Oil And Natural Gas Producing Activities | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Information On Oil And Natural Gas Producing Activities | |
Supplemental Information On Oil And Natural Gas Producing Activities | 19. SUPPLEMENTAL INFORMATION ON OIL AND NATURAL GAS PRODUCING ACTIVITIES (UNAUDITED) The Supplementary Information on Oil and Natural Gas Producing Activities is presented as required by the appropriate authoritative guidance . The supplemental information includes capitalized costs related to oil and natural gas producing activities; costs incurred for the acquisition of oil and natural gas producing activities, exploration and development activities and the results of operations from oil and natural gas producing activities. Supplemental information is also provided for per unit production costs; oil and natural gas production and average sales prices; the estimated quantities of proved oil and natural gas reserves; the standardized measure of discounted future net cash flows associated with proved reserves and a summary of the changes in the standardized measure of discounted future net cash flows associated with proved reserves. Costs The following table sets forth our capitalized costs as of December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ 170,750 $ 758,366 Unproved property — 46 Land — 501 Total property costs 170,750 758,913 Materials and supplies — 1,056 Total 170,750 759,969 Less: Accumulated depreciation, depletion, amortization and impairments (115,704) (674,338) Oil and natural gas properties and equipment, net $ 55,046 $ 85,631 (a) Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist. The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2017 and 2016 (in thousands): For the Years Ended December 31, 2017 2016 Costs incurred for the period: Acquisition of properties Proved $ — $ 25,622 Development costs 441 937 Oil and natural gas properties and equipment, net $ 441 $ 26,559 The development costs for the year ended December 31, 2017 and 2016 primarily represent costs related to recompletions. The properties acquired in 2016 were related to the Production Acquisition, for additional information see Note 3. “Acquisitions and Divestitures.” We had no exploration and dry hole costs in 2017 and 2016. Results of Operations The revenues and expenses associated directly with oil and natural gas producing activities are reflected in the Consolidated Statements of Operations. All of our oil and natural gas producing activities are located in the United States. Net Proved Reserves of Natural Gas, NGLs and Oil The following table sets forth information with respect to changes in proved developed and undeveloped reserves. This information excludes reserves related to royalty and net profit interests. All of our reserves are located in the United States. Natural Gas Total Oil Natural Gas Liquids (MMBoe) (in MMBoe) (in MMBoe) (in MMBoe) Net proved reserves December 31, 2015 11,642 3,159 7,736 747 Purchase of reserves in place 1,397 1,049 176 172 Sales of reserves in place (610) (47) (563) — Revisions of previous estimates (4,426) (316) (4,202) 92 Production (1,133) (331) (721) (81) December 31, 2016 6,870 3,514 2,426 930 Sales of reserves in place (1,731) (358) (1,280) (93) Revisions of previous estimates 1,062 504 383 175 Production (936) (414) (420) (102) December 31, 2017 5,265 3,246 1,109 910 Proved developed reserves: December 31, 2016 6,870 3,514 2,426 930 December 31, 2017 5,265 3,246 1,109 910 Reserves and Related Estimates Our estimate of proved reserves is based on the quantities of oil and natural gas that engineering and geological analyses demonstrate, with reasonable certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our year end December 31, 2017 and 2016, proved reserve estimates were 5.3 MMBoe and 6.9 MMBoe, respectively. Reserve estimates for those periods were prepared by, Ryder Scott, an independent petroleum engineering firm, and are used for the applicable disclosures in our financial statements. Our 2017 estimates of total proved reserves decreased 1.6 MMBoe from 2016 primarily due to a decrease in reserves of 1.7 MMBoe due to the Oklahoma Production Divestiture and Texas Production Divestiture. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $48.69 per barrel for oil, $21.34 per barrel for NGLs and $3.04 per Mcf for natural gas. Our 2016 estimates of total proved reserves decreased 4.7 MMBoe from 2015 due to a downward revision of previous estimates of 4.4 MMBoe offset by an increase of 1.4 MMBoe related to the purchase of reserves in place. The downward revision was due to lower commodity prices as well as a decrease in proved developed not producing and PUD reserves, partially offset by an increase in PDP reserves from our Production Acquisition. Our reserves are 35% natural gas and are sensitive to lower prices for natural gas and basis differentials in the Mid-Continent region. For proved reserves, the production weighted average product price over the remaining lives of the properties used in our reserve report were: $38.85 per barrel for oil, $13.84 per barrel for NGLs and $2.28 per Mcf for natural gas. Proved developed producing reserves were lower due to natural production decline and our sale of reserves in place. Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves, Including a Reconciliation of Changes Therein The following table sets forth the standardized measure of the discounted future net cash flows attributable to our proved oil and natural gas reserves. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. Future cash inflows are calculated by applying the SEC-required prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future cash inflows exclude the impact of our hedging program. Future development and production costs represent the estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, assuming continuation of existing economic conditions. In addition, asset retirement obligations are included within future production and development costs. There are no future income tax expenses because the Partnership is a non-taxable entity. The assumptions used to compute estimated future cash inflows do not necessarily reflect expectations of actual revenues or costs or their present values. In addition, variations from expected production rates could result directly or indirectly from factors outside of our control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production; however, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized. The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands): For the Years Ended December 31, 2017 2016 Future cash inflows $ 197,739 $ 182,612 Future production costs (101,300) (102,569) Future estimated development costs (4,346) (8,872) Future net cash flows 92,093 71,171 10% annual discount for estimated timing of cash flows (35,396) (21,535) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 56,697 $ 49,636 The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): For the Years Ended December 31, 2017 2016 Beginning of the period $ 49,636 $ 67,852 Sales and transfers of oil and natural gas, net of production costs (14,758) (8,700) Net changes in prices and production costs related to future production 15,036 (7,868) Changes in development costs 3,854 5,040 Changes in extensions and discoveries 160 — Revisions of previous quantity estimates 9,137 (17,924) Purchases and sales of reserves in place (11,952) 9,134 Accretion discount 4,964 6,175 Change in production rates, timing, and other 620 (4,073) Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 56,697 $ 49,636 |
Subsequent Events
Subsequent Events | 12 Months Ended |
Dec. 31, 2017 | |
Subsequent Events | |
Subsequent Events | 20. SUBSEQUENT EVENTS On February 8, 2018, the board of directors of our general partner declared a fourth quarter 2017 cash distribution on its common units of $0.4508 per unit ($1.8032 per unit annualized) payable on February 28, 2018 to holders of record on February 20, 2018. The Partnership also declared a fourth 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, paid on February 28, 2018 to holders of record on February 20, 2018. |
Basis Of Presentation And Sum28
Basis Of Presentation And Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
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. The accompanying financial statements include the accounts of us and our wholly-owned subsidiaries. All intercompany accounts and transactions have been eliminated in consolidation. We conduct our business activities as two operating segments: the production of oil and natural gas and the midstream business, which include Western Catarina Midstream. Our management evaluates performance based on these two business segments. |
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 consolidated financial statements upon adoption. In January 2017, the FASB issued Accounting Standards Update (“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. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In December 2016, the FASB issued ASU 2016-19 “Technical Corrections and Improvements,” which amends a number of Topics in the FASB ASC. The ASU is part of an ongoing FASB project to facilitate Codification updates for non-substantive technical corrections, clarifications, and improvements that are not expected to have a significant effect on accounting practice or create a significant administrative cost to most entities. The ASU applies to all reporting entities within the scope of the affected accounting guidance. Most amendments were effective upon issuance (December 2016). 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 effective for public business entities for annual and interim periods in fiscal years beginning after December 15, 2017. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. 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 became effective beginning with the first quarter of 2018. Early adoption is permitted, and the Partnership is currently in the process of evaluating the impact of adoption of this guidance on our consolidated financial statements. In August 2016, the FASB issued ASU No. 2016-15, “Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments” effective for annual and interim periods beginning after December 15, 2017. This ASU is intended to clarify the presentation of cash receipts and payments in specific situations. Early adoption is permitted including adoption in an interim period. We chose to adopt ASU 2016-15 for the year ended December 31, 2016 on a retrospective basis. 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, with a modified retrospective approach to be used for implementation. ASU 2016-02 updates 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 started the assessment process by evaluating the population of leases under the revised definition. 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, and May 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 will apply the modified retrospective approach. As part of the assessment, the Partnership formed an implementation work team, completed trainings on the new revenue recognition model and gathered our material revenue contracts covering current revenue streams for which the impacts to the consolidated financial statements under the revised standards were evaluated. Upon adoption of the standard, while we do not anticipate material changes to our current revenue processes, we could be required to present revenue from the Gathering Agreement and revenue from the SECO Pipeline Transportation Agreement as separate line items within the statement of operations. Other accounting standards that have been issued by the FASB or other standards-setting bodies are not expected to have a material impact on the Partnership’s financial position, results of operations and cash flows. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the amounts reported in the 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 commodity 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 estimates and judgment. 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. |
Cash and Cash Equivalents | Cash and Cash Equivalents All highly liquid investments with original maturities of three months or less are considered cash equivalents. |
Restricted Cash | Restricted Cash We had no restricted cash as of December 31, 2017 and 2016. |
Accounts Receivable, Net | Accounts Receivable, Net Our accounts receivable are primarily from our contractual agreements with Sanchez Energy and its subsidiaries, operators of our oil and natural gas properties and counterparties to our financial instruments. Oil receivables are generally collected within 30 days after the end of the month. Natural gas receivables are generally collected within 60 days after the end of the month. We review all outstanding accounts receivable balances and record a reserve for amounts that we expect will not be fully recovered. Actual balances are not applied against the reserves until substantially all collection efforts have been exhausted. Our allowance for doubtful accounts was $0.4 million as of December 31, 2017 and 2016. |
Concentration of Credit Risk and Accounts Receivable | Concentration of Credit Risk and Accounts Receivable Financial instruments that potentially subject us to a concentration of credit risk consist of cash and cash equivalents, accounts receivable and derivative financial instruments. We place our cash with high credit quality financial institutions. We place our derivative financial instruments with financial institutions that participate in our Credit Agreement and maintain an investment grade credit rating. Substantially all of our accounts receivables are due from operators of our oil and natural gas properties. These sales are generally unsecured and, in some cases, may carry a parent guarantee. As we generally have fewer than 10 large customers for our oil and natural gas sales, we routinely assess the financial strength of our customers. Bad debt expense is recognized on an account-by-account review and when recovery is not probable. Our allowance for doubtful accounts was $0.4 million as of December 31, 2017 and 2016. We have no off-balance-sheet credit exposure related to our operations or customers. Sanchez Energy, whose earned revenues contribute exclusively to our midstream segment, accounted for 63% and 76% of total revenue for the years ended December 31, 2017 and 2016, respectively. |
Derivatives and Hedging Activities | Derivatives and Hedging Activities We use derivative financial instruments to achieve a more predictable cash flow from our oil and natural gas production by reducing our exposure to price fluctuations. We account for all our open derivatives as mark-to-market activities. All derivative instruments are recorded in the consolidated balance sheets as either an asset or a liability measured at fair value with changes in fair value recognized in earnings. All of our open derivatives are effective as economic hedges of our commodity price exposure. These contracts are accounted for using the mark-to-market accounting method. Using this method, the contracts are carried at their fair value on our consolidated balance sheets as either short-term or long-term assets or liabilities based on their anticipated settlement date. We recognize all unrealized and realized gains and losses related to these contracts on our consolidated statements of operations under the caption “Oil sales” or “Natural gas sales.” |
Revenue Recognition | Revenue Recognition Sales are recognized when natural gas, NGLs and oil have been delivered to a custody transfer point, persuasive evidence of a sales arrangement exists, the rights and responsibility of ownership pass to the purchaser upon delivery, collection of revenue from the sale is reasonably assured and the sales price is fixed or determinable. Natural gas, NGLs and oil are generally sold on a monthly basis. Most of the contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a specific tank battery, gathering or transmission line, quality of natural gas, NGLs and oil, and prevailing supply and demand conditions, so that the price of the natural gas, NGLs and oil fluctuates to remain competitive with other available natural gas, NGLs and oil supplies. As a result, revenues from the sale of natural gas, NGLs and oil will suffer if market prices decline and benefit if they increase. We believe that the pricing provisions of our natural gas, NGLs and oil contracts are customary in the industry. Gas imbalances occur when sales are more or less than the entitled ownership percentage of total gas production. We use the entitlements method when accounting for gas imbalances. Any amount received in excess is treated as a liability. If less than the entitled share of the production is received, the excess is recorded as a receivable. There were no material gas imbalance positions at December 31, 2017 and 2016. Revenues relating to the gathering and transportation sales of oil and natural gas are recognized in the period service is provided. Under these arrangements, the Partnership receives a fee or fees for services provided. The revenue the Partnership recognizes from gathering and transportation services is generally directly related to the volume of oil and natural gas that flows through its systems. |
Income Taxes | Income Taxes SNMP and each of its wholly-owned subsidiary LLCs are treated as a partnership for federal and state income tax purposes. All of our taxable income or loss, which may differ considerably from net income or loss reported for financial reporting purposes, is passed through to the federal income tax returns of our members. As such, no federal income tax for these entities has been provided for in the accompanying financial statements. |
Earnings per Unit | 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), 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). 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. 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. |
Environmental Cost | Environmental Cost We record environmental liabilities at their undiscounted amounts on our balance sheets in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the federal Environmental Protection Agency (“EPA”) or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period charge in operation and maintenance expense when clean-up efforts do not benefit future periods. For the years ended December 31, 2017 and 2016, we had no environmental liabilities recorded, as no liabilities were deemed necessary. |
Unit-Based Compensation | Unit-Based Compensation The Partnership records unit-based compensation expense for awards granted to the directors of its general partner (for their services as directors) in accordance with the provisions of Accounting Standards Codification (“ASC”) Topic 718, “Compensation—Stock Compensation.” Unit-based compensation expense for these awards is based on the grant-date fair value and recognized over the vesting period using the straight-line method. Unit-based compensation granted to employees of SOG (including those employees who also serve as the officers of our general partner) and consultants in exchange for services are considered awards to non-employees, and the Partnership records unit-based compensation expense for these awards at fair value in accordance with the provisions of ASC 505-50, “Equity-Based Payments to Non-Employees.” For awards granted to non-employees, the Partnership records compensation expenses equal to the fair value of the unit-based award at the measurement date, which is determined to be the earlier of the performance commitment date or the service completion date. Compensation expense for unvested awards to non-employees is revalued at each period end and is amortized over the vesting period of the unit-based award. Unit-based payments are measured based on the fair value of the equity instruments granted, as it is more determinable than the value of the services rendered. In accordance with the guidance, the inclusion of market performance acceleration conditions does not change the accounting classification as compared to those awards without market performance acceleration conditions. Compensation expense for the unvested awards is revalued at each period end and is amortized over the vesting period of the stock-based award. |
Other Contingencies | Other Contingencies We recognize liabilities for other contingencies when we have an exposure that, when fully analyzed, indicates it is both probable that an asset has been impaired or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. Funds spent to remedy these contingencies are charged against the associated reserve, if one exists, or expensed. When a range of probable loss can be estimated, we accrue the most likely amount or at least the minimum of the range of probable loss. |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Acquisitions and Divestitures | |
Revenues And Lease Operating Expenses | The total purchase price was allocated to the assets purchased and liabilities assumed based upon their fair values on the date of acquisition as follows (in thousands): Proved developed reserves $ 25,016 Fair value of assets acquired 25,016 Asset retirement obligations (832) Fair value of net assets acquired $ 24,184 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 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 Oil 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) 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, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Fair Value Oil derivative instrument Derivative assets $ — $ 6,436 $ — $ 6,436 Midstream derivative instrument Earnout derivative liability — — (4,270) (4,270) Total $ — $ 6,436 $ (4,270) $ 2,166 |
Non-Recurring Fair Value Measurements Of Assets And Liabilities | The following table summarizes the non-recurring fair value measurements of our assets and liabilities 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 acquired in the Production Acquisition. The carrying values of the impaired proved properties were reduced to a fair value of $7.3 million, estimated using inputs characteristic of a Level 3 fair value measurement. The following table summarizes the non-recurring fair value measurements of our assets and liabilities as of December 31, 2016 (in thousands): Fair Value Measurements at December 31, 2016 Active Markets for Observable Identical Assets Inputs Unobservable Inputs (Level 1) (Level 2) (Level 3) Impairment (a) $ — $ — $ 10,733 Acquisitions (b) — — 24,184 Total net assets $ — $ — $ 34,917 (a) For the year ended December 31, 2016, we recorded a non-cash impairment charge of $7.6 million to impair our producing oil and natural gas properties in Texas and Louisiana (acquired prior to the Eagle Ford Acquisition) and in Oklahoma. The carrying values of the impaired proved properties were reduced to a fair value of $10.7 million, estimated using inputs characteristic of a Level 3 fair value measurement. (b) During the year ended December 31, 2016, we acquired oil and natural gas properties with a fair value of $24.2 million. See Note 3. “Acquisitions and Divestitures” for fair value allocation |
Reconciliation Of Changes In Fair Value Of Embedded and Earnout Derivative Classified As Level 3 | The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded and earnout derivatives classified as Level 3 in the fair value hierarchy (in thousands): December 31, 2017 2016 Beginning balance $ (4,270) $ (193,077) Initial fair value of earnout derivative 221 (4,270) Gain on embedded derivative — 47,794 Loss on earnout derivative (2,353) — Transfer to mezzanine equity — 145,283 Ending balance $ (6,402) $ (4,270) Loss included in earnings related to derivatives still held as of December 31, 2017 and 2016 respectively $ (2,353) $ — |
Derivative And Financial Inst31
Derivative And Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Derivative And Financial Instruments | |
Summary Of Derivative Contracts In Place | MTM Fixed Price Swaps – NYMEX (Henry Hub) For the Year Ended December 31, (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 132,088 $ 3.00 126,600 $ 3.00 121,600 $ 3.00 117,040 $ 3.00 497,328 $ 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 1,355,976 MTM Fixed Price Basis Swaps – West Texas Intermediate (WTI) For the Year Ended December 31, (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 70,600 $ 59.63 66,432 $ 59.71 62,840 $ 59.78 59,704 $ 59.84 259,576 $ 59.74 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 $ 53.50 694,088 |
Fair Value for Risk Management Assets and Liabilities | The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the years ended December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Beginning fair value of commodity derivatives $ 6,436 $ 31,018 Net gains (losses) on crude oil derivatives 3,284 (8,355) Net gains on natural gas derivatives 663 1,116 Net settlements on derivative contracts: Oil (6,422) (13,622) Natural gas (2,730) (6,919) Net premiums on derivative contracts — 3,198 Ending fair value of commodity derivatives $ 1,231 $ 6,436 |
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations | The effect of derivative instruments on our consolidated statements of operations was as follows (in thousands): Location of Gain(Loss) Year Ended December 31, Derivative Type in Income 2017 2016 Commodity – Mark-to-Market Oil sales $ 3,284 $ (8,355) Commodity – Mark-to-Market Natural gas sales 663 1,116 $ 3,947 $ (7,239) |
Reconciliation Of Changes In Fair Value Of Embedded Derivative and Earnout Derivative | The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded and earnout derivatives for the years ended December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Beginning fair value of embedded derivative $ (4,270) $ (193,077) Initial fair value of earnout derivative 221 (4,270) Gain on embedded derivative — 47,794 Loss on earnout derivative (2,353) — Transfer to mezzanine equity — 145,283 Ending fair value of embedded derivative $ (6,402) $ (4,270) |
Oil And Natural Gas Propertie32
Oil And Natural Gas Properties And Related Equipment (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Oil And Natural Gas Properties And Related Equipment. | |
Gathering and Transportation Assets | Gathering and transportation assets consist of the following (in thousands): December 31, 2017 2016 Gathering and transportation assets Midstream assets $ 184,969 $ 152,209 Less: Accumulated depreciation and amortization (26,870) (15,020) Total gathering and transportation assets $ 158,099 $ 137,189 |
Oil and Natural Gas Properties | Oil and natural gas properties consist of the following (in thousands): December 31, 2017 2016 Oil and natural gas properties and related equipment Property costs Proved property $ 170,750 $ 758,366 Unproved property — 46 Land — 501 Total property costs 170,750 758,913 Materials and supplies — 1,056 Total 170,750 759,969 Less: Accumulated depreciation, depletion, amortization and impairments (115,704) (674,338) Oil and natural gas properties and equipment, net $ 55,046 $ 85,631 |
Depreciation, Depletion, Amortization and Impairments | Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Year Ended December 31, 2017 2016 Depreciation, depletion and amortization of oil and natural gas-related assets $ 9,413 $ 6,722 Depreciation, depletion and amortization of gathering and transportation related assets 11,849 13,320 Amortization of intangible assets 13,568 13,757 Total Depreciation, depletion and amortization 34,830 33,799 Asset impairments 4,688 7,646 Total $ 39,518 $ 41,445 |
Provision For Income Taxes (Tab
Provision For Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Provision For Income Taxes | |
Reconciliation of Provision for (Benefit from) Income Taxes | A reconciliation of the provision for (benefit from) income taxes with amounts determined by applying the statutory U.S. federal income tax rate to income before income taxes is as follows (in thousands): For the Years Ended December 31, 2017 2016 Pre-tax net book income (loss) $ (3,040) $ 19,231 Texas Margin Tax (a) (438) 255 Return to accrual — — Valuation allowance 438 (255) Provision for income taxes $ — $ — Effective income tax rate % % (a) Although the Texas Margin Tax is not considered a state income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers our Texas-sourced revenues and expenses. |
Significant Components of Deferred Tax Assets and Deferred Tax Liabilities | The following table presents the significant components of deferred tax assets and deferred tax liabilities at the dates indicated (in thousands): December 31, 2017 2016 Deferred tax assets (liabilities): Derivative assets $ 7 $ (230) Depreciable, depletable property, plant and equipment 78 753 Other 1 2 Deferred tax assets: 86 525 Valuation allowance (86) (525) Total deferred tax assets $ — $ — |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Asset Retirement Obligation | |
Reconciliation of Asset Retirement Obligation | The following table is a reconciliation of the ARO (in thousands): December 31, 2017 2016 Asset retirement obligation, beginning balance $ 13,579 $ 20,364 Liabilities added from acquisitions 198 912 Sold (8,416) (6,291) Revisions to cost estimates — (2,399) Settlements (60) (134) Accretion expense 773 1,127 Asset retirement obligation, ending balance $ 6,074 $ 13,579 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Intangible Assets | |
Intangible assets | Intangible assets as of December 31, 2017 and 2016 are detailed below (in thousands): December 31, 2017 2016 Beginning balance $ 185,766 $ 199,741 Disposals (32) (219) Amortization (13,568) (13,756) Ending balance $ 172,166 $ 185,766 |
Investments (Tables)
Investments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Investments | |
Summarized financial information of unconsolidated entities | Summarized financial information of unconsolidated entities is as follows (in thousands): Years Ended December 31, 2017 2016 Sales $ 136,178 $ 12,465 Total expenses 118,077 2,677 Net income $ 18,101 $ 9,788 As of December 31, 2017 2016 Current assets $ 38,344 $ 27,779 Noncurrent assets 193,748 152,112 Current liabilities 24,710 16,577 |
Unit-Based Compensation (Tables
Unit-Based Compensation (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Unit-Based Compensation | |
Schedule Of Units Activity | Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2015 361,357 $ 14.18 Granted 67,627 10.35 Vested (195,613) 12.69 Returned/Cancelled (14,227) 15.81 Outstanding at December 31, 2016 219,144 $ 14.22 Granted 220,814 14.73 Vested (153,487) 14.20 Returned/Cancelled (3,333) 13.59 Outstanding at December 31, 2017 283,138 $ 14.64 |
Distributions To Unitholders (T
Distributions To Unitholders (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Common units | |
Schedule of payment of cash distributions | The table below reflects the payment of cash distributions on common units relating to the years ended December 31, 2017 and 2016. Distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2016 $ 0.4121 May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ 0.4183 August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ 0.4246 October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 $ 0.4310 February 9, 2017 February 20, 2017 February 28, 2017 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 |
Class B preferred units | |
Schedule of payment of cash distributions | The table below reflects the payment of distributions on Class B preferred units during the years ended December 31, 2017 and 2016. Cash distribution Date of Date of Date of Three months ended per unit declaration record distribution March 31, 2016 $ 0.4500 May 10, 2016 May 20, 2016 May 31, 2016 June 30, 2016 $ 0.4500 August 10, 2016 August 22, 2016 August 31, 2016 September 30, 2016 $ 0.4500 October 31, 2016 November 10, 2016 November 30, 2016 December 31, 2016 (a) $ 0.2258 February 9, 2017 February 20, 2017 February 28, 2017 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 The Partnership elected to pay the fourth quarter 2016 and first quarter 2017 distributions on the Class B preferred units in part cash and, with the 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 208,594 common units, each paid on February 28, 2017 to holders of record on February 20, 2017, and the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each paid on May 31, 2017 to holders of record on May 22, 2017. |
Members' Equity_Partners' Cap39
Members' Equity/Partners' Capital (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Members' Equity/Partners' Capital | |
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 in the consolidated balance sheet consisting of the following (in thousands): December 31, 2017 2016 Mezzanine equity beginning balance $ 342,991 $ 172,111 Discount — (87) Amortization of discount 1,796 23,477 Distributions 35,875 39,375 Distributions paid (36,750) (37,168) Transfer embedded derivative to Class B preferred units — 145,283 Total mezzanine equity $ 343,912 $ 342,991 |
Schedule of weighted average basic and diluted units outstanding | December 31, 2017 2016 Common units - Basic and Diluted 14,039,726 4,658,970 Weighted Common units - Basic and Diluted 14,039,726 4,658,970 |
Schedule of basic and diluted loss per unit | The following table presents our basic and diluted loss per unit for the year ended December 31, 2017 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (40,711) $ (40,711) Basic and diluted loss per unit $ (2.90) The following table presents our basic and diluted loss per unit for the year ended December 31, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (44,484) $ (44,484) Basic and diluted loss per unit $ (9.55) |
Reporting Segments (Tables)
Reporting Segments (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Reporting Segments | |
Schedule of Segment Information | The following tables present financial information for each operating segment for the periods indicated based on the realignment of our operating segments (in thousands): For the Year Ended December 31, 2017 Production Midstream Total Segment operating revenues: Natural gas sales $ 6,626 $ — $ 6,626 Oil sales 23,701 — 23,701 Natural gas liquid sales 1,997 — 1,997 Gathering and transportation sales — 55,825 55,825 Earnings (losses) from equity investments (101) 7,986 7,885 Total segment operating revenues 32,223 63,811 96,034 Segment operating costs: Lease operating expenses 12,066 928 12,994 Transportation operating expenses — 11,600 11,600 Earnout rebate — 64 64 Cost of sales 77 — 77 Production taxes 1,476 — 1,476 Gain on sale of assets (4,150) — (4,150) Depreciation, depletion and amortization 9,522 25,308 34,830 Asset impairments 4,688 — 4,688 Accretion expense 499 274 773 Total segment operating costs 24,178 38,174 62,352 Segment operating income $ 8,045 $ 25,637 $ 33,682 For the Year Ended December 31, 2016 Production Midstream Total Segment operating revenues: Natural gas sales $ 10,408 $ — $ 10,408 Oil sales 5,138 — 5,138 Natural gas liquid sales 1,167 — 1,167 Gathering and transportation sales — 53,972 53,972 Earnings from equity investments 81 2,301 2,382 Total segment operating revenues 16,794 56,273 73,067 Segment operating costs: Lease operating expenses 14,327 654 14,981 Transportation operating expenses — 12,478 12,478 Cost of sales 328 — 328 Production taxes 1,167 — 1,167 Loss on sale of assets 219 — 219 Depreciation, depletion and amortization 6,722 27,077 33,799 Asset impairments 7,646 — 7,646 Accretion expense 875 252 1,127 Total segment operating costs 31,284 40,461 71,745 Segment operating income (loss) $ (14,490) $ 15,812 $ 1,322 For the Years Ended December 31, 2017 2016 Reconciliation of segment operating income to net income (loss): Total segment operating income $ 33,682 $ 1,322 General and administrative (22,655) (22,901) Unit-based compensation expense (3,373) (1,941) Interest expense, net (8,341) (5,093) Gain on embedded derivative — 47,794 Other income (expense) (a) (2,353) 50 Net income (loss) $ (3,040) $ 19,231 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. |
Schedule of reconciliation of segment operating income to net income (loss) | For the Years Ended December 31, 2017 2016 Reconciliation of segment operating income to net income (loss): Total segment operating income $ 33,682 $ 1,322 General and administrative (22,655) (22,901) Unit-based compensation expense (3,373) (1,941) Interest expense, net (8,341) (5,093) Gain on embedded derivative — 47,794 Other income (expense) (a) (2,353) 50 Net income (loss) $ (3,040) $ 19,231 |
Summary of Total Assets by Operating Segment | The following table summarizes the total assets and capital expenditures by operating segment based on the segment realignment as of December 31, 2017 and 2016 (in thousands): 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 December 31, 2016 Production Midstream Corporate (a) Total Other financial information Total assets $ 96,262 $ 440,675 $ 2,768 $ 539,705 Capital expenditures (b) $ 939 $ 18,595 $ — $ 19,534 (a) Corporate assets not reviewed by the CODM on a segment basis consists of cash, some prepaids, and other assets. (a) Inclusive of capital contributions made to equity method investments. |
Summary of Percentage of Revenue Earned from Customers by Segment | For the Years Ended December 31, 2017 2016 Midstream Sanchez Energy 63 % 76 % Total 63 % 76 % |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
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 December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Capital investments $ 121,010 $ 107,320 Earnings in equity investments 10,288 2,301 Distributions received (11,632) (2,950) Estimated earnout accrued 4,049 4,270 Equity in equity investments $ 123,715 $ 110,941 December 31, 2017 2016 Equity in equity investments $ 123,715 $ 110,941 Guarantees of capital investments — 17,584 Maximum exposure to loss $ 123,715 $ 128,525 |
Supplemental Information On O42
Supplemental Information On Oil And Natural Gas Producing Activities (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Supplemental Information On Oil And Natural Gas Producing Activities | |
Schedule Of Capitalized Costs | The following table sets forth our capitalized costs as of December 31, 2017 and 2016 (in thousands): December 31, 2017 2016 Capitalized costs at the end of the period: ⁽ᵃ⁾ Oil and natural gas properties and related equipment (successful efforts method) Property costs Proved property $ 170,750 $ 758,366 Unproved property — 46 Land — 501 Total property costs 170,750 758,913 Materials and supplies — 1,056 Total 170,750 759,969 Less: Accumulated depreciation, depletion, amortization and impairments (115,704) (674,338) Oil and natural gas properties and equipment, net $ 55,046 $ 85,631 (a) Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist. |
Schedule Of Costs Incurred For Oil And Natural Gas Producing Activities | The following table sets forth costs incurred for oil and natural gas producing activities for the years ended December 31, 2017 and 2016 (in thousands): For the Years Ended December 31, 2017 2016 Costs incurred for the period: Acquisition of properties Proved $ — $ 25,622 Development costs 441 937 Oil and natural gas properties and equipment, net $ 441 $ 26,559 |
Schedule Of Changes In Proved Developed And Undeveloped Reserves | Natural Gas Total Oil Natural Gas Liquids (MMBoe) (in MMBoe) (in MMBoe) (in MMBoe) Net proved reserves December 31, 2015 11,642 3,159 7,736 747 Purchase of reserves in place 1,397 1,049 176 172 Sales of reserves in place (610) (47) (563) — Revisions of previous estimates (4,426) (316) (4,202) 92 Production (1,133) (331) (721) (81) December 31, 2016 6,870 3,514 2,426 930 Sales of reserves in place (1,731) (358) (1,280) (93) Revisions of previous estimates 1,062 504 383 175 Production (936) (414) (420) (102) December 31, 2017 5,265 3,246 1,109 910 Proved developed reserves: December 31, 2016 6,870 3,514 2,426 930 December 31, 2017 5,265 3,246 1,109 910 |
Summary Of Standardized Measure Of Estimated Discounted Future Cash Flows From Properties | The following table summarizes the standardized measure of estimated discounted future cash flows from the oil and natural gas properties (in thousands): For the Years Ended December 31, 2017 2016 Future cash inflows $ 197,739 $ 182,612 Future production costs (101,300) (102,569) Future estimated development costs (4,346) (8,872) Future net cash flows 92,093 71,171 10% annual discount for estimated timing of cash flows (35,396) (21,535) Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves $ 56,697 $ 49,636 |
Summary Of Change In Standardized Measure Of Estimated Discounted Future Net Cash Flows | The following table summarizes the principal sources of change in the standardized measure of estimated discounted future net cash flows (in thousands): For the Years Ended December 31, 2017 2016 Beginning of the period $ 49,636 $ 67,852 Sales and transfers of oil and natural gas, net of production costs (14,758) (8,700) Net changes in prices and production costs related to future production 15,036 (7,868) Changes in development costs 3,854 5,040 Changes in extensions and discoveries 160 — Revisions of previous quantity estimates 9,137 (17,924) Purchases and sales of reserves in place (11,952) 9,134 Accretion discount 4,964 6,175 Change in production rates, timing, and other 620 (4,073) Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves $ 56,697 $ 49,636 |
Basis Of Presentation And Sum43
Basis Of Presentation And Summary Of Significant Accounting Policies (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)segmentcustomershares | Dec. 31, 2016USD ($)shares | Dec. 31, 2015shares | |
Number of operating segments | segment | 2 | ||
Restricted unvested common units granted and outstanding | shares | 283,138 | 219,144 | 361,357 |
Restricted cash | $ 0 | $ 0 | |
Allowance for doubtful accounts | 400,000 | 400,000 | |
Gas Balancing Asset (Liability) | 0 | ||
Environmental liabilities | $ 0 | $ 0 | |
Oil | |||
Trade accounts receivable, general collection period after month end | 30 days | ||
Natural Gas | |||
Trade accounts receivable, general collection period after month end | 60 days | ||
Maximum | |||
Number of large customers | customer | 10 | ||
Sales | Customer Concentration Risk | Sanchez Energy | |||
Percentage of sales revenue | 63.00% | 76.00% |
Acquisitions and Divestitures44
Acquisitions and Divestitures (Details) | Jul. 05, 2016USD ($) | Oct. 31, 2017USD ($) | May 31, 2017USD ($) | Nov. 30, 2016USD ($)MMcfe / ditem | Jul. 31, 2016USD ($)mi | Jun. 30, 2016USD ($) | Dec. 31, 2017USD ($) | Sep. 30, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2017USD ($) |
Carnero Processing, Joint Venture | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Capital contribution commitments | $ 18,800,000 | |||||||||
Ownership interest (as a percent) | 50.00% | |||||||||
Payments to acquire interest in joint venture | $ 55,500,000 | |||||||||
Assumption of capital commitments in joint venture | $ 24,500,000 | |||||||||
Proved developed reserves (in mmcf/d) | MMcfe / d | 260 | |||||||||
Targa | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||||
Carnero Gathering, Joint Venture | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||||
Payments to acquire interest in joint venture | $ 37,000,000 | $ 37,000,000 | $ 8,800,000 | |||||||
Assumption of capital commitments in joint venture | $ 7,400,000 | $ 7,400,000 | ||||||||
Number of miles of high pressure natural gas gathering pipelines | mi | 45 | |||||||||
Agreement Term | 15 years | |||||||||
SN Cotulla Assets, LLC and SN Palmetto, LLC | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Producing wellbores | item | 23 | |||||||||
SN Cotulla Assets, LLC and SN Palmetto, LLC | Eagle Ford | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Cash payment for acquisition | $ 24,200,000 | |||||||||
Producing wellbores | item | 11 | |||||||||
Closing adjustments | $ 2,800,000 | |||||||||
Texas Production Divestiture | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from divestiture of business | $ 6,300,000 | |||||||||
Gain on sale | $ 1,400,000 | |||||||||
Oklahoma Production Divestiture | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from divestiture of business | $ 5,500,000 | |||||||||
Gain on sale | $ 2,400,000 | |||||||||
Mid-Continent Divestiture | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Proceeds from divestiture of business | $ 7,120 | |||||||||
Loss on disposition of intangible assets | $ 200,000 | |||||||||
Sanchez Energy | ||||||||||
Business Acquisition [Line Items] | ||||||||||
Payments to acquire interest in joint venture | 25,000,000 | |||||||||
Assumption of capital commitments in joint venture | $ 24,200,000 | |||||||||
Gathering Agreement delivery commitment period | 5 years |
Acquisitions and Divestitures45
Acquisitions and Divestitures (Value Net Assets Acquired) (Details) - SN Cotulla Assets, LLC and SN Palmetto, LLC $ in Thousands | Nov. 22, 2016USD ($) |
Business Acquisition [Line Items] | |
Proved developed reserves | $ 25,016 |
Fair value of assets acquired | 25,016 |
Asset retirement obligations | (832) |
Fair value of net assets acquired | $ 24,184 |
Fair Value Measurements (Recurr
Fair Value Measurements (Recurring) (Details) - Recurring - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | $ 1,231 | $ 6,436 |
Midstream derivative instrument - Earnout derivative liability | (6,402) | (4,270) |
Total net assets | (5,171) | 2,166 |
Fair Value, Inputs, Level 2 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets | 1,231 | 6,436 |
Total net assets | 1,231 | 6,436 |
Fair Value, Inputs, Level 3 | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Midstream derivative instrument - Earnout derivative liability | (6,402) | (4,270) |
Total net assets | $ (6,402) | $ (4,270) |
Fair Value Measurements (Non-Re
Fair Value Measurements (Non-Recurring) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Asset impairments | $ 4,688 | $ 7,646 |
Fair Value, Inputs, Level 3 | Nonrecurring | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Impairment | 7,277 | 10,733 |
Acquisitions | 24,184 | |
Total net assets | $ 7,277 | $ 34,917 |
Fair Value Measurements (Embedd
Fair Value Measurements (Embedded and Earnout Derivative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Fair Value Measurements | ||
Beginning Balance | $ (4,270) | $ (193,077) |
Initial fair value of earnout derivative | 221 | (4,270) |
Gain on embedded derivative | 47,794 | |
Loss on earnout derivative | (2,353) | |
Transfer to mezzanine equity | 145,283 | |
Ending Balance | $ (6,402) | $ (4,270) |
Derivative And Financial Inst49
Derivative And Financial Instruments (Hedges In Place) (Details) | 12 Months Ended |
Dec. 31, 2017MMBTU$ / MMBTU$ / bblbbl | |
West Texas Intermediate 2018 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | bbl | 70,600 |
Average Price | $ / bbl | 59.63 |
West Texas Intermediate 2018 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | bbl | 66,432 |
Average Price | $ / bbl | 59.71 |
West Texas Intermediate 2018 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | bbl | 62,840 |
Average Price | $ / bbl | 59.78 |
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 | 259,576 |
Average Price | $ / bbl | 59.74 |
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 | 694,088 |
NYMEX 2018 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in MMBtu) | MMBTU | 132,088 |
Average Price | $ / MMBTU | 3 |
NYMEX 2018 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in MMBtu) | MMBTU | 126,600 |
Average Price | $ / MMBTU | 3 |
NYMEX 2018 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in MMBtu) | MMBTU | 121,600 |
Average Price | $ / MMBTU | 3 |
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 | 497,328 |
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 | 1,355,976 |
Derivative And Financial Inst50
Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands | 1 Months Ended | 12 Months Ended | |
Aug. 31, 2017USD ($) | Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($) | |
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | $ 3,947 | $ (7,239) | |
Early termination of hedges | $ 3,600 | ||
Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Beginning fair value of commodity derivatives | 6,436 | 31,018 | |
Net premiums on derivative contracts | 3,198 | ||
Ending fair value of commodity derivatives | $ 1,231 | 6,436 | |
Number of counterparties | item | 4 | ||
Oil | Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | $ 3,284 | (8,355) | |
Net settlements on derivative contracts | (6,422) | (13,622) | |
Natural Gas | Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | 663 | 1,116 | |
Net settlements on derivative contracts | $ (2,730) | $ (6,919) |
Derivative And Financial Inst51
Derivative And Financial Instruments (Embedded Derivative) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Derivative And Financial Instruments | ||
Beginning Balance | $ (4,270) | $ (193,077) |
Initial fair value of earnout derivative | 221 | (4,270) |
Gain on embedded derivative | 47,794 | |
Loss on earnout derivative | (2,353) | |
Transfer to mezzanine equity | 145,283 | |
Ending Balance | $ (6,402) | $ (4,270) |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Line of Credit Facility [Line Items] | ||
Unamortized debt issue costs | $ 1,200 | $ 1,700 |
Amortization of debt issuance costs | 524 | $ 507 |
Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | 249,300 | |
Sub-limit which may be used for issuance of letters of credit | 15,000 | |
Initial borrowing capacity | $ 200,000 | |
Commitment fee on unutilized borrowing base | 0.50% | |
Credit Agreement | Scenario One | ||
Line of Credit Facility [Line Items] | ||
Debt to Adjusted EBITDA ratio | 4 | |
Credit Facility Maturing March 31, 2020 | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 500,000 | |
lender loan | ||
Line of Credit Facility [Line Items] | ||
Maximum borrowing capacity | $ 200,000 | |
Minimum | Credit Agreement | ||
Line of Credit Facility [Line Items] | ||
Required interest coverage ratio | 2.5 | |
Ownership percentage by subsidiary | 50 | |
Distribution limitation, credit facility excess over borrowing base (as a percent) | 90.00% | |
Required working capital ratio | 1 | |
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 | Scenario One | ||
Line of Credit Facility [Line Items] | ||
Debt to Adjusted EBITDA ratio | 4.5 | |
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% | |
Western Catarina Midstream | Credit Agreement | Scenario One | ||
Line of Credit Facility [Line Items] | ||
Debt to Adjusted EBITDA ratio | 5 | |
Western Catarina Midstream | Credit Agreement | Scenario Two | ||
Line of Credit Facility [Line Items] | ||
Debt to Adjusted EBITDA ratio | 4.75 | |
Western Catarina Midstream | Credit Agreement | Scenario Three | ||
Line of Credit Facility [Line Items] | ||
Debt to Adjusted EBITDA ratio | 4.5 |
Oil And Natural Gas Propertie53
Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | ||
Midstream assets | $ 184,969 | $ 152,209 |
Less: Accumulated depreciation and amortization | (115,704) | (674,338) |
Midstream | ||
Property, Plant and Equipment [Line Items] | ||
Midstream assets | 184,969 | 152,209 |
Less: Accumulated depreciation and amortization | (26,870) | (15,020) |
Total gathering and transportation assets | $ 158,099 | $ 137,189 |
Oil And Natural Gas Propertie54
Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Oil And Natural Gas Properties And Related Equipment. | ||
Proved property | $ 170,750 | $ 758,366 |
Unproved property | 46 | |
Land | 501 | |
Total property costs | 170,750 | 758,913 |
Materials and supplies | 1,056 | |
Total | 170,750 | 759,969 |
Less: Accumulated depreciation, depletion, amortization and impairments | (115,704) | (674,338) |
Oil and natural gas properties and equipment, net | $ 55,046 | $ 85,631 |
Oil And Natural Gas Propertie55
Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | ||
Amortization of intangible assets | $ 13,568 | $ 13,756 |
Depreciation, depletion and amortization | 21,262 | 21,901 |
Asset impairments | 4,688 | 7,646 |
Total | 39,518 | 41,445 |
Non-cash impairment charges | 4,700 | 7,600 |
Exploration and dry hole costs | $ 0 | 0 |
Furniture and Equipment | Minimum | ||
Property, Plant and Equipment [Line Items] | ||
Useful lives | 3 years | |
Furniture and Equipment | Maximum | ||
Property, Plant and Equipment [Line Items] | ||
Useful lives | 15 years | |
Gathering Facilities | Maximum | ||
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 | $ 9,413 | 6,722 |
Gathering and Transportation Related Assets | ||
Property, Plant and Equipment [Line Items] | ||
Depreciation, depletion and amortization | 11,849 | 13,320 |
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets | ||
Property, Plant and Equipment [Line Items] | ||
Amortization of intangible assets | 13,568 | 13,757 |
Depreciation, depletion and amortization | $ 34,830 | 33,799 |
Texas And Louisiana Oil And Natural Gas Fields | ||
Property, Plant and Equipment [Line Items] | ||
Non-cash impairment charges | 1,300 | |
Oklahoma oil and natural gas fields | ||
Property, Plant and Equipment [Line Items] | ||
Non-cash impairment charges | $ 6,300 |
Provision For Income Taxes (Inc
Provision For Income Taxes (Income Tax Provision (Benefit)) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Provision For Income Taxes | ||
Income tax expense | $ 0 | $ 0 |
Provision For Income Taxes (Rec
Provision For Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Provision For Income Taxes | ||
Pre-tax net book income (loss) | $ (3,040) | $ 19,231 |
Texas Margin Tax | (438) | 255 |
Valuation allowance | 438 | (255) |
Provision for income taxes | $ 0 | $ 0 |
Effective income tax rate | 0.00% | 0.00% |
Provision For Income Taxes (DTA
Provision For Income Taxes (DTA and DTL) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Deferred tax assets (liabilities): | ||
Derivative assets | $ 7 | |
Derivative assets, liability | $ (230) | |
Depreciable, depletable property, plant and equipment | 78 | 753 |
Other | 1 | 2 |
Deferred tax assets: | 86 | 525 |
Valuation allowance | (86) | (525) |
Total deferred tax assets |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Asset Retirement Obligation | ||
Asset retirement obligation, beginning balance | $ 13,579,000 | $ 20,364,000 |
Liabilities added from acquisitions | 198,000 | 912,000 |
Sold | (8,416,000) | (6,291,000) |
Revisions to cost estimates | (2,399,000) | |
Settlements | (60,000) | (134,000) |
Accretion expense | 773,000 | 1,127,000 |
Asset retirement obligation, ending balance | 6,074,000 | 13,579,000 |
Legally restricted assets | $ 0 | $ 0 |
Intangible Assets (Details)
Intangible Assets (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | |
Finite-Lived Intangible Assets [Line Items] | ||
Amortization of intangible assets | $ 13,568 | $ 13,756 |
Beginning balance | 185,766 | 199,741 |
Disposals | (32) | (219) |
Amortization | (13,568) | (13,756) |
Ending balance | $ 172,166 | $ 185,766 |
Customer Contracts | ||
Finite-Lived Intangible Assets [Line Items] | ||
Agreement term (in years) | 15 years | |
Dedicated acreage | a | 35,000 | |
Useful life | 15 years |
Investments (Details)
Investments (Details) - USD ($) $ in Thousands | Nov. 22, 2016 | Jul. 05, 2016 | Nov. 30, 2016 | Jul. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 |
Schedule of Equity Method Investments [Line Items] | |||||||
Capital investments | $ 121,010 | $ 107,320 | $ 121,010 | ||||
Earnout | 4,049 | 4,270 | 4,049 | ||||
Earnings in equity investments | 7,885 | 2,382 | |||||
Amortization of intangible assets | 13,568 | 13,756 | |||||
Distributions received | 8,720 | 2,950 | |||||
Targa | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||
Carnero Gathering, Joint Venture | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||
Payments to acquire interest in joint venture | $ 37,000 | $ 37,000 | 8,800 | ||||
Assumption of capital commitments in joint venture | $ 7,400 | $ 7,400 | |||||
Payments of capital commitments, joint venture | 5,400 | ||||||
Capital investments | 46,200 | 46,200 | |||||
Agreement term (in years) | 15 years | ||||||
Earnings in equity investments | 6,600 | ||||||
Distributions received | 7,600 | ||||||
Carnero Gathering, Joint Venture | Customer Relationships | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Intangible asset, fair value | $ 13,000 | ||||||
Amortization of intangible assets | 900 | ||||||
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 | $ 55,500 | |||||
Assumption of capital commitments in joint venture | $ 24,500 | 24,500 | |||||
Payments of capital commitments, joint venture | 8,200 | ||||||
Capital investments | 48,000 | 74,700 | $ 74,700 | ||||
Earnings in equity investments | 2,200 | ||||||
Distributions received | 1,100 | ||||||
Sanchez Energy | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Payments to acquire interest in joint venture | 25,000 | ||||||
Assumption of capital commitments in joint venture | $ 24,200 | ||||||
Sanchez Energy | Carnero Gathering, Joint Venture | |||||||
Schedule of Equity Method Investments [Line Items] | |||||||
Capital investments | $ 26,000 | ||||||
Earnout payments | $ 0 | $ 0 |
Investments (Unconsolidated Ent
Investments (Unconsolidated Entities) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Investments | ||
Sales | $ 136,178 | $ 12,465 |
Total expenses | 118,077 | 2,677 |
Net income | 18,101 | 9,788 |
Current assets | 38,344 | 27,779 |
Noncurrent assets | 193,748 | 152,112 |
Current liabilities | $ 24,710 | $ 16,577 |
Commitments And Contingencies (
Commitments And Contingencies (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Recurring | ||
Variable Interest Entity [Line Items] | ||
Earnout derivative liability | $ 6,402 | $ 4,270 |
Sanchez Energy | Carnero Gathering, Joint Venture | ||
Variable Interest Entity [Line Items] | ||
Earnout payments | $ 0 | $ 0 |
Related Party Transactions (Det
Related Party Transactions (Details) $ in Millions | Nov. 22, 2016USD ($) | Jul. 05, 2016USD ($) | Oct. 14, 2015a$ / bbl$ / McfMMcfbbl | Nov. 30, 2016USD ($)itemshares | Jul. 31, 2016USD ($) | Dec. 31, 2017USD ($)a | Dec. 31, 2016USD ($) | Dec. 31, 2017USD ($)a | Mar. 06, 2018 | Mar. 05, 2018 |
Related Party Transaction [Line Items] | ||||||||||
Related parties, net receivable | $ 13.1 | $ 6 | $ 13.1 | |||||||
Related parties, net payable | $ 10.4 | 7 | $ 10.4 | |||||||
Sanchez Energy | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Acres dedicated for gathering | a | 487,000 | 487,000 | ||||||||
Gathering Agreement delivery commitment period | 5 years | |||||||||
Payments to acquire interest in joint venture | $ 25 | |||||||||
Assumption of capital commitments in joint venture | $ 24.2 | |||||||||
Accrued payable, value | $ 0.1 | $ 0.1 | ||||||||
Net acres assembled | a | 285,000 | 285,000 | ||||||||
SP Holdings | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Quarterly fee (as a percent) | 0.375% | 0.375% | ||||||||
Maximum asset acquisition, disposition and financing fee (as a percent) | 2.00% | |||||||||
Agreement term (in years) | 10 years | |||||||||
Services Agreement renewal term | 10 years | |||||||||
Agreement notice period | 180 days | |||||||||
Administrative fee | $ 8.8 | 7.5 | ||||||||
Targa | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||||
Carnero Processing Joint Venture | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership interest (as a percent) | 50.00% | |||||||||
Payments to acquire interest in joint venture | $ 55.5 | $ 55.5 | ||||||||
Assumption of capital commitments in joint venture | $ 24.5 | $ 24.5 | ||||||||
Carnero Gathering, Joint Venture | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Agreement term (in years) | 15 years | |||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||||
Payments to acquire interest in joint venture | $ 37 | $ 37 | $ 8.8 | |||||||
Assumption of capital commitments in joint venture | $ 7.4 | $ 7.4 | ||||||||
Carnero Gathering, Joint Venture | Sanchez Energy | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Earnout payments | 0 | 0 | ||||||||
Acquisition of Wellbore Interests | Sanchez Energy | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Producing wellbores | item | 23 | |||||||||
Acquisition of Working Interests | Sanchez Energy | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Producing wellbores | item | 11 | |||||||||
Western Catarina Midstream | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Agreement term (in years) | 15 years | |||||||||
Acres dedicated for gathering | a | 35,000 | |||||||||
Gathering Agreement delivery commitment period | 5 years | |||||||||
Western Catarina Midstream | Oil | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Gathering Agreement minimum quarterly volume delivery commitment | bbl | 10,200 | |||||||||
Gathering and processing fees (in dollars per volume) | $ / bbl | 0.96 | |||||||||
Western Catarina Midstream | Natural Gas | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Gathering Agreement minimum quarterly volume delivery commitment | MMcf | 142,000 | |||||||||
Gathering and processing fees (in dollars per volume) | $ / Mcf | 0.74 | |||||||||
Western Catarina Midstream | Sanchez Energy | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Proceeds from gathering and processing agreement | 52.8 | $ 50.1 | ||||||||
Western Catarina Midstream | SN Catarina | Oil | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Proceeds from transportation agreement | $ 0.9 | |||||||||
Common units | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership by related parties (as a percentage) | 15.20% | |||||||||
Common units | Sanchez Energy | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Shares repurchased | shares | 2,272,727 | |||||||||
Common units | Sanchez Energy | Executive Chairman | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership by related parties (as a percentage) | 6.80% | |||||||||
Common units | Sanchez Energy | Chief Executive Officer | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership by related parties (as a percentage) | 3.00% | |||||||||
Common units | Sanchez Energy | President | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership by related parties (as a percentage) | 1.20% | |||||||||
Common units | Sanchez Energy | Related Individual | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership by related parties (as a percentage) | 1.40% |
Unit-Based Compensation (Restri
Unit-Based Compensation (Restricted Units Activity) (Details) - $ / shares | 1 Months Ended | 12 Months Ended | ||
Apr. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of Restricted Units, Outstanding | 219,144 | 361,357 | ||
Number of Restricted Units, Granted | 220,814 | 67,627 | ||
Number of Restricted Units, Vested | (153,487) | (195,613) | ||
Number of Restricted Units, Returned/Cancelled | (3,333) | (14,227) | ||
Number of Restricted Units, Outstanding | 283,138 | 219,144 | ||
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ 14.22 | $ 14.18 | ||
Weighted Averaged Grant Date Fair Value Per Unit, Granted | 14.73 | 10.35 | ||
Weighted Averaged Grant Date Fair Value Per Unit, Vested | 14.20 | 12.69 | ||
Weighted Averaged Grant Date Fair Value Per Unit, Returned/Cancelled | 13.59 | 15.81 | ||
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ 14.64 | $ 14.22 | ||
LTIP | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of Restricted Units, Outstanding | 283,138 | |||
Units available for issuance | 1,599,135 | |||
Director | LTIP | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of Restricted Units, Granted | 67,627 | |||
Restricted Stock Units (RSUs) | LTIP | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Number of Restricted Units, Granted | 44,583 | 171,231 |
Distributions To Unitholders (D
Distributions To Unitholders (Details) - $ / shares | May 31, 2017 | Feb. 28, 2017 | Dec. 31, 2017 | Sep. 30, 2017 | Jun. 30, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 | Dec. 31, 2017 |
Common units | |||||||||||
Distribution paid per unit | $ 0.4508 | $ 0.4508 | $ 0.4441 | $ 0.4375 | $ 0.4310 | $ 0.4246 | $ 0.4183 | $ 0.4121 | |||
Aggregate distribution of units | 393,291 | ||||||||||
Class B preferred units | |||||||||||
Distribution paid per unit | $ 0.28225 | $ 0.28225 | $ 0.28225 | $ 0.2258 | $ 0.2258 | $ 0.4500 | $ 0.4500 | $ 0.4500 | |||
Aggregate distribution of units | 184,697 | 208,594 |
Members' Equity_Partners' Cap67
Members' Equity/Partners' Capital (Details) $ / shares in Units, $ in Thousands | May 22, 2017shares | Feb. 20, 2017shares | Jan. 25, 2017$ / sharesshares | Oct. 14, 2015USD ($)$ / sharesshares | Apr. 30, 2017USD ($)shares | Nov. 30, 2016USD ($)shares | Sep. 30, 2017shares | Jun. 30, 2017shares | Mar. 31, 2017shares | Dec. 31, 2016shares | Sep. 30, 2016shares | Dec. 31, 2015 | Dec. 31, 2017USD ($)shares | Dec. 31, 2016USD ($)shares | Dec. 06, 2016shares | Mar. 31, 2016 |
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Class B preferred units, outstanding | 29,296,441 | 31,000,887 | 29,296,441 | |||||||||||||
Common units, outstanding | 13,447,749 | 14,965,134 | 13,447,749 | |||||||||||||
Units, issued | 13,447,749 | 14,965,134 | 13,447,749 | |||||||||||||
Proceeds from common units sold | $ | $ 1,290 | $ 99,196 | ||||||||||||||
Paid-in kind units per annum | 4.00% | |||||||||||||||
Class B preferred units, issued | 29,296,441 | 31,000,887 | 29,296,441 | |||||||||||||
Pubic Offering | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Units, issued | 6,745,107 | |||||||||||||||
Proceeds from common units sold | $ | $ 69,700 | |||||||||||||||
Private Placement | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Units, issued | 2,272,727 | |||||||||||||||
Proceeds from common units sold | $ | $ 25,000 | |||||||||||||||
Over-Allotment Option | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Units, issued | 194,305 | |||||||||||||||
Class A preferred units | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Preferred units converted to common shares, conversion ratio | 1 | |||||||||||||||
Class B preferred units | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Class B preferred units, outstanding | 31,000,887 | |||||||||||||||
Units, issued | 9,851,996 | |||||||||||||||
Units sold (in units) | 184,697 | 208,594 | 19,444,445 | |||||||||||||
Price per unit sold | $ / shares | $ 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% | |||||||||||||||
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 | $ / shares | $ 11.29 | |||||||||||||||
Common units | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Common units, outstanding | 14,965,134 | |||||||||||||||
Units, issued | 84,577 | |||||||||||||||
Units sold (in units) | 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 | |||||||||||||||
Minimum | Class B preferred units | ||||||||||||||||
Limited Partners' Capital Account [Line Items] | ||||||||||||||||
Preferred unit conversion, amount | $ | $ 17,500 |
Members' Equity_Partners' Cap68
Members' Equity/Partners' Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Mezzanine equity beginning balance | $ 342,991 | |
Distributions | 31,500 | $ 37,168 |
Total mezzanine equity | 343,912 | 342,991 |
Class B preferred units | ||
Mezzanine equity beginning balance | 342,991 | 172,111 |
Discount | (87) | |
Amortization of discount | 1,796 | 23,477 |
Distributions | 35,875 | 39,375 |
Distributions paid | (36,750) | (37,168) |
Transfer embedded derivative to Class B preferred units | 145,283 | |
Total mezzanine equity | $ 343,912 | $ 342,991 |
Members' Equity_Partners' Cap69
Members' Equity/Partners' Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Weighted Common Units - Basic and Diluted (in units) | 14,039,726 | 4,658,970 | |
Restricted unvested common units granted and outstanding | 283,138 | 219,144 | 361,357 |
Assumed net loss to be allocated | $ (40,711) | $ (44,484) | |
Asset impairments | $ 4,688 | $ 7,646 | |
Common units | |||
Weighted Common Units - Basic and Diluted (in units) | 14,039,726 | 4,658,970 | |
Assumed net loss to be allocated | $ (40,711) | $ (44,484) | |
Basic and diluted loss per unit (in dollars per share) | $ (2.90) | $ (9.55) | |
Common units | Prior To Stock Split | |||
Weighted Common Units - Basic and Diluted (in units) | 14,039,726 | 4,658,970 | |
Restricted Unvested Units | |||
Assumed net loss to be allocated | $ 0 | $ 0 |
Reporting Segments (Segment Inf
Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Segment operating revenues: | ||
Natural gas sales | $ 6,626 | $ 10,408 |
Oil sales | 23,701 | 5,138 |
Natural gas liquid sales | 1,997 | 1,167 |
Gathering and transportation sales | 55,825 | 53,972 |
Earnings (losses) from equity investments | 7,885 | 2,382 |
Total revenues | 88,149 | 70,685 |
Segment operating costs: | ||
Lease operating expenses | 12,994 | 14,981 |
Transportation operating expenses | 11,600 | 12,478 |
Cost of sales | 77 | 328 |
Production taxes | 1,476 | 1,167 |
Loss (gain) on sale of assets | (4,150) | 219 |
Depreciation, depletion and amortization | 34,830 | 33,799 |
Asset impairments | 4,688 | 7,646 |
Accretion expense | 773 | 1,127 |
Total operating expenses | 88,316 | 96,587 |
Segment operating income (loss | 33,682 | 1,322 |
Operating Segments | ||
Segment operating revenues: | ||
Natural gas sales | 6,626 | 10,408 |
Oil sales | 23,701 | 5,138 |
Natural gas liquid sales | 1,997 | 1,167 |
Gathering and transportation sales | 55,825 | 53,972 |
Earnings (losses) from equity investments | 7,885 | 2,382 |
Total revenues | 96,034 | 73,067 |
Segment operating costs: | ||
Lease operating expenses | 12,994 | 14,981 |
Transportation operating expenses | 11,600 | 12,478 |
Earnout rebate | 64 | |
Cost of sales | 77 | 328 |
Production taxes | 1,476 | 1,167 |
Loss (gain) on sale of assets | (4,150) | 219 |
Depreciation, depletion and amortization | 34,830 | 33,799 |
Asset impairments | 4,688 | 7,646 |
Accretion expense | 773 | 1,127 |
Total operating expenses | 62,352 | 71,745 |
Segment operating income (loss | 33,682 | 1,322 |
Operating Segments | Production | ||
Segment operating revenues: | ||
Natural gas sales | 6,626 | 10,408 |
Oil sales | 23,701 | 5,138 |
Natural gas liquid sales | 1,997 | 1,167 |
Earnings (losses) from equity investments | (101) | 81 |
Total revenues | 32,223 | 16,794 |
Segment operating costs: | ||
Lease operating expenses | 12,066 | 14,327 |
Cost of sales | 77 | 328 |
Production taxes | 1,476 | 1,167 |
Loss (gain) on sale of assets | (4,150) | 219 |
Depreciation, depletion and amortization | 9,522 | 6,722 |
Asset impairments | 4,688 | 7,646 |
Accretion expense | 499 | 875 |
Total operating expenses | 24,178 | 31,284 |
Segment operating income (loss | 8,045 | (14,490) |
Operating Segments | Midstream | ||
Segment operating revenues: | ||
Gathering and transportation sales | 55,825 | 53,972 |
Earnings (losses) from equity investments | 7,986 | 2,301 |
Total revenues | 63,811 | 56,273 |
Segment operating costs: | ||
Lease operating expenses | 928 | 654 |
Transportation operating expenses | 11,600 | 12,478 |
Earnout rebate | 64 | |
Depreciation, depletion and amortization | 25,308 | 27,077 |
Accretion expense | 274 | 252 |
Total operating expenses | 38,174 | 40,461 |
Segment operating income (loss | $ 25,637 | $ 15,812 |
Reporting Segments - Reconcilia
Reporting Segments - Reconciliation of Segment Operating Income (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Reconciliation of segment operating income to net income (loss): | ||
Segment operating income (loss | $ 33,682 | $ 1,322 |
General and administrative | (22,655) | (22,901) |
Unit-based compensation expense | (3,373) | (1,941) |
Interest expense, net | (8,341) | (5,093) |
Gain on embedded derivative | 47,794 | |
Loss on earnout derivative | (2,353) | |
Other income (expense) | (2,353) | 50 |
Net income (loss) | $ (3,040) | $ 19,231 |
Reporting Segments (Assets by S
Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Total assets | $ 528,423 | $ 539,705 |
Capital expenditures | 46,893 | 19,534 |
Production | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Total assets | 58,623 | 96,262 |
Capital expenditures | 441 | 939 |
Midstream | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Total assets | 468,656 | 440,675 |
Capital expenditures | 46,452 | 18,595 |
Corporate | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Total assets | $ 1,144 | $ 2,768 |
Reporting Segments (Percentage
Reporting Segments (Percentage of Revenue) (Details) - Revenue - Customer Concentration Risk | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Revenue, Major Customer [Line Items] | ||
Percentage of revenue | 63.00% | 76.00% |
Midstream | Sanchez Energy | ||
Revenue, Major Customer [Line Items] | ||
Percentage of revenue | 63.00% | 76.00% |
Variable Interest Entities (Det
Variable Interest Entities (Details) - USD ($) $ in Thousands | Nov. 22, 2016 | Jul. 05, 2016 | Nov. 30, 2016 | Jul. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2017 |
Variable Interest Entity [Line Items] | |||||||
Capital investments | $ 121,010 | $ 107,320 | $ 121,010 | ||||
Earnings in equity investments | 10,288 | 2,301 | 10,288 | ||||
Distributions received | (11,632) | (2,950) | |||||
Estimated earnout accrued | 4,049 | 4,270 | 4,049 | ||||
Equity in equity investments | 123,715 | 110,941 | 123,715 | ||||
Guarantees of capital investments | 17,584 | ||||||
Maximum exposure to loss | 123,715 | $ 128,525 | 123,715 | ||||
Carnero Gathering, Joint Venture | |||||||
Variable Interest Entity [Line Items] | |||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||
Payments to acquire interest in joint venture | $ 37,000 | $ 37,000 | 8,800 | ||||
Assumption of capital commitments in joint venture | $ 7,400 | $ 7,400 | |||||
Debt incurred | 0 | 0 | |||||
Capital investments | 46,200 | 46,200 | |||||
Maximum exposure to loss | 47,900 | 47,900 | |||||
Carnero Processing Joint Venture | |||||||
Variable Interest Entity [Line Items] | |||||||
Ownership interest (as a percent) | 50.00% | ||||||
Payments to acquire interest in joint venture | $ 55,500 | $ 55,500 | |||||
Assumption of capital commitments in joint venture | $ 24,500 | 24,500 | |||||
Debt incurred | 0 | 0 | |||||
Capital investments | $ 48,000 | 74,700 | 74,700 | ||||
Maximum exposure to loss | $ 75,800 | $ 75,800 |
Supplemental Information On O75
Supplemental Information On Oil And Natural Gas Producing Activities (Capitalized Costs) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Information On Oil And Natural Gas Producing Activities | |||
Proved property | [1] | $ 170,750 | $ 758,366 |
Unproved property | [1] | 46 | |
Land | 501 | ||
Total property costs | [1] | 170,750 | 758,913 |
Materials and supplies | [1] | 1,056 | |
Total | [1] | 170,750 | 759,969 |
Less: accumulated depreciation, depletion, amortization and impairments | [1] | (115,704) | (674,338) |
Oil and natural gas properties and equipment, net | [1] | $ 55,046 | $ 85,631 |
[1] | Capitalized costs include the cost of equipment and facilities for our oil and natural gas producing activities. Proved property costs include capitalized costs for leaseholds holding proved reserves; development wells and related equipment and facilities (including uncompleted development well costs); and support equipment. Unproved property costs include capitalized costs for oil and natural gas leaseholds where proved reserves do not exist. |
Supplemental Information On O76
Supplemental Information On Oil And Natural Gas Producing Activities (Costs Incurred Production) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Information On Oil And Natural Gas Producing Activities | ||
Proved | $ 25,622 | |
Development costs | $ 441 | 937 |
Oil and natural gas properties and equipment, net | $ 441 | $ 26,559 |
Supplemental Information On O77
Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves) (Details) - MMBoe | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Changes in proved developed and undeveloped reserves | ||
Balance | 6,870 | 11,642 |
Purchase of reserves in place | 1,397 | |
Sales of reserves in place | (1,731) | (610) |
Revisions of previous estimates | 1,062 | (4,426) |
Production | (936) | (1,133) |
Balance | 5,265 | 6,870 |
Proved developed reserves | 5,265 | 6,870 |
Oil | ||
Changes in proved developed and undeveloped reserves | ||
Balance | 3,514 | 3,159 |
Purchase of reserves in place | 1,049 | |
Sales of reserves in place | (358) | (47) |
Revisions of previous estimates | 504 | (316) |
Production | (414) | (331) |
Balance | 3,246 | 3,514 |
Proved developed reserves | 3,246 | 3,514 |
Natural Gas | ||
Changes in proved developed and undeveloped reserves | ||
Balance | 2,426 | 7,736 |
Purchase of reserves in place | 176 | |
Sales of reserves in place | (1,280) | (563) |
Revisions of previous estimates | 383 | (4,202) |
Production | (420) | (721) |
Balance | 1,109 | 2,426 |
Proved developed reserves | 1,109 | 2,426 |
Natural Gas Liquids | ||
Changes in proved developed and undeveloped reserves | ||
Balance | 930 | 747 |
Purchase of reserves in place | 172 | |
Sales of reserves in place | (93) | |
Revisions of previous estimates | 175 | 92 |
Production | (102) | (81) |
Balance | 910 | 930 |
Proved developed reserves | 910 | 930 |
Supplemental Information On O78
Supplemental Information On Oil And Natural Gas Producing Activities (Proved Reserves Narrative) (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2017USD ($)MMBoe$ / bbl$ / Mcf | Dec. 31, 2016USD ($)MMBoe$ / bbl$ / Mcf | Dec. 31, 2015MMBoe | |
Reserve Quantities [Line Items] | |||
Exploration and dry hole costs | $ | $ 0 | $ 0 | |
Proved reserve estimates | 5,265 | 6,870 | 11,642 |
Reserve revision | 5,265 | 6,870 | |
Increase (decrease) in proved reserve estimates | 1,600,000 | (4,700,000) | |
Oil | |||
Reserve Quantities [Line Items] | |||
Proved reserve estimates | 3,246 | 3,514 | 3,159 |
Reserve revision | 3,246 | 3,514 | |
Weighted-average product price | $ / bbl | 48.69 | 38.85 | |
Natural Gas Liquids | |||
Reserve Quantities [Line Items] | |||
Proved reserve estimates | 910 | 930 | 747 |
Reserve revision | 910 | 930 | |
Weighted-average product price | $ / bbl | 21.34 | 13.84 | |
Natural Gas | |||
Reserve Quantities [Line Items] | |||
Proved reserve estimates | 1,109 | 2,426 | 7,736 |
Reserve revision | 1,109 | 2,426 | |
Percentage of reserves | 35.00% | ||
Weighted-average product price | $ / Mcf | 3.04 | 2.28 |
Supplemental Information On O79
Supplemental Information On Oil And Natural Gas Producing Activities (Standardized Measure) (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
Supplemental Information On Oil And Natural Gas Producing Activities | |||
Future cash inflows | $ 197,739 | $ 182,612 | |
Future production costs | (101,300) | (102,569) | |
Future estimated development costs | (4,346) | (8,872) | |
Future net cash flows | 92,093 | 71,171 | |
10% annual discount for estimated timing of cash flows | (35,396) | (21,535) | |
Standardized measure of discounted estimated future net cash flows related to proved oil and natural gas reserves | $ 56,697 | $ 49,636 | $ 67,852 |
Supplemental Information On O80
Supplemental Information On Oil And Natural Gas Producing Activities (Change Standardized Measure) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Supplemental Information On Oil And Natural Gas Producing Activities | ||
Beginning of the period | $ 49,636 | $ 67,852 |
Sales and transfers of oil and natural gas, net of production costs | (14,758) | (8,700) |
Net changes in prices and production costs related to future production | 15,036 | (7,868) |
Changes in development costs | 3,854 | 5,040 |
Changes in extensions and discoveries | 160 | |
Revisions of previous quantity estimates | 9,137 | (17,924) |
Purchases and sales of reserves in place | (11,952) | 9,134 |
Accretion discount | 4,964 | 6,175 |
Change in production rates, timing, and other | 620 | (4,073) |
Standardized measure of discounted future net cash flows related to proved oil and natural gas reserves | $ 56,697 | $ 49,636 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - Subsequent event | Feb. 08, 2018$ / shares |
Common units | |
Subsequent Event [Line Items] | |
Distribution declared per unit | $ 0.4508 |
Annual distribution declared per unit | 1.8032 |
Class B preferred units | |
Subsequent Event [Line Items] | |
Distribution declared per unit | $ 0.28225 |