Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2017 | May 10, 2017 | |
Document And Entity Information | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2017 | |
Document Fiscal Year Focus | 2,017 | |
Document Fiscal Period Focus | Q1 | |
Entity Registrant Name | Sanchez Production 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 | 14,282,221 | |
Entity Current Reporting Status | Yes |
Condensed Consolidated Statemen
Condensed Consolidated Statements of Operations - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Revenues | ||
Natural gas sales | $ 2,779 | $ 3,675 |
Oil sales | 11,350 | 5,343 |
Natural gas liquids sales | 467 | 276 |
Gathering and transportation sales | 11,211 | 13,875 |
Total revenues | 25,807 | 23,169 |
Operating expenses: | ||
Lease operating expenses | 4,983 | 4,973 |
Transportation operating expenses | 3,296 | 3,054 |
Cost of sales | 37 | 130 |
Production taxes | 473 | 221 |
General and administrative | 5,609 | 5,719 |
Unit-based compensation expense | 540 | 438 |
Depreciation, depletion and amortization | 12,181 | 7,188 |
Asset impairments | 4,688 | 1,309 |
Accretion expense | 258 | 315 |
Total operating expenses | 32,065 | 23,347 |
Other (income) expense | ||
Interest expense, net | 1,883 | 899 |
Gain on embedded derivatives | (6,294) | |
Earnings from equity investments | (482) | (12) |
Other income | (48) | |
Total other (income) expenses | 1,401 | (5,455) |
Total expenses | 33,466 | 17,892 |
Income (loss) before income taxes | (7,659) | 5,277 |
Net income (loss) | (7,659) | 5,277 |
Less: | ||
Preferred unit distributions paid in common units | (2,625) | |
Preferred unit distributions | (7,000) | (8,750) |
Preferred unit amortization | (404) | (7,266) |
Net loss attributable to common unitholders | $ (17,688) | $ (10,739) |
Net loss per unit | ||
Weighted Average Units Outstanding - Basic and diluted | 13,400,138 | 2,743,419 |
Common Units | ||
Other (income) expense | ||
Net income (loss) | $ (7,659) | |
Less: | ||
Net loss attributable to common unitholders | $ (17,688) | $ (10,739) |
Net loss per unit | ||
Net loss per unit - Basic and diluted | $ (1.32) | $ (3.91) |
Weighted Average Units Outstanding - Basic and diluted | 13,400,138 | 2,743,419 |
Condensed Consolidated Balance
Condensed Consolidated Balance Sheets - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Current assets | ||
Cash and cash equivalents | $ 2,493 | $ 957 |
Accounts receivable | 1,169 | 1,212 |
Accounts receivable - related entities | 3,036 | 5,987 |
Prepaid expenses | 2,061 | 2,041 |
Fair value of derivative instruments | 5,062 | 4,568 |
Total current assets | 13,821 | 14,765 |
Oil and natural gas properties and related equipment | ||
Oil and natural gas properties, equipment and facilities (successful efforts method) | 757,825 | 758,913 |
Gathering and transportation assets | 165,111 | 152,209 |
Material and supplies | 1,056 | 1,056 |
Less: accumulated depreciation, depletion, amortization and impairment | (702,803) | (689,358) |
Oil and natural gas properties and equipment, net | 221,189 | 222,820 |
Other assets | ||
Intangible assets, net | 182,354 | 185,766 |
Fair value of derivative instruments | 5,945 | 3,964 |
Equity investments | 111,987 | 111,614 |
Other non-current assets | 681 | 776 |
Total assets | 535,977 | 539,705 |
Current liabilities | ||
Accounts payable and accrued liabilities | 883 | 951 |
Accounts payable and accrued liabilities - related entities | 13,272 | 7,046 |
Royalties payable | 954 | 706 |
Fair value of derivative instruments | 92 | 740 |
Total current liabilities | 15,201 | 9,443 |
Other liabilities | ||
Asset retirement obligation | 14,032 | 13,579 |
Long-term debt, net of debt issuance costs | 158,924 | 151,322 |
Fair value of derivative instruments | 1,356 | |
Other liabilities | 4,049 | 4,270 |
Total other liabilities | 177,005 | 170,527 |
Total liabilities | 192,206 | 179,970 |
Commitments and contingencies (See Note 11) | ||
Mezzanine equity | ||
Class B preferred units, 31,000,887 and 29,296,441 units issued and outstanding as of March 31, 2017 and December 31, 2016, respectively | 343,395 | 342,991 |
Partners' capital | ||
Common units, 14,153,061 and 13,447,749 units issued and outstanding as of March 31, 2017 and December 31, 2016, respectively | 376 | 16,744 |
Total partners' capital | 376 | 16,744 |
Total liabilities and partners' capital | $ 535,977 | $ 539,705 |
Condensed Consolidated Balance4
Condensed Consolidated Balance Sheets (Parenthetical) - shares | Mar. 31, 2017 | Dec. 31, 2016 |
Condensed 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 | 14,153,061 | 13,447,749 |
Units, outstanding | 14,153,061 | 13,447,749 |
Condensed Consolidated Stateme5
Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Cash flows from operating activities: | ||
Net income (loss) | $ (7,659) | $ 5,277 |
Adjustments to reconcile net income (loss) to cash provided by operating activities: | ||
Depreciation, depletion and amortization | 8,769 | 3,730 |
Amortization of debt issuance costs | 128 | 123 |
Asset impairments | 4,688 | 1,309 |
Accretion expense | 258 | 315 |
Distributions from equity investments | 2,010 | |
Equity earnings in affiliate | (482) | (12) |
Bad debt expense | 17 | |
Total mark-to-market on commodity derivative contracts | (6,055) | (3,991) |
Cash settlements on commodity derivative contracts | 1,513 | 7,062 |
Unit-based compensation expense | 540 | 862 |
Gain on embedded derivative | (6,294) | |
Amortization of intangible assets | 3,412 | 3,458 |
Costs for plug and abandon activities | (17) | |
Changes in Operating Assets and Liabilities: | ||
Accounts receivable | 43 | 566 |
Accounts receivable - related entities | 2,951 | (416) |
Prepaid expenses | (20) | (1,146) |
Other assets | 83 | 632 |
Accounts payable and accrued liabilities | (3,092) | (2,810) |
Accounts payable and accrued liabilities - related entities | 6,226 | 2,006 |
Royalties payable | 248 | (239) |
Net cash provided by operating activities | 13,561 | 10,432 |
Cash flows from investing activities: | ||
Final settlement of oil and natural gas properties acquisition | 1,468 | |
Development of oil and natural gas properties | (143) | (1,084) |
Proceeds from sale of assets | 26 | |
Construction of gathering and transportation assets | (5,786) | |
Purchases of equity affiliates | (2,122) | |
Net cash used in investing activities | (6,583) | (1,058) |
Cash flows from financing activities: | ||
Payments for offering costs | (120) | (83) |
Proceeds from issuance of debt | 7,500 | 2,000 |
Repurchase of common units under repurchase program | (3,106) | |
Units tendered by employees for tax withholdings | (140) | |
Distributions to common unitholders | (5,796) | (1,262) |
Class B preferred unit cash distributions | (7,000) | (7,418) |
Debt issuance costs | (26) | |
Net cash used in financing activities | (5,442) | (10,009) |
Net increase (decrease) in cash and cash equivalents | 1,536 | (635) |
Cash and cash equivalents, beginning of period | 957 | 6,571 |
Cash and cash equivalents, end of period | 2,493 | 5,936 |
Supplemental disclosures of cash flow information: | ||
Change in accrued capital expenditures | 7,158 | 738 |
Asset retirement obligation | 195 | |
Earnout liability | 221 | |
Cash paid during the period for interest | $ 1,473 | $ 859 |
Condensed Consolidated Stateme6
Condensed Consolidated Statements of Changes in Partners’ Capital - USD ($) $ in Thousands | Class A Preferred | Common Units | Total |
Partner's Capital (Deficit) at Dec. 31, 2015 | $ 17,112 | $ (45,285) | $ (28,173) |
Partner's Capital (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 (loss) | 19,231 | 19,231 | |
Partner's Capital (Deficit) at Dec. 31, 2016 | $ 16,744 | 16,744 | |
Partner's Capital (Deficit) (in shares) at Dec. 31, 2016 | 13,447,749 | ||
Unit-based compensation programs | $ 540 | 540 | |
Unit-based compensation programs (in shares) | 171,231 | ||
Issuance of common units, net of offering costs | $ 3,951 | 3,951 | |
Issuance of common units, net of offering costs (in shares) | 325,487 | ||
Cash distributions to common unit holders | $ (5,796) | (5,796) | |
Common units issued as Class B Preferred distributions | $ 2,625 | 2,625 | |
Common units issued as Class B Preferred distributions (in shares) | 208,594 | ||
Distributions - Class B preferred units | $ (10,029) | (10,029) | |
Net income (loss) | (7,659) | (7,659) | |
Partner's Capital (Deficit) at Mar. 31, 2017 | $ 376 | $ 376 | |
Partner's Capital (Deficit) (in shares) at Mar. 31, 2017 | 14,153,061 |
Condensed Consolidated Stateme7
Condensed Consolidated Statements of Changes in Partners’ Capital (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2017 | Dec. 31, 2016 |
Condensed Consolidated Statements of Changes in Partners’ Capital | ||
Offering costs | $ 0.1 | $ 5.3 |
Organization And Business
Organization And Business | 3 Months Ended |
Mar. 31, 2017 | |
Organization And Business | |
Organization And Business | 1. ORGANIZATION AND BUSINESS Organization Sanchez Production Partners LP, a Delaware limited partnership (“SPP,” “we,” “us,” “our” or the “Partnership”), is a publicly-traded limited partnership focused on the acquisition, development, ownership and operation of midstream and other production assets in North America. SPP completed its initial public offering on November 20, 2006, as Constellation Energy Partners LLC (“CEP” or the “Company”). We have entered into a shared services agreement (the “Services Agreement”) with Manager, 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 March 6, 2015, the Company’s unitholders approved the conversion of Sanchez Production Partners LLC to a Delaware limited partnership and the name was changed to Sanchez Production Partners LP. Manager owns the general partner of SPP and all of SPP’s incentive distribution rights. Our common units are currently listed on the NYSE MKT under the symbol “SPP.” Historically, our operations have consisted of the production of proved reserves located in the Cherokee Basin in Oklahoma and Kansas, the Woodford Shale in the Arkoma Basin in Oklahoma, the Central Kansas Uplift in Kansas, the Eagle Ford Shale in South Texas and in other areas of Texas and Louisiana. In October 2015, we consummated the acquisition of midstream assets in the Eagle Ford Shale from Sanchez Energy and entered into a 15-year gathering and processing agreement with Sanchez Energy. We also commenced a process to sell our oil and natural gas properties in the Mid-Continent region. In July 2016, we sold a portion of our oil and natural gas properties in the Mid-Continent region and acquired a 50% equity interest in Carnero Gathering. In November 2016, we completed a public offering of approximately 6,745,107 common units (which includes exercise of the underwriters’ option to purchase 194,305 common units) for net proceeds of approximately $69.7 million, after deducting customary offering expenses. Concurrent with the public offering, we completed a private placement of 2,272,727 common units representing limited partner interests for net proceeds of approximately $25.0 million. The combined proceeds were used to close the acquisition of a 50% equity interest in Carnero Processing, as well as acquire working interests in 23 producing Eagle Ford Shale wellbores located in Dimmit and Zavala counties in South Texas and escalating working interests in an additional 11 producing wellbores in the Palmetto Field in Gonzales, Texas. |
Basis Of Presentation And Summa
Basis Of Presentation And Summary Of Significant Accounting Policies | 3 Months Ended |
Mar. 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 These unaudited condensed consolidated financial statements include the accounts of SPP 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 includes the Western Catarina gathering system. Our management evaluates performance based on these two business segments. These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of the Partnership and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2016, which was filed with the SEC on March 28, 2017. Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. In 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 will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are 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 will be 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 March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The adoption of this guidance did not have a material impact on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, 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 not early adopt the standard although early adoption is permitted. The Partnership is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Partnership is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. Use of Estimates The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. |
Acquisitions and Divestitures
Acquisitions and Divestitures | 3 Months Ended |
Mar. 31, 2017 | |
Acquisitions and Divestitures | |
Acquisitions and Divestitures | 3. ACQUISITIONS AND DIVESTITURES Our acquisitions are accounted for under the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations.” A business combination may result in the recognition of a gain or goodwill based on the measurement of the fair value of the assets acquired at the acquisition date as compared to the fair value of consideration transferred, adjusted for purchase price adjustments. The initial accounting for acquisitions may not be complete and adjustments to provisional amounts, or recognition of additional assets acquired or liabilities assumed, may occur as more detailed analyses are completed and additional information is obtained about the facts and circumstances that existed as of the acquisition dates. The results of operations of the properties acquired in our acquisitions have been included in the condensed consolidated financial statements since the closing dates of the acquisitions. Carnero Processing Acquisition On November 22, 2016, we completed the acquisition of 50% of the outstanding membership interests in Carnero Processing from Sanchez Energy and SN Midstream, LLC (“SN Midstream”), a wholly-owned subsidiary of Sanchez Energy, for aggregate cash consideration of approximately $55.5 million and the assumption of approximately $24.5 million of remaining capital contribution commitments (the “Carnero Processing Transaction”). The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Processing, with the other 50% of the membership interests being owned by TPL SouthTex Processing Company LP, an affiliate of Targa Resources Group (“Targa”). Carnero Processing is constructing a cryogenic gas processing facility located in La Salle County, Texas. See Note 10. “Investments” for additional information relating to the Carnero Processing Transaction. The Partnership made capital contributions to Carnero Processing totaling $12.5 million between November 22, 2016 and March 31, 2017. Production Acquisition On November 22, 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 approximately $24.2 million after approximately $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 which, for certain properties, escalate on January 1 for 2017 and 2018, at which point, SPP’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 On July 5, 2016, the Partnership purchased from Sanchez Energy and SN Midstream 50% of the issued and outstanding membership interests in Carnero Gathering for total consideration of approximately $37.0 million, plus the assumption of approximately $7.4 million of remaining capital contribution commitments (the “Carnero Gathering Transaction”). In addition, the Partnership is required to pay an earnout based on gas received at the delivery points from SN Catarina, LLC, a wholly-owned subsidiary of Sanchez Energy (“SN Catarina”), and other producers. The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Gathering, with the other 50% of the membership interests being owned by TPL SouthTex Processing Company LP, an affiliate of Targa. Carnero Gathering operates a gas gathering pipeline from an interconnection in Webb County, Texas to interconnection(s) with a gas processing facility being developed and constructed by Carnero Processing. See Note 10. “Investments” for additional information relating to the Carnero Gathering Transaction. The Partnership made capital contributions to Carnero Gathering totaling $3.5 million between July 5, 2016 and March 31, 2017. Mid-Continent Divestiture On June 15, 2016, certain wholly-owned subsidiaries of the Partnership entered into an agreement with Gateway Resources U.S.A., Inc. (“Gateway”) to sell substantially all of the Partnership’s 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, subject to adjustment for title and environmental defects, effective as of August 1, 2016 (the “Effective Time”). In addition, Gateway 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 Partnership closed the sale of this transaction on July 15, 2016. The Partnership recorded a $0.2 million loss related to an intangible asset balance comprised of marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture . |
Fair Value Measurements
Fair Value Measurements | 3 Months Ended |
Mar. 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 March 31, 2017 (in thousands): Fair Value Measurements at March 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Fair Value at (Level 1) (Level 2) (Level 3) March 31, 2017 Derivative assets (net) $ — $ 10,915 $ — $ 10,915 Total net assets $ — $ 10,915 $ — $ 10,915 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 Fair Value at (Level 1) (Level 2) (Level 3) December 31, 2016 Derivative assets (net) $ — $ 6,436 $ — $ 6,436 Total net assets $ — $ 6,436 $ — $ 6,436 As of March 31, 2017 and December 31, 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 8, “Asset Retirement Obligation.” The following table summarizes the non-recurring fair value measurements of our assets as of March 31, 2017 (in thousands): Fair Value Measurements at March 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 quarter ended March 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties 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 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) During 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 March 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 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. The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded derivative classified as Level 3 in the fair value hierarchy for the year ended Dec ember 31 , 2016 (in thousands): Year ended December 31, 2016 Beginning balance $ (193,077) Gain on embedded derivative 47,794 Transfer to mezzanine equity 145,283 Ending balance $ — Loss included in earnings related to derivatives still held as of December 31, 2016 $ — |
Derivative And Financial Instru
Derivative And Financial Instruments | 3 Months Ended |
Mar. 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 condensed consolidated balance sheets at fair value as either short-term or long-term assets or liabilities based on their anticipated settlement date. We will net derivative assets and liabilities for counterparties where we have a legal right of offset. Changes in the derivatives’ fair values are recognized currently in earnings unless specific hedge accounting criteria are met. We have not elected to designate any of our current derivative contracts as hedges; however, changes in the fair value of all of our derivative instruments are recognized in earnings and included in natural gas sales and oil sales in the condensed consolidated statements of operations. As of March 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: Fixed Price Basis Swaps–West Texas Intermediate (WTI) March 31, June 30, September 30, December 31, Total Volume Average Volume Average Volume Average Volume Average Volume Average (Bbls) Price (Bbls) Price (Bbls) Price (Bbls) Price (Bbls) Price 2017 — $ — 94,005 $ 61.25 87,304 $ 61.42 81,702 $ 61.55 263,011 $ 61.40 2018 88,854 $ 60.82 83,976 $ 60.90 79,683 $ 60.96 75,864 $ 61.02 328,377 $ 60.92 2019 78,667 $ 61.48 75,326 $ 61.53 72,279 $ 61.57 69,480 $ 61.61 295,752 $ 61.54 2020 66,914 $ 53.50 64,477 $ 53.50 62,251 $ 53.50 60,224 $ 53.50 253,866 $ 53.50 1,141,006 Fixed Price Swaps—NYMEX (Henry Hub) March 31, June 30, September 30, December 31, Total Volume Average Volume Average Volume Average Volume Average Volume Average (MMBtu) Price (MMBtu) Price (MMBtu) Price (MMBtu) Price (MMBtu) Price 2017 — $ — 287,439 $ 5.45 271,368 $ 5.45 257,234 $ 5.45 816,041 $ 5.45 2018 260,841 $ 3.18 248,018 $ 3.18 235,810 $ 3.18 225,208 $ 3.18 969,877 $ 3.18 2019 224,303 $ 3.10 214,186 $ 3.10 205,533 $ 3.10 197,455 $ 3.10 841,477 $ 3.10 2020 188,696 $ 2.85 176,946 $ 2.85 170,637 $ 2.85 164,747 $ 2.85 701,026 $ 2.85 3,328,421 The following table sets forth a reconciliation of the changes in fair value of the Partnership’s commodity derivatives for the three months ended March 31, 2017 and the year ended December 31, 2016 (in thousands): March 31, December 31, 2017 2016 Beginning fair value of commodity derivatives $ 6,435 $ 31,018 Net gains (losses) on crude oil derivatives 5,495 (8,355) Net gains on natural gas derivatives 560 1,116 Net settlements on derivative contracts: Crude oil (929) (13,622) Natural gas (646) (6,919) Net premiums on derivative contracts — 3,197 Ending fair value of commodity derivatives $ 10,915 $ 6,435 The effect of derivative instruments on our condensed consolidated statements of operations was as follows (in thousands): Three Months Ended March 31, Derivative Type Location of Gain in Income 2017 2016 Commodity – Oil Hedges Oil sales $ 5,495 $ 2,692 Commodity – Gas Hedges Natural gas sales 560 1,298 $ 6,055 $ 3,990 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. As of March 31, 2017 and December 31, 2016, the impact of non-performance credit risk on the valuation of our derivative instruments was not significant. 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. 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. The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2016 (in thousands): Year ended December 31, 2016 Beginning fair value of embedded derivative $ (193,077) Gain on embedded derivative 47,794 Transfer to mezzanine equity 145,283 Ending fair value of embedded derivative $ — |
Long-Term Debt
Long-Term Debt | 3 Months Ended |
Mar. 31, 2017 | |
Long-Term Debt | |
Long-Term Debt | 6. LONG-TERM DEBT We have entered into a credit facility with Royal Bank of Canada, as administrative agent and collateral agent, and the lenders party thereto (the “Credit Agreement”). The Credit Agreement provides a maximum commitment of $500.0 million and has a maturity date of March 31, 2020. Borrowings under the Credit Agreement are secured by various mortgages of oil and natural gas properties that we own as well as various security and pledge agreements among the Partnership 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 properties. Borrowings under the Credit Agreement are available for direct investment in oil and natural gas properties, acquisitions, and working capital and general business purposes. The Credit Agreement has a sub-limit of $15.0 million which may be used for the issuance of letters of credit. The initial borrowing base under the Credit Agreement was $200.0 million. The borrowing base for the credit available for the upstream oil and natural 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 multiplied by 4.5. Outstanding borrowings in excess of our borrowing base must be repaid or we must pledge other oil and natural gas properties as additional collateral. We may elect to pay any borrowing base deficiency in three equal monthly installments such that the deficiency is eliminated in a period of three months. Any increase in our borrowing base must be approved by all of the lenders. As of March 31, 2017, the borrowing base under the Credit Agreement was $215.1 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 March 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 for any violation of a financial covenant from the lenders, but there is no assurance that such waivers would be granted. Debt Issuance Costs As of March 31, 2017 and December 31, 2016 , our unamortized debt issuance costs were $1. 6 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 three months ended March 31, 2017 and 2016 were $0.1 million and $0.1 million, respectively. |
Oil And Natural Gas Properties
Oil And Natural Gas Properties And Related Equipment | 3 Months Ended |
Mar. 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): March 31, December 31, 2017 2016 Gathering and transportation assets Midstream assets $ 165,111 $ 152,209 Less: Accumulated depreciation and amortization (20,555) (15,020) Total gathering and transportation assets $ 144,556 $ 137,189 Oil and natural gas properties consisted of the following (in thousands): March 31, December 31, 2017 2016 Oil and natural gas properties and related equipment Property costs Proved property $ 757,278 $ 758,366 Unproved property 46 46 Land 501 501 Total property costs 757,825 758,913 Materials and supplies 1,056 1,056 Total 758,881 759,969 Less: Accumulated depreciation, depletion, amortization and impairments (682,248) (674,338) Oil and natural gas properties and equipment, net $ 76,633 $ 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. Under this method of accounting, costs relating to the development of proved areas are capitalized when incurred. 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): Three Months Ended March 31, 2017 2016 Depreciation, depletion and amortization of oil and natural gas-related assets $ 3,234 $ 2,020 Depreciation, depletion and amortization of gathering and transportation related assets 5,535 1,710 Amortization of intangible assets 3,412 3,458 Total Depreciation, depletion and amortization 12,181 7,188 Asset impairments 4,688 1,309 Total $ 16,869 $ 8,497 Impairment of Oil and Natural Gas Properties and Other Non-Current Assets. Oil and natural gas properties are reviewed for impairment on a field-by-field basis when facts and circumstances indicate that their carrying value may not be recoverable. We assess impairment of capitalized costs of proved oil and natural gas properties by comparing net capitalized costs to estimated undiscounted future net cash flows using expected prices. If net capitalized costs exceed estimated undiscounted future net cash flows, the measurement of impairment is based on estimated fair value, which would consider estimated future discounted cash flows. The cash flow estimates are based upon reserve reports using future expected oil and natural gas prices adjusted for basis differentials. Other significant inputs, besides reserves, used to determine the fair values of proved properties include estimates of: (i) future operating and development costs; (ii) future commodity prices; and (iii) a market-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Partnership’s management at the time of the valuation and are the most sensitive and subject to change. Cash flow estimates for impairment testing exclude derivative instruments. For the three months ended March 31, 2017, we recorded non-cash charges of $4.7 million, to impair certain of our producing oil and natural gas properties in Texas acquired as part of the Production Acquisition. For the three months ended March 31, 2016, we recorded non-cash charges of $1.3 million, to impair our producing oil and natural gas properties in Texas and Louisiana acquired prior to the Eagle Ford acquisition . Asset Retirement Obligation. As described in Note 8, 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 three months ended March 31, 2017 or 2016. |
Asset Retirement Obligation
Asset Retirement Obligation | 3 Months Ended |
Mar. 31, 2017 | |
Asset Retirement Obligation | |
Asset Retirement Obligation | 8. ASSET RETIREMENT OBLIGATION We recognize the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred if a reasonable estimate of fair value can be made. Each period, we accrete the ARO to its then present value. The associated asset retirement cost (“ARC”) is capitalized as part of the carrying amount of our oil and natural gas properties, equipment and facilities or gathering and transportation assets. Subsequently, the ARC is depreciated using the units-of-production method for production assets and the straight-line method for midstream assets. The AROs recorded by us relate to the plugging and abandonment of oil and natural gas wells, and decommissioning of oil and natural gas gathering and other facilities. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions result in adjustments to the recorded fair value of the existing ARO, a corresponding adjustment is made to the ARC capitalized as part of the oil and natural gas property balance. The following table is a reconciliation of the ARO (in thousands): March 31, December 31, 2017 2016 Asset retirement obligation, beginning balance $ 13,579 $ 20,364 Liabilities added from acquisitions 195 912 Sold — (6,291) Revisions to cost estimates — (2,399) Settlements — (134) Accretion expense 258 1,127 Asset retirement obligation, ending balance $ 14,032 $ 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 and other facilities reduce the liability for AROs. During the three months ended March 31, 2017 and the year ended December 31, 2016, there were no significant expenditures for abandonments and as of March 31, 2017 and December 31, 2016, there were no assets legally restricted for purposes of settling existing AROs. During 2016, obligations were sold as part of the Mid-Continent Divestiture that significantly lowered the Partnership’s future abandonment expenses. |
Intangible Assets
Intangible Assets | 3 Months Ended |
Mar. 31, 2017 | |
Intangible Assets | |
Intangible Assets | 9. INTANGIBLE ASSETS Intangible assets are comprised of customer and marketing contracts. The intangible assets balance includes $182.3 million related to the customer contract with Sanchez Energy that was entered into as part of the acquisition of Western Catarina Midstream Acquisition. Pursuant to the 15-year agreement, Sanchez Energy tenders all of its crude petroleum, natural gas and other hydrocarbon-based product volumes on 35,000 dedicated acres in the Western Catarina of the Eagle Ford Shale in Texas for processing and transportation through the gathering system, 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. During 2016, the intangible asset balance was reduced by $0.2 million due to marketing contracts from the 2007 Newfield acquisition which were included in the Mid-Continent Divestiture. Amortization expense for the three months ended March 31, 2017 and 2016 was $3.4 million and $3.5 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of March 31, 2017 and December 31, 2016 are detailed below (in thousands): March 31, December 31, 2017 2016 Beginning balance $ 185,766 $ 199,741 Disposals — (219) Amortization (3,412) (13,756) Ending balance $ 182,354 $ 185,766 |
Investments
Investments | 3 Months Ended |
Mar. 31, 2017 | |
Investments | |
Investments | 10. INVESTMENTS On July 5, 2016, the Partnership purchased a 50% membership interest in Carnero Gathering from SN Midstream 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 membership interests acquired constitute 50% of the outstanding membership interests in Carnero Gathering. The remaining 50% membership interests of Carnero Gathering are owned by an affiliate of Targa. During the three months ended March 31, 2017, the Partnership made approximately $0.1 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $26.0 million in the Carnero Gathering joint venture. 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 the contract term of fifteen years and decrease earnings from Carnero Gathering. As part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered by other producers and processing by Carnero Processing, which is anticipated to begin in the second quarter of 2017. This earnout is considered as contingent consideration and its estimated fair value of $4.0 million was recorded on the balance sheet as a deferred liability as of March 31, 2017. As of March 31, 2017, the Partnership had paid approximately $41.0 million for the Carnero Gathering Transaction related to the initial purchase price, acquisition costs and contributed capital to date. 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 Condensed Consolidated Balance Sheet. The Partnership recorded earnings of approximately $1.4 million in equity investments from Carnero Gathering, which was offset by approximately $0.2 million related to the amortization of the contractual customer intangible asset for the three months ended March 31, 2017. We have included these equity method earnings in the “Earnings from equity investments” line within the Condensed Consolidated Statements of Operations. Cash distributions of $2.0 million were received during the three months ended March 31, 2017. On November 22, 2016, the Partnership purchased a 50% membership interest in Carnero Processing from SN Midstream 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 remaining 50% membership interests of Carnero Processing are owned by an affiliate of Targa. During the three months ended March 31, 2017, the Partnership made $2.0 million of capital contributions to the joint venture. Prior to the sale, SN Midstream had invested approximately $48.0 million in the Carnero Processing joint venture. As of March 31, 2017, the Partnership had paid approximately $68.5 million for the Carnero Processing transaction related to the initial payment, acquisition costs 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 expenses of approximately $0.5 million in the “Earnings from equity investments” line within our consolidated statements of operations for the three months ended March 31, 2017. |
Commitments And Contingencies
Commitments And Contingencies | 3 Months Ended |
Mar. 31, 2017 | |
Commitments And Contingencies | |
Commitments And Contingencies | 11. COMMITMENTS AND CONTINGENCIES As part of the Carnero Gathering Transaction, the Partnership is required to pay SN Midstream a monthly earnout based upon gas received at Carnero Gathering’s receipt points from SN Catarina and gas delivered and processed at Carnero Processing by other producers which is anticipated to begin in the second quarter of 2017. This earnout has an approximate value of $4.0 million and was recorded on the balance sheet as a deferred liability as of March 31, 2017. We did not have any other material commitments and contingencies as of March 31, 2017. |
Related Party Transactions
Related Party Transactions | 3 Months Ended |
Mar. 31, 2017 | |
Related Party Transactions | |
Related Party Transactions | 12. RELATED PARTY TRANSACTIONS 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, professionals, 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 additional one year terms unless either Manager or the Partnership provides notice of termination to the other with at least 180 days’ notice. During the three months ended March 31, 2017, we expensed approximately $2.0 million to Manager pursuant to the Services Agreement. Manager utilizes Sanchez Oil & Gas Corporation (“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. The Partnership has entered into a Firm Gathering and Processing Agreement with Sanchez Energy for an initial term of 15 years under which production from approximately 35,000 acres in Dimmit County and Webb County, Texas is dedicated for gathering by Catarina Midstream, LLC. In addition, for the first five years of the Gathering Agreement, SN Catarina will be required to meet a minimum quarterly volume delivery commitment of 10,200 barrels per day of crude oil and condensate and 142,000 Mcf per day of natural gas, subject to certain adjustments. As of March 31, 2017 and December 31, 2016, the Partnership had a net receivable from related parties of $3.0 million and $6.0 million, respectively, which are included in “Accounts receivable – related entities” in the condensed consolidated balance sheets. As of March 31, 2017 and December 31, 2016, the Partnership also had a net payable to related parties of $13.3 million and $7.0 million, respectively. The net receivables/payable as of March 31, 2017 and 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, development of gathering and transportation assets and obligations for general and administrative costs. In July 2016, the Partnership entered into an agreement with Sanchez Energy and SN Midstream to purchase 50% of the issued and outstanding membership interests in Carnero Gathering for total consideration of approximately $37.0 million, plus the assumption of approximately $7.4 million of remaining capital contribution commitments. In addition, the Partnership is required to pay an earnout based on gas received at the delivery points from SN Catarina and other producers. The membership interests acquired constitute 50% of the outstanding membership interests in Carnero Gathering, with the other 50% of the membership interests being owned by TPL SouthTex Processing Company LP. Carnero Gathering operates a gas gathering pipeline from an interconnection in Webb County, Texas to interconnection(s) with a gas processing facility being developed and constructed by Carnero Processing. The Partnership made capital contributions to Carnero Gathering totaling $3.5 million between July 5, 2016 and March 31, 2017. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures .” In October 2016, the Partnership entered into a Purchase and Sale Agreement (the “Lease Option Purchase Agreement”) with Sanchez Energy and SN Terminal, LLC (the “SNT”), pursuant to which SNT granted and conveyed to the Partnership an option to acquire a ground lease (the “Lease Option”) to which SNT is a party for a tract of land leased from the Calhoun Port Authority in Point Comfort, Texas. In addition, if Sanchez Energy or any of its affiliates have entered into an option to engage in the construction of or participation in a Project (as defined below) and/or receive the benefit of an acreage dedication from an affiliate of the Sanchez Energy relating to a Project, then such option and/or acreage dedication will also be assigned to us, if we exercise the Lease Option. The Partnership will pay SNT $1.00 if the Lease Option is exercised, along with $250,000 if the Partnership or any of its affiliates elects to construct, own or operate a marine crude storage terminal on or within five miles of the Point Comfort lease or participates as an investor in the same, within five miles thereof (a “Project”). 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 (the “Purchaser”), 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. See further discussion of the transaction in Note 3, “Acquisitions and Divestitures .” In November 2016, the Partnership consummated a Purchase and Sale Agreement with Sanchez Energy and SN Midstream to purchase all of SN Midstream’s issued and outstanding membership interests in Carnero Processing for approximately $55.5 million plus the assumption of approximately $24.5 million of remaining capital commitments. 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 interest 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. See further discussion of the transactions in Note 3, “Acquisitions and Divestitures .” |
Unit-Based Compensation
Unit-Based Compensation | 3 Months Ended |
Mar. 31, 2017 | |
Unit-Based Compensation | |
Unit-Based Compensation | 13. UNIT-BASED COMPENSATION The Sanchez Production Partners LP Long-Term Incentive Plan (the “LTIP”) allows for restricted unit grants. Restricted unit activity under the LTIP during the period is presented in the following table: Weighted Average Number of Grant Date Restricted Fair Value Units Per Unit Outstanding at December 31, 2016 219,144 $ 14.22 Granted 171,231 14.60 Outstanding at March 31, 2017 390,375 $ 14.39 During the three months ended March 31, 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. 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 March 31, 2017, 1,523,074 common units remain available for future issuance to participants under the LTIP. |
Distributions To Unitholders
Distributions To Unitholders | 3 Months Ended |
Mar. 31, 2017 | |
Distributions To Unitholders | |
Distributions To Unitholders | 14. DISTRIBUTIONS TO UNITHOLDERS The table below reflects the payment of cash distributions on common units related to the three months ended March 31, 2017 and the year ended December 31, 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 $ May 10, 2017 May 22, 2017 May 31, 2017 The table below reflects the payment of distributions on Class B preferred units related to the three months ended March 31, 2017 and the year ended December 31, 2016. 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 (b) $ May 10, 2017 May 22, 2017 May 31, 2017 (a) 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 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. (b) 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 declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017. |
Partners' Capital
Partners' Capital | 3 Months Ended |
Mar. 31, 2017 | |
Partners' Capital | |
Partners' Capital | 15. PARTNERS’ CAPITAL Outstanding Units As of March 31, 2017, we had 31,000,887 Class B Preferred Units outstanding, and 14,153,061 common units outstanding. Common Unit Issuances In March 2016, the Partnership converted all remaining outstanding Class A Preferred Units into common units of the Partnership on a one for one basis, adjusted for the 1-for-10 unit split in August 2015. 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 B Preferred Unit Offering On October 14, 2015, pursuant to that certain Class B Preferred Unit Purchase Agreement dated September 25, 2015 between the Partnership and Stonepeak Catarina Holdings LLC (“Stonepeak”), the Partnership sold and Stonepeak purchased 19,444,445 of the Partnership’s newly created Class B Preferred Units (the “Class B Preferred Units”) in a privately negotiated transaction for an aggregate cash purchase price of $18.00 per Class B Preferred Unit, which resulted in gross proceeds to the Partnership of approximately $350.0 million. The Partnership used the net proceeds to pay a portion of the consideration for the acquisition of the Western Catarina gathering system, 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, commencing with the quarter ended on December 31, 2015, the Class B Preferred Units received 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). In the event the Partnership did not raise at least $75.0 million through the issuance of additional common units prior to September 30, 2016 (with the conversion of the Class A Preferred Units of the Partnership counting toward such amount), the cash portion of the distribution rate was to have increased by 4.0% per annum until consummation of such issuance, as applicable. The Partnership did not raise at least $75.0 million through the issuance of additional common units prior to September 30, 2016 and an aggregate 14% per annum cash distribution was paid related to the three months ended September 30, 2016. As a result of the common unit issuance in November 2016 the $75.0 million common unit issuance threshold was met and the increased distribution rate was not paid for the three months ended December 31, 2016. 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): March 31, December 31, 2017 2016 Mezzanine equity beginning balance $ 342,991 $ 172,111 Discount — (87) Amortization of discount 404 23,477 Distributions 9,625 39,375 Distributions paid (9,625) (37,168) Transfer embedded derivative to Class B — 145,283 Total mezzanine equity $ 343,395 $ 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) based on provisions of the partnership agreement, divided by the weighted average number of common units outstanding. The two-class method dictates that net income (loss) for a period be reduced by the amount of distributions and that any residual amount representing undistributed net income (loss) be allocated to common unitholders and other participating unitholders to the extent that each unit may share in net income (loss) as if all of the net income for the period had been distributed in accordance with the partnership agreement. Unit-based awards granted but unvested are eligible to receive distributions. The underlying unvested restricted unit awards are considered participating securities for purposes of determining net income (loss) per unit. Undistributed income (loss) is allocated to participating securities based on the proportional relationship of the weighted average number of common units and unit-based awards outstanding. Undistributed losses (including those resulting from distributions in excess of net income) are allocated to common units based on provisions of the partnership agreement. Undistributed losses are not allocated to unvested restricted unit awards as they do not participate in net losses. Distributions declared and paid in the period are treated as distributed earnings in the computation of earnings per common unit even though cash distributions are not necessarily derived from current or prior period earnings. Our general partner does not have an economic interest in the Partnership and, therefore, does not participate in the Partnership’s net income. The following table presents the weighted average basic and diluted units outstanding for the periods indicated: Three Months Ended March 31, 2017 2016 Common units - Basic and Diluted 13,400,138 2,743,419 Weighted Common units - Basic and Diluted 13,400,138 2,743,419 At March 31, 2017, we had 390,375 common units that were restricted unvested common units granted and outstanding. 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 three months ended March 31, 2017 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (17,688) $ (17,688) Basic and diluted loss per unit $ (1.32) The following table presents our basic and diluted loss per unit for the three months ended March 31, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (10,739) $ (10,739) Basic and diluted loss per unit $ (3.91) |
Reporting Segments
Reporting Segments | 3 Months Ended |
Mar. 31, 2017 | |
Reporting Segments | |
Reporting Segments | 16. REPORTING SEGMENTS “Midstream” and “Production” best describe the operating segments of the businesses that we separately report. The factors used to identify these reporting segments are based on the nature of the operations that are undertaken by each segment. The Midstream segment operates the gathering, processing and transportation of crude oil, natural gas and NGLs. The Production segment operates to produce crude oil and natural gas. These segments are broadly understood across the petroleum and petrochemical industries. These functions have been defined as the operating segments of the Partnership because they are the segments (1) that engage in business activities from which revenues are earned and expenses are incurred; (2) whose operating results are regularly reviewed by the Partnership’s chief operating decision maker to make decisions about resources to be allocated to the segment and to assess its performance; and (3) for which discrete financial information is available. Operating segments are evaluated for their contribution to the Partnership’s consolidated results based on operating income, which is defined as segment operating revenues less expenses. The following tables set forth our segment information for the periods indicated (in thousands): Three Months Ended March 31, 2017 Production Midstream Total Operating revenues Natural gas sales $ 2,779 $ — $ 2,779 Oil sales 11,350 — 11,350 Natural gas liquids sales 467 — 467 Gathering and transportation sales — 11,211 11,211 Total operating revenues 14,596 11,211 25,807 Operating expenses: Lease operating expenses 4,724 259 4,983 Transportation operating expenses — 3,296 3,296 Cost of sales 37 — 37 Production taxes 473 — 473 General and administrative 4,104 1,505 5,609 Unit-based compensation expense 540 — 540 Depreciation, depletion and amortization 3,281 8,900 12,181 Asset impairments 4,688 — 4,688 Accretion expense 192 66 258 Total operating expenses 18,039 14,026 32,065 Operating loss $ (3,443) $ (2,815) $ (6,258) Three Months Ended March 31, 2016 Production Midstream Total Operating revenues Natural gas sales $ 3,675 $ — $ 3,675 Oil sales 5,343 — 5,343 Natural gas liquids sales 276 — 276 Gathering and transportation sales — 13,875 13,875 Total operating revenues 9,294 13,875 23,169 Operating expenses: Lease operating expenses 4,875 98 4,973 Transportation operating expenses — 3,054 3,054 Cost of sales 130 — 130 Production taxes 221 — 221 General and administrative 4,434 1,285 5,719 Unit-based compensation expense 438 — 438 Depreciation, depletion and amortization 2,114 5,074 7,188 Asset impairments 1,309 — 1,309 Accretion expense 254 61 315 Total operating expenses 13,775 9,572 23,347 Operating income (loss) $ (4,481) $ 4,303 $ (178) The following table summarizes the total assets by operating segment as of March 31, 2017 and December 31, 2016 (in thousands): March 31, December 31, 2017 2016 Segment Assets Production $ 201,991 $ 207,219 Midstream 333,986 332,486 Total assets $ 535,977 $ 539,705 |
Variable Interest Entities
Variable Interest Entities | 3 Months Ended |
Mar. 31, 2017 | |
Variable Interest Entities | |
Variable Interest Entities | 17. VARIABLE INTEREST ENTITIES As noted above in Note 10, “Investments,” the Partnership purchased a 50% membership interest in Carnero Gathering from SN Midstream 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 $47.3 million. As of March 31, 2017, the Partnership had invested approximately $41.0 million in Carnero Gathering. As of March 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 10, “Investments,” the Partnership purchased a 50% membership interest in Carnero Processing from SN Midstream 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. 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 $79.6 million. As of March 31, 2017, the Partnership had invested approximately $68.5 million in Carnero Processing. As of March 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 March 31, 2017 and December 31, 2016 (in thousands): March 31, December 31, 2017 2016 Capital investments $ 109,441 $ 107,320 Earnings in equity investments 2,919 2,301 Distributions received (4,950) (2,950) Estimated earnout accrued 4,049 4,270 Equity in equity investments $ 111,459 $ 110,941 March 31, December 31, 2017 2016 Equity in equity investments $ 111,459 $ 110,941 Guarantees of capital investments 15,462 17,584 Maximum exposure to loss $ 126,921 $ 128,525 |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2017 | |
Subsequent Events | |
Subsequent Events | 18. SUBSEQUENT EVENTS On April 17, 2017, the Partnership received notification that pursuant to the terms of its Credit Agreement its lenders have completed both their quarterly review of the midstream component and their semi-annual review of the RBL component of the Partnership’s borrowing base. Based on this review, the midstream component was set at $168.1 million and the RBL component was set at $47.5 million, resulting in a total borrowing base of $215.6 million. The elected commitment amount remained unchanged at $200.0 million. On May 10, 2017, we entered into a purchase and sale agreement to sell all of the Partnership’s equity interests in the entities that own our remaining operated oil and natural gas wells, leases and other associated assets and interests in Oklahoma for cash consideration of $5.5 million, subject to adjustment for title and environmental defects. The buyer has agreed to assume 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 transaction is anticipated to close by July 15, 2017, subject to customary closing conditions. We do not expect to record a loss from the sale at closing. On May 10, 2017, the board of directors of the general partner of the Partnership declared a first quarter 2017 cash distribution on its common units of $0.4375 per unit ($1.75 per unit annualized) payable on May 31, 2017 to holders of record on May 22, 2017. The Partnership also declared a first quarter distribution on the Class B preferred units and elected to pay the distribution in part cash and in part common units. Accordingly, the Partnership declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017. |
Basis Of Presentation And Sum26
Basis Of Presentation And Summary Of Significant Accounting Policies (Policies) | 3 Months Ended |
Mar. 31, 2017 | |
Basis Of Presentation And Summary Of Significant Accounting Policies | |
Basis of Presentation | Basis of Presentation These unaudited condensed consolidated financial statements include the accounts of SPP 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 includes the Western Catarina gathering system. Our management evaluates performance based on these two business segments. These unaudited condensed consolidated financial statements have been prepared pursuant to the rules of the Securities and Exchange Commission (“SEC”). Certain information and footnote disclosures, normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”), have been condensed or omitted pursuant to those rules and regulations. We believe that the disclosures made are adequate to make the information presented not misleading. In the opinion of management, all adjustments, consisting only of normal recurring adjustments, necessary to fairly state the financial position, results of operations and cash flows with respect to the interim condensed consolidated financial statements have been included. The results of operations for the interim periods are not necessarily indicative of the results for the entire year. These unaudited condensed consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto of the Partnership and our subsidiaries included in our Annual Report on Form 10-K for the year ended December 31, 2016, which was filed with the SEC on March 28, 2017. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements From time to time, new accounting pronouncements are issued by the Financial Accounting Standards Board (“FASB”), which are adopted by us as of the specified effective date. Unless otherwise discussed, management believes that the impact of recently issued standards, which are not effective, will not have a material impact on our condensed consolidated financial statements upon adoption. In 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 will apply to all reporting entities within the scope of the affected accounting guidance. Most amendments are 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 will be 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 March 2016, the FASB issued ASU No. 2016-09 “Improvements to Employee Share-Based Payment Accounting,” effective for annual and interim periods for public companies beginning after December 15, 2016, with a cumulative-effect and prospective approach to be used for implementation. ASU 2016-09 changes several aspects of the accounting for share-based payment award transactions including accounting for income taxes, classification of excess tax benefits on the statement of cash flows, forfeitures, minimum statutory tax withholding requirements and classification of employee taxes paid on the statement of cash flows when an employer withholds shares for tax-withholding purposes. The adoption of this guidance did not have a material impact on our consolidated financial statements. In February 2016, the FASB issued ASU No. 2016-02 “Leases (Topic 842),” effective for annual and interim periods for public companies beginning after December 15, 2018, 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 not early adopt the standard although early adoption is permitted. The Partnership is currently evaluating whether to apply the retrospective approach or modified retrospective approach with the cumulative effect recognized as of the date of initial application. The Partnership is currently evaluating the impact the standard is expected to have on its consolidated financial statements by evaluating current revenue streams and evaluating contracts under the revised standards. |
Use of Estimates | Use of Estimates The condensed consolidated financial statements are prepared in conformity with U.S. GAAP, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The most significant estimates pertain to proved oil and natural gas reserves and related cash flow estimates used in the calculation of depletion and impairment of oil and natural gas properties, the fair value of commodity derivative contracts and asset retirement obligations, accrued oil and natural gas revenues and expenses and the allocation of general and administrative expenses. Actual results could differ materially from those estimates. |
Acquisitions and Divestitures (
Acquisitions and Divestitures (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Acquisitions and Divestitures | |
Estimated Values Of Assets Purchased And Liabilities Assumed | 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) | 3 Months Ended |
Mar. 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 March 31, 2017 (in thousands): Fair Value Measurements at March 31, 2017 Active Markets for Observable Identical Assets Inputs Unobservable Inputs Fair Value at (Level 1) (Level 2) (Level 3) March 31, 2017 Derivative assets (net) $ — $ 10,915 $ — $ 10,915 Total net assets $ — $ 10,915 $ — $ 10,915 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 Fair Value at (Level 1) (Level 2) (Level 3) December 31, 2016 Derivative assets (net) $ — $ 6,436 $ — $ 6,436 Total net assets $ — $ 6,436 $ — $ 6,436 |
Non-Recurring Fair Value Measurements Of Assets And Liabilities | The following table summarizes the non-recurring fair value measurements of our assets as of March 31, 2017 (in thousands): Fair Value Measurements at March 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 quarter ended March 31, 2017, we recorded a non-cash impairment charge of $4.7 million to impair our producing oil and natural gas properties 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 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) During 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 Derivative Classified As Level 3 | The following table sets forth a reconciliation of changes in the fair value of the Partnership's embedded derivative classified as Level 3 in the fair value hierarchy for the year ended Dec ember 31 , 2016 (in thousands): Year ended December 31, 2016 Beginning balance $ (193,077) Gain on embedded derivative 47,794 Transfer to mezzanine equity 145,283 Ending balance $ — Loss included in earnings related to derivatives still held as of December 31, 2016 $ — |
Derivative And Financial Inst29
Derivative And Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Derivative And Financial Instruments | |
Summary Of Derivative Contracts In Place | Fixed Price Basis Swaps–West Texas Intermediate (WTI) March 31, June 30, September 30, December 31, Total Volume Average Volume Average Volume Average Volume Average Volume Average (Bbls) Price (Bbls) Price (Bbls) Price (Bbls) Price (Bbls) Price 2017 — $ — 94,005 $ 61.25 87,304 $ 61.42 81,702 $ 61.55 263,011 $ 61.40 2018 88,854 $ 60.82 83,976 $ 60.90 79,683 $ 60.96 75,864 $ 61.02 328,377 $ 60.92 2019 78,667 $ 61.48 75,326 $ 61.53 72,279 $ 61.57 69,480 $ 61.61 295,752 $ 61.54 2020 66,914 $ 53.50 64,477 $ 53.50 62,251 $ 53.50 60,224 $ 53.50 253,866 $ 53.50 1,141,006 Fixed Price Swaps—NYMEX (Henry Hub) March 31, June 30, September 30, December 31, Total Volume Average Volume Average Volume Average Volume Average Volume Average (MMBtu) Price (MMBtu) Price (MMBtu) Price (MMBtu) Price (MMBtu) Price 2017 — $ — 287,439 $ 5.45 271,368 $ 5.45 257,234 $ 5.45 816,041 $ 5.45 2018 260,841 $ 3.18 248,018 $ 3.18 235,810 $ 3.18 225,208 $ 3.18 969,877 $ 3.18 2019 224,303 $ 3.10 214,186 $ 3.10 205,533 $ 3.10 197,455 $ 3.10 841,477 $ 3.10 2020 188,696 $ 2.85 176,946 $ 2.85 170,637 $ 2.85 164,747 $ 2.85 701,026 $ 2.85 3,328,421 |
Schedule Of Change In Commodity Derivatives Fair Value | March 31, December 31, 2017 2016 Beginning fair value of commodity derivatives $ 6,435 $ 31,018 Net gains (losses) on crude oil derivatives 5,495 (8,355) Net gains on natural gas derivatives 560 1,116 Net settlements on derivative contracts: Crude oil (929) (13,622) Natural gas (646) (6,919) Net premiums on derivative contracts — 3,197 Ending fair value of commodity derivatives $ 10,915 $ 6,435 |
Schedule Of Effect Of Derivative Instruments On Consolidated Statements Of Operations | Three Months Ended March 31, Derivative Type Location of Gain in Income 2017 2016 Commodity – Oil Hedges Oil sales $ 5,495 $ 2,692 Commodity – Gas Hedges Natural gas sales 560 1,298 $ 6,055 $ 3,990 |
Reconciliation Of Changes In Fair Value Of Embedded Derivative | The following table sets forth a reconciliation of the changes in fair value of the Partnership’s embedded derivative for the year ended December 31, 2016 (in thousands): Year ended December 31, 2016 Beginning fair value of embedded derivative $ (193,077) Gain on embedded derivative 47,794 Transfer to mezzanine equity 145,283 Ending fair value of embedded derivative $ — |
Oil And Natural Gas Propertie30
Oil And Natural Gas Properties And Related Equipment (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Oil And Natural Gas Properties And Related Equipment. | |
Gathering and Transportation Assets | Gathering and transportation assets consist of the following (in thousands): March 31, December 31, 2017 2016 Gathering and transportation assets Midstream assets $ 165,111 $ 152,209 Less: Accumulated depreciation and amortization (20,555) (15,020) Total gathering and transportation assets $ 144,556 $ 137,189 |
Oil and Natural Gas Properties | March 31, December 31, 2017 2016 Gathering and transportation assets Midstream assets $ 165,111 $ 152,209 Less: Accumulated depreciation and amortization (20,555) (15,020) Total gathering and transportation assets $ 144,556 $ 137,189 Oil and natural gas properties consisted of the following (in thousands): March 31, December 31, 2017 2016 Oil and natural gas properties and related equipment Property costs Proved property $ 757,278 $ 758,366 Unproved property 46 46 Land 501 501 Total property costs 757,825 758,913 Materials and supplies 1,056 1,056 Total 758,881 759,969 Less: Accumulated depreciation, depletion, amortization and impairments (682,248) (674,338) Oil and natural gas properties and equipment, net $ 76,633 $ 85,631 |
Depreciation, Depletion, Amortization and Impairments | Depreciation, depletion, amortization and impairments consisted of the following (in thousands): Three Months Ended March 31, 2017 2016 Depreciation, depletion and amortization of oil and natural gas-related assets $ 3,234 $ 2,020 Depreciation, depletion and amortization of gathering and transportation related assets 5,535 1,710 Amortization of intangible assets 3,412 3,458 Total Depreciation, depletion and amortization 12,181 7,188 Asset impairments 4,688 1,309 Total $ 16,869 $ 8,497 |
Asset Retirement Obligation (Ta
Asset Retirement Obligation (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Asset Retirement Obligation | |
Reconciliation of Asset Retirement Obligation | The following table is a reconciliation of the ARO (in thousands): March 31, December 31, 2017 2016 Asset retirement obligation, beginning balance $ 13,579 $ 20,364 Liabilities added from acquisitions 195 912 Sold — (6,291) Revisions to cost estimates — (2,399) Settlements — (134) Accretion expense 258 1,127 Asset retirement obligation, ending balance $ 14,032 $ 13,579 |
Intangible Assets (Tables)
Intangible Assets (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Intangible Assets | |
Intangible assets | Amortization expense for the three months ended March 31, 2017 and 2016 was $3.4 million and $3.5 million, respectively. These costs are amortized to depreciation, depletion, and amortization expense in our consolidated statement of operations. Intangible assets as of March 31, 2017 and December 31, 2016 are detailed below (in thousands): March 31, December 31, 2017 2016 Beginning balance $ 185,766 $ 199,741 Disposals — (219) Amortization (3,412) (13,756) Ending balance $ 182,354 $ 185,766 |
Unit-Based Compensation (Tables
Unit-Based Compensation (Tables) | 3 Months Ended |
Mar. 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, 2016 219,144 $ 14.22 Granted 171,231 14.60 Outstanding at March 31, 2017 390,375 $ 14.39 |
Distributions To Unitholders (T
Distributions To Unitholders (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Common Units | |
Schedule of payment of cash distributions | Distribution Date of Date of Date of Three Months Ended Per Unit Declaration Record Distribution March 31, 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 $ May 10, 2017 May 22, 2017 May 31, 2017 |
Class B Preferred | |
Schedule of payment of cash distributions | 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 (b) $ May 10, 2017 May 22, 2017 May 31, 2017 (a) 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 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. 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 declared a cash distribution of $0.2258 per Class B preferred unit and an aggregate distribution of 184,697 common units, each payable on May 31, 2017 to holders of record on May 22, 2017. |
Partners' Capital (Tables)
Partners' Capital (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
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): March 31, December 31, 2017 2016 Mezzanine equity beginning balance $ 342,991 $ 172,111 Discount — (87) Amortization of discount 404 23,477 Distributions 9,625 39,375 Distributions paid (9,625) (37,168) Transfer embedded derivative to Class B — 145,283 Total mezzanine equity $ 343,395 $ 342,991 |
Schedule of Weighted Average Basic and Diluted Units Outstanding | Three Months Ended March 31, 2017 2016 Common units - Basic and Diluted 13,400,138 2,743,419 Weighted Common units - Basic and Diluted 13,400,138 2,743,419 |
Loss Per Unit Amounts | The following table presents our basic and diluted loss per unit for the three months ended March 31, 2017 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (17,688) $ (17,688) Basic and diluted loss per unit $ (1.32) The following table presents our basic and diluted loss per unit for the three months ended March 31, 2016 (in thousands, except for per unit amounts): Total Common Units Assumed net loss to be allocated $ (10,739) $ (10,739) Basic and diluted loss per unit $ (3.91) |
Reporting Segments (Tables)
Reporting Segments (Tables) | 3 Months Ended |
Mar. 31, 2017 | |
Reporting Segments | |
Schedule of Segment Information | The following tables set forth our segment information for the periods indicated (in thousands): Three Months Ended March 31, 2017 Production Midstream Total Operating revenues Natural gas sales $ 2,779 $ — $ 2,779 Oil sales 11,350 — 11,350 Natural gas liquids sales 467 — 467 Gathering and transportation sales — 11,211 11,211 Total operating revenues 14,596 11,211 25,807 Operating expenses: Lease operating expenses 4,724 259 4,983 Transportation operating expenses — 3,296 3,296 Cost of sales 37 — 37 Production taxes 473 — 473 General and administrative 4,104 1,505 5,609 Unit-based compensation expense 540 — 540 Depreciation, depletion and amortization 3,281 8,900 12,181 Asset impairments 4,688 — 4,688 Accretion expense 192 66 258 Total operating expenses 18,039 14,026 32,065 Operating loss $ (3,443) $ (2,815) $ (6,258) Three Months Ended March 31, 2016 Production Midstream Total Operating revenues Natural gas sales $ 3,675 $ — $ 3,675 Oil sales 5,343 — 5,343 Natural gas liquids sales 276 — 276 Gathering and transportation sales — 13,875 13,875 Total operating revenues 9,294 13,875 23,169 Operating expenses: Lease operating expenses 4,875 98 4,973 Transportation operating expenses — 3,054 3,054 Cost of sales 130 — 130 Production taxes 221 — 221 General and administrative 4,434 1,285 5,719 Unit-based compensation expense 438 — 438 Depreciation, depletion and amortization 2,114 5,074 7,188 Asset impairments 1,309 — 1,309 Accretion expense 254 61 315 Total operating expenses 13,775 9,572 23,347 Operating income (loss) $ (4,481) $ 4,303 $ (178) |
Summary of Total Assets by Operating Segment | The following table summarizes the total assets by operating segment as of March 31, 2017 and December 31, 2016 (in thousands): March 31, December 31, 2017 2016 Segment Assets Production $ 201,991 $ 207,219 Midstream 333,986 332,486 Total assets $ 535,977 $ 539,705 |
Variable Interest Entities (Tab
Variable Interest Entities (Tables) | 3 Months Ended |
Mar. 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 March 31, 2017 and December 31, 2016 (in thousands): March 31, December 31, 2017 2016 Capital investments $ 109,441 $ 107,320 Earnings in equity investments 2,919 2,301 Distributions received (4,950) (2,950) Estimated earnout accrued 4,049 4,270 Equity in equity investments $ 111,459 $ 110,941 March 31, December 31, 2017 2016 Equity in equity investments $ 111,459 $ 110,941 Guarantees of capital investments 15,462 17,584 Maximum exposure to loss $ 126,921 $ 128,525 |
Organization And Business (Deta
Organization And Business (Details) $ in Millions | Jul. 05, 2016 | Nov. 30, 2016USD ($)itemshares | Mar. 31, 2017shares | Dec. 31, 2016shares | Jul. 31, 2016 |
Units, issued | 14,153,061 | 13,447,749 | |||
IPO | |||||
Units, issued | 6,745,107 | ||||
Proceeds from common units sold | $ | $ 69.7 | ||||
Private Placement | |||||
Units, issued | 2,272,727 | ||||
Proceeds from common units sold | $ | $ 25 | ||||
Over-Allotment Option | |||||
Units, issued | 194,305 | ||||
Carnero Gathering LLC, Joint Venture | |||||
Gathering and processing agreement term | 15 years | ||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||
Sanchez Energy Corporation | |||||
Gathering and processing agreement term | 15 years | ||||
Sanchez Energy Corporation | Acquisition of Wellbore Interests | |||||
Producing wellbores | item | 23 | ||||
Sanchez Energy Corporation | Acquisition of Working Interests | |||||
Producing wellbores | item | 11 |
Basis Of Presentation And Sum39
Basis Of Presentation And Summary Of Significant Accounting Policies (Details) | 3 Months Ended |
Mar. 31, 2017segment | |
Basis Of Presentation And Summary Of Significant Accounting Policies | |
Number of operating segments | 2 |
Acquisitions and Divestitures40
Acquisitions and Divestitures (Details) | Nov. 22, 2016USD ($)item | Jul. 05, 2016USD ($) | Jun. 15, 2016USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2017USD ($) | Jul. 31, 2016 |
Carnero Processing Acquisition | ||||||||
Business Acquisition [Line Items] | ||||||||
Acquisition membership interest (as percent) | 50.00% | |||||||
Cash payment for acquisition | $ 55,500,000 | |||||||
Capital contribution commitments | 24,500,000 | |||||||
Payments to acquire interest in joint venture | $ 12,500,000 | |||||||
Eagle Ford | ||||||||
Business Acquisition [Line Items] | ||||||||
Purchase price | $ 25,016,000 | |||||||
Carnero Gathering LLC, 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 | $ 100,000 | $ 3,500,000 | $ 3,500,000 | ||||
Assumption of capital commitments in joint venture | $ 7,400,000 | |||||||
TPL South Tex Processing Company LP | ||||||||
Business Acquisition [Line Items] | ||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||
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 | |||||||
Gateway Resources U.S.A., Inc. | ||||||||
Business Acquisition [Line Items] | ||||||||
Proceeds from divestiture of business | $ 7,120 | |||||||
Loss on disposition of intangible assets | $ 200,000 |
Acquisitions and Divestitures41
Acquisitions and Divestitures (Value Net Assets Acquired) (Details) - Eagle Ford $ 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) $ in Thousands | Mar. 31, 2017USD ($)derivative | Dec. 31, 2016USD ($) |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Number of interest rate derivatives | derivative | 0 | |
Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Total net assets | $ 10,915 | $ 6,436 |
Fair value of derivative instruments | 10,915 | 6,436 |
Fair Value, Inputs, Level 2 | Recurring | ||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | ||
Derivative assets (net) | 10,915 | 6,436 |
Total net assets | $ 10,915 | $ 6,436 |
Fair Value Measurements (Non-Re
Fair Value Measurements (Non-Recurring) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Asset impairments | $ 4,688 | $ 1,309 | $ 7,600 |
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 Derivative) (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2016USD ($) | |
Fair Value Measurements | |
Beginning Balance | $ (193,077) |
Gain on embedded derivative | 47,794 |
Transfer to mezzanine equity | 145,283 |
Ending Balance |
Derivative And Financial Inst45
Derivative And Financial Instruments (Hedges In Place) (Details) | 3 Months Ended |
Mar. 31, 2017$ / bblbbl | |
West Texas Intermediate 2017 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 94,005 |
Average Price | $ / bbl | 61.25 |
West Texas Intermediate 2017 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 87,304 |
Average Price | $ / bbl | 61.42 |
West Texas Intermediate 2017 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 81,702 |
Average Price | $ / bbl | 61.55 |
West Texas Intermediate 2017 | |
Derivative [Line Items] | |
Volume (in Bbls) | 263,011 |
Average Price | $ / bbl | 61.40 |
West Texas Intermediate 2018 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | 88,854 |
Average Price | $ / bbl | 60.82 |
West Texas Intermediate 2018 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 83,976 |
Average Price | $ / bbl | 60.90 |
West Texas Intermediate 2018 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 79,683 |
Average Price | $ / bbl | 60.96 |
West Texas Intermediate 2018 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 75,864 |
Average Price | $ / bbl | 61.02 |
West Texas Intermediate 2018 | |
Derivative [Line Items] | |
Volume (in Bbls) | 328,377 |
Average Price | $ / bbl | 60.92 |
West Texas Intermediate 2019 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | 78,667 |
Average Price | $ / bbl | 61.48 |
West Texas Intermediate 2019 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 75,326 |
Average Price | $ / bbl | 61.53 |
West Texas Intermediate 2019 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 72,279 |
Average Price | $ / bbl | 61.57 |
West Texas Intermediate 2019 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 69,480 |
Average Price | $ / bbl | 61.61 |
West Texas Intermediate 2019 | |
Derivative [Line Items] | |
Volume (in Bbls) | 295,752 |
Average Price | $ / bbl | 61.54 |
West Texas Intermediate 2020 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | 66,914 |
Average Price | $ / bbl | 53.50 |
West Texas Intermediate 2020 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 64,477 |
Average Price | $ / bbl | 53.50 |
West Texas Intermediate 2020 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 62,251 |
Average Price | $ / bbl | 53.50 |
West Texas Intermediate 2020 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 60,224 |
Average Price | $ / bbl | 53.50 |
West Texas Intermediate 2020 | |
Derivative [Line Items] | |
Volume (in Bbls) | 253,866 |
Average Price | $ / bbl | 53.50 |
West Texas Intermediate | |
Derivative [Line Items] | |
Volume (in Bbls) | 1,141,006 |
NYMEX 2017 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 287,439 |
Average Price | $ / bbl | 5.45 |
NYMEX 2017 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 271,368 |
Average Price | $ / bbl | 5.45 |
NYMEX 2017 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 257,234 |
Average Price | $ / bbl | 5.45 |
NYMEX 2,017 | |
Derivative [Line Items] | |
Volume (in Bbls) | 816,041 |
Average Price | $ / bbl | 5.45 |
NYMEX 2018 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | 260,841 |
Average Price | $ / bbl | 3.18 |
NYMEX 2018 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 248,018 |
Average Price | $ / bbl | 3.18 |
NYMEX 2018 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 235,810 |
Average Price | $ / bbl | 3.18 |
NYMEX 2018 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 225,208 |
Average Price | $ / bbl | 3.18 |
NYMEX 2,018 | |
Derivative [Line Items] | |
Volume (in Bbls) | 969,877 |
Average Price | $ / bbl | 3.18 |
NYMEX 2019 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | 224,303 |
Average Price | $ / bbl | 3.10 |
NYMEX 2019 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 214,186 |
Average Price | $ / bbl | 3.10 |
NYMEX 2019 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 205,533 |
Average Price | $ / bbl | 3.10 |
NYMEX 2019 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 197,455 |
Average Price | $ / bbl | 3.10 |
NYMEX 2,019 | |
Derivative [Line Items] | |
Volume (in Bbls) | 841,477 |
Average Price | $ / bbl | 3.10 |
NYMEX 2020 Swap Quarter 1 | |
Derivative [Line Items] | |
Volume (in Bbls) | 188,696 |
Average Price | $ / bbl | 2.85 |
NYMEX 2020 Swap Quarter 2 | |
Derivative [Line Items] | |
Volume (in Bbls) | 176,946 |
Average Price | $ / bbl | 2.85 |
NYMEX 2020 Swap Quarter 3 | |
Derivative [Line Items] | |
Volume (in Bbls) | 170,637 |
Average Price | $ / bbl | 2.85 |
NYMEX 2020 Swap Quarter 4 | |
Derivative [Line Items] | |
Volume (in Bbls) | 164,747 |
Average Price | $ / bbl | 2.85 |
NYMEX 2,020 | |
Derivative [Line Items] | |
Volume (in Bbls) | 701,026 |
Average Price | $ / bbl | 2.85 |
NYMEX | |
Derivative [Line Items] | |
Volume (in Bbls) | 3,328,421 |
Derivative And Financial Inst46
Derivative And Financial Instruments (Changes In Fair Value) (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017USD ($)item | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($) | |
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | $ 6,055 | $ 3,990 | |
Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Beginning fair value of commodity derivatives | 6,435 | 31,018 | $ 31,018 |
Net premiums on derivative contracts | 3,197 | ||
Ending fair value of commodity derivatives | $ 10,915 | 6,435 | |
Number of counterparties | item | 4 | ||
Oil | Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | $ 5,495 | (8,355) | |
Net settlements on derivative contracts | (929) | (13,622) | |
Oil | Oil And Liquids Sales | Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | 5,495 | 2,692 | |
Natural Gas | Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | 560 | 1,116 | |
Net settlements on derivative contracts | (646) | $ (6,919) | |
Natural Gas | Natural Gas Sales | Commodity Contract | |||
Derivative Instruments Gain Loss [Line Items] | |||
Net gains (losses) on derivatives | $ 560 | $ 1,298 |
Derivative And Financial Inst47
Derivative And Financial Instruments (Embedded Derivative) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2016 | Dec. 31, 2016 | |
Derivative And Financial Instruments | ||
Beginning Balance | $ (193,077) | $ (193,077) |
Gain on embedded derivative | $ 6,294 | (47,794) |
Transfer to mezzanine equity | 145,283 | |
Ending Balance |
Long-Term Debt (Details)
Long-Term Debt (Details) $ in Thousands | 3 Months Ended | |||
Mar. 31, 2017USD ($) | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($) | May 19, 2016USD ($) | |
Line of Credit Facility [Line Items] | ||||
Amortization of debt issuance costs | $ 128 | $ 123 | ||
Unamortized debt issue costs | 1,600 | $ 1,700 | ||
Credit Agreement | ||||
Line of Credit Facility [Line Items] | ||||
Maximum borrowing capacity | 215,100 | |||
Sub-limit which may be used for issuance of letters of credit | $ 15,000 | |||
Borrowing base amount | $ 200,000 | |||
Commitment fee on unutilized borrowing base | 0.50% | |||
Credit Agreement | Second full quarter after Catarina acquisition | ||||
Line of Credit Facility [Line Items] | ||||
Borrowing base multiplier | 4.5 | |||
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] | ||||
Consolidated current asset ratio | 1 | |||
Required interest coverage ratio | 2.5 | |||
Exceeding of reserve-based credit facility over borrowing base (as a percent) | 90.00% | |||
Ownership percentage by subsidiary | 50 | |||
Minimum | Credit Agreement | Scenario One | ||||
Line of Credit Facility [Line Items] | ||||
Debt to Adjusted EBITDA ratio | 4.5 | |||
Minimum | Credit Agreement | Scenario Two | ||||
Line of Credit Facility [Line Items] | ||||
Debt to Adjusted EBITDA ratio | 4 | |||
Minimum | Credit Agreement | London Interbank Offered Rate (LIBOR) | ||||
Line of Credit Facility [Line Items] | ||||
Variable interest rate | 2.25% | |||
Minimum | Credit Agreement | ABR | ||||
Line of Credit Facility [Line Items] | ||||
Variable interest rate | 1.25% | |||
Maximum | Credit Agreement | London Interbank Offered Rate (LIBOR) | ||||
Line of Credit Facility [Line Items] | ||||
Variable interest rate | 3.25% | |||
Maximum | Credit Agreement | ABR | ||||
Line of Credit Facility [Line Items] | ||||
Variable interest rate | 2.25% |
Oil And Natural Gas Propertie49
Oil And Natural Gas Properties And Related Equipment (Gathering and Transportation Assets) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Property, Plant and Equipment [Line Items] | ||
Midstream assets | $ 165,111 | $ 152,209 |
Less: Accumulated depreciation and amortization | (682,248) | (674,338) |
Midstream | ||
Property, Plant and Equipment [Line Items] | ||
Midstream assets | 165,111 | 152,209 |
Less: Accumulated depreciation and amortization | (20,555) | (15,020) |
Total gathering and transportation assets | $ 144,556 | $ 137,189 |
Oil And Natural Gas Propertie50
Oil And Natural Gas Properties And Related Equipment (Properties) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Oil And Natural Gas Properties And Related Equipment. | ||
Proved property | $ 757,278 | $ 758,366 |
Unproved property | 46 | 46 |
Land | 501 | 501 |
Total property costs | 757,825 | 758,913 |
Materials and supplies | 1,056 | 1,056 |
Total | 758,881 | 759,969 |
Less: Accumulated depreciation, depletion, amortization and impairments | (682,248) | (674,338) |
Oil and natural gas properties and equipment, net | $ 76,633 | $ 85,631 |
Oil And Natural Gas Propertie51
Oil And Natural Gas Properties And Related Equipment (DDA and Impairments) (Details) - USD ($) $ in Thousands | 3 Months Ended | ||
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Property, Plant and Equipment [Line Items] | |||
Amortization of intangible asset | $ 3,412 | $ 3,458 | |
Depreciation, depletion and amortization | 8,769 | 3,730 | |
Asset impairments | 4,688 | 1,309 | |
Total | 16,869 | 8,497 | |
Non-cash impairment charges | 4,700 | 1,300 | |
Proved property | 757,278 | $ 758,366 | |
Exploration and dry hole costs | $ 0 | 0 | |
Gathering Facilities | |||
Property, Plant and Equipment [Line Items] | |||
Useful lives | 36 years | ||
Oil and Natural Gas-Related Assets | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization | $ 3,234 | 2,020 | |
Gathering and Transportation Related Assets | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization | $ 5,535 | 1,710 | |
Gathering and Transportation Related Assets | Minimum | |||
Property, Plant and Equipment [Line Items] | |||
Useful lives | 3 years | ||
Gathering and Transportation Related Assets | Maximum | |||
Property, Plant and Equipment [Line Items] | |||
Useful lives | 15 years | ||
Oil and Natural Gas-Related Assets and Gathering and Transportation-Related Assets | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation, depletion and amortization | $ 12,181 | $ 7,188 |
Asset Retirement Obligation (De
Asset Retirement Obligation (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Asset Retirement Obligation | |||
Asset retirement obligation, beginning balance | $ 13,579 | $ 20,364 | $ 20,364 |
Liabilities added from acquisitions | 195 | 912 | |
Sold | (6,291) | ||
Revisions to cost estimates | (2,399) | ||
Settlements | (134) | ||
Accretion expense | 258 | $ 315 | 1,127 |
Asset retirement obligation, ending balance | 14,032 | 13,579 | |
Legally restricted assets | $ 0 | $ 0 |
Intangible Assets (Details)
Intangible Assets (Details) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017USD ($)a | Mar. 31, 2016USD ($) | Dec. 31, 2016USD ($) | |
Finite-Lived Intangible Assets [Line Items] | |||
Amortization of intangible assets | $ 3,412 | $ 3,458 | |
Beginning balance | 185,766 | $ 199,741 | $ 199,741 |
Disposals | (219) | ||
Amortization | (3,412) | (13,756) | |
Ending balance | $ 182,354 | $ 185,766 | |
Customer Contracts | |||
Finite-Lived Intangible Assets [Line Items] | |||
Agreement term | 15 years | ||
Dedicated acreage | a | 35,000 | ||
Useful life | 15 years | ||
Ending balance | $ 182,300 | ||
Marketing Contracts | |||
Finite-Lived Intangible Assets [Line Items] | |||
Amortization | $ 200 |
Investments (Details)
Investments (Details) - USD ($) $ in Thousands | Nov. 22, 2016 | Jul. 05, 2016 | Mar. 31, 2017 | Mar. 31, 2016 | Mar. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Jul. 31, 2016 | Jun. 05, 2016 |
Schedule of Equity Method Investments [Line Items] | |||||||||
Capital investments | $ 109,441 | $ 109,441 | $ 109,441 | $ 107,320 | |||||
Earnings in equity investments | 482 | $ 12 | |||||||
Amortization of intangible asset | 3,412 | 3,458 | |||||||
Cash distributions | 5,796 | $ 1,262 | |||||||
Carnero Gathering LLC, 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 | 100 | 3,500 | 3,500 | |||||
Assumption of capital commitments in joint venture | $ 7,400 | ||||||||
Capital investments | 41,000 | 41,000 | 41,000 | ||||||
Agreement term | 15 years | ||||||||
Earnings in equity investments | 1,400 | ||||||||
Cash distributions | 2,000 | ||||||||
Carnero Gathering LLC, Joint Venture | Customer Relationships | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Intangible asset, fair value | $ 13,000 | ||||||||
Amortization of intangible asset | 200 | ||||||||
Carnero Processing Joint Venture | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest (as a percent) | 50.00% | ||||||||
Payments to acquire interest in joint venture | $ 55,500 | ||||||||
Assumption of capital commitments in joint venture | 24,500 | ||||||||
Payments of capital commitments from joint venture | 2,000 | ||||||||
Capital investments | $ 48,000 | 68,500 | $ 68,500 | $ 68,500 | |||||
Earnings in equity investments | $ 500 | ||||||||
TPL South Tex Processing Company LP | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | |||||||
SN Midstream | Carnero Gathering LLC, Joint Venture | |||||||||
Schedule of Equity Method Investments [Line Items] | |||||||||
Capital investments | $ 26,000 |
Commitments And Contingencies (
Commitments And Contingencies (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Commitments And Contingencies | ||
Estimated earnout accrued | $ 4,049 | $ 4,270 |
Related Party Transactions (Det
Related Party Transactions (Details) | Nov. 22, 2016USD ($) | Oct. 06, 2016USD ($) | Jul. 05, 2016USD ($) | Oct. 14, 2015aMcfbbl | Nov. 30, 2016USD ($)itemshares | Mar. 31, 2017USD ($) | Mar. 31, 2017USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Jul. 31, 2016 |
Related Party Transaction [Line Items] | ||||||||||
Related parties, net receivable | $ 3,000,000 | $ 3,000,000 | $ 3,000,000 | $ 6,000,000 | ||||||
Related parties, net payable | $ 13,300,000 | $ 13,300,000 | $ 13,300,000 | $ 7,000,000 | ||||||
Sanchez Energy Corporation | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Agreement term | 15 years | |||||||||
Payments to acquire interest in joint venture | $ 25,000,000 | |||||||||
Assumption of capital commitments in joint venture | 24,200,000 | |||||||||
SP Holdings | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Percent of value of properties held used to compute quarterly fee | 0.375% | 0.375% | 0.375% | |||||||
Maximum asset acquisition, disposition and financing fee | 2.00% | |||||||||
Agreement term | 10 years | |||||||||
Agreement notice period | 180 days | |||||||||
Administrative fee paid | $ 2,000,000 | |||||||||
SN Terminal, LLC | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Contingent payment in the event of Lease Option exercise | $ 1 | |||||||||
Contingent payment in the event of marine crude storage terminal construction | $ 250,000 | |||||||||
Carnero Processing Joint Venture | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
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 | |||||||||
Carnero Processing Joint Venture | Sanchez Energy Corporation | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Payments to acquire interest in joint venture | 55,500,000 | |||||||||
Assumption of capital commitments in joint venture | $ 24,500,000 | |||||||||
Carnero Gathering LLC, Joint Venture | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Agreement term | 15 years | |||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||||
Payments to acquire interest in joint venture | $ 37,000,000 | $ 100,000 | $ 3,500,000 | $ 3,500,000 | ||||||
Assumption of capital commitments in joint venture | $ 7,400,000 | |||||||||
TPL South Tex Processing Company LP | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Ownership interest (as a percent) | 50.00% | 50.00% | ||||||||
Acquisition of Wellbore Interests | Sanchez Energy Corporation | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Producing wellbores | item | 23 | |||||||||
Acquisition of Working Interests | Sanchez Energy Corporation | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Producing wellbores | item | 11 | |||||||||
Western Catarina Midstream | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Agreement term | 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 | |||||||||
Western Catarina Midstream | Natural Gas | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Gathering Agreement minimum quarterly volume delivery commitment | Mcf | 142,000 | |||||||||
Common Units | Sanchez Energy Corporation | ||||||||||
Related Party Transaction [Line Items] | ||||||||||
Shares repurchased | shares | 2,272,727 |
Unit-Based Compensation (Restri
Unit-Based Compensation (Restricted Units Activity) (Details) - $ / shares | 3 Months Ended | 12 Months Ended |
Mar. 31, 2017 | Dec. 31, 2016 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of Restricted Units, Outstanding | 390,375 | |
LTIP | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Units available for issuance | 1,523,074 | |
Restricted Stock Units | LTIP | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Number of Restricted Units, Outstanding | 219,144 | |
Common units granted | 171,231 | |
Number of Restricted Units, Outstanding | 390,375 | 219,144 |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ 14.22 | |
Weighted Averaged Grant Date Fair Value Per Unit, Granted | 14.60 | |
Weighted Averaged Grant Date Fair Value Per Unit, Outstanding | $ 14.39 | $ 14.22 |
Prior To Stock Split | Director | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Common units granted | 67,627 | |
Prior To Stock Split | Executives | ||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||
Common units granted | 171,231 |
Distributions To Unitholders (D
Distributions To Unitholders (Details) - $ / shares | May 31, 2017 | Feb. 28, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Sep. 30, 2016 | Jun. 30, 2016 | Mar. 31, 2016 |
Common Units | |||||||
Distribution paid per unit | $ 0.4375 | $ 0.4310 | $ 0.4246 | $ 0.4183 | $ 0.4121 | ||
Aggregate distribution of units | 208,594 | ||||||
Class B Preferred | |||||||
Distribution paid per unit | $ 0.2258 | $ 0.2258 | $ 0.4500 | $ 0.4500 | $ 0.4500 | ||
Aggregate distribution of units | 208,594 | ||||||
Class B Preferred | Subsequent Event | |||||||
Aggregate distribution of units | 184,697 |
Partners' Capital (Details)
Partners' Capital (Details) $ / shares in Units, $ in Millions | Jan. 25, 2017$ / sharesshares | Oct. 14, 2015USD ($)$ / sharesshares | Nov. 30, 2016USD ($)shares | Mar. 31, 2017USD ($)shares | Dec. 31, 2016shares | Dec. 31, 2015 | Dec. 06, 2016shares | Mar. 31, 2016 |
Limited Partners' Capital Account [Line Items] | ||||||||
Class B preferred units, outstanding | 31,000,887 | 29,296,441 | ||||||
Units, outstanding | 14,153,061 | 13,447,749 | ||||||
Class A preferred units converted to common shares, conversion ratio | 1 | |||||||
Units, issued | 14,153,061 | 13,447,749 | ||||||
Class B preferred units, issued | 31,000,887 | 29,296,441 | ||||||
IPO | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Units, issued | 6,745,107 | |||||||
Proceeds from common units sold | $ | $ 69.7 | |||||||
Private Placement | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Units, issued | 2,272,727 | |||||||
Proceeds from common units sold | $ | $ 25 | |||||||
Over-Allotment Option | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Units, issued | 194,305 | |||||||
Class A Preferred | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Increase in distribution rate | 4.00% | |||||||
Class B Preferred | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Class B preferred units, outstanding | 31,000,887 | |||||||
Units, issued | 9,851,996 | |||||||
Units sold (in units) | 19,444,445 | |||||||
Price per unit sold | $ / shares | $ 18 | |||||||
Proceeds from preferred units sold | $ | $ 350 | |||||||
Percent of consideration paid | 2.25% | |||||||
Paid in full in cash, per annum | 10.00% | |||||||
Paid in part cash, per annum | 12.00% | |||||||
Dividend per annum | 8.00% | |||||||
Paid-in kind per annum | 4.00% | |||||||
Class B Preferred | Settlement Agreement with Stonepeak Catarina Holdings LLC [Member] | ||||||||
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] | ||||||||
Units, outstanding | 14,153,061 | |||||||
Aggregate cash distribution | 14.00% | |||||||
Minimum | Class A Preferred | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Proceeds from common units sold | $ | $ 75 | |||||||
Minimum | Class B Preferred | ||||||||
Limited Partners' Capital Account [Line Items] | ||||||||
Preferred unit conversion, amount | $ | 17.5 | |||||||
Cash from conversion | $ | $ 75 |
Partners Capital (Class B Prefe
Partners Capital (Class B Preferred Units) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Mezzanine equity beginning balance | $ 342,991 | ||
Distributions | 7,000 | $ 7,418 | |
Total mezzanine equity | 343,395 | $ 342,991 | |
Class B Preferred | |||
Mezzanine equity beginning balance | 342,991 | $ 172,111 | 172,111 |
Discount | (87) | ||
Amortization of discount | 404 | 23,477 | |
Distributions | 9,625 | 39,375 | |
Distributions paid | (9,625) | (37,168) | |
Transfer embedded derivative to Class B | 145,283 | ||
Total mezzanine equity | $ 343,395 | $ 342,991 |
Partners' Capital (EPU) (Detail
Partners' Capital (EPU) (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | |
Weighted Average Units Outstanding - Basic and diluted | 13,400,138 | 2,743,419 |
Restricted unvested common units granted and outstanding | 390,375 | |
Assumed net loss to be allocated | $ (17,688) | $ (10,739) |
Asset impairments | $ 4,688 | $ 1,309 |
Common Units | ||
Weighted Average Units Outstanding - Basic and diluted | 13,400,138 | 2,743,419 |
Assumed net loss to be allocated | $ (17,688) | $ (10,739) |
Net loss per unit - Basic and diluted | $ (1.32) | $ (3.91) |
Reporting Segments (Segment Inf
Reporting Segments (Segment Information) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2017 | Mar. 31, 2016 | Dec. 31, 2016 | |
Operating Revenues | |||
Natural gas sales | $ 2,779 | $ 3,675 | |
Oil sales | 11,350 | 5,343 | |
Natural gas liquids sales | 467 | 276 | |
Gathering and transportation sales | 11,211 | 13,875 | |
Total revenues | 25,807 | 23,169 | |
Operating expenses: | |||
Lease operating expenses | 4,983 | 4,973 | |
Transportation operating expenses | 3,296 | 3,054 | |
Cost of sales | 37 | 130 | |
Production taxes | 473 | 221 | |
General and administrative | 5,609 | 5,719 | |
Unit-based compensation expense | 540 | 438 | |
Depreciation, depletion and amortization | 12,181 | 7,188 | |
Asset impairments | 4,688 | 1,309 | |
Accretion expense | 258 | 315 | $ 1,127 |
Total operating expenses | 32,065 | 23,347 | |
Operating income (loss) | (6,258) | (178) | |
Upstream | |||
Operating Revenues | |||
Natural gas sales | 2,779 | 3,675 | |
Oil sales | 11,350 | 5,343 | |
Natural gas liquids sales | 467 | 276 | |
Total revenues | 14,596 | 9,294 | |
Operating expenses: | |||
Lease operating expenses | 4,724 | 4,875 | |
Cost of sales | 37 | 130 | |
Production taxes | 473 | 221 | |
General and administrative | 4,104 | 4,434 | |
Unit-based compensation expense | 540 | 438 | |
Depreciation, depletion and amortization | 3,281 | 2,114 | |
Asset impairments | 4,688 | 1,309 | |
Accretion expense | 192 | 254 | |
Total operating expenses | 18,039 | 13,775 | |
Operating income (loss) | (3,443) | (4,481) | |
Midstream | |||
Operating Revenues | |||
Gathering and transportation sales | 11,211 | 13,875 | |
Total revenues | 11,211 | 13,875 | |
Operating expenses: | |||
Lease operating expenses | 259 | 98 | |
Transportation operating expenses | 3,296 | 3,054 | |
General and administrative | 1,505 | 1,285 | |
Depreciation, depletion and amortization | 8,900 | 5,074 | |
Accretion expense | 66 | 61 | |
Total operating expenses | 14,026 | 9,572 | |
Operating income (loss) | $ (2,815) | $ 4,303 |
Reporting Segments (Assets by S
Reporting Segments (Assets by Segment) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Dec. 31, 2016 |
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Assets | $ 535,977 | $ 539,705 |
Upstream | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Assets | 201,991 | 207,219 |
Midstream | ||
Segment Reporting, Asset Reconciling Item [Line Items] | ||
Assets | $ 333,986 | $ 332,486 |
Variable Interest Entities (Det
Variable Interest Entities (Details) - USD ($) $ in Thousands | Nov. 22, 2016 | Jul. 05, 2016 | Mar. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 | Mar. 31, 2017 | Jul. 31, 2016 |
Variable Interest Entity [Line Items] | |||||||
Capital investments | $ 109,441 | $ 109,441 | $ 107,320 | $ 109,441 | |||
Earnings in equity investments | 2,919 | 2,919 | 2,301 | 2,919 | |||
Distributions received | (4,950) | (2,950) | |||||
Estimated earnout accrued | 4,049 | 4,049 | 4,270 | 4,049 | |||
Equity in equity investments | 111,459 | 111,459 | 110,941 | 111,459 | |||
Guarantees of capital investments | 15,462 | 15,462 | 17,584 | 15,462 | |||
Maximum exposure to loss | 126,921 | 126,921 | $ 128,525 | 126,921 | |||
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 | ||||||
Assumption of capital commitments in joint venture | 24,500 | ||||||
Debt incurred | 0 | 0 | 0 | ||||
Capital investments | $ 48,000 | 68,500 | 68,500 | 68,500 | |||
Maximum exposure to loss | 79,600 | 79,600 | 79,600 | ||||
Carnero Gathering LLC, 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 | 100 | 3,500 | 3,500 | |||
Assumption of capital commitments in joint venture | $ 7,400 | ||||||
Debt incurred | 0 | 0 | 0 | ||||
Capital investments | 41,000 | 41,000 | 41,000 | ||||
Maximum exposure to loss | $ 47,300 | $ 47,300 | $ 47,300 |
Subsequent Events (Details)
Subsequent Events (Details) - USD ($) $ / shares in Units, $ in Millions | May 31, 2017 | May 10, 2017 | Feb. 28, 2017 | Mar. 31, 2017 | Apr. 17, 2017 |
Credit Agreement | |||||
Subsequent Event [Line Items] | |||||
Maximum borrowing capacity | $ 215.1 | ||||
lender loan | |||||
Subsequent Event [Line Items] | |||||
Maximum borrowing capacity | $ 200 | ||||
Common Units | |||||
Subsequent Event [Line Items] | |||||
Aggregate distribution of units | 208,594 | ||||
Class B Preferred | |||||
Subsequent Event [Line Items] | |||||
Aggregate distribution of units | 208,594 | ||||
Subsequent Event | Credit Agreement | |||||
Subsequent Event [Line Items] | |||||
Maximum borrowing capacity | $ 215.6 | ||||
Subsequent Event | lender loan | |||||
Subsequent Event [Line Items] | |||||
Maximum borrowing capacity | 200 | ||||
Subsequent Event | Oil and natural gas reserves | Oklahoma | |||||
Subsequent Event [Line Items] | |||||
Proceeds from divestiture of business | $ 5.5 | ||||
Subsequent Event | Common Units | |||||
Subsequent Event [Line Items] | |||||
Distribution declared per unit | $ 0.4375 | ||||
Annual distribution declared per unit | 1.75 | ||||
Subsequent Event | Class B Preferred | |||||
Subsequent Event [Line Items] | |||||
Distribution declared per unit | $ 0.2258 | ||||
Aggregate distribution of units | 184,697 | ||||
Upstream | Subsequent Event | |||||
Subsequent Event [Line Items] | |||||
Maximum borrowing capacity | 168.1 | ||||
Midstream | Subsequent Event | |||||
Subsequent Event [Line Items] | |||||
Maximum borrowing capacity | $ 47.5 |