(a) The following documents are filed as a part of this Report: | | (2) | | | | (2) Financial Statement Schedules - None. |
– None | | | | | | (3) Exhibits – see Index to Exhibits | | | | | (b) Exhibits - see Index to Exhibits | | | | | (c) Financial statements of affiliates whose securities are pledged as collateral - See Index to Financial Statements on page S-1. | |
(c) Financial statements of affiliates whose securities are pledged as collateral - See Index to Financial Statements on page S-1.
The Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in this Annual Report on Form 10-K and have been included herein. The Parent Company’s interestsinterest in ETP GP and ETE Common Holdings, LLC (collectively, the “Non-Reporting Entities”) also constituteconstitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting EntitiesETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities hasETP GP does not have substantive operations of its own; rather, each ofETP GP only owns the Non-Reporting Entities holds only direct or indirect interestsgeneral partner interest in ETP and/or the consolidated subsidiaries of ETP. As further discussed in Note 6 to the consolidated financial statements, as referenced in (a) above, the financial statements of the Non-Reporting EntitiesETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of the Non-Reporting EntitiesETP GP have been excluded from this Annual Report on Form 10-K.
ITEM 16. FORM 10-K SUMMARY None.
INDEX TO EXHIBITS The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable. | | | | Exhibit Number | | Description | | | | | | Exchange and Repurchase Agreement, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated December 23, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 23, 2014) | | | Agreement and Plan of Merger, dated as of September 28, 2015, among Energy Transfer Corp LP, ETE Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, ETE GP, LLC and The Williams Companies, Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K/A, File No. 1-32740, filed October 2, 2015) | | | Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed January 26, 2015) | | | Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, File No. 1-11727, filed February 19, 2015) | | | Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.1 of Form 8-K File No. 1-11727, filed November 21, 2016 | | | Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K File No. 1-11727, filed December 21, 2016 | | | Contribution Agreement, dated as of January 15, 2018, by and among USA Compression Partners, LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETC Compression, LLC and, solely for certain purposes therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 to the Registrant’s Form 8-K filed January 16, 2018). | | | Purchase Agreement, dated as of January 15, 2018, by and among USA Compression Holdings, LLC, Energy Transfer Equity, L.P., Energy Transfer Partners, L.L.C. and, solely for certain purposes therein, R/C IV USACP Holdings, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.2 to the Registrant’s Form 8-K filed January 16, 2018). | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Exhibit Number | | Description | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 of Form 8-K, File No. 1-32740, filed May 7, 2007) | | | | | |
| | | Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-32740, filed May 1, 2013) | | | Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 19, 2014) | | | |
| | | | Exhibit Number | | Description | | | Credit Agreement, dated as of March 24, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed March 30, 2017) | | | | | | | | | Senior Secured Term Loan Agreement, dated February 2, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 3, 2017.) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 101* | | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2017 and December 31, 2016; (ii) our Consolidated Statements of Operations for the years ended December 31, 2017, 2016 and 2015; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2017, 2016 and 2013; (iv) our Consolidated Statement of Equity for the years ended December 31, 2017, 2016 and 2015; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2017, 2016 and 2015 |
| | | * | Filed herewith. | ** | Furnished herewith. | + | Denotes a management contract or compensatory plan or arrangement. |
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | | | | | | | | ENERGY TRANSFER EQUITY, L.P. | | | | | | | By: | | LE GP, LLC, | | | | | its general partner | | | | | Date: | February 24, 201723, 2018 | By: | | /s/ Thomas E. Long | | | | | Thomas E. Long | | | | | Group Chief Financial Officer (duly authorized to sign on behalf of the registrant) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons in the capacities and on the dates indicated: | | | | | | Signature | | Title | | Date | | | | | | /s/ John W. McReynolds | | Director and President | | February 24, 201723, 2018 | John W. McReynolds | | (Principal Executive Officer) | | | | | | | | /s/ Thomas E. Long | | Group Chief Financial Officer (Principal Financial and Accounting Officer) | | February 24, 201723, 2018 | Thomas E. Long | | | | | | | | | /s/ Kelcy L. Warren | | Director and Chairman of the Board | | February 24, 201723, 2018 | Kelcy L. Warren | | | | | | | | | | /s/ Richard D. Brannon | | Director | | February 24, 201723, 2018 | Richard D. Brannon | | | | | | | | | | /s/ Marshall S. McCrea, III | | Director | | February 24, 201723, 2018 | Marshall S. McCrea, III | | | | | | | | | | /s/ Matthew S. Ramsey | | Director | | February 24, 201723, 2018 | Matthew S. Ramsey | | | | | | | | | | /s/ K. Rick Turner | | Director | | February 24, 201723, 2018 | K. Rick Turner | | | | | | | | | | /s/ William P. Williams | | Director | | February 24, 201723, 2018 | William P. Williams | | | | | | | | | | | | | | | | | | | |
INDEX TO EXHIBITS
The exhibits listed on the following Exhibit Index are filed as part of this report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.
| | | | Exhibit
Number
| | Description | | | Energy Transfer Equity, L.P. | 2.1 | | Redemption and Transfer Agreement, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. dated November 19, 2013 (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-32740, filed November 21, 2013) | 2.2 | | Exchange and Repurchase Agreement, by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated December 23, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 23, 2014) | 2.3 | | Agreement and Plan of Merger, dated as of September 28, 2015, among Energy Transfer Corp LP, ETE Corp GP, LLC, Energy Transfer Equity, L.P., LE GP, LLC, ETE GP, LLC and The Williams Companies, Inc. (incorporated by reference to Exhibit 2.1 of Form 8-K/A, File No. 1-32740, filed October 2, 2015) | | | | | | Energy Transfer Partners, L.P. | 2.4 | | Purchase and Sale Agreement, by and between Southern Union Company, as Seller, Plaza Missouri Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc., as Buyers, dated as of December 14, 2012 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed December 17, 2012) | 2.5 | | Purchase and Sale Agreement, by and between Southern Union Company, as Seller, Plaza Massachusetts Acquisition, Inc. and for certain limited purposes The Laclede Group, Inc., as Buyers, dated as of December 14, 2012 (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed December 17, 2012) | 2.6 | | Contribution Agreement, dated as of February 27, 2013, by and among Southern Union Company, Regency Energy Partners LP, Regency Western G&P LLC, and for certain limited purposes, ETP Holdco Corporation, Energy Transfer Equity, L.P., Energy Transfer Partners, L.P. and ETC Texas Pipeline, Ltd. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-06407, filed February 28, 2013) | 2.7 | | Agreement and Plan of Merger, dated as of October 9, 2013, by and among Regency Energy Partners LP, RVP LLC, Regency GP LP, PVR Partners, L.P. and PVR GP, LLC (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35262, filed October 10, 2013) | 2.8 | | Amendment No. 1 to Agreement and Plan of Merger, dated as of November 7, 2013, by and among Regency Energy Partners LP, RVP LLC, Regency GP LP, PVR Partners, L.P. and PVR GP, LLC (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35262, filed November 8, 2013) | 2.9 | | Contribution Agreement, dated as of December 23, 2013, by and among Regency Energy Partners LP, Regal Midstream LLC, and Eagle Rock Energy Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35262, filed December 24, 2013) | 2.10 | | Agreement and Plan of Merger, dated as of April 27, 2014, by and among, Energy Transfer Partners, L.P., Drive Acquisition Corporation, Heritage Holdings, Inc., Energy Transfer Partners GP, L.P., Susser Holdings Corporation, and, for certain limited purposes set forth therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed April 28, 2014) | 2.11 | | Agreement and Plan of Merger, dated as of January 25, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners, GP, L.P., Regency Energy Partners LP, Regency GP LP and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-11727, filed January 26, 2015) | 2.12 | | Amendment No. 1 to Agreement and Plan of Merger, dated as of February 18, 2015, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Rendezvous I LLC, Rendezvous II LLC, Regency Energy Partners LP, Regency GP LP, ETE GP Acquirer LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 2.2 of Form 8-K, File No. 1-11727, filed February 19, 2015) | 2.13 | | Agreement and Plan of Merger, dated as of November 20, 2016, by and among Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., Sunoco Logistics Partners L.P., Sunoco Partners LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.1 of Form 8-K File No. 1-11727, filed November 21, 2016 | 2.14 | | Amendment No. 1 to Agreement and Plan of Merger, dated as of December 16, 2016, by and among Sunoco Logistics Partners L.P., Sunoco Partners LLC, SXL Acquisition Sub LLC, SXL Acquisition Sub LP, Energy Transfer Partners, L.P., Energy Transfer Partners GP, L.P., ETP Acquisition Sub, LLC and, solely for purposes of certain provisions therein, Energy Transfer Equity, L.P. (incorporate by reference to Exhibit 2.2 of Form 8-K File No. 1-11727, filed December 21, 2016 | | | | | | Sunoco Logistics Partners L.P. |
| | | | Exhibit
Number
| | Description | 2.15 | | Exchange Agreement, dated as of September 16, 2015, by and among Energy Transfer Partners, L.P., La Grange Acquisition, L.P., Sunoco Logistics Partners L.P., and Sunoco Pipeline L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-31219, filed October 15, 2015) | | | | | | Sunoco LP | 2.16 | | Contribution Agreement, dated as of September 25, 2014, by and among Mid-Atlantic Convenience Stores, LLC, ETC M-A Acquisition LLC, Susser Petroleum Partners LP and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed October 1, 2014) | 2.17 | | Contribution Agreement, dated as of March 23, 2015, by and among Sunoco, LLC, ETP Retail Holdings, LLC, Sunoco LP and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed March 23, 2015) | 2.18 | | Contribution Agreement, dated as of July 14, 2015, by and among Susser Holdings Corporation, Heritage Holdings, Inc., ETP Holdco Corporation, Sunoco LP, Sunoco GP LLC and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed July 15, 2015) | 2.19 | | Contribution Agreement, dated as of November 15, 2015, by and among Sunoco, LLC, Sunoco, Inc., ETP Retail Holdings, LLC, Sunoco LP, Sunoco GP LLC, and solely with respect to limited provisions therein, Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 2.1 of Form 8-K, File No. 1-35653, filed November 16, 2015) | | | | | | Energy Transfer Equity, L.P. | 3.1 | | Certificate of Limited Partnership of Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 3.2 of Form S-1, File No. 333-128097, filed September 2, 2005) | 3.2 | | Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated February 8, 2006 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed February 14, 2006) | 3.3 | | Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P. dated November 1, 2006 (incorporated by reference to Exhibit 3.3.1 of Form 10-K, File No. 1-32740, filed November 29, 2006) | 3.4 | | Amendment No. 2 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated November 9, 2007 (incorporated by reference to Exhibit 3.3.2 of Form 8-K, File No. 1-32740, filed November 13, 2007) | 3.5 | | Amendment No. 3 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated May 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed June 2, 2010) | 3.6 | | Amendment No. 4 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P., dated December 23, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-32740, filed December 27, 2013) | | | | | | Energy Transfer Partners, L.P. | 3.7 | | Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 3.3 of Form 10-Q, File No. 1-11727, filed April 14, 2004) | 3.8 | | Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.) dated July 28, 2009 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed July 29, 2009) | 3.9 | | Amendment No. 1 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated March 26, 2012 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed March 28, 2012) | 3.10 | | Amendment No. 2 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated October 5, 2012 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 3.11 | | Amendment No. 3 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 15, 2013 (incorporated by reference to Exhibit 3.1 to Form 8-K/A, File No. 1-11727, filed April 18, 2013) | 3.12 | | Amendment No. 4 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 30, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed May 1, 2013) | 3.13 | | Amendment No. 5 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated October 31, 2013 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed November 1, 2013) |
| | | | Exhibit
Number
| | Description | 3.14 | | Amendment No. 6 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated February 19, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed February 19, 2014) | 3.15 | | Amendment No. 7 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated March 3, 2014 (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-11727, filed March 5, 2014) | 3.16 | | Amendment No. 8 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated August 29, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed August 29, 2014) | 3.17 | | Amendment No. 9 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated March 9, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed March 10, 2015) | 3.18 | | Amendment No. 10 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated April 30, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed April 30, 2015) | 3.19 | | Amendment No. 11 to Second Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P., dated August 21, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-11727, filed August 27, 2015) | | | | | | Sunoco Logistics Partners L.P. | 3.20 | | Certificate of Limited Partnership of Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 3.1 of Form S-1, File No. 333-71968, filed October 22, 2001) | 3.20.1 | | Amendment to the Certificate of Limited Partnership of Sunoco Logistics Partners L.P. dated as of August 28, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 1, 2015) | 3.21 | | Third Amended and Restated Agreement of Limited Partnership of Sunoco Logistics Partners L.P., dated as of January 26, 2010 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed January 28, 2010) | 3.21.1 | | Amendment No. 1 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 1, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed July 5, 2011) | 3.21.2 | | Amendment No. 2 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of November 21, 2011 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed November 28, 2011) | 3.21.3 | | Amendment No. 3 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of June 12, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed June 17, 2014) | 3.21.4 | | Amendment No. 4 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of July 30, 2014 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed August 4, 2014) | 3.21.5 | | Amendment No. 5 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of August 28, 2015 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No. 1-31219, filed September 1, 2015) | 3.21.6 | | Amendment No. 6 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of October 8, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed October 15, 2015) | 3.21.7 | | Amendment No. 7 to Third Amended and Restated Partnership Agreement of Sunoco Logistics Partners L.P., dated as of September 26, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-31219, filed September 26, 2016) | | | | | | Sunoco LP | 3.28 | | Certificate of Limited Partnership of Susser Petroleum Partners LP (incorporated by reference to Exhibit 3.1 of Form S-1, File No. 333-182276, filed June 22, 2012) | 3.29 | | Certificate of Amendment to the Certificate of Limited Partnership of Susser Petroleum Partners LP (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed October 28, 2014) | 3.30 | | First Amended and Restated Agreement of Limited Partnership of Susser Petroleum Partners LP, dated September 25, 2012 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed September 25, 2012) | 3.31 | | Amendment No. 1 to First Amended and Restated Agreement of Limited Partnership of Susser Petroleum Partners LP, dated October 27, 2014 (incorporated by reference to Exhibit 3.2 of Form 8-K, File No. 1-35653, filed October 28, 2014) | 3.32 | | Amendment No. 2 to First Amended and Restated Agreement of Limited Partnership of Sunoco LP, dated July 31, 2015 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed August 6, 2015) |
| | | | Exhibit
Number
| | Description | 3.33 | | Amendment No. 3 to First Amended and Restated Agreement of Limited Partnership of Sunoco LP, dated January 1, 2016 (incorporated by reference to Exhibit 3.1 of Form 8-K, File No. 1-35653, filed January 5, 2016) | | | | | | Energy Transfer Equity, L.P. | 4.1 | | Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.14 of Form 8-K, File No. 1-32740, filed September 20, 2010) | 4.2 | | First Supplemental Indenture, dated September 20, 2010 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, File No. 1-32740, filed September 20, 2010) | 4.3 | | Second Supplemental Indenture, dated December 20, 2011 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form S-3, File No. 1-32740, filed November 14, 2013) | 4.4 | | Second Supplemental Indenture, dated February 16, 2012 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-32740, filed February 17, 2012) | 4.5 | | Third Supplemental Indenture, dated April 24, 2012 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.15 of Form 8-K, File No. 1-32740, filed September 20, 2010) | 4.6 | | Fourth Supplemental Indenture, dated December 2, 2013 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed December 2, 2013) | 4.7 | | Fifth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 28, 2014) | 4.8 | | Sixth Supplemental Indenture, dated May 28, 2014 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-32740, filed May 28, 2014) | 4.9 | | Seventh Supplemental Indenture, dated May 22, 2015 between Energy Transfer Equity, L.P. and U.S. Bank National Association, as trustee (including form of the Notes) (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-32740, filed May 22, 2015) | | | | | | Energy Transfer Partners, L.P. | 4.10 | | Indenture, dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-11727, filed January 19, 2005) | 4.11 | | First Supplemental Indenture, dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed January 19, 2005) | 4.12 | | Second Supplemental Indenture, dated February 24, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association (incorporated by reference to Exhibit 10.45 of Form 10-Q, File No. 1-11727, filed February 28, 2005) | 4.13 | | Fourth Supplemental Indenture, dated June 29, 2006 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.13 of Form 10-K File No. 1-11727, filed August 31, 2006) | 4.14 | | Fifth Supplemental Indenture, dated October 23, 2006 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of ETP’s Form 8-K filed October 25, 2006) | 4.15 | | Sixth Supplemental Indenture, dated March 28, 2008 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K File No. 1-11727, filed March 28, 2008) | 4.16 | | Seventh Supplemental Indenture, dated December 23, 2008 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed December 23, 2008) | 4.17 | | Eighth Supplemental Indenture, dated April 7, 2009 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed April 7, 2009) | 4.18 | | Ninth Supplemental Indenture, dated May 12, 2011 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 to Form 8-K, File No. 1-11727, filed May 12, 2011) |
| | | | Exhibit
Number
| | Description | 4.19 | | Tenth Supplemental Indenture, dated January 17, 2012 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 1.1 of Form 8-K, File No. 1-11727, filed January 17, 2012) | 4.20 | | Eleventh Supplemental Indenture, dated January 22, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed January 22, 2013) | 4.21 | | Twelfth Supplemental Indenture, dated June 24, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed June 26, 2013) | 4.22 | | Thirteenth Supplemental Indenture, dated September 19, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed September 19, 2013) | 4.23 | | Fourteenth Supplemental Indenture, dated as of March 12, 2015 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-11727, filed March 12, 2015) | 4.24 | | Fifteenth Supplemental Indenture, dated as of June 23, 2015 between Energy Transfer Partners, L.P. and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-11727, filed June 18, 2015) | 4.25 | | Indenture, dated June 24, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-11727, filed June 26, 2013) | 4.26 | | First Supplemental Indenture, dated June 24, 2013 between Energy Transfer Partners, L.P. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-11727, filed June 26, 2013) | 4.27 | | Second Amended and Restated Credit Agreement, dated October 27, 2011, among Energy Transfer Partners, L.P., the borrower, and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A., as syndication agent, BNP Paribas, JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland PLC, as co-documentation agents, and Citibank, N.A., Credit Suisse, Cayman Islands Branch, Deutsche Bank Securities, Inc., Morgan Stanley Bank, Suntrust Bank and UBS Securities, LLC, as senior managing agents, and the other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 2, 2011) | 4.28 | | First Amendment to Second Amended and Restated Credit Agreement, dated November 19, 2013, among Energy Transfer Partners, L.P., Wells Fargo Bank, National Association, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 20, 2013) | 4.29 | | Guarantee of Collection, made as of March 26, 2012, by Citrus ETP Finance LLC, to Energy Transfer Partners, L.P. under the Indenture dated as of January 18, 2005, as supplemented by the Tenth Supplemental Indenture dated as of January 17, 2012 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed March 28, 2012) | 4.30 | | Support Agreement, dated March 26, 2012, by and among PEPL Holdings, LLC, Energy Transfer Partners, L.P. and Citrus ETP Finance LLC (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed March 28, 2012) | 4.31 | | Guarantee of Collection, made as of April 1, 2015, by ETP Retail Holdings, LLC, to Sunoco LP and Sunoco Finance Corp. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed April 1, 2015) | 4.32 | | Support Agreement, made as of April 1, 2015, by and among Sunoco, Inc. (R&M), Sunoco LP, Sunoco Finance Corp. and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-11727, filed April 1, 2015) | 4.33 | | Support Agreement, made as of April 1, 2015, by and among Atlantic Refining & Marketing Corp., Sunoco LP, Sunoco Finance Corp. and ETP Retail Holdings, LLC (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 1-11727, filed April 1, 2015) | 4.34 | | Note Purchase Agreement, dated as of November 17, 2004, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.55 of Form 10-Q, File No. 1-11727, filed May 31, 2007) | 4.35 | | Amendment No. 1 to the Note Purchase Agreement, dated as of April 18, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.55.1 of Form 10-Q, File No. 1-11727, filed May 31, 2007) | 4.36 | | Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.6 of Form 10-Q, File No. 1-11727, filed May 31, 2007) | 4.37 | | Note Purchase Agreement, dated December 9, 2009, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed December 14, 2009) |
| | | | Exhibit
Number
| | Description | 4.38 | | Indenture, dated as of June 30, 2000 between Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.39 | | First Supplemental Indenture, dated October 5, 2012 among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.7 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.40 | | Indenture, dated May 15, 1994 between Sun Company, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.8 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.41 | | First Supplemental Indenture, dated October 5, 2012 among Energy Transfer Partners, L.P., Sunoco, Inc. and U.S. Bank National Association, as successor trustee to Citibank, N.A. (incorporated by reference to Exhibit 4.9 of Form 8-K, File No. 1-11727, filed October 5, 2012) | 4.42 | | Indenture, dated October 27, 2010 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 0-51757, filed October 27, 2010) | 4.43 | | Third Supplemental Indenture, dated May 26, 2011 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 0-51757, filed May 26, 2011) | 4.44 | | Fifth Supplemental Indenture, dated October 2, 2012 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-35262, filed October 2, 2012) | 4.45 | | Eleventh Supplemental Indenture, dated as of April 30, 2015 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed April 30, 2015) | 4.46 | | Twelfth Supplemental Indenture, dated as of August 10, 2015 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed August 13, 2015) | 4.47 | | Indenture, dated April 30, 2013 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-11727, filed April 30, 2013) | 4.48 | | Seventh Supplemental Indenture, dated as of May 28, 2015 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Panhandle Eastern Pipe Line Company, LP, Energy Transfer Partners, L.P., as co-obligor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed June 1, 2015) | 4.49 | | Eighth Supplemental Indenture, dated as of August 10, 2015 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed August 13, 2015) | 4.50 | | Indenture, dated September 11, 2013 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35262, filed September 11, 2013) | 4.51 | | First Supplemental Indenture, dated September 11, 2013 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-35262, filed September 11, 2013) | 4.52 | | Third Supplemental Indenture, dated February 10, 2014 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.3 of Form 8-K, File No. 1-35262, filed February 10, 2014) | 4.53 | | Sixth Supplemental Indenture, dated as of July 25, 2014 among Regency Energy Partners LP, Regency Energy Finance Corp., the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-35262, filed July 28, 2014) | 4.54 | | Eighth Supplemental Indenture, dated as of April 30, 2015 by and among Regency Energy Partners LP, Regency Energy Finance Corp., the subsidiary guarantors party thereto, Energy Transfer Partners, L.P., as parent guarantor, and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.4 of Form 8-K, File No. 1-11727, filed April 30, 2015) | 4.55 | | Ninth Supplemental Indenture, dated as of August 10, 2015 by and among Energy Transfer Partners, L.P., Regency Energy Finance Corp. and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-11727, filed August 13, 2015) |
| | | | Exhibit
Number
| | Description | 4.56 | | Indenture, dated as of March 29, 1999 among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company, LP and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4(a) of Form 10-Q, File No. 1-02921, filed May 14, 1999) | 4.57 | | First Supplemental Indenture, dated as of March 29, 1999 among CMS Panhandle Holding Company, Panhandle Eastern Pipe Line Company, LP and NBD Bank (the predecessor to Bank One Trust Company, National Association, J.P. Morgan Trust Company, National Association, The Bank of New York Trust Company, N.A. and The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4(b) of Form 10-Q, File No. 1-02921, filed May 14, 1999) | 4.58 | | Fifth Supplemental Indenture, dated as of October 26, 2007 between Panhandle Eastern Pipe Line Company, LP and the Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-02921, filed October 29, 2007) | 4.59 | | Form of Sixth Supplemental Indenture, dated as of June 12, 2008 between Panhandle Eastern Pipe Line Company, LP and the Bank of New York Trust Company, N.A. (now known as The Bank of New York Mellon Trust Company, N.A.), as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-02921, filed June 11, 2008) | 4.60 | | Form of Seventh Supplemental Indenture, dated June 2, 2009 between Panhandle Eastern Pipeline Company, LP and the Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-02921, filed May 28, 2009) | 4.61 | | Senior Debt Securities Indenture between Southern Union Company and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company N.A., as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-06407, filed February 15, 1994) | 4.62 | | Form of Supplemental Indenture No. 1, dated June 11, 2003 between Southern Union Company and JP Morgan Chase Bank, which changed its name to JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.5 of Form 8-A/A, File No. 1-06407, filed June 20, 2003) | 4.63 | | Supplemental Indenture No. 2, dated February 11, 2005 between Southern Union Company and JP Morgan Chase Bank, N.A., the predecessor to The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.4 of Form 8-A/A, File No. 1-06407, filed February 22, 2005) | 4.64 | | Subordinated Debt Securities Indenture between Southern Union and The Chase Manhattan Bank (National Association), which changed its name to JP Morgan Chase Bank and then to JP Morgan Chase Bank, N.A., which was then succeeded to by The Bank of New York Trust Company, N.A., which changed its name to The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4-G of Form S-3, File No. 033-58297, filed May 8, 1995) | 4.65 | | Second Supplemental Indenture, dated October 23, 2006 between Southern Union Company and The Bank of New York Trust Company, N.A., now known as The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to Exhibit 4.1 of Form 8-K/A, File No. 1-06407, filed October 24, 2006) | 4.66 | | 2006 Series A Junior Subordinated Notes Due November 1, 2066, dated October 23, 2006 (incorporated by reference to Exhibit 4.2 of Form 8-K/A, File No. 1-06407, filed October 24, 2006) | | | | | | Sunoco Logistics Partners L.P. | 4.67 | | Indenture, dated December 16, 2005 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P., the subsidiary guarantors named therein and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form S-3, File No. 333-13056, filed December 21, 2005) | 4.68 | | First Supplemental Indenture, dated as of May 8, 2006 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P., Sunoco Partners Marketing & Terminals L.P., Sunoco Pipeline L.P. and Citibank, N.A., (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed May 8, 2006) | 4.69 | | Third Supplemental Indenture, dated as of February 12, 2010 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed February 12, 2010) | 4.70 | | Fourth Supplemental Indenture, dated as of February 12, 2010 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed February 12, 2010) | 4.71 | | Fifth Supplemental Indenture, dated as of August 2, 2011 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.2 of Form 8-K, File No. 1-31219, filed August 2, 2011) |
| | | | Exhibit
Number
| | Description | 4.72 | | Sixth Supplemental Indenture, dated as of August 2, 2011 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 1.3 of Form 8-K, File No. 1-31219, filed August 2, 2011) | 4.73 | | Seventh Supplemental Indenture, dated January 10, 2013 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed January 10, 2013) | 4.74 | | Eighth Supplemental Indenture, dated January 10, 2013 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed January 10, 2013) | 4.75 | | Ninth Supplemental Indenture, dated April 3, 2014 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed April 3, 2014) | 4.76 | | Tenth Supplemental Indenture, dated April 3, 2014 among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed April 3, 2014) | 4.77 | | Eleventh Supplemental Indenture, dated as of November 17, 2014 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association, as successor trustee (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed November 17, 2014) | 4.78 | | Twelfth Supplemental Indenture, dated as of November 17, 2015 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 4.2 of Form 8-K, File No. 1-31219, filed November 17, 2015) | 4.79 | | Thirteenth Supplemental Indenture, dated as of November 17, 2015 by and among Sunoco Logistics Partners Operations L.P., Sunoco Logistics Partners L.P. and U.S. Bank National Association (incorporated by reference to Exhibit 4.4 of Form 8-K, File No. 1-31219, filed November 17, 2015) | 4.80 | | Unitholder Agreement, dated as of October 8, 2015, between Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P. (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-31219, filed October 2, 2015) | | | | | | Sunoco LP | 4.81 | | Indenture, dated as of April 1, 2015, by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35653, filed on April 2, 2015) | 4.82 | | Indenture, dated as of July 20, 2015 by and among Sunoco LP, Sunoco Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35653, filed July 21, 2015) | | | | | | Energy Transfer Equity, L.P. | 10.1+ | | Energy Transfer Equity, L.P. Long-Term Incentive Plan (incorporated by reference to Exhibit 10.25 of Form S-1, File No. 333-128097, filed December 20, 2005) | 10.2+ | | Form of Director and Officer Indemnification Agreement (incorporated by reference to Exhibit 10.26 of Form S-1, File No. 333-128097, filed December 20, 2005) | 10.3 | | Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P. (incorporated by reference to Exhibit 10.38 of Form 10-K, File No. 1-32740, filed November 29, 2006) | 10.4 | | Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed November 30, 2006) | 10.5+ | | LE GP, LLC Outside Director Compensation Policy (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed December 26, 2006) | 10.6 | | Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein (incorporated by reference to Exhibit 99.1 of Form 8-K, File No. 1-32740, filed March 5, 2007) | 10.7 | | Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P. (incorporated by reference to Exhibit 10.45 of Form 8-K, File No. 1-32740, filed May 7, 2007) | 10.8 | | Letter Agreement, dated as of April 29, 2012, by and among Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed May 1, 2012) |
| | | | Exhibit
Number
| | Description | 10.9 | | First Amendment, dated April 30, 2013, to the Services Agreement, effective as of May 26, 2010, by and among Energy Transfer Equity, L.P., ETE Services Company LLC and Regency Energy Partners LP (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed May 1, 2013) | 10.10 | | Second Amendment, dated April 30, 2013, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010, by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.(incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-32740, filed May 1, 2013) | 10.11 | | Third Amendment, dated February 19, 2014, to the Shared Services Agreement dated as of August 26, 2005, as amended May 26, 2010 and April 30, 2013 by and between Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P. (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 19, 2014) | 10.12 | | Exchange and Redemption Agreement by and among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and ETE Common Holdings, LLC, dated August 7, 2013 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed August 8, 2013) | 10.13 | | Credit Agreement, dated as of December 2, 2013 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 2, 2013) | 10.14 | | Second Amended and Restated Pledge and Security Agreement, dated December 2, 2013 among Energy Transfer Equity, L.P., the other grantors named therein and U.S. Bank National Association, as collateral agent (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-32740, filed December 2, 2013) | 10.15 | | Energy Transfer Equity, L.P. Incremental Loan Agreement No. 1, dated April 16, 2014 (incorporated by reference to Exhibit 10.5 of Form 10-Q, File No. 1-32470, filed August 7, 2014) | 10.16 | | Amendment and Incremental Commitment Agreement No. 2, dated May 6, 2014 (incorporated by reference to Exhibit 10.6 of Form 10-Q, File No. 1-32470, filed August 7, 2014) | 10.17 | | Amendment and Incremental Commitment Agreement No. 3, dated February 10, 2015 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 17, 2015) | 10.18 | | Class D Unit Agreement (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed December 27, 2013) | 10.19*+ | | Retention Agreement, by and among Energy Transfer Equity, L.P. and Thomas P. Mason, dated February 24, 2016. | 10.20 | | Senior Secured Term Loan Agreement, dated February 2, 2017 among Energy Transfer Equity, L.P., Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-32740, filed February 3, 2017. |
| | | | | | | | Energy Transfer Partners, L.P. | 10.22 | | Cushion Gas Litigation Agreement, dated January 26, 2005, among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and LaGrange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed February 1, 2005) | 10.23 | | Second Amended and Restated Credit Agreement, dated October 27, 2011, among Energy Transfer Partners, L.P., the borrower, and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A., as syndication agent, BNP Paribas, JPMorgan Chase Bank, N.A. and the Royal Bank of Scotland PLC, as co-documentation agents, and Citibank, N.A., Credit Suisse, Cayman Islands Branch, Deutsche Bank Securities, Inc., Morgan Stanley Bank, Suntrust Bank and UBS Securities, LLC, as senior managing agents, and other lenders party hereto (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 2, 2011) | 10.24 | | Redemption Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and CCE Holdings, LLC (incorporated by reference to Exhibit 10.2 of Form 8-K, File No. 1-11727, filed September 18, 2006) | 10.25 | | Letter Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and Southern Union Company (incorporated by reference to Exhibit 10.3 of Form 8-K, File No. 1-11727, filed September 18, 2006) | 10.26+ | | Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan (incorporated by reference to Exhibit 10.6.6 of Form 10-Q, File No. 1-11727, filed August 11, 2008) | 10.27+ | | Energy Transfer Partners, L.P. Second Amended and Restated 2008 Long Term Incentive Plan (incorporated by reference to Exhibit A of Definitive Proxy Statement on Schedule 14A, File No. 1-11727, filed October 24, 2014) | 10.28+ | | Energy Transfer Partners Deferred Compensation Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed March 31, 2010) |
| | | | Exhibit
Number
| | Description | 10.29+ | | Form of Grant Agreement under the Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan and the Energy Transfer Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-11727, filed November 1, 2004) | 10.30+ | | Energy Transfer Partners, L.P. Annual Bonus Plan (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 1-11727, filed August 7, 2014) | 10.31+ | | Energy Transfer Partners, L.L.C. Annual Bonus Plan effective January 1, 2014 (incorporated by reference to Exhibit 10.2 of Form 10-Q, File No. 1-11727, filed August 7, 2014) | | | | | | Sunoco Logistics Partners L.P. | 10.32 | | $2,500,000,000 Amended and Restated Credit Agreement, dated as of March 20, 2015, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swingline Lender and a L/C Issuer; and the other LC Issuers and Lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed May 7, 2015) | 10.33 | | Amendment No. 1 to the $2,500,000,000 Amended and Restated Credit Agreement, dated as of June 29, 2015, among Sunoco Logistics Partners Operations L.P., as the Borrower; Sunoco Logistics Partners L.P., as the Guarantor; Citibank, N.A., as Administrative Agent, Swing Line Lender and a L/C Issuer; and the other LC Issuers and Lenders party thereto (incorporated by reference to Exhibit 10.1 of Form 10-Q, File No. 1-31219, filed August 6, 2015) | | | | | | Sunoco LP | 10.34 | | Credit Agreement among Susser Petroleum Partners LP, as the Borrower, the lenders from time to time party thereto and Bank of America, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and an LC Issuer, dated September 25, 2014 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-35653, filed October 1, 2014) | 10.35 | | First Amendment to Credit Agreement and Increase Agreement by and among Sunoco LP, Bank of America, N.A., as Administrative Agent, Collateral Agent, Swingline Lender and an LC Issuer, and the financial institutions parties thereto, dated April 10, 2015 (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-35653, filed April 13, 2015) | 10.36 | | Second Amendment to Credit Agreement, dated as of December 2, 2015, by and among Sunoco LP, Bank of America, N.A. and the financial institutions parties thereto as Lenders (incorporated by reference to Exhibit 10.1 of Form 8-K, File No. 1-35653, filed December 8, 2015) | 10.37 | | Registration Rights Agreement, dated as of December 3, 2015, by and among Sunoco LP and the purchasers named on Schedule A thereto (incorporated by reference to Exhibit 4.1 of Form 8-K, File No. 1-35653, filed December 8, 2015) | | | | | | Other Exhibits | 12.1* | | Computation of Ratio of Earnings to Fixed Charges. | 21.1* | | List of Subsidiaries. | 23.1* | | Consent of Grant Thornton LLP related to Energy Transfer Equity, L.P. | 23.2* | | Consent of Grant Thornton LLP related to Energy Transfer Partners, L.P. | 31.1* | | Certification of President (Principal Executive Officer) pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | 31.2* | | Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | 32.1** | | Certification of President (Principal Executive Officer) pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | 32.2** | | Certification Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | 99.1 | | Statement of Policies Relating to Potential Conflicts among Energy Transfer Partners, L.P., Energy Transfer Equity, L.P. and Regency Energy Partners LP dated as of April 26, 2011 (incorporated by reference to Exhibit 99.1 of Form 10-Q, file No. 1-32740, filed August 8, 2011) | 101* | | Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Balance Sheets as of December 31, 2015 and December 31, 2014; (ii) our Consolidated Statements of Operations for the years ended December 31, 2015, 2014 and 2013; (iii) our Consolidated Statements of Comprehensive Income for years ended December 31, 2015, 2014 and 2013; (iv) our Consolidated Statement of Equity for the years ended December 31, 2015, 2014 and 2013; and (v) our Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013. |
| | | * | Filed herewith. | ** | Furnished herewith. | + | Denotes a management contract or compensatory plan or arrangement. |
INDEX TO FINANCIAL STATEMENTS Energy Transfer Equity, L.P. and Subsidiaries
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Partners
Board of Directors of LE GP, LLC and Unitholders of Energy Transfer Equity, L.P. WeOpinion on the financial statements
We have audited the accompanying consolidated balance sheets of Energy Transfer Equity, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 20162017 and 2015, and2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)“financial statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Equity, L.P. and subsidiariesthe Partnership as of December 31, 20162017 and 2015,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20162017, in conformity with accounting principles generally accepted in the United States of America. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2016,2017, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”), and our report dated February 24, 201723, 2018 expressed an unqualified opinion thereon. Change in accounting principle As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories. Basis for opinion These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Partnership’s auditor since 2004.
Dallas, Texas February 24, 201723, 2018
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016* | ASSETS | | | | | | | Current assets: | | | | | | | Cash and cash equivalents | $ | 483 |
| | $ | 606 |
| $ | 336 |
| | $ | 467 |
| Accounts receivable, net | 3,557 |
| | 2,400 |
| 4,504 |
| | 3,557 |
| Accounts receivable from related companies | 47 |
| | 119 |
| 53 |
| | 47 |
| Inventories | 2,291 |
| | 1,636 |
| 2,022 |
| | 2,055 |
| Income taxes receivable | | 136 |
| | 128 |
| Derivative assets | 21 |
| | 46 |
| 24 |
| | 21 |
| Other current assets | 586 |
| | 603 |
| 295 |
| | 447 |
| Current assets held for sale | | 3,313 |
| | 177 |
| Total current assets | 6,985 |
| | 5,410 |
| 10,683 |
| | 6,899 |
| | | | | | | | Property, plant and equipment | 63,721 |
| | 54,979 |
| 71,177 |
| | 61,562 |
| Accumulated depreciation and depletion | (8,283 | ) | | (6,296 | ) | (10,089 | ) | | (7,984 | ) | | 55,438 |
| | 48,683 |
| 61,088 |
| | 53,578 |
| | | | | | | | Advances to and investments in unconsolidated affiliates | 3,040 |
| | 3,462 |
| 2,705 |
| | 3,040 |
| Other non-current assets, net | 818 |
| | 730 |
| 886 |
| | 815 |
| Intangible assets, net | 5,992 |
| | 5,431 |
| 6,116 |
| | 5,512 |
| Goodwill | 6,738 |
| | 7,473 |
| 4,768 |
| | 5,670 |
| Non-current assets held for sale | | — |
| | 3,411 |
| Total assets | $ | 79,011 |
| | $ | 71,189 |
| $ | 86,246 |
| | $ | 78,925 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | | | | Current liabilities: | | | | | | | Accounts payable | $ | 3,502 |
| | $ | 2,274 |
| $ | 4,685 |
| | $ | 3,502 |
| Accounts payable to related companies | 42 |
| | 28 |
| 31 |
| | 42 |
| Derivative liabilities | 172 |
| | 69 |
| 111 |
| | 172 |
| Accrued and other current liabilities | 2,367 |
| | 2,408 |
| 2,582 |
| | 2,367 |
| Current maturities of long-term debt | 1,194 |
| | 131 |
| 413 |
| | 1,194 |
| Current liabilities held for sale | | 75 |
| | — |
| Total current liabilities | 7,277 |
| | 4,910 |
| 7,897 |
| | 7,277 |
| | | | | | | | Long-term debt, less current maturities | 42,608 |
| | 36,837 |
| 43,671 |
| | 42,608 |
| Long-term notes payable - related companies | 250 |
| | — |
| | Long-term notes payable - related company | | — |
| | 250 |
| Deferred income taxes | 5,112 |
| | 4,590 |
| 3,315 |
| | 5,112 |
| Non-current derivative liabilities | 76 |
| | 137 |
| 145 |
| | 76 |
| Other non-current liabilities | 1,123 |
| | 1,069 |
| 1,217 |
| | 1,075 |
| Liabilities associated with assets held for sale | | — |
| | 48 |
| | | | | | | | Commitments and contingencies |
|
| |
|
|
|
| |
|
| Preferred units of subsidiary (Note 7) | 33 |
| | 33 |
| — |
| | 33 |
| Redeemable noncontrolling interests | 15 |
| | 15 |
| 21 |
| | 15 |
| | | | | | | | Equity: | | | | | | | General Partner | (3 | ) | | (2 | ) | (3 | ) | | (3 | ) | Limited Partners: | | | | | | | Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) | (1,871 | ) | | (952 | ) | | Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015) | — |
| | 22 |
| | Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016) | 180 |
| | — |
| | Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively) | | (1,643 | ) | | (1,871 | ) | Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016) | | 450 |
| | 180 |
| Accumulated other comprehensive loss | | — |
| | — |
| Total partners’ deficit | (1,694 | ) | | (932 | ) | (1,196 | ) | | (1,694 | ) | Noncontrolling interest | 24,211 |
| | 24,530 |
| 31,176 |
| | 24,125 |
| Total equity | 22,517 |
| | 23,598 |
| 29,980 |
| | 22,431 |
| Total liabilities and equity | $ | 79,011 |
| | $ | 71,189 |
| $ | 86,246 |
| | $ | 78,925 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in millions, except per unit data) | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | | | | | | Natural gas sales | $ | 3,619 |
| | $ | 3,671 |
| | $ | 5,386 |
| $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 4,841 |
| | 3,935 |
| | 5,845 |
| 6,972 |
| | 4,841 |
| | 3,935 |
| Crude sales | 6,766 |
| | 8,378 |
| | 16,416 |
| 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,172 |
| | 4,200 |
| | 3,733 |
| 4,435 |
| | 4,172 |
| | 4,200 |
| Refined product sales | 14,020 |
| | 15,672 |
| | 19,437 |
| 11,975 |
| | 10,097 |
| | 11,321 |
| Other | 4,086 |
| | 6,270 |
| | 4,874 |
| 2,785 |
| | 2,297 |
| | 4,591 |
| Total revenues | 37,504 |
| | 42,126 |
| | 55,691 |
| 40,523 |
| | 31,792 |
| | 36,096 |
| COSTS AND EXPENSES: | | | | | | | | | | | Cost of products sold | 28,656 |
| | 34,009 |
| | 48,414 |
| 30,966 |
| | 23,693 |
| | 28,668 |
| Operating expenses | 2,696 |
| | 2,661 |
| | 2,102 |
| 2,644 |
| | 2,307 |
| | 2,303 |
| Depreciation, depletion and amortization | 2,359 |
| | 2,079 |
| | 1,724 |
| 2,554 |
| | 2,216 |
| | 1,951 |
| Selling, general and administrative | 807 |
| | 639 |
| | 611 |
| 607 |
| | 693 |
| | 548 |
| Impairment losses | 1,487 |
| | 339 |
| | 370 |
| 1,039 |
| | 1,040 |
| | 339 |
| Total costs and expenses | 36,005 |
| | 39,727 |
| | 53,221 |
| 37,810 |
| | 29,949 |
| | 33,809 |
| OPERATING INCOME | 1,499 |
| | 2,399 |
| | 2,470 |
| 2,713 |
| | 1,843 |
| | 2,287 |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | Interest expense, net | (1,832 | ) | | (1,643 | ) | | (1,369 | ) | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Equity in earnings from unconsolidated affiliates | 270 |
| | 276 |
| | 332 |
| 144 |
| | 270 |
| | 276 |
| Impairment of investment in an unconsolidated affiliate | (308 | ) | | — |
| | — |
| | Impairment of investments in unconsolidated affiliates | | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | 83 |
| | — |
| | — |
| — |
| | 83 |
| | — |
| Gain on sale of AmeriGas common units | — |
| | — |
| | 177 |
| | Losses on extinguishments of debt | — |
| | (43 | ) | | (25 | ) | (89 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (12 | ) | | (18 | ) | | (157 | ) | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 124 |
| | 22 |
| | (11 | ) | 214 |
| | 132 |
| | 20 |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE | (176 | ) | | 993 |
| | 1,417 |
| | Income tax expense (benefit) from continuing operations | (217 | ) | | (100 | ) | | 357 |
| | INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX BENEFIT | | 710 |
| | 204 |
| | 900 |
| Income tax benefit from continuing operations | | (1,833 | ) | | (258 | ) | | (123 | ) | INCOME FROM CONTINUING OPERATIONS | 41 |
| | 1,093 |
| | 1,060 |
| 2,543 |
| | 462 |
| | 1,023 |
| Income from discontinued operations | — |
| | — |
| | 64 |
| | Income (loss) from discontinued operations, net of income taxes | | (177 | ) | | (462 | ) | | 38 |
| NET INCOME | 41 |
| | 1,093 |
| | 1,124 |
| 2,366 |
| | — |
| | 1,061 |
| Less: Net income (loss) attributable to noncontrolling interest | (954 | ) | | (96 | ) | | 491 |
| 1,412 |
| | (995 | ) | | (128 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 995 |
| | 1,189 |
| | 633 |
| 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 3 |
| | 3 |
| | 2 |
| 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | 9 |
| | — |
| | — |
| | Convertible Unitholders’ interest in net income | | 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | 3 |
| | 2 |
| — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 983 |
| | $ | 1,183 |
| | $ | 629 |
| $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
| INCOME FROM CONTINUING OPERATIONS PER LIMITED PARTNER UNIT: | | | | | | | | | | | Basic | $ | 0.94 |
| | $ | 1.11 |
| | $ | 0.58 |
| $ | 0.86 |
| | $ | 0.95 |
| | $ | 1.11 |
| Diluted | $ | 0.92 |
| | $ | 1.11 |
| | $ | 0.57 |
| $ | 0.84 |
| | $ | 0.93 |
| | $ | 1.11 |
| NET INCOME PER LIMITED PARTNER UNIT: | | | | | | | | | | | Basic | $ | 0.94 |
| | $ | 1.11 |
| | $ | 0.58 |
| $ | 0.85 |
| | $ | 0.94 |
| | $ | 1.11 |
| Diluted | $ | 0.92 |
| | $ | 1.11 |
| | $ | 0.57 |
| $ | 0.83 |
| | $ | 0.92 |
| | $ | 1.11 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in millions) | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016* | | 2015* | Net income | $ | 41 |
| | $ | 1,093 |
| | $ | 1,124 |
| $ | 2,366 |
| | $ | — |
| | $ | 1,061 |
| Other comprehensive income (loss), net of tax: | | | | | | | | | | | Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | — |
| | — |
| | 3 |
| | Change in value of available-for-sale securities | 2 |
| | (3 | ) | | 1 |
| 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (1 | ) | | 65 |
| | (113 | ) | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | (1 | ) | | (1 | ) | | (2 | ) | — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | 4 |
| | (1 | ) | | (6 | ) | | Change in other comprehensive income (loss) from unconsolidated affiliates | | 1 |
| | 4 |
| | (1 | ) | | 4 |
| | 60 |
| | (117 | ) | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 45 |
| | 1,153 |
| | 1,007 |
| 2,361 |
| | 4 |
| | 1,121 |
| Less: Comprehensive income (loss) attributable to noncontrolling interest | (950 | ) | | (41 | ) | | 388 |
| 1,407 |
| | (991 | ) | | (68 | ) | Comprehensive income attributable to partners | $ | 995 |
| | $ | 1,194 |
| | $ | 619 |
| $ | 954 |
| | $ | 995 |
| | $ | 1,189 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (Dollars in millions) | | | General Partner | | Common Unitholders | | Class D Units | | Series A Convertible Preferred Units | | Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interest | | Total | General Partner | | Common Unitholders | | Class D Units | | Series A Convertible Preferred Units | | Accumulated Other Comprehensive Income (Loss) | | Non- controlling Interest | | Total | Balance, December 31, 2013 | $ | (3 | ) | | $ | 1,066 |
| | $ | 6 |
| | $ | — |
| | $ | 9 |
| | $ | 15,201 |
| | $ | 16,279 |
| | Distributions to partners | (2 | ) | | (817 | ) | | (2 | ) | | — |
| | — |
| | — |
| | (821 | ) | | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (1,905 | ) | | (1,905 | ) | | Subsidiary units issued for cash | — |
| | 148 |
| | 2 |
| | — |
| | — |
| | 2,907 |
| | 3,057 |
| | Subsidiary units issued in certain acquisitions | — |
| | 211 |
| | — |
| | — |
| | — |
| | 5,604 |
| | 5,815 |
| | Subsidiary units redeemed in Lake Charles LNG Transaction | 2 |
| | 480 |
| | — |
| | — |
| | — |
| | (482 | ) | | — |
| | Purchase of additional Regency Units | — |
| | (99 | ) | | — |
| | — |
| | — |
| | 99 |
| | — |
| | Subsidiary acquisition of a noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (319 | ) | | (319 | ) | | Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | — |
| | 14 |
| | — |
| | — |
| | 51 |
| | 65 |
| | Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 139 |
| | 139 |
| | Other, net | — |
| | 30 |
| | — |
| | — |
| | — |
| | (33 | ) | | (3 | ) | | Units repurchased under buyback program | — |
| | (1,000 | ) | | — |
| | — |
| | — |
| | — |
| | (1,000 | ) | | Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | — |
| | (14 | ) | | (103 | ) | | (117 | ) | | Net income | 2 |
| | 629 |
| | 2 |
| | — |
| | — |
| | 491 |
| | 1,124 |
| | Balance, December 31, 2014 | (1 | ) | | 648 |
| | 22 |
| | — |
| | (5 | ) | | 21,650 |
| | 22,314 |
| | Balance, December 31, 2014* | | (1 | ) | | 648 |
| | 22 |
| | — |
| | (5 | ) | | 21,637 |
| | 22,301 |
| Distributions to partners | (3 | ) | | (1,084 | ) | | (3 | ) | | — |
| | — |
| | — |
| | (1,090 | ) | (3 | ) | | (1,084 | ) | | (3 | ) | | — |
| | — |
| | — |
| | (1,090 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (2,335 | ) | | (2,335 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (2,335 | ) | | (2,335 | ) | Subsidiary units issued | (1 | ) | | (524 | ) | | (1 | ) | | — |
| | — |
| | 4,415 |
| | 3,889 |
| (1 | ) | | (524 | ) | | (1 | ) | | — |
| | — |
| | 4,415 |
| | 3,889 |
| Conversion of Class D Units to ETE Common Units | — |
| | 7 |
| | (7 | ) | | — |
| | — |
| | — |
| | — |
| — |
| | 7 |
| | (7 | ) | | — |
| | — |
| | — |
| | — |
| Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | — |
| | 8 |
| | — |
| | — |
| | 62 |
| | 70 |
| — |
| | — |
| | 8 |
| | — |
| | — |
| | 62 |
| | 70 |
| Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | 875 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | 875 |
| Units repurchased under buyback program | — |
| | (1,064 | ) | | — |
| | — |
| | — |
| | — |
| | (1,064 | ) | — |
| | (1,064 | ) | | — |
| | — |
| | — |
| | — |
| | (1,064 | ) | Acquisition and disposition of noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (65 | ) | | (65 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (65 | ) | | (65 | ) | Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 5 |
| | 55 |
| | 60 |
| — |
| | — |
| | — |
| | — |
| | 5 |
| | 55 |
| | 60 |
| Other, net | — |
| | (118 | ) | | — |
| | — |
| | — |
| | (31 | ) | | (149 | ) | — |
| | (118 | ) | | — |
| | — |
| | — |
| | (31 | ) | | (149 | ) | Net income (loss) | 3 |
| | 1,183 |
| | 3 |
| | — |
| | — |
| | (96 | ) | | 1,093 |
| 3 |
| | 1,183 |
| | 3 |
| | — |
| | — |
| | (128 | ) | | 1,061 |
| Balance, December 31, 2015 | (2 | ) | | (952 | ) | | 22 |
| | — |
| | — |
| | 24,530 |
| | 23,598 |
| | Balance, December 31, 2015* | | (2 | ) | | (952 | ) | | 22 |
| | — |
| | — |
| | 24,485 |
| | 23,553 |
| Distributions to partners | (3 | ) | | (1,019 | ) | | — |
| | — |
| | — |
| | — |
| | (1,022 | ) | (3 | ) | | (1,019 | ) | | — |
| | — |
| | — |
| | — |
| | (1,022 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (2,795 | ) | | (2,795 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (2,795 | ) | | (2,795 | ) | Distributions reinvested | — |
| | (173 | ) | | — |
| | 173 |
| | — |
| | — |
| | — |
| — |
| | (173 | ) | | — |
| | 173 |
| | — |
| | — |
| | — |
| Subsidiary units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | 2,559 |
| | 2,559 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 2,559 |
| | 2,559 |
| Subsidiary units issued for acquisition | — |
| | — |
| | — |
| | — |
| | — |
| | 307 |
| | 307 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 307 |
| | 307 |
| Issuance of common units | — |
| | 39 |
| |
|
| | (2 | ) | | — |
| | — |
| | 37 |
| — |
| | 39 |
| |
|
| | (2 | ) | | — |
| | — |
| | 37 |
| Non-cash compensation expense, net of units tendered by employees for tax withholdings | — |
| | — |
| | (22 | ) | | — |
| | — |
| | 74 |
| | 52 |
| — |
| | — |
| | (22 | ) | | — |
| | — |
| | 74 |
| | 52 |
| Capital contributions received from noncontrolling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | 236 |
| Acquisition and disposition of noncontrolling interest | | — |
| | (779 | ) | | — |
| | — |
| | — |
| | — |
| | (779 | ) | PennTex Acquisition | | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | 236 |
| Other comprehensive income, net of tax | | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | 4 |
| Other, net | | (1 | ) | | 30 |
| | — |
| | — |
| | — |
| | 14 |
| | 43 |
| Net income (loss) | | 3 |
| | 983 |
| | — |
| | 9 |
| | — |
| | (995 | ) | | — |
| Balance, December 31, 2016* | | $ | (3 | ) | | $ | (1,871 | ) | | $ | — |
| | $ | 180 |
| | $ | — |
| | $ | 24,125 |
| | $ | 22,431 |
| Distributions to partners | | (2 | ) | | (1,008 | ) | | — |
| | — |
| | — |
| | — |
| | (1,010 | ) | Distributions to noncontrolling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | (2,999 | ) | | (2,999 | ) | Distributions reinvested | | — |
| | (234 | ) | | — |
| | 234 |
| | — |
| | — |
| | — |
| Units issuance | | — |
| | 568 |
| | — |
| | — |
| | — |
| | — |
| | 568 |
| Subsidiary units issued for cash | | — |
| | (55 | ) | | — |
| | (1 | ) | | — |
| | 3,291 |
| | 3,235 |
| Non-cash unit-based compensation expense, net of units tendered by employees for tax withholdings | | — |
| | — |
| | — |
| | — |
| | — |
| | 86 |
| | 86 |
| Capital contributions received from noncontrolling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | 2,202 |
| | 2,202 |
| Other, net | | — |
| | — |
| | — |
| | — |
| | — |
| | (92 | ) | | (92 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Capital contributions received from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | 236 |
| Acquisition and disposition of noncontrolling interest | — |
| | (779 | ) | | — |
| | — |
| | — |
| | — |
| | (779 | ) | PennTex Acquisition | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | 236 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | 4 |
| Other, net | (1 | ) | | 30 |
| | — |
| | — |
| | — |
| | 14 |
| | 43 |
| Net income (loss) | 3 |
| | 983 |
| | — |
| | 9 |
| | — |
| | (954 | ) | | 41 |
| Balance, December 31, 2016 | $ | (3 | ) | | $ | (1,871 | ) | | $ | — |
| | $ | 180 |
| | $ | — |
| | $ | 24,211 |
| | $ | 22,517 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | PennTex unit acquisition | — |
| | (2 | ) | | — |
| | — |
| | — |
| | (278 | ) | | (280 | ) | Sale of Bakken Pipeline interest | — |
| | 42 |
| | — |
| | — |
| | — |
| | 1,958 |
| | 2,000 |
| Sale of Rover Pipeline interest | — |
| | 2 |
| | — |
| | — |
| | — |
| | 1,476 |
| | 1,478 |
| Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | — |
| | — |
| | (5 | ) | | (5 | ) | Net income | 2 |
| | 915 |
| | — |
| | 37 |
| | — |
| | 1,412 |
| | 2,366 |
| Balance, December 31, 2017 | $ | (3 | ) | | $ | (1,643 | ) | | $ | — |
| | $ | 450 |
| | $ | — |
| | $ | 31,176 |
| | $ | 29,980 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in millions) | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | | | | | | Net income | $ | 41 |
| | $ | 1,093 |
| | $ | 1,124 |
| $ | 2,366 |
| | $ | — |
| | $ | 1,061 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | | | | | | Loss (income) from discontinued operations | | 177 |
| | 462 |
| | (38 | ) | Depreciation, depletion and amortization | 2,359 |
| | 2,079 |
| | 1,724 |
| 2,554 |
| | 2,216 |
| | 1,951 |
| Deferred income taxes | (201 | ) | | 242 |
| | (50 | ) | (1,871 | ) | | (177 | ) | | 239 |
| Amortization included in interest expense | 3 |
| | (21 | ) | | (51 | ) | 24 |
| | 3 |
| | (21 | ) | Unit-based compensation expense | 70 |
| | 91 |
| | 82 |
| 99 |
| | 70 |
| | 91 |
| Impairment losses | 1,487 |
| | 339 |
| | 370 |
| 1,039 |
| | 1,040 |
| | 339 |
| Gains on acquisitions | (83 | ) | | — |
| | — |
| — |
| | (83 | ) | | — |
| Gain on sale of AmeriGas common units | — |
| | — |
| | (177 | ) | | Losses on extinguishments of debt | — |
| | 43 |
| | 25 |
| 89 |
| | — |
| | 43 |
| Impairment of investment in an unconsolidated affiliate | 308 |
| | — |
| | — |
| | (Gains) losses on disposal of assets | 8 |
| | (8 | ) | | (1 | ) | | Impairment of investments in unconsolidated affiliates | | 313 |
| | 308 |
| | — |
| Losses on disposal of assets | | — |
| | — |
| | (6 | ) | Equity in earnings of unconsolidated affiliates | (270 | ) | | (276 | ) | | (332 | ) | (144 | ) | | (270 | ) | | (276 | ) | Distributions from unconsolidated affiliates | 268 |
| | 409 |
| | 291 |
| 297 |
| | 268 |
| | 409 |
| Inventory valuation adjustments | (273 | ) | | 249 |
| | 473 |
| (24 | ) | | (97 | ) | | 67 |
| Other non-cash | (239 | ) | | (8 | ) | | (72 | ) | (298 | ) | | (239 | ) | | (8 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (61 | ) | | (1,164 | ) | | (231 | ) | (192 | ) | | (179 | ) | | (872 | ) | Net cash provided by operating activities | 3,417 |
| | 3,068 |
| | 3,175 |
| 4,429 |
| | 3,322 |
| | 2,979 |
| INVESTING ACTIVITIES: | | | | | | | | | | | Proceeds from sale of Bakken Pipeline interest | | 2,000 |
| | — |
| | — |
| Proceeds from sale of Rover Pipeline interest | | 1,478 |
| | — |
| | — |
| Cash paid for acquisition of PennTex noncontrolling interest | | (280 | ) | | — |
| | — |
| Proceeds from sale of noncontrolling interest | — |
| | 64 |
| | — |
| — |
| | — |
| | 64 |
| Proceeds from the sale of AmeriGas common units | — |
| | — |
| | 814 |
| | Cash paid for acquisitions, net of cash received | (1,570 | ) | | (835 | ) | | (2,367 | ) | (303 | ) | | (1,398 | ) | | (777 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | (129 | ) | | — |
| — |
| | — |
| | (129 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (8,092 | ) | | (9,386 | ) | | (5,381 | ) | (8,444 | ) | | (7,771 | ) | | (9,073 | ) | Contributions in aid of construction costs | 71 |
| | 80 |
| | 45 |
| 31 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (68 | ) | | (45 | ) | | (334 | ) | (268 | ) | | (68 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 135 |
| | 128 |
| | 136 |
| 135 |
| | 135 |
| | 128 |
| Proceeds from the sale of discontinued operations | — |
| | — |
| | 77 |
| | Proceeds from the sale of other assets | 43 |
| | 26 |
| | 62 |
| 48 |
| | 35 |
| | 14 |
| Change in restricted cash | 14 |
| | 19 |
| | 172 |
| — |
| | 14 |
| | 19 |
| Other | — |
| | (16 | ) | | (19 | ) | (3 | ) | | — |
| | (16 | ) | Net cash used in investing activities | (9,467 | ) | | (10,094 | ) | | (6,795 | ) | (5,606 | ) | | (8,982 | ) | | (9,735 | ) | FINANCING ACTIVITIES: | | | | | | | | | | | Proceeds from borrowings | 25,785 |
| | 26,455 |
| | 18,375 |
| 31,608 |
| | 25,785 |
| | 26,455 |
| Repayments of long-term debt | (19,076 | ) | | (19,828 | ) | | (13,886 | ) | (31,268 | ) | | (19,076 | ) | | (19,828 | ) | Cash received from affiliate notes | 5,317 |
| | — |
| | — |
| — |
| | 5,317 |
| | — |
| Cash paid on affiliate notes | (5,051 | ) | | — |
| | — |
| (255 | ) | | (5,051 | ) | | — |
| Units issued for cash | | 568 |
| | — |
| | — |
| Subsidiary units issued for cash | 2,559 |
| | 3,889 |
| | 3,057 |
| 3,235 |
| | 2,559 |
| | 3,889 |
| Distributions to partners | (1,022 | ) | | (1,090 | ) | | (821 | ) | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Distributions to noncontrolling interests | (2,766 | ) | | (2,335 | ) | | (1,905 | ) | (2,961 | ) | | (2,766 | ) | | (2,335 | ) | Redemption of ETP Convertible Preferred Units | | (53 | ) | | — |
| | — |
| Debt issuance costs | (52 | ) | | (75 | ) | | (77 | ) | (131 | ) | | (52 | ) | | (75 | ) | Capital contributions from noncontrolling interest | 236 |
| | 841 |
| | 139 |
| 1,214 |
| | 236 |
| | 841 |
| Redemption of Preferred Units | — |
| | — |
| | — |
| | Units repurchased under buyback program | — |
| | (1,064 | ) | | (1,000 | ) | — |
| | — |
| | (1,064 | ) | Other, net | (3 | ) | | (8 | ) | | (5 | ) | 6 |
| | (3 | ) | | (8 | ) | Net cash provided by financing activities | 5,927 |
| | 6,785 |
| | 3,877 |
| 953 |
| | 5,927 |
| | 6,785 |
| Increase (decrease) in cash and cash equivalents | (123 | ) | | (241 | ) | | 257 |
| | Cash and cash equivalents, beginning of period | 606 |
| | 847 |
| | 590 |
| | Cash and cash equivalents, end of period | $ | 483 |
| | $ | 606 |
| | $ | 847 |
| | DISCONTINUED OPERATIONS | | | | | | | Operating activities | | 136 |
| | 93 |
| | 90 |
| Investing activities | | (38 | ) | | (483 | ) | | (360 | ) |
| | | | | | | | | | | | | Changes in cash included in current assets held for sale | (5 | ) | | 5 |
| | (13 | ) | Net increase (decrease) in cash and cash equivalents of discontinued operations | 93 |
| | (385 | ) | | (283 | ) | Decrease in cash and cash equivalents | (131 | ) | | (118 | ) | | (254 | ) | Cash and cash equivalents, beginning of period | 467 |
| | 585 |
| | 839 |
| Cash and cash equivalents, end of period | $ | 336 |
| | $ | 467 |
| | $ | 585 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Tabular dollar and unit amounts, except per unit data, are in millions)
| | 1. | OPERATIONS AND ORGANIZATION: |
Financial Statement Presentation The consolidated financial statements of Energy Transfer Equity, L.P. (the “Partnership,” “we” or “ETE”) presented herein for the years ended December 31, 2017, 2016, 2015, and 2014,2015, have been prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC. We consolidate all majority-owned subsidiaries and limited partnerships, which we control as the general partner or owner of the general partner. All significant intercompany transactions and accounts are eliminated in consolidation. Unless the context requires otherwise, references to “we,” “us,” “our,” the “Partnership” and “ETE” mean Energy Transfer Equity, L.P. and its consolidated subsidiaries, which include ETP, ETP GP, ETP LLC, ETE Common Holdings, LLC, Panhandle, (or Southern Union prior to its merger into Panhandle in January 2014), Sunoco Logistics, Sunoco LP and ETP Holdco.Lake Charles LNG. References to the “Parent Company” mean Energy Transfer Equity, L.P. on a stand-alone basis. As discussed in Note 8, in January 2014 and July 2015, the Partnership completed two-for-one splits of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit splits for all periods presented.
At December 31, 2016, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as 2.6 million ETP common units, 81.0 million ETP Class H units and 2.3 million Sunoco LP common units held by us or our wholly-owned subsidiaries. We also own 0.1% of Sunoco Partners LLC, the entity that owns the general partner interest and IDRs of Sunoco Logistics, while ETP owns the remaining 99.9% of Sunoco Partners LLC. Additionally, ETE owns 100 ETP Class I Units, the distributions from which offset a portion of IDR subsidies ETE has previously provided to ETP.
The consolidated financial statements of ETE presented herein include the results of operations of: the Parent Company; our controlled subsidiaries, ETP and Sunoco LP (see descriptionLP; consolidated subsidiaries of their respective operations below under “Business Operations”); ETP’s and Sunoco LP’s consolidatedour controlled subsidiaries and our wholly-owned subsidiaries that own the general partner interests and IDR interests in ETP and Sunoco LP; and
our wholly-owned subsidiary, Lake Charles LNG. Our subsidiaries also own varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, we apply proportionate consolidation for our interests in these entities. CertainAt January 25, 2018, subsequent to Sunoco LP’s repurchase of the 12 million Sunoco LP Series A Preferred Units held by ETE, our interests in ETP and Sunoco LP consisted of 100% of the respective general partner interests and IDRs, as well as approximately 27.5 million ETP common units, and approximately 2.3 million Sunoco LP common units. Additionally, ETE owns 100 ETP Class I Units, which are currently not entitled to any distributions.
As discussed in Note 8, in July 2015, the Partnership completed a two-for-one split of ETE Common Units. All references to unit and per unit amounts in the consolidated financial statements and in these notes to the consolidated financial statements have been adjusted to reflect the effects of the unit split for all periods presented. In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior period amountsto the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled. In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” Energy Transfer, LP is a wholly-owned subsidiary of Energy Transfer Partners, L.P. For purposes of maintaining clarity, the following references are used herein: References to “ETLP” refer to the entity named Energy Transfer, LP subsequent to the close of the merger;
References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger. The historical common units for ETP presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. For prior periods herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to conform to the 2016 presentation.operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity. Additionally, for prior periods herein, certain balances have been reclassified to assets and liabilities held for sale and certain revenues and expenses to discontinued operations. These reclassifications had no impact on net income or total equity. Business Operations The Parent Company’s principal sources of cash flow are derived from its direct and indirect investments in the limited partner and general partner interests in ETP and Sunoco LP.LP and cash flows from the operations of Lake Charles LNG. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service requirements and distributions to its partners. Parent Company-only assets are not available to satisfy the debts and other obligations of ETE’s subsidiaries. In order to understand the financial condition of the Parent Company on a stand-alone basis, see Note 17 for stand-alone financial information apart from that of the consolidated partnership information included herein. Our financial statements reflect the following reportable business segments:
Investment in ETP, including the consolidated operations of ETP; Investment in Sunoco LP, including the consolidated operations of Sunoco LP; Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and Corporate and Other, including the following: activities of the Parent Company; and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. ETP is a publicly traded partnership whose operations comprise the following: the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales; intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia; interstate pipelines that are owned and operated, either directly or through equity method investments, that transport natural gas to various markets in the United States; and a controlling interest in Sunoco Logistics a publicly traded Delaware limited partnership thatPartners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLNGLs and refined products pipelines.products.
Sunoco LP is a publicly traded partnership engaged in retail sale of motor fuels and merchandise through its company-operated convenience stores and retail fuel sites, as well as the wholesale distribution of motor fuels to convenience stores, independent dealers, commercial customers, and distributors.distributors, as well as the retail sale of motor fuels and merchandise through Sunoco LP operated convenience stores and retail fuel sites. Lake Charles LNG operates a LNG import terminal, which has approximately 9.0 Bcf of above ground LNG storage capacity and re-gasification facilities on Louisiana’s Gulf Coast near Lake Charles, Louisiana. Lake Charles LNG is engaged in interstate commerce and is subject to the rules, regulations and accounting requirements of the FERC. Our financial statements reflect the following reportable business segments:
•Investment in ETP, including the consolidated operations of ETP;
•Investment in Sunoco LP, including the consolidated operations of Sunoco LP;
•Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and
•Corporate and Other including the following:
•activities of the Parent Company; and
the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P.
| | 2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: |
Change in Accounting Policy During the fourth quarter of 2017, ETP elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined product and NGL associated with the legacy Sunoco Logistics business. ETP’s management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method. As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2016 | | Year Ended December 31, 2015 | | As Originally Reported* | | Effect of Change | | As Adjusted | | As Originally Reported* | | Effect of Change | | As Adjusted | Consolidated Statement of Operations and Comprehensive Income: | | | | | | | | | | | | Cost of products sold | $ | 23,652 |
| | $ | 41 |
| | $ | 23,693 |
| | $ | 28,636 |
| | $ | 32 |
| | $ | 28,668 |
| Operating income | 1,884 |
| | (41 | ) | | 1,843 |
| | 2,319 |
| | (32 | ) | | 2,287 |
| Income from continuing operations before income tax benefit | 245 |
| | (41 | ) | | 204 |
| | 932 |
| | (32 | ) | | 900 |
| Net income | 41 |
| | (41 | ) | | — |
| | 1,093 |
| | (32 | ) | | 1,061 |
| Net income (loss) attributable to noncontrolling interest | (954 | ) | | (41 | ) | | (995 | ) | | (96 | ) | | (32 | ) | | (128 | ) | Comprehensive income | 45 |
| | (41 | ) | | 4 |
| | 1,153 |
| | (32 | ) | | 1,121 |
| | | | | | | | | | | | | Consolidated Statements of Cash Flows: | | | | | | | | | | | | Net income | 41 |
| | (41 | ) | | — |
| | 1,093 |
| | (32 | ) | | 1,061 |
| Inventory valuation adjustments | (267 | ) | | 170 |
| | (97 | ) | | 229 |
| | (162 | ) | | 67 |
| Net change in operating assets and liabilities (change in inventories) | (50 | ) | | (129 | ) | | (179 | ) | | (1,066 | ) | | 194 |
| | (872 | ) | | | | | | | | | | | | | Consolidated Balance Sheets (at period end): | | | | | | | | | | | | Inventories | 2,141 |
| | (86 | ) | | 2,055 |
| | 1,498 |
| | (45 | ) | | 1,453 |
| Noncontrolling interest | 24,211 |
| | (86 | ) | | 24,125 |
| | 24,530 |
| | (45 | ) | | 24,485 |
|
* Amounts reflect certain reclassifications made to conform to the current year presentation and include the impact of discontinued operations as discussed in Note 3. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation, amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill
impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. NewRecent Accounting Pronouncements
ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenuefrom Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based
on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2015, the FASB deferred the effective date of The Partnership adopted ASU 2014-09 which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.on January 1, 2018. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively withPartnership applied the cumulative catchup transition method and recognized the cumulative effect of initially applying the guidance recognized atretrospective application of the datestandard. The effect of initialthe retrospective application (the cumulative catchup transition method). The Partnershipof the standard was not material.
For future periods, ETP expects that the adoption of this standard will result in a change to adopt ASU 2014-09revenues with offsetting changes to costs associated primarily with the designation of certain of its midstream agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the first quarteraccounting for noncash consideration in multiple of 2018our reportable segments, as well as fuel usage and will apply the cumulative catchup transition method.loss allowances. None of these changes is expected to have a material impact on net income. We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts mayassociated with Sunoco LP’s operations will be impacted by the adoption of the new standard; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continuecurrently estimate the cumulative catch-up effect to monitor additional authoritative or interpretive guidanceSunoco LP’s retained earnings as of January 1, 2018 to be approximately $54 million. These adjustments are primarily related to the new standard as it becomes available, as well as comparing our conclusions on specific interpretative issues to other peerschange in our industry, to the extent that such information is available to us.recognition of dealer incentives and rebates. ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 is effective for fiscal years beginning after December 15, 2018,in the first quarter of 2019 and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. In October 2016,ASU 2016-16
On January 1, 2018, the FASB issuedPartnership adopted Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluatingWe do not anticipate a material impact to our financial position or results of operations as a result of the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.standard. On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.2017-04
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. Adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill“Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment”.impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit'sunit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance doesdid not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017. ASU 2017-12 In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal
years, beginning after December 15, 2019,2018, with early adoption permitted. We expectThe Partnership is currently evaluating the impact that our adoption ofadopting this new standard will change our approach for testing goodwill for impairment; however, this standard requires prospective applicationhave on the consolidated financial statements and therefore will only impact periods subsequent to adoption.related disclosures. Revenue Recognition Our segments are engaged in multiple revenue-generating activities. To the extent that those activities are similar among our segments, revenue recognition policies are similar. Below is a description of revenue recognition policies for significant revenue-generating activities within our segments.
Investment in ETP Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation.sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. The results of ETP’s intrastate transportation and storage and interstate transportation and storage operations are determined primarily by the amount of capacity customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. ETP’s intrastate transportation and storage operations also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, ETP purchases natural gas from the market, including purchases from ETP’s marketing operations, and from producers at the wellhead. In addition, ETP’s intrastate transportation and storage operations generate revenues and margin from fees charged for storing customers’ working natural gas in ETP’s storage facilities. ETP also engages in natural gas storage transactions in which ETP seeks to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. ETP purchases physical natural gas and then sells financial contracts at a price sufficient to cover ETP’s carrying costs and provide for a gross profit margin. ETP expects margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, ETP cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which ETP operate, competitive factors in the energy industry, and other issues. Results from ETP’s midstream operations are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETP’s pipeline and gathering systems and the level of natural gas and NGL prices. ETP generates midstream revenues and grosssegment margins principally under fee-based or other arrangements in which ETP receives a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through ETP’s systems and is not directly dependent on commodity prices. ETP also utilizes other types of arrangements in ETP’s midstream operations, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which ETP gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where ETP gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing ETP’s plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing objectives. In many cases, ETP provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETP’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. ETP’s contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors.
NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer. In ETP’s natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized.
ETP conducts marketing activities in which ETP markets the natural gas that flows through ETP’s assets, referred to as on-system gas. ETP also attracts other customers by marketing volumes of natural gas that do not move through ETP’s assets, referred to as off-system gas. For both on-system and off-system gas, ETP purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations. Investment in Sunoco LP Revenues from Sunoco LP’s two primary product categories, motor fuel and merchandise, are recognized either at the time fuel is delivered to the customer or at the time of sale. Revenue recognition on consignment sales differ from this and are discussed in greater detail below. Shipment and delivery of motor fuel generally occurs on the same day. Sunoco LP charges its wholesale customers for third-party transportation costs, which are recorded net in cost of sales. Through PropCo, Sunoco LP’s wholly owned corporate subsidiary, Sunoco LP may sell motor fuel to wholesale customers on a consignmentcommission agent basis, in which Sunoco LP retains title to inventory, control access to and sale of fuel inventory, and recognize revenue at the time the fuel is sold to the ultimate customer. Sunoco LP derives other income from rental income, propane and lubricating oils and other ancillary product and service offerings. Sunoco LP derives other income from lottery ticket sales, money orders, prepaid phone cards and wireless services, ATM transactions, car washes, movie rentals and other ancillary product and service offerings. Sunoco LP records revenue on a net commission basis when the product is sold and/or services are rendered. Rental income from operating leases is recognized on a straight line basis over the term of the lease. Investment in Lake Charles LNG Lake Charles LNG’s revenues from storage and re-gasification of natural gas are based on capacity reservation charges and, to a lesser extent, commodity usage charges. Reservation revenues are based on contracted rates and capacity reserved by the customers and recognized monthly. Revenues from commodity usage charges are also recognized monthly and represent the recovery of electric power charges at Lake Charles LNG’s terminal. Regulatory Accounting – Regulatory Assets and Liabilities ETP’s interstate transportation and storage operations are subject to regulation by certain state and federal authorities and certain subsidiaries in those operations have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of ETP’s regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, ETP ceases to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the NGA and NGPA, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs.
Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value.
We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit. The net change in operating assets and liabilities (net of effects of acquisitions, dispositions and deconsolidation) included in cash flows from operating activities was comprised as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Accounts receivable | $ | (1,126 | ) | | $ | 856 |
| | $ | 600 |
| $ | (948 | ) | | $ | (1,126 | ) | | $ | 856 |
| Accounts receivable from related companies | 42 |
| | (5 | ) | | 30 |
| 24 |
| | 42 |
| | (5 | ) | Inventories | (356 | ) | | (430 | ) | | 51 |
| 58 |
| | (480 | ) | | (212 | ) | Other current assets | 149 |
| | (225 | ) | | 151 |
| 38 |
| | 165 |
| | (225 | ) | Other non-current assets, net | (148 | ) | | 250 |
| | (6 | ) | 84 |
| | (148 | ) | | 247 |
| Accounts payable | 1,146 |
| | (1,127 | ) | | (850 | ) | 712 |
| | 1,170 |
| | (1,070 | ) | Accounts payable to related companies | (64 | ) | | 400 |
| | 5 |
| (178 | ) | | (64 | ) | | 400 |
| Exchanges payable | — |
| | — |
| | — |
| | Accrued and other current liabilities | 89 |
| | (697 | ) | | (158 | ) | (97 | ) | | 89 |
| | (697 | ) | Other non-current liabilities | 140 |
| | (261 | ) | | (73 | ) | 106 |
| | 106 |
| | (241 | ) | Derivative assets and liabilities, net | 67 |
| | 75 |
| | 19 |
| 9 |
| | 67 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions | $ | (61 | ) | | $ | (1,164 | ) | | $ | (231 | ) | $ | (192 | ) | | $ | (179 | ) | | $ | (872 | ) |
Non-cash investing and financing activities and supplemental cash flow information were as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | | | | | | Accrued capital expenditures | $ | 930 |
| | $ | 910 |
| | $ | 643 |
| $ | 1,060 |
| | $ | 848 |
| | $ | 910 |
| Net gains (losses) from subsidiary common unit transactions | 16 |
| | (526 | ) | | 744 |
| (56 | ) | | 16 |
| | (526 | ) | NON-CASH FINANCING ACTIVITIES: | | | | | | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | 307 |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | 307 |
| | $ | — |
| Contribution of property, plant and equipment from noncontrolling interest | $ | — |
| | $ | 34 |
| | $ | — |
| | Subsidiary issuances of common units in connection with PVR, Hoover and Eagle Rock Midstream acquisitions | — |
| | — |
| | 4,281 |
| | Subsidiary issuances of common units in connection with the Susser Merger | — |
| | — |
| | 908 |
| | Long-term debt assumed in PVR Acquisition | — |
| | — |
| | 1,887 |
| | Long-term debt exchanged in Eagle Rock Midstream Acquisition | — |
| | — |
| | 499 |
| | Contribution of assets from noncontrolling interest | | 988 |
| | — |
| | 34 |
| SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,922 |
| | $ | 1,800 |
| | $ | 1,416 |
| $ | 1,914 |
| | $ | 1,922 |
| | $ | 1,800 |
| Cash paid for (refund of) income taxes | (229 | ) | | 72 |
| | 345 |
| 50 |
| | (229 | ) | | 72 |
|
Accounts Receivable Our subsidiaries assess the credit risk of their customers and take steps to mitigate risk as necessary. Management reviews accounts receivable and an allowance for doubtful accounts is determined based on the overall creditworthiness of customers, historical write-off experience, general and specific economic trends, and identification of specific customers with payment issues.
Inventories As discussed under “Change in Accounting Policy” in Note 2, ETP changed its accounting policy for certain inventory in the fourth quarter of 2017. Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil refined products and spare parts. Natural gas held in storage isparts, all of which are valued at the lower of cost or marketnet realizable value utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method. Inventories consisted of the following: | | | | | | | | | | December 31, | | 2016 | | 2015 | Natural gas and NGLs | $ | 699 |
| | $ | 415 |
| Crude oil | 683 |
| | 424 |
| Refined products | 540 |
| | 420 |
| Spare parts and other | 369 |
| | 377 |
| Total inventories | $ | 2,291 |
| | $ | 1,636 |
|
During the years ended December 31, 2016 and 2015, the Partnership recorded write-downs of $273 million and $249 million, respectively, on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-downs were calculated based upon current replacement costs. | | | | | | | | | | December 31, | | 2017 | | 2016 | Natural gas, NGLs, and refined products | $ | 1,120 |
| | $ | 1,141 |
| Crude oil | 551 |
| | 651 |
| Spare parts and other | 351 |
| | 263 |
| Total inventories | $ | 2,022 |
| | $ | 2,055 |
|
ETP utilizes commodity derivatives to manage price volatility associated with certain of its natural gas inventory and designates certain of these derivatives as fair value hedges for accounting purposes. Changes in fair value of the designated hedged inventory have been recorded in inventory on our consolidated balance sheets and in cost of products sold in our consolidated statements of operations. Other Current Assets Other current assets consisted of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Deposits paid to vendors | $ | 74 |
| | $ | 74 |
| $ | 64 |
| | $ | 74 |
| Income taxes receivable | 128 |
| | 326 |
| | Prepaid expenses and other | 384 |
| | 203 |
| 231 |
| | 373 |
| Total other current assets | $ | 586 |
| | $ | 603 |
| $ | 295 |
| | $ | 447 |
|
Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Natural gas and NGLs used to maintain pipeline minimum pressures is capitalized and classified as property, plant and equipment. Additionally, our subsidiaries capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. For the Lake Charles LNG project, a portion of the management fees are capitalized. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2017, ETP recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, ETP recorded a $133 million fixed asset impairment related to theits interstate transportation and storage operations primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in ETP’sits midstream operations. In 2015, weETP recorded a $110 million fixed asset impairmentsimpairment related to ETP’s liquidsits NGL and refined products transportation and services operations primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for ourits reporting units during the periods presented.
Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our
revolving credit facilities when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds. Components and useful lives of property, plant and equipment were as follows: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Land and improvements | $ | 1,764 |
| | $ | 686 |
| $ | 2,222 |
| | $ | 1,189 |
| Buildings and improvements (1 to 45 years) | 3,275 |
| | 1,526 |
| 2,786 |
| | 2,247 |
| Pipelines and equipment (5 to 83 years) | 35,593 |
| | 32,677 |
| 44,673 |
| | 36,570 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,515 |
| | 390 |
| 1,681 |
| | 1,451 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,677 |
| | 2,853 |
| 3,883 |
| | 3,701 |
| Tanks and other equipment (5 to 40 years) | 1,286 |
| | 1,488 |
| | Retail equipment (2 to 99 years) | 1,141 |
| | 401 |
| | Vehicles (1 to 25 years) | 241 |
| | 220 |
| 126 |
| | 217 |
| Right of way (20 to 83 years) | 3,374 |
| | 2,573 |
| 3,432 |
| | 3,349 |
| Natural resources | 434 |
| | 484 |
| 434 |
| | 434 |
| Other (1 to 40 years) | 1,031 |
| | 3,837 |
| 1,029 |
| | 2,285 |
| Construction work-in-process | 10,390 |
| | 7,844 |
| 10,911 |
| | 10,119 |
| | 63,721 |
| | 54,979 |
| 71,177 |
| | 61,562 |
| Less – Accumulated depreciation and depletion | (8,283 | ) | | (6,296 | ) | (10,089 | ) | | (7,984 | ) | Property, plant and equipment, net | $ | 55,438 |
| | $ | 48,683 |
| $ | 61,088 |
| | $ | 53,578 |
|
We recognized the following amounts for the periods presented: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 2,089 |
| | $ | 1,776 |
| | $ | 1,457 |
| $ | 2,204 |
| | $ | 1,952 |
| | $ | 1,661 |
| Capitalized interest, excluding AFUDC | 202 |
| | 163 |
| | 113 |
| | Capitalized interest | | 286 |
| | 201 |
| | 164 |
|
Advances to and Investments in Affiliates Certain of our subsidiaries own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: | | | | | | | | | | December 31, | | 2016 | | 2015 | Unamortized financing costs(1) | $ | 13 |
| | $ | 29 |
| Regulatory assets | 86 |
| | 90 |
| Deferred charges | 217 |
| | 198 |
| Restricted funds | 190 |
| | 192 |
| Other | 312 |
| | 221 |
| Total other non-current assets, net | $ | 818 |
| | $ | 730 |
|
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities. | | | | | | | | | | December 31, | | 2017 | | 2016 | Regulatory assets | 85 |
| | 86 |
| Deferred charges | 210 |
| | 217 |
| Restricted funds | 192 |
| | 190 |
| Other | 399 |
| | 322 |
| Total other non-current assets, net | $ | 886 |
| | $ | 815 |
|
Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 6,070 |
| | $ | (981 | ) | | $ | 5,254 |
| | $ | (738 | ) | $ | 6,979 |
| | $ | (1,277 | ) | | $ | 6,050 |
| | $ | (971 | ) | Trade names (15 years) | 818 |
| | (29 | ) | | 559 |
| | (25 | ) | | Patents (9 years) | 48 |
| | (21 | ) | | 48 |
| | (16 | ) | | Other (1 to 15 years) | 42 |
| | (14 | ) | | 15 |
| | (7 | ) | | Trade names (20 years) | | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Patents (10 years) | | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Other (5 to 20 years) | | 28 |
| | (14 | ) | | 25 |
| | (10 | ) | Total amortizable intangible assets | 6,978 |
| | (1,045 | ) | | 5,876 |
| | (786 | ) | 7,121 |
| | (1,342 | ) | | 6,189 |
| | (1,024 | ) | Non-amortizable intangible assets: | | | | | | | | | | | | | | | Trademarks | — |
| | — |
| | 341 |
| | — |
| 295 |
| | — |
| | 288 |
| | — |
| Contractual rights | 43 |
| | — |
| | — |
| | — |
| | Liquor licenses | 16 |
| | — |
| | — |
| | — |
| | Other | | 42 |
| | — |
| | 59 |
| | — |
| Total intangible assets | $ | 7,037 |
| | $ | (1,045 | ) | | $ | 6,217 |
| | $ | (786 | ) | $ | 7,458 |
| | $ | (1,342 | ) | | $ | 6,536 |
| | $ | (1,024 | ) |
Aggregate amortization expense of intangibles assets was as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Reported in depreciation, depletion and amortization | $ | 270 |
| | $ | 303 |
| | $ | 219 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Reported in depreciation, depletion and amortization | $ | 344 |
| | $ | 264 |
| | $ | 290 |
|
Estimated aggregate amortization expense of intangible assets for the next five years was as follows: | | Years Ending December 31: | | | 2017 | $ | 281 |
| | 2018 | 279 |
| $ | 341 |
| 2019 | 275 |
| 338 |
| 2020 | 270 |
| 336 |
| 2021 | 253 |
| 319 |
| 2022 | | 287 |
|
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2016, we recorded $32
Sunoco LP performed impairment tests on their indefinite-lived intangible assets during the fourth quarter of 2017 and recognized $13 million of intangible assetand $4 million impairment related to Sunoco LP’s Laredo Taco Company trade namecharge on their contractual rights and liquor licenses, included in Other in the table above, primarily due to decreases in projected future revenues and cash flows from the date the intangible asset was originally recorded. In 2015, weETP recorded $24 million of intangible asset impairments related to ETP’s liquidsits NGL and retail products transportation and services operations primarily due to an expected decrease in future cash flows.
Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter. Changes in the carrying amount of goodwill were as follows: | | | Investment in ETP | | Investment in Sunoco LP | | Investment in Lake Charles LNG | | Corporate, Other and Eliminations | | Total | Investment in ETP | | Investment in Sunoco LP | | Investment in Lake Charles LNG | | Corporate, Other and Eliminations | | Total | Balance, December 31, 2014 | $ | 7,642 |
| | $ | 3,143 |
| | $ | 184 |
| | $ | (3,104 | ) | | $ | 7,865 |
| | Balance, December 31, 2015 | | $ | 5,428 |
| | $ | 1,694 |
| | $ | 184 |
| | $ | (1,250 | ) | | $ | 6,056 |
| Goodwill acquired | — |
| | 31 |
| | — |
| | — |
| | 31 |
| 428 |
| | 81 |
| | — |
| | — |
| | 509 |
| Sunoco LP Exchange | (2,018 | ) | | — |
| | — |
| | 2,018 |
| | — |
| (1,289 | ) | | — |
| | — |
| | 1,289 |
| | — |
| Goodwill impairment | (205 | ) | | — |
| | — |
| | — |
| | (205 | ) | (670 | ) | | (227 | ) | | — |
| | — |
| | (897 | ) | Other | 9 |
| | (63 | ) | | — |
| | (164 | ) | | (218 | ) | — |
| | 2 |
| | — |
| | — |
| | 2 |
| Balance, December 31, 2015 | 5,428 |
| | 3,111 |
| | 184 |
| | (1,250 | ) | | 7,473 |
| | Balance, December 31, 2016 | | 3,897 |
| | 1,550 |
| | 184 |
| | 39 |
| | 5,670 |
| Goodwill acquired | 428 |
| | 140 |
| | — |
| | — |
| | 568 |
| 12 |
| | — |
| | — |
| | — |
| | 12 |
| Contribution of retail business | (1,289 | ) | | — |
| | — |
| | 1,289 |
| | — |
| | Goodwill impairment | (670 | ) | | (642 | ) | | — |
| | — |
| | (1,312 | ) | (793 | ) | | (102 | ) | | — |
| | — |
| | (895 | ) | Other | — |
| | 9 |
| | — |
| | — |
| | 9 |
| (1 | ) | | (18 | ) | | — |
| | — |
| | (19 | ) | Balance, December 31, 2016 | $ | 3,897 |
| | $ | 2,618 |
| | $ | 184 |
| | $ | 39 |
| | $ | 6,738 |
| | Balance, December 31, 2017 | | $ | 3,115 |
| | $ | 1,430 |
| | $ | 184 |
| | $ | 39 |
| | $ | 4,768 |
|
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2017, ETP recognized goodwill impairments of $262 million in its interstate transportation and storage operations, $79 million in its NGL and refined products transportation and services operations and $452 million in its all other operations primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. Sunoco LP recognized goodwill impairments of $387 million, of which $102 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units andETP recognized goodwill impairments of $638 million thein its interstate transportation and storage operations and $32 million in theits midstream operations primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. Sunoco LP recognized goodwill impairments of $642$641 million, of which $227 million was allocated to continuing operations,primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. During the fourth quarter of 2015, ETP performed goodwill impairment tests on its reporting units and recognized goodwill impairments of: (i)of $99 million in the Transwestern reporting unitits interstate transportation and storage operations and $106 million in its NGL and refined products transportation and services operations primarily due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015, and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices.2015. The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business.
Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions
related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO. An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates. Except for certain amounts recorded by Panhandle and Sunoco Logistics discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20162017 and 2015,2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes itWe believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time. Below is a scheduleAs of AROs by segment recorded asDecember 31, 2017 and 2016, other non-current liabilities in ourETP’s consolidated balance sheets:
| | | | | | | | | | December 31, | | 2016 | | 2015 | Investment in ETP: | | | | Interstate transportation and storage operations | $ | 54 |
| | $ | 58 |
| Investment in Sunoco Logistics | 88 |
| | 88 |
| All other | 28 |
| | 66 |
| | $ | 170 |
| | $ | 212 |
|
sheets included AROs of $165 million and $170 million, respectively.
Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. Long-lived assets related to AROs aggregated $14to $2 million and $18$14 million, and were reflected as property, plant and equipment on our consolidated balance sheetsheets as of December 31, 20162017 and 2015,2016, respectively. In addition, the Partnership had $13$21 million and $6$13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 20162017 and 2015,2016, respectively. All amounts recorded in our consolidated balance sheets as of December 31, 2017 and 2016 are attributable to the obligations of ETP.
Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Interest payable | $ | 545 |
| | $ | 519 |
| $ | 552 |
| | $ | 545 |
| Customer advances and deposits | 72 |
| | 114 |
| 59 |
| | 72 |
| Accrued capital expenditures | 769 |
| | 743 |
| 1,006 |
| | 769 |
| Accrued wages and benefits | 254 |
| | 218 |
| 280 |
| | 254 |
| Taxes payable other than income taxes | 201 |
| | 76 |
| 108 |
| | 201 |
| Income taxes payable | | 180 |
| | — |
| Exchanges payable | 208 |
| | 106 |
| 154 |
| | 208 |
| Other | 318 |
| | 632 |
| 243 |
| | 318 |
| Total accrued and other current liabilities | $ | 2,367 |
| | $ | 2,408 |
| $ | 2,582 |
| | $ | 2,367 |
|
Deposits or advances are received from customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. Redeemable Noncontrolling Interests The noncontrolling interest holders in one of Sunoco Logistics’ETP’s consolidated subsidiaries have the option to sell their interests to Sunoco Logistics.ETP. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on theour consolidated balance sheet. Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our consolidated debt obligations as of December 31, 20162017 was $45.05$45.62 billion and $43.80$44.08 billion, respectively. As of December 31, 20152016, the aggregate fair value and carrying amount of our consolidated debt obligations was $33.22$45.05 billion and $36.97$43.80 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives, interest rate derivatives and embedded derivatives in the ETP Convertible Preferred Units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2017 and 2016, no transfers were made between any levels within the fair value hierarchy.
The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 20162017 and 20152016 based on inputs used to derive their fair values: | | | | | | | | | | | | | | Fair Value Measurements at | | Fair Value Measurements at December 31, 2016 | | | December 31, 2017 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Fair Value Total | | Level 1 | | Level 2 | Assets: | | | | | | | | | | | | | Commodity derivatives: | | | | | | | | | | | | | Natural Gas: | | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 2 |
| | — |
| | 2 |
| | — |
| 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 96 |
| | 96 |
| | — |
| | — |
| 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 1 |
| | — |
| | 1 |
| | — |
| 8 |
| | — |
| | 8 |
| Power: | | | | | | | | | Forwards | 4 |
| | — |
| | 4 |
| | — |
| | Futures | 1 |
| | 1 |
| | — |
| | — |
| | Options — Calls | 1 |
| | 1 |
| | — |
| | — |
| | Power — Forwards | | 23 |
| | — |
| | 23 |
| Natural Gas Liquids — Forwards/Swaps | 233 |
| | 233 |
| | — |
| | — |
| 193 |
| | 193 |
| | — |
| Refined Products – Futures | 2 |
| | 2 |
| | — |
| | — |
| 1 |
| | 1 |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| 2 |
| | 2 |
| | — |
| Total commodity derivatives | 363 |
| | 356 |
| | 7 |
| | — |
| 321 |
| | 277 |
| | 44 |
| Other non-current assets | | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 363 |
| | $ | 356 |
| | $ | 7 |
| | $ | — |
| $ | 342 |
| | $ | 291 |
| | $ | 51 |
| Liabilities: | | | | | | | | | | | | | Interest rate derivatives | $ | (193 | ) | | $ | — |
| | $ | (193 | ) | | $ | — |
| $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Embedded derivatives in the ETP Preferred Units | (1 | ) | | — |
| | — |
| | (1 | ) | | Commodity derivatives: | | | | | | | | | | | | | Natural Gas: | | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (11 | ) | | (11 | ) | | — |
| | — |
| (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (3 | ) | | — |
| | (3 | ) | | — |
| (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (149 | ) | | (149 | ) | | — |
| | — |
| (57 | ) | | (57 | ) | | — |
| Power: | | | | | | | | | Forwards | (5 | ) | |
|
| | (5 | ) | | — |
| | Futures | (1 | ) | | (1 | ) | | — |
| | — |
| | Forward Physical Swaps | | (2 | ) | | — |
| | (2 | ) | Power — Forwards | | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids — Forwards/Swaps | (273 | ) | | (273 | ) | | — |
| | — |
| (192 | ) | | (192 | ) | |
|
| Refined Products – Futures | (23 | ) | | (23 | ) | | — |
| | — |
| (28 | ) | | (28 | ) | | — |
| Crude — Futures | (13 | ) | | (13 | ) | | — |
| | — |
| (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (478 | ) | | (470 | ) | | (8 | ) | | — |
| (341 | ) | | (303 | ) | | (38 | ) | Total liabilities | $ | (672 | ) | | $ | (470 | ) | | $ | (201 | ) | | $ | (1 | ) | $ | (560 | ) | | $ | (303 | ) | | $ | (257 | ) |
| | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2015 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | $ | 16 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| Swing Swaps IFERC | 10 |
| | 2 |
| | 8 |
| | — |
| Fixed Swaps/Futures | 274 |
| | 274 |
| | — |
| | — |
| Forward Physical Contracts | 4 |
| | — |
| | 4 |
| | — |
| Power: | | | | | | | | Forwards | 22 |
| | — |
| | 22 |
| | — |
| Futures | 3 |
| | 3 |
| | — |
| | — |
| Options — Calls | 1 |
| | 1 |
| | — |
| | — |
| Options — Puts | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | 99 |
| | 99 |
| | — |
| | — |
| Refined Products – Futures | 15 |
| | 15 |
| | — |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| Total commodity derivatives | 454 |
| | 420 |
| | 34 |
| | — |
| Total assets | $ | 454 |
| | $ | 420 |
| | $ | 34 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (171 | ) | | $ | — |
| | $ | (171 | ) | | $ | — |
| Embedded derivatives in the ETP Preferred Units | (5 | ) | | — |
| | — |
| | (5 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (16 | ) | | (16 | ) | | — |
| | — |
| Swing Swaps IFERC | (12 | ) | | (2 | ) | | (10 | ) | | — |
| Fixed Swaps/Futures | (203 | ) | | (203 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (22 | ) | | — |
| | (22 | ) | | — |
| Futures | (2 | ) | | (2 | ) | | — |
| | — |
| Options — Puts | (1 | ) | | (1 | ) | | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | (89 | ) | | (89 | ) | | — |
| | — |
| Refined Products – Futures | (6 | ) | | (6 | ) | | — |
| | — |
| Crude — Futures | (5 | ) | | (5 | ) | | — |
| | — |
| Total commodity derivatives | (356 | ) | | (324 | ) | | (32 | ) | | — |
| Total liabilities | $ | (532 | ) | | $ | (324 | ) | | $ | (203 | ) | | $ | (5 | ) |
The following table presents the material unobservable inputs used to estimate the fair value of ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units:
| | | | | | | Unobservable Input | | December 31, 2016 | Embedded derivatives in the ETP Preferred Units | Credit Spread | | 5.12 | % | | Volatility | | 31.73 | % |
Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in ETP’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the ETP Preferred Units. Changes in ETP’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2016.
| | | | | Balance, December 31, 2015 | $ | (5 | ) | Net unrealized gains included in other income (expense) | 4 |
| Balance, December 31, 2016 | $ | (1 | ) |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at | | | | December 31, 2016 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| Swing Swaps IFERC | 2 |
| | — |
| | 2 |
| | — |
| Fixed Swaps/Futures | 96 |
| | 96 |
| | — |
| | — |
| Forward Physical Contracts | 1 |
| | — |
| | 1 |
| | — |
| Power: | | | | | | | | Forwards | 4 |
| | — |
| | 4 |
| | — |
| Futures | 1 |
| | 1 |
| | — |
| | — |
| Options — Calls | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | 233 |
| | 233 |
| | — |
| | — |
| Refined Products – Futures | 2 |
| | 2 |
| | — |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| Total commodity derivatives | 363 |
| | 356 |
| | 7 |
| | — |
| Other non-current assets | 13 |
| | 8 |
| | 5 |
| | — |
| Total assets | $ | 376 |
| | $ | 364 |
| | $ | 12 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (193 | ) | | $ | — |
| | $ | (193 | ) | | $ | — |
| Embedded derivatives in the ETP Convertible Preferred Units | (1 | ) | | — |
| | — |
| | (1 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (11 | ) | | (11 | ) | | — |
| | — |
| Swing Swaps IFERC | (3 | ) | | — |
| | (3 | ) | | — |
| Fixed Swaps/Futures | (149 | ) | | (149 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (5 | ) | |
|
| | (5 | ) | | — |
| Futures | (1 | ) | | (1 | ) | | — |
| | — |
| Natural Gas Liquids — Forwards/Swaps | (273 | ) | | (273 | ) | | — |
| | — |
| Refined Products – Futures | (23 | ) | | (23 | ) | | — |
| | — |
| Crude — Futures | (13 | ) | | (13 | ) | | — |
| | — |
| Total commodity derivatives | (478 | ) | | (470 | ) | | (8 | ) | | — |
| Total liabilities | $ | (672 | ) | | $ | (470 | ) | | $ | (201 | ) | | $ | (1 | ) |
Contributions in Aid of Construction Cost On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized. Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses Costs of products sold include actual cost of fuel sold, adjusted for the effects of hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel. We record the collection of taxes to be remitted to governmental authorities on a net basis except for our retail marketing operations in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). Excise taxes collected by ourSunoco LP’s retail marketing operationslocations where Sunoco LP holds the inventory were $3.48 billion, $3.05 billion$234 million, $243 million and $2.46 billion$231 million for the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively. Issuances of Subsidiary Units We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiaries’ issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital. Income Taxes ETE is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under our Third Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, we would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, 2015, and 2014,2015, our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company, Susser Petroleum Property Company, Aloha Petroleum and Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes. Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in the consolidated statement of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statement of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We previously have managed a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations. Unit-Based Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our common units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our common units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets. Pensions and Other Postretirement Benefit Plans Employers are required to recognize in their balance sheetsETP recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation
(the (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the changeChanges in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income For purposes of maintaining partner capital accounts, our Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. | | 3. | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: |
2018 Transactions CDM Contribution Agreement In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions. In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million. Sunoco LP Convenience Store and Real Estate Sale On January 23, 2018, Sunoco LP closed on an asset purchase agreement with 7-Eleven, Inc., a Texas corporation (“7-Eleven”) and SEI Fuel Services, Inc., a Texas corporation and wholly-owned subsidiary of 7-Eleven (“SEI Fuel” and together with 7-Eleven, referred to herein collectively as “Buyers”). Under the agreement, Sunoco LP sold a portfolio of approximately 1,030 company-operated retail fuel outlets in 19 geographic regions, together with ancillary businesses and related assets, including the proprietary Laredo Taco Company brand, for an aggregate purchase price of $3.3 billion.
Sunoco LP has signed definitive agreements with a commission agent to operate the approximately 207 retail sites located in certain West Texas, Oklahoma and New Mexico markets, which were not included in the previously announced transaction with 7-Eleven, Inc. Conversion of these sites to the commission agent is expected to occur in the first quarter of 2018. On January 18, 2017, with the assistance of a third-party brokerage firm, Sunoco LP launched a portfolio optimization plan to market and sell 97 real estate assets. Real estate assets included in this process are company-owned locations, undeveloped greenfield sites and other excess real estate. Properties are located in Florida, Louisiana, Massachusetts, Michigan, New Hampshire, New Jersey, New Mexico, New York, Ohio, Oklahoma, Pennsylvania, Rhode Island, South Carolina, Texas and Virginia. The properties were marketed through a sealed-bid sale. Sunoco LP will review all bids before divesting any assets. As of December 31, 2017, of the 97 properties, 40 have been sold, 5 are under contract to be sold, and 11 continue to be marketed by the third-party brokerage firm. Additionally, 32 were sold to 7-Eleven and nine are part of the approximately 207 retail sites located in certain West Texas, Oklahoma, and New Mexico markets which will be operated by a commission agent.
The assets under the asset purchase agreement and the real estate assets subject to the portfolio optimization plan comprise the retail divestment presented as discontinued operations (“Retail Divestment”). The Partnership has concluded that it meets the accounting requirements for reporting results of operations and cash flows of Sunoco LP’s continental United States retail convenience stores as discontinued operations and the related assets and liabilities as held for sale. The following tables present the aggregate carrying amounts of assets and liabilities classified as held for sale in the consolidated balance sheet: | | | | | | | | | | December 31, 2017 | | December 31, 2016 | Carrying amount of assets included as part of discontinued operations: | | | | Accounts receivable, net | $ | 21 |
| | $ | 16 |
| Inventories | 149 |
| | 150 |
| Other current assets | 16 |
| | 11 |
| Property and equipment, net | 1,851 |
| | 1,860 |
| Goodwill | 796 |
| | 1,068 |
| Intangible assets, net | 477 |
| | 480 |
| Other noncurrent assets | 3 |
| | 3 |
| Total assets classified as held for sale in the Consolidated Balance Sheet | $ | 3,313 |
| | $ | 3,588 |
| | | | | Carrying amount of liabilities included as part of discontinued operations: | | | | Other current and noncurrent liabilities | $ | 75 |
| | $ | 48 |
| Total liabilities classified as held for sale in the Consolidated Balance Sheet | $ | 75 |
| | $ | 48 |
|
The results of operations associated with discontinued operations are presented in the following table: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | REVENUES | $ | 6,964 |
| | $ | 5,712 |
| | $ | 6,030 |
| | | | | | | COSTS AND EXPENSES | | | | | | Cost of products sold | 5,806 |
| | 4,649 |
| | 5,026 |
| Operating expenses | 763 |
| | 744 |
| | 705 |
| Depreciation, depletion and amortization | 34 |
| | 143 |
| | 128 |
| Selling, general and administrative | 168 |
| | 114 |
| | 91 |
| Impairment losses | 285 |
| | 447 |
| | — |
| Total costs and expenses | 7,056 |
| | 6,097 |
| | 5,950 |
| OPERATING INCOME | (92 | ) | | (385 | ) | | 80 |
| Interest expense, net | 36 |
| | 28 |
| | 21 |
| Other, net | 1 |
| | 8 |
| | (2 | ) | INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE | (129 | ) | | (421 | ) | | 61 |
| Income tax expense | 48 |
| | 41 |
| | 23 |
| INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF INCOME TAXES | $ | (177 | ) | | $ | (462 | ) | | $ | 38 |
| INCOME (LOSS) FROM DISCONTINUED OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) ATTRIBUTABLE TO ETE | $ | (6 | ) | | $ | (12 | ) | | $ | 1 |
|
In connection with the classification of those assets as held-for-sale, the related goodwill was tested for impairment based on the assumed proceeds from the sale of those assets, resulting in goodwill impairment charges of $285 million recognized in 2017. 2017 Transactions Rover Contribution Agreement In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments. ETP and Sunoco Logistics Merger As discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics completed the Sunoco Logistics Merger. Permian Express Partners In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in southern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the Partnership’s consolidated balance sheet at the date of the contribution, including $547 million of intangible assets and $435 million of property, plant and equipment. In July 2017, the Partnership contributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in the Partnership’s ownership interest in PEP to approximately 88%. The Partnership maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance
sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity. Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access and ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP continues to consolidate Dakota Access and ETCO subsequent to this transaction. 2016 Transactions WMB Merger On June 24, 2016, the Delaware Court of Chancery issued an opinion finding that ETE was contractually entitled to terminate its Merger Agreement with WMB in the event Latham & Watkins LLP (“Latham”) were unable to deliver a required tax opinion on or prior to June 28, 2016. Latham advised ETE that it was unable to deliver the tax opinion as of June 28, 2016. Consistent with its rights and obligations under the merger agreement, ETE subsequently provided written notice terminating the merger agreement due to the failure of conditions under the merger agreement, including Latham’s inability to deliver the tax opinion, as well as the other bases detailed in ETE’s filings in the Delaware lawsuit referenced above. WMB has appealed the decision by the Delaware Court of Chancery to the Delaware Supreme Court. ETP and Sunoco Logistics Merger
In November 2016, ETP and Sunoco Logistics entered into a merger agreement providing for the acquisition of ETP by Sunoco Logistics in a unit-for-unit transaction. Under the terms of the transaction, ETP unitholders will receive 1.5 common units of Sunoco Logistics for each common unit of ETP they own. Under the terms of the merger agreement, Sunoco Logistics’ general partner will be merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. The transaction is expected to close in April 2017.
PennTex Acquisition On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, ETP purchased PennTex’s remaining outstanding common units in June 2017. Summary of Assets Acquired and Liabilities Assumed We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The total purchase price was allocated as follows: | | | | | | | | At November 1, 2016 | Total current assets | | $ | 34 |
| Property, plant and equipment | | 393 |
| Goodwill(1) | | 177 |
| Intangible assets | | 446 |
| | | 1,050 |
| | | | Total current liabilities | | 6 |
| Long-term debt, less current maturities | | 164 |
| Other non-current liabilities | | 17 |
| Noncontrolling interest | | 236 |
| | | 423 |
| Total consideration | | 627 |
| Cash received | | 21 |
| Total consideration, net of cash received | | $ | 606 |
|
| | (1) | None of the goodwill is expected to be deductible for tax purposes. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Sunoco Logistics’ Vitol Acquisition In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol'sVitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC ("SunVit"(“SunVit”), which increased Sunoco Logistics'Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million. Sunoco Logistics’ Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately 85%. Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics. ExxonMobil Corp.’s interest will be reflected as noncontrolling interest in Sunoco Logistics’ consolidated balance sheet.
Bakken Equity Sale
On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.
Bakken Financing In August 2016, ETP Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provideprovided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2016, $1.102017, $2.50 billion was outstanding under this credit facility. Bayou Bridge In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, Partners LP, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system. Sunoco Retail to Sunoco LP In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. Sunoco LP Acquisitions In August 2016, Sunoco LP acquired the fuels business from Emerge Energy Services LP for $171 million, including tax deductible goodwill of $78$53 million and intangible assets of $23$56 million. Additionally, during 2016, Sunoco LP made other acquisitions primarily consisting of convenience stores, totaling $114 million plus the value of inventory on hand at closing and increasing goodwill by $61 million. In October 2016, Sunoco LP completed the acquisition of a convenience store, wholesale motor fuel distribution, and commercial fuels distribution business for approximately $55 million plus inventory on hand at closing, subject to closing adjustments. 2015 Transactions Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons of motor fuel per year to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million ofin Sunoco LP common units to Retail Holdings, based on the five-day volume weightedvolume-weighted average price of Sunoco LP’s common units as of March 20, 2015. In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries.
Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 2131.5 million ETP common units owned by ETE. In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In connection with the exchange and repurchase, ETE will provide ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. Bakken Pipeline In March 2015, ETE transferred 30.846.2 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP Class H Units that, when combined with the 50.2 million previously issued ETP Class H Units, generally entitleentitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provideprovided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017. In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access LLC and Energy Transfer Crude Oil Company, LLC,ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction. Regency Merger On April 30, 2015, a wholly-owned subsidiary of ETP merged with Regency, with Regency surviving as a wholly-owned subsidiary of ETP (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.41240.6186 common units of ETP. ETP issued 172.2258.3 million ETP common units to Regency unitholders, including 15.523.3 million units issued to ETP subsidiaries. TheRegency’s 1.9 million outstanding RegencySeries A Convertible Preferred Units were converted into corresponding new ETP Series A Convertible Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from ETP by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. 2014 Transactions
MACS to Sunoco LP
In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens ETP’s retail geographic footprint and provides synergy opportunities and a platform for future growth.
In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
Summary of Assets Acquired and Liabilities Assumed
ETP accounted for the Susser Merger using the acquisition method of accounting which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date:
| | | | | | | | Susser | Total current assets | | $ | 446 |
| Property, plant and equipment | | 1,069 |
| Goodwill(1) | | 1,734 |
| Intangible assets | | 611 |
| Other non-current assets | | 17 |
| | | 3,877 |
| | | | Total current liabilities | | 377 |
| Long-term debt, less current maturities | | 564 |
| Deferred income taxes | | 488 |
| Other non-current liabilities | | 39 |
| Noncontrolling interest | | 626 |
| | | 2,094 |
| Total consideration | | 1,783 |
| Cash received | | 67 |
| Total consideration, net of cash received | | $ | 1,716 |
|
| | (1)
| None of the goodwill is expected to be deductible for tax purposes. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2015. Our consolidated statements of operations for the year ended December 31, 2015 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented for the Susser Merger, as the impact of this acquisition was not material in relation to our consolidated results of operations.
Regency’s Acquisition of Eagle Rock’s Midstream Business
On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
The total purchase price was allocated as follows:
| | | | | Assets | At July 1, 2014 | Current assets | $ | 120 |
| Property, plant and equipment | 1,295 |
| Other non-current assets | 4 |
| Goodwill | 49 |
| Total assets acquired | 1,468 |
| Liabilities | | Current liabilities | 116 |
| Long-term debt | 499 |
| Other non-current liabilities | 12 |
| Total liabilities assumed | 627 |
| | | Net assets acquired | $ | 841 |
|
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of PVR Partners, L.P.
On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
Regency completed the evaluation of the assigned fair values to the assets acquired and liabilities assumed. The total purchase price was allocated as follows:
| | | | | Assets | At March 21, 2014 | Current assets | $ | 149 |
| Property, plant and equipment | 2,716 |
| Investment in unconsolidated affiliates | 62 |
| Intangible assets (average useful life of 30 years) | 2,717 |
| Goodwill(1) | 370 |
| Other non-current assets | 18 |
| Total assets acquired | 6,032 |
| Liabilities | | Current liabilities | 168 |
| Long-term debt | 1,788 |
| Premium related to senior notes | 99 |
| Non-current liabilities | 30 |
| Total liabilities assumed | 2,085 |
| Net assets acquired | $ | 3,947 |
|
(1)None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Lake Charles LNG Transaction
On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). The transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG.
In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8.
Panhandle Merger
On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million Regency Common Units and 6.3 million Regency Class F Units), and ETP (2.2 million ETP Common Units).
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2016 and 2015, were as follows:
| | | | | | | | | | December 31, | | 2016 | | 2015 | Citrus | $ | 1,729 |
| | $ | 1,739 |
| AmeriGas | 82 |
| | 80 |
| FEP | 101 |
| | 115 |
| MEP | 318 |
| | 660 |
| HPC | 382 |
| | 402 |
| Others | 428 |
| | 466 |
| Total | $ | 3,040 |
| | $ | 3,462 |
|
Citrus ETP owns CrossCountry, which owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, a natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. AmeriGas
In 2012, ETP received 29.6 million AmeriGas common units in connection with the contribution of its propane operations. During the year ended December 31, 2014, ETP sold 18.9 million AmeriGas common units for net proceeds of $814 million. As of December 31, 2016, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company and is reflected in the Investment in ETP segment.
FEP ETP has a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. ETP evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. ETP recorded an impairment of its investment in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor.
MEP ETP owns a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. ETP evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016. HPC ETP owns a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from Northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. ETP evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, ETP recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes. The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2017 and 2016, were as follows: | | | | | | | | | | December 31, | | 2017 | | 2016 | Citrus | $ | 1,754 |
| | $ | 1,729 |
| FEP | 121 |
| | 101 |
| MEP | 242 |
| | 318 |
| HPC | 28 |
| | 382 |
| Others | 560 |
| | 510 |
| Total | $ | 2,705 |
| | $ | 3,040 |
|
The following table presents equity in earnings (losses) of unconsolidated affiliates: | | | | | | | | | | | | | | December 31, | Equity in earnings (losses) of unconsolidated affiliates: | 2017 | | 2016 | | 2015 | Citrus | $ | 144 |
| | $ | 102 |
| | $ | 97 |
| FEP | 53 |
| | 51 |
| | 55 |
| MEP | 38 |
| | 40 |
| | 45 |
| HPC(1) | (168 | ) | | 31 |
| | 32 |
| Others | 77 |
| | 46 |
| | 47 |
| Total | $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | (1) | For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million. |
Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, including AmeriGas, Citrus, FEP, HPC and MEP (on a 100% basis) for all periods presented: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Current assets | $ | 720 |
| | $ | 632 |
| $ | 206 |
| | $ | 214 |
| Property, plant and equipment, net | 9,982 |
| | 10,213 |
| 8,336 |
| | 8,726 |
| Other assets | 2,618 |
| | 2,649 |
| 43 |
| | 181 |
| Total assets | $ | 13,320 |
| | $ | 13,494 |
| $ | 8,585 |
| | $ | 9,121 |
| | | | | | | | Current liabilities | $ | 1,358 |
| | $ | 841 |
| $ | 861 |
| | $ | 816 |
| Non-current liabilities | 7,583 |
| | 7,950 |
| 4,492 |
| | 4,940 |
| Equity | 4,379 |
| | 4,703 |
| 3,232 |
| | 3,365 |
| Total liabilities and equity | $ | 13,320 |
| | $ | 13,494 |
| $ | 8,585 |
| | $ | 9,121 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Revenue | $ | 3,509 |
| | $ | 4,026 |
| | $ | 4,925 |
| $ | 1,358 |
| | $ | 1,164 |
| | $ | 1,385 |
| Operating income | 1,181 |
| | 1,302 |
| | 1,071 |
| 407 |
| | 714 |
| | 800 |
| Net income | 602 |
| | 807 |
| | 577 |
| 145 |
| | 384 |
| | 470 |
|
In addition to the equity method investments described above our subsidiaries have other equity method investments which are not significant to our consolidated financial statements.
| | 5. | NET INCOME PER LIMITED PARTNER UNIT: |
Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding. Diluted net income per limited partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of limited partner interests outstanding and the assumed conversion of ourthe ETE Series A Convertible Preferred Units, seeas discussed in Note 7.8. For the diluted earnings per share computation, income allocable to the limited partners is reduced, where applicable, for the decrease in earnings from ETE’s limited partner unit ownership in ETP or Sunoco LP that would have resulted assuming the incremental units related to ETP’s or Sunoco LP’s equity incentive plans, as applicable, had been issued during the respective periods. Such units have been determined based on the treasury stock method. A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Income from continuing operations | $ | 41 |
| | $ | 1,093 |
| | $ | 1,060 |
| $ | 2,543 |
| | $ | 462 |
| | $ | 1,023 |
| Less: Income (loss) from continuing operations attributable to noncontrolling interest | (954 | ) | | (96 | ) | | 434 |
| 1,583 |
| | (545 | ) | | (165 | ) | Income from continuing operations, net of noncontrolling interest | 995 |
| | 1,189 |
| | 626 |
| 960 |
| | 1,007 |
| | 1,188 |
| Less: General Partner’s interest in income from continuing operations | 3 |
| | 3 |
| | 2 |
| 2 |
| | 3 |
| | 3 |
| Less: Convertible Unitholders’ interest in net income | 9 |
| | — |
| | — |
| | Less: Convertible Unitholders’ interest in net income from continuing operations | | 38 |
| | 8 |
| | — |
| Less: Class D Unitholder’s interest in income from continuing operations | — |
| | 3 |
| | 2 |
| — |
| | — |
| | 3 |
| Income from continuing operations available to Limited Partners | $ | 983 |
| | $ | 1,183 |
| | $ | 622 |
| $ | 920 |
| | $ | 996 |
| | $ | 1,182 |
| Basic Income from Continuing Operations per Limited Partner Unit: | | | | | | | | | | | Weighted average limited partner units | 1,045.5 |
| | 1,062.8 |
| | 1,088.6 |
| 1,078.2 |
| | 1,045.5 |
| | 1,062.8 |
| Basic income from continuing operations per Limited Partner unit | $ | 0.94 |
| | $ | 1.11 |
| | $ | 0.58 |
| $ | 0.86 |
| | $ | 0.95 |
| | $ | 1.11 |
| Basic income from discontinued operations per Limited Partner unit | $ | — |
| | $ | — |
| | $ | — |
| | Basic income (loss) from discontinued operations per Limited Partner unit | | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | — |
| Diluted Income from Continuing Operations per Limited Partner Unit: | | | | | | | | | | | Income from continuing operations available to Limited Partners | $ | 983 |
| | $ | 1,183 |
| | $ | 622 |
| $ | 920 |
| | $ | 996 |
| | $ | 1,182 |
| Dilutive effect of equity-based compensation of subsidiaries, distributions to Class D Unitholder and Convertible Units | 9 |
| | (2 | ) | | (2 | ) | 38 |
| | 8 |
| | 3 |
| Diluted income from continuing operations available to Limited Partners | 992 |
| | 1,181 |
| | 620 |
| 958 |
| | 1,004 |
| | 1,185 |
| Weighted average limited partner units | 1,045.5 |
| | 1,062.8 |
| | 1,088.6 |
| 1,078.2 |
| | 1,045.5 |
| | 1,062.8 |
| Dilutive effect of unconverted unit awards and Convertible Units | 33.1 |
| | 1.6 |
| | 2.2 |
| 72.6 |
| | 33.1 |
| | 1.6 |
| Weighted average limited partner units, assuming dilutive effect of unvested unit awards | 1,078.6 |
| | 1,064.4 |
| | 1,090.8 |
| 1,150.8 |
| | 1,078.6 |
| | 1,064.4 |
| Diluted income from continuing operations per Limited Partner unit | $ | 0.92 |
| | $ | 1.11 |
| | $ | 0.57 |
| $ | 0.84 |
| | $ | 0.93 |
| | $ | 1.11 |
| Diluted income from discontinued operations per Limited Partner unit | $ | — |
| | $ | — |
| | $ | 0.01 |
| | Diluted income (loss) from discontinued operations per Limited Partner unit | | $ | (0.01 | ) | | $ | (0.01 | ) | | $ | — |
|
Our debt obligations consist of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Parent Company Indebtedness: | | | | | | | 7.50% Senior Notes, due October 15, 2020 | $ | 1,187 |
| | $ | 1,187 |
| | 5.875% Senior Notes, due January 15, 2024 | 1,150 |
| | 1,150 |
| | 7.50% Senior Notes due October 15, 2020 | | $ | 1,187 |
| | $ | 1,187 |
| 5.875% Senior Notes due January 15, 2024 | | 1,150 |
| | 1,150 |
| 5.50% Senior Notes due June 1, 2027 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| ETE Senior Secured Term Loan, due December 2, 2019 | 2,190 |
| | 2,190 |
| | 4.25% Senior Notes due March 15, 2023 | | 1,000 |
| | — |
| ETE Senior Secured Term Loan due December 2, 2019 | | — |
| | 2,190 |
| ETE Senior Secured Term Loan due February 2, 2024 | | 1,220 |
| | — |
| ETE Senior Secured Revolving Credit Facility due December 18, 2018 | 875 |
| | 860 |
| — |
| | 875 |
| ETE Senior Secured Revolving Credit Facility due March 24, 2022 | | 1,188 |
| | — |
| Unamortized premiums, discounts and fair value adjustments, net | (15 | ) | | (17 | ) | (11 | ) | | (15 | ) | Deferred debt issuance costs | (30 | ) | | (38 | ) | (34 | ) | | (30 | ) | | 6,357 |
| | 6,332 |
| 6,700 |
| | 6,357 |
| | | | | | | | Subsidiary Indebtedness: | | | | | | | ETP Debt | | | | | | | 6.125% Senior Notes due February 15, 2017 | 400 |
| | 400 |
| — |
| | 400 |
| 2.50% Senior Notes due June 15, 2018 | 650 |
| | 650 |
| | 6.70% Senior Notes due July 1, 2018 | 600 |
| | 600 |
| | 2.50% Senior Notes due June 15, 2018 (1) | | 650 |
| | 650 |
| 6.70% Senior Notes due July 1, 2018 (1) | | 600 |
| | 600 |
| 9.70% Senior Notes due March 15, 2019 | 400 |
| | 400 |
| 400 |
| | 400 |
| 9.00% Senior Notes due April 15, 2019 | 450 |
| | 450 |
| 450 |
| | 450 |
| 5.50% Senior Notes due February 15, 2020 | | 250 |
| | 250 |
| 5.75% Senior Notes due September 1, 2020 | 400 |
| | 400 |
| 400 |
| | 400 |
| 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 1,050 |
| 1,050 |
| | 1,050 |
| 4.40% Senior Notes due April 1, 2021 | | 600 |
| | 600 |
| 6.50% Senior Notes due July 15, 2021 | 500 |
| | 500 |
| — |
| | 500 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 4.65% Senior Notes due February 15, 2022 | | 300 |
| | 300 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | 900 |
| 900 |
| | 900 |
| 5.00% Senior Notes due October 1, 2022 | 700 |
| | 700 |
| 700 |
| | 700 |
| 3.45% Senior Notes due January 15, 2023 | | 350 |
| | 350 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 800 |
| | 800 |
| 5.50% Senior Notes due April 15, 2023 | 700 |
| | 700 |
| — |
| | 700 |
| 4.50% Senior Notes due November 1, 2023 | 600 |
| | 600 |
| 600 |
| | 600 |
| 4.90% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 350 |
| | 350 |
| 7.60% Senior Notes due February 1, 2024 | 277 |
| | 277 |
| 277 |
| | 277 |
| 4.25% Senior Notes due April 1, 2024 | | 500 |
| | 500 |
| 9.00% Debentures due November 1, 2024 | | 65 |
| | 65 |
| 4.05% Senior Notes due March 15, 2025 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 5.95% Senior Notes due December 1, 2025 | | 400 |
| | 400 |
| 4.75% Senior Notes due January 15, 2026 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 3.90% Senior Notes due July 15, 2026 | | 550 |
| | 550 |
| 4.20% Senior Notes due April 15, 2027 | | 600 |
| | — |
| 4.00% Senior Notes due October 1, 2027
| | 750 |
| | — |
| 8.25% Senior Notes due November 15, 2029 | 267 |
| | 267 |
| 267 |
| | 267 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | 500 |
| 500 |
| | 500 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 400 |
| | 400 |
| 7.50% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 550 |
| | 550 |
| 6.85% Senior Notes due February 15, 2040 | | 250 |
| | 250 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 5.15% Senior Notes due February 1, 2043 | 450 |
| | 450 |
| | 5.95% Senior Notes due October 1, 2043 | 450 |
| | 450 |
| | 5.15% Senior Notes due March 15, 2045 | 1,000 |
| | 1,000 |
| | 6.125% Senior Notes due December 15, 2045 | 1,000 |
| | 1,000 |
| | Floating Rate Junior Subordinated Notes due November 1, 2066 | 546 |
| | 545 |
| | ETP $3.75 billion Revolving Credit Facility due November 2019 | 2,777 |
| | 1,362 |
| | Unamortized premiums, discounts and fair value adjustments, net | (18 | ) | | (21 | ) | | Deferred debt issuance costs | (132 | ) | | (147 | ) | | | 22,067 |
| | 20,633 |
| | | | | | | Transwestern Debt | | | | | 5.54% Senior Notes due November 17, 2016 | — |
| | 125 |
| | 5.64% Senior Notes due May 24, 2017 | 82 |
| | 82 |
| | 5.36% Senior Notes due December 9, 2020 | 175 |
| | 175 |
| | 5.89% Senior Notes due May 24, 2022 | 150 |
| | 150 |
| | 5.66% Senior Notes due December 9, 2024 | 175 |
| | 175 |
| | 6.10% Senior Notes due February 15, 2042 | | 300 |
| | 300 |
|
| | 4.95% Senior Notes due January 15, 2043 | | 350 |
| | 350 |
| 5.15% Senior Notes due February 1, 2043 | | 450 |
| | 450 |
| 5.95% Senior Notes due October 1, 2043 | | 450 |
| | 450 |
| 5.30% Senior Notes due April 1, 2044 | | 700 |
| | 700 |
| 5.15% Senior Notes due March 15, 2045 | | 1,000 |
| | 1,000 |
| 5.35% Senior Notes due May 15, 2045 | | 800 |
| | 800 |
| 6.125% Senior Notes due December 15, 2045 | | 1,000 |
| | 1,000 |
| 5.30% Senior Notes due April 15, 2047 | | 900 |
| | — |
| 5.40% Senior Notes due October 1, 2047
| | 1,500 |
| | — |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | | 546 |
| | 546 |
| ETP $4.0 billion Revolving Credit Facility due December 2022 | | 2,292 |
| | — |
| ETP $1.0 billion 364-Day Credit Facility due November 2018 (2) | | 50 |
| | — |
| ETLP $3.75 billion Revolving Credit Facility due November 2019 | | — |
| | 2,777 |
| Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | | — |
| | 1,292 |
| Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017 | | — |
| | 630 |
| Unamortized premiums, discounts and fair value adjustments, net | | 33 |
| | 66 |
| Deferred debt issuance costs | | (170 | ) | | (166 | ) | | | 29,210 |
| | 29,454 |
| | | | | | Transwestern Debt | | | | | 5.64% Senior Notes due May 24, 2017 | | — |
| | 82 |
| 5.36% Senior Notes due December 9, 2020 | | 175 |
| | 175 |
| 5.89% Senior Notes due May 24, 2022 | | 150 |
| | 150 |
| 5.66% Senior Notes due December 9, 2024 | | 175 |
| | 175 |
| 6.16% Senior Notes due May 24, 2037 | 75 |
| | 75 |
| 75 |
| | 75 |
| Unamortized premiums, discounts and fair value adjustments, net | — |
| | (1 | ) | | Deferred debt issuance costs | (1 | ) | | (2 | ) | (1 | ) | | (1 | ) | | 656 |
| | 779 |
| 574 |
| | 656 |
| | | | | | | | Panhandle Debt | | | | | | | 6.20% Senior Notes due November 1, 2017 | 300 |
| | 300 |
| — |
| | 300 |
| 7.00% Senior Notes due June 15, 2018 | 400 |
| | 400 |
| 400 |
| | 400 |
| 8.125% Senior Notes due June 1, 2019 | 150 |
| | 150 |
| 150 |
| | 150 |
| 7.60% Senior Notes due February 1, 2024 | 82 |
| | 82 |
| 82 |
| | 82 |
| 7.00% Senior Notes due July 15, 2029 | 66 |
| | 66 |
| 66 |
| | 66 |
| 8.25% Senior Notes due November 14, 2029 | 33 |
| | 33 |
| 33 |
| | 33 |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 54 |
| | 54 |
| 54 |
| | 54 |
| Unamortized premiums, discounts and fair value adjustments, net | 50 |
| | 75 |
| 28 |
| | 50 |
| | 1,135 |
| | 1,160 |
| 813 |
| | 1,135 |
| | | | | | | | Sunoco, Inc. Debt | | | | | | | 5.75% Senior Notes due January 15, 2017 | 400 |
| | 400 |
| — |
| | 400 |
| 9.00% Debentures due November 1, 2024 | 65 |
| | 65 |
| | Unamortized premiums, discounts and fair value adjustments, net | 9 |
| | 20 |
| | | 474 |
| | 485 |
| | | | | | | Sunoco Logistics Debt | | | | | 6.125% Senior Notes due May 15, 2016 | — |
| | 175 |
| | 5.50% Senior Notes due February 15, 2020 | 250 |
| | 250 |
| | 4.40% Senior Notes due April 1, 2021 | 600 |
| | 600 |
| | 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| | 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| | 4.25% Senior Notes due April 1, 2024 | 500 |
| | 500 |
| | 5.95% Senior Notes due December 1, 2025 | 400 |
| | 400 |
| | 3.90% Senior Notes due July 15, 2026 | 550 |
| | — |
| | 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| | 6.10% Senior Notes due February 15, 2042 | 300 |
| | 300 |
| | 4.95% Senior Notes due January 15, 2043 | 350 |
| | 350 |
| | 5.30% Senior Notes due April 1, 2044 | 700 |
| | 700 |
| | 5.35% Senior Notes due May 15, 2045 | 800 |
| | 800 |
| | Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | 1,292 |
| | 562 |
| | Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017(1) | 630 |
| | — |
| | Unamortized premiums, discounts and fair value adjustments, net | 75 |
| | 85 |
| | Deferred debt issuance costs | (34 | ) | | (32 | ) | | | 7,313 |
| | 5,590 |
| | | | | | | | | Bakken Project Debt | | | | | | | Bakken Project $2.50 billion Credit Facility due August 2019 | 1,100 |
| | — |
| 2,500 |
| | 1,100 |
| Deferred debt issuance costs | (13 | ) | | — |
| (8 | ) | | (13 | ) | | 1,087 |
| | — |
| 2,492 |
| | 1,087 |
| PennTex Debt | | | | | | | PennTex $275 million Revolving Credit Facility due December 2019 | 168 |
| | — |
| — |
| | 168 |
| | | | | | | | Sunoco LP Debt | | | | | | | 5.50% Senior Notes Due August 1, 2020 | 600 |
| | 600 |
| | 5.50% Senior Notes due August 1, 2020 | | 600 |
| | 600 |
| 6.375% Senior Notes due April 1, 2023 | 800 |
| | 800 |
| 800 |
| | 800 |
| 6.25% Senior Notes due April 15, 2021 | 800 |
| | — |
| 800 |
| | 800 |
| Sunoco LP $1.50 billion Revolving Credit Facility due September 25, 2019 | 1,000 |
| | 450 |
| 765 |
| | 1,000 |
| Sunoco LP Term Loan due October 1, 2019 | 1,243 |
| | — |
| 1,243 |
| | 1,243 |
| Lease-related obligations | 118 |
| | 126 |
| 113 |
| | 118 |
| Deferred debt issuance costs | (47 | ) | | (18 | ) | (34 | ) | | (47 | ) | | 4,514 |
| | 1,958 |
| 4,287 |
| | 4,514 |
|
| | | | | | | | | Other | 31 |
| | 31 |
| 8 |
| | 31 |
| | 43,802 |
| | 36,968 |
| | Less: current maturities | 1,194 |
| | 131 |
| | | $ | 42,608 |
| | $ | 36,837 |
| | Total debt | | 44,084 |
| | 43,802 |
| Less: current maturities of long-term debt | | 413 |
| | 1,194 |
| Long-term debt, less current maturities | | $ | 43,671 |
| | $ | 42,608 |
|
| | (1) | Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630As of December 31, 2017 ETP’s management had the intent and ability to refinance the $650 million term loan,2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current. |
| | (2) | Borrowings under 364-day credit facilities were classified as long-term debt as of December 31, 2016 as Sunoco Logistics hasbased on the Partnership’s ability and intent to refinance such borrowings on a long-term basis. |
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $156$197 million in unamortized premiums, fair value adjustments and deferred debt issuance costs, net: | | 2017 | $ | 1,817 |
| | 2018 | 2,530 |
| $ | 1,705 |
| 2019 | 9,483 |
| 5,512 |
| 2020 | 4,960 |
| 3,667 |
| 2021 | 2,706 |
| 2,205 |
| 2022 | | 6,540 |
| Thereafter | 22,462 |
| 24,652 |
| Total | $ | 43,958 |
| $ | 44,281 |
|
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. Notes and Debentures ETE Senior Notes Offering In October 2017, ETE issued $1 billion aggregate principal amount of 4.25% senior notes due 2023. The $990 million net proceeds from the offering were used to repay a portion of the outstanding indebtedness under its term loan facility and for general partnership purposes. The senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the senior notes. The balance is payable upon maturity. Interest on the senior notes is paid semi-annually. ETE Senior Notes The ETE Senior Notes are the Parent Company’s senior obligations, ranking equally in right of payment with our other existing and future unsubordinated debt and senior to any of its future subordinated debt. The Parent Company’s obligations under the ETE Senior Notes are secured on a first-priority basis with its obligations under the Revolver Credit Agreement and the ETE Term Loan Facility, by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets, subject to certain exceptions and permitted liens. The ETE Senior Notes are not guaranteed by any of the Parent Company’s subsidiaries. The covenants related to the ETE Senior Notes include a limitation on liens, a limitation on transactions with affiliates, a restriction on sale-leaseback transactions and limitations on mergers and sales of all or substantially all of the Parent Company’s assets. As discussed above, the Parent Company’s outstanding senior notes are collateralized by its interests in certain of its subsidiaries. SEC Rule 3-16 of Regulation S-X (“Rule 3-16”) requires a registrant to file financial statements for each of its affiliates whose securities constitute a substantial portion of the collateral for registered securities. The Parent Company’s limited partner interests in ETP constitute substantial portions of the collateral for the Parent Company’s outstanding senior notes; accordingly, financial statements of ETP are required under Rule 3-16 to be included in thisthe Partnership’s Annual Report on Form 10-K and have been included herein.
The Parent Company’s interests in ETP GP and ETE Common Holdings, LLC, (collectively, the “Non-Reporting Entities”) also constituteconstitutes substantial portions of the collateral for the Parent Company’s outstanding senior notes. Accordingly, the financial statements of the Non-Reporting EntitiesETP GP would be required under Rule 3-16 to be included in the Parent Company’s Annual Report on Form 10-K. None of the Non-Reporting Entities hasETP GP does not have substantive operations of its own; rather, each of the Non-Reporting Entities holds only direct or indirect interests in ETP and/or the consolidated subsidiaries of ETP. Following is a summary of the interests held by each of the Non-Reporting Entities, as well as a summary of the significant differences between each of the Non-Reporting Entities compared to ETP: ETP GP only owns 100% of the general partner interest in ETP. ETP GP does not own limited partner interests in ETP; therefore, the limited partner interests in ETP, which had a carrying value of $18.43$28.02 billion and $20.53$18.41 billion as of December 31, 20162017 and 2015,2016, respectively, would be reflected as noncontrolling interests on ETP GP’s balance sheets. Likewise, ETP’s income (loss) attributable to limited partners (including common unitholders, Class H
unitholders, Class I unitholders and Class I unitholders)ETP Preferred Units) of $(651) million, $334$1.08 billion, $(660) million and $823$325 million for the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively, would be reflected as income attributable to noncontrolling interest in ETP GP’s statements of operations. As of December 31, 2014, ETE Common Holdings, LLC (“ETE Common Holdings”) owned 5.2 million ETP Common Units, representing approximately 1.5% of the total outstanding ETP Common Units, and 50.2 million ETP Class H Units, representing 100% of the total outstanding ETP Class H Units. ETE Common Holdings also owned 30.9 million Regency Common Units, representing approximately 7.5% of the total outstanding Regency Common Units; ETE Common Holdings’ interest in Regency was acquired in 2014. During 2015, all of the units held by ETE Common Holdings were redeemed by ETP. ETE Common Holdings does not own the general partner interests in ETP; therefore, the financial statements of ETE Common Holdings would only reflect equity method investments in ETP. The carrying values of ETE Common Holdings’ investments in ETP was $1.72 billion as of December 31, 2014, and ETE Common Holdings’ equity in earnings from its investments in ETP was $292 million for the year ended December 31, 2014.
ETP’s general partner interest Common Units and Class H Units areis reflected separately in ETP’s financial statements. As a result, the financial statements of the Non-Reporting EntitiesETP GP would substantially duplicate information that is available in the financial statements of ETP. Therefore, the financial statements of the Non-Reporting EntitiesETP GP have been excluded from thisthe Partnership’s Annual Report on Form 10-K. ETP as Co-Obligor of Sunoco, Inc. Debt In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2016, and $400 million matured and was repaid in January 2017.
Panhandle Junior Subordinated Notes
The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.77% at December 31, 2016.
ETP Senior Notes Offerings
In January 2017, ETP issued $600 million aggregate principal amount of 4.20% senior notes due April 2027 and $900 million aggregate principal amount of 5.30% senior notes due April 2047. ETP used the $1.48 billion net proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility.
The ETP senior notes were registered under the Securities Act of 1933 (as amended). ETP may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligations of ETP and the obligation of ETP to repay the ETP senior notes is not guaranteed by us or any of ETP’s subsidiaries. Asas a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries. Transwestern Senior Notes The Transwestern senior notes are redeemable at any time in whole or pro rata in part, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is payable semi-annually. Panhandle Junior Subordinated Notes The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 4.39% at December 31, 2017. Sunoco LogisticsLP Private Offering of Senior Notes Offerings In July 2016,On January 23, 2018, Sunoco Logistics issued $550 millionLP completed a private offering of $2.2 billion of senior notes, comprised of $1.0 billion in aggregate principal amount of 3.90%4.875% senior notes due 2023, $800 million in July 2026. The netaggregate principal amount of 5.500% senior notes due 2026 and $400 million in aggregate principal amount of 5.875% senior notes due 2028. Sunoco LP used the proceeds from thisthe private offering, were used toalong with proceeds from the closing of the asset purchase agreement with 7-Eleven to: 1) redeem in full its existing senior notes as of December 31, 2017, comprised of $800 million in aggregate principal amount of 6.250%senior notes due 2021, $600 million in aggregate principal amount of 5.500% senior notes due 2020, and $800 million in aggregate principal amount of 6.375% senior notes due 2023; 2) repay in full and terminate the Sunoco LP Term Loan; 3) pay all closing costs and taxes in connection with the 7-Eleven transaction; 4) redeem the outstanding credit facility borrowingsSunoco LP Series A Preferred Units as mentioned above; and for general partnership purposes.5) repurchase 17,286,859 common units owned by ETP as mentioned above.
Sunoco LP Senior Notes In April 2016, Sunoco LP issued $800 million aggregate principal amount of 6.25% Senior Notes due 2021. The net proceeds of $789 million were used to repay a portion of the borrowings under its term loan facility. The 6.25% Senior Notes due 2021 were redeemed on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above.
Term Loans, Credit Facilities and Commercial Paper ETE Term Loan Facility As of December 31, 2016, the Parent Company had outstanding a Senior Secured Term Loan Agreement, dated as of March 5, 2015, both with scheduled maturities on December 2, 2019. In connection with the Parent Company’s entry into a Senior Secured Term loan Agreement on February 2, 2017, as discussed below, the Parent Company terminated both agreements.
On February 2, 2017, the Partnership entered into a Senior Secured Term Loan Agreement (the “Term Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch, as administrative agent, and the other lenders party thereto. The Term Credit Agreement has a scheduled maturity date of February 2, 2024, with an option for the Parent Company to extend the term
subject to the terms and conditions set forth therein. The Term Credit Agreement contains an accordion feature, under which the total commitments may be increased, subject to the terms thereof. In connection with the Parent Company’s entry into the Senior Secured Term Loan Agreement on February 2, 2017, the Parent Company terminated its previous term loan agreements. Pursuant to the Term Credit Agreement, the Term Lenders have provided senior secured financing in an aggregate principal amount of $2.2 billion (the “Term Loan Facility”). The Parent Company is not required to make any amortization payments with respect to the term loans under the Term Credit Agreement. Under certain circumstances and subject to certain reinvestment rights, the Parent Company is required to prepay the term loan in connection with dispositions of (a) IDRs in (i) prior to the consummation of the MLPSunoco Logistics Merger, ETP , and (ii) upon and after the consummation of the MLPSunoco Logistics Merger, Sunoco Logistics ; or (b) equity interests of any person which owns, directly or indirectly, IDRs in (i) prior to the consummation of the MLPSunoco Logistics Merger, ETP, and (ii) upon and after the consummation of the MLPSunoco Logistics Merger, Sunoco Logistics, in each case, with a percentage ranging from 50% to 75% of such net proceeds in excess of $50 million. Under the Term Credit Agreement, the obligations of the Parent Company are secured by a lien on substantially all of the Parent Company’s and certain of its subsidiaries’ tangible and intangible assets including (i) approximately 18.427.5 million common units representing limited partner interests in ETP and approximately 81.0 million Class H units of ETP owned by the Partnership; and (ii) the Partnership’s 100% equity interest in Energy Transfer Partners, L.L.C. and Energy Transfer Partners GP, L.P., through which the Partnership indirectly holds all of the outstanding general partnership interests and IDRs in immediately prior to the consummation of the MLP Merger, ETP and, immediately after the consummation of the MLP Merger, Sunoco Logistics.ETP. The Term Loan Facility initially is not guaranteed by any of the Partnership’s subsidiaries. Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The applicable margin for LIBOR rate loans is 2.75% and the applicable margin for base rate loans is 1.75%. Proceeds of the borrowings under the Term Credit Agreement were used to refinance amounts outstanding under the Parent Company’s existing term loan facilities and to pay transaction fees and expenses related to the Term Loan Facility and other transactions incidental thereto. On October 18, 2017, ETE amended its existing Term Credit Agreement (the “Amendment”) to reduce the applicable margin for LIBOR rate loans from 2.75% to 2.00% and for base rate loans from 1.75% to 1.00%. In connection with the Amendment, the Partnership prepaid a portion of amounts outstanding under the senior secured term loan agreement. ETE Revolving Credit Facility The Parent Company has the Revolver Credit Agreementhad a revolver credit agreement which hashad a scheduled maturity date of December 2, 2018, with an option for the Parent Company to extend the term subject to the terms and conditions set forth therein. The agreement was terminated in connection with entry into the Revolver Credit Agreement, discussed below. On March 24, 2017, the Parent Company entered into a Credit Agreement (the “Revolver Credit Agreement”) with Credit Suisse AG, Cayman Islands Branch as administrative agent and the other lenders party thereto (the “Revolver Lenders”). The Revolver Credit Agreement has a scheduled maturity date of March 24, 2022 and includes an option for the Parent Company to extend the term, in each case subject to the terms and conditions set forth therein. Pursuant to the Revolver Credit Agreement, the lenders have committed to provide advances up to an aggregate principal amount of $1.50 billion at any one time outstanding. The Revolver Credit Agreement contains an accordion feature, under whichoutstanding, and the totalParent Company has the option to request increases in the aggregate commitments may be increased, subjectby up to the terms thereof. $500 million in additional commitments. As part of the aggregate commitments under the facility, the Revolver Credit Agreement provides for letters of credit to be issued at the request of the Parent Company in an aggregate amount not to exceed a $150$150 million sublimit. Under the Revolver Credit Agreement, the obligations of the Parent CompanyPartnership are secured by a lien on substantially all of the Parent Company’sPartnership’s and certain of its subsidiaries’ tangible and intangible assets. Borrowings under the Revolver Credit Agreement are not guaranteed by any of the Parent Company’s subsidiaries. Interest accrues on advances at a LIBOR rate or a base rate, based on the election of the Parent Company for each interest period, plus an applicable margin. The issuing fees for all letters of credit are also based on an applicable margin. The applicable margin used in connection with interest rates and fees is based on the then applicable leverage ratio of the Parent Company. The applicable margin for LIBOR rate loans and letter of credit fees ranges from 1.75% to 2.50% and the applicable margin for base rate loans ranges from 0.75% to 1.50%. The Parent Company will also pay a commitment fee based on its leverage ratio on the actual daily unused amount of the aggregate commitments. As of December 31, 2017, there were $1.19 billion outstanding borrowings under the Parent Company revolver credit facility and the amount available for future borrowings was $312 million.
ETP Credit Facilities On December 1, 2017 ETP entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”). The ETP Five-Year Facility contains an accordion feature, under which the total aggregate commitments may be increased up to $6.0 billion under certain conditions. ETP uses the ETP Credit Facilities to provide temporary financing for its growth projects, as well as for general partnership purposes. As of December 31, 2017, the ETP Five-Year Facility had $2.29 billion outstanding, of which $2.01 billion was commercial paper. The amount available for future borrowings was $1.56 billion after taking into account letters of credit of $150 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 2.48%. As of December 31, 2017, the ETP 364-Day Facility had $50 million outstanding, and the amount available for future borrowings was $950 million. The weighted average interest rate on the total amount outstanding as of December 31, 2017 was 5.00%. ETLP Credit Facility The ETPETLP Credit Facility allowsallowed for borrowings of up to $3.75 billion and matures on November 18, 2019. The indebtedness under the ETP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our current and future unsecured debt. The indebtedness under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt. We use the ETP Credit Facilitywas used to provide temporary financing for our growth projects, as well as for general partnership purposes. As This facility was repaid and terminated concurrent with the establishment of December 31, 2016, the ETP Credit Facility had $2.78 billion outstanding, and the amount available for future borrowings was $813 million after taking into account letters of credit of $160 million and commercial paper of $777 million. The weighted average interest rateFacilities on the total amount outstanding as of December 31, 2016 was 2.20%.1, 2017.
Sunoco Logistics Credit Facilities Sunoco Logistics maintainsETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions.Facilities on December 1, 2017.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, based on Sunoco Logistics’ election for each interest period, plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2016, the Sunoco Logistics Credit Facility had $1.29 billion of outstanding borrowings, which included commercial paper of $50 million. The weighted average interest rate on the total amount outstanding as of December 31, 2016 was 1.76%.
In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("(“364-Day Credit Facility"Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion, including a $630 million term loan. The terms ofbillion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility are similar to those of the $2.50 billion Sunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. The 364-Day Credit Facility is expected to bewas terminated and repaid in connection with the completion of the ETP and Sunoco Logistics merger.May 2017. Bakken Credit Facility In August 2016, ETP,Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 announced the completion of thecompleted project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”).Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2016,2017, the Bakken Credit Facility had $1.10$2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 20162017 was 2.13%3.00%. PennTex Revolving Credit Facility On December 19, 2014, PennTex entered intopreviously maintained a senior secured$275 million revolving credit facility with Royal Bank of Canada, as administrative agent, and a syndicate of lenders that became effective upon the closing of PennTex’s initial public offering and matures in December 2019commitment (the “PennTex Revolving Credit Facility”). The agreement provides for a $275 million commitment that is expandable up to $400 million under certain conditions. The funds have been used for general purposes, including the funding of capital expenditures. PennTex’s assets have been pledged as collateral for this credit facility.
As of December 31, 2016, PennTex had $106 million of available borrowing capacity underIn August 2017, the PennTex Revolving Credit Facility. As of December 31, 2016, the weighted average interest rate on outstanding borrowingsFacility was 2.90%.repaid and terminated.
Sunoco LP Term Loan In March 2016, Sunoco LP entered intohas a term loan agreement which provides secured financing in an aggregate principal amount of up to $2.035 billion due 2019. Amounts borrowed under the term loan bear interest at either LIBOR or base rate, based on Sunoco LP’s election for each interest period, plus an applicable margin. The proceeds were used to fund a portion of the ETP dropdown and to pay fees and expenses incurred in connection with the ETP dropdown and the term loan. In December, 2016, Sunoco LP entered into an amendment to the term loan to, among other matters, increase the maximum applicable margin for LIBOR rate loans, increase the maximum ratio of funded debt, and add new obligations to maintain a maximum ratio of secured funded debt to EBITDA of the Sunoco LP. As of December 31, 2016, the balance on the term loan was $1.24 billion. In January 2017, Sunoco LP entered into a limited waiver to its term loan, under which the agents and
lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay incremental interest owed under the term loan. As of December 31, 2017, the balance on the term loan was $1.24 billion. The Sunoco LP term loan was repaid in full and terminated on January 23, 2018. See Sunoco LP Private Offering of Senior Notes above. Sunoco LP Credit Facility Sunoco LP maintains a $1.50 billion revolving credit agreement, which was amended in April 2015 from the initially committed amount of $1.25 billion and matures in September 2019. As of December 31, 2016, the Sunoco LP Credit Facility had $1.00 billion of outstanding borrowings. In January 2017, Sunoco LP entered into a limited waiver to its revolving credit facility, under which the agents and lenders party thereto waived and deemed remedied the miscalculations of Sunoco LP’s leverage ratio as set forth in its previously delivered compliance certificates and the resulting failure to pay
incremental interest owed under the revolving credit facility. As of December 31, 2017, the Sunoco LP credit facility had $9 million in standby letters of credit. The amount available for future borrowings on the revolver at December 31, 2017 was $726 million. On October 16, 2017, Sunoco LP entered into the Fifth Amendment to the Credit Agreement with the lenders party thereto and Bank of America, N.A., in its capacity as a letter of credit issuer, as swing line lender, and as administrative agent. The Fifth Amendment amended the agreement to (i) permit the dispositions contemplated by the Retail Divestment, (ii) extend the interest coverage ratio covenant of 2.25x through maturity, (iii) modify the definition of consolidated EBITDA to include the pro forma effect of the divestitures and the new fuel supply contracts, and (iv) modify the leverage ratio covenant. Covenants Related to Our Credit Agreements Covenants Related to the Parent Company The Term Loan Facility and ETE Revolving Credit Facility contain customary representations, warranties, covenants and events of default, including a change of control event of default and limitations on incurrence of liens, new lines of business, merger, transactions with affiliates and restrictive agreements. The Term Loan Facility and ETE Revolving Credit Facility contain financial covenants as follows: Maximum Leverage Ratio – Consolidated Funded Debt (as defined therein) of the Parent Company to Consolidated EBITDA (as defined therein) of the Parent Company of not more than 6.0 to 1, with a permitted increase to 7 to 1 during a specified acquisition period following the close of a specified acquisition; and Consolidated EBITDA (as defined therein) to interest expense of not less than 1.5 to 1. Covenants Related to ETP The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The ETP Credit FacilityFacilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: make certain investments; make Distributions (as defined in the ETP Credit Facility)Facilities) during certain Defaults (as defined in the ETP Credit Facility)Facilities) and during any Event of Default (as defined in the ETP Credit Facility)Facilities); engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; engage in transactions with affiliates; and enter into restrictive agreements. The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit agreement relatingratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%. The ETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit FacilityFacilities also containslimit us, on a financial covenant that provides that the Leverage Ratio,rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the ETP Credit Facility, shall not exceed underlying credit agreements,
of 5.0 to 1, as of the end of each quarter, with a permitted increasewhich can generally be increased to 5.5 to 1 during a Specified Acquisition Period,Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as definedcalculated in accordance with the ETP Credit Facility.credit agreements. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio.
Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries. In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt. Covenants Related to Sunoco Logistics
The Sunoco Logistics $2.50 billion Credit Facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The Sunoco Logistics Credit Facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total Consolidated Funded Indebtedness to Consolidated EBITDA ratio, each as defined in the Sunoco Logistics Credit Facility, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total Consolidated Funded Indebtedness, excluding net unamortized fair value adjustments, to Consolidated EBITDA was 4.4 to 1 at December 31, 2016, as calculated in accordance with the credit agreements.
Covenants Related to Bakken Credit Facility The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to: prohibition of certain incremental secured indebtedness; prohibition of certain liens / negative pledge; limitations on uses of loan proceeds; limitations on asset sales and purchases; limitations on permitted business activities; limitations on mergers and acquisitions; limitations on investments; limitations on transactions with affiliates; and maintenance of commercially reasonable insurance coverage. A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder.
Covenants Related to PennTex
The PennTex Revolving Credit Facility contains various covenants and restrictive provisions that, among other things, limit or restrict PennTex’s ability to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of PennTex’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arm’s-length transactions with affiliates and designate certain subsidiaries of PennTex as “Unrestricted Subsidiaries” for purposes of the credit agreement. Currently, no subsidiaries have been designated as Unrestricted Subsidiaries. PennTex is required to comply with a minimum consolidated interest coverage ratio of 2.50x and a maximum consolidated leverage ratio of 4.75x under the PennTex Revolving Credit Facility.
The borrowed amounts accrue interest at a LIBOR rate or a base rate, based on PennTex’s election for each interest period, plus an applicable margin. The applicable margin used in connection with the interest rates and fees is based on the then applicable Consolidated Total Leverage Ratio (as defined therein). The applicable margin for LIBOR rate loans and letter of credit fees range from 2.00% and 3.25% based on the Consolidated Total Leverage Ratio and the applicable margin for ABR loans ranges from 1.00% to 2.25% based on the Consolidated Total Leverage Ratio. The unused portion of the credit facility is subject to a commitment fee, which is based on the Consolidated Total Leverage Ratio and ranges from 0.35% to 0.50% multiplied by the amount of the unused commitment.
Covenants Related to Sunoco LP The Sunoco LP Credit Facilities contain various customary representations, warranties, covenants and events of default, including a change of control event of default, as defined therein. The Sunoco LP Credit Facilities require Sunoco LP to maintain a leverage ratio (as defined therein) of not more than (a) as of the last day of each fiscal quarter through December 31, 2017, 6.75 to 1.0, (b) as of March 31, 2018, 6.5 to 1.0, (c) as of June 30, 2018, 6.25 to 1.0, (d) as of September 30, 2018, 6.0 to 1.0, (e) as of December 31, 2018, 5.75 to 1.0 and (f) thereafter, 5.5 to 1.0 (in the case of the quarter ending March 31, 2019 and thereafter, subject to increases to 6.0 to 1.0 in connection with certain specified acquisitions in excess of $50 million, as permitted under the Credit Facilities. Indebtedness under the Credit Facilities is secured by a security interest in, among other things, all of Sunoco LP’s present and future personal property and all of the present and future personal property of its guarantors, the capital stock of its material subsidiaries (or 66% of the capital stock of material foreign subsidiaries), and any intercompany debt. Upon the first achievement by Sunoco LP of an investment grade credit rating, all security interests securing borrowings under the Credit Facilities will be released. Compliance With Our Covenants Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities and note agreements could require us or our subsidiaries to pay debt balances prior to scheduled maturity and could negatively impact the subsidiaries ability to incur additional debt and/or our ability to pay distributions. We and our subsidiaries are required to assess compliance quarterly and were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2016.2017. | | 7. | REDEEMABLEETP CONVERTIBLE PREFERRED UNITS: |
The ETP Convertible Preferred Units arewere mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and are reflected as long-term liabilities in our consolidated balance sheets. The ETP Convertible Preferred Units are entitled to a preferential quarterly cash distribution of $0.445 per ETP Preferred Unit if outstanding on the record dates of ETP’s common unit distributions. Holders of the ETP Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of ETP common units issuable upon conversion of the ETP Preferred Units is equal to the issue price of $18.30, plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37. As of December 31, 2016, the ETP Preferred Units were convertible into 0.9 million ETP Common Units. In January 2017, ETP repurchased all of its 1.9 million outstanding Series AETP Convertible Preferred Units for cash in the aggregate amount of $53 million. Limited Partner Units Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Parent Company Quarterly Distributions of Available Cash.” As of December 31, 2016,2017, there were issued and outstanding 1.051.08 billion Common Units representing an aggregate 97.71%94.38% limited partner interest in the Partnership. Our Partnership Agreement contains specific provisions for the allocation of net earnings and losses to the partners for purposes of maintaining the partner capital accounts. For any fiscal year that the Partnership has net profits, such net profits are first allocated to the General Partner until the aggregate amount of net profits for the current and all prior fiscal years equals the aggregate amount of net losses allocated to the General Partner for the current and all prior fiscal years. Second, such net profits shall be allocated to the Limited Partners pro rata in accordance with their respective sharing ratios. For any fiscal year in which the Partnership has net losses, such net losses shall be first allocated to the Limited Partners in proportion to their respective adjusted capital account balances, as defined by the Partnership Agreement, (before taking into account such net losses) until their adjusted capital account balances have been reduced to zero. Second, all remaining net losses shall be allocated to the General Partner. The General Partner may distribute to the Limited Partners funds of the Partnership that the General Partner reasonably determines are not needed for the payment of existing or foreseeable Partnership obligations and expenditures.
Common Units The change in ETE Common Units during the years ended December 31, 20162017, 20152016 and 20142015 was as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Number of Common Units, beginning of period | 1,044.8 |
| | 1,077.5 |
| | 1,119.8 |
| 1,046.9 |
| | 1,044.8 |
| | 1,077.5 |
| Conversion of Class D Units to ETE Common Units | — |
| | 0.9 |
| | — |
| — |
| | — |
| | 0.9 |
| Repurchase of common units under buyback program | — |
| | (33.6 | ) | | (42.3 | ) | — |
| | — |
| | (33.6 | ) | Issuance of common units | 2.1 |
| | — |
| | — |
| 32.2 |
| | 2.1 |
| | — |
| Number of Common Units, end of period | 1,046.9 |
| | 1,044.8 |
| | 1,077.5 |
| 1,079.1 |
| | 1,046.9 |
| | 1,044.8 |
|
ETE Equity Distribution Agreement In March 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1 billion. There was no activity under the distribution agreements for the year ended December 31, 2017. ETE Series A Convertible Preferred Units | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Number of Series A Convertible Preferred Units, beginning of period | — |
| | — |
| | — |
| 329.3 |
| | — |
| | — |
| Issuance of Series A Convertible Preferred Units | 329.3 |
| | — |
| | — |
| — |
| | 329.3 |
| | — |
| Number of Series A Convertible Preferred Units, end of period | 329.3 |
| | — |
| | — |
| 329.3 |
| | 329.3 |
| | — |
|
On March 8, 2016, the Partnership completed a private offering of 329.3 million Series A Convertible Preferred Units representing limited partner interests in the Partnership (the “Convertible Units”) to certain common unitholders (“Electing Unitholders”) who elected to participate in a plan to forgo a portion of their future potential cash distributions on common units participating in the plan for a period of up to nine fiscal quarters, commencing with distributions for the fiscal quarter ended March 31, 2016, and reinvest those distributions in the Convertible Units. With respect to each quarter for which the declaration date and record date occurs prior to the closing of the merger, or earlier termination of the merger agreement (the “WMB End Date”), each participating common unit will receive the same cash distribution as all other ETE common units
up to $0.11 per unit, which represents approximately 40% of the per unit distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Preferred Distribution Amount”), and the holder of such participating common unit will forgo all cash distributions in excess of that amount (other than (i) any non-cash distribution or (ii) any cash distribution that is materially and substantially greater, on a per unit basis, than ETE’s most recent regular quarterly distribution, as determined by the ETE general partner (such distributions in clauses (i) and (ii), “Extraordinary Distributions”)). With respect to each quarter for which the declaration date and record date occurs after the WMB End Date, each participating common unit will forgo all distributions for each such quarter (other than Extraordinary Distributions), and each Convertible Unit will receive the Preferred Distribution Amount payable in cash prior to any distribution on ETE common units (other than Extraordinary Distributions). At the end of the plan period, which is expected to be May 18, 2018, the Convertible Units are expected to automatically convert into common units based on the Conversion Value (as defined and described below) of the Convertible Units and a conversion rate of $6.56. The conversion value of each Convertible Unit (the “Conversion Value”) on the closing date of the offering is zero. The Conversion Value will increase each quarter in an amount equal to $0.285, which is the per unit amount of the cash distribution paid with respect to ETE common units for the quarter ended December 31, 2015 (the “Conversion Value Cap”), less the cash distribution actually paid with respect to each Convertible Unit for such quarter (or, if prior to the WMB End Date, each participating common unit). Any cash distributions in excess of $0.285 per ETE common unit, and any Extraordinary Distributions, made with respect to any quarter during the plan period will be disregarded for purposes of calculating the Conversion Value. The Conversion Value will be reflected in the carrying amount of the Convertible Units until the conversion into common units at the end of the plan period. The Convertible Units had $180$450 million carrying value as of December 31, 2016.2017. ETE issued 329,295,770 Convertible Units to the Electing Unitholders at the closing of the offering, which represents the participation by common unitholders with respect to approximately 31.5% of ETE’s total outstanding common units. ETE’s
Chairman, Kelcy L. Warren, participated in the Plan with respect to substantially all of his common units, which represent approximately 18% of ETE’s total outstanding common units, and was issued 187,313,942 Convertible Units. In addition, John McReynolds, a director of our general partner and President of our general partner; and Matthew S. Ramsey, a director of our general partner and the general partner of ETP and Sunoco LP and President of the general partner of ETP, participated in the Plan with respect to substantially all of their common units, and Marshall S. McCrea, III, a director of our general partner and the general partner of ETP and Sunoco Logistics and the Group Chief Operating Officer and Chief Commercial Officer of our general partner, participated in the Plan with respect to a substantial portion of his common units. The common units for which Messrs. McReynolds, Ramsey and McCrea elected to participate in the Plan collectively represent approximately 2.2% of ETE’s total outstanding common units. ETE issued 21,382,155 Convertible Units to Mr. McReynolds, 51,317 Convertible Units to Mr. Ramsey and 1,112,728 Convertible Units to Mr. McCrea. Mr. Ray Davis, who owns an 18.8% membership interest in our general partner, participated in the Plan with respect to substantially all of his ETE common units, which represents approximately 6.9% of ETE’s total outstanding common units, and was issued 72,042,486 Convertible Units. Other than Mr. Davis, no other Electing Unitholder owns a material amount of equity securities of ETE or its affiliates. ETE January 2017 Private Placement and ETP Unit Purchase In January 2017, ETE issued 32.2 million common units representing limited partner interests in the Partnership to certain institutional investors in a private transaction for gross proceeds of approximately $580 million, which ETE used to purchase 15.823.7 million newly issued ETP common units for approximately $568 million. Common Unit Split On December 23, 2013,July 27, 2015, ETE announced that the board of directors of its general partner approvedcompleted a two-for-one split of the Partnership’s outstanding common units (the “2014 Split”). The 2014 Split was completed on January 27, 2014. The 2014 Split was effected by a distribution of one ETE Common Unit for each common unit outstanding and held by unitholders of record at the close of business on January 13, 2014. On May 28, 2015, ETE announced that the board of directors its general partner approved a two-for-one split of the Partnership’s outstanding common units (the “2015 Split”). The 2015 Split was completed on July 27, 2015. The 2015 Split was effected by a distribution of one ETE common unit for each common unit outstanding and held by unitholders of record at the close of business on July 15, 2015.
Repurchase Program In December 2013, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to $1 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and
other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 42.3 million ETE Common Units under this program through May 23, 2014, and the program was completed.
In February 2015, the Partnership announced a common unit repurchase program, whereby the Partnership may repurchase up to an additional $2 billion of ETE Common Units in the open market at the Partnership’s discretion, subject to market conditions and other factors, and in accordance with applicable regulatory requirements. The Partnership repurchased 33.6 million ETE Common Units under this program in 2015. No units were repurchased under this program in 2017 or 2016, and there was $936 million available to use under the program as of December 31, 2016.2017. Class D Units On May 1,In 2013, Jamie Welch was appointed Group Chief Financial Officer and Head of Corporate Development of LE GP, LLC, the general partner of ETE, effective June 24, 2013. Pursuant to an equity award agreement between Mr. Welch and the Partnership dated April 23, 2013, Mr. Welch received 3,000,000 restricted ETE common units representing limited partner interest. The restricted ETE common units were subject to vesting, based on continued employment with ETE. On December 23, 2013, ETE and Mr. Welch entered into (i) a rescission agreement in order to rescind the original offer letter to the extent it relates to the award of 3,000,000 common units of ETE to Mr. Welch, the original award agreements, and the receipt of cash amounts by Mr. Welch with respect to such awarded units and (ii) a new Class D Unit Agreement between ETE and Mr. Welch providing for the issuance to Mr. Welch of an aggregate ofissued 3,080,000 Class D Units of ETE which number ofpursuant to an agreement with a former executive. The Class D Units includes an additional 80,000 Class D Units that were issued to Mr. Welch in connection with other changes to his original offer letter.
Under the terms of the Class D Unit Agreement, as amended, 30% of the Class D Units convertedconvertible to ETE common units on a one-for-one basis on March 31, 2015, 35%Common Units, subject to certain vesting requirements which were scheduled to convert to ETE common units on a one-for-one-basis on March 31, 2018, and the remaining 35% were scheduled to convert to ETE common units on a one-for-one basis on March 31, 2020, subject in each case to (i) Mr. Welch being in Good Standing with ETE (as defined in the Class D Unit Agreement) and (ii) there being a sufficient amount of gain available (based on the ETE partnership agreement) to be allocatednot met prior to the Class D Units being converted so as to cause the capital account of each such unit to equal the capital account of an ETE Common Unit on the conversion date. Per the terms of the Class D Unit Agreement, 924,000 units converted to ETE common units on a one-for-one basis March 31, 2015. In connection with Mr. Welch’s replacement as Group Chief Financial Officer and Head of Business Development of our General Partner and hisformer executive’s termination of employment by an affiliate of ETE, any future conversion of the Class D Units is the subject of on-going discussions between ETE and Mr. Welch in connection with his separation from employment. On March 10, 2016, Jamie Welch (“Welch”) filed an original petition against ETE and LE GP, LLC in Texas state court in Dallas. A confidential settlement was reached in August 2016. The court dismissed the matter with prejudice on September 6, 2016.
Sale of Common Units by Subsidiaries The Parent Company accounts for the difference between the carrying amount of its investment in subsidiaries and the underlying book value arising from issuance of units by subsidiaries (excluding unit issuances to the Parent Company) as a capital transaction. If a subsidiary issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment has been impaired, in which case a provision would be reflected in our statement of operations. The Parent Company did not recognize any impairment related to the issuances of subsidiary common units during the periods presented. Sale of Common Units by ETP ETP’s Equity Distribution Program From time to time, ETP has sold ETP Common Units through an equity distribution agreement. Such sales of ETP Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreement. In July 2016,connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, ETP entered into an equity distribution agreement with an aggregate offering price up to $1.50$1.00 billion.
During the year ended December 31, 2016,2017, ETP issued 26.122.6 million units for $891$503 million, net of commissions of $8$5 million. As of December 31, 2016, $9362017, $752 million of ETPETP’s Common Units remained available to be issued under theETP’s currently effective equity distribution agreement.
ETP’s Equity Incentive Plan Activity ETP issues ETP Common Units to employees and directors upon vesting of awards granted under ETP’s equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the ETP Common Units to which they are entitled withheld by ETP to satisfy tax-withholding obligations. ETP’s Distribution Reinvestment Program ETP’s Distribution Reinvestment Plan (the “DRIP”) provides ETP’s Unitholders of record and beneficial owners of ETP Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional ETP Common Units. In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, ETP initiated a new distribution reinvestment plan. During the years ended December 31, 2017, 2016 2015 and 2014,2015, aggregate distributions of $228 million, $216 million, $360 million, and $155$360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 17.125.5 million Common Units. As of December 31, 2016,2017, a total of 4.920.8 million Common Units remain available to be issued under the existing registration statement. August 2017 Units Offering In August 2017, ETP issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by ETP to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes. ETP Class E Units TheseThere are currently 8.9 million ETP Class E Units outstanding, all of which are currently owned by HHI. The ETP Class E Units generally do not have any voting rights. The ETP Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all ETP Unitholders, including the ETP Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to ETP Unitholders other thanyear. As the holders of ETP Class E Units in proportion to their respective interests. The ETP Class E Units are treated by ETP as treasury units for accounting purposes because they are owned by a wholly-owned subsidiary, of ETP Holdco, Heritage Holdings, Inc.the cash distributions on those units are eliminated in ETP’s consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire some or all of the ETP Class E Units at a future date. All of the 8.9 million ETP Class E Units outstanding are held by a subsidiary of ETP and are reported by ETP as treasury units.
ETP Class G Units In conjunction with the Sunoco Merger, ETP amended its partnership agreement to create ETP Class F Units. The number of ETP Class F Units issued was determined at the closing of the Sunoco Merger and equaledThere are currently 90.7 million, which included 40 million ETP Class FG Units issued in exchange for cash contributedoutstanding, all of which are held by Sunoco, Inc. to ETP immediately prior to or concurrent with the closingwholly-owned subsidiaries of the Sunoco Merger.ETP. The ETP Class FG Units generally diddo not have any voting rights. The ETP Class FG Units wereare entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by ETP and its subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per ETP Class FG Unit per year. In April 2013, all of the outstanding ETP Class F Units were exchanged for ETP Class G Units on a one-for-one basis. The ETP Class G Units have terms that are substantially the same as the ETP Class F Units, with the principal difference between the ETP Class G Units and the ETP Class F Units being that allocationsAllocations of depreciation and amortization to the ETP Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. The ETP Class G UnitsThese units are held by a subsidiary of ETP and therefore are reflected by ETP as treasury units in itsthe consolidated financial statements.
ETP Class H Units and Class I Units Currently Outstanding
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which arewere generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. Bakken Pipeline Transaction
In March 2015, ETE transferred 30.8 million ETP common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to ETP in exchange for 30.8 million newly issued ETP The Class H Units that, when combinedunits were cancelled in connection with the 50.2merger of ETP and Sunoco Logistics in April 2017.
million previously issued ETP Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, ETP also issued to ETE 100 ETP Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on ETP Class I Units, were reduced by $55 million in 2015 and $30 million in 2016.
In connection with the transaction,Bakken Pipeline Transaction discussed in Note 3, in March 2015, ETP issued 100 ETP Class I Units. The ETP Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the ETP Class I Units for the current taxable period and all previous taxable periods is equal to the cumulative amount of all distributions made to the holders of the ETP Class I Units and (ii) after making cash distributions to ETP Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in ETP’s Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter endingended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the ETP Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding. Bakken Equity Sale On August 2, 2016,In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60%100% membership interest, and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sellsold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum CorporationMPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”).ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continuecontinues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.
Class K Units On December 29, 2016, ETP issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in ETP, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, other than the Class H Units and the Class I Units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. If ETP is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2016,2017, a total of 101,525,429101.5 million Class K Units were held by indirectwholly-owned subsidiaries of ETP. Sales of Common Units by Sunoco Logistics Prior to the Sunoco Logistics Merger, we accounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions. In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol. In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes. In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes. In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion. During the year ended December 31, 2016, Sunoco Logistics received proceedsMerger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Series A and Series Preferred Units In November 2017, ETP issued 950,000 of $744 million, netits 6.250% Series A Preferred Units at a price of commissions$1,000 per unit, and 550,000 of $8 million,its 6.625% Series B Preferred Units at a price of $1,000 per unit. Distributions on the ETP Series A Preferred Units will accrue and be cumulative from and including the issuancedate of 29.1 millionoriginal issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the ETP Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The ETP Series A Preferred Units are redeemable at ETP’s option on or after February 15,
2023 at a redemption price of $1,000 per ETP Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Distributions on the ETP Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the ETP Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The ETP Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per ETP Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. PennTex Tender Offer and Limited Call Right Exercise In June 2017, ETP purchased all of the outstanding PennTex common units pursuant tonot previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the equity distribution agreement. economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ.
Sales of Common Units by Sunoco LP In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. In October 2016, Sunoco LP entered into an equity distribution agreement pursuant to which Sunoco LP may sell from time to time common units having aggregate offering prices of up to $400 million. Through December 31, 2016, Sunoco LP received net proceeds of $71 million from the issuance of 2.8 million Sunoco LP common units pursuant to such equity distribution agreement. Sunoco LP intends to use the proceeds from any sales for general partnership purposes. From January 1, 2017 through December 31, 2017, Sunoco LP issued additional 1.3 million units with total net proceeds of $33 million, net of commissions of $0.3 million. As of December 31, 2016, $3282017, $295 million of Sunoco LP common units remained available to be issued under the currently effective equity distribution agreement. From January 1, 2017 through February 24, 2017, Sunoco LP issued additional 0.4 million units with total net proceeds of $10 million and intends to use the net proceeds from sales for general partnership purposes, which may include repaying or refinancing all or a portion of our outstanding indebtedness and funding capital expenditures, acquisitions or working capital. In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment, and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of ETP. On March 31, 2016, Sunoco LP sold 2.3 million of Sunoco LP’s common units in a private placement to the Partnership. In January 2016, Sunoco LP issued 16.4 million Class C units representing limited partner interest consisting of (i) 5.2 million Class C Units issued by Sunoco LP to Aloha Petroleum, Ltd as consideration for the contribution by Aloha to an indirect wholly-owned subsidiary, and (ii) 11.2 million Class C Units that were issued by Sunoco LP to its indirect wholly-owned subsidiaries in exchange for all of the outstanding Class A Units held by such subsidiaries. In July 2015, Sunoco LP completed an offering of 5.5 million Sunoco LP common units for net proceeds of $213 million. The net proceeds from the offering were used to repay outstanding balances under the Sunoco LP revolving credit facility. In October 2014 and November 2014, Sunoco LP issuedSeries A Preferred Units
On March 30, 2017, the Partnership purchased 12.0 million Sunoco LP Series A Preferred Units representing limited partner interests in Sunoco LP in a private placement transaction for an aggregate totalpurchase price of 9.1 million common units in an underwritten public offering. Aggregate net proceeds$300 million. The distribution rate of $405 million from the offering were used to repay amounts outstanding under the $1.50 billion Sunoco LP Credit FacilitySeries A Preferred Units is10.00%, per annum, of the $25.00 liquidation preference per unit until March 30, 2022, at which point the distribution rate will become a floating rate of 8.00% plus three-month LIBOR of the liquidation preference. In January 2018, Sunoco LP redeemed all outstanding Sunoco LP Series A Preferred Units held by ETE for an aggregate redemption amount of approximately $313 million. The redemption amount included the original consideration of $300 million and for general partnership purposes.a 1% call premium plus accrued and unpaid quarterly distributions. Contributions to Subsidiaries The Parent Company indirectly owns the entire general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP has the right, but not the obligation, to contribute a proportionate amount of capital to ETP to maintain
its current general partner interest. ETP GP’s interest in ETP’s distributions is reduced if ETP issues additional units and ETP GP does not contribute a proportionate amount of capital to ETP to maintain its General Partner interest. Parent Company Quarterly Distributions of Available Cash Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. The Parent Company’s only cash-generating assets currently consist of distributions from ETP and Sunoco LP related to limited and general partner interests, including IDRs, as well as cash generated from our investment in Lake Charles LNG.
Our distributions declared and paid with respect to our common units duringfor the years ended December 31, 2016, 2015, and 2014periods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2013 | | February 7, 2014 | | February 19, 2014 | | $ | 0.1731 |
| March 31, 2014 | | May 5, 2014 | | May 19, 2014 | | 0.1794 |
| June 30, 2014 | | August 4, 2014 | | August 19, 2014 | | 0.1900 |
| September 30, 2014 | | November 3, 2014 | | November 19, 2014 | | 0.2075 |
| December 31, 2014 | | February 6, 2015 | | February 19, 2015 | | 0.2250 |
| March 31, 2015 | | May 8, 2015 | | May 19, 2015 | | 0.2450 |
| June 30, 2015 | | August 6, 2015 | | August 19, 2015 | | 0.2650 |
| September 30, 2015 | | November 5, 2015 | | November 19, 2015 | | 0.2850 |
| December 31, 2015 | | February 4, 2016 | | February 19, 2016 | | 0.2850 |
| March 31, 2016 (1) | | May 6, 2016 | | May 19, 2016 | | 0.2850 |
| June 30, 2016 (1) | | August 8, 2016 | | August 19, 2016 | | 0.2850 |
| September 30, 2016 (1) | | November 7, 2016 | | November 18, 2016 | | 0.2850 |
| December 31, 2016 (1) | | February 7, 2017 | | February 21, 2017 | | 0.2850 |
|
| | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2014 | | February 6, 2015 | | February 19, 2015 | | 0.2250 |
| March 31, 2015 | | May 8, 2015 | | May 19, 2015 | | 0.2450 |
| June 30, 2015 | | August 6, 2015 | | August 19, 2015 | | 0.2650 |
| September 30, 2015 | | November 5, 2015 | | November 19, 2015 | | 0.2850 |
| December 31, 2015 | | February 4, 2016 | | February 19, 2016 | | 0.2850 |
| March 31, 2016 (1) | | May 6, 2016 | | May 19, 2016 | | 0.2850 |
| June 30, 2016 (1) | | August 8, 2016 | | August 19, 2016 | | 0.2850 |
| September 30, 2016 (1) | | November 7, 2016 | | November 18, 2016 | | 0.2850 |
| December 31, 2016 (1) | | February 7, 2017 | | February 21, 2017 | | 0.2850 |
| March 31, 2017 (1) | | May 10, 2017 | | May 19, 2017 | | 0.2850 |
| June 30, 2017 (1) | | August 7, 2017 | | August 21, 2017 | | 0.2850 |
| September 30, 2017 (1) | | November 7, 2017 | | November 20, 2017 | | 0.2950 |
| December 31, 2017 (1) | | February 8, 2018 | | February 20, 2018 | | 0.3050 |
|
| | (1) | Certain common unitholders elected to participate in a plan pursuant to which those unitholders elected to forego their cash distributions on all or a portion of their common units for a period of up to nine quarters commencing with the distribution for the quarter ended March 31, 2016 and, in lieu of receiving cash distributions on these common units for each such quarter, each said unitholder received Convertible Units (on a one-for-one basis for each common unit as to which the participating unitholder elected be subject to this plan) that entitled them to receive a cash distribution of up to $0.11 per Convertible Unit. See Note 8, ETE Series A Preferred Units.additional information below. |
Our distributions declared and paid with respect to our Convertible Unit during the yearyears ended December 31, 2016 and 2017 were as follows: | | Quarter Ended | | Record Date | | Payment Date | | Rate | | Record Date | | Payment Date | | Rate | March 31, 2016 | | May 6, 2016 | | May 19, 2016 | | $ | 0.1100 |
| | May 6, 2016 | | May 19, 2016 | | $ | 0.1100 |
| June 30, 2016 | | August 8, 2016 | | August 19, 2016 | | 0.1100 |
| | August 8, 2016 | | August 19, 2016 | | 0.1100 |
| September 30, 2016 | | November 7, 2016 | | November 18, 2016 | | 0.1100 |
| | November 7, 2016 | | November 18, 2016 | | 0.1100 |
| December 31, 2016 | | February 7, 2017 | | February 21, 2017 | | 0.1100 |
| | February 7, 2017 | | February 21, 2017 | | 0.1100 |
| March 31, 2017 | | | May 10, 2017 | | May 19, 2017 | | 0.1100 |
| June 30, 2017 | | | August 7, 2017 | | August 21, 2017 | | 0.1100 |
| September 30, 2017 | | | November 7, 2017 | | November 20, 2017 | | 0.1100 |
| December 31, 2017 | | | February 8, 2018 | | February 20, 2018 | | 0.1100 |
|
ETP’s Quarterly Distributions of Available Cash Under ETP’s Partnership Agreement requires that ETP distribute all of its Available Cash to its Unitholders and its General Partnerlimited partnership agreement, within 45 days followingafter the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of ETP distributes all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by its General Partnerthe general partner in its solediscretion. This is defined as “available cash” in ETP’s partnership agreement. The general partner has broad discretion to provide forestablish cash reserves that it determines are necessary or appropriate to properly conduct ETP’s business. ETP will make quarterly distributions to the proper conductextent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of the incentive distribution rights receive increasing percentages, up to 48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.” As the holder of Energy Transfer Partners, L.P.’s IDRs, the Parent Company has historically been entitled to an increasing share of Energy Transfer Partners, L.P.’s total distributions above certain target levels. Following the Sunoco Logistics Merger, the Parent Company will continue to be entitled to such incentive distributions; however, the amount of the incentive distributions to be paid by ETP will be determined based on the historical incentive distribution schedule of Sunoco Logistics. The following table summarizes the target levels related to ETP’s distributions (as a percentage of total distributions on common units, IDRs and the general partner interest). The percentage reflected in the table includes only the percentage related to the IDRs and excludes distributions to which the Parent Company would also be entitled through its direct or indirect ownership of ETP’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or moregeneral partner interest, Class I units and a portion of the next four quarters. Available Cash is more fully defined in ETP’s Partnership Agreement.
ETP’s distributions declared during the periods presented below were as follows:outstanding ETP common units.
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2013 | | February 7, 2014 | | February 14, 2014 | | $ | 0.9200 |
| March 31, 2014 | | May 5, 2014 | | May 15, 2014 | | 0.9350 |
| June 30, 2014 | | August 4, 2014 | | August 14, 2014 | | 0.9550 |
| September 30, 2014 | | November 3, 2014 | | November 14, 2014 | | 0.9750 |
| December 31, 2014 | | February 6, 2015 | | February 13, 2015 | | 0.9950 |
| March 31, 2015 | | May 8, 2015 | | May 15, 2015 | | 1.0150 |
| June 30, 2015 | | August 6, 2015 | | August 14, 2015 | | 1.0350 |
| September 30, 2015 | | November 5, 2015 | | November 16, 2015 | | 1.0550 |
| December 31, 2015 | | February 8, 2016 | | February 16, 2016 | | 1.0550 |
| March 31, 2016 | | May 6, 2016 | | May 16, 2016 | | 1.0550 |
| June 30, 2016 | | August 8, 2016 | | August 15, 2016 | | 1.0550 |
| September 30, 2016 | | November 7, 2016 | | November 14, 2016 | | 1.0550 |
| December 31, 2016 | | February 7, 2017 | | February 14, 2017 | | 1.0550 |
|
| | | | | | | | | | | | Marginal Percentage Interest in Distributions | | | Total Quarterly Distribution Target Amount | | IDRs | | Partners (1) | Minimum Quarterly Distribution | | $0.0750 | | —% | | 100% | First Target Distribution | | up to $0.0833 | | —% | | 100% | Second Target Distribution | | above $0.0833 up to $0.0958 | | 13% | | 87% | Third Target Distribution | | above $0.0958 up to $0.2638 | | 35% | | 65% | Thereafter | | above $0.2638 | | 48% | | 52% |
ETE(1) Includes general partner and limited partner interests, based on the proportionate ownership of each.
The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Distributions on common units declared and paid by ETP and Sunoco Logistics during the pre-merger periods were as follows: | | | | | | | | | | Quarter Ended | | ETP | | Sunoco Logistics | December 31, 2014 | | $ | 0.6633 |
| | $ | 0.4000 |
| March 31, 2015 | | 0.6767 |
| | 0.4190 |
| June 30, 2015 | | 0.6900 |
| | 0.4380 |
| September 30, 2015 | | 0.7033 |
| | 0.4580 |
| December 31, 2015 | | 0.7033 |
| | 0.4790 |
| March 31, 2016 | | 0.7033 |
| | 0.4890 |
| June 30, 2016 | | 0.7033 |
| | 0.5000 |
| September 30, 2016 | | 0.7033 |
| | 0.5100 |
| December 31, 2016 | | 0.7033 |
| | 0.5200 |
|
Distributions on common units declared and paid by Post-Merger ETP were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2017 | | May 10, 2017 | | May 16, 2017 | | $ | 0.5350 |
| June 30, 2017 | | August 7, 2017 | | August 15, 2017 | | 0.5500 |
| September 30, 2017 | | November 7, 2017 | | November 14, 2017 | | 0.5650 |
| December 31, 2017 | | February 8, 2018 | | February 14, 2018 | | 0.5650 |
|
In connection with previous transactions, we have agreed to relinquish its right to the following amounts of incentive distributions in future periods: | | | | | | | | Total Year | 2017 | | $ | 626 |
| 2018 | | 138 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Sunoco Logistics Quarterly Distributions of Available Cash | | | | | | | | Total Year | 2018 | | $ | 153 |
| 2019 | | 128 |
| Each year beyond 2019 | | 33 |
|
Distributions declared and paid by Sunoco Logistics duringETP to the years ended December 31, 2016, 2015,Series A and 2014Series B preferred unitholders were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2013 | | February 10, 2014 | | February 14, 2014 | | $ | 0.3312 |
| March 31, 2014 | | May 9, 2014 | | May 15, 2014 | | 0.3475 |
| June 30, 2014 | | August 8, 2014 | | August 14, 2014 | | 0.3650 |
| September 30, 2014 | | November 7, 2014 | | November 14, 2014 | | 0.3825 |
| December 31, 2014 | | February 9, 2015 | | February 13, 2015 | | 0.4000 |
| March 31, 2015 | | May 11, 2015 | | May 15, 2015 | | 0.4190 |
| June 30, 2015 | | August 10, 2015 | | August 14, 2015 | | 0.4380 |
| September 30, 2015 | | November 9, 2015 | | November 13, 2015 | | 0.4580 |
| December 31, 2015 | | February 8, 2016 | | February 12, 2016 | | 0.4790 |
| March 31, 2016 | | May 9, 2016 | | May 13, 2016 | | 0.4890 |
| June 30, 2016 | | August 8, 2016 | | August 12, 2016 | | 0.5000 |
| September 30, 2016 | | November 9, 2016 | | November 14, 2016 | | 0.5100 |
| December 31, 2016 | | February 7, 2017 | | February 14, 2017 | | 0.5200 |
|
PennTex Quarterly Distributions of Available Cash
PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of $0.2750 per unit at the end of each quarter. Distributions declared during the periods presented were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | September 30, 2016 | | November 7, 2016 | | November 14, 2016 | | $ | 0.2950 |
| December 31, 2016 | | February 7, 2017 | | February 14, 2017 | | 0.2950 |
|
| | | | | | | | | | | | | | | Distribution per Preferred Unit | Quarter Ended | | Record Date | | Payment Date | | Series A | | Series B | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.451 |
| | $ | 16.378 |
|
Sunoco LP Quarterly Distributions of Available Cash The following table illustrates the percentage allocations of available cash from operating surplus between Sunoco LP’s common unitholders and the holder of its IDRs based on the specified target distribution levels, after the payment of distributions to Class C unitholders. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the IDR holder and the common unitholders in any available cash from operating surplus which Sunoco LP distributes up to and including the corresponding amount in the column “total quarterly distribution per unit target amount.” The percentage interests shown for common unitholders and IDR holder for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Effective July 1, 2015, ETE exchanged 21 million ETP common units, owned by ETE, the owner of ETP’s general partner interest, for 100% of the general partner interest and all of the IDRs of Sunoco LP. ETP had previously owned our IDRs since September 2014, prior to that date the IDRs were owned by Susser. | | | | | | | | | | | | Marginal Percentage Interest in Distributions | | | Total Quarterly Distribution Target Amount | | Common Unitholders | | Holder of IDRs | Minimum Quarterly Distribution | | $0.4375 | | 100% | | —% | First Target Distribution | | $0.4375 to $0.503125 | | 100% | | —% | Second Target Distribution | | $0.503125 to $0.546875 | | 85% | | 15% | Third Target Distribution | | $0.546875 to $0.656250 | | 75% | | 25% | Thereafter | | Above $0.656250 | | 50% | | 50% |
Distributions declared and paid by Sunoco LP subsequent to our acquisition on August 29, 2014for the periods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | September 30, 2014 | | November 18, 2014 | | November 28, 2014 | | $ | 0.5457 |
| December 31, 2014 | | February 17, 2015 | | February 27, 2015 | | 0.6000 |
| March 31, 2015 | | May 19, 2015 | | May 29, 2015 | | 0.6450 |
| June 30, 2015 | | August 18, 2015 | | August 28, 2015 | | 0.6934 |
| September 30, 2015 | | November 17, 2015 | | November 27, 2015 | | 0.7454 |
| December 31, 2015 | | February 5, 2016 | | February 16, 2016 | | 0.8013 |
| March 31, 2016 | | May 6, 2016 | | May 16, 2016 | | 0.8173 |
| June 30, 2016 | | August 5, 2016 | | August 15, 2016 | | 0.8255 |
| September 30, 2016 | | November 7, 2016 | | November 15, 2016 | | 0.8255 |
| December 31, 2016 | | February 13, 2017 | | February 21, 2017 | | 0.8255 |
|
| | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2014 | | February 17, 2015 | | February 27, 2015 | | 0.6000 |
| March 31, 2015 | | May 19, 2015 | | May 29, 2015 | | 0.6450 |
| June 30, 2015 | | August 18, 2015 | | August 28, 2015 | | 0.6934 |
| September 30, 2015 | | November 17, 2015 | | November 27, 2015 | | 0.7454 |
| December 31, 2015 | | February 5, 2016 | | February 16, 2016 | | 0.8013 |
| March 31, 2016 | | May 6, 2016 | | May 16, 2016 | | 0.8173 |
| June 30, 2016 | | August 5, 2016 | | August 15, 2016 | | 0.8255 |
| September 30, 2016 | | November 7, 2016 | | November 15, 2016 | | 0.8255 |
| December 31, 2016 | | February 13, 2017 | | February 21, 2017 | | 0.8255 |
| March 31, 2017 | | May 9, 2017 | | May 16, 2017 | | 0.8255 |
| June 30, 2017 | | August 7, 2017 | | August 15, 2017 | | 0.8255 |
| September 30, 2017 | | November 7, 2017 | | November 14, 2017 | | 0.8255 |
| December 31, 2017 | | February 06, 2018 | | February 14, 2018 | | 0.8255 |
|
Accumulated Other Comprehensive Income (Loss) The following table presents the components of AOCI, net of tax: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Available-for-sale securities | $ | 2 |
| | $ | — |
| $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (5 | ) | | (4 | ) | (5 | ) | | (5 | ) | Actuarial gain related to pensions and other postretirement benefits | 7 |
| | 8 |
| | Actuarial gain (loss) related to pensions and other postretirement benefits | | (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 4 |
| | — |
| 5 |
| | 4 |
| Subtotal | 8 |
| | 4 |
| 3 |
| | 8 |
| Amounts attributable to noncontrolling interest | (8 | ) | | (4 | ) | (3 | ) | | (8 | ) | Total AOCI included in partners’ capital, net of tax | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
|
The table below sets forth the tax amounts included in the respective components of other comprehensive income (loss): | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 4 |
| 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | — |
| | 7 |
| 3 |
| | — |
| Total | $ | 1 |
| | $ | 9 |
| $ | 4 |
| | $ | 1 |
|
| | 9. | UNIT-BASED COMPENSATION PLANS: |
We, ETP Sunoco Logistics and Sunoco LP have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase Common Units, restricted units, phantom units, distribution equivalent rights (“DERs”), common unit appreciation rights, cash restricted units and other unit-based awards. ETE Long-Term Incentive Plan The Board of Directors or the Compensation Committee of the board of directors of the our General Partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE. The plan provides for the following types of awards: restricted units, phantom
units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be
delivered pursuant to these awards is limited to 12,000,00012.0 million units. As of December 31, 2016, 8,271,7672017, 10.8 million units remain available to be awarded under the plan. During the year ended December 31, 2016, no2017, 1.2 million ETE unit awards were granted to ETE employees and 23,821certain employees of ETP and 15,648 ETE units were granted to non-employee directors. Under our equity incentive plans, our non-employee directors each receive grants that vest 60% in three years and 40% in five years and do not entitle the holders to receive distributions during the vesting period. During the year ended December 31, 20162017 and 2015,2016, a total of 28,6482,018 and 26,24428,648 ETE Common Units vested, with a total fair value of $0.2 million$39 thousand and $0.8 million,$205 thousand, respectively, as of the vesting date. As of December 31, 2016,2017, a total of 43,7401,251,002 restricted units granted to ETE directors remain outstanding, for which we expect to recognize a total of less than $1$21 million in compensation over a weighted average period of 3.03.5 years. Subsidiary Unit-Based Compensation Plans Each of ETP Sunoco Logistics and Sunoco LP has granted restricted or phantom unit awards (collectively, the “Subsidiary Unit Awards” to employees and directors that entitle the grantees to receive common units of the respective subsidiary. In some cases, at the discretion of the respective subsidiary’s compensation committee, the grantee may instead receive an amount of cash equivalent to the value of common units upon vesting. Substantially all of the Subsidiary Unit Awards are time-vested grants, which generally vest over a five-year period, and vesting The Subsidiary Unit Awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by the respective subsidiaries during the period the restricted unit is outstanding. The following table summarizes the activity of the Subsidiary Unit Awards: | | | | | | | | | | | | | | | | | | | | | | | ETP | | Sunoco Logistics | | Sunoco LP | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Unvested awards as of December 31, 2015 | 4.8 |
| | $ | 47.61 |
| | 2.5 |
| | $ | 33.16 |
| | 1.1 |
| | $ | 41.19 |
| Awards granted | 2.5 |
| | 35.73 |
| | 1.3 |
| | 23.21 |
| | 1.0 |
| | 26.95 |
| Awards vested | (0.8 | ) | | 53.22 |
| | (0.5 | ) | | 34.19 |
| | — |
| | 36.98 |
| Awards forfeited | (0.2 | ) | | 48.39 |
| | (0.1 | ) | | 33.72 |
| | (0.1 | ) | | 39.77 |
| Unvested awards as of December 31, 2016 | 6.3 |
| | 41.53 |
| | 3.2 |
| | 28.57 |
| | 2.0 |
| | 34.43 |
| | | | | | | | | | | | | Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31: | | | | | | | | | | | | 2016 | | | $ | 35.73 |
| | | | $ | 23.21 |
| | | | $ | 26.95 |
| 2015 | | | 35.21 |
| | | | 29.54 |
| | | | 40.63 |
| 2014 | | | 60.85 |
| | | | 41.59 |
| | | | 45.50 |
|
| | | | | | | | | | | | | | | | ETP | | Sunoco LP | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Unvested awards as of December 31, 2016 | 9.4 |
| | $ | 27.68 |
| | 2.0 |
| | $ | 34.43 |
| Legacy Sunoco Logistics unvested awards as of December 31, 2016 | 3.2 |
| | 28.57 |
| | — |
| | — |
| Awards granted | 4.9 |
| | 17.69 |
| | 0.2 |
| | 28.31 |
| Awards vested | (2.3 | ) | | 34.22 |
| | (0.3 | ) | | 45.48 |
| Awards forfeited | (1.1 | ) | | 25.03 |
| | (0.2 | ) | | 34.71 |
| Unvested awards as of December 31, 2017 | 14.1 |
| | 23.18 |
| | 1.7 |
| | 31.89 |
|
| | | | | | | | | | | | | Weighted average grant date fair value for Subsidiary Unit Awards during the year ended December 31: | | | | | | | | 2017 | | | $ | 17.69 |
| | | | $ | 28.31 |
| 2016 | | | 23.82 |
| | | | 26.95 |
| 2015 | | | 23.47 |
| | | | 40.63 |
|
The total fair value of Subsidiary Unit Awards vested for the years ended December 31, 2017, 2016, 2015, and 20142015 was $40 million, $57$40 million, and $56$57 million, respectively, based on the market price of the respective subsidiaries’ common units as of the vesting date. As of December 31, 2016,2017, estimated compensation cost related to Subsidiary Unit Awards not yet recognized was $275$216 million, and the weighted average period over which this cost is expected to be recognized in expense is 2.1 years, 3.0 years and 4.3 years for ETP, Sunoco Logistics, and Sunoco LP, respectively.2.8 years.
As a partnership, we are not subject to U.S.United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) of our taxable subsidiaries were summarized as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Current expense (benefit): | | | | | | | | | | | Federal | $ | 11 |
| | $ | (292 | ) | | $ | 321 |
| $ | 54 |
| | $ | (47 | ) | | $ | (308 | ) | State | (27 | ) | | (51 | ) | | 86 |
| (16 | ) | | (34 | ) | | (54 | ) | Total | (16 | ) | | (343 | ) | | 407 |
| 38 |
| | (81 | ) | | (362 | ) | Deferred expense (benefit): | | | | | | | | | | | Federal | (221 | ) | | 272 |
| | (53 | ) | (2,055 | ) | | (189 | ) | | 268 |
| State | 20 |
| | (29 | ) | | 3 |
| 184 |
| | 12 |
| | (29 | ) | Total | (201 | ) | | 243 |
| | (50 | ) | (1,871 | ) | | (177 | ) | | 239 |
| Total income tax expense (benefit) from continuing operations | $ | (217 | ) | | $ | (100 | ) | | $ | 357 |
| $ | (1,833 | ) | | $ | (258 | ) | | $ | (123 | ) |
Historically, our effective tax rate has differed from the statutory rate primarily due to partnership earnings that are not subject to U.S.United States federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and the Susser Merger - (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S.United States statutory rate to the income tax expense (benefit) attributable to continuing operations for the years ended December 31, 20162017, 20152016 and 20142015 is as follows: | | | December 31, 2016 | December 31, 2015 | December 31, 2014 | 2017 | | 2016 | | 2015 | Income tax expense (benefit) at U.S. statutory rate of 35 percent | $ | (62 | ) | | $ | 348 |
| | $ | 496 |
| | Income tax expense (benefit) at United States statutory rate of 35 percent | | $ | 248 |
| | $ | 71 |
| | $ | 316 |
| Increase (reduction) in income taxes resulting from: | | | | | | | | | | | Nondeductible goodwill included in the Lake Charles LNG transaction | — |
| | — |
| | 105 |
| | Partnership earnings not subject to tax | (590 | ) | | (366 | ) | | (284 | ) | (477 | ) | | (576 | ) | | (355 | ) | Goodwill impairment | 448 |
| | — |
| | — |
| 207 |
| | 278 |
| | — |
| State tax, net of federal tax benefit | (1 | ) | | (26 | ) | | 55 |
| 124 |
| | (10 | ) | | (29 | ) | Dividend received deduction | (15 | ) | | (22 | ) | | — |
| (14 | ) | | (15 | ) | | (22 | ) | Premium on debt retirement | — |
| | — |
| | (10 | ) | | Federal rate change | | (1,812 | ) | | — |
| | — |
| Audit settlement | — |
| | (7 | ) | | — |
| — |
| | — |
| | (7 | ) | Foreign taxes | — |
| | — |
| | (8 | ) | | Change in tax status of subsidiary | | (124 | ) | | — |
| | — |
| Other | 3 |
| | (27 | ) | | 3 |
| 15 |
| | (6 | ) | | (26 | ) | Income tax expense (benefit) from continuing operations | $ | (217 | ) | | $ | (100 | ) | | $ | 357 |
| $ | (1,833 | ) | | $ | (258 | ) | | $ | (123 | ) |
Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Deferred income tax assets: | | | | | | | Net operating losses and alternative minimum tax credit | $ | 472 |
| | $ | 217 |
| $ | 683 |
| | $ | 472 |
| Pension and other postretirement benefits | 30 |
| | 36 |
| 21 |
| | 30 |
| Long term debt | 32 |
| | 61 |
| | Long-term debt | | 14 |
| | 32 |
| Other | 182 |
| | 162 |
| 191 |
| | 182 |
| Total deferred income tax assets | 716 |
| | 476 |
| 909 |
| | 716 |
| Valuation allowance | (118 | ) | | (121 | ) | (189 | ) | | (118 | ) | Net deferred income tax assets | 598 |
| | 355 |
| 720 |
| | 598 |
| | | | | | | | Deferred income tax liabilities: | | | | | | | Properties, plants and equipment | (1,633 | ) | | (1,633 | ) | | Property, plant and equipment | | (1,036 | ) | | (1,633 | ) | Investments in unconsolidated affiliates | (3,789 | ) | | (2,976 | ) | (2,726 | ) | | (3,789 | ) | Trademarks | (273 | ) | | (286 | ) | (173 | ) | | (273 | ) | Other | (15 | ) | | (50 | ) | (100 | ) | | (15 | ) | Total deferred income tax liabilities | (5,710 | ) | | (4,945 | ) | (4,035 | ) | | (5,710 | ) | Accumulated deferred income taxes | $ | (5,112 | ) | | $ | (4,590 | ) | | Net deferred income taxes | | $ | (3,315 | ) | | $ | (5,112 | ) |
The table below provides a rollforward of the net deferred income tax liability as follows: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Net deferred income tax liability, beginning of year | $ | (4,590 | ) | | $ | (4,410 | ) | $ | (5,112 | ) | | $ | (4,590 | ) | Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | (460 | ) | | — |
| — |
| | (460 | ) | Net assets (excluding goodwill) associated with Sunoco Retail to Sunoco LP (see Note 3) | (243 | ) | | — |
| — |
| | (243 | ) | Tax provision | 201 |
| | (242 | ) | | Tax provision, including provision from discontinued operations | | 1,825 |
| | 201 |
| Other | (20 | ) | | 62 |
| (28 | ) | | (20 | ) | Net deferred income tax liability | $ | (5,112 | ) | | $ | (4,590 | ) | $ | (3,315 | ) | | $ | (5,112 | ) |
ETP Holdco and certain other corporate subsidiaries have federal net operating loss carryforward tax benefits of $292$403 million, all of which will expire in 20322031 through December 31, 2035.2037. Our corporate subsidiaries have state$62 million of federal alternative minimum tax credits at December 31, 2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have net operating loss carryforward benefits of $127$274 million, $217 million net of federal tax, which expire between January 1, 20172018 and 2036.2037. A valuation allowance of $118$186 million is applicable to the state net operating loss carryforward benefits applicable to significant restriction on their use in the Commonwealth of Pennsylvania.Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.
The following table sets forth the changes in unrecognized tax benefits: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Balance at beginning of year | $ | 610 |
| | $ | 440 |
| | $ | 429 |
| $ | 615 |
| | $ | 610 |
| | $ | 440 |
| Additions attributable to tax positions taken in the current year | 8 |
| | 178 |
| | 20 |
| — |
| | 8 |
| | 178 |
| Additions attributable to tax positions taken in prior years | 18 |
| | — |
| | — |
| 28 |
| | 18 |
| | — |
| Reduction attributable to tax positions taken in prior years | (20 | ) | | — |
| | (1 | ) | (25 | ) | | (20 | ) | | — |
| Settlements | — |
| | — |
| | (5 | ) | | Lapse of statute | (1 | ) | | (8 | ) | | (3 | ) | (9 | ) | | (1 | ) | | (8 | ) | Balance at end of year | $ | 615 |
| | $ | 610 |
| | $ | 440 |
| $ | 609 |
| | $ | 615 |
| | $ | 610 |
|
As of December 31, 2016,2017, we have $596$605 million ($554576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $1 million ($0.6 million, net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2016,2017, we recognized interest and penalties of less than $1$3 million. At December 31, 2016,2017, we have interest and penalties accrued of $6$9 million, net of tax. Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in its litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the consolidated balance sheet as of December 31, 2016.2017. In December of 2015, Thethe Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”Nextel”) that the Pennsylvania limitation on NOL carryforwardscarryforward deductions violated the uniformity clause of the Pennsylvania Constitution. Based uponConstitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision in with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel, has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court. Sunoco, Inc. is recognizinghas recognized approximately $46$67 million ($3053 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims.claims as relates to its cases currently held pending the Nextel matter. However, asbased upon the NextelPennsylvania Supreme Court’s October 2017 decision, is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9$27 million ($621 million after federal income tax benefits) against the receivable.
In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007. Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. ETE and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations. Income Tax Benefit.On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.81 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.
| | 11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Contingent Residual Support Agreement —– AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to providepreviously provided contingent residual support of $1.55 billioncertain debt obligations of intercompany borrowings made byAmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and certain of its affiliates with maturities through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchases. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under theno longer provides contingent residual support agreement. In February 2017,for any AmeriGas repurchased $378 million of its 7.00% senior notes, which reduced the remaining amount supported by ETP to $122 million.notes. Guarantee of Sunoco LP Notes In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC.LLC (“ETC M-A”). NGL Pipeline RegulationOn January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
We$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023; $800 million aggregate principal amount of 5.50% senior notes due 2026; and $400 million aggregate principal amount of 5.875% senior notes due 2028. Under the guarantee of collection, ETC M-A would have intereststhe obligation to pay the principal of each series of notes once all remedies, including in NGL pipelines locatedthe context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in Texas and New Mexico. We commencedrespect of the interstate transportationprincipal of NGLs in 2013, which issuch notes. ETC M-A will not otherwise be subject to the jurisdictioncovenants of the FERC underindenture governing the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.notes. FERC Audit In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing. Commitments In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. ETP’s joint venture agreements require that they fund their proportionate share of capital contributions to their unconsolidated affiliates. Such contributions will depend upon their unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations.
We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034.with typical initial terms of 5 to 15 years, with some having a term of 40 years or more. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: | | | | Years Ended December 31, | | Years Ended December 31, | | | 2016 | | 2015 | | 2014 | | 2017 | | 2016 | | 2015 | Rental expense(1) | | $ | 221 |
| | $ | 225 |
| | $ | 159 |
| | $ | 196 |
| | $ | 187 |
| | $ | 281 |
| Less: Sublease rental income | | (30 | ) | | (16 | ) | | (26 | ) | | (25 | ) | | (26 | ) | | (26 | ) | Rental expense, net | | $ | 191 |
| | $ | 209 |
| | $ | 133 |
| | $ | 171 |
| | $ | 161 |
| | $ | 255 |
|
| | (1) | Includes contingent rentals totaling $23$16 million, $26$18 million and $24$20 million for the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively. |
Future minimum lease commitments for such leases are: | | Years Ending December 31: | | | 2017 | $ | 148 |
| | 2018 | 129 |
| $ | 113 |
| 2019 | 117 |
| 100 |
| 2020 | 112 |
| 96 |
| 2021 | 108 |
| 83 |
| 2022 | | 71 |
| Thereafter | 548 |
| 606 |
| Future minimum lease commitments | 1,162 |
| 1,069 |
| Less: Sublease rental income | (79 | ) | (152 | ) | Net future minimum lease commitments | $ | 1,083 |
| $ | 917 |
|
Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Dakota Access Pipeline During the summer of 2016, individuals affiliated with, or sympathetic to, the Standing Rock Sioux Tribe (the “SRST”) began gathering near a construction site on the Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. At this time, we are working with the various authorities to mitigate the effects of this largely unlawful protest. We believe that Dakota Access now has the necessary permits and approvals to perform all work on the pipeline project. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted Dakota Access’s request for a TRO, and the defendants filed a motion to dismiss the case and dissolve the TRO. The Court later granted the defendants’ motions to dissolve the TRO. Dakota Access filed a response to the defendant’s motion to dismiss, and the Court has yet to rule. At this time, we cannot determine how long the protest will continue, how the legal action will be resolved. Construction work on the pipeline is ongoing, and, barring legal delays, we expect the final portion of the pipeline to be completed in March or April. Additional protests or legal actions may arise in connection with our Dakota Access project or other projects. Trespass on to construction sites or our physical facilities, or other disruptions, could result in further damage to our assets, safety incidents, potential liability or project delays.
InOn July 25, 2016, the U.S.United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. TheAfter significant delay, the USACE has also issued an easementeasements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The SRSTAlso in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S.United States District Court for the District of Columbia against the USACE challengingthat challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimingclaimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access’ moved to interveneAccess intervened in the case and that motion was granted by the Court.case. The SRST has also soughtsoon added a request for an emergency TROtemporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction. injunction, rendering the TRO request moot.
After that decision,the September 9, 2016 ruling, the Department of the Army, the Department of Justice,DOJ, and the Department of the Interior released a joint statement stating that the USACE would not grant the easement for the land adjacent to Lake Oahe until the federal departmentsDepartment of the Army completed a review ofto determine whether it was necessary to reconsider the SRST’s claims in its lawsuit with respectUSACE’s decision under various federal statutes relevant to the USACE’s compliance with certain federal statutes in connection with its activities related to the granting of the permits. pipeline approval. The SRST appealed the denial of the preliminary injunction to the U.S.United States Court of Appeals for the D.C. Circuit and filed an emergency motion in the United States District Court for an injunction pending the appeal, towhich was denied. The D.C. Circuit then denied the U.S. District Court. The U.S. District Court denied SRST’s emergency motionapplication for an injunction pending appeal and later dismissed SRST’s appeal of the appeal.order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statuesstatutes governing the use of government property. The D.C. Circuit denied the SRST’s application for a stay pending appeal and later dismissed the SRST’s appeal of the denied TRO. In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In JanuaryFebruary 2017, pursuantin response to a presidential memorandum, the Department the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access an easementallowing the pipeline to cross Lake Oahe. Construction at the site is ongoing. In the fall of 2016,Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened alongsidein the SRST. After USACE gave Dakota Access its final easement, the Cheyenne River Siouxlawsuit in August 2016, moved for a preliminary injunction and temporary restraining order blocking construction.TRO to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the Tribe. The district courtDistrict Court denied the TRO and has yet to decide whether to grant a preliminary injunction. The SRST has also moved for summary judgment on its claims against the government based on its treaty rightsinjunction, and the National Environmental Policy Act,CRST appealed and requested an injunction pending appeal in the district court is still considering this motion. Briefing is ongoing.and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal.
The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes. On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018. On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017. In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing. While we believe that the pending lawsuits are unlikely to block constructionhalt or suspend the operation of the pipeline, and that construction on the land adjacent to Lake Oahe will be completed in a timely manner, we cannot assure this outcome. Any significant delay imposed by the court will delay the receipt of revenue from this project. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project. Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (Lone Star)(“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. TheLone Star is still quantifying the extent of possibleits incurred and ongoing damages is still under investigation.and has or will be seeking reimbursement for these losses. MTBE Litigation Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other refiners, manufacturers and sellersmembers of gasoline,the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically include water purveyors and municipalities responsible for supplying drinking water andstate-level governmental authorities. The plaintiffs primarilyentities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, andand/or deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of December 31, 2016,2017, Sunoco, Inc. is a defendant in sixseven cases, including casesone case each initiated by the States of Maryland, New Jersey, Vermont, Pennsylvania, Rhode Island, one by the Commonwealth of Pennsylvania and two others by the Commonwealth of Puerto Rico with theRico. The more recent Puerto Rico action beingis a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are venuedpending in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico, Vermont, and Pennsylvania cases assert natural resource damage claims.court; one is
Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phasepending in the New Jersey casefederal court in Rhode Island, one is pending in state court in Vermont, and the initial Puerto Rico case. The initial set of 19 New Jersey trial sites are nowone is pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participatestate court in global settlement discussions in a global mediation forum before Hon. Garrett Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. The first mediation session with Judge Brown is scheduled for November 2 through November 3, 2016. In early 2017, Maryland.
Sunoco, Inc. and two other co-defendantsSunoco, Inc. (R&M) have reached a settlement in principle with the State of New Jersey, subject toJersey. The Court approved the parties agreeingJudicial Consent Order on December 5, 2017. Dismissal of the termscase against Sunoco, Inc. and conditions of a Settlement and Release agreement. Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018. It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that anAn adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any saidsuch adverse determination occurs, but does not believe that any such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position. Regency Merger Litigation Following the January 26, 2015 announcement of the Regency Merger,Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal.dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, on behalf of Regency’s common unitholdersDieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware. Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”). The lawsuitRegency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. Defendants filed a motion to dismiss, and onOn March 29, 2016, the Delaware courtCourt of Chancery granted the Regency Litigation Defendants’ motion and dismissedto dismiss the lawsuit. On April 26, 2016,lawsuit in its entirety. Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument was held on November 16, 2016 before the Delaware Supreme Court.appealed. On January 20, 2017, the Delaware Supreme Court issued an order reversingreversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery that dismissed Counts Iissued an Order granting in part and IIdenying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC. The Regency Litigation Defendants cannot predict the outcome of the Dieckman’s Complaint.Regency Merger Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger. Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal with the TexasCourt of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. Thereversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.due February 26, 2018. Sunoco Logistics Merger Litigation Between January 6, 2017 and February 8, 2017, sevenSeven purported ETPEnergy Transfer Partners, L.P. common unitholders (“(the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits challengingagainst ETP, ETP GP, ETP LLC, the mergermembers of the ETP Board, and the disclosures madeETE (the “ETP-SXL Defendants”) in connection with the merger.announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits are styled (a)were consolidated as Koma v.In re Energy Transfer Partners, L.P. Shareholder Litig., et al., Case No. 3:17-cv-00060-G, in the United States District Court for the Northern District of Texas, Dallas Division (the “Koma Lawsuit”); (b) Ashraf v. Energy Transfer Partners, L.P. et al., Case No. 3:17-cv-00118-B, in the United States District Court for the Northern District of Texas, Dallas Division (the “Ashraf Lawsuit”); (c) Shure v. Energy Transfer Partners, L.P. et al., CaseC.A. No. 1:17-cv-00044-UNA,17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Shure Lawsuit”); (d) Verlin v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the “Verlin Lawsuit”); (e) Duany v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the “Duany Lawsuit”); (f) Epstein v. Energy Transfer Partners, L.P. et. al., Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the “Epstein Lawsuit”) and (g) Sgnilek v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the “Sgnilek Lawsuit” and collectively with the Koma Lawsuit, Ashraf Lawsuit, Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit,
the “Lawsuits”“Sunoco Logistics Merger Litigation”). The Koma Lawsuit, Ashraf Lawsuit, Duany Lawsuit, and Epstein Lawsuit are filed against ETP ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively “Defendants”).
Unitholder Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According toSunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE’s, ETP’s, and Sunoco Logistics’ financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, Plaintiffs allege that (i) Defendants have violated Section 14(a)sought rescission of the Exchange ActSunoco Logistics Merger or rescissory damages for ETP unitholders, as well
as an award of costs and Rule 14a-9 promulgated thereunder and (ii)attorneys’ fees. On October 5, 2017, the members ofETP-SXL Defendants filed a Motion to Dismiss the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process. Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP have aided and abetted those alleged breaches. Based on these allegations, Plaintiffs seek to enjoin Defendants from proceeding with or consummating the merger unless and until Defendants disclose the allegedly omitted information summarized above. The Koma Lawsuit and Sgnilek Lawsuit also seek to enjoin Defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and attorneys’ fees.
Defendants’ dates to answer, move to dismiss, or otherwiseUnitholder Plaintiffs’ claims. Rather than respond to the Lawsuits have not yet been set.Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of these or any othersuch lawsuits that might be filed subsequent tobe. Nor can the date of the filing of this annual report, nor canETP-SXL Defendants predict the amount of time and expense that willwould be required to resolve such litigation.lawsuits. The ETP-SXL Defendants believe the Lawsuits areSunoco Logistics Merger Litigation was without merit and intend to defend vigorously against the Lawsuits and any other actionsfuture lawsuits challenging the merger.Sunoco Logistics Merger. Litigation Filed By or Against WMBWilliams On April 6, 2016, WMBWilliams filed a complaint,The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG, against ETE and LE GP in the Delaware Court of Chancery (the “First Delaware WMBWilliams Litigation”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., C.A. No. 12168-VCG. WMB alleged that Defendants breached the merger agreement between WMB, ETE, and several of ETE’s affiliates (the “Merger Agreement”) by issuing ETE’s Series A Convertible Preferred Units. According to WMB, the issuance of Convertible Units (the “Issuance”) violates various contractual restrictions on ETE’s actions between the execution and closing of the merger. WMB sought, among other things, to (a) rescind the Issuance and (b) invalidate an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the Issuance. On May 3, 2016, ETE and LE GP filed an answer and counterclaim in the First Delaware WMBWilliams Litigation. The counterclaim asserts in general that WMBWilliams materially breached its obligations under the Merger Agreement by (a) blocking ETE’s attempts to complete a public offering of the Convertible Units, including, among other things, by declining to allow WMB’sWilliams’ independent registered public accounting firm to provide the auditor consent required to be included in the registration statement for a public offering and (b) bringing a lawsuit concerning the Texas WMB LitigationIssuance against Mr. Warren in the District Court of Dallas County, Texas.Texas, which the Texas state court later dismissed based on the Merger Agreement’s forum-selection clause. On May 13, 2016, WMBWilliams filed a second lawsuit in the Delaware Court of Chancery (the “Court”) against ETE and LE GP and added Energy Transfer Corp LP, ETE Corp GP, LLC, and Energy Transfer Equity GP, LLC as additional defendants (the “Second Delaware WMB Litigation”(collectively, “Defendants”). This lawsuit is styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., et al.al., C.A. No. 12337-VCG.12337-VCG (the “Second Delaware Williams Litigation”). In general, WMBWilliams alleged that the defendantsDefendants breached the Merger Agreement by (a) failing to use commercially reasonable efforts to obtain from Latham & Watkins LLP (“Latham”) the delivery of a tax opinion underconcerning Section 721 of the TaxInternal Revenue Code (“721 Opinion”), (b) breaching a condition precedent torepresentation and warranty in the closingMerger Agreement concerning Section 721 of the merger,Internal Revenue Code, and (b)(c) taking actions that allegedly delayed the SEC in declaring the Form S-4 filed in connection with the merger (the “Form S-4”) effective. WMBWilliams asked the Court, in general, to (a) issue a declaratory judgment that ETE breached the Merger Agreement, (b) enjoin ETE from terminating the Merger Agreement on the basis that it failed to obtain a 721 Opinion, (c) enjoin ETE from terminating the Merger Agreement on the basis that the transaction failed to close by the outside date, and (d) force ETE to close the merger or take various other affirmative actions. WMB sought to expedite the second lawsuit, and ETE agreed to expedite both Delaware actions.
ETE also filed an answer and counterclaim in the Second Delaware WMBWilliams Litigation. In addition to the counterclaims previously asserted, ETE asserted that WMBWilliams materially breached the Merger Agreement by, among other things, (a) modifying or qualifying the WMBWilliams board of directors’ recommendation to its stockholders regarding the merger, (b) failing to provide material information to ETE for inclusion in the Form S-4 related to the merger, necessary to prevent the Form S-4 from being materially misleading, (c) failing to facilitate the financing of the merger, (d) failing to be reasonable with respect to its withholding of its consent to ETE’s offering of Series A Convertible Preferred Units, and (e) failing to use its reasonable best efforts to consummate the merger.merger, and (e) breaching the Merger Agreement’s forum-selection clause. ETE sought, among other things, a declaration that it could validly terminate the Merger Agreement after June 28, 2016 in the event that Latham was unable to deliver the 721 Opinion on or prior to June 28, 2016. After expedited discovery and a two-day trial on June 20 and 21, 2016, the Court ruled in favor of ETE on Williams’ claims in the Second Delaware Williams Litigation and issued a declaratory judgment that ETE could terminate the merger after June 28, 2016 because of Latham’s inability to provide the required 721 Opinion. The Court also denied WMB’sWilliams’ requests for injunctive relief. WMBThe Court did not reach a decision regarding Williams’ claims related to the Issuance or ETE’s counterclaims. Williams filed a notice of appeal to the Supreme Court of Delaware on June 27, 2016. The appeal is2016, styled The Williams Companies, Inc. v. Energy Transfer Equity, L.P., No. 330, 2016. Williams filed an amended complaint on September 16, 2016. In the amended complaint, Williams abandons its request for injunctive relief, including its request that the Court order the ETE Defendants to consummate the merger. Instead, Williams seeks2016 and sought a $410 million termination fee and additional damages of up to $10 billion based on the purported lost value of the merger consideration. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that the ETE Defendants breached an additional representation and warranty in the Merger Agreement. The ETE Defendants filed amended counterclaims and affirmative defenses on September 23, 2016. In the amended counterclaim, the ETE Defendants seek2016 and sought a $1.48 billion termination fee under the Merger Agreement and additional damages caused by Williams’ misconduct. These damages claims are based on the alleged breaches of the Merger Agreement detailed above, as well as new allegations that Williams breached the Merger Agreement by failing to disclose material information that was required to be disclosed in the Form S-4. On
September 29, 2016, Williams filed a motion to dismiss the ETE Defendants’ amended counterclaims and to strike certain of the ETE Defendants’ affirmative defenses. Following briefing by the parties on Williams’ motion, the Delaware Court of Chancery held oral arguments on November 30, 2016. The parties are awaiting the Court’s decision. On January 11,March 23, 2017, the Delaware Supreme Court held oral argumentsaffirmed the Court of Chancery’s Opinion and Order on Williams’ appeal of the June 2016 trial. The partiestrial and denied Williams’ motion for reargument on April 5, 2017. As a result of the Delaware Supreme Court’s affirmance, Williams has conceded that its $10 billion damages claim is foreclosed, although its $410 million termination fee claim remains pending. Defendants cannot predict the outcome of the First Delaware Williams Litigation, the Second Delaware Williams Litigation, or any lawsuits that might be filed subsequent to the date of this filing; nor can Defendants predict the amount of time and expense that will be required to resolve these lawsuits. Defendants believe that Williams’ claims are awaiting the Court’s decision. The parties are currently engaging in discovery in connection with their amended claimswithout merit and counterclaims.intend to defend vigorously against them.
Unitholder Litigation Relating to the Issuance In April 2016, two purported ETE unitholders (the “Issuance Plaintiffs”) filed putative class action lawsuits against ETE, LE GP, Kelcy Warren, John McReynolds, Marshall McCrea, Matthew Ramsey, Ted Collins, K. Rick Turner, William Williams, Ray Davis, and Richard Brannon (collectively, the “Issuance Defendants”) in the Delaware Court of Chancery. These lawsuits have been consolidated as In re Energy Transfer Equity, L.P. Unitholder Litigation, Consolidated C.A. No. 12197-VCG, in the Court of Chancery of the State of Delaware.Delaware (the “Issuance Litigation”). Another purported ETE unitholder, Chester County Employees’ Retirement Fund, joined the consolidated action as an additional plaintiff of April 25, 2016. The Issuance Plaintiffs allege that the Issuance breached various provisions of ETE’s limited partnership agreement. The Issuance Plaintiffs seek, among other things, preliminary and permanent injunctive relief that (a) prevents ETE from making distributions to the Convertible Units and (b) invalidates an amendment to ETE’s partnership agreement that was adopted on March 8, 2016 as part of the issuance of Convertible Units.Issuance. The parties engaged in discovery, and Plaintiffs’On August 29, 2016, the Issuance Plaintiffs filed a consolidated amended complaint, on August 29, 2016. Inand in addition to the injunctive relief described above, Plaintiffs seek class-wide damages allegedly resulting from the Issuance.
On September 28, 2016,The Issuance Defendants and the Issuance Plaintiffs filed cross-motions for partial summary judgment. On February 28, 2017, the Court denied both motions for partial summary judgment. A trial in the Issuance Litigation is currently set for February 19-21, 2018.
The Court heldIssuance Defendants cannot predict the outcome of the Issuance Litigation or any lawsuits that might be filed subsequent to the date of this filing; nor can the Issuance Defendants predict the amount of time and expense that will be required to resolve the Issuance Litigation. The Issuance Defendants believe the Issuance Litigation is without merit and intend to defend vigorously against it and any other actions challenging the Issuance. Litigation filed by BP Products On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million. SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the parties’ motionsmatter was held in November 2016. On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint.
On July 26, 2017, each of the parties filed with the FERC a brief on November 9, 2016exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and has takenFERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter under advisement.is now awaiting a decision by FERC. Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 20162017 and 2015,2016, accruals of approximately $93$33 million and $40$77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As
new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. No amounts have been recorded in our December 31, 20162017 or 20152016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Compliance Orders from the New Mexico Environmental Department
Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. The Air Quality Bureau issued a Settlement Offer for Revised Notice of Violation REG-0569-1402-RI on February 7, 2017. The Settlement Agreement includes a civil penalty of $465,000. Energy Transfer and the New Mexico Environmental Department are scheduling a meeting to discuss the Settlement Offer in March 2017.
Lone Star NGL Fractionators Notice of Enforcement
Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $50,000 related to this claim as of December 31, 2016 and will continue to assess its potential exposure to the allegations as the matter progresses. As of December 31, 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 Supplemental Environmental Project.
Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million
for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality. On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in February of 2017, during the construction of the project. Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons.
Currently operating Sunoco, Inc. retail sites.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a “potentially responsible party” (“PRP”). As of December 31, 2016,2017, Sunoco, Inc. had been named as a PRP at approximatelapproximaty 50ely 43 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Current | $ | 37 |
| | $ | 42 |
| $ | 35 |
| | $ | 26 |
| Non-current | 348 |
| | 326 |
| 337 |
| | 318 |
| Total environmental liabilities | $ | 385 |
| | $ | 368 |
| $ | 372 |
| | $ | 344 |
|
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company. During the years ended December 31, 20162017 and 2015,2016, the Partnership recorded $43$32 million and $38$43 million, respectively, of expenditures related to environmental cleanup programs. On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (TRC) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closing time period. On January 2, 2013, USEPA issued a Finding of Violation (FOV) to TRC and, on September 30, 2013, EPA issued an NOV/FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 and EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to its results of operations, cash flows or financial position. Our pipeline operations are subject to regulation by the U.S.United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets
will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. In January 2012, Sunoco LogisticsETP experienced a release on its products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco LogisticsETP is obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco LogisticsThis PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. ETP also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco LogisticsETP has also received a "No“No Further Action"Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco LogisticsETP received a proposed penalty from the EPA and U.S. Department of JusticeDOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco LogisticsETP does not expect there to be a material impact to its results of operations, cash flows or financial position. In October 2016, the PHMSA issued a Notice of Probable Violation (“NOPVs”) and a Proposed Compliance Order (“PCO”) related to ETP’s West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalty is in excess of $100,000. The case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position. In 2012, the EPA issued a proposed consent agreement related to the releases that occurred at Sunoco Logistics’ pump station/tank farm in Barbers Hill, Texas and pump station/tank farm located in Cromwell, Oklahoma in 2010 and 2011, respectively. These matters were referred to the DOJ by the EPA. In November 2012, Sunoco Logistics received an initial assessment of $1.4 million associated with these releases. Sunoco Logistics is in discussions with the EPA and the DOJ on this matter to resolve the issue. The timing or outcome of this matter cannot be reasonably determined at this time. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position. In April 2015 and October 2016, the PHMSA issued separate Notices of Probable Violation ("NOPVs") and a Proposed Compliance Order ("PCO") related to Sunoco Logistics’ West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalties are in excess of $100,000. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of Sunoco Logistics’ETP’s Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. Sunoco LogisticsThe case went to hearing in November 2016 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position.
In JuneJuly 2016, the PHMSA issued NOPVsa NOPV and a PCO to our West Texas Gulf pipeline in connection with alleged violationsinspection and maintenance activities related to a 2013 incident on Sunoco Logistics’ Texasour crude oil pipeline system.near Wortham, Texas. The proposed penalties are in excess of $100,000. Sunoco LogisticsThe case went to hearing in March 2017 and remains open with PHMSA. ETP does not expect there to be a material impact to its results of operations, cash flows, or financial position.
In July 2016,August 2017, the PHMSA issued a NOPV and a PCO in connection with inspectionalleged violations on ETP’s Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and maintenance activities related to a 2013 incident on Sunoco Logistics' crude oil pipeline near Wortham, Texas. Thethe proposed penalties are in excess of $100,000, and Sunoco Logistics is currently in discussions with PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics$100,000. ETP does not expect there to be a material impact to its results of operations, cash flows or financial position. Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’sOccupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future. | | 12. | DERIVATIVE ASSETS AND LIABILITIES: |
Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price
result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage operations and operational gas sales on our interstate transportation and storage operations. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream operations whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We use derivatives in our liquids transportation and services operations to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. Sunoco Logistics utilizesutilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs.NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use futures and swaps to achieve ratable pricing of crude oil purchases, to convert certain expected refined product sales to fixed or floating prices, to lock in margins for certain refined products and to lock in the price of a portion of natural gas purchases or sales and transportation costs in our retail marketing operations. These contracts are not designated as hedges for accounting purposes. We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage operations’ and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other operations which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage operations, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following table details our outstanding commodity-related derivatives: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | | (Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Fixed Swaps/Futures | (682,500 | ) | | 2017 | | (602,500 | ) | | 2016 - 2017 | 1,078 |
| | 2018 | | (683 | ) | | 2017 | Basis Swaps IFERC/NYMEX (1) | 2,242,500 |
| | 2017 | | (31,240,000 | ) | | 2016 - 2017 | 48,510 |
| | 2018-2020 | | 2,243 |
| | 2017 | Options – Puts | | 13,000 |
| | 2018 | | — |
| | — | Power (Megawatt): | | | | | | | | | Forwards | 391,880 |
| | 2017 - 2018 | | 357,092 |
| | 2016 - 2017 | 435,960 |
| | 2018-2019 | | 391,880 |
| | 2017 - 2018 | Futures | 109,564 |
| | 2017 - 2018 | | (109,791 | ) | | 2016 | (25,760 | ) | | 2018 | | 109,564 |
| | 2017 - 2018 | Options — Puts | (50,400 | ) | | 2017 | | 260,534 |
| | 2016 | (153,600 | ) | | 2018 | | (50,400 | ) | | 2017 | Options — Calls | 186,400 |
| | 2017 | | 1,300,647 |
| | 2016 | 137,600 |
| | 2018 | | 186,400 |
| | 2017 | Crude (Bbls) – Futures | (617,000 | ) | | 2017 | | (591,000 | ) | | 2016 - 2017 | | Crude (MBbls) – Futures | | — |
| | — | | (617 | ) | | 2017 | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | 10,750,000 |
| | 2017 - 2018 | | (6,522,500 | ) | | 2016 - 2017 | 4,650 |
| | 2018-2020 | | 10,750 |
| | 2017 - 2018 | Swing Swaps IFERC | (5,662,500 | ) | | 2017 | | 71,340,000 |
| | 2016 - 2017 | 87,253 |
| | 2018-2019 | | (5,663 | ) | | 2017 | Fixed Swaps/Futures | (52,652,500 | ) | | 2017 - 2019 | | (14,380,000 | ) | | 2016 - 2018 | (4,390 | ) | | 2018-2019 | | (52,653 | ) | | 2017 - 2019 | Forward Physical Contracts | (22,492,489 | ) | | 2017 | | 21,922,484 |
| | 2016 - 2017 | (145,105 | ) | | 2018-2020 | | (22,492 | ) | | 2017 | Natural Gas Liquid (Bbls) – Forwards/Swaps | (5,786,627 | ) | | 2017 | | (8,146,800 | ) | | 2016 - 2018 | | Refined Products (Bbls) – Futures | (3,144,000 | ) | | 2017 | | (1,289,000 | ) | | 2016 - 2017 | | Natural Gas Liquid (MBbls) – Forwards/Swaps | | 6,744 |
| | 2018-2019 | | (5,787 | ) | | 2017 | Refined Products (MBbls) – Futures | | (3,901 | ) | | 2018-2019 | | (3,144 | ) | | 2017 | Corn (Bushels) – Futures | 1,580,000 |
| | 2017 | | 1,185,000 |
| | 2016 | 1,870,000 |
| | 2018 | | 1,580,000 |
| | 2017 | Fair Value Hedging Derivatives | | | | | | | | | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | (36,370,000 | ) | | 2017 | | (37,555,000 | ) | | 2016 | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Fixed Swaps/Futures | (36,370,000 | ) | | 2017 | | (37,555,000 | ) | | 2016 | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Hedged Item — Inventory | 36,370,000 |
| | 2017 | | 37,555,000 |
| | 2016 | 39,770 |
| | 2018 | | 36,370 |
| | 2017 |
| | (1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which are designated as hedges for accounting purposes: | | | | | | | | Notional Amount Outstanding | | | | | | Notional Amount Outstanding | Entity | | Term | | Type(1) | | December 31, 2016 | | December 31, 2015 | | Term | | Type(1) | | December 31, 2017 | | December 31, 2016 | ETP | | July 2016(2) | | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | | $ | — |
| | $ | 200 |
| | July 2017(2) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | $ | — |
| | $ | 500 |
| ETP | | July 2017(3) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | 500 |
| | 300 |
| | July 2018(2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | 300 |
| | 200 |
| ETP | | July 2018(3) | | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | | 200 |
| | 200 |
| | July 2019(2) | | Forward-starting to pay a fixed rate of 3.64% and receive a floating rate | | 300 |
| | 200 |
| ETP | | July 2019(3) | | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate | | 200 |
| | 200 |
| | July 2020(2) | | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | | 400 |
| | — |
| ETP | | December 2018 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | | 1,200 |
| | 1,200 |
| | December 2018 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | | 1,200 |
| | 1,200 |
| ETP | | March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | 300 |
| | March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | 300 |
|
| | (1) | Floating rates are based on 3-month LIBOR. |
| | (2) | Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date. |
| | (3)
| Represents the effective date. These forward-starting swaps have a term of 30 years with a mandatory termination date the same as the effective date. |
Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies, and independent power generators and fuel distributors.generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary The following table provides a summary of our derivative assets and liabilities: | | | Fair Value of Derivative Instruments | Fair Value of Derivative Instruments | | Asset Derivatives | | Liability Derivatives | Asset Derivatives | | Liability Derivatives | | December 31, 2016 | | December 31, 2015 | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | $ | — |
| | $ | 38 |
| | $ | (4 | ) | | $ | (3 | ) | $ | 14 |
| | $ | — |
| | $ | (2 | ) | | $ | (4 | ) | | — |
| | 38 |
| | (4 | ) | | (3 | ) | 14 |
| | — |
| | (2 | ) | | (4 | ) | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | 338 |
| | 353 |
| | (416 | ) | | (306 | ) | 262 |
| | 338 |
| | (281 | ) | | (416 | ) | Commodity derivatives | 25 |
| | 63 |
| | (58 | ) | | (47 | ) | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Interest rate derivatives | — |
| | — |
| | (193 | ) | | (171 | ) | — |
| | — |
| | (219 | ) | | (193 | ) | Embedded derivatives in ETP Preferred Units | — |
| | — |
| | (1 | ) | | (5 | ) | | Embedded derivatives in ETP Convertible Preferred Units | | — |
| | — |
| | — |
| | (1 | ) | | 363 |
| | 416 |
| | (668 | ) | | (529 | ) | 307 |
| | 363 |
| | (558 | ) | | (668 | ) | Total derivatives | $ | 363 |
| | $ | 454 |
| | $ | (672 | ) | | $ | (532 | ) | $ | 321 |
| | $ | 363 |
| | $ | (560 | ) | | $ | (672 | ) |
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: | | | | Asset Derivatives | | Liability Derivatives | | Asset Derivatives | | Liability Derivatives | | | Balance Sheet Location | | December 31, 2016 | | December 31, 2015 | | December 31, 2016 | | December 31, 2015 | | Balance Sheet Location | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives without offsetting agreements | | Derivative assets (liabilities) | | $ | — |
| | $ | — |
| | $ | (194 | ) | | $ | (176 | ) | | Derivative assets (liabilities) | | $ | — |
| | $ | — |
| | $ | (219 | ) | | $ | (194 | ) | Derivatives in offsetting agreements: | Derivatives in offsetting agreements: | | | | | | | | | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 25 |
| | 63 |
| | (58 | ) | | (47 | ) | | Derivative assets (liabilities) | | 45 |
| | 25 |
| | (58 | ) | | (58 | ) | Broker cleared derivative contracts | | Other current assets | | 338 |
| | 391 |
| | (420 | ) | | (309 | ) | | Other current assets (liabilities) | | 276 |
| | 338 |
| | (283 | ) | | (420 | ) | | | | 363 |
| | 454 |
| | (672 | ) | | (532 | ) | | | 321 |
| | 363 |
| | (560 | ) | | (672 | ) | Offsetting agreements: | Offsetting agreements: | | | | | | | | | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (4 | ) | | (17 | ) | | 4 |
| | 17 |
| | Derivative assets (liabilities) | | (21 | ) | | (4 | ) | | 21 |
| | 4 |
| Payments on margin deposit | | Other current assets | | (338 | ) | | (309 | ) | | 338 |
| | 309 |
| | Counterparty netting | | | Other current assets (liabilities) | | (263 | ) | | (338 | ) | | 263 |
| | 338 |
| Total net derivatives | Total net derivatives | | $ | 21 |
| | $ | 128 |
| | $ | (330 | ) | | $ | (206 | ) | Total net derivatives | | $ | 37 |
| | $ | 21 |
| | $ | (276 | ) | | $ | (330 | ) |
We disclose the non-exchange traded financial derivative instruments as derivative assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
The following tables summarize the amounts recognized with respect to our derivative financial instruments: | | | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Derivatives in cash flow hedging relationships: | | | | | | | | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | — |
| | $ | — |
| | $ | (3 | ) | Cost of products sold | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
| Total | | $ | — |
| | $ | — |
| | $ | (3 | ) | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 14 |
| | $ | 21 |
| | $ | (8 | ) | Total | | | $ | 14 |
| | $ | 21 |
| | $ | (8 | ) |
| | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income on Derivatives | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain/(Loss) Recognized in Income on Derivatives | | | Years Ended December 31, | | Years Ended December 31, | | | 2016 | | 2015 | | 2014 | | 2017 | | 2016 | | 2015 | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | (35 | ) | | $ | (11 | ) | | $ | (6 | ) | Cost of products sold | | $ | 31 |
| | $ | (35 | ) | | $ | (11 | ) | Commodity derivatives – Non-trading | Cost of products sold | | (177 | ) | | 15 |
| | 199 |
| Cost of products sold | | 5 |
| | (177 | ) | | 15 |
| Interest rate derivatives | Losses on interest rate derivatives | | (12 | ) | | (18 | ) | | (157 | ) | Losses on interest rate derivatives | | (37 | ) | | (12 | ) | | (18 | ) | Embedded derivatives | Other, net | | 4 |
| | 12 |
| | 3 |
| Other, net | | 1 |
| | 4 |
| | 12 |
| Total | | $ | (220 | ) | | $ | (2 | ) | | $ | 39 |
| | $ | — |
| | $ | (220 | ) | | $ | (2 | ) |
Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees, including those of ETP, Sunoco LP and Lake Charles LNG. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries have made matching contributions of $38 million, $44 million $40 million and $50$40 million to the 401(k) savings plan for the years ended December 31, 2017, 2016, and 2015, and 2014, respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2017, 2016, and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. Sunoco, Inc. Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015. Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations. Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services.
The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Change in benefit obligation: | | | | | | | | | | | | | | | | | | | | | | | Benefit obligation at beginning of period | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| | $ | 718 |
| | $ | 65 |
| | $ | 203 |
| $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| Interest cost | 1 |
| | 2 |
| | 4 |
| | 23 |
| | 2 |
| | 4 |
| 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (1 | ) | | (7 | ) | | (21 | ) | | (46 | ) | | (8 | ) | | (20 | ) | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | (2 | ) | | (1 | ) | | 2 |
| | 16 |
| | (2 | ) | | (6 | ) | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | — |
| | — |
| | — |
| | (691 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Benefit obligation at end of period | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | $ | 20 |
| | $ | 57 |
| | $ | 181 |
| $ | 1 |
| | $ | 47 |
| | $ | 156 |
| | $ | 18 |
| | $ | 51 |
| | $ | 166 |
| | | | | | | | | | | | | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of period | $ | 15 |
| | $ | — |
| | $ | 261 |
| | $ | 598 |
| | $ | — |
| | $ | 272 |
| $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| Return on plan assets and other | (2 | ) | | — |
| | 6 |
| | 16 |
| | — |
| | — |
| 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | — |
| | — |
| | 10 |
| | 138 |
| | — |
| | 9 |
| 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (1 | ) | | — |
| | (21 | ) | | (46 | ) | | — |
| | (20 | ) | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | — |
| | — |
| | — |
| | (691 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of plan assets at end of period | $ | 12 |
| | $ | — |
| | $ | 256 |
| | $ | 15 |
| | $ | — |
| | $ | 261 |
| $ | 1 |
| | $ | — |
| | $ | 257 |
| | $ | 12 |
| | $ | — |
| | $ | 256 |
| | | | | | | | | | | | | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | $ | 5 |
| | $ | 57 |
| | $ | (80 | ) | $ | — |
| | $ | 47 |
| | $ | (101 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (90 | ) | | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 114 |
| | $ | — |
| | $ | — |
| | $ | 103 |
| $ | — |
| | $ | — |
| | $ | 127 |
| | $ | — |
| | $ | — |
| | $ | 114 |
| Current liabilities | — |
| | (7 | ) | | (2 | ) | | — |
| | (9 | ) | | (2 | ) | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | (6 | ) | | (44 | ) | | (23 | ) | | (5 | ) | | (48 | ) | | (22 | ) | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | $ | (5 | ) | | $ | (57 | ) | | $ | 79 |
| $ | — |
| | $ | (47 | ) | | $ | 101 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 89 |
| | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive loss (pre-tax basis) consist of: | | | | | | | | | | | | | | | | | | | | | | | Net actuarial gain | $ | — |
| | $ | — |
| | $ | (13 | ) | | $ | 2 |
| | $ | 4 |
| | $ | (18 | ) | $ | — |
| | $ | 5 |
| | $ | (18 | ) | | $ | — |
| | $ | — |
| | $ | (13 | ) | Prior service cost | — |
| | — |
| | 15 |
| | — |
| | — |
| | 16 |
| — |
| | — |
| | 21 |
| | — |
| | — |
| | 15 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
| | $ | 4 |
| | $ | (2 | ) | $ | — |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 18 |
| | $ | 51 |
| | N/A |
| | $ | 20 |
| | $ | 57 |
| | N/A |
| $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 18 |
| | 51 |
| | $ | 166 |
| | 20 |
| | 57 |
| | $ | 181 |
| 1 |
| | 47 |
| | $ | 156 |
| | 18 |
| | 51 |
| | $ | 166 |
| Fair value of plan assets | 12 |
| | — |
| | 256 |
| | 15 |
| | — |
| | 261 |
| 1 |
| | — |
| | 257 |
| | 12 |
| | — |
| | 256 |
|
Components of Net Periodic Benefit Cost | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net Periodic Benefit Cost: | | | | | | | | | | | | | | | Interest cost | $ | 3 |
| | $ | 4 |
| | $ | 25 |
| | $ | 4 |
| $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | (1 | ) | | (8 | ) | | (16 | ) | | (8 | ) | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 1 |
| | — |
| | 1 |
| — |
| | 2 |
| | — |
| | 1 |
| Actuarial loss amortization | — |
| | — |
| | — |
| | — |
| | Settlements | — |
| | — |
| | 32 |
| | — |
| | Net periodic benefit cost | $ | 2 |
| | $ | (3 | ) | | $ | 41 |
| | $ | (3 | ) | $ | 2 |
| | $ | (3 | ) | | $ | 2 |
| | $ | (3 | ) |
Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.65 | % | | 2.34 | % | | 3.59 | % | | 2.38 | % | 3.27 | % | | 2.34 | % | | 3.65 | % | | 2.34 | % | Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
| N/A |
| | N/A |
| | N/A |
| | N/A |
|
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.60 | % | | 3.06 | % | | 3.65 | % | | 2.79 | % | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | | | | | | | | Tax exempt accounts | 3.50 | % | | 7.00 | % | | 7.50 | % | | 7.00 | % | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
| N/A |
| | N/A |
| | N/A |
| | N/A |
|
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest
rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle’s and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Health care cost trend rate | 6.73 | % | | 7.16 | % | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | 4.96 | % | | 5.39 | % | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | 2021 |
| | 2018 |
| 2023 |
| | 2021 |
|
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%. The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: | | | | | | Fair Value Measurements at December 31, 2016 | | | | Fair Value Measurements at December 31, 2017 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Mutual funds (1) | | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| Total | | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of 100% equities as of December 31, 2016.2017. |
| | | | | | Fair Value Measurements at December 31, 2015 | | | | Fair Value Measurements at December 31, 2016 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Mutual funds (1) | | $ | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| Total | | $ | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
| | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of 100% equities as of December 31, 2015.2016. |
The fair value of the other postretirement plan assets by asset category at the dates indicated is as follows:
| | | | | | Fair Value Measurements at December 31, 2016 | | | | Fair Value Measurements at December 31, 2017 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Cash and Cash Equivalents | | $ | 23 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 142 |
| | 142 |
| | — |
| | — |
| | 154 |
| | 154 |
| | — |
| | — |
| Fixed income securities | | 91 |
| | — |
| | 91 |
| | — |
| | 70 |
| | — |
| | 70 |
| | — |
| Total | | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
| | $ | 257 |
| | $ | 187 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 31%38% equities, 66%61% fixed income securities and 3%2% cash as of December 31, 2016.2017. |
| | | | | | Fair Value Measurements at December 31, 2015 | | | | Fair Value Measurements at December 31, 2016 | | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset Category: | | | | | | | | | | | | | | | | | Cash and Cash Equivalents | | $ | 18 |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 23 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| Mutual funds (1) | | 141 |
| | 141 |
| | — |
| | — |
| | 142 |
| | 142 |
| | — |
| | — |
| Fixed income securities | | 102 |
| | — |
| | 102 |
| | — |
| | 91 |
| | — |
| | 91 |
| | — |
| Total | | $ | 261 |
| | $ | 159 |
| | $ | 102 |
| | $ | — |
| | $ | 256 |
| | $ | 165 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 56%31% equities, 33%66% fixed income securities and 11%3% cash as of December 31, 2015.2016. |
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. Contributions We expect to contribute $12$8 million to pension plans and $10 million to other postretirement plans in 2017.2018. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments Panhandle’s and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: | | | | Pension Benefits | | | | | | | | Years | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits (Gross, Before Medicare Part D) | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2017 | | $ | 1 |
| | $ | 7 |
| | $ | 26 |
| | 2018 | | 1 |
| | 7 |
| | 25 |
| | $ | 8 |
| | $ | 24 |
| 2019 | | 1 |
| | 6 |
| | 23 |
| | 6 |
| | 23 |
| 2020 | | 1 |
| | 6 |
| | 22 |
| | 6 |
| | 21 |
| 2021 | | 1 |
| | 5 |
| | 19 |
| | 5 |
| | 19 |
| 2022 – 2026 | | 6 |
| | 17 |
| | 39 |
| | 2022 | | | 4 |
| | 17 |
| 2023 – 2027 | | | 15 |
| | 37 |
|
(1) Expected benefit payments of funded pension plans are less than $1 million for the next ten years. The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.
| | 14. | RELATED PARTY TRANSACTIONS: |
The Parent Company has agreements with subsidiaries to provide or receive various generalIn June 2017, ETP acquired all of the publicly held PennTex common units through a tender offer and administrative services. The Parent Company paysexercise of a limited call right, as further discussed in Note 8.
ETE previously paid ETP to provide services on its behalf and theon behalf of other subsidiaries of the Parent Company. The Parent Company receives management fees from certain of its subsidiaries,ETE, which includeincluded the reimbursement of various operating and general and administrative services for expenses incurred by ETP on behalf of thoseETE and its subsidiaries. All such amounts have been eliminatedThese agreements expired in our consolidated financial statements. In the ordinary course of business, our subsidiaries have related party transactions between each other which are generally based on transactions made at market-related rates. Our consolidated revenues and expenses reflect the elimination of all material intercompany transactions (see Note 15).2016.
In addition, subsidiaries of ETE recorded sales with affiliates of $303 million, $221 million $290 million and $965$290 million during the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively. Subsequent to ETE’s acquisition of a controlling interest in Sunoco LP, our financial statements reflect the following reportable business segments: Investment in ETP, including the consolidated operations of ETP; Investment in Sunoco LP, including the consolidated operations of Sunoco LP; Investment in Lake Charles LNG, including the operations of Lake Charles LNG; and Corporate and Other, including the following: activities of the Parent Company; and the goodwill and property, plant and equipment fair value adjustments recorded as a result of the 2004 reverse acquisition of Heritage Propane Partners, L.P. ETP completed its acquisition of Regency in April 2015; therefore, the Investment in ETP segment amounts have been retrospectively adjusted to reflect Regency for the periods presented. The Investment in Sunoco LP segment reflects the results of Sunoco LP beginning August 29, 2014, the date that ETP originally obtained control of Sunoco LP. ETE’s consolidated results reflect the elimination of MACS, Sunoco, LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP. In addition, subsequent to July 2015, ETP holds an equity method investment in Sunoco, LLC, and a continuing investment in Sunoco LP, the equity in earnings from which is also eliminated in ETE’s consolidated financial statements. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership. Based on the change in our reportable segments we have recast the presentation of our segment results for the prior years to be consistent with the current year presentation.
Eliminations in the tables below include the following: ETP’s Segment Adjusted EBITDA reflected the results of Lake Charles LNG prior to the Lake Charles LNG Transaction, which was effective January 1, 2014. The Investment in Lake Charles LNG segment reflected the results of operations of Lake Charles LNG for all periods presented. Consequently, the results of operations of Lake Charles LNG were reflected in two segments for the year ended December 31, 2013. Therefore, the results of Lake Charles LNG were included in eliminations for 2013.
MACS, Sunoco LLC, Susser and Sunoco Retail LLC for the periods during which those entities were included in the consolidated results of both ETP and Sunoco LP, as discussed above. | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Revenues: | | | | | | Investment in ETP: | | | | | | Revenues from external customers | $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
| Intersegment revenues | 441 |
| | 209 |
| | 136 |
| | 29,054 |
| | 21,827 |
| | 34,292 |
| Investment in Sunoco LP: | | | | | | Revenues from external customers | 11,713 |
| | 9,977 |
| | 12,419 |
| Intersegment revenues | 10 |
| | 9 |
| | 11 |
| | 11,723 |
| | 9,986 |
| | 12,430 |
| Investment in Lake Charles LNG: | | | | | | Revenues from external customers | 197 |
| | 197 |
| | 216 |
| |
|
| |
|
| |
|
| Adjustments and Eliminations: | (451 | ) | | (218 | ) | | (10,842 | ) | Total revenues | $ | 40,523 |
| | $ | 31,792 |
| | $ | 36,096 |
| | | | | | | Costs of products sold: | | | | | | Investment in ETP | $ | 20,801 |
| | $ | 15,080 |
| | $ | 26,714 |
| Investment in Sunoco LP | 10,615 |
| | 8,830 |
| | 11,450 |
| Adjustments and Eliminations | (450 | ) | | (217 | ) | | (9,496 | ) | Total costs of products sold | $ | 30,966 |
| | $ | 23,693 |
| | $ | 28,668 |
| | | | | | | Depreciation, depletion and amortization: | | | | | | Investment in ETP | $ | 2,332 |
| | $ | 1,986 |
| | $ | 1,929 |
| Investment in Sunoco LP | 169 |
| | 176 |
| | 150 |
| Investment in Lake Charles LNG | 39 |
| | 39 |
| | 39 |
| Corporate and Other | 14 |
| | 15 |
| | 17 |
| Adjustments and Eliminations | — |
| | — |
| | (184 | ) | Total depreciation, depletion and amortization | $ | 2,554 |
| | $ | 2,216 |
| | $ | 1,951 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Revenues: | | | | | | Investment in ETP: | | | | | | Revenues from external customers | $ | 21,618 |
| | $ | 34,156 |
| | $ | 55,475 |
| Intersegment revenues | 209 |
| | 136 |
| | — |
| | 21,827 |
| | 34,292 |
| | 55,475 |
| Investment in Sunoco LP: | | | | | | Revenues from external customers | 15,689 |
| | 18,449 |
| | 7,343 |
| Intersegment revenues | 9 |
| | 11 |
| | — |
| | 15,698 |
| | 18,460 |
| | 7,343 |
| Investment in Lake Charles LNG: | | | | | | Revenues from external customers | 197 |
| | 216 |
| | 216 |
| |
|
| |
|
| |
|
| Adjustments and Eliminations: | (218 | ) | | (10,842 | ) | | (7,343 | ) | Total revenues | $ | 37,504 |
| | $ | 42,126 |
| | $ | 55,691 |
| | | | | | | Costs of products sold: | | | | | | Investment in ETP | $ | 15,394 |
| | $ | 27,029 |
| | $ | 48,414 |
| Investment in Sunoco LP | 13,479 |
| | 16,476 |
| | 6,767 |
| Adjustments and Eliminations | (217 | ) | | (9,496 | ) | | (6,767 | ) | Total costs of products sold | $ | 28,656 |
| | $ | 34,009 |
| | $ | 48,414 |
| | | | | | | Depreciation, depletion and amortization: | | | | | | Investment in ETP | $ | 1,986 |
| | $ | 1,929 |
| | $ | 1,669 |
| Investment in Sunoco LP | 319 |
| | 278 |
| | 86 |
| Investment in Lake Charles LNG | 39 |
| | 39 |
| | 39 |
| Corporate and Other | 15 |
| | 17 |
| | 16 |
| Adjustments and Eliminations | — |
| | (184 | ) | | (86 | ) | Total depreciation, depletion and amortization | $ | 2,359 |
| | $ | 2,079 |
| | $ | 1,724 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Equity in earnings of unconsolidated affiliates: | | | | | | | | | | | Investment in ETP | $ | 336 |
| | $ | 469 |
| | $ | 332 |
| $ | 156 |
| | $ | 59 |
| | $ | 469 |
| Adjustments and Eliminations | (66 | ) | | (193 | ) | | — |
| (12 | ) | | 211 |
| | (193 | ) | Total equity in earnings of unconsolidated affiliates | $ | 270 |
| | $ | 276 |
| | $ | 332 |
| $ | 144 |
| | $ | 270 |
| | $ | 276 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | | | | | | Investment in ETP | $ | 5,605 |
| | $ | 5,714 |
| | $ | 5,710 |
| $ | 6,712 |
| | $ | 5,733 |
| | $ | 5,517 |
| Investment in Sunoco LP | 665 |
| | 719 |
| | 332 |
| 732 |
| | 665 |
| | 719 |
| Investment in Lake Charles LNG | 179 |
| | 196 |
| | 195 |
| 175 |
| | 179 |
| | 196 |
| Corporate and Other | (170 | ) | | (104 | ) | | (97 | ) | (31 | ) | | (170 | ) | | (104 | ) | Adjustments and Eliminations | (272 | ) | | (590 | ) | | (300 | ) | (268 | ) | | (272 | ) | | (590 | ) | Total Segment Adjusted EBITDA | 6,007 |
| | 5,935 |
| | 5,840 |
| 7,320 |
| | 6,135 |
| | 5,738 |
| Depreciation, depletion and amortization | (2,359 | ) | | (2,079 | ) | | (1,724 | ) | (2,554 | ) | | (2,216 | ) | | (1,951 | ) | Interest expense, net of interest capitalized | (1,832 | ) | | (1,643 | ) | | (1,369 | ) | (1,922 | ) | | (1,804 | ) | | (1,622 | ) | Gains on acquisitions | 83 |
| | — |
| | — |
| — |
| | 83 |
| | — |
| Gain on sale of AmeriGas common units | — |
| | — |
| | 177 |
| | Impairment of investment in affiliate | (308 | ) | | — |
| | — |
| | Impairment of investments in unconsolidated affiliates | | (313 | ) | | (308 | ) | | — |
| Impairment losses | (1,487 | ) | | (339 | ) | | (370 | ) | (1,039 | ) | | (1,040 | ) | | (339 | ) | Losses on interest rate derivatives | (12 | ) | | (18 | ) | | (157 | ) | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (70 | ) | | (91 | ) | | (82 | ) | (99 | ) | | (70 | ) | | (91 | ) | Unrealized gains (losses) on commodity risk management activities | (136 | ) | | (65 | ) | | 116 |
| 59 |
| | (136 | ) | | (65 | ) | Losses on extinguishments of debt | — |
| | (43 | ) | | (25 | ) | (89 | ) | | — |
| | (43 | ) | Inventory valuation adjustments | 273 |
| | (249 | ) | | (473 | ) | 24 |
| | 97 |
| | (67 | ) | Adjusted EBITDA related to discontinued operations | — |
| | — |
| | (27 | ) | (223 | ) | | (199 | ) | | (228 | ) | Adjusted EBITDA related to unconsolidated affiliates | (675 | ) | | (713 | ) | | (748 | ) | (716 | ) | | (675 | ) | | (713 | ) | Equity in earnings of unconsolidated affiliates | 270 |
| | 276 |
| | 332 |
| 144 |
| | 270 |
| | 276 |
| Other, net | 70 |
| | 22 |
| | (73 | ) | 155 |
| | 79 |
| | 23 |
| Income from continuing operations before income tax expense | $ | (176 | ) | | $ | 993 |
| | $ | 1,417 |
| | Income from continuing operations before income tax benefit | | $ | 710 |
| | $ | 204 |
| | $ | 900 |
| Income tax benefit from continuing operations | | (1,833 | ) | | (258 | ) | | (123 | ) | Income from continuing operations | | 2,543 |
| | 462 |
| | 1,023 |
| Income (loss) from discontinued operations, net of tax | | (177 | ) | | (462 | ) | | 38 |
| Net income | | $ | 2,366 |
| | $ | — |
| | $ | 1,061 |
|
| | | | | | | | | | | | | | December 31, | | 2016 | | 2015 | | 2014 | Total assets: | | | | | | Investment in ETP | $ | 70,191 |
| | $ | 65,173 |
| | $ | 62,518 |
| Investment in Sunoco LP | 8,701 |
| | 8,842 |
| | 8,773 |
| Investment in Lake Charles LNG | 1,508 |
| | 1,369 |
| | 1,210 |
| Corporate and Other | 711 |
| | 638 |
| | 1,119 |
| Adjustments and Eliminations | (2,100 | ) | | (4,833 | ) | | (9,341 | ) | Total | $ | 79,011 |
| | $ | 71,189 |
| | $ | 64,279 |
|
| | | Years Ended December 31, | December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Additions to property, plant and equipment, net of contributions in aid of construction costs (accrual basis): | | | | | | | Total assets: | | | | | | | Investment in ETP | $ | 5,810 |
| | $ | 8,167 |
| | $ | 5,494 |
| $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
| Investment in Sunoco LP | 439 |
| | 491 |
| | 154 |
| 8,344 |
| | 8,701 |
| | 8,842 |
| Investment in Lake Charles LNG | — |
| | 1 |
| | 1 |
| 1,646 |
| | 1,508 |
| | 1,369 |
| Corporate and Other | | 598 |
| | 711 |
| | 638 |
| Adjustments and Eliminations | — |
| | (123 | ) | | (90 | ) | (2,307 | ) | | (2,100 | ) | | (4,833 | ) | Total | $ | 6,249 |
| | $ | 8,536 |
| | $ | 5,559 |
| $ | 86,246 |
| | $ | 78,925 |
| | $ | 71,144 |
|
| | | December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Advances to and investments in affiliates: | | | | | | | Additions to property, plant and equipment, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis): | | | | | | | Investment in ETP | $ | 4,280 |
| | $ | 5,003 |
| | $ | 3,760 |
| $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
| Investment in Sunoco LP | | 103 |
| | 119 |
| | 178 |
| Investment in Lake Charles LNG | | 2 |
| | — |
| | 1 |
| Adjustments and Eliminations | (1,240 | ) | | (1,541 | ) | | (101 | ) | — |
| | — |
| | (123 | ) | Total | $ | 3,040 |
| | $ | 3,462 |
| | $ | 3,659 |
| $ | 6,006 |
| | $ | 5,929 |
| | $ | 8,223 |
|
| | | | | | | | | | | | | | December 31, | | 2017 | | 2016 | | 2015 | Advances to and investments in affiliates: | | | | | | Investment in ETP | $ | 3,816 |
| | $ | 4,280 |
| | $ | 5,003 |
| Adjustments and Eliminations | (1,111 | ) | | (1,240 | ) | | (1,541 | ) | Total | $ | 2,705 |
| | $ | 3,040 |
| | $ | 3,462 |
|
The following tables provide revenues, grouped by similar products and services, for our reportable segments. These amounts include intersegment revenues for transactions between ETP and Sunoco LP. Investment in ETP | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Intrastate Transportation and Storage | $ | 2,155 |
| | $ | 1,912 |
| | $ | 2,645 |
| $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Interstate Transportation and Storage | 946 |
| | 1,008 |
| | 1,057 |
| 915 |
| | 946 |
| | 1,008 |
| Midstream | 2,342 |
| | 2,607 |
| | 4,770 |
| 2,510 |
| | 2,342 |
| | 2,607 |
| Liquids Transportation and Services | 4,498 |
| | 3,247 |
| | 3,730 |
| | Investment in Sunoco Logistics | 9,015 |
| | 10,302 |
| | 17,920 |
| | NGL and refined products transportation and services | | 8,326 |
| | 5,973 |
| | 4,569 |
| Crude oil transportation and services | | 11,672 |
| | 7,539 |
| | 8,980 |
| All Other | 2,871 |
| | 15,216 |
| | 25,353 |
| 2,740 |
| | 2,872 |
| | 15,216 |
| Total revenues | 21,827 |
| | 34,292 |
| | 55,475 |
| 29,054 |
| | 21,827 |
| | 34,292 |
| Less: Intersegment revenues | 209 |
| | 136 |
| | — |
| 441 |
| | 209 |
| | 136 |
| Revenues from external customers | $ | 21,618 |
| | $ | 34,156 |
| | $ | 55,475 |
| $ | 28,613 |
| | $ | 21,618 |
| | $ | 34,156 |
|
Investment in Sunoco LP | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Retail operations | $ | 7,703 |
| | $ | 8,256 |
| | $ | 3,095 |
| $ | 2,263 |
| | $ | 1,991 |
| | $ | 2,226 |
| Wholesale operations | 7,995 |
| | 10,204 |
| | 4,248 |
| 9,460 |
| | 7,995 |
| | 10,204 |
| Total revenues | 15,698 |
| | 18,460 |
| | 7,343 |
| 11,723 |
| | 9,986 |
| | 12,430 |
| Less: Intersegment revenues | 9 |
| | 11 |
| | — |
| 10 |
| | 9 |
| | 11 |
| Revenues from external customers | $ | 15,689 |
| | $ | 18,449 |
| | $ | 7,343 |
| $ | 11,713 |
| | $ | 9,977 |
| | $ | 12,419 |
|
Investment in Lake Charles LNG Lake Charles LNG’s revenues of $197 million, $216$197 million and $216 million for the years ended December 31, 2017, 2016 2015 and 2014,2015, respectively, were related to LNG terminalling.
| | 16. | QUARTERLY FINANCIAL DATA (UNAUDITED): |
Summarized unaudited quarterly financial data is presented below. Earnings per unit are computed on a stand-alone basis for each quarter and total year. | | | Quarters Ended | | | Quarters Ended | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | March 31* | | June 30* | | September 30* | | December 31 | | Total Year | 2016: | | | | | | | | | | | 2017: | | | | | | | | | | | Revenues | $ | 7,682 |
| | $ | 9,344 |
| | $ | 9,675 |
| | $ | 10,803 |
| | $ | 37,504 |
| $ | 9,660 |
| | $ | 9,427 |
| | $ | 9,984 |
| | $ | 11,452 |
| | $ | 40,523 |
| Operating income (loss) | 701 |
| | 827 |
| | 697 |
| | (726 | ) | | 1,499 |
| 758 |
| | 746 |
| | 924 |
| | 285 |
| | 2,713 |
| Net income (loss) | 336 |
| | 424 |
| | 41 |
| | (760 | ) | | 41 |
| 319 |
| | 121 |
| | 758 |
| | 1,168 |
| | 2,366 |
| Limited Partners’ interest in net income | 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| 232 |
| | 204 |
| | 240 |
| | 239 |
| | 915 |
| Basic net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| $ | 0.22 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.85 |
| Diluted net income per limited partner unit | $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.19 |
| | $ | 0.21 |
| | $ | 0.92 |
| $ | 0.21 |
| | $ | 0.18 |
| | $ | 0.22 |
| | $ | 0.22 |
| | $ | 0.83 |
|
| | | Quarters Ended | | | Quarters Ended | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2015: | | | | | | | | | | | 2016: | | | | | | | | | | | Revenues | $ | 10,380 |
| | $ | 11,594 |
| | $ | 10,616 |
| | $ | 9,536 |
| | $ | 42,126 |
| $ | 6,447 |
| | $ | 7,866 |
| | $ | 8,156 |
| | $ | 9,323 |
| | $ | 31,792 |
| Operating income | 617 |
| | 896 |
| | 650 |
| | 236 |
| | 2,399 |
| 680 |
| | 814 |
| | 624 |
| | (275 | ) | | 1,843 |
| Net income (loss) | 221 |
| | 772 |
| | 238 |
| | (138 | ) | | 1,093 |
| 320 |
| | 417 |
| | (3 | ) | | (734 | ) | | — |
| Limited Partners’ interest in net income | 282 |
| | 298 |
| | 291 |
| | 312 |
| | 1,183 |
| 311 |
| | 239 |
| | 207 |
| | 226 |
| | 983 |
| Basic net income per limited partner unit | $ | 0.26 |
| | $ | 0.28 |
| | $ | 0.28 |
| | $ | 0.30 |
| | $ | 1.11 |
| $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.20 |
| | $ | 0.22 |
| | $ | 0.94 |
| Diluted net income per limited partner unit | $ | 0.26 |
| | $ | 0.28 |
| | $ | 0.28 |
| | $ | 0.30 |
| | $ | 1.11 |
| $ | 0.30 |
| | $ | 0.23 |
| | $ | 0.19 |
| | $ | 0.21 |
| | $ | 0.92 |
|
* As adjusted. See Note 2 and Note 3. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality. The three months ended December 31, 20162017 and 2015 reflected the unfavorable impacts of $130 million and $120 million, respectively, related to non-cash inventory valuation adjustments primarily in ETP’s investment in Sunoco Logistics and retail marketing operations and our investment in Sunoco LP. The three months ended December 31, 2016 and 2015 reflected the recognition of impairment losses of $1.49$1.04 billion and $339 million,$1.04 billion, respectively. Impairment losses in 2017 were primarily related to ETP’s interstate transportation and storage operations, NGL and refined products operations and other operations as well as Sunoco LP’s retail operations. Impairment losses in 2016 were primarily related to ourETP’s interstate operations, midstream midcontinenttransportation and storage operations and midstream operations as well as Sunoco LP’s retail operations. In 2015, impairment losses were primarily related to Lone Star Refinery Services operations and our Transwestern pipeline. The three months ended September 30,December 31, 2017 and December 31, 2016 reflected the recognition of a non-cash impairment of our investmentETP’s investments in MEPsubsidiaries of $313 million and $308 million, respectively, in ourits interstate transportation and storage operations.
| | 17. | SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION: |
Following are the financial statements of the Parent Company, which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis: BALANCE SHEETS | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | $ | 2 |
| | $ | 1 |
| $ | 1 |
| | $ | 2 |
| Accounts receivable from related companies | 55 |
| | 34 |
| 65 |
| | 55 |
| Other current assets | | 1 |
| | — |
| Total current assets | 57 |
| | 35 |
| 67 |
| | 57 |
| PROPERTY, PLANT AND EQUIPMENT, net | 36 |
| | 20 |
| 27 |
| | 36 |
| ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES | 5,088 |
| | 5,764 |
| 6,082 |
| | 5,088 |
| INTANGIBLE ASSETS, net | 1 |
| | 6 |
| — |
| | 1 |
| GOODWILL | 9 |
| | 9 |
| 9 |
| | 9 |
| OTHER NON-CURRENT ASSETS, net | 10 |
| | 10 |
| 8 |
| | 10 |
| Total assets | $ | 5,201 |
| | $ | 5,844 |
| $ | 6,193 |
| | $ | 5,201 |
| LIABILITIES AND PARTNERS’ CAPITAL | | | | | | | CURRENT LIABILITIES: | | | | | | | Accounts payable | $ | 1 |
| | $ | — |
| $ | — |
| | $ | 1 |
| Accounts payable to related companies | 22 |
| | 111 |
| — |
| | 22 |
| Interest payable | 66 |
| | 66 |
| 66 |
| | 66 |
| Accrued and other current liabilities | 3 |
| | 1 |
| 4 |
| | 3 |
| Total current liabilities | 92 |
| | 178 |
| 70 |
| | 92 |
| LONG-TERM DEBT, less current maturities | 6,358 |
| | 6,332 |
| 6,700 |
| | 6,358 |
| NOTE PAYABLE TO AFFILIATE | 443 |
| | 265 |
| 617 |
| | 443 |
| OTHER NON-CURRENT LIABILITIES | 2 |
| | 1 |
| 2 |
| | 2 |
| | | | | | | | COMMITMENTS AND CONTINGENCIES |
| |
|
| |
| | | | | | | | PARTNERS’ DEFICIT: | | | | | | | General Partner | (3 | ) | | (2 | ) | (3 | ) | | (3 | ) | Limited Partners: | | | | | | | Common Unitholders (1,046,947,157 and 1,044,767,336 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) | (1,871 | ) | | (952 | ) | | Class D Units (2,156,000 units authorized, issued and outstanding as of December 31, 2015) | — |
| | 22 |
| | Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2016) | 180 |
| | — |
| | Common Unitholders (1,079,145,561 and 1,046,947,157 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively) | | (1,643 | ) | | (1,871 | ) | Series A Convertible Preferred Units (329,295,770 units authorized, issued and outstanding as of December 31, 2017 and 2016) | | 450 |
| | 180 |
| Total partners’ deficit | (1,694 | ) | | (932 | ) | (1,196 | ) | | (1,694 | ) | Total liabilities and partners’ deficit | $ | 5,201 |
| | $ | 5,844 |
| $ | 6,193 |
| | $ | 5,201 |
|
STATEMENTS OF OPERATIONS | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | SELLING, GENERAL AND ADMINISTRATIVE EXPENSES | $ | (185 | ) | | $ | (112 | ) | | $ | (111 | ) | $ | (31 | ) | | $ | (185 | ) | | $ | (112 | ) | OTHER INCOME (EXPENSE): | | | | | | | | | | | Interest expense, net of interest capitalized | (327 | ) | | (294 | ) | | (205 | ) | (347 | ) | | (327 | ) | | (294 | ) | Equity in earnings of unconsolidated affiliates | 1,511 |
| | 1,601 |
| | 955 |
| 1,381 |
| | 1,511 |
| | 1,601 |
| Loss on extinguishment of debt | | (47 | ) | | — |
| | — |
| Other, net | (4 | ) | | (5 | ) | | (5 | ) | (2 | ) | | (4 | ) | | (5 | ) | INCOME BEFORE INCOME TAXES | 995 |
| | 1,190 |
| | 634 |
| 954 |
| | 995 |
| | 1,190 |
| Income tax expense | — |
| | 1 |
| | 1 |
| — |
| | — |
| | 1 |
| NET INCOME | 995 |
| | 1,189 |
| | 633 |
| 954 |
| | 995 |
| | 1,189 |
| General Partner’s interest in net income | 3 |
| | 3 |
| | 2 |
| 2 |
| | 3 |
| | 3 |
| Convertible Unitholders’ interest in income | 9 |
| | — |
| | — |
| 37 |
| | 9 |
| | — |
| Class D Unitholder’s interest in net income | — |
| | 3 |
| | 2 |
| — |
| | — |
| | 3 |
| Limited Partners’ interest in net income | $ | 983 |
| | $ | 1,183 |
| | $ | 629 |
| $ | 915 |
| | $ | 983 |
| | $ | 1,183 |
|
STATEMENTS OF CASH FLOWS | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES | $ | 918 |
| | $ | 1,103 |
| | $ | 816 |
| $ | 831 |
| | $ | 918 |
| | $ | 1,103 |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | Cash paid for Bakken Pipeline Transaction | — |
| | (817 | ) | | — |
| — |
| | — |
| | (817 | ) | Contributions to unconsolidated affiliates | (70 | ) | | — |
| | (118 | ) | (861 | ) | | (70 | ) | | — |
| Capital expenditures | (16 | ) | | (19 | ) | | — |
| (1 | ) | | (16 | ) | | (19 | ) | Purchase of additional interest in Regency | — |
| | — |
| | (800 | ) | | Contributions in aid of construction costs | | 7 |
| | — |
| | — |
| Net cash used in investing activities | (86 | ) | | (836 | ) | | (918 | ) | (855 | ) | | (86 | ) | | (836 | ) | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | Proceeds from borrowings | 225 |
| | 3,672 |
| | 3,020 |
| 2,219 |
| | 225 |
| | 3,672 |
| Principal payments on debt | (210 | ) | | (1,985 | ) | | (1,142 | ) | (1,881 | ) | | (210 | ) | | (1,985 | ) | Distributions to partners | (1,022 | ) | | (1,090 | ) | | (821 | ) | (1,010 | ) | | (1,022 | ) | | (1,090 | ) | Proceeds from affiliate | 176 |
| | 210 |
| | 54 |
| 174 |
| | 176 |
| | 210 |
| Common Units issued for cash | | 568 |
| | — |
| | — |
| Units repurchased under buyback program | — |
| | (1,064 | ) | | (1,000 | ) | — |
| | — |
| | (1,064 | ) | Debt issuance costs | — |
| | (11 | ) | | (15 | ) | (47 | ) | | — |
| | (11 | ) | Net cash provided by (used in) financing activities | (831 | ) | | (268 | ) | | 96 |
| 23 |
| | (831 | ) | | (268 | ) | INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 1 |
| | (1 | ) | | (6 | ) | (1 | ) | | 1 |
| | (1 | ) | CASH AND CASH EQUIVALENTS, beginning of period | 1 |
| | 2 |
| | 8 |
| 2 |
| | 1 |
| | 2 |
| CASH AND CASH EQUIVALENTS, end of period | $ | 2 |
| | $ | 1 |
| | $ | 2 |
| $ | 1 |
| | $ | 2 |
| | $ | 1 |
|
ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES
INDEX TO FINANCIAL STATEMENTS OF CERTAIN SUBSIDIARIES INCLUDED PURSUANT TO RULE 3-16 OF REGULATION S-X | | | | Page | 1. Energy Transfer Partners, L.P. Financial Statements | S - 2 | | | | |
| | 1. | ENERGY TRANSFER PARTNERS, L.P. FINANCIAL STATEMENTS |
INDEX TO FINANCIAL STATEMENTS | | | | Page | Report of Independent Registered Public Accounting Firm | S - 3 | Consolidated Balance Sheets – December 31, 20162017 and 20152016 | S - 4 | Consolidated Statements of Operations – Years Ended December 31, 2017, 2016 2015 and 20142015 | S - 6 | Consolidated Statements of Comprehensive Income – Years Ended December 31, 2017, 2016 2015 and 20142015 | S - 7 | Consolidated Statements of Equity – Years Ended December 31, 2017, 2016 2015 and 20142015 | S - 8 | Consolidated Statements of Cash Flows – Years Ended December 31, 2017, 2016 2015 and 20142015 | S - 10 | Notes to Consolidated Financial Statements | S - 12 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM Partners
Board of Directors of Energy Transfer Partners, L.L.C. and Unitholders of Energy Transfer Partners, L.P. Opinion on the financial statements We have audited the accompanying consolidated balance sheets of Energy Transfer Partners, L.P. (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of December 31, 20162017 and 2015, and2016, the related consolidated statements of operations, comprehensive income, equity, and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are2017, and the responsibility ofrelated notes (collectively referred to as the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States)“financial statements”). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Energy Transfer Partners, L.P. and subsidiariesthe Partnership as of December 31, 20162017 and 2015,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20162017, in conformity with accounting principles generally accepted in the United States of America. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Partnership’s internal control over financial reporting as of December 31, 2016,2017, based on criteria established in the 2013Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO)(“COSO”), and our report dated February 24, 2017 (not23, 2018 (not separately included herein) expressed an unqualified opinion thereon. Change in accounting principle As discussed in Note 2 to the consolidated financial statements, the Partnership has changed its method of accounting for certain inventories. Basis for opinion These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP We have served as the Partnership’s auditor since 2004.
Dallas, Texas February 24, 201723, 2018
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016* | ASSETS | | | | | | | Current assets: | | | | | | | Cash and cash equivalents | $ | 360 |
| | $ | 527 |
| $ | 306 |
| | $ | 360 |
| Accounts receivable, net | 3,002 |
| | 2,118 |
| 3,946 |
| | 3,002 |
| Accounts receivable from related companies | 209 |
| | 268 |
| 318 |
| | 209 |
| Inventories | 1,712 |
| | 1,213 |
| 1,589 |
| | 1,626 |
| Income taxes receivable | | 135 |
| | 128 |
| Derivative assets | 20 |
| | 40 |
| 24 |
| | 20 |
| Other current assets | 426 |
| | 532 |
| 210 |
| | 298 |
| Total current assets | 5,729 |
| | 4,698 |
| 6,528 |
| | 5,643 |
| | | | | | | | Property, plant and equipment | 58,220 |
| | 50,869 |
| 67,699 |
| | 58,220 |
| Accumulated depreciation and depletion | (7,303 | ) | | (5,782 | ) | (9,262 | ) | | (7,303 | ) | | 50,917 |
| | 45,087 |
| 58,437 |
| | 50,917 |
| | | | | | | | Advances to and investments in unconsolidated affiliates | 4,280 |
| | 5,003 |
| 3,816 |
| | 4,280 |
| Other non-current assets, net | 672 |
| | 536 |
| 758 |
| | 672 |
| Intangible assets, net | 4,696 |
| | 4,421 |
| 5,311 |
| | 4,696 |
| Goodwill | 3,897 |
| | 5,428 |
| 3,115 |
| | 3,897 |
| Total assets | $ | 70,191 |
| | $ | 65,173 |
| $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (Dollars in millions) | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016* | LIABILITIES AND EQUITY | | | | | | | Current liabilities: | | | | | | | Accounts payable | $ | 2,900 |
| | $ | 1,859 |
| $ | 4,126 |
| | $ | 2,900 |
| Accounts payable to related companies | 43 |
| | 25 |
| 209 |
| | 43 |
| Derivative liabilities | 166 |
| | 63 |
| 109 |
| | 166 |
| Accrued and other current liabilities | 1,905 |
| | 2,048 |
| 2,143 |
| | 1,905 |
| Current maturities of long-term debt | 1,189 |
| | 126 |
| 407 |
| | 1,189 |
| Total current liabilities | 6,203 |
| | 4,121 |
| 6,994 |
| | 6,203 |
| | | | | | | | Long-term debt, less current maturities | 31,741 |
| | 28,553 |
| 32,687 |
| | 31,741 |
| Long-term notes payable – related company | 250 |
| | 233 |
| — |
| | 250 |
| Non-current derivative liabilities | 76 |
| | 137 |
| 145 |
| | 76 |
| Deferred income taxes | 4,394 |
| | 4,082 |
| 2,883 |
| | 4,394 |
| Other non-current liabilities | 952 |
| | 968 |
| 1,084 |
| | 952 |
| | | | | | | | Commitments and contingencies | | | |
| |
|
| Series A Preferred Units | 33 |
| | 33 |
| | Legacy ETP Preferred Units | | — |
| | 33 |
| Redeemable noncontrolling interests | 15 |
| | 15 |
| 21 |
| | 15 |
| | | | | | | | Equity: | | | | | | | Series A Preferred Units (950,000 units authorized, issued and outstanding as of December 31, 2017) | | 944 |
| | — |
| Series B Preferred Units (550,000 units authorized, issued and outstanding as of December 31, 2017) | | 547 |
| | — |
| Limited Partners: | | | | | Common Unitholders (1,164,112,575 and 794,803,854 units authorized, issued and outstanding as of December 31, 2017 and 2016, respectively) | | 26,531 |
| | 14,925 |
| Class E Unitholder (8,853,832 units authorized, issued and outstanding – held by subsidiary) | | — |
| | — |
| Class G Unitholder (90,706,000 units authorized, issued and outstanding – held by subsidiary) | | — |
| | — |
| Class H Unitholder (81,001,069 units authorized, issued and outstanding as of December 31, 2016) | | — |
| | 3,480 |
| Class I Unitholder (100 units authorized, issued and outstanding) | | — |
| | 2 |
| Class K Unitholders (101,525,429 units authorized, issued and outstanding – held by subsidiaries) | | — |
| | — |
| General Partner | 206 |
| | 306 |
| 244 |
| | 206 |
| Limited Partners: | | | | | Common Unitholders (529,869,235 and 505,645,703 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively) | 14,946 |
| | 17,043 |
| | Class E Unitholders (8,853,832 units authorized, issued and outstanding – held by subsidiary) | — |
| | — |
| | Class G Unitholders (90,706,000 units authorized, issued and outstanding – held by subsidiary) | — |
| | — |
| | Class H Unitholders (81,001,069 units authorized, issued and outstanding as of December 31, 2016 and 2015) | 3,480 |
| | 3,469 |
| | Class I Unitholders (100 units authorized, issued and outstanding) | 2 |
| | 14 |
| | Class K Unitholders (101,525,429 and 0 units authorized, issued and outstanding as of December 31, 2016 and 2015, respectively – held by subsidiary) | — |
| | — |
| | Accumulated other comprehensive income | 8 |
| | 4 |
| 3 |
| | 8 |
| Total partners’ capital | 18,642 |
| | 20,836 |
| 28,269 |
| | 18,621 |
| Noncontrolling interest | 7,885 |
| | 6,195 |
| 5,882 |
| | 7,820 |
| Total equity | 26,527 |
| | 27,031 |
| 34,151 |
| | 26,441 |
| Total liabilities and equity | $ | 70,191 |
| | $ | 65,173 |
| $ | 77,965 |
| | $ | 70,105 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (Dollars in millions, except per unit data) | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016* | | 2015* | REVENUES: | | | | | | | | | | | Natural gas sales | $ | 3,619 |
| | $ | 3,671 |
| | $ | 5,386 |
| $ | 4,172 |
| | $ | 3,619 |
| | $ | 3,671 |
| NGL sales | 4,841 |
| | 3,936 |
| | 5,845 |
| 6,972 |
| | 4,841 |
| | 3,936 |
| Crude sales | 6,766 |
| | 8,378 |
| | 16,416 |
| 10,184 |
| | 6,766 |
| | 8,378 |
| Gathering, transportation and other fees | 4,003 |
| | 3,997 |
| | 3,517 |
| 4,265 |
| | 4,003 |
| | 3,997 |
| Refined product sales (see Note 3) | 1,047 |
| | 9,958 |
| | 19,437 |
| 1,515 |
| | 1,047 |
| | 9,958 |
| Other (see Note 3) | 1,551 |
| | 4,352 |
| | 4,874 |
| 1,946 |
| | 1,551 |
| | 4,352 |
| Total revenues | 21,827 |
| | 34,292 |
| | 55,475 |
| 29,054 |
| | 21,827 |
| | 34,292 |
| COSTS AND EXPENSES: | | | | | | | | | | | Cost of products sold (see Note 3) | 15,394 |
| | 27,029 |
| | 48,414 |
| 20,801 |
| | 15,080 |
| | 26,714 |
| Operating expenses (see Note 3) | 1,484 |
| | 2,261 |
| | 2,059 |
| 2,170 |
| | 1,839 |
| | 2,608 |
| Depreciation, depletion and amortization | 1,986 |
| | 1,929 |
| | 1,669 |
| 2,332 |
| | 1,986 |
| | 1,929 |
| Selling, general and administrative (see Note 3) | 348 |
| | 475 |
| | 520 |
| 434 |
| | 348 |
| | 475 |
| Impairment losses | 813 |
| | 339 |
| | 370 |
| 920 |
| | 813 |
| | 339 |
| Total costs and expenses | 20,025 |
| | 32,033 |
| | 53,032 |
| 26,657 |
| | 20,066 |
| | 32,065 |
| OPERATING INCOME | 1,802 |
| | 2,259 |
| | 2,443 |
| 2,397 |
| | 1,761 |
| | 2,227 |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | Interest expense, net | (1,317 | ) | | (1,291 | ) | | (1,165 | ) | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Equity in earnings from unconsolidated affiliates | 59 |
| | 469 |
| | 332 |
| 156 |
| | 59 |
| | 469 |
| Impairment of investment in an unconsolidated affiliate | (308 | ) | | — |
| | — |
| | Impairment of investments in unconsolidated affiliates | | (313 | ) | | (308 | ) | | — |
| Gains on acquisitions | 83 |
| | — |
| | — |
| — |
| | 83 |
| | — |
| Gain on sale of AmeriGas common units | — |
| | — |
| | 177 |
| | Losses on extinguishments of debt | — |
| | (43 | ) | | (25 | ) | (42 | ) | | — |
| | (43 | ) | Losses on interest rate derivatives | (12 | ) | | (18 | ) | | (157 | ) | (37 | ) | | (12 | ) | | (18 | ) | Other, net | 131 |
| | 22 |
| | (12 | ) | 209 |
| | 131 |
| | 22 |
| INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE (BENEFIT) | 438 |
| | 1,398 |
| | 1,593 |
| | Income tax expense (benefit) from continuing operations | (186 | ) | | (123 | ) | | 358 |
| | INCOME FROM CONTINUING OPERATIONS | 624 |
| | 1,521 |
| | 1,235 |
| | Income from discontinued operations | — |
| | — |
| | 64 |
| | INCOME BEFORE INCOME TAX BENEFIT | | 1,005 |
| | 397 |
| | 1,366 |
| Income tax benefit | | (1,496 | ) | | (186 | ) | | (123 | ) | NET INCOME | 624 |
| | 1,521 |
| | 1,299 |
| 2,501 |
| | 583 |
| | 1,489 |
| Less: Net income attributable to noncontrolling interest | 327 |
| | 157 |
| | 116 |
| 420 |
| | 295 |
| | 134 |
| Less: Net loss attributable to predecessor | — |
| | (34 | ) | | (153 | ) | — |
| | — |
| | (34 | ) | NET INCOME ATTRIBUTABLE TO PARTNERS | 297 |
| | 1,398 |
| | 1,336 |
| 2,081 |
| | 288 |
| | 1,389 |
| General Partner’s interest in net income | 948 |
| | 1,064 |
| | 513 |
| 990 |
| | 948 |
| | 1,064 |
| Preferred Unitholders’ interest in net income | | 12 |
| | — |
| | — |
| Class H Unitholder’s interest in net income | 351 |
| | 258 |
| | 217 |
| 93 |
| | 351 |
| | 258 |
| Class I Unitholder’s interest in net income | 8 |
| | 94 |
| | — |
| — |
| | 8 |
| | 94 |
| Common Unitholders’ interest in net income (loss) | $ | (1,010 | ) | | $ | (18 | ) | | $ | 606 |
| $ | 986 |
| | $ | (1,019 | ) | | $ | (27 | ) | INCOME (LOSS) FROM CONTINUING OPERATIONS PER COMMON UNIT: | | | | | | | Basic | $ | (2.06 | ) | | $ | (0.09 | ) | | $ | 1.58 |
| | Diluted | $ | (2.06 | ) | | $ | (0.10 | ) | | $ | 1.58 |
| | NET INCOME (LOSS) PER COMMON UNIT: | | | | | | | | | | | Basic | $ | (2.06 | ) | | $ | (0.09 | ) | | $ | 1.77 |
| $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | Diluted | $ | (2.06 | ) | | $ | (0.10 | ) | | $ | 1.77 |
| $ | 0.93 |
| | $ | (1.38 | ) | | $ | (0.08 | ) |
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Dollars in millions) | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016* | | 2015* | Net income | $ | 624 |
| | $ | 1,521 |
| | $ | 1,299 |
| $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Other comprehensive income (loss), net of tax: | | | | | | | | | | | Reclassification to earnings of gains and losses on derivative instruments accounted for as cash flow hedges | — |
| | — |
| | 3 |
| | Change in value of available-for-sale securities | 2 |
| | (3 | ) | | 1 |
| 6 |
| | 2 |
| | (3 | ) | Actuarial gain (loss) relating to pension and other postretirement benefits | (1 | ) | | 65 |
| | (113 | ) | (12 | ) | | (1 | ) | | 65 |
| Foreign currency translation adjustment | (1 | ) | | (1 | ) | | (2 | ) | — |
| | (1 | ) | | (1 | ) | Change in other comprehensive income from unconsolidated affiliates | 4 |
| | (1 | ) | | (6 | ) | | Change in other comprehensive income (loss) from unconsolidated affiliates | | 1 |
| | 4 |
| | (1 | ) | | 4 |
| | 60 |
| | (117 | ) | (5 | ) | | 4 |
| | 60 |
| Comprehensive income | 628 |
| | 1,581 |
| | 1,182 |
| 2,496 |
| | 587 |
| | 1,549 |
| Less: Comprehensive income attributable to noncontrolling interest | 327 |
| | 157 |
| | 116 |
| 420 |
| | 295 |
| | 134 |
| Less: Comprehensive loss attributable to predecessor | — |
| | (34 | ) | | (153 | ) | — |
| | — |
| | (34 | ) | Comprehensive income attributable to partners | $ | 301 |
| | $ | 1,458 |
| | $ | 1,219 |
| $ | 2,076 |
| | $ | 292 |
| | $ | 1,449 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF EQUITY (Dollars in millions) | | | | | Limited Partners | | | | | | | | | | | | | Limited Partners | | | | | | | | | | | | General Partner | | Common Unitholders | | Class H Units | | Class I Units | | Accumulated Other Comprehensive Income (Loss) | | Noncontrolling Interest | | Predecessor Equity | | Total | Series A Preferred Units | | Series B Preferred Units | | Common Unit holders | | Class H Units | | Class I Units | | General Partner | | Accumulated Other Comprehensive Income (Loss) | | Non-controlling Interest | | Predecessor Equity | | Total | Balance, December 31, 2013 | $ | 171 |
| | $ | 9,797 |
| | $ | 1,511 |
| | $ | — |
| | $ | 61 |
| | $ | 3,780 |
| | $ | 3,374 |
| | $ | 18,694 |
| | Distributions to partners | (500 | ) | | (1,252 | ) | | (212 | ) | | — |
| | — |
| | — |
| | — |
| | (1,964 | ) | | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (241 | ) | | — |
| | (241 | ) | | Units issued for cash | — |
| | 1,382 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,382 |
| | Subsidiary units issued for cash | 1 |
| | 174 |
| | — |
| | — |
| | — |
| | 1,069 |
| | — |
| | 1,244 |
| | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 67 |
| | — |
| | 67 |
| | Lake Charles LNG Transaction | — |
| | (1,167 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,167 | ) | | Susser Merger | — |
| | 908 |
| | — |
| | — |
| | — |
| | 626 |
| | — |
| | 1,534 |
| | Sunoco Logistics acquisition of a noncontrolling interest | (1 | ) | | (79 | ) | | — |
| | — |
| | — |
| | (245 | ) | | — |
| | (325 | ) | | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (645 | ) | | (645 | ) | | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,227 |
| | 1,227 |
| | Predecessor equity issued for acquisitions, net of cash received | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4,281 |
| | 4,281 |
| | Other comprehensive loss, net of tax | — |
| | — |
| | — |
| | — |
| | (117 | ) | | — |
| | — |
| | (117 | ) | | Other, net | — |
| | 61 |
| | (4 | ) | | — |
| | — |
| | (19 | ) | | 4 |
| | 42 |
| | Net income (loss) | 513 |
| | 606 |
| | 217 |
| | — |
| | — |
| | 116 |
| | (153 | ) | | 1,299 |
| | Balance, December 31, 2014 | 184 |
| | 10,430 |
| | 1,512 |
| | — |
| | (56 | ) | | 5,153 |
| | 8,088 |
| | 25,311 |
| | Balance, December 31, 2014* | | $ | — |
| | $ | — |
| | $ | 10,427 |
| | $ | 1,512 |
| | $ | — |
| | $ | 184 |
| | $ | (56 | ) | | $ | 5,143 |
| | $ | 8,088 |
| | $ | 25,298 |
| Distributions to partners | (944 | ) | | (1,863 | ) | | (247 | ) | | (80 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | — |
| | — |
| | (1,863 | ) | | (247 | ) | | (80 | ) | | (944 | ) | | — |
| | — |
| | — |
| | (3,134 | ) | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (338 | ) | | — |
| | (338 | ) | Units issued for cash | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| — |
| | — |
| | 1,428 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,428 |
| Subsidiary units issued for cash | 2 |
| | 298 |
| | — |
| | — |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| — |
| | — |
| | 298 |
| | — |
| | — |
| | 2 |
| | — |
| | 1,219 |
| | — |
| | 1,519 |
| Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 875 |
| | — |
| | 875 |
| Bakken Pipeline Transaction | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| — |
| | — |
| | (999 | ) | | 1,946 |
| | — |
| | — |
| | — |
| | 72 |
| | — |
| | 1,019 |
| Sunoco LP Exchange Transaction | — |
| | (52 | ) | | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | — |
| | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | (940 | ) | | — |
| | (992 | ) | Susser Exchange Transaction | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | — |
| | — |
| | (68 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (68 | ) | Acquisition and disposition of noncontrolling interest | — |
| | (26 | ) | | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | — |
| | — |
| | (26 | ) | | — |
| | — |
| | — |
| | — |
| | (39 | ) | | — |
| | (65 | ) | Predecessor distributions to partners | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (202 | ) | | (202 | ) | Predecessor units issued for cash | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 34 |
| | 34 |
| Regency Merger | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| — |
| | — |
| | 7,890 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (7,890 | ) | | — |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| Other, net | — |
| | 23 |
| | — |
| | — |
| | — |
| | 36 |
| | 4 |
| | 63 |
| — |
| | — |
| | 23 |
| | — |
| | — |
| | — |
| | — |
| | 36 |
| | 4 |
| | 63 |
| Net income (loss) | | — |
| | — |
| | (27 | ) | | 258 |
| | 94 |
| | 1,064 |
| | — |
| | 134 |
| | (34 | ) | | 1,489 |
| Balance, December 31, 2015* | | — |
| | — |
| | 17,031 |
| | 3,469 |
| | 14 |
| | 306 |
| | 4 |
| | 6,162 |
| | — |
| | 26,986 |
| Distributions to partners | | — |
| | — |
| | (2,134 | ) | | (340 | ) | | (20 | ) | | (1,048 | ) | | — |
| | — |
| | — |
| | (3,542 | ) | Distributions to noncontrolling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (481 | ) | | — |
| | (481 | ) | Units issued for cash | | — |
| | — |
| | 1,098 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,098 |
| Subsidiary units issued | | — |
| | — |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | 1,351 |
| | — |
| | 1,388 |
|
| | Net income (loss) | 1,064 |
| | (18 | ) | | 258 |
| | 94 |
| | — |
| | 157 |
| | (34 | ) | | 1,521 |
| | Balance, December 31, 2015 | $ | 306 |
| | $ | 17,043 |
| | $ | 3,469 |
| | $ | 14 |
| | $ | 4 |
| | $ | 6,195 |
| | $ | — |
| | $ | 27,031 |
| | Distributions to partners | (1,048 | ) | | (2,134 | ) | | (340 | ) | | (20 | ) | | — |
| | — |
| | — |
| | (3,542 | ) | | Distributions to noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | (481 | ) | | — |
| | (481 | ) | | Units issued for cash | — |
| | 1,098 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,098 |
| | Subsidiary units issued | — |
| | 37 |
| | — |
| | — |
| | — |
| | 1,351 |
| | — |
| | 1,388 |
| | Capital contributions from noncontrolling interest | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 236 |
| Sunoco, Inc. retail business to Sunoco LP transaction | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | — |
| | — |
| | (405 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (405 | ) | PennTex Acquisition | — |
| | 307 |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| — |
| | — |
| | 307 |
| | — |
| | — |
| | — |
| | — |
| | 236 |
| | — |
| | 543 |
| Other comprehensive income, net of tax | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | — |
| | 4 |
| Other, net | — |
| | 10 |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| | — |
| | 31 |
| Net income (loss) | 948 |
| | (1,010 | ) | | 351 |
| | 8 |
| | — |
| | 327 |
| | — |
| | 624 |
| — |
| | — |
| | (1,019 | ) | | 351 |
| | 8 |
| | 948 |
| | — |
| | 295 |
| | — |
| | 583 |
| Balance, December 31, 2016 | $ | 206 |
| | $ | 14,946 |
| | $ | 3,480 |
| | $ | 2 |
| | $ | 8 |
| | $ | 7,885 |
| | $ | — |
| | $ | 26,527 |
| | Balance, December 31, 2016* | | — |
| | — |
| | 14,925 |
| | 3,480 |
| | 2 |
| | 206 |
| | 8 |
| | 7,820 |
| | — |
| | 26,441 |
| Distributions to partners | | — |
| | — |
| | (2,419 | ) | | (95 | ) | | (2 | ) | | (952 | ) | | — |
| | — |
| | — |
| | (3,468 | ) | Distributions to noncontrolling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (430 | ) | | — |
| | (430 | ) | Units issued for cash | | 937 |
| | 542 |
| | 2,283 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 3,762 |
| Sunoco Logistics Merger | | — |
| | — |
| | 9,416 |
| | (3,478 | ) | | — |
| | — |
| | — |
| | (5,938 | ) | | — |
| | — |
| Capital contributions from noncontrolling interest | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,202 |
| | — |
| | 2,202 |
| Sale of Bakken Pipeline interest | | — |
| | — |
| | 1,260 |
| | — |
| | — |
| | — |
| | — |
| | 740 |
| | — |
| | 2,000 |
| Sale of Rover Pipeline interest | | — |
| | — |
| | 93 |
| | — |
| | — |
| | — |
| | — |
| | 1,385 |
| | — |
| | 1,478 |
| Acquisition of PennTex noncontrolling interest | | — |
| | — |
| | (48 | ) | | — |
| | — |
| | — |
| | — |
| | (232 | ) | | — |
| | (280 | ) | Other comprehensive loss, net of tax | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | (5 | ) | Other, net | | — |
| | — |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | (85 | ) | | — |
| | (50 | ) | Net income | | 7 |
| | 5 |
| | 986 |
| | 93 |
| | — |
| | 990 |
| | — |
| | 420 |
| | — |
| | 2,501 |
| Balance, December 31, 2017 | | $ | 944 |
| | $ | 547 |
| | $ | 26,531 |
| | $ | — |
| | $ | — |
| | $ | 244 |
| | $ | 3 |
| | $ | 5,882 |
| | $ | — |
| | $ | 34,151 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Dollars in millions) | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016* | | 2015* | OPERATING ACTIVITIES: | | | | | | | | | | | Net income | $ | 624 |
| | $ | 1,521 |
| | $ | 1,299 |
| $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Reconciliation of net income to net cash provided by operating activities: | | | | | | | | | | | Depreciation, depletion and amortization | 1,986 |
| | 1,929 |
| | 1,669 |
| 2,332 |
| | 1,986 |
| | 1,929 |
| Deferred income taxes | (169 | ) | | 202 |
| | (49 | ) | (1,531 | ) | | (169 | ) | | 202 |
| Amortization included in interest expense | (20 | ) | | (36 | ) | | (60 | ) | 2 |
| | (20 | ) | | (36 | ) | Inventory valuation adjustments | (170 | ) | | 104 |
| | 473 |
| — |
| | — |
| | (58 | ) | Unit-based compensation expense | 80 |
| | 79 |
| | 68 |
| 74 |
| | 80 |
| | 79 |
| Impairment losses | 813 |
| | 339 |
| | 370 |
| 920 |
| | 813 |
| | 339 |
| Gains on acquisitions | (83 | ) | | — |
| | — |
| — |
| | (83 | ) | | — |
| Gain on sale of AmeriGas common units | — |
| | — |
| | (177 | ) | | Losses on extinguishments of debt | — |
| | 43 |
| | 25 |
| 42 |
| | — |
| | 43 |
| Impairment of investment in an unconsolidated affiliate | 308 |
| | — |
| | — |
| | Impairment of investments in unconsolidated affiliates | | 313 |
| | 308 |
| | — |
| Distributions on unvested awards | (25 | ) | | (16 | ) | | (16 | ) | (31 | ) | | (25 | ) | | (16 | ) | Equity in earnings of unconsolidated affiliates | (59 | ) | | (469 | ) | | (332 | ) | (156 | ) | | (59 | ) | | (469 | ) | Distributions from unconsolidated affiliates | 406 |
| | 440 |
| | 291 |
| 440 |
| | 406 |
| | 440 |
| Other non-cash | (271 | ) | | (22 | ) | | (72 | ) | (261 | ) | | (271 | ) | | (22 | ) | Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | (117 | ) | | (1,367 | ) | | (320 | ) | (160 | ) | | (246 | ) | | (1,173 | ) | Net cash provided by operating activities | 3,303 |
| | 2,747 |
| | 3,169 |
| 4,485 |
| | 3,303 |
| | 2,747 |
| INVESTING ACTIVITIES: | | | | | | | | | | | Cash proceeds from sale of Bakken Pipeline interest | | 2,000 |
| | — |
| | — |
| Cash proceeds from sale of Rover Pipeline interest | | 1,478 |
| | — |
| | — |
| Proceeds from the Sunoco, Inc. retail business to Sunoco LP transaction | 2,200 |
| | — |
| | — |
| — |
| | 2,200 |
| | — |
| Proceeds from Bakken Pipeline Transaction | — |
| | 980 |
| | — |
| — |
| | — |
| | 980 |
| Proceeds from Susser Exchange Transaction | — |
| | 967 |
| | — |
| — |
| | — |
| | 967 |
| Proceeds from sale of noncontrolling interest | — |
| | 64 |
| | — |
| — |
| | — |
| | 64 |
| Proceeds from the sale of AmeriGas common units | — |
| | — |
| | 814 |
| | Cash paid for acquisition of PennTex noncontrolling interest | | (280 | ) | | — |
| | — |
| Cash paid for Vitol Acquisition, net of cash received | (769 | ) | | — |
| | — |
| — |
| | (769 | ) | | — |
| Cash paid for PennTex Acquisition, net of cash received | (299 | ) | | — |
| | — |
| — |
| | (299 | ) | | — |
| Cash transferred to ETE in connection with the Sunoco LP Exchange | — |
| | (114 | ) | | — |
| — |
| | — |
| | (114 | ) | Cash paid for acquisition of a noncontrolling interest | — |
| | (129 | ) | | (325 | ) | — |
| | — |
| | (129 | ) | Cash paid for Susser Merger, net of cash received | — |
| | — |
| | (808 | ) | | Cash paid for predecessor acquisitions, net of cash received | — |
| | — |
| | (762 | ) | | Cash paid for all other acquisitions | (159 | ) | | (675 | ) | | (472 | ) | (264 | ) | | (159 | ) | | (675 | ) | Capital expenditures, excluding allowance for equity funds used during construction | (7,550 | ) | | (9,098 | ) | | (5,213 | ) | (8,335 | ) | | (7,550 | ) | | (9,098 | ) | Contributions in aid of construction costs | 71 |
| | 80 |
| | 45 |
| 24 |
| | 71 |
| | 80 |
| Contributions to unconsolidated affiliates | (59 | ) | | (45 | ) | | (399 | ) | (268 | ) | | (59 | ) | | (45 | ) | Distributions from unconsolidated affiliates in excess of cumulative earnings | 135 |
| | 124 |
| | 136 |
| 136 |
| | 135 |
| | 124 |
| Proceeds from sale of discontinued operations | — |
| | — |
| | 77 |
| | Proceeds from the sale of assets | 25 |
| | 23 |
| | 61 |
| 35 |
| | 25 |
| | 23 |
| Change in restricted cash | 14 |
| | 19 |
| | 172 |
| — |
| | 14 |
| | 19 |
| Other | 1 |
| | (16 | ) | | (18 | ) | 1 |
| | 1 |
| | (16 | ) | Net cash used in investing activities | (6,390 | ) | | (7,820 | ) | | (6,692 | ) | (5,473 | ) | | (6,390 | ) | | (7,820 | ) | | | | | | | | | | | |
| | FINANCING ACTIVITIES: | | | | | | | | | | | Proceeds from borrowings | 19,916 |
| | 22,462 |
| | 15,354 |
| 26,736 |
| | 19,916 |
| | 22,462 |
| Repayments of long-term debt | (15,799 | ) | | (17,843 | ) | | (12,702 | ) | (26,494 | ) | | (15,799 | ) | | (17,843 | ) | Proceeds from affiliate notes | 4,997 |
| | 233 |
| | — |
| | Repayments on affiliate notes | (4,873 | ) | | — |
| | — |
| | Units issued for cash | 1,098 |
| | 1,428 |
| | 1,382 |
| | Cash (paid to) received from affiliate notes | | (255 | ) | | 124 |
| | 233 |
| Common Units issued for cash | | 2,283 |
| | 1,098 |
| | 1,428 |
| Preferred Units issued for cash | | 1,479 |
| | — |
| | — |
| Subsidiary units issued for cash | 1,388 |
| | 1,519 |
| | 1,244 |
| — |
| | 1,388 |
| | 1,519 |
| Predecessor units issued for cash | — |
| | 34 |
| | 1,227 |
| — |
| | — |
| | 34 |
| Capital contributions from noncontrolling interest | 236 |
| | 841 |
| | 67 |
| 1,214 |
| | 236 |
| | 841 |
| Distributions to partners | (3,542 | ) | | (3,134 | ) | | (1,964 | ) | (3,468 | ) | | (3,542 | ) | | (3,134 | ) | Predecessor distributions to partners | — |
| | (202 | ) | | (645 | ) | — |
| | — |
| | (202 | ) | Distributions to noncontrolling interest | (481 | ) | | (338 | ) | | (241 | ) | (430 | ) | | (481 | ) | | (338 | ) | Redemption of Legacy ETP Preferred Units | | (53 | ) | | — |
| | — |
| Debt issuance costs | (22 | ) | | (63 | ) | | (63 | ) | (83 | ) | | (22 | ) | | (63 | ) | Other | 2 |
| | — |
| | (41 | ) | 5 |
| | 2 |
| | — |
| Net cash provided by financing activities | 2,920 |
| | 4,937 |
| | 3,618 |
| 934 |
| | 2,920 |
| | 4,937 |
| Increase (decrease) in cash and cash equivalents | (167 | ) | | (136 | ) | | 95 |
| | Decrease in cash and cash equivalents | | (54 | ) | | (167 | ) | | (136 | ) | Cash and cash equivalents, beginning of period | 527 |
| | 663 |
| | 568 |
| 360 |
| | 527 |
| | 663 |
| Cash and cash equivalents, end of period | $ | 360 |
| | $ | 527 |
| | $ | 663 |
| $ | 306 |
| | $ | 360 |
| | $ | 527 |
|
* As adjusted. See Note 2.
ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Tabular dollar and unit amounts, except per unit data, are in millions)
| | 1. | OPERATIONS AND BASIS OF PRESENTATION: |
Organization. The consolidated financial statements presented herein contain the results of Energy Transfer Partners, L.P. and its subsidiaries (the “Partnership,” “we,” “us,” “our” or “ETP”). The Partnership is managed by our general partner, ETP GP, which is in turn managed by its general partner, ETP LLC. ETE, a publicly traded master limited partnership, owns ETP LLC, the general partner of our General Partner. In April 2017, ETP and Sunoco Logistics completed the previously announced merger transaction in which Sunoco Logistics acquired ETP in a unit-for-unit transaction (the “Sunoco Logistics Merger”). Under the terms of the transaction, ETP unitholders received 1.5 common units of Sunoco Logistics for each common unit of ETP they owned. Under the terms of the merger agreement, Sunoco Logistics’ general partner was merged with and into ETP GP, with ETP GP surviving as an indirect wholly-owned subsidiary of ETE. In connection with the merger, the ETP Class H units were cancelled. The outstanding ETP Class E units, Class G units, Class I units and Class K units at the effective time of the merger were converted into an equal number of newly created classes of Sunoco Logistics units, with the same rights, preferences, privileges, duties and obligations as such classes of ETP units had immediately prior to the closing of the merger. Additionally, the outstanding Sunoco Logistics common units and Sunoco Logistics Class B units owned by ETP at the effective time of the merger were cancelled. In connection with the Sunoco Logistics Merger, Energy Transfer Partners, L.P. changed its name from “Energy Transfer Partners, L.P.” to “Energy Transfer, LP” and Sunoco Logistics Partners L.P. changed its name to “Energy Transfer Partners, L.P.” For purposes of maintaining clarity, the following references are used herein: References to “ETLP” refer to Energy Transfer, LP subsequent to the close of the merger; References to “Sunoco Logistics” refer to the entity named Sunoco Logistics Partners L.P. prior to the close of the merger; and References to “ETP” refer to the consolidated entity named Energy Transfer Partners, L.P. subsequent to the close of the merger. The Sunoco Logistics Merger resulted in Energy Transfer Partners, L.P. being treated as the surviving consolidated entity from an accounting perspective, while Sunoco Logistics (prior to changing its name to “Energy Transfer Partners, L.P.”) was the surviving consolidated entity from a legal and reporting perspective. Therefore, for the pre-merger periods, the consolidated financial statements reflect the consolidated financial statements of the legal acquiree (i.e., the entity that was named “Energy Transfer Partners, L.P.” prior to the merger and name changes). The Sunoco Logistics Merger was accounted for as an equity transaction. The Sunoco Logistics Merger did not result in any changes to the carrying values of assets and liabilities in the consolidated financial statements, and no gain or loss was recognized. For the periods prior to the Sunoco Logistics Merger, the Sunoco Logistics limited partner interests that were owned by third parties (other than Energy Transfer Partners, L.P. or its consolidated subsidiaries) are presented as noncontrolling interest in these consolidated financial statements. The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. The Partnership is engaged in the gathering and processing, compression, treating and transportation of natural gas, focusing on providing midstream services in some of the most prolific natural gas producing regions in the United States, including the Eagle Ford, Haynesville, Barnett, Fayetteville, Marcellus, Utica, Bone Spring and Avalon shales. The Partnership is engaged in intrastate transportation and storage natural gas operations that own and operate natural gas pipeline systems that are engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and NGLs in the states of Texas, Louisiana, New Mexico and West Virginia. The Partnership owns and operates interstate pipelines, either directly or through equity method investments, that transport natural gas to various markets in the United States.
The Partnership owns a controlling interest in Sunoco Logistics a publicly traded Delaware limited partnership thatPartners Operations L.P., which owns and operates a logistics business, consisting of a geographically diverse portfolio of complementary pipeline, terminalling, and acquisition and marketing assets, which are used to facilitate the purchase and sale of crude oil, NGLNGLs and refined products pipelines. The Partnership owns a controlling interest in PennTex, a publicly traded Delaware limited partnership that provides natural gas gathering and processing and residue gas and natural gas liquids transportation services to producers.products.
Basis of Presentation. The consolidated financial statements of the Partnership have been prepared in accordance with GAAP and include the accounts of all controlled subsidiaries after the elimination of all intercompany accounts and transactions. Certain prior year amounts have been conformed to the current year presentation. These reclassifications had no impact on net income or total equity. Management evaluated subsequent events through the date the financial statements were issued. For prior periods reported herein, certain transactions related to the business of legacy Sunoco Logistics have been reclassified from cost of products sold to operating expenses; these transactions include sales between operating subsidiaries and their marketing affiliates. These reclassifications had no impact on net income or total equity. The Partnership owns varying undivided interests in certain pipelines. Ownership of these pipelines has been structured as an ownership of an undivided interest in assets, not as an ownership interest in a partnership, limited liability company, joint venture or other forms of entities. Each owner controls marketing and invoices separately, and each owner is responsible for any loss, damage or injury that may occur to their own customers. As a result, these undivided interests are consolidated proportionately. | | 2. | ESTIMATES, SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL: |
Change in Accounting Policy During the fourth quarter of 2017, the Partnership elected to change its method of inventory costing to weighted-average cost for certain inventory that had previously been accounted for using the last-in, first-out (“LIFO”) method. The inventory impacted by this change included the crude oil, refined products and NGLs associated with the legacy Sunoco Logistics business. Management believes that the weighted-average cost method is preferable to the LIFO method as it more closely aligns the accounting policies across the consolidated entity, given that the legacy ETP inventory has been accounted for using the weighted-average cost method.
As a result of this change in accounting policy, prior periods have been retrospectively adjusted, as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2016 | | Year Ended December 31, 2015 | | As Originally Reported* | | Effect of Change | | As Adjusted | | As Originally Reported* | | Effect of Change | | As Adjusted | Consolidated Statement of Operations and Comprehensive Income: | | | | | | | | | | | | Cost of products sold | $ | 15,039 |
| | $ | 41 |
| | $ | 15,080 |
| | $ | 26,682 |
| | $ | 32 |
| | $ | 26,714 |
| Operating income | 1,802 |
| | (41 | ) | | 1,761 |
| | 2,259 |
| | (32 | ) | | 2,227 |
| Income before income tax benefit | 438 |
| | (41 | ) | | 397 |
| | 1,398 |
| | (32 | ) | | 1,366 |
| Net income | 624 |
| | (41 | ) | | 583 |
| | 1,521 |
| | (32 | ) | | 1,489 |
| Net income attributable to partners | 297 |
| | (9 | ) | | 288 |
| | 1,398 |
| | (9 | ) | | 1,389 |
| Net loss per common unit - basic | (1.37 | ) | | (0.01 | ) | | (1.38 | ) | | (0.06 | ) | | (0.01 | ) | | (0.07 | ) | Net loss per common unit - diluted | (1.37 | ) | | (0.01 | ) | | (1.38 | ) | | (0.07 | ) | | (0.01 | ) | | (0.08 | ) | Comprehensive income | 628 |
| | (41 | ) | | 587 |
| | 1,581 |
| | (32 | ) | | 1,549 |
| Comprehensive income attributable to partners | 301 |
| | (9 | ) | | 292 |
| | 1,458 |
| | (9 | ) | | 1,449 |
| | | | | | | | | | | | | Consolidated Statements of Cash Flows: | | | | | | | | | | | | Net income | 624 |
| | (41 | ) | | 583 |
| | 1,521 |
| | (32 | ) | | 1,489 |
| Net change in operating assets and liabilities (change in inventories) | (117 | ) | | (129 | ) | | (246 | ) | | (1,367 | ) | | 194 |
| | (1,173 | ) | | | | | | | | | | | | | Consolidated Balance Sheets (at period end): | | | | | | | | | | | | Inventories | 1,712 |
| | (86 | ) | | 1,626 |
| | 1,213 |
| | (45 | ) | | 1,168 |
| Total partners' capital | 18,642 |
| | (21 | ) | | 18,621 |
| | 20,836 |
| | (12 | ) | | 20,824 |
|
* Amounts reflect certain reclassifications made to conform to the current year presentation. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream, NGL and intrastate transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the estimated operating results represent the actual results in all material respects. Some of the other significant estimates made by management include, but are not limited to, the timing of certain forecasted transactions that are hedged, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, fair value measurements used in the goodwill impairment test, market value of inventory, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates. NewRecent Accounting Pronouncements
ASU 2014-09 In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update No. 2014-09, Revenuefrom Contracts with Customers (Topic 606) (“ASU 2014-09”), which clarifies the principles for recognizing revenue based
on the core principle that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
In August 2015, the FASB deferred the effective date ofThe Partnership adopted ASU 2014-09 which is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.on January 1, 2018. The guidance permits two methods of adoption: retrospectively to each prior reporting period presented (full retrospective method), or retrospectively withPartnership applied the cumulative catchup transition method and recognized the cumulative effect of initially applying the guidance recognized atretrospective application of the datestandard. The effect of initialthe retrospective application (the cumulative catchup transition method). The Partnership expects to adopt ASU 2014-09 inof the first quarter of 2018 and will apply the cumulative catchup transition method.standard was not material.
We are in the process of evaluating our revenue contracts by segment and fee type to determine the potential impact of adopting the new standards. At this point in our evaluation process,For future periods, we have determinedexpect that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by the adoption of this standard will result in a change to revenues with offsetting changes to costs associated primarily with the new standard; however, we are stilldesignation of certain of our midstream segment agreements to be in-substance supply agreements, requiring amounts that had previously been reported as revenue under these agreements to be reclassified to a reduction of cost of sales. Changes to revenues along with offsetting changes to costs will also occur due to changes in the processaccounting for noncash consideration in multiple of quantifying these impacts and cannot say whether or not they would be material to our financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls to support recognition and disclosure under the new standard. We continue to monitor additional authoritative or interpretive guidance related to the new standard as it becomes available,reportable segments, as well as comparing our conclusionsfuel usage and loss allowances. None of these changes is expected to have a material impact on specific interpretative issues to other peers in our industry, to the extent that such information is available to us.net income.
ASU 2016-02 In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“ASU 2016-02”), which establishes the principles that lessees and lessors shall apply to report useful information to users of financial statements about the amount, timing, and uncertainty of cash flows arising from a lease. The Partnership expects to adopt ASU 2016-02 is effective for fiscal years beginning after December 15, 2018,in the first quarter of 2019 and interim periods within those fiscal years. Early adoption is permitted. The Partnership is currently evaluating the impact that adopting this new standard will have on the consolidated financial statements and related disclosures. ASU 2016-16 On January 1, 2017,2018, the Partnership adopted Accounting Standards Update No. 2016-09, Stock Compensation (Topic 718) (“ASU 2016-09”). The objective of the update is to reduce complexity in accounting standards. The areas for simplification in this update involve several aspects of the accounting for employee share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The adoption of this standard did not have a material impact on the Partnership’s consolidated financial statements and related disclosures. In October 2016, the FASB issued Accounting Standards Update No. 2016-16, Income Taxes (Topic 740): Intra-entity Transfers of Assets Other Than Inventory (“ASU 2016-16”), which requires that entities recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The amendments in this update do not change GAAP for the pre-tax effects of an intra-entity asset transfer under Topic 810, Consolidation, or for an intra-entity transfer of inventory. ASU 2016-16 is effective for fiscal years beginning after December 15, 2017, and interim periods within those annual periods. Early adoption is permitted. The Partnership is currently evaluatingWe do not anticipate a material impact to our financial position or results of operations as a result of the impact that adoption of this standard will have on the consolidated financial statements and related disclosures.standard.
On January 1, 2017, the Partnership adopted Accounting Standards Update No. 2016-17, Consolidation (Topic 810): Interests Held Through Related Parties That Are Under Common Control (“ASU 2016-17”), which amends the consolidation guidance on how a reporting entity that is the single decision maker of a variable interest entity (VIE) should treat indirect interests in the entity held through related parties that are under common control with the reporting entity when determining whether it is the primary beneficiary of that VIE. Under the amendments, a single decision maker is required to include indirect interests on a proportionate basis consistent with indirect interests held through other related parties. The adoption of this standard did not have an impact on the Partnership’s consolidated financial statements and related disclosures.2017-04
In January 2017, the FASB issued ASU No. 2017-04 “Intangibles-Goodwill and other (Topic 350): Simplifying the test for goodwill impairment.” The amendments in this update remove the second step of the two-step test currently required by Topic 350. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit'sunit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance doesdid not amend the optional qualitative assessment of goodwill impairment. The standard requires prospective application and therefore will only impact periods subsequent to the adoption. The Partnership adopted this ASU for its annual goodwill impairment test in the fourth quarter of 2017. ASU 2017-12 In August 2017, the FASB issued ASU No. 2017-12 “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The amendments in this update improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. In addition, the amendments in this update make certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. This ASU is effective for financial statements issued for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019,2018, with early adoption permitted. We expectThe Partnership is currently evaluating the impact that our adoption ofadopting this new standard will change our approach for testing goodwill for impairment; however, this standard requires prospective applicationhave on the consolidated financial statements and therefore will only impact periods subsequent to adoption.related disclosures.
Revenue Recognition Revenues for sales of natural gas and NGLs are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation.sale. Revenues from service labor, transportation, treating, compression and gas processing are recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity is made available. Our intrastate transportation and storage and interstate transportation and storage segments’ results are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through the transportation pipelines. Under transportation contracts, our customers are charged (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, (iii) fuel retention based on a percentage of gas transported on the
pipeline, or (iv) a combination of the three, generally payable monthly. Fuel retained for a fee is typically valued at market prices. Our intrastate transportation and storage segment also generates revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies on the HPL System. Generally, we purchase natural gas from the market, including purchases from our marketing operations, and from producers at the wellhead. In addition, our intrastate transportation and storage segment generates revenues and margin from fees charged for storing customers’ working natural gas in our storage facilities. We also engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. We expect margins from natural gas storage transactions to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues. Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate midstream revenues and grosssegment margins principally under fee-based or other arrangements in which we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue earned from these arrangements is directly related to the volume of natural gas that flows through our systems and is not directly dependent on commodity prices. We also utilize other types of arrangements in our midstream segment, including (i) discount-to-index price arrangements, which involve purchases of natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount, (ii) percentage-of-proceeds arrangements under which we gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price, (iii) keep-whole arrangements where we gather natural gas from the producer, process the natural gas and sell the resulting NGLs to third parties at market prices, (iv) purchasing all or a specified percentage of natural gas and/or NGL delivered from producers and treating or processing our plant facilities, and (v) making other direct purchases of natural gas and/or NGL at specified delivery points to meet operational or marketing obligations. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. The terms of our contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Our contract mix may change as a result of changes in producer preferences, expansion in regions where some types of contracts are more common and other market factors. NGL storage and pipeline transportation revenues are recognized when services are performed or products are delivered, respectively. Fractionation and processing revenues are recognized when product is either loaded into a truck or injected into a third-party pipeline, which is when title and risk of loss pass to the customer. In our natural gas compression business, revenue is recognized for compressor packages and technical service jobs using the completed contract method which recognizes revenue upon completion of the job. Costs incurred on a job are deducted at the time revenue is recognized. We conduct marketing activities in which we market the natural gas that flows through our assets, referred to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, referred to as
off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices. Terminalling and storage revenues are recognized at the time the services are provided. Pipeline revenues are recognized upon delivery of the barrels to the location designated by the shipper. Crude oil acquisition and marketing revenues, as well as refined product marketing revenues, are recognized when title to the product is transferred to the customer. Revenues are not recognized for crude oil exchange transactions, which are entered into primarily to acquire crude oil of a desired quality or to reduce transportation costs by taking delivery closer to end markets. Any net differential for exchange transactions is recorded as an adjustment of inventory costs in the purchases component of cost of products sold and operating expenses in the statements of operations.
Regulatory Accounting – Regulatory Assets and Liabilities Our interstate transportation and storage segment is subject to regulation by certain state and federal authorities, and certain subsidiaries in that segment have accounting policies that conform to the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows certain of our regulated entities to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for these entities, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs. Although Panhandle’s natural gas transmission systems and storage operations are subject to the jurisdiction of FERC in accordance with the Natural Gas Act of 1938 and Natural Gas Policy Act of 1978, it does not currently apply regulatory accounting policies in accounting for its operations. Panhandle does not apply regulatory accounting policies primarily due to the level of discounting from tariff rates and its inability to recover specific costs. Cash, Cash Equivalents and Supplemental Cash Flow Information Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and that are subject to an insignificant risk of changes in value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.
The net change in operating assets and liabilities (net of effects of acquisitions and deconsolidations) included in cash flows from operating activities is comprised as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Accounts receivable | $ | (919 | ) | | $ | 819 |
| | $ | 600 |
| $ | (950 | ) | | $ | (919 | ) | | $ | 819 |
| Accounts receivable from related companies | 30 |
| | (243 | ) | | (22 | ) | 67 |
| | 30 |
| | (243 | ) | Inventories | (368 | ) | | (351 | ) | | 51 |
| 37 |
| | (497 | ) | | (157 | ) | Other current assets | 83 |
| | (178 | ) | | 150 |
| 39 |
| | 83 |
| | (178 | ) | Other non-current assets, net | (78 | ) | | 188 |
| | (6 | ) | (94 | ) | | (78 | ) | | 188 |
| Accounts payable | 972 |
| | (1,215 | ) | | (851 | ) | 758 |
| | 972 |
| | (1,215 | ) | Accounts payable to related companies | 29 |
| | (160 | ) | | 3 |
| (3 | ) | | 29 |
| | (160 | ) | Accrued and other current liabilities | 39 |
| | (83 | ) | | (191 | ) | (47 | ) | | 39 |
| | (83 | ) | Other non-current liabilities | 33 |
| | (219 | ) | | (73 | ) | 24 |
| | 33 |
| | (219 | ) | Price risk management assets and liabilities, net | 62 |
| | 75 |
| | 19 |
| 9 |
| | 62 |
| | 75 |
| Net change in operating assets and liabilities, net of effects of acquisitions and deconsolidations | $ | (117 | ) | | $ | (1,367 | ) | | $ | (320 | ) | $ | (160 | ) | | $ | (246 | ) | | $ | (1,173 | ) |
Non-cash investing and financing activities and supplemental cash flow information are as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | NON-CASH INVESTING ACTIVITIES: | | | | | | | | | | | Accrued capital expenditures | $ | 822 |
| | $ | 896 |
| | $ | 643 |
| $ | 1,059 |
| | $ | 822 |
| | $ | 896 |
| Sunoco LP limited partner interest received in exchange for contribution of the Sunoco, Inc. retail business to Sunoco LP | 194 |
| | — |
| | — |
| — |
| | 194 |
| | — |
| Net gains from subsidiary common unit transactions | 37 |
| | 300 |
| | 175 |
| — |
| | 37 |
| | 300 |
| NON-CASH FINANCING ACTIVITIES: | | | | | | | | | | | Issuance of Common Units in connection with the PennTex Acquisition | $ | 307 |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | 307 |
| | $ | — |
| Issuance of Common Units in connection with the Regency Merger | — |
| | 9,250 |
| | — |
| — |
| | — |
| | 9,250 |
| Issuance of Class H Units in connection with the Bakken Pipeline Transaction | — |
| | 1,946 |
| | — |
| — |
| | — |
| | 1,946 |
| Issuance of Common Units in connection with the Susser Merger | — |
| | — |
| | 908 |
| | Contribution of property, plant and equipment from noncontrolling interest | — |
| | 34 |
| | — |
| | Long-term debt assumed and non-compete agreement notes payable issued in acquisitions | — |
| | — |
| | 564 |
| | Predecessor equity issuances of common units in connection with Regency’s acquisitions | — |
| | — |
| | 4,281 |
| | Long-term debt assumed or exchanged in Regency’s acquisitions | — |
| | — |
| | 2,386 |
| | Contribution of assets from noncontrolling interest | | 988 |
| | — |
| | 34 |
| Redemption of Common Units in connection with the Bakken Pipeline Transaction | — |
| | 999 |
| | — |
| — |
| | — |
| | 999 |
| Redemption of Common Units in connection with the Sunoco LP Exchange | — |
| | 52 |
| | — |
| — |
| | — |
| | 52 |
| Redemption of Common Units in connection with the Lake Charles LNG Transaction | — |
| | — |
| | 1,167 |
| | SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | | | | | | Cash paid for interest, net of interest capitalized | $ | 1,411 |
| | $ | 1,467 |
| | $ | 1,232 |
| $ | 1,329 |
| | $ | 1,411 |
| | $ | 1,467 |
| Cash paid for (refund of) income taxes | (229 | ) | | 71 |
| | 344 |
| 50 |
| | (229 | ) | | 71 |
|
Accounts Receivable Our midstream, NGL and intrastate transportation and storage operations deal with a variety of counterparties across the energy sector, some of which are investment grade, and most of which are not. Internal credit ratings and credit limits are assigned to all counterparties and limits are monitored against credit exposure. Letters of credit or prepayments may be required from those counterparties that are not investment grade depending on the internal credit rating and level of commercial activity with the counterparty. Master setoff agreements are put in place with counterparties where appropriate to mitigate risk. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Our investment in Sunoco Logistics segment extends credit terms to certain customers after review of various credit indicators, including the customer’s credit rating. Based on that review, a letter of credit or other security may be required. Outstanding customer receivable balances are regularly reviewed for possible non-payment indicators and reserves are recorded for doubtful accounts based upon management’s estimate of collectability at the time of review. Actual balances are charged against the reserve when all collection efforts have been exhausted.
We have a diverse portfolio of customers,customers; however, because of the midstream and transportation services we provide, many of our customers are engaged in the exploration and production segment. We manage trade credit risk to mitigate credit losses and exposure to uncollectible trade receivables. Prospective and existing customers are reviewed regularly for creditworthiness to manage credit risk within approved tolerances. Customers that do not meet minimum credit standards are required to provide additional credit support in the form of a letter of credit, prepayment, or other forms of security. We establish an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables and considers many factors including historical customer collection experience, general and specific economic trends, and known specific issues related to individual customers, sectors, and transactions that might impact collectability. Increases in the allowance are recorded as a component of operating expenses; reductions in the allowance are recorded when receivables are subsequently collected or written-off. Past due receivable balances are written-off when our efforts have been unsuccessful in collecting the amount due. We enter into netting arrangements with counterparties to the extent possible to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the consolidated balance sheets. Inventories As discussed under “Change in Accounting Policy” in Note 2, the Partnership changed its accounting policy for certain inventory in the fourth quarter of 2017. Inventories consist principally of natural gas held in storage, NGLs and refined products, crude oil refined products and spare parts. Natural gas held in storage isparts, all of which are valued at the lower of cost or marketnet realizable value utilizing the weighted-average cost method. The cost of crude oil and refined products is determined using the last-in, first out method. The cost of spare parts is determined by the first-in, first-out method.
Inventories consisted of the following: | | | | | | | | | | December 31, | | 2016 | | 2015 | Natural gas and NGLs | $ | 699 |
| | $ | 415 |
| Crude oil | 683 |
| | 424 |
| Refined products | 113 |
| | 104 |
| Spare parts and other | 217 |
| | 270 |
| Total inventories | $ | 1,712 |
| | $ | 1,213 |
|
During the years ended December 31, 2016 and 2015, the Partnership recorded write-downs of $170 million and $104 million, respectively, on its crude oil, refined products and NGL inventories as a result of declines in the market price of these products. The write-downs were calculated based upon current replacement costs. | | | | | | | | | | December 31, | | 2017 | | 2016 | Natural gas, NGLs, and refined products | $ | 733 |
| | $ | 758 |
| Crude oil | 551 |
| | 651 |
| Spare parts and other | 305 |
| | 217 |
| Total inventories | $ | 1,589 |
| | $ | 1,626 |
|
We utilize commodity derivatives to manage price volatility associated with our natural gas inventory. Changes in fair value of designated hedged inventory are recorded in inventory on our consolidated balance sheets and cost of products sold in our consolidated statements of operations.
Other Current Assets Other current assets consisted of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Deposits paid to vendors | $ | 74 |
| | $ | 74 |
| $ | 64 |
| | $ | 74 |
| Income taxes receivable | 128 |
| | 291 |
| | Prepaid expenses and other | 224 |
| | 167 |
| 146 |
| | 224 |
| Total other current assets | $ | 426 |
| | $ | 532 |
| $ | 210 |
| | $ | 298 |
|
Property, Plant and Equipment Property, plant and equipment are stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful or FERC mandated lives of the assets, if applicable. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our consolidated statements of operations. Property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. In 2017, the Partnership recorded a $127 million fixed asset impairment related to Sea Robin primarily due to a reduction in expected future cash flows due to an increase during 2017 in insurance costs related to offshore assets. In 2016, the Partnership recorded a $133 million fixed asset impairment related to the interstate transportation and storage segment primarily due to expected decreases in future cash flows driven by declines in commodity prices as well as a $10 million impairment to property, plant and equipment in the midstream segment. In 2015, the Partnership recorded a $110 million fixed asset impairment related to the liquidsNGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. No other fixed asset impairments were identified or recorded for our reporting units during the periods presented. Capitalized interest is included for pipeline construction projects, except for certain interstate projects for which an allowance for funds used during construction (“AFUDC”) is accrued. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred. AFUDC is calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant for interstate projects. It represents the cost of servicing the capital invested in construction work-in-process. AFUDC is segregated into two component parts – borrowed funds and equity funds.
Components and useful lives of property, plant and equipment were as follows: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Land and improvements | $ | 659 |
| | $ | 686 |
| $ | 1,706 |
| | $ | 676 |
| Buildings and improvements (1 to 45 years) | 1,784 |
| | 1,526 |
| 1,960 |
| | 1,617 |
| Pipelines and equipment (5 to 83 years) | 35,923 |
| | 33,148 |
| 44,050 |
| | 36,356 |
| Natural gas and NGL storage facilities (5 to 46 years) | 1,515 |
| | 391 |
| 1,681 |
| | 1,452 |
| Bulk storage, equipment and facilities (2 to 83 years) | 3,677 |
| | 2,853 |
| 3,036 |
| | 3,701 |
| Retail equipment (2 to 99 years) | — |
| | 401 |
| | Vehicles (1 to 25 years) | 241 |
| | 220 |
| 124 |
| | 217 |
| Right of way (20 to 83 years) | 3,374 |
| | 2,573 |
| 3,424 |
| | 3,349 |
| Natural resources | 434 |
| | 484 |
| 434 |
| | 434 |
| Other (1 to 40 years) | 517 |
| | 743 |
| 534 |
| | 484 |
| Construction work-in-process | 10,096 |
| | 7,844 |
| 10,750 |
| | 9,934 |
| | 58,220 |
| | 50,869 |
| 67,699 |
| | 58,220 |
| Less – Accumulated depreciation and depletion | (7,303 | ) | | (5,782 | ) | (9,262 | ) | | (7,303 | ) | Property, plant and equipment, net | $ | 50,917 |
| | $ | 45,087 |
| $ | 58,437 |
| | $ | 50,917 |
|
We recognized the following amounts for the periods presented: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Depreciation and depletion expense | $ | 1,793 |
| | $ | 1,713 |
| | $ | 1,457 |
| $ | 2,060 |
| | $ | 1,793 |
| | $ | 1,713 |
| Capitalized interest, excluding AFUDC | 200 |
| | 163 |
| | 101 |
| | Capitalized interest | | 283 |
| | 199 |
| | 163 |
|
Advances to and Investments in Unconsolidated Affiliates We own interests in a number of related businesses that are accounted for by the equity method. In general, we use the equity method of accounting for an investment for which we exercise significant influence over, but do not control, the investee’s operating and financial policies. An impairment of an investment in an unconsolidated affiliate is recognized when circumstances indicate that a decline in the investment value is other than temporary. Other Non-Current Assets, net Other non-current assets, net are stated at cost less accumulated amortization. Other non-current assets, net consisted of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Unamortized financing costs(1) | $ | 3 |
| | $ | 11 |
| | Regulatory assets | 86 |
| | 90 |
| $ | 85 |
| | $ | 86 |
| Deferred charges | 217 |
| | 198 |
| 210 |
| | 217 |
| Restricted funds | 190 |
| | 192 |
| 192 |
| | 190 |
| Long-term affiliated receivable | 90 |
| | — |
| 85 |
| | 90 |
| Other | 86 |
| | 45 |
| 186 |
| | 89 |
| Total other non-current assets, net | $ | 672 |
| | $ | 536 |
| $ | 758 |
| | $ | 672 |
|
(1)Includes unamortized financing costs related to the Partnership’s revolving credit facilities. Restricted funds primarily consisted of restricted cash held in our wholly-owned captive insurance companies.
Intangible Assets Intangible assets are stated at cost, net of amortization computed on the straight-line method. The Partnership removes the gross carrying amount and the related accumulated amortization for any fully amortized intangibles in the year they are fully amortized. Components and useful lives of intangible assets were as follows: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Gross Carrying Amount | | Accumulated Amortization | | Gross Carrying Amount | | Accumulated Amortization | Amortizable intangible assets: | | | | | | | | | | | | | | | Customer relationships, contracts and agreements (3 to 46 years) | $ | 5,362 |
| | $ | (737 | ) | | $ | 4,601 |
| | $ | (554 | ) | $ | 6,250 |
| | $ | (1,003 | ) | | $ | 5,362 |
| | $ | (737 | ) | Patents (10 years) | 48 |
| | (21 | ) | | 48 |
| | (16 | ) | 48 |
| | (26 | ) | | 48 |
| | (21 | ) | Trade Names (20 years) | 66 |
| | (22 | ) | | 66 |
| | (18 | ) | 66 |
| | (25 | ) | | 66 |
| | (22 | ) | Other (1 to 15 years) | 2 |
| | (2 | ) | | 6 |
| | (3 | ) | | Total amortizable intangible assets | $ | 5,478 |
| | $ | (782 | ) | | $ | 4,721 |
| | $ | (591 | ) | | Non-amortizable intangible assets: | | | | | | | | | Trademarks | — |
| | — |
| | 291 |
| | — |
| | Other (5 to 20 years) | | 1 |
| | — |
| | 2 |
| | (2 | ) | Total intangible assets | $ | 5,478 |
| | $ | (782 | ) | | $ | 5,012 |
| | $ | (591 | ) | $ | 6,365 |
| | $ | (1,054 | ) | | $ | 5,478 |
| | $ | (782 | ) |
Aggregate amortization expense of intangible assets was as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Reported in depreciation, depletion and amortization | $ | 193 |
| | $ | 216 |
| | $ | 212 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Reported in depreciation, depletion and amortization | $ | 272 |
| | $ | 193 |
| | $ | 216 |
|
Estimated aggregate amortization expense for the next five years is as follows: | | Years Ending December 31: | | | 2017 | $ | 213 |
| | 2018 | 213 |
| $ | 280 |
| 2019 | 211 |
| 278 |
| 2020 | 211 |
| 278 |
| 2021 | 211 |
| 268 |
| 2022 | | 256 |
|
We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually, or more frequently if circumstances dictate. In 2015, we recorded $24 million of intangible asset impairments related to the liquidsNGL and refined products transportation and services segment primarily due to an expected decrease in future cash flows. Goodwill Goodwill is tested for impairment annually or more frequently if circumstances indicate that goodwill might be impaired. The annual impairment test is performed during the fourth quarter.
Changes in the carrying amount of goodwill were as follows: | | | Intrastate Transportation and Storage | | Interstate Transportation and Storage | | Midstream | | Liquids Transportation and Services | | Investment in Sunoco Logistics | | All Other | | Total | Intrastate Transportation and Storage | | Interstate Transportation and Storage | | Midstream | | NGL and Refined Products Transportation and Services | | Crude Oil Transportation and Services | | All Other | | Total | Balance, December 31, 2014 | $ | 10 |
| | $ | 1,011 |
| | $ | 767 |
| | $ | 432 |
| | $ | 1,358 |
| | $ | 4,064 |
| | $ | 7,642 |
| | Reduction due to Sunoco LP deconsolidation | — |
| | — |
| | — |
| | — |
| | — |
| | (2,018 | ) | | (2,018 | ) | | Balance, December 31, 2015 | | $ | 10 |
| | $ | 912 |
| | $ | 718 |
| | $ | 772 |
| | $ | 912 |
| | $ | 2,104 |
| | $ | 5,428 |
| Reduction due to contribution of legacy Sunoco, Inc. retail business | | — |
| | — |
| | — |
| | — |
| | — |
| | (1,289 | ) | | (1,289 | ) | Acquired | | — |
| | — |
| | 177 |
| | — |
| | 251 |
| | — |
| | 428 |
| Impaired | | — |
| | (638 | ) | | (32 | ) | | — |
| | — |
| | — |
| | (670 | ) | Balance, December 31, 2016 | | 10 |
| | 274 |
| | 863 |
| | 772 |
| | 1,163 |
| | 815 |
| | 3,897 |
| Acquired | | — |
| | — |
| | 8 |
| | — |
| | 4 |
| | — |
| | 12 |
| Impaired | — |
| | (99 | ) | | — |
| | (106 | ) | | — |
| | — |
| | (205 | ) | — |
| | (262 | ) | | — |
| | (79 | ) | | — |
| | (452 | ) | | (793 | ) | Other | — |
| | — |
| | (49 | ) | | — |
| | — |
| | 58 |
| | 9 |
| — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | Balance, December 31, 2015 | 10 |
| | 912 |
| | 718 |
| | 326 |
| | 1,358 |
| | 2,104 |
| | 5,428 |
| | Acquired | — |
| | — |
| | 177 |
| | — |
| | 251 |
| | — |
| | 428 |
| | Reduction due to contribution of legacy Sunoco, Inc. retail business | — |
| | — |
| | — |
| | — |
| | — |
| | (1,289 | ) | | (1,289 | ) | | Impaired | — |
| | (638 | ) | | (32 | ) | | — |
| | — |
| | — |
| | (670 | ) | | Balance, December 31, 2016 | $ | 10 |
| | $ | 274 |
| | $ | 863 |
| | $ | 326 |
| | $ | 1,609 |
| | $ | 815 |
| | $ | 3,897 |
| | Balance, December 31, 2017 | | $ | 10 |
| | $ | 12 |
| | $ | 870 |
| | $ | 693 |
| | $ | 1,167 |
| | $ | 363 |
| | $ | 3,115 |
|
Goodwill is recorded at the acquisition date based on a preliminary purchase price allocation and generally may be adjusted when the purchase price allocation is finalized. During the fourth quarter of 2017, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $262 million in the interstate transportation and storage segment, $79 million in the NGL and refined products transportation and services segment and $452 million in the all other segment primarily due to changes in assumptions related to projected future revenues and cash flows from the dates the goodwill was originally recorded. During the fourth quarter of 2016, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of $638 million the interstate transportation and storage segment and $32 million in the midstream segment primarily due to decreases in projected future revenues and cash flows driven by declines in commodity prices and changes in the markets that these assets serve. During the fourth quarter of 2015, the Partnership performed goodwill impairment tests on our reporting units and recognized goodwill impairments of: (i)of $99 million in the Transwestern reporting unitinterstate transportation and storage segment and $106 million in the NGL and refined products transportation and services segment primarily due primarily to the market declines in current and expected future commodity prices in the fourth quarter of 2015 and (ii) $106 million in the Lone Star Refinery Services reporting unit due primarily to changes in assumptions related to potential future revenues decrease as well as the market declines in current and expected future commodity prices.2015. The Partnership determined the fair value of our reporting units using a weighted combination of the discounted cash flow method and the guideline company method. Determining the fair value of a reporting unit requires judgment and the use of significant estimates and assumptions. Such estimates and assumptions include revenue growth rates, operating margins, weighted average costs of capital and future market conditions, among others. The Partnership believes the estimates and assumptions used in our impairment assessments are reasonable and based on available market information, but variations in any of the assumptions could result in materially different calculations of fair value and determinations of whether or not an impairment is indicated. Under the discounted cash flow method, the Partnership determined fair value based on estimated future cash flows of each reporting unit including estimates for capital expenditures, discounted to present value using the risk-adjusted industry rate, which reflect the overall level of inherent risk of the reporting unit. Cash flow projections are derived from one year budgeted amounts and five year operating forecasts plus an estimate of later period cash flows, all of which are evaluated by management. Subsequent period cash flows are developed for each reporting unit using growth rates that management believes are reasonably likely to occur. Under the guideline company method, the Partnership determined the estimated fair value of each of our reporting units by applying valuation multiples of comparable publicly-traded companies to each reporting unit’s projected EBITDA and then averaging that estimate with similar historical calculations using a three year average. In addition, the Partnership estimated a reasonable control premium representing the incremental value that accrues to the majority owner from the opportunity to dictate the strategic and operational actions of the business. Asset Retirement Obligations We have determined that we are obligated by contractual or regulatory requirements to remove facilities or perform other remediation upon retirement of certain assets. The fair value of any ARO is determined based on estimates and assumptions related to retirement costs, which the Partnership bases on historical retirement costs, future inflation rates and credit-adjusted
risk-free interest rates. These fair value assessments are considered to be Level 3 measurements, as they are based on both observable and unobservable inputs. Changes in the liability are recorded for the passage of time (accretion) or for revisions to cash flows originally estimated to settle the ARO.
An ARO is required to be recorded when a legal obligation to retire an asset exists and such obligation can be reasonably estimated. We will record an asset retirement obligation in the periods in which management can reasonably estimate the settlement dates. Except for certain amounts recorded by Panhandle and Sunoco Logistics discussed below, management was not able to reasonably measure the fair value of asset retirement obligations as of December 31, 20162017 and 2015,2016, in most cases because the settlement dates were indeterminable. Although a number of other onshore assets in Panhandle’s system are subject to agreements or regulations that give rise to an ARO upon Panhandle’s discontinued use of these assets, AROs were not recorded because these assets have an indeterminate removal or abandonment date given the expected continued use of the assets with proper maintenance or replacement. Sunoco, Inc. has legal asset retirement obligations for several other assets at its previously owned refineries, pipelines and terminals, for which it is not possible to estimate when the obligations will be settled. Consequently, the retirement obligations for these assets cannot be measured at this time. At the end of the useful life of these underlying assets, Sunoco, Inc. is legally or contractually required to abandon in place or remove the asset. Sunoco Logistics believes itWe believe we may have additional asset retirement obligations related to its pipeline assets and storage tanks, for which it is not possible to estimate whether or when the retirement obligations will be settled. Consequently, these retirement obligations cannot be measured at this time. Below is a scheduleAs of AROs by segment recorded asDecember 31, 2017 and 2016, other non-current liabilities in ETP’sthe Partnership’s consolidated balance sheets:
| | | | | | | | | | December 31, | | 2016 | | 2015 | Interstate transportation and storage | $ | 54 |
| | $ | 58 |
| Investment in Sunoco Logistics | 88 |
| | 88 |
| All other | 28 |
| | 66 |
| | $ | 170 |
| | $ | 212 |
|
sheets included AROs of $165 million and $170 million, respectively.Individual component assets have been and will continue to be replaced, but the pipeline and the natural gas gathering and processing systems will continue in operation as long as supply and demand for natural gas exists. Based on the widespread use of natural gas in industrial and power generation activities, management expects supply and demand to exist for the foreseeable future. We have in place a rigorous repair and maintenance program that keeps the pipelines and the natural gas gathering and processing systems in good working order. Therefore, although some of the individual assets may be replaced, the pipelines and the natural gas gathering and processing systems themselves will remain intact indefinitely. Long-lived assets related to AROs aggregated $14$2 million and $18$14 million, and were reflected as property, plant and equipment on our balance sheet as of December 31, 20162017 and 2015,2016, respectively. In addition, the Partnership had $13$21 million and $6$13 million legally restricted funds for the purpose of settling AROs that was reflected as other non-current assets as of December 31, 20162017 and 2015,2016, respectively. Accrued and Other Current Liabilities Accrued and other current liabilities consisted of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Interest payable | $ | 440 |
| | $ | 425 |
| $ | 443 |
| | $ | 440 |
| Customer advances and deposits | 56 |
| | 95 |
| 59 |
| | 56 |
| Accrued capital expenditures | 749 |
| | 743 |
| 1,006 |
| | 749 |
| Accrued wages and benefits | 212 |
| | 218 |
| 208 |
| | 212 |
| Taxes payable other than income taxes | 63 |
| | 76 |
| 108 |
| | 63 |
| Exchanges payable | 208 |
| | 105 |
| 154 |
| | 208 |
| Other | 177 |
| | 386 |
| 165 |
| | 177 |
| Total accrued and other current liabilities | $ | 1,905 |
| | $ | 2,048 |
| $ | 2,143 |
| | $ | 1,905 |
|
Deposits or advances are received from our customers as prepayments for natural gas deliveries in the following month. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit.
Redeemable Noncontrolling Interests The noncontrolling interest holders in one of Sunoco Logistics’our consolidated subsidiaries havehas the option to sell theirits interests to Sunoco Logistics.us. In accordance with applicable accounting guidance, the noncontrolling interest is excluded from total equity and reflected as redeemable interest on ETP’s consolidated balance sheet. Environmental Remediation We accrue environmental remediation costs for work at identified sites where an assessment has indicated that cleanup costs are probable and reasonably estimable. Such accruals are undiscounted and are based on currently available information, estimated timing of remedial actions and related inflation assumptions, existing technology and presently enacted laws and regulations. If a range of probable environmental cleanup costs exists for an identified site, the minimum of the range is accrued unless some other point in the range is more likely in which case the most likely amount in the range is accrued. Fair Value of Financial Instruments The carrying amounts of cash and cash equivalents, accounts receivable and accounts payable approximate their fair value. Based on the estimated borrowing rates currently available to us and our subsidiaries for loans with similar terms and average maturities, the aggregate fair value and carrying amount of our debt obligations as of December 31, 20162017 was $33.85$34.28 billion and $32.93$33.09 billion, respectively. As of December 31, 2015,2016, the aggregate fair value and carrying amount of our debt obligations was $25.71$33.85 billion and $28.68$32.93 billion, respectively. The fair value of our consolidated debt obligations is a Level 2 valuation based on the observable inputs used for similar liabilities. We have commodity derivatives, interest rate derivatives and embedded derivatives in our preferred units that are accounted for as assets and liabilities at fair value in our consolidated balance sheets. We determine the fair value of our assets and liabilities subject to fair value measurement by using the highest possible “level” of inputs. Level 1 inputs are observable quotes in an active market for identical assets and liabilities. We consider the valuation of marketable securities and commodity derivatives transacted through a clearing broker with a published price from the appropriate exchange as a Level 1 valuation. Level 2 inputs are inputs observable for similar assets and liabilities. We consider OTC commodity derivatives entered into directly with third parties as a Level 2 valuation since the values of these derivatives are quoted on an exchange for similar transactions. Additionally, we consider our options transacted through our clearing broker as having Level 2 inputs due to the level of activity of these contracts on the exchange in which they trade. We consider the valuation of our interest rate derivatives as Level 2 as the primary input, the LIBOR curve, is based on quotes from an active exchange of Eurodollar futures for the same period as the future interest swap settlements. Level 3 inputs are unobservable. Derivatives related to the embedded derivatives in our preferred units are valued using a binomial lattice model. The market inputs utilized in the model include credit spread, probabilities of the occurrence of certain events, common unit price, dividend yield, and expected value, and are considered Level 3. During the year ended December 31, 2016,2017, no transfers were made between any levels within the fair value hierarchy.
The following tables summarize the fair value of our financial assets and liabilities measured and recorded at fair value on a recurring basis as of December 31, 20162017 and 20152016 based on inputs used to derive their fair values: | | | Fair Value Total | | Fair Value Measurements at December 31, 2016 | Fair Value Total | | Fair Value Measurements at December 31, 2017 | | Level 1 | | Level 2 | | Level 3 | Level 1 | | Level 2 | Assets: | | | | | | | | | | | | | Commodity derivatives: | | | | | | | | | | | | | Natural Gas: | | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| $ | 11 |
| | $ | 11 |
| | $ | — |
| Swing Swaps IFERC | 2 |
| | — |
| | 2 |
| | — |
| 13 |
| | — |
| | 13 |
| Fixed Swaps/Futures | 96 |
| | 96 |
| | — |
| | — |
| 70 |
| | 70 |
| | — |
| Forward Physical Swaps | 1 |
| | — |
| | 1 |
| | — |
| 8 |
| | — |
| | 8 |
| Power: | | | | | | | | | | | | | Forwards | 4 |
| | — |
| | 4 |
| | — |
| 23 |
| | — |
| | 23 |
| Futures | 1 |
| | 1 |
| | — |
| | — |
| | Options – Calls | 1 |
| | 1 |
| | — |
| | — |
| | Natural Gas Liquids – Forwards/Swaps | 233 |
| | 233 |
| | — |
| | — |
| 193 |
| | 193 |
| | — |
| Refined Products – Futures | 1 |
| | 1 |
| | — |
| | — |
| | Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| 2 |
| | 2 |
| | — |
| Total commodity derivatives | 362 |
| | 355 |
| | 7 |
| | — |
| 320 |
| | 276 |
| | 44 |
| Other non-current assets | | 21 |
| | 14 |
| | 7 |
| Total assets | $ | 362 |
| | $ | 355 |
| | $ | 7 |
| | $ | — |
| $ | 341 |
| | $ | 290 |
| | $ | 51 |
| Liabilities: | | | | | | | | | | | | | Interest rate derivatives | $ | (193 | ) | | $ | — |
| | $ | (193 | ) | | $ | — |
| $ | (219 | ) | | $ | — |
| | $ | (219 | ) | Embedded derivatives in the ETP Preferred Units | (1 | ) | | — |
| | — |
| | (1 | ) | | Commodity derivatives: | | | | | | | | | | | | | Natural Gas: | | | | | | | | | | | | | Basis Swaps IFERC/NYMEX | (11 | ) | | (11 | ) | | — |
| | — |
| (24 | ) | | (24 | ) | | — |
| Swing Swaps IFERC | (3 | ) | | — |
| | (3 | ) | | — |
| (15 | ) | | (1 | ) | | (14 | ) | Fixed Swaps/Futures | (149 | ) | | (149 | ) | | — |
| | — |
| (57 | ) | | (57 | ) | | — |
| Power: | | | | | | | | | Forwards | (5 | ) | | — |
| | (5 | ) | | — |
| | Futures | (1 | ) | | (1 | ) | | — |
| | — |
| | Forward Physical Swaps | | (2 | ) | | — |
| | (2 | ) | Power – Forwards | | (22 | ) | | — |
| | (22 | ) | Natural Gas Liquids – Forwards/Swaps | (273 | ) | | (273 | ) | | — |
| | — |
| (192 | ) | | (192 | ) | | — |
| Refined Products – Futures | (17 | ) | | (17 | ) | | — |
| | — |
| (25 | ) | | (25 | ) | | — |
| Crude – Futures | (13 | ) | | (13 | ) | | — |
| | — |
| (1 | ) | | (1 | ) | | — |
| Total commodity derivatives | (472 | ) | | (464 | ) | | (8 | ) | | — |
| (338 | ) | | (300 | ) | | (38 | ) | Total liabilities | $ | (666 | ) | | $ | (464 | ) | | $ | (201 | ) | | $ | (1 | ) | $ | (557 | ) | | $ | (300 | ) | | $ | (257 | ) |
| | | | | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2015 | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | $ | 16 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| Swing Swaps IFERC | 10 |
| | 2 |
| | 8 |
| | — |
| Fixed Swaps/Futures | 274 |
| | 274 |
| | — |
| | — |
| Forward Physical Swaps | 4 |
| | — |
| | 4 |
| | — |
| Power: | | | | | | | | Forwards | 22 |
| | — |
| | 22 |
| | — |
| Futures | 3 |
| | 3 |
| | — |
| | — |
| Options – Puts | 1 |
| | 1 |
| | — |
| | — |
| Options – Calls | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | 99 |
| | 99 |
| | — |
| | — |
| Refined Products – Futures | 9 |
| | 9 |
| | — |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| Total commodity derivatives | 448 |
| | 414 |
| | 34 |
| | — |
| Total assets | $ | 448 |
| | $ | 414 |
| | $ | 34 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (171 | ) | | $ | — |
| | $ | (171 | ) | | $ | — |
| Embedded derivatives in the ETP Preferred Units | (5 | ) | | — |
| | — |
| | (5 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (16 | ) | | (16 | ) | | — |
| | — |
| Swing Swaps IFERC | (12 | ) | | (2 | ) | | (10 | ) | | — |
| Fixed Swaps/Futures | (203 | ) | | (203 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (22 | ) | | — |
| | (22 | ) | | — |
| Futures | (2 | ) | | (2 | ) | | — |
| | — |
| Options – Puts | (1 | ) | | (1 | ) | | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | (89 | ) | | (89 | ) | | — |
| | — |
| Crude – Futures | (5 | ) | | (5 | ) | | — |
| | — |
| Total commodity derivatives | (350 | ) | | (318 | ) | | (32 | ) | | — |
| Total liabilities | $ | (526 | ) | | $ | (318 | ) | | $ | (203 | ) | | $ | (5 | ) |
The following table presents the material unobservable inputs used to estimate the fair value of ETP’s Preferred Units and the embedded derivatives in ETP’s Preferred Units:
| | | | | | | Unobservable Input | | December 31, 2016 | Embedded derivatives in the ETP Preferred Units | Credit Spread | | 5.12 | % | | Volatility | | 31.73 | % |
Changes in the remaining term of the Preferred Units, U.S. Treasury yields and valuations in related instruments would cause a change in the yield to value the Preferred Units. Changes in ETP’s cost of equity and U.S. Treasury yields would cause a change in the credit spread used to value the embedded derivatives in the ETP Preferred Units. Changes in ETP’s historical unit price volatility would cause a change in the volatility used to value the embedded derivatives.
The following table presents a reconciliation of the beginning and ending balances for our Level 3 financial instruments measured at fair value on a recurring basis using significant unobservable inputs for the year ended December 31, 2016.
| | | | | Balance, December 31, 2015 | $ | (5 | ) | Net unrealized gains included in other income (expense) | 4 |
| Balance, December 31, 2016 | $ | (1 | ) |
| | | | | | | | | | | | | | | | | | Fair Value Total | | Fair Value Measurements at December 31, 2016 | | Level 1 | | Level 2 | | Level 3 | Assets: | | | | | | | | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | $ | 14 |
| | $ | 14 |
| | $ | — |
| | $ | — |
| Swing Swaps IFERC | 2 |
| | — |
| | 2 |
| | — |
| Fixed Swaps/Futures | 96 |
| | 96 |
| | — |
| | — |
| Forward Physical Swaps | 1 |
| | — |
| | 1 |
| | — |
| Power: | | | | | | | | Forwards | 4 |
| | — |
| | 4 |
| | — |
| Futures | 1 |
| | 1 |
| | — |
| | — |
| Options – Calls | 1 |
| | 1 |
| | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | 233 |
| | 233 |
| | — |
| | — |
| Refined Products – Futures | 1 |
| | 1 |
| | — |
| | — |
| Crude – Futures | 9 |
| | 9 |
| | — |
| | — |
| Total commodity derivatives | 362 |
| | 355 |
| | 7 |
| | — |
| Other non-current assets | 13 |
| | 8 |
| | 5 |
| | — |
| Total assets | $ | 375 |
| | $ | 363 |
| | $ | 12 |
| | $ | — |
| Liabilities: | | | | | | | | Interest rate derivatives | $ | (193 | ) | | $ | — |
| | $ | (193 | ) | | $ | — |
| Embedded derivatives in the Legacy ETP Preferred Units | (1 | ) | | — |
| | — |
| | (1 | ) | Commodity derivatives: | | | | | | | | Natural Gas: | | | | | | | | Basis Swaps IFERC/NYMEX | (11 | ) | | (11 | ) | | — |
| | — |
| Swing Swaps IFERC | (3 | ) | | — |
| | (3 | ) | | — |
| Fixed Swaps/Futures | (149 | ) | | (149 | ) | | — |
| | — |
| Power: | | | | | | | | Forwards | (5 | ) | | — |
| | (5 | ) | | — |
| Futures | (1 | ) | | (1 | ) | | — |
| | — |
| Natural Gas Liquids – Forwards/Swaps | (273 | ) | | (273 | ) | | — |
| | — |
| Refined Products – Futures | (17 | ) | | (17 | ) | | — |
| | — |
| Crude – Futures | (13 | ) | | (13 | ) | | — |
| | — |
| Total commodity derivatives | (472 | ) | | (464 | ) | | (8 | ) | | — |
| Total liabilities | $ | (666 | ) | | $ | (464 | ) | | $ | (201 | ) | | $ | (1 | ) |
Contributions in Aid of Construction Costs On certain of our capital projects, third parties are obligated to reimburse us for all or a portion of project expenditures. The majority of such arrangements are associated with pipeline construction and production well tie-ins. Contributions in aid of construction costs (“CIAC”) are netted against our project costs as they are received, and any CIAC which exceeds our total project costs, is recognized as other income in the period in which it is realized. Shipping and Handling Costs Shipping and handling costs are included in cost of products sold, except for shipping and handling costs related to fuel consumed for compression and treating which are included in operating expenses.
Costs and Expenses CostsCost of products sold include actual cost of fuel sold, adjusted for the effects of our hedging and other commodity derivative activities, and the cost of appliances, parts and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, purchasing costs and plant operations. Selling, general and administrative expenses include all partnership related expenses and compensation for executive, partnership, and administrative personnel.
We record the collection of taxes to be remitted to government authorities on a net basis except for our all other segment in which consumer excise taxes on sales of refined products and merchandise are included in both revenues and costs and expenses in the consolidated statements of operations, with no effect on net income (loss). For the year ended December 31, 2016, due to the dropdown of our retail assets to2015, excise taxes collected by Sunoco LP were $1.85 billion. The Partnership deconsolidated Sunoco LP effective July 1, 2015 and no excise taxes were collected. For the years ended December 31, 2015 and 2014, excise taxes collected by our all other segment were $1.85 billion and $2.46 billion, respectively.consolidated operations subsequent to that date. Issuances of Subsidiary Units We record changes in our ownership interest of our subsidiaries as equity transactions, with no gain or loss recognized in consolidated net income or comprehensive income. For example, upon our subsidiary’s issuance of common units in a public offering, we record any difference between the amount of consideration received or paid and the amount by which the noncontrolling interest is adjusted as a change in partners’ capital. Income Taxes ETP is a publicly traded limited partnership and is not taxable for federal and most state income tax purposes. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and most state purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial basis of assets and liabilities, differences between the tax accounting and financial accounting treatment of certain items, and due to allocation requirements related to taxable income under our Second Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”). As a publicly traded limited partnership, we are subject to a statutory requirement that our “qualifying income” (as defined by the Internal Revenue Code, related Treasury Regulations, and IRS pronouncements) exceed 90% of our total gross income, determined on a calendar year basis. If our qualifying income does not meet this statutory requirement, ETP would be taxed as a corporation for federal and state income tax purposes. For the years ended December 31, 2017, 2016, 2015, and 2014,2015, our qualifying income met the statutory requirement. The Partnership conducts certain activities through corporate subsidiaries which are subject to federal, state and local income taxes. These corporate subsidiaries include ETP Holdco, Inland Corporation, Oasis Pipeline Company and until July 31, 2015, Susser Holding Corporation. The Partnership and its corporate subsidiaries account for income taxes under the asset and liability method.
Under this method, deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rate is recognized in earnings in the period that includes the enactment date. Valuation allowances are established when necessary to reduce deferred tax assets to the amounts more likely than not to be realized. The determination of the provision for income taxes requires significant judgment, use of estimates, and the interpretation and application of complex tax laws. Significant judgment is required in assessing the timing and amounts of deductible and taxable items and the probability of sustaining uncertain tax positions. The benefits of uncertain tax positions are recorded in our financial statements only after determining a more-likely-than-not probability that the uncertain tax positions will withstand challenge, if any, from taxing authorities. When facts and circumstances change, we reassess these probabilities and record any changes through the provision for income taxes. Accounting for Derivative Instruments and Hedging Activities For qualifying hedges, we formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment and the gains and losses offset related results on the hedged item in the statement of operations. The market prices used to value our financial derivatives and related transactions have been determined using independent third-party prices, readily available market information, broker quotes and appropriate valuation techniques.
At inception of a hedge, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness and how any ineffectiveness will be measured and recorded. We also assess, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in net income for the period. If we designate a commodity hedging relationship as a fair value hedge, we record the changes in fair value of the hedged asset or liability in cost of products sold in our consolidated statements of operations. This amount is offset by the changes in fair value of the related hedging instrument. Any ineffective portion or amount excluded from the assessment of hedge ineffectiveness is also included in the cost of products sold in the consolidated statements of operations. Cash flows from derivatives accounted for as cash flow hedges are reported as cash flows from operating activities, in the same category as the cash flows from the items being hedged. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, the change in the fair value is deferred in AOCI until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges remain in AOCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For financial derivative instruments that do not qualify for hedge accounting, the change in fair value is recorded in cost of products sold in the consolidated statements of operations. We manage a portion of our interest rate exposures by utilizing interest rate swaps and similar instruments. Certain of our interest rate derivatives are accounted for as either cash flow hedges or fair value hedges. For interest rate derivatives accounted for as either cash flow or fair value hedges, we report realized gains and losses and ineffectiveness portions of those hedges in interest expense. For interest rate derivatives not designated as hedges for accounting purposes, we report realized and unrealized gains and losses on those derivatives in “Gains (losses) on interest rate derivatives” in the consolidated statements of operations. Unit-Based Compensation For awards of restricted units, we recognize compensation expense over the vesting period based on the grant-date fair value, which is determined based on the market price of our Common Units on the grant date. For awards of cash restricted units, we remeasure the fair value of the award at the end of each reporting period based on the market price of our Common Units as of the reporting date, and the fair value is recorded in other non-current liabilities on our consolidated balance sheets. Pensions and Other Postretirement Benefit Plans Employers are required to recognize in their balance sheetsThe Partnership recognizes the overfunded or underfunded status of defined benefit pension and other postretirement plans, measured as the difference between the fair value of the plan assets and the benefit obligation
(the (the projected benefit obligation for pension plans and the accumulated postretirement benefit obligation for other postretirement plans). Each overfunded plan is recognized as an asset and each underfunded plan is recognized as a liability. Employers must recognize the changeChanges in the funded status of the plan are recorded in the year in which the change occurs within AOCI in equity or, for entities applying regulatory accounting, as a regulatory asset or regulatory liability.
Allocation of Income For purposes of maintaining partner capital accounts, the Partnership Agreement specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests. The capital account provisions of our Partnership Agreement incorporate principles established for U.S.United States Federal income tax purposes and are not comparable to the partners’ capital balances reflected under GAAP in our consolidated financial statements. Our net income for partners’ capital and statement of operations presentation purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to priority income allocations for incentive distributions, if any, to our General Partner, the holder of the IDRs pursuant to our Partnership Agreement, which are declared and paid following the close of each quarter. Earnings in excess of distributions are allocated to the General Partner and Limited Partners based on their respective ownership interests.
| | 3. | ACQUISITIONS, DIVESTITURES AND RELATED TRANSACTIONS: |
20162018 Transactions
CDM Contribution Agreement In January 2018, ETP entered into a contribution agreement (“CDM Contribution Agreement”) with ETP GP, ETC Compression, LLC, USAC and ETE, pursuant to which, among other things, ETP will contribute to USAC and USAC will acquire from ETP all of the issued and outstanding membership interests of CDM and CDM E&T for aggregate consideration of approximately $1.7 billion, consisting of (i) 19,191,351 common units representing limited partner interests in USAC (“USAC Common Units”), with a value of approximately $335 million, (ii) 6,397,965 units of a newly authorized and established class of units representing limited partner interests in USAC (“Class B Units”), with a value of approximately $112 million and (iii) an amount in cash equal to $1.225 billion, subject to certain adjustments. The Class B Units that ETP will receive will be a new class of partnership interests of USAC that will have substantially all of the rights and obligations of a USAC Common Unit, except the Class B Units will not participate in distributions made prior to the one year anniversary of the closing date of the CDM Contribution Agreement (such date, the “Class B Conversion Date”) with respect to USAC Common Units. On the Class B Conversion Date, each Class B Unit will automatically convert into one USAC Common Unit. The transaction is expected to close in the first half of 2018, subject to customary closing conditions. In connection with the CDM Contribution Agreement, ETP entered into a purchase agreement with ETE, Energy Transfer Partners, L.L.C. (together with ETE, the “GP Purchasers”), USAC Holdings and, solely for certain purposes therein, R/C IV USACP Holdings, L.P., pursuant to which, among other things, the GP Purchasers will acquire from USAC Holdings (i) all of the outstanding limited liability company interests in USA Compression GP, LLC, the general partner of USAC (“USAC GP”), and (ii) 12,466,912 USAC Common Units for cash consideration equal to $250 million. 2017 Transactions Rover Contribution Agreement In October 2017, ETP completed the previously announced contribution transaction with a fund managed by Blackstone Energy Partners and Blackstone Capital Partners, pursuant to which ETP exchanged a 49.9% interest in the holding company that owns 65% of the Rover pipeline (“Rover Holdco”). As a result, Rover Holdco is now owned 50.1% by ETP and 49.9% by Blackstone. Upon closing, Blackstone contributed funds to reimburse ETP for its pro rata share of the Rover construction costs incurred by ETP through the closing date, along with the payment of additional amounts subject to certain adjustments. ETP and Sunoco Logistics Merger In November 2016, ETPAs discussed in Note 1, in April 2017, Energy Transfer Partners, L.P. and Sunoco Logistics entered into a merger agreement providing forcompleted the acquisition of ETP by Sunoco Logistics Merger.
Permian Express Partners In February 2017, Sunoco Logistics formed PEP, a strategic joint venture with ExxonMobil. Sunoco Logistics contributed its Permian Express 1, Permian Express 2, Permian Longview and Louisiana Access pipelines. ExxonMobil contributed its Longview to Louisiana and Pegasus pipelines, Hawkins gathering system, an idle pipeline in a unit-for-unit transaction. Undersouthern Oklahoma, and its Patoka, Illinois terminal. Assets contributed to PEP by ExxonMobil were reflected at fair value on the termsPartnership’s consolidated balance sheet at the date of the transaction,contribution, including $547 million of intangible assets and $435 million of property, plant and equipment. In July 2017, ETP unitholders will receive 1.5 common unitscontributed an approximate 15% ownership interest in Dakota Access and ETCO to PEP, which resulted in an increase in ETP’s ownership interest in PEP to approximately 88%. ETP maintains a controlling financial and voting interest in PEP and is the operator of Sunoco Logistics for each common unit of ETP they own. Under the termsall of the merger agreement, Sunoco Logistics’ general partner will be merged with and intoassets. As such, PEP is reflected as a consolidated subsidiary of the Partnership. ExxonMobil’s interest in PEP is reflected as noncontrolling interest in the consolidated balance sheets. ExxonMobil’s contribution resulted in an increase of $988 million in noncontrolling interest, which is reflected in “Capital contributions from noncontrolling interest” in the consolidated statement of equity.
Bakken Equity Sale In February 2017, Bakken Holdings Company LLC, an entity in which ETP GP, with ETP GP surviving as an indirectindirectly owns a 100% membership interest, sold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by MPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of ETE.Dakota Access and ETCO. The transactionremaining 25% of each of Dakota Access and ETCO is expectedowned by wholly-owned subsidiaries of Phillips 66. ETP continues to close in April 2017.consolidate Dakota Access and ETCO subsequent to this transaction. 2016 Transactions PennTex Acquisition On November 1, 2016, ETP acquired certain interests in PennTex from various parties for total consideration of approximately $627 million in ETP units and cash. Through this transaction, ETP acquired a controlling financial interest in PennTex, whose assets complement ETP’s existing midstream footprint in northern Louisiana. As discussed in Note 8, the Partnership purchased PennTex’s remaining outstanding common units in June 2017. Summary of Assets Acquired and Liabilities Assumed We accounted for the PennTex acquisition using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The total purchase price was allocated as follows: | | | | | | | | At November 1, 2016 | Total current assets | | $ | 34 |
| Property, plant and equipment | | 393 |
| Goodwill(1) | | 177 |
| Intangible assets | | 446 |
| | | 1,050 |
| | | | Total current liabilities | | 6 |
| Long-term debt, less current maturities | | 164 |
| Other non-current liabilities | | 17 |
| Noncontrolling interest | | 236 |
| | | 423 |
| Total consideration | | 627 |
| Cash received | | 21 |
| Total consideration, net of cash received | | $ | 606 |
|
| | (1) | None of the goodwill is expected to be deductible for tax purposes. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches. Sunoco Logistics’ Vitol Acquisition In November 2016, Sunoco Logistics completed an acquisition from Vitol, Inc. (“Vitol”) of an integrated crude oil business in West Texas for $760 million plus working capital. The acquisition provides Sunoco Logistics with an approximately 2 million barrel crude oil terminal in Midland, Texas, a crude oil gathering and mainline pipeline system in the Midland Basin, including a significant acreage dedication from an investment-grade Permian producer, and crude oil inventories related to Vitol'sVitol’s crude oil purchasing and marketing business in West Texas. The acquisition also included the purchase of a 50% interest in SunVit Pipeline LLC ("SunVit"(“SunVit”), which increased Sunoco Logistics'Logistics’ overall ownership of SunVit to 100%. The $769 million purchase price, net of cash received, consisted primarily of net working capital of $13 million largely attributable to inventory and receivables; property, plant and equipment of $286 million primarily related to pipeline and terminalling assets; intangible assets of $313 million attributable to customer relationships; and goodwill of $251 million. Sunoco Logistics’ Permian Express Partners
In February 2017, Sunoco Logistics formed Permian Express Partners LLC ("PEP"), a strategic joint venture, with ExxonMobil Corp. Sunoco Logistics contributed its Permian Express 1, Permian Express 2 and Permian Longview and Louisiana Access pipelines. ExxonMobil Corp. contributed its Longview to Louisiana and Pegasus pipelines; Hawkins gathering system; an idle pipeline in southern Oklahoma; and its Patoka, Illinois terminal. Sunoco Logistics’ ownership percentage is approximately 85%. Upon commencement of operations on the Bakken Pipeline, Sunoco Logistics will contribute its investment in the project, with a corresponding increase in its ownership percentage in PEP. Sunoco Logistics maintains a controlling financial and voting interest in PEP and is the operator of all of the assets. As such, PEP will be reflected as a consolidated subsidiary of Sunoco Logistics. ExxonMobil Corp.’s interest will be reflected as noncontrolling interest in Sunoco Logistics’ consolidated balance sheet.
Bakken Equity Sale
On August 2, 2016, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60% membership interest and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sell a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum Corporation and Enbridge Energy Partners, L.P. for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access, LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”). The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continue to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer
Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.
Bakken Financing In August 2016, ETP, Sunoco Logistics and Phillips 66 announced the completion of the project-level financing of the Bakken Pipeline. The $2.50 billion credit facility is anticipated to provideprovided substantially all of the remaining capital necessary to complete the projects. As of December 31, 2016, $1.102017, $2.50 billion was outstanding under this credit facility. Bayou Bridge In April 2016, Bayou Bridge Pipeline, LLC (“Bayou Bridge”), a joint venture among ETP, Sunoco Logistics and Phillips 66, Partners LP, began commercial operations on the 30-inch segment of the pipeline from Nederland, Texas to Lake Charles, Louisiana. ETP and Sunoco Logistics each hold a 30% interest in the entity and Sunoco Logistics is the operator of the system. Sunoco Retail to Sunoco LP In March 2016, ETP contributed to Sunoco LP its remaining 68.42% interest in Sunoco, LLC and 100% interest in the legacy Sunoco, Inc. retail business for $2.23 billion. Sunoco LP paid $2.20 billion in cash, including a working capital adjustment and issued 5.7 million Sunoco LP common units to Retail Holdings, a wholly-owned subsidiary of the Partnership. The transaction was effective January 1, 2016. In connection with this transaction, the Partnership deconsolidated the legacy Sunoco, Inc. retail business, including goodwill of $1.29 billion and intangible assets of $294 million. The results of Sunoco, LLC and the legacy Sunoco, Inc. retail business’ operations have not been presented as discontinued operations and Sunoco, Inc.’s retail business assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Following is a summary of amounts reflected for the prior periods in ETP’s consolidated statements of operations related to Sunoco, LLC and the legacy Sunoco, Inc. retail business, which operations are no longer consolidated for the current period in 2016:consolidated: | | | Years Ended December 31, | | | | | 2015 | | 2014 | Year Ended December 31, 2015 | Revenues | $ | 12,482 |
| | $ | 22,487 |
| $ | 12,482 |
| Cost of products sold | 11,174 |
| | 21,155 |
| 11,174 |
| Operating expenses | 798 |
| | 727 |
| 798 |
| Selling, general and administrative expenses | 106 |
| | 99 |
| 106 |
|
2015 Transactions Sunoco LP In April 2015, Sunoco LP acquired a 31.58% equity interest in Sunoco, LLC from Retail Holdings for $816 million. Sunoco, LLC distributes approximately 5.3 billion gallons per year of motor fuel to customers in the east, midwest and southwest regions of the United States. Sunoco LP paid $775 million in cash and issued a value of $41 million ofin Sunoco LP common units to Retail Holdings, based on the five-day volume weighted average price of Sunoco LP’s common units as of March 20, 2015. In July 2015, in exchange for the contribution of 100% of Susser from ETP to Sunoco LP, Sunoco LP paid $970 million in cash and issued to ETP subsidiaries 22 million Sunoco LP Class B units valued at $970 million. The Sunoco Class B units did not receive second quarter 2015 cash distributions from Sunoco LP and converted on a one-for-one basis into Sunoco LP common units on the day immediately following the record date for Sunoco LP’s second quarter 2015 distribution. In addition, (i) a Susser subsidiary exchanged its 79,308 Sunoco LP common units for 79,308 Sunoco LP Class A units, (ii) 10.9 million Sunoco LP subordinated units owned by Susser subsidiaries were converted into 10.9 million Sunoco LP Class A units and (iii) Sunoco LP issued 79,308 Sunoco LP common units and 10.9 million Sunoco LP subordinated units to subsidiaries of ETP. The Sunoco LP Class A units owned by the Susser subsidiaries were contributed to Sunoco LP as part of the transaction. Sunoco LP subsequently contributed its interests in Susser to one of its subsidiaries. Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from ETP, and in exchange, ETP repurchased from ETE 2131.5 million ETP common units owned by ETE (the “Sunoco LP Exchange”). In connection with ETP’s 2014 acquisition of Susser, ETE agreed to provide ETP a $35 million annual IDR subsidy for 10 years, which terminated upon the closing of ETE’s acquisition of Sunoco GP. In
connection with the exchange and repurchase, ETE will provideprovided ETP a $35 million annual IDR subsidy for two years beginning with the quarter ended September 30, 2015. In connection with this transaction, the Partnership deconsolidated Sunoco LP, including goodwill of $1.81 billion and intangible assets of $982 million related to Sunoco LP. TheAt December 31, 2017, the Partnership continues to holdheld 37.8 million Sunoco LP common units accounted for under the equity method. Subsequent to Sunoco LP’s
repurchase of a portion of its common units on February 7, 2018, as discussed in Note 4, our investment in Sunoco LP consists of 26.2 million units. The results of Sunoco LP’s operations have not been presented as discontinued operations and Sunoco LP’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements. Bakken Pipeline In March 2015, ETE transferred 30.846.2 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued Class H Units of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitleentitled ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 Class I Units that provideprovided distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. The Class H Units were cancelled in connection with the Sunoco Logistics Merger in April 2017. In October 2015, Sunoco Logistics completed the previously announced acquisition of a 40% membership interest (the “Bakken Membership Interest”) in Bakken Holdings Company LLC (“Bakken Holdco”). Bakken Holdco, through its wholly-owned subsidiaries, owns a 75% membership interest in each of Dakota Access LLC and Energy Transfer Crude Oil Company, LLC,ETCO, which together intend to develop the Bakken Pipeline system to deliver crude oil from the Bakken/Three Forks production area in North Dakota to the Gulf Coast. ETP transferred the Bakken Membership Interest to Sunoco Logistics in exchange for approximately 9.4 million Class B Units representing limited partner interests in Sunoco Logistics and the payment by Sunoco Logistics to ETP of $382 million of cash, which represented reimbursement for its proportionate share of the total cash contributions made in the Bakken Pipeline project as of the date of closing of the exchange transaction. Regency Merger On April 30, 2015, a wholly-owned subsidiary of the Partnership merged with Regency, with Regency surviving as a wholly-owned subsidiary of the Partnership (the “Regency Merger”). Each Regency common unit and Class F unit was converted into the right to receive 0.41240.6186 Partnership common units. ETP issued 172.2258.3 million Partnership common units to Regency unitholders, including 15.523.3 million units issued to Partnership subsidiaries. TheRegency’s 1.9 million outstanding Regency seriesSeries A preferred unitsConvertible Preferred Units were converted into corresponding new Partnership Series ALegacy ETP Preferred Units on a one-for-one basis. In connection with the Regency Merger, ETE agreed to reduce the incentive distributions it receives from the Partnership by a total of $320 million over a five-year period. The IDR subsidy was $80 million for the year ended December 31, 2015 and will total $60 million per year for the following four years. The Regency Merger was a combination of entities under common control; therefore, Regency’s assets and liabilities were not adjusted. The Partnership’s consolidated financial statements have been retrospectively adjusted to reflect consolidation of Regency for all prior periods subsequent to May 26, 2010 (the date ETE acquired Regency’s general partner). Predecessor equity included on the consolidated financial statements represents Regency’s equity prior to the Regency Merger. ETP has assumed all of the obligations of Regency and Regency Energy Finance Corp., of which ETP was previously a co-obligor or parent guarantor. 2014 Transactions
MACS to Sunoco LP
In October 2014, Sunoco LP acquired MACS from a subsidiary of ETP in a transaction valued at approximately $768 million (the “MACS Transaction”). The transaction included approximately 110 company-operated retail convenience stores and 200 dealer-operated and consignment sites from MACS, which had originally been acquired by ETP in October 2013. The consideration paid by Sunoco LP consisted of approximately 4 million Sunoco LP common units issued to ETP and $556 million in cash, subject to customary closing adjustments. Sunoco LP initially financed the cash portion by utilizing availability under its revolving credit facility. In October 2014 and November 2014, Sunoco LP partially repaid borrowings on its revolving credit facility with aggregate net proceeds of $405 million from a public offering of 9.1 million Sunoco LP common units.
Susser Merger
In August 2014, ETP and Susser completed the merger of an indirect wholly-owned subsidiary of ETP, with and into Susser, with Susser surviving the merger as a subsidiary of ETP for total consideration valued at approximately $1.8 billion (the “Susser Merger”). The total consideration paid in cash was approximately $875 million and the total consideration paid in equity was approximately 15.8 million ETP Common Units. The Susser Merger broadens our retail geographic footprint and provides synergy opportunities and a platform for future growth.
In connection with the Susser Merger, ETP acquired an indirect 100% equity interest in Susser and the general partner interest and the incentive distribution rights in Sunoco LP, approximately 11 million Sunoco LP common and subordinated units, and Susser’s existing retail operations, consisting of 630 convenience store locations.
Effective with the closing of the transaction, Susser ceased to be a publicly traded company and its common stock discontinued trading on the NYSE.
Summary of Assets Acquired and Liabilities Assumed
We accounted for the Susser Merger using the acquisition method of accounting, which requires, among other things, that assets acquired and liabilities assumed be recognized on the balance sheet at their fair values as of the acquisition date.
The following table summarizes the assets acquired and liabilities assumed recognized as of the merger date:
| | | | | | | | Susser | Total current assets | | $ | 446 |
| Property, plant and equipment | | 1,069 |
| Goodwill(1) | | 1,734 |
| Intangible assets | | 611 |
| Other non-current assets | | 17 |
| | | 3,877 |
| | | | Total current liabilities | | 377 |
| Long-term debt, less current maturities | | 564 |
| Deferred income taxes | | 488 |
| Other non-current liabilities | | 39 |
| Noncontrolling interest | | 626 |
| | | 2,094 |
| Total consideration | | 1,783 |
| Cash received | | 67 |
| Total consideration, net of cash received | | $ | 1,716 |
|
| | (1)
| None of the goodwill is expected to be deductible for tax purposes. |
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
ETP incurred merger related costs related to the Susser Merger of $25 million during the year ended December 31, 2014. Our consolidated statements of operations for the year ended December 31, 2014 reflected revenue and net income related to Susser of $2.32 billion and $105 million, respectively.
No pro forma information has been presented, as the impact of these acquisitions was not material in relation to ETP’s consolidated results of operations.
Regency’s Acquisition of Eagle Rock’s Midstream Business
On July 1, 2014, Regency acquired Eagle Rock’s midstream business (the “Eagle Rock Midstream Acquisition”) for $1.3 billion, including the assumption of $499 million of Eagle Rock’s 8.375% senior notes due 2019. The remainder of the purchase price was funded by $400 million in Regency Common Units sold to a wholly-owned subsidiary of ETE, 8.2 million
Regency Common Units issued to Eagle Rock and borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to Eagle Rock’s operations of $903 million and $30 million, respectively.
The total purchase price was allocated as follows:
| | | | | Assets | At July 1, 2014 | Current assets | $ | 120 |
| Property, plant and equipment | 1,295 |
| Other non-current assets | 4 |
| Goodwill | 49 |
| Total assets acquired | 1,468 |
| Liabilities | | Current liabilities | 116 |
| Long-term debt | 499 |
| Other non-current liabilities | 12 |
| Total liabilities assumed | 627 |
| | | Net assets acquired | $ | 841 |
|
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Regency’s Acquisition of PVR Partners, L.P.
On March 21, 2014, Regency acquired PVR for a total purchase price of $5.7 billion (based on Regency’s closing price of $27.82 per Regency Common Unit on March 21, 2014), including $1.8 billion principal amount of assumed debt (the “PVR Acquisition”). PVR unitholders received (on a per unit basis) 1.02 Regency Common Units and a one-time cash payment of $36 million, which was funded through borrowings under Regency’s revolving credit facility. Our consolidated statement of operations for the year ended December 31, 2014 included revenues and net income attributable to PVR’s operations of $956 million and $166 million, respectively.
The total purchase price was allocated as follows:
| | | | | Assets | At March 21, 2014 | Current assets | $ | 149 |
| Property, plant and equipment | 2,716 |
| Investment in unconsolidated affiliates | 62 |
| Intangible assets (average useful life of 30 years) | 2,717 |
| Goodwill(1) | 370 |
| Other non-current assets | 18 |
| Total assets acquired | 6,032 |
| Liabilities | | Current liabilities | 168 |
| Long-term debt | 1,788 |
| Premium related to senior notes | 99 |
| Non-current liabilities | 30 |
| Total liabilities assumed | 2,085 |
| Net assets acquired | $ | 3,947 |
|
(1)None of the goodwill is expected to be deductible for tax purposes.
The fair values of the assets acquired and liabilities assumed were determined using various valuation techniques, including the income and market approaches.
Lake Charles LNG Transaction
On February 19, 2014, ETP completed the transfer to ETE of Lake Charles LNG, the entity that owns a LNG regasification facility in Lake Charles, Louisiana, in exchange for the redemption by ETP of 18.7 million ETP Common Units held by ETE (the “Lake Charles LNG Transaction”). This transaction was effective as of January 1, 2014, at which time ETP deconsolidated Lake Charles LNG, including goodwill of $184 million and intangible assets of $50 million related to Lake Charles LNG. The results of Lake Charles LNG’s operations have not been presented as discontinued operations and Lake Charles LNG’s assets and liabilities have not been presented as held for sale in the Partnership’s consolidated financial statements due to the continuing involvement among the entities.
In connection with ETE’s acquisition of Lake Charles LNG, ETP agreed to continue to provide management services for ETE through 2015 in relation to both Lake Charles LNG’s regasification facility and the development of a liquefaction project at Lake Charles LNG’s facility, for which ETE has agreed to pay incremental management fees to ETP of $75 million per year for the years ending December 31, 2014 and 2015. ETE also agreed to provide additional subsidies to ETP through the relinquishment of future incentive distributions, as discussed further in Note 8.
Panhandle Merger
On January 10, 2014, Panhandle consummated a merger with Southern Union, the indirect parent of Panhandle at the time of the merger, and PEPL Holdings, a wholly-owned subsidiary of Southern Union and the sole limited partner of Panhandle at the time of the merger, pursuant to which each of Southern Union and PEPL Holdings were merged with and into Panhandle (the “Panhandle Merger”), with Panhandle surviving the Panhandle Merger. In connection with the Panhandle Merger, Panhandle assumed Southern Union’s obligations under its 7.6% senior notes due 2024, 8.25% senior notes due 2029 and the junior subordinated notes due 2066. At the time of the Panhandle Merger, Southern Union did not have material operations of its own, other than its ownership of Panhandle and noncontrolling interests in PEI Power II, LLC, Regency (31.4 million common units and 6.3 million Class F Units, all of which have subsequently converted into ETP common units), and ETP (2.2 million Common Units).
| | 4. | ADVANCES TO AND INVESTMENTS IN UNCONSOLIDATED AFFILIATES: |
The carrying values of the Partnership’s investments in unconsolidated affiliates as of December 31, 2016 and 2015 were as follows:
| | | | | | | | | | December 31, | | 2016 | | 2015 | Citrus | $ | 1,729 |
| | $ | 1,739 |
| AmeriGas | 82 |
| | 80 |
| FEP | 101 |
| | 115 |
| MEP | 318 |
| | 660 |
| HPC | 382 |
| | 402 |
| Sunoco LP | 1,225 |
| | 1,380 |
| Others | 443 |
| | 627 |
| Total | $ | 4,280 |
| | $ | 5,003 |
|
Citrus ETP owns CrossCountry, which in turn owns a 50% interest in Citrus. The other 50% interest in Citrus is owned by a subsidiary of KMI. Citrus owns 100% of FGT, aan approximately 5,360-mile natural gas pipeline system that originates in Texas and delivers natural gas to the Florida peninsula. AmeriGas
In 2012, we received 29.6 million AmeriGas common units Our investment in connection with the contribution of our propane operations. During the year ended December 31, 2014, we sold 18.9 million AmeriGas common units for net proceeds of $814 million.
As of December 31, 2016, the Partnership’s remaining interest in AmeriGas common units consisted of 3.1 million units held by a wholly-owned captive insurance company andCitrus is reflected in the all otherour interstate transportation and storage segment.
FEP We have a 50% interest in FEP which owns an approximately 185-mile natural gas pipeline that originates in Conway County, Arkansas, continues eastward through White County, Arkansas and terminates at an interconnect with Trunkline Gas Company in Panola County, Mississippi. Our investment in FEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in FEP for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. The Partnership recorded an impairment of its investment
in FEP of $141 million during the year ended December 31, 2017 due to a negative outlook for long-term transportation contracts as a result of a decrease in production in the Fayetteville basin and a customer re-contracting with a competitor. MEP We own a 50% interest in MEP, which owns approximately 500 miles of natural gas pipeline that extends from Southeast Oklahoma, across Northeast Texas, Northern Louisiana and Central Mississippi to an interconnect with the Transcontinental natural gas pipeline system in Butler, Alabama. Our investment in MEP is reflected in the interstate transportation and storage segment. The Partnership evaluated its investment in MEP for impairment as of September 30, 2016, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. Based on commercial discussions with current and potential shippers on MEP regarding the outlook for long-term transportation contract rates, the Partnership concluded that the fair value of its investment was other than temporarily impaired, resulting in a non-cash impairment of $308 million during the year ended December 31, 2016. HPC We own a 49.99% interest in HPC, which, through its ownership of RIGS, delivers natural gas from northwest Louisiana to downstream pipelines and markets through a 450-mile intrastate pipeline system. Our investment in HPC is reflected in the intrastate transportation and storage segment. The Partnership evaluated its investment in HPC for impairment as of December 31, 2017, based on FASB Accounting Standards Codification 323, Investments - Equity Method and Joint Ventures. During the year ended December 31, 2017, the Partnership recorded a $172 million impairment of its equity method investment in HPC primarily due to a decrease in projected future revenues and cash flows driven by the bankruptcy of one of HPC’s major customers in 2017 and an expectation that contracts expiring in the next few years will be renewed at lower tariff rates and lower volumes. Sunoco LP Effective July 1, 2015, ETE acquired 100% of the membership interests of Sunoco GP, the general partner of Sunoco LP, and all of the IDRs of Sunoco LP from the Partnership. As a result, the Partnership deconsolidated Sunoco LP, and its remaining investment in Sunoco LP is accounted for under the equity method. As of December 31, 2016,2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 44.3%43.6% of Sunoco LP’s total outstanding common units, and is reflected in the all other segment. In February 2018, after the record date for Sunoco LP’s fourth quarter 2017 cash distributions, Sunoco LP repurchased 17,286,859 Sunoco LP common units owned by ETP for aggregate cash consideration of approximately $540 million. ETP used the proceeds from the sale of the Sunoco LP common units to repay amounts outstanding under its revolving credit facility. The carrying values of the Partnership’s advances to and investments in unconsolidated affiliates as of December 31, 2017 and 2016 were as follows: | | | | | | | | | | December 31, | | 2017 | | 2016 | Citrus | $ | 1,754 |
| | $ | 1,729 |
| FEP | 121 |
| | 101 |
| MEP | 242 |
| | 318 |
| HPC | 28 |
| | 382 |
| Sunoco LP | 1,095 |
| | 1,225 |
| Others | 576 |
| | 525 |
| Total | $ | 3,816 |
| | $ | 4,280 |
|
The following table presents equity in earnings (losses) of unconsolidated affiliates: | | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Citrus | $ | 144 |
| | $ | 102 |
| | $ | 97 |
| FEP | 53 |
| | 51 |
| | 55 |
| MEP | 38 |
| | 40 |
| | 45 |
| HPC(1) | (168 | ) | | 31 |
| | 32 |
| Sunoco, LLC | — |
| | — |
| | (10 | ) | Sunoco LP(2) | 12 |
| | (211 | ) | | 202 |
| Other | 77 |
| | 46 |
| | 48 |
| Total equity in earnings of unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
|
| | (1) | For the year ended December 31, 2017, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by HPC, which reduced the Partnership’s equity in earnings by $185 million. |
| | (2) | For the years ended December 31, 2017 and 2016, equity in earnings (losses) of unconsolidated affiliates includes the impact of non-cash impairments recorded by Sunoco LP, which reduced the Partnership’s equity in earnings by $176 million and $277 million, respectively. |
Summarized Financial Information The following tables present aggregated selected balance sheet and income statement data for our unconsolidated affiliates, AmeriGas, Citrus, FEP, MEP, HPC MEP and Sunoco LP (on a 100% basis) for all periods presented: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Current assets | $ | 2,109 |
| | $ | 1,646 |
| $ | 4,750 |
| | $ | 1,532 |
| Property, plant and equipment, net | 13,355 |
| | 12,611 |
| 9,893 |
| | 10,310 |
| Other assets | 6,557 |
| | 5,485 |
| 2,286 |
| | 5,980 |
| Total assets | $ | 22,021 |
| | $ | 19,742 |
| $ | 16,929 |
| | $ | 17,822 |
| | | | | | | | Current liabilities | $ | 2,547 |
| | $ | 1,517 |
| $ | 2,075 |
| | $ | 1,918 |
| Non-current liabilities | 12,899 |
| | 10,428 |
| 9,375 |
| | 10,343 |
| Equity | 6,575 |
| | 7,797 |
| 5,479 |
| | 5,561 |
| Total liabilities and equity | $ | 22,021 |
| | $ | 19,742 |
| $ | 16,929 |
| | $ | 17,822 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Revenue | $ | 19,207 |
| | $ | 20,961 |
| | $ | 4,925 |
| $ | 13,081 |
| | $ | 11,150 |
| | $ | 13,815 |
| Operating income | 933 |
| | 1,620 |
| | 1,071 |
| 636 |
| | 859 |
| | 1,052 |
| Net income | 196 |
| | 894 |
| | 577 |
| | Net income (loss) | | 294 |
| | (22 | ) | | 664 |
|
In addition to the equity method investments described above we have other equity method investments which are not significant to our consolidated financial statements.
| | 5. | NET INCOME (LOSS) PER LIMITED PARTNER UNIT: |
The following table provides a reconciliation of the numerator and denominator of the basic and diluted income (loss) per unit. The historical common units and net income (loss) per limited partner unit amounts presented in these consolidated financial statements have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. | | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Income from continuing operations | $ | 624 |
| | $ | 1,521 |
| | $ | 1,235 |
| Less: Income from continuing operations attributable to noncontrolling interest | 327 |
| | 157 |
| | 116 |
| Less: Loss from continuing operations attributable to predecessor | — |
| | (34 | ) | | (153 | ) | Income from continuing operations, net of noncontrolling interest | 297 |
| | 1,398 |
| | 1,272 |
| General Partner’s interest in income from continuing operations | 948 |
| | 1,064 |
| | 513 |
| Class H Unitholder’s interest in income from continuing operations | 351 |
| | 258 |
| | 217 |
| Class I Unitholder’s interest in income from continuing operations | 8 |
| | 94 |
| | — |
| Common Unitholders’ interest in income (loss) from continuing operations | (1,010 | ) | | (18 | ) | | 542 |
| Additional earnings allocated to General Partner | (10 | ) | | (5 | ) | | (4 | ) | Distributions on employee unit awards, net of allocation to General Partner | (19 | ) | | (16 | ) | | (13 | ) | Income (loss) from continuing operations available to Common Unitholders | $ | (1,039 | ) | | $ | (39 | ) | | $ | 525 |
| Weighted average Common Units – basic | 505.5 |
| | 432.8 |
| | 331.5 |
| Basic income (loss) from continuing operations per Common Unit | $ | (2.06 | ) | | $ | (0.09 | ) | | $ | 1.58 |
| | | | | | | Income (loss) from continuing operations available to Common Unitholders | $ | (1,039 | ) | | $ | (39 | ) | | $ | 525 |
| Loss attributable to ETP Series A Preferred Units | — |
| | (6 | ) | | — |
| | $ | (1,039 | ) | | $ | (45 | ) | | $ | 525 |
| Weighted average Common Units – basic | 505.5 |
| | 432.8 |
| | 331.5 |
| Dilutive effect of unvested Unit Awards | — |
| | — |
| | 1.3 |
| Dilutive effect of Preferred Units | — |
| | 0.7 |
| | — |
| Weighted average Common Units – diluted | 505.5 |
| | 433.5 |
| | 332.8 |
| Diluted income (loss) from continuing operations per Common Unit | $ | (2.06 | ) | | $ | (0.10 | ) | | $ | 1.58 |
| Basic income from discontinued operations per Common Unit | $ | — |
| | $ | — |
| | $ | 0.19 |
| Diluted income from discontinued operations per Common Unit | $ | — |
| | $ | — |
| | $ | 0.19 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Net income | $ | 2,501 |
| | $ | 583 |
| | $ | 1,489 |
| Less: Income attributable to noncontrolling interest | 420 |
| | 295 |
| | 134 |
| Less: Loss attributable to predecessor | — |
| | — |
| | (34 | ) | Net income, net of noncontrolling interest | 2,081 |
| | 288 |
| | 1,389 |
| General Partner’s interest in net income | 990 |
| | 948 |
| | 1,064 |
| Preferred Unitholders’ interest in net income | 12 |
| | — |
| | — |
| Class H Unitholder’s interest in net income | 93 |
| | 351 |
| | 258 |
| Class I Unitholder’s interest in net income | — |
| | 8 |
| | 94 |
| Common Unitholders’ interest in net income (loss) | 986 |
| | (1,019 | ) | | (27 | ) | Additional earnings allocated from (to) General Partner | 9 |
| | (10 | ) | | (5 | ) | Distributions on employee unit awards, net of allocation to General Partner | (27 | ) | | (19 | ) | | (16 | ) | Net income (loss) available to Common Unitholders | $ | 968 |
| | $ | (1,048 | ) | | $ | (48 | ) | Weighted average Common Units – basic | 1,032.7 |
| | 758.2 |
| | 649.2 |
| Basic net income (loss) per Common Unit | $ | 0.94 |
| | $ | (1.38 | ) | | $ | (0.07 | ) | | | | | | | Income (loss) available to Common Unitholders | $ | 968 |
| | $ | (1,048 | ) | | $ | (48 | ) | Loss attributable to Legacy ETP Preferred Units | — |
| | — |
| | (6 | ) | Diluted income (loss) available to Common Unitholders | $ | 968 |
| | $ | (1,048 | ) | | $ | (54 | ) | Weighted average Common Units – basic | 1,032.7 |
| | 758.2 |
| | 649.2 |
| Dilutive effect of unvested Unit Awards | 5.1 |
| | — |
| | — |
| Dilutive effect of Legacy ETP Preferred Units | — |
| | — |
| | 1.0 |
| Weighted average Common Units – diluted | 1,037.8 |
| | 758.2 |
| | 650.2 |
| Diluted income (loss) per Common Unit | $ | 0.93 |
| | $ | (1.38 | ) | | $ | (0.08 | ) |
Our debt obligations consist of the following: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | ETP Debt | | | | | | | 6.125% Senior Notes due February 15, 2017 | $ | 400 |
| | $ | 400 |
| $ | — |
| | $ | 400 |
| 2.50% Senior Notes due June 15, 2018(1) | 650 |
| | 650 |
| 650 |
| | 650 |
| 6.70% Senior Notes due July 1, 2018(1) | 600 |
| | 600 |
| 600 |
| | 600 |
| 9.70% Senior Notes due March 15, 2019 | 400 |
| | 400 |
| 400 |
| | 400 |
| 9.00% Senior Notes due April 15, 2019 | | 450 |
| | 450 |
| 5.50% Senior Notes due February 15, 2020 | | 250 |
| | 250 |
| 5.75% Senior Notes due September 1, 2020 | | 400 |
| | 400 |
|
| | 9.00% Senior Notes due April 15, 2019 | 450 |
| | 450 |
| | 5.75% Senior Notes due September 1, 2020 | 400 |
| | 400 |
| | 4.15% Senior Notes due October 1, 2020 | 1,050 |
| | 1,050 |
| 1,050 |
| | 1,050 |
| 4.40% Senior Notes due April 1, 2021 | | 600 |
| | 600 |
| 6.50% Senior Notes due July 15, 2021 | 500 |
| | 500 |
| — |
| | 500 |
| 4.65% Senior Notes due June 1, 2021 | 800 |
| | 800 |
| 800 |
| | 800 |
| 5.20% Senior Notes due February 1, 2022 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 4.65% Senior Notes due February 15, 2022 | | 300 |
| | 300 |
| 5.875% Senior Notes due March 1, 2022 | 900 |
| | 900 |
| 900 |
| | 900 |
| 5.00% Senior Notes due October 1, 2022 | 700 |
| | 700 |
| 700 |
| | 700 |
| 3.45% Senior Notes due January 15, 2023 | | 350 |
| | 350 |
| 3.60% Senior Notes due February 1, 2023 | 800 |
| | 800 |
| 800 |
| | 800 |
| 5.50% Senior Notes due April 15, 2023 | 700 |
| | 700 |
| — |
| | 700 |
| 4.50% Senior Notes due November 1, 2023 | 600 |
| | 600 |
| 600 |
| | 600 |
| 4.90% Senior Notes due February 1, 2024 | 350 |
| | 350 |
| 350 |
| | 350 |
| 7.60% Senior Notes due February 1, 2024 | 277 |
| | 277 |
| 277 |
| | 277 |
| 4.25% Senior Notes due April 1, 2024 | | 500 |
| | 500 |
| 9.00% Debentures due November 1, 2024 | | 65 |
| | 65 |
| 4.05% Senior Notes due March 15, 2025 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 5.95% Senior Notes due December 1, 2025 | | 400 |
| | 400 |
| 4.75% Senior Notes due January 15, 2026 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 3.90% Senior Notes due July 15, 2026 | | 550 |
| | 550 |
| 4.20% Senior Notes due April 15, 2027 | | 600 |
| | — |
| 4.00% Senior Notes due October 1, 2027 | | 750 |
| | — |
| 8.25% Senior Notes due November 15, 2029 | 267 |
| | 267 |
| 267 |
| | 267 |
| 4.90% Senior Notes due March 15, 2035 | 500 |
| | 500 |
| 500 |
| | 500 |
| 6.625% Senior Notes due October 15, 2036 | 400 |
| | 400 |
| 400 |
| | 400 |
| 7.50% Senior Notes due July 1, 2038 | 550 |
| | 550 |
| 550 |
| | 550 |
| 6.85% Senior Notes due February 15, 2040 | | 250 |
| | 250 |
| 6.05% Senior Notes due June 1, 2041 | 700 |
| | 700 |
| 700 |
| | 700 |
| 6.50% Senior Notes due February 1, 2042 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 6.10% Senior Notes due February 15, 2042 | | 300 |
| | 300 |
| 4.95% Senior Notes due January 15, 2043 | | 350 |
| | 350 |
| 5.15% Senior Notes due February 1, 2043 | 450 |
| | 450 |
| 450 |
| | 450 |
| 5.95% Senior Notes due October 1, 2043 | 450 |
| | 450 |
| 450 |
| | 450 |
| 5.30% Senior Notes due April 1, 2044 | | 700 |
| | 700 |
| 5.15% Senior Notes due March 15, 2045 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 5.35% Senior Notes due May 15, 2045 | | 800 |
| | 800 |
| 6.125% Senior Notes due December 15, 2045 | 1,000 |
| | 1,000 |
| 1,000 |
| | 1,000 |
| 5.30% Senior Notes due April 15, 2047 | | 900 |
| | — |
| 5.40% Senior Notes due October 1, 2047 | | 1,500 |
| | — |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 546 |
| | 545 |
| 546 |
| | 546 |
| ETP $3.75 billion Revolving Credit Facility due November 2019 | 2,777 |
| | 1,362 |
| | ETP $4.0 billion Revolving Credit Facility due December 2022 | | 2,292 |
| | — |
| ETP $1.0 billion 364-Day Credit Facility due November 2018 (2) | | 50 |
| | — |
| ETLP $3.75 billion Revolving Credit Facility due November 2019 | | — |
| | 2,777 |
| Legacy Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | | — |
| | 1,292 |
| Legacy Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017 | | — |
| | 630 |
| Unamortized premiums, discounts and fair value adjustments, net | (18 | ) | | (21 | ) | 33 |
| | 66 |
| Deferred debt issuance costs | (132 | ) | | (147 | ) | (170 | ) | | (166 | ) | | 22,067 |
| | 20,633 |
| 29,210 |
| | 29,454 |
| Transwestern Debt | | | | | | | 5.54% Senior Notes due November 17, 2016 | — |
| | 125 |
| | 5.64% Senior Notes due May 24, 2017 | 82 |
| | 82 |
| — |
| | 82 |
| 5.36% Senior Notes due December 9, 2020 | 175 |
| | 175 |
| 175 |
| | 175 |
| 5.89% Senior Notes due May 24, 2022 | 150 |
| | 150 |
| 150 |
| | 150 |
| 5.66% Senior Notes due December 9, 2024 | 175 |
| | 175 |
| 175 |
| | 175 |
| 6.16% Senior Notes due May 24, 2037 | 75 |
| | 75 |
| 75 |
| | 75 |
| Unamortized premiums, discounts and fair value adjustments, net | — |
| | (1 | ) | | Deferred debt issuance costs | (1 | ) | | (2 | ) | (1 | ) | | (1 | ) | | 656 |
| | 779 |
| 574 |
| | 656 |
| Panhandle Debt | | | | | | | 6.20% Senior Notes due November 1, 2017 | 300 |
| | 300 |
| — |
| | 300 |
| 7.00% Senior Notes due June 15, 2018 | 400 |
| | 400 |
| | 8.125% Senior Notes due June 1, 2019 | 150 |
| | 150 |
| | 7.60% Senior Notes due February 1, 2024 | 82 |
| | 82 |
| | 7.00% Senior Notes due July 15, 2029 | 66 |
| | 66 |
| | 8.25% Senior Notes due November 15, 2029 | 33 |
| | 33 |
| | Floating Rate Junior Subordinated Notes due November 1, 2066 | 54 |
| | 54 |
| | Unamortized premiums, discounts and fair value adjustments, net | 50 |
| | 75 |
| | | 1,135 |
| | 1,160 |
| |
| | | | | | | | | Sunoco, Inc. Debt | | | | 5.75% Senior Notes due January 15, 2017 | 400 |
| | 400 |
| 9.00% Debentures due November 1, 2024 | 65 |
| | 65 |
| Unamortized premiums, discounts and fair value adjustments, net | 9 |
| | 20 |
| | 474 |
| | 485 |
| Sunoco Logistics Debt | | | | 6.125% Senior Notes due May 15, 2016 | — |
| | 175 |
| 5.50% Senior Notes due February 15, 2020 | 250 |
| | 250 |
| 4.40% Senior Notes due April 1, 2021 | 600 |
| | 600 |
| 4.65% Senior Notes due February 15, 2022 | 300 |
| | 300 |
| 3.45% Senior Notes due January 15, 2023 | 350 |
| | 350 |
| 4.25% Senior Notes due April 1, 2024 | 500 |
| | 500 |
| 5.95% Senior Notes due December 1, 2025 | 400 |
| | 400 |
| 3.90% Senior Notes due July 15, 2026 | 550 |
| | — |
| 6.85% Senior Notes due February 15, 2040 | 250 |
| | 250 |
| 6.10% Senior Notes due February 15, 2042 | 300 |
| | 300 |
| 4.95% Senior Notes due January 15, 2043 | 350 |
| | 350 |
| 5.30% Senior Notes due April 1, 2044 | 700 |
| | 700 |
| 5.35% Senior Notes due May 15, 2045 | 800 |
| | 800 |
| Sunoco Logistics $2.50 billion Revolving Credit Facility due March 2020 | 1,292 |
| | 562 |
| Sunoco Logistics $1.0 billion 364-Day Credit Facility due December 2017(1) | 630 |
| | — |
| Unamortized premiums, discounts and fair value adjustments, net | 75 |
| | 85 |
| Deferred debt issuance costs | (34 | ) | | (32 | ) | | 7,313 |
| | 5,590 |
| Bakken Project Debt | | | | Bakken Project $2.50 billion Credit Facility due August 2019 | 1,100 |
| | — |
| Deferred debt issuance costs | (13 | ) | | — |
| | 1,087 |
| | — |
| PennTex Debt | | | | PennTex $275 million Revolving Credit Facility due December 2019 | 168 |
| | — |
| | | | | Other | 30 |
| | 32 |
| | 32,930 |
| | 28,679 |
| Less: current maturities | 1,189 |
| | 126 |
| | $ | 31,741 |
| | $ | 28,553 |
|
| | | | | | | | | 7.00% Senior Notes due June 15, 2018 | 400 |
| | 400 |
| 8.125% Senior Notes due June 1, 2019 | 150 |
| | 150 |
| 7.60% Senior Notes due February 1, 2024 | 82 |
| | 82 |
| 7.00% Senior Notes due July 15, 2029 | 66 |
| | 66 |
| 8.25% Senior Notes due November 15, 2029 | 33 |
| | 33 |
| Floating Rate Junior Subordinated Notes due November 1, 2066 | 54 |
| | 54 |
| Unamortized premiums, discounts and fair value adjustments, net | 28 |
| | 50 |
| | 813 |
| | 1,135 |
| Sunoco, Inc. Debt | | | | 5.75% Senior Notes due January 15, 2017 | — |
| | 400 |
| | | | | Bakken Project Debt | | | | Bakken Project $2.50 billion Credit Facility due August 2019 | 2,500 |
| | 1,100 |
| Deferred debt issuance costs | (8 | ) | | (13 | ) | | 2,492 |
| | 1,087 |
| PennTex Debt | | | | PennTex $275 million Revolving Credit Facility due December 2019 | — |
| | 168 |
| | | | | Other | 5 |
| | 30 |
| | 33,094 |
| | 32,930 |
| Less: Current maturities of long-term debt | 407 |
| | 1,189 |
| | $ | 32,687 |
| | $ | 31,741 |
|
| | (1) | Sunoco Logistics’ $1.0 billion 364-Day Credit Facility, including its $630As of December 31, 2017 management had the intent and ability to refinance the $650 million term loan,2.50% senior notes due June 15, 2018 and the $600 million 6.70% senior notes due July 1, 2018, and therefore neither was classified as current. |
| | (2) | Borrowings under 364-day credit facilities were classified as long-term debt as of December 31, 2016 as Sunoco Logistics hasbased on the Partnership’s ability and intent to refinance such borrowings on a long-term basis. |
The following table reflects future maturities of long-term debt for each of the next five years and thereafter. These amounts exclude $64$118 million in unamortized net premiums, fair value adjustments and deferred debt issuance costs: | | 2017 | | $ | 1,812 |
| | 2018 | | 1,650 |
| | $ | 1,700 |
| 2019 | | 5,045 |
| | 3,500 |
| 2020 | | 3,167 |
| | 1,875 |
| 2021 | | 1,900 |
| | 1,400 |
| 2022 | | | 5,346 |
| Thereafter | | 19,420 |
| | 19,391 |
| Total | | $ | 32,994 |
| | $ | 33,212 |
|
Long-term debt reflected on our consolidated balance sheets includes fair value adjustments related to interest rate swaps, which represent fair value adjustments that had been recorded in connection with fair value hedge accounting prior to the termination of the interest rate swap. ETP as Co-Obligor of Sunoco, Inc. Debt In connection with the Sunoco Merger and ETP Holdco Transaction, ETP became a co-obligor on approximately $965 million of aggregate principal amount of Sunoco, Inc.’s existing senior notes and debentures. The balance of these notes was $465 million as of December 31, 2016, and $400 million matured and was repaid in January 2017.
ETP Senior Notes Offerings
In January 2017, ETP issued $600 million aggregate principal amount of 4.20% senior notes due April 2027 and $900 million aggregate principal amount of 5.30% senior notes due April 2047. ETP used the $1.48 billion net proceeds from the offering to refinance current maturities and to repay borrowings outstanding under the ETP Credit Facility.
The ETP senior notes were registered under the Securities Act of 1933 (as amended). The Partnership may redeem some or all of the ETP senior notes at any time, or from time to time, pursuant to the terms of the indenture and related indenture supplements related to the ETP senior notes. The balance is payable upon maturity. Interest on the ETP senior notes is paid semi-annually. The ETP senior notes are unsecured obligations of the Partnership and the obligation of the Partnership to repay the ETP senior notes is not guaranteed by any of the Partnership’s subsidiaries. Asas a result, the ETP senior notes effectively rank junior to any future indebtedness of ours or our subsidiaries that is both secured and unsubordinated to the extent of the value of the assets securing such indebtedness, and the ETP senior notes effectively rank junior to all indebtedness and other liabilities of our existing and future subsidiaries.
Transwestern Senior Notes The Transwestern senior notes are redeemable at any time in whole or pro rata, subject to a premium or upon a change of control event or an event of default, as defined. The balance is payable upon maturity. Interest is paid semi-annually. Panhandle Junior Subordinated Notes The interest rate on the remaining portion of Panhandle’s junior subordinated notes due 2066 is a variable rate based upon the three-month LIBOR rate plus 3.0175%. The balance of the variable rate portion of the junior subordinated notes was $54 million at an effective interest rate of 3.77%4.39% at December 31, 2016.2017. Sunoco Logistics Senior Notes Offerings
In July 2016, Sunoco Logistics issued $550 million aggregate principal amount of 3.90% senior notes due in July 2026. The net proceeds from this offering were used to repay outstanding credit facility borrowings and for general partnership purposes.
Credit Facilities and Commercial Paper ETP Credit FacilityFacilities The ETP Credit Facility allows for borrowings of up to $3.75On December 1, 2017 the Partnership entered into a five-year, $4.0 billion unsecured revolving credit facility, which matures December 1, 2022 (the “ETP Five-Year Facility”) and a $1.0 billion 364-day revolving credit facility that matures on November 18, 2019.30, 2018 (the “ETP 364-Day Facility”) (collectively, the “ETP Credit Facilities”). The indebtednessETP Five-Year Facility contains an accordion feature, under which the ETP Credit Facility is unsecured, is not guaranteed by any of the Partnership’s subsidiaries and has equal rightstotal aggregate commitments may be increased up to holders of our current and future unsecured debt. The indebtedness$6.0 billion under the ETP Credit Facility has the same priority of payment as our other current and future unsecured debt.certain conditions. We use the ETP Credit FacilityFacilities to provide temporary financing for our growth projects, as well as for general partnership purposes.
As of December 31, 2016,2017, the ETP CreditFive-Year Facility had $2.78$2.29 billion outstanding, and theof which $2.01 billion was commercial paper. The amount available for future borrowings was $813 million$1.56 billion after taking into account letters of credit of $160 million and commercial paper of $777$150 million. The weighted average interest rate on the total amount outstanding as of December 31, 20162017 was 2.20%2.48%. Sunoco Logistics Credit Facilities
Sunoco Logistics maintains a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”), which matures in March 2020. The Sunoco Logistics Credit Facility contains an accordion feature, under which the total aggregate commitment may be increased to $3.25 billion under certain conditions.
The Sunoco Logistics Credit Facility is available to fund Sunoco Logistics’ working capital requirements, to finance acquisitions and capital projects, to pay distributions and for general partnership purposes. The Sunoco Logistics Credit Facility bears interest at LIBOR or the Base Rate, based on Sunoco Logistics’ election for each interest period, plus an applicable margin. The credit facility may be prepaid at any time. As of December 31, 2016,2017, the Sunoco Logistics CreditETP 364-Day Facility had $1.29 billion of$50 million outstanding, and the amount available for future borrowings which included commercial paper of $50was $950 million. The weighted average interest rate on the total amount outstanding as of December 31, 20162017 was 1.76%5.00%.
ETLP Credit Facility The ETLP Credit Facility allowed for borrowings of up to $3.75 billion and was used to provide temporary financing for our growth projects, as well as for general partnership purposes. This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017. Sunoco Logistics Credit Facilities ETP maintained a $2.50 billion unsecured revolving credit agreement (the “Sunoco Logistics Credit Facility”). This facility was repaid and terminated concurrent with the establishment of the ETP Credit Facilities on December 1, 2017. In December 2016, Sunoco Logistics entered into an agreement for a 364-day maturity credit facility ("(“364-Day Credit Facility"Facility”), due to mature on the earlier of the occurrence of the Sunoco Logistics Merger or in December 2017, with a total lending capacity of $1.00 billion, including a $630 million term loan. The terms ofbillion. In connection with the Sunoco Logistics Merger, the 364-Day Credit Facility are similar to those of the $2.50 billion Sunoco Logistics Credit Facility, including limitations on the creation of indebtedness, liens and financial covenants. The 364-Day Credit Facility is expected to bewas terminated and repaid in connection with the completion of the ETP and Sunoco Logistics merger.May 2017. Bakken Credit Facility In August 2016, ETP,Energy Transfer Partners, L.P., Sunoco Logistics and Phillips 66 announced the completion of thecompleted project-level financing of the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the “Bakken Pipeline”).Bakken Pipeline. The $2.50 billion credit facility is anticipated to provide substantially all of the remaining capital necessary to complete the projects and matures in August 2019 (the “Bakken Credit Facility”). As of December 31, 2016,2017, the Bakken Credit Facility had $1.10$2.50 billion of outstanding borrowings. The weighted average interest rate on the total amount outstanding as of December 31, 20162017 was 2.13%3.00%. PennTex Revolving Credit Facility On December 19, 2014, PennTex entered intopreviously maintained a senior secured$275 million revolving credit facility with Royal Bank of Canada, as administrative agent, and a syndicate of lenders that became effective upon the closing of PennTex’s initial public offering and matures in December 2019commitment (the “PennTex Revolving Credit Facility”). The agreement provides for a $275 million commitment that is expandable up to $400 million under certain conditions. The funds have been used for general purposes, including the funding of capital expenditures. PennTex’s assets have been pledged as collateral for this credit facility.
As of December 31, 2016, PennTex had $106 million of available borrowing capacity underIn August 2017, the PennTex Revolving Credit Facility. As of December 31, 2016, the weighted average interest rate on outstanding borrowingsFacility was 2.90%.repaid and terminated.
Covenants Related to Our Credit Agreements Covenants Related to ETP The agreements relating to the ETP senior notes contain restrictive covenants customary for an issuer with an investment-grade rating from the rating agencies, which covenants include limitations on liens and a restriction on sale-leaseback transactions. The ETP Credit FacilityFacilities contains covenants that limit (subject to certain exceptions) the Partnership’s and certain of the Partnership’s subsidiaries’ ability to, among other things: make certain investments; make Distributions (as defined in the ETP Credit Facility)Facilities) during certain Defaults (as defined in the ETP Credit Facility)Facilities) and during any Event of Default (as defined in the ETP Credit Facility)Facilities); engage in business substantially different in nature than the business currently conducted by the Partnership and its subsidiaries; engage in transactions with affiliates; and enter into restrictive agreements. The ETP Credit Facilities applicable margin and rate used in connection with the interest rates and commitment fees, respectively, are based on the credit ratings assigned to our senior, unsecured, non-credit enhanced long-term debt. The applicable margin for eurodollar rate loans under the ETP Five-Year Facility ranges from 1.125% to 2.000% and the applicable margin for base rate loans ranges from 0.125% to 1.000%. The applicable rate for commitment fees under the ETP Five-Year Facility ranges from 0.125% to 0.300%. The applicable margin for eurodollar rate loans under the ETP 364-Day Facility ranges from 1.125% to 1.750% and the applicable margin for base rate loans ranges from 0.250% to 0.750%. The applicable rate for commitment fees under the ETP 364-Day Facility ranges from 0.125% to 0.225%.
The credit agreement relatingETP Credit Facilities contain various covenants including limitations on the creation of indebtedness and liens, and related to the operation and conduct of our business. The ETP Credit FacilityFacilities also containslimit us, on a financial covenant that provides that the Leverage Ratio,rolling four quarter basis, to a maximum Consolidated Funded Indebtedness to Consolidated EBITDA ratio, as defined in the ETP Credit Facility, shall not exceedunderlying credit agreements, of 5.0 to 1, as of the end of each quarter, with a permitted increasewhich can generally be increased to 5.5 to 1 during a Specified Acquisition Period,Period. Our Leverage Ratio was 3.96 to 1 at December 31, 2017, as definedcalculated in accordance with the ETP Credit Facility.credit agreements. The agreements relating to the Transwestern senior notes contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and specify a maximum debt to capitalization ratio. Failure to comply with the various restrictive and affirmative covenants of our revolving credit facilities could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Companies’ ability to incur additional debt and/or our ability to pay distributions. Covenants Related to Panhandle Panhandle is not party to any lending agreement that would accelerate the maturity date of any obligation due to a failure to maintain any specific credit rating, nor would a reduction in any credit rating, by itself, cause an event of default under any of Panhandle’s lending agreements. Financial covenants exist in certain of Panhandle’s debt agreements that require Panhandle to maintain a certain level of net worth, to meet certain debt to total capitalization ratios and to meet certain ratios of earnings before depreciation, interest and taxes to cash interest expense. A failure by Panhandle to satisfy any such covenant would give rise to an event of default under the associated debt, which could become immediately due and payable if Panhandle did not cure such default within any permitted cure period or if Panhandle did not obtain amendments, consents or waivers from its lenders with respect to such covenants. Panhandle’s restrictive covenants include restrictions on debt levels, restrictions on liens securing debt and guarantees, restrictions on mergers and on the sales of assets, capitalization requirements, dividend restrictions, cross default and cross-accelerationcross-
acceleration and prepayment of debt provisions. A breach of any of these covenants could result in acceleration of Panhandle’s debt and other financial obligations and that of its subsidiaries. In addition, Panhandle and/or its subsidiaries are subject to certain additional restrictions and covenants. These restrictions and covenants include limitations on additional debt at some of its subsidiaries; limitations on the use of proceeds from borrowing at some of its subsidiaries; limitations, in some cases, on transactions with its affiliates; limitations on the incurrence of liens; potential limitations on the abilities of some of its subsidiaries to declare and pay dividends and potential limitations on some of its subsidiaries to participate in Panhandle’s cash management program; and limitations on Panhandle’s ability to prepay debt. Covenants Related to Sunoco Logistics The Sunoco Logistics Credit Facility contains various covenants, including limitations on the creation of indebtedness and liens, and other covenants related to the operation and conduct of the business of Sunoco Logistics and its subsidiaries. The Sunoco Logistics Credit Facility also limits Sunoco Logistics, on a rolling four-quarter basis, to a maximum total Consolidated Funded Indebtedness to Consolidated EBITDA ratio, each as defined in the Sunoco Logistics Credit Facility, of 5.0 to 1, which can generally be increased to 5.5 to 1 during an acquisition period. Sunoco Logistics’ ratio of total Consolidated Funded Indebtedness, excluding net unamortized fair value adjustments, to Consolidated EBITDA was 4.4 to 1 at December 31, 2016, as calculated in accordance with the credit agreements.
Covenants Related to Bakken Credit Facility
The Bakken Credit Facility contains standard and customary covenants for a financing of this type, subject to materiality, knowledge and other qualifications, thresholds, reasonableness and other exceptions. These standard and customary covenants include, but are not limited to: prohibition of certain incremental secured indebtedness; prohibition of certain liens / negative pledge; limitations on uses of loan proceeds; limitations on asset sales and purchases; limitations on permitted business activities; limitations on mergers and acquisitions; limitations on investments;
limitations on transactions with affiliates; and maintenance of commercially reasonable insurance coverage. A restricted payment covenant is also included in the Bakken Credit Facility which requires a minimum historic debt service coverage ratio (“DSCR”) of not less than 1.20 to 1 (the “Minimum Historic DSCR”) with respect each 12-month period following the commercial in-service date of the Dakota Access and ETCO Project in order to make certain restricted payments thereunder. Covenants Related to PennTex
The PennTex Revolving Credit Facility contains various covenants and restrictive provisions that, among other things, limit or restrict PennTex’s ability to incur or guarantee additional debt, incur certain liens on assets, dispose of assets, make certain distributions (including distributions from available cash, if a default or event of default under the credit agreement then exists or would result from making such a distribution), change the nature of PennTex’s business, engage in certain mergers or make certain investments and acquisitions, enter into non-arm’s-length transactions with affiliates and designate certain subsidiaries of PennTex as “Unrestricted Subsidiaries” for purposes of the credit agreement. Currently, no subsidiaries have been designated as Unrestricted Subsidiaries. PennTex is required to comply with a minimum consolidated interest coverage ratio of 2.50x and a maximum consolidated leverage ratio of 4.75x under the PennTex Revolving Credit Facility.
The borrowed amounts accrue interest at a LIBOR rate or a base rate, based on PennTex’s election for each interest period, plus an applicable margin. The applicable margin used in connection with the interest rates and fees is based on the then applicable Consolidated Total Leverage Ratio (as defined therein). The applicable margin for LIBOR rate loans and letter of credit fees range from 2.00% and 3.25% based on the Consolidated Total Leverage Ratio and the applicable margin for ABR loans ranges from 1.00% to 2.25% based on the Consolidated Total Leverage Ratio. The unused portion of the credit facility is subject to a commitment fee, which is based on the Consolidated Total Leverage Ratio and ranges from 0.35% to 0.50% multiplied by the amount of the unused commitment.
Compliance with our Covenants We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of December 31, 2016.2017.
| | 7. | SERIES ALEGACY ETP PREFERRED UNITS: |
The Series ALegacy ETP Preferred Units arewere mandatorily redeemable on September 2, 2029 for $35 million plus all accrued but unpaid distributions and interest thereon and arewere reflected as long-term liabilities in our consolidated balance sheets. The Legacy ETP Preferred Units arewere entitled to a preferential quarterly cash distribution of $0.445 per Preferred Unit if outstanding on the record dates of the Partnership’s common unit distributions. Holders of the Preferred Units can elect to convert the ETP Preferred Units to ETP Common Units at any time in accordance with ETP’s partnership agreement. The number of common units issuable upon conversion of the Preferred Units is equal to the issue price of $18.30, plus all accrued but unpaid distributions and interest thereon, divided by the conversion price of $44.37. As of December 31, 2016, the Preferred Units were convertible into 0.9 million ETP Common Units. In January 2017, ETP repurchased all of its 1.9 million outstanding Series ALegacy ETP Preferred Units for cash in the aggregate amount of $53 million.
Limited Partner interests are represented by Common, Class E Units, Class G Units, Class HI Units, Class J Units and Class IK Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement. The Partnership’s outstanding securities also include preferred units, as described below. No person is entitled to preemptive rights in respect of issuances of equity securities by us, except that ETP GP has the right, in connection with the issuance of any equity security by us, to purchase equity securities on the same terms as equity securities are issued to third parties sufficient to enable ETP GP and its affiliates to maintain the aggregate percentage equity interest in us as ETP GP and its affiliates owned immediately prior to such issuance.
IDRs represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash (as defined in our Partnership Agreement) from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. ETP GP, a wholly-owned subsidiary of ETE, owns all of the IDRs.
Common Units The change in Common Units was as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 (1) | | 2016 (1) | | 2015 (1) | Number of Common Units, beginning of period | 505.6 |
| | 355.5 |
| | 333.8 |
| 794.8 |
| | 758.5 |
| | 533.4 |
| Common Units redeemed in connection with certain transactions | (17.8 | ) | | (51.8 | ) | | (18.7 | ) | — |
| | (26.7 | ) | | (77.8 | ) | Common Units issued in connection with public offerings | | 54.0 |
| | — |
| | — |
| Common Units issued in connection with certain acquisitions | 8.9 |
| | 172.2 |
| | 15.8 |
| — |
| | 13.3 |
| | 258.2 |
| Common Units issued in connection with the Distribution Reinvestment Plan | 6.6 |
| | 7.7 |
| | 2.8 |
| 12.0 |
| | 9.9 |
| | 11.7 |
| Common Units issued in connection with Equity Distribution Agreements | 26.1 |
| | 21.1 |
| | 21.4 |
| 22.6 |
| | 39.0 |
| | 31.7 |
| Common Units issued to ETE in a private placement transaction | | 23.7 |
| | — |
| | — |
| Common Unit increase from Sunoco Logistics Merger (2) | | 255.4 |
| | — |
| | — |
| Issuance of Common Units under equity incentive plans | 0.5 |
| | 0.9 |
| | 0.4 |
| 1.6 |
| | 0.8 |
| | 1.3 |
| Number of Common Units, end of period | 529.9 |
| | 505.6 |
| | 355.5 |
| 1,164.1 |
| | 794.8 |
| | 758.5 |
|
| | (1) | The historical common units presented have been retrospectively adjusted to reflect the 1.5 to one unit-for-unit exchange in connection with the Sunoco Logistics Merger. |
| | (2) | Represents the Sunoco Logistics common units outstanding at the close of the Sunoco Logistics Merger. See Note 1 for discussion on the accounting treatment of the Sunoco Logistics Merger. |
Our Common Units are registered under the Securities Exchange Act of 1934 (as amended) and are listed for trading on the NYSE. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.” Equity Distribution Program From time to time, we have sold Common Units through equity distribution agreements. Such sales of Common Units are made by means of ordinary brokers’ transactions on the NYSE at market prices, in block transactions or as otherwise agreed between us and the sales agent which is the counterparty to the equity distribution agreements. In July 2016,connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. equity distribution agreement was terminated. In May 2017, the Partnership entered into an equity distribution agreement with an aggregate offering price up to $1.50$1.00 billion. During the year ended December 31, 2016,2017, we issued 26.122.6 million units for $891$503 million, net of commissions of $8$5 million. As of December 31, 2016, $9362017, $752 million of our Common Units remained available to be issued under our currently effective equity distribution agreement. Equity Incentive Plan Activity We issue Common Units to employees and directors upon vesting of awards granted under our equity incentive plans. Upon vesting, participants in the equity incentive plans may elect to have a portion of the Common Units to which they are entitled withheld by the Partnership to satisfy tax-withholding obligations.
Distribution Reinvestment Program Our Distribution Reinvestment Plan (the “DRIP”) provides Unitholders of record and beneficial owners of our Common Units a voluntary means by which they can increase the number of ETP Common Units they own by reinvesting the quarterly cash distributions they would otherwise receive in the purchase of additional Common Units. In connection with the Sunoco Logistics Merger, the previous Energy Transfer Partners, L.P. distribution reinvestment plan was terminated. In July 2017, the Partnership initiated a new distribution reinvestment plan. During the years ended December 31, 2017, 2016 2015 and 2014,2015, aggregate distributions of $228 million, $216 million, $360 million, and $155$360 million, respectively, were reinvested under the DRIP resulting in the issuance in aggregate of 17.125.5 million Common Units. As of December 31, 2016,2017, a total of 4.920.8 million Common Units remain available to be issued under the existing registration statement. August 2017 Units Offering In August 2017, the Partnership issued 54 million ETP common units in an underwritten public offering. Net proceeds of $997 million from the offering were used by the Partnership to repay amounts outstanding under its revolving credit facilities, to fund capital expenditures and for general partnership purposes. January 2017 Private Placement In January 2017, the Partnership sold 15.823.7 million ETP Common Units to ETE in a private placement transaction for gross proceeds of approximately $568 million.
Class E Units There are currently 8.9 million Class E Units outstanding, all of which are currently owned by HHI. The Class E Units generally do not have any voting rights. The Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $1.41 per unit per year, with any excess thereof available for distribution to Unitholders other thanyear. As the holders of Class E Units in proportion to their respective interests. The Class E Units are treated as treasury units for accounting purposes because they are owned by a wholly-owned subsidiary, of ETP Holdco, Heritage Holdings, Inc.the cash distributions on those units are eliminated in our consolidated financial statements. Although no plans are currently in place, management may evaluate whether to retire some or all of the Class E Units at a future date. All of the 8.9 Class G Units There are currently 90.7 million Class EG Units outstanding, all of which are held by a wholly-owned subsidiary and are reported as treasury units. of the Partnership. The Class G Units In conjunction with the Sunoco Merger, we amended our partnership agreement to create Class F Units. The number of Class F Units issued was determined at the closing of the Sunoco Merger and equaled 90.7 million, which included 40 million Class F Units issued in exchange for cash contributed by Sunoco, Inc. to us immediately prior to or concurrent with the closing of the Sunoco Merger. The Class F Units generally diddo not have any voting rights. The Class FG Units wereare entitled to aggregate cash distributions equal to 35% of the total amount of cash generated by us and our subsidiaries, other than ETP Holdco, and available for distribution, up to a maximum of $3.75 per Class FG Unit per year. In April 2013, all of the outstanding Class F Units were exchanged for Class G Units on a one-for-one basis. The Class G Units have terms that are substantially the same as the Class F Units, with the principal difference between the Class G Units and the Class F Units being that allocationsAllocations of depreciation and amortization to the Class G Units for tax purposes are based on a predetermined percentage and are not contingent on whether ETP has net income or loss. These units are held by a subsidiary and therefore are reflected as treasury units in the consolidated financial statements.
Class H Units and Class I Units Currently Outstanding
Pursuant to an Exchange and Redemption Agreement previously entered into between ETP, ETE and ETE Holdings, ETP redeemed and cancelled 50.2 million of its Common Units representing limited partner interests (the “Redeemed Units”) owned by ETE Holdings on October 31, 2013 in exchange for the issuance by ETP to ETE Holdings of a new class of limited partner interest in ETP (the “Class H Units”), which arewere generally entitled to (i) allocations of profits, losses and other items from ETP corresponding to 90.05% of the profits, losses, and other items allocated to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners and (ii) distributions from available cash at ETP for each quarter equal to 90.05% of the cash distributed to ETP by Sunoco Partners with respect to the IDRs and general partner interest in Sunoco Logistics held by Sunoco Partners for such quarter and, to the extent not previously distributed to holders of the Class H Units, for any previous quarters. Bakken Pipeline Transactions
In March 2015, ETE transferred 30.8 million Partnership common units, ETE’s 45% interest in the Bakken Pipeline project, and $879 million in cash to the Partnership in exchange for 30.8 million newly issued The Class H Unitsunits were cancelled in connection with the merger of ETP that, when combined with the 50.2 million previously issued Class H Units, generally entitle ETE to receive 90.05% of the cash distributions and other economic attributes of the general partner interest and IDRs of Sunoco Logistics (the “Bakken Pipeline Transaction”). In connection with this transaction, the Partnership also issued to ETE 100 in April 2017.
Class I Units that provide distributions to ETE to offset IDR subsidies previously provided to ETP. These IDR subsidies, including the impact from distributions on Class I Units, were reduced by $55 million in 2015 and $30 million in 2016. In connection with the transaction,Bakken Pipeline Transaction discussed in Note 3, in April 2015, ETP issued 100 Class I Units. The Class I Units are generally entitled to: (i) pro rata allocations of gross income or gain until the aggregate amount of such items allocated to the holders of the Class I Units for the current taxable period and all previous taxable periods is equal to the
cumulative amount of all distributions made to the holders of the Class I Units and (ii) after making cash distributions to Class H Units, any additional available cash deemed to be either operating surplus or capital surplus with respect to any quarter will be distributed to the Class I Units in an amount equal to the excess of the distribution amount set forth in our Partnership Agreement, as amended, (the “Partnership Agreement”) for such quarter over the cumulative amount of available cash previously distributed commencing with the quarter endingended March 31, 2015 until the quarter ending December 31, 2016. The impact of (i) the IDR subsidy adjustments and (ii) the Class I Unit distributions, along with the currently effective IDR subsidies, is included in the table below under “Quarterly Distributions of Available Cash.” Subsequent to the April 2017 merger of ETP and Sunoco Logistics, 100 Class I Units remain outstanding.
Bakken Equity Sale On August 2, 2016,In February 2017, Bakken Holdings Company LLC, an entity in which ETP indirectly owns a 60%100% membership interest, and Sunoco Logistics indirectly owns a 40% membership interest, agreed to sellsold a 49% interest in its wholly-owned subsidiary, Bakken Pipeline Investments LLC, to MarEn Bakken Company LLC, an entity jointly owned by Marathon Petroleum CorporationMPLX LP and Enbridge Energy Partners, L.P., for $2.00 billion in cash. This transaction closed in February 2017. Bakken Pipeline Investments LLC indirectly owns a 75% interest in each of Dakota Access LLC (“Dakota Access”) and Energy Transfer Crude Oil Company, LLC (“ETCO”).ETCO. The remaining 25% of each of Dakota Access and ETCO is owned by wholly-owned subsidiaries of Phillips 66. ETP will continuecontinues to consolidate Dakota Access and ETCO subsequent to this transaction. Upon closing, ETP and Sunoco Logistics collectively own a 38.25% interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects (collectively, the "Bakken Pipeline"), and MarEn Bakken Company owns 36.75% and Phillips 66 owns 25.00% in the Bakken Pipeline.
Class K Units On December 29, 2016, the Partnership issued to certain of its indirect subsidiaries, in exchange for cash contributions and the exchange of outstanding common units representing limited partner interests in the Partnership, Class K Units, each of which is entitled to a quarterly cash distribution of $0.67275 per Class K Unit prior to ETP making distributions of available cash to any class of units, other than the Class H Units and the Class I Units, excluding any cash available distributions or dividends or capital stock sales proceeds received by ETP from ETP Holdco. If the Partnership is unable to pay the Class K Unit quarterly distribution with respect to any quarter, the accrued and unpaid distributions will accumulate until paid and any accumulated balance will accrue 1.5% per annum until paid. As of December 31, 2016,2017, a total of 101,525,429101.5 million Class K Units were held by indirectwholly-owned subsidiaries of ETP. Sales of Common Units by legacy Sunoco Logistics With respectPrior to our investment inthe Sunoco Logistics Merger, we accountaccounted for the difference between the carrying amount of our investment in Sunoco Logistics and the underlying book value arising from the issuance or redemption of units by the respective subsidiary (excluding transactions with us) as capital transactions.
As a result of Sunoco Logistics’ issuances of common units during the year ended December 31, 2016, we recognized increases in partners’ capital of $37 million.
In September and October 2016, a total of 24.2 million common units were issued for net proceeds of $644 million in connection with a public offering and related option exercise. The proceeds from this offering were used to partially fund the acquisition from Vitol. In March and April 2015, a total of 15.5 million common units were issued in connection with a public offering and related option exercise. Net proceeds of $629 million were used to repay outstanding borrowings under Sunoco Logistics’ $2.50 billion Credit Facility and for general partnership purposes. In September 2014, Sunoco Logistics completed an overnight public offering of 7.7 million common units for net proceeds of $362 million were used to repay outstanding borrowings under the Sunoco Logistics Credit Facility and for general partnership purposes. In 2014, Sunoco Logistics entered into equity distribution agreements pursuant to which Sunoco Logistics may sell from time to time common units having aggregate offering prices of up to $1.25 billion. In connection with the fourth quarter of 2015, the aggregate capacity was increased to $2.25 billion. During the year ended December 31, 2016, Sunoco Logistics received proceedsMerger, the previous Sunoco Logistics equity distribution agreement was terminated.
ETP Preferred Units In November 2017, ETP issued 950,000 of $744 million, netits 6.250% Series A Preferred Units at a price of commissions$1,000 per unit, and 550,000 of $8 million,its 6.625% Series B Preferred Units at a price of $1,000 per unit. Distributions on the Series A Preferred Units will accrue and be cumulative from and including the issuancedate of 29.1 millionoriginal issue to, but excluding, February 15, 2023, at a rate of 6.250% per annum of the stated liquidation preference of $1,000. On and after February 15, 2023, distributions on the Series A Preferred Units will accumulate at a percentage of the $1,000 liquidation preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.028% per annum. The Series A Preferred Units are redeemable at ETP’s option on or after February 15, 2023 at a redemption price of $1,000 per Series A Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. Distributions on the Series B Preferred Units will accrue and be cumulative from and including the date of original issue to, but excluding, February 15, 2028, at a rate of 6.625% per annum of the stated liquidation preference of $1,000. On and after February 15, 2028, distributions on the Series B Preferred Units will accumulate at a percentage of the $1,000 liquidation
preference equal to an annual floating rate of the three-month LIBOR, determined quarterly, plus a spread of 4.155% per annum. The Series B Preferred Units are redeemable at ETP’s option on or after February 15, 2028 at a redemption price of$1,000 per Series B Preferred Unit, plus an amount equal to all accumulated and unpaid distributions thereon to, but excluding, the date of redemption. PennTex Tender Offer and Limited Call Right Exercise In June 2017, ETP purchased all of the outstanding PennTex common units pursuant tonot previously owned by ETP for $20.00 per common unit in cash. ETP now owns all of the equity distribution agreement.economic interests of PennTex, and PennTex common units are no longer publicly traded or listed on the NASDAQ. Quarterly Distributions of Available Cash The Partnership Agreement requires that we distribute all of our Available Cash to our Unitholders and our General PartnerUnder the Partnership’s limited partnership agreement, within forty-five45 days followingafter the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of IDRs to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any of our fiscal quarters,Partnership distributes all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partnergeneral partner in its solediscretion. This is defined as “available cash” in the partnership agreement. The general partner has broad discretion to provide forestablish cash reserves that it determines are necessary or appropriate to properly conduct the proper conduct of our business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for futurePartnership’s business. The Partnership will make quarterly distributions to partners with respectthe extent there is sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to any one or morethe general partner.
If cash distributions exceed $0.0833 per unit in a quarter, the holders of the next four quarters. Available Cash is more fully defined in our Partnership Agreement. Our distributions of Available Cash from operating surplus, excluding incentive distributions,distribution rights receive increasing percentages, up to our General Partner and Limited Partner interests are based on their respective interests as48 percent, of the cash distributed in excess of that amount. These distributions are referred to as “incentive distributions.”
The following table shows the target distribution record date. Incentive distributionslevels and distribution “splits” between the general and limited partners and the holders of the Partnership’s incentive distribution rights (”IDRs”): allocated to our General Partner are determined | | | | | | | | | | | | Marginal Percentage Interest in Distributions | | | Total Quarterly Distribution Target Amount | | IDRs | | Partners (1) | Minimum Quarterly Distribution | | $0.0750 | | —% | | 100% | First Target Distribution | | up to $0.0833 | | —% | | 100% | Second Target Distribution | | above $0.0833 up to $0.0958 | | 13% | | 87% | Third Target Distribution | | above $0.0958 up to $0.2638 | | 35% | | 65% | Thereafter | | above $0.2638 | | 48% | | 52% |
(1) Includes general partner and limited partner interests, based on the amount by whichproportionate ownership of each. The percentage interests shown for the unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. Distributions on common Unitholders exceed certain specified target levels, as set forth in our Partnership Agreement. Distributionsunits declared and paid by ETP and Sunoco Logistics during the pre-merger periods presented were as follows:
| | Quarter Ended | | Record Date | | Payment Date | | Rate | | ETP | | Sunoco Logistics | December 31, 2013 | | February 7, 2014 | | February 14, 2014 | | $ | 0.9200 |
| | March 31, 2014 | | May 5, 2014 | | May 15, 2014 | | 0.9350 |
| | June 30, 2014 | | August 4, 2014 | | August 14, 2014 | | 0.9550 |
| | September 30, 2014 | | November 3, 2014 | | November 14, 2014 | | 0.9750 |
| | December 31, 2014 | | February 6, 2015 | | February 13, 2015 | | 0.9950 |
| | $ | 0.6633 |
| | $ | 0.4000 |
| March 31, 2015 | | May 8, 2015 | | May 15, 2015 | | 1.0150 |
| | 0.6767 |
| | 0.4190 |
| June 30, 2015 | | August 6, 2015 | | August 14, 2015 | | 1.0350 |
| | 0.6900 |
| | 0.4380 |
| September 30, 2015 | | November 5, 2015 | | November 16, 2015 | | 1.0550 |
| | 0.7033 |
| | 0.4580 |
| December 31, 2015 | | February 8, 2016 | | February 16, 2016 | | 1.0550 |
| | 0.7033 |
| | 0.4790 |
| March 31, 2016 | | May 6, 2016 | | May 16, 2016 | | 1.0550 |
| | 0.7033 |
| | 0.4890 |
| June 30, 2016 | | August 8, 2016 | | August 15, 2016 | | 1.0550 |
| | 0.7033 |
| | 0.5000 |
| September 30, 2016 | | November 7, 2016 | | November 14, 2016 | | 1.0550 |
| | 0.7033 |
| | 0.5100 |
| December 31, 2016 | | February 7, 2017 | | February 14, 2017 | | 1.0550 |
| | 0.7033 |
| | 0.5200 |
|
Distributions on common units declared and paid by Post-Merger ETP were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | March 31, 2017 | | May 10, 2017 | | May 16, 2017 | | $ | 0.5350 |
| June 30, 2017 | | August 7, 2017 | | August 15, 2017 | | 0.5500 |
| September 30, 2017 | | November 7, 2017 | | November 14, 2017 | | 0.5650 |
| December 31, 2017 | | February 8, 2018 | | February 14, 2018 | | 0.5650 |
|
In connection with previous transactions, ETE has agreed to relinquish its right to the following amounts of incentive distributions in future periods, including distributions on Class I Units:periods: | | | | Total Year | | Total Year | 2017 | | $ | 626 |
| | 2018 | | 138 |
| | $ | 153 |
| 2019 | | 128 |
| | 128 |
| Each year beyond 2019 | | 33 |
| | 33 |
|
Sunoco Logistics Quarterly Distributions of Available Cash
Distributions declared duringand paid by ETP to the periods presented were as follows: | | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | December 31, 2013 | | February 10, 2014 | | February 14, 2014 | | $ | 0.3312 |
| March 31, 2014 | | May 9, 2014 | | May 15, 2014 | | 0.3475 |
| June 30, 2014 | | August 8, 2014 | | August 14, 2014 | | 0.3650 |
| September 30, 2014 | | November 7, 2014 | | November 14, 2014 | | 0.3825 |
| December 31, 2014 | | February 9, 2015 | | February 13, 2015 | | 0.4000 |
| March 31, 2015 | | May 11, 2015 | | May 15, 2015 | | 0.4190 |
| June 30, 2015 | | August 10, 2015 | | August 14, 2015 | | 0.4380 |
| September 30, 2015 | | November 9, 2015 | | November 13, 2015 | | 0.4580 |
| December 31, 2015 | | February 8, 2016 | | February 12, 2016 | | 0.4790 |
| March 31, 2016 | | May 9, 2016 | | May 13, 2016 | | 0.4890 |
| June 30, 2016 | | August 8, 2016 | | August 12, 2016 | | 0.5000 |
| September 30, 2016 | | November 9, 2016 | | November 14, 2016 | | 0.5100 |
| December 31, 2016 | | February 7, 2017 | | February 14, 2017 | | 0.5200 |
|
PennTex Quarterly Distributions of Available Cash
PennTex is required by its partnership agreement to distribute a minimum quarterly distribution of $0.2750 per unit at the end of each quarter. Distributions declared during the periods presentedpreferred unitholders were as follows:
| | | | | | | | | | Quarter Ended | | Record Date | | Payment Date | | Rate | September 30, 2016 | | November 7, 2016 | | November 14, 2016 | | $ | 0.2950 |
| December 31, 2016 | | February 7, 2017 | | February 14, 2017 | | 0.2950 |
|
| | | | | | | | | | | | | | | Distribution per Preferred Unit | Quarter Ended | | Record Date | | Payment Date | | Series A | | Series B | December 31, 2017 | | February 1, 2018 | | February 15, 2018 | | $ | 15.451 |
| | $ | 16.378 |
|
Accumulated Other Comprehensive Income The following table presents the components of AOCI, net of tax: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Available-for-sale securities | $ | 2 |
| | $ | — |
| $ | 8 |
| | $ | 2 |
| Foreign currency translation adjustment | (5 | ) | | (4 | ) | (5 | ) | | (5 | ) | Actuarial gain related to pensions and other postretirement benefits | 7 |
| | 8 |
| (5 | ) | | 7 |
| Investments in unconsolidated affiliates, net | 4 |
| | — |
| 5 |
| | 4 |
| Total AOCI, net of tax | $ | 8 |
| | $ | 4 |
| $ | 3 |
| | $ | 8 |
|
The table below sets forth the tax amounts included in the respective components of other comprehensive income: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Available-for-sale securities | $ | (2 | ) | | $ | (2 | ) | $ | (2 | ) | | $ | (2 | ) | Foreign currency translation adjustment | 3 |
| | 4 |
| 3 |
| | 3 |
| Actuarial loss relating to pension and other postretirement benefits | — |
| | 7 |
| 3 |
| | — |
| Total | $ | 1 |
| | $ | 9 |
| $ | 4 |
| | $ | 1 |
|
| | 9. | UNIT-BASED COMPENSATION PLANS: |
ETP Unit-Based Compensation Plan We have issued equity incentive plans for employees, officers and directors, which provide for various types of awards, including options to purchase ETP Common Units, restricted units, phantom units, Common Units, distribution equivalent
rights (“DERs”), Common Unit appreciation rights, and other unit-based awards. As of December 31, 2016,2017, an aggregate total of 1.88.4 million ETP Common Units remain available to be awarded under our equity incentive plans. Restricted Units We have granted restricted unit awards to employees that vest over a specified time period, typically a five-year service vesting requirement, with vesting based on continued employment as of each applicable vesting date. Upon vesting, ETP Common Units are issued. These unit awards entitle the recipients of the unit awards to receive, with respect to each Common Unit subject to such award that has not either vested or been forfeited, a cash payment equal to each cash distribution per Common Unit made by us on our Common Units promptly following each such distribution by us to our Unitholders. We refer to these rights as “distribution equivalent rights.” Under our equity incentive plans, our non-employee directors each receive grants with a five-year service vesting requirement.
The following table shows the activity of the awards granted to employees and non-employee directors: | | | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Number of Units | | Weighted Average Grant-Date Fair Value Per Unit | Unvested awards as of December 31, 2015 | 4.8 |
| | $ | 47.61 |
| | Unvested awards as of December 31, 2016 | | 9.4 |
| | $ | 27.68 |
| Legacy Sunoco Logistics unvested awards as of December 31, 2016 | | 3.2 |
| | 28.57 |
| Awards granted | 2.5 |
| | 35.73 |
| 4.9 |
| | 17.69 |
| Awards vested | (0.8 | ) | | 53.22 |
| (2.3 | ) | | 34.22 |
| Awards forfeited | (0.2 | ) | | 48.39 |
| (1.1 | ) | | 25.03 |
| Unvested awards as of December 31, 2016 | 6.3 |
| | 41.53 |
| | Unvested awards as of December 31, 2017 | | 14.1 |
| | 23.18 |
|
During the years ended December 31, 2017, 2016, 2015, and 2014,2015, the weighted average grant-date fair value per unit award granted was $35.73, $35.21$17.69, $23.82 and $60.85,$23.47, respectively. The total fair value of awards vested was $28$40 million, $49$40 million and $26$57 million, respectively, based on the market price of ETP Common Units as of the vesting date. As of December 31, 2016,2017, a total of 6.314.1 million unit awards remain unvested, for which ETP expects to recognize a total of $179$189 million in compensation expense over a weighted average period of 2.12.7 years. Cash Restricted Units. The Partnership has alsopreviously granted cash restricted units, which vest 100% at the end of the third year of service. A cash restricted unit entitlesentitled the award recipient to receive cash equal to the market value of one ETP Common Unit upon vesting. As of December 31, 2016, a total of 0.2 million unvested The Partnership does not currently have any cash restricted units were outstanding.
Based on the trading price of ETP Common Units at December 31, 2016, the Partnership expects to recognize $3 million of unit-based compensation expense related to non-vested cash restricted units over a period of 1.0 year.
Sunoco Logistics Unit-Based Compensation Plan
Sunoco Logistics’ general partner has a long-term incentive plan for employees and directors, which permits the grant of restricted units, phantom unit awards, unit appreciation rights, unrestricted unit awards and other unit-based awards.
Restricted Units
Sunoco Logistics has granted restricted unit awards to employees and directors that entitle the grantees to receive Sunoco Logistics common units or, at the discretion of the Sunoco Logistics compensation committee, an amount of cash equivalent to the value of common units upon vesting. Sunoco Logistics’ outstanding restricted unit awards are time-vested grants, the vesting of which occurs over a five-year period, and is conditioned solely upon continued employment or service as of the applicable vesting date. These unit awards entitle the grantees of the unit awards to receive an amount of cash equal to the per unit cash distributions made by Sunoco Logistics during the period the restricted unit is outstanding.
The following table summarizes the activity of the Sunoco Logistics restricted unit awards:
| | | | | | | | | Number of Sunoco Logistics Units | | Weighted Average Grant-Date Fair Value Per Sunoco Logistics Unit | Unvested awards as of December 31, 2015 | 2.5 |
| | $ | 33.16 |
| Awards granted | 1.3 |
| | 23.21 |
| Awards vested | (0.5 | ) | | 34.19 |
| Awards forfeited | (0.1 | ) | | 33.72 |
| Unvested awards as of December 31, 2016 | 3.2 |
| | 28.57 |
|
During the years ended December 31, 2016, 2015 and 2014, the weighted average grant-date fair value per unit award granted was $23.21, $29.54 and $41.59, respectively. The total fair value of restricted unit awards vested for the years ended December 31, 2016, 2015 and 2014, was $12 million, $8 million, and $30 million, respectively, based on the market price of Sunoco Logistics’ common units as of the vesting date. As of December 31, 2016, estimated compensation cost related to non-vested awards not yet recognized was $57 million, and the weighted average period over which this cost is expected to be recognized in expense is 3.0 years.
As a partnership, we are not subject to U.S.United States federal income tax and most state income taxes. However, the Partnership conducts certain activities through corporate subsidiaries which are subject to federal and state income taxes. The components of the federal and state income tax expense (benefit) are summarized as follows: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Current expense (benefit): | | | | | | | | | | | Federal | $ | 18 |
| | $ | (274 | ) | | $ | 321 |
| $ | 53 |
| | $ | 18 |
| | $ | (274 | ) | State | (35 | ) | | (51 | ) | | 86 |
| (18 | ) | | (35 | ) | | (51 | ) | Total | (17 | ) | | (325 | ) | | 407 |
| 35 |
| | (17 | ) | | (325 | ) | Deferred expense (benefit): | | | | | | | | | | | Federal | (173 | ) | | 231 |
| | (50 | ) | (1,723 | ) | | (173 | ) | | 231 |
| State | 4 |
| | (29 | ) | | 1 |
| 192 |
| | 4 |
| | (29 | ) | Total | (169 | ) | | 202 |
| | (49 | ) | (1,531 | ) | | (169 | ) | | 202 |
| Total income tax expense (benefit) from continuing operations | $ | (186 | ) | | $ | (123 | ) | | $ | 358 |
| | Total income tax benefit | | $ | (1,496 | ) | | $ | (186 | ) | | $ | (123 | ) |
Historically, our effective rate has differed from the statutory rate primarily due to Partnership earnings that are not subject to U.S.United States federal and most state income taxes at the partnership level. The completion of the Southern Union Merger, Sunoco Merger, ETP Holdco Transaction and Susser Merger (see Note 3) significantly increased the activities conducted through corporate subsidiaries. A reconciliation of income tax expense (benefit) at the U.S.United States statutory rate to the Partnership’s income tax expense (benefit) attributable to continuing operationsbenefit for the years ended December 31, 2017, 2016 2015 and 20142015 is as follows: | | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Income tax expense at U.S. statutory rate of 35 percent | $ | 154 |
| | $ | 490 |
| | $ | 558 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (519 | ) | | (515 | ) | | (341 | ) | Nondeductible goodwill included in the Lake Charles LNG Transaction | — |
| | — |
| | 105 |
| Goodwill impairments | 223 |
| | — |
| | — |
| State income taxes (net of federal income tax effects) | (17 | ) | | (37 | ) | | 54 |
| Dividend Received Deduction | (15 | ) | | (24 | ) | | — |
| Audit Settlement | — |
| | (7 | ) | | — |
| Premium on debt retirement | — |
| | — |
| | (10 | ) | Foreign | — |
| | — |
| | (8 | ) | Other | (12 | ) | | (30 | ) | | — |
| Income tax expense (benefit) from continuing operations | $ | (186 | ) | | $ | (123 | ) | | $ | 358 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016* | | 2015* | Income tax expense at United States statutory rate of 35 percent | $ | 352 |
| | $ | 139 |
| | $ | 479 |
| Increase (reduction) in income taxes resulting from: | | | | | | Partnership earnings not subject to tax | (457 | ) | | (504 | ) | | (504 | ) | Federal rate change | (1,559 | ) | | — |
|
| — |
| Goodwill impairments | 172 |
| | 223 |
| | — |
| State income taxes (net of federal income tax effects) | 131 |
| | (17 | ) | | (37 | ) | Dividend received deduction | (14 | ) | | (15 | ) | | (24 | ) | Audit settlement | — |
| | — |
| | (7 | ) | Change in tax status of subsidiary | (124 | ) | | — |
| | — |
| Other | 3 |
| | (12 | ) | | (30 | ) | Income tax benefit | $ | (1,496 | ) | | $ | (186 | ) | | $ | (123 | ) |
* As adjusted. See Note 2.
Deferred taxes result from the temporary differences between financial reporting carrying amounts and the tax basis of existing assets and liabilities. The table below summarizes the principal components of the deferred tax assets (liabilities) as follows: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Deferred income tax assets: | | | | | | | Net operating losses and alternative minimum tax credit | $ | 380 |
| | $ | 155 |
| $ | 604 |
| | $ | 380 |
| Pension and other postretirement benefits | 30 |
| | 36 |
| 21 |
| | 30 |
| Long term debt | 32 |
| | 61 |
| | Long-term debt | | 14 |
| | 32 |
| Other | 84 |
| | 142 |
| 93 |
| | 84 |
| Total deferred income tax assets | 526 |
| | 394 |
| 732 |
| | 526 |
| Valuation allowance | (118 | ) | | (121 | ) | (189 | ) | | (118 | ) | Net deferred income tax assets | $ | 408 |
| | $ | 273 |
| $ | 543 |
| | $ | 408 |
| | | | | | | | Deferred income tax liabilities: | | | | | | | Properties, plants and equipment | $ | (1,054 | ) | | $ | (1,305 | ) | | Property, plant and equipment | | $ | (664 | ) | | $ | (1,054 | ) | Investment in unconsolidated affiliates | (3,728 | ) | | (2,889 | ) | (2,664 | ) | | (3,728 | ) | Trademarks | — |
| | (112 | ) | | Other | (20 | ) | | (49 | ) | (98 | ) | | (20 | ) | Total deferred income tax liabilities | (4,802 | ) | | (4,355 | ) | (3,426 | ) | | (4,802 | ) | Accumulated deferred income taxes | $ | (4,394 | ) | | $ | (4,082 | ) | | Net deferred income taxes | | $ | (2,883 | ) | | $ | (4,394 | ) |
The table below provides a rollforward of the net deferred income tax liability as follows: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Net deferred income tax liability, beginning of year | $ | (4,082 | ) | | $ | (4,331 | ) | $ | (4,394 | ) | | $ | (4,082 | ) | ETE Acquisition of general partner of Sunoco LP | — |
| | 490 |
| | Goodwill associated with Sunoco Retail to Sunoco LP transaction (see Note 3) | (460 | ) | | — |
| — |
| | (460 | ) | Tax provision | 169 |
| | (202 | ) | 1,531 |
| | 169 |
| Other | (21 | ) | | (39 | ) | (20 | ) | | (21 | ) | Net deferred income tax liability, end of year | $ | (4,394 | ) | | $ | (4,082 | ) | $ | (2,883 | ) | | $ | (4,394 | ) |
ETP Holdco and other corporate subsidiaries have federal net operating loss carryforward of $580 million,$1.57 billion, all of which will expire in 20322031 through 2035.2037. Our corporate subsidiaries have $52$62 million of federal alternative minimum tax credits at December 31, 2016.2017, of which $29 million is expected to be reclassified to current income tax receivable in 2018 pursuant to the Tax Cuts and Jobs Act. Our corporate subsidiaries have state net operating loss carryforward benefits of $124$210 million, net of federal tax, which expire between 20172018 and 2036. A valuation allowance of $118$186 million is applicable to the state net operating loss carryforward benefits primarily attributable to significant restrictions on their use in the Commonwealth of Pennsylvania. Pennsylvania and the remaining $3 million valuation allowance is applicable to the federal net operating loss carryforward benefit.
The following table sets forth the changes in unrecognized tax benefits: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Balance at beginning of year | $ | 610 |
| | $ | 440 |
| | $ | 429 |
| $ | 615 |
| | $ | 610 |
| | $ | 440 |
| Additions attributable to tax positions taken in the current year | 8 |
| | — |
| | 20 |
| — |
| | 8 |
| | — |
| Additions attributable to tax positions taken in prior years | 18 |
| | 178 |
| | — |
| 28 |
| | 18 |
| | 178 |
| Reduction attributable to tax positions taken in prior years | (20 | ) | | — |
| | (1 | ) | (25 | ) | | (20 | ) | | — |
| Settlements | — |
| | — |
| | (5 | ) | | Lapse of statute | (1 | ) | | (8 | ) | | (3 | ) | (9 | ) | | (1 | ) | | (8 | ) | Balance at end of year | $ | 615 |
| | $ | 610 |
| | $ | 440 |
| $ | 609 |
| | $ | 615 |
| | $ | 610 |
|
As of December 31, 2016,2017, we have $596$605 million ($554576 million after federal income tax benefits) related to tax positions which, if recognized, would impact our effective tax rate. We believe it is reasonably possible that its unrecognized tax benefits may be reduced by $1 million ($0.6 million, net of federal tax) within the next twelve months due to settlement of certain positions. Our policy is to accrue interest expense and penalties on income tax underpayments (overpayments) as a component of income tax expense. During 2016,2017, we recognized interest and penalties of less than $1$3 million. At December 31, 2016,2017, we have interest and penalties accrued of $6$9 million, net of tax. Sunoco, Inc. has historically included certain government incentive payments as taxable income on its federal and state income tax returns. In connection with Sunoco, Inc.’s 2004 through 2011 years, Sunoco, Inc. filed amended returns with the IRS excluding these government incentive payments from federal taxable income. The IRS denied the amended returns, and Sunoco, Inc. petitioned the Court of Federal Claims (“CFC”) in June 2015 on this issue. In November 2016, the CFC ruled against Sunoco, Inc., and Sunoco, Inc. is appealing this decision to the Federal Circuit. If Sunoco, Inc. is ultimately fully successful in this litigation, it will receive tax refunds of approximately $530 million. However, due to the uncertainty surrounding the litigation, a reserve of $530 million was established for the full amount of the litigation. Due to the timing of the litigation and the related reserve, the receivable and the reserve for this issue have been netted in the financial statements as of December 31, 2016.2017. In December of 2015, Thethe Pennsylvania Commonwealth Court determined in Nextel Communications v. Commonwealth (“Nextel”Nextel”) that the Pennsylvania limitation on NOL carryforwardscarryforward deductions violated the uniformity clause of the Pennsylvania Constitution. Based uponConstitution and struck the NOL limitation in its entirety. In October 2017, the Pennsylvania Supreme Court affirmed the decision in with respect to the uniformity clause violation; however, the Court reversed with respect to the remedy and instead severed the flat-dollar limitation, leaving the percentage-based limitation intact. Nextel, has until April 4, 2018 to file a petition for writ of certiorari with the U.S. Supreme Court. Sunoco, Inc. is recognizinghas recognized approximately $46$67 million ($3053 million after federal income tax benefits) in tax benefit based on previously filed tax returns and certain previously filed protective claims.claims as relates to its cases currently held pending the Nextel matter. However, asbased upon the NextelPennsylvania Supreme Court’s
October 2017 decision, is subject to appeal, and because of uncertainty in the breadth of the application of the decision, we have reserved $9$27 million ($621 million after federal income tax benefits) against the receivable. In general, ETP and its subsidiaries are no longer subject to examination by the Internal Revenue Service (“IRS”), and most state jurisdictions, for the 2013 and prior tax years. However, Sunoco, Inc. and its subsidiaries are no longer subject to examination by the IRS for tax years prior to 2007. Sunoco, Inc. has been examined by the IRS for tax years through 2013. However, statutes remain open for tax years 2007 and forward due to carryback of net operating losses and/or claims regarding government incentive payments discussed above. All other issues are resolved. Though we believe the tax years are closed by statute, tax years 2004 through 2006 are impacted by the carryback of net operating losses and under certain circumstances may be impacted by adjustments for government incentive payments. ETP and its subsidiaries also have various state and local income tax returns in the process of examination or administrative appeal in various jurisdictions. We believe the appropriate accruals or unrecognized tax benefits have been recorded for any potential assessment with respect to these examinations. On December 22, 2017, the Tax Cuts and Jobs Act was signed into law. Among other provisions, the highest corporate federal income tax rate was reduced from 35% to 21% for taxable years beginning after December 31, 2017. As a result, the Partnership recognized a deferred tax benefit of $1.56 billion in December 2017. For the year ended December 2016, the Partnership recorded an income tax benefit due to pre-tax losses at its corporate subsidiaries.
| | 11. | REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES: |
Contingent Residual Support Agreement – AmeriGas In connection with the closing of the contribution of its propane operations in January 2012, ETP agreed to providepreviously provided contingent residual support of $1.55 billioncertain debt obligations of intercompany borrowings made byAmeriGas. AmeriGas has subsequently repaid the remainder of the related obligations and certain of its affiliates with maturities
through 2022 from a finance subsidiary of AmeriGas that have maturity dates and repayment terms that mirror those of an equal principal amount of senior notes issued by this finance company subsidiary to third-party purchases. In 2016, AmeriGas repurchased certain of its senior notes, which caused a reduction in the amount supported by ETP under theno longer provides contingent residual support agreement. In February 2017,for any AmeriGas repurchased $378 million of its 7.00% senior notes, which reduced the remaining amount supported by ETP to $122 million.notes.
Guarantee of Sunoco LP Notes In connection with previous transactions whereby Retail Holdings contributed assets to Sunoco LP, Retail Holdings provided a limited contingent guarantee of collection, but not of payment, to Sunoco LP with respect to (i) $800 million principal amount of 6.375% senior notes due 2023 issued by Sunoco LP, (ii) $800 million principal amount of 6.25% senior notes due 2021 issued by Sunoco LP and (iii) $2.035 billion aggregate principal for Sunoco LP’s term loan due 2019. In December 2016, Retail Holdings contributed its interests in Sunoco LP, along with the assignment of the guarantee of Sunoco LP’s senior notes, to its subsidiary, ETC M-A Acquisition LLC.LLC (“ETC M-A”). NGL Pipeline RegulationOn January 23, 2018, Sunoco LP redeemed the previously guaranteed senior notes and issued the following notes for which ETC M-A has also guaranteed collection with respect to the payment of principal amounts:
We$1.00 billion aggregate principal amount of 4.875%, senior notes due 2023; $800 million aggregate principal amount of 5.50% senior notes due 2026; and $400 million aggregate principal amount of 5.875% senior notes due 2028. Under the guarantee of collection, ETC M-A would have intereststhe obligation to pay the principal of each series of notes once all remedies, including in NGL pipelines locatedthe context of bankruptcy proceedings, have first been fully exhausted against Sunoco LP with respect to such payment obligation, and holders of the notes are still owed amounts in Texas and New Mexico. We commencedrespect of the interstate transportationprincipal of NGLs in 2013, which issuch notes. ETC M-A will not otherwise be subject to the jurisdictioncovenants of the FERC underindenture governing the Interstate Commerce Act (“ICA”) and the Energy Policy Act of 1992. Under the ICA, tariff rates must be just and reasonable and not unduly discriminatory and pipelines may not confer any undue preference. The tariff rates established for interstate services were based on a negotiated agreement; however, the FERC’s rate-making methodologies may limit our ability to set rates based on our actual costs, may delay or limit the use of rates that reflect increased costs and may subject us to potentially burdensome and expensive operational, reporting and other requirements. Any of the foregoing could adversely affect our business, revenues and cash flow.notes. FERC Audit In March 2016, the FERC commenced an audit of Trunkline for the period from January 1, 2013 to present to evaluate Trunkline’s compliance with the requirements of its FERC gas tariff, the accounting regulations of the Uniform System of Accounts as prescribed by the FERC, and the FERC’s annual reporting requirements. The audit is ongoing. Commitments In the normal course of business, ETP purchases, processes and sells natural gas pursuant to long-term contracts and enters into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. ETP
believes that the terms of these agreements are commercially reasonable and will not have a material adverse effect on its financial position or results of operations. ETP’s joint venture agreements require that it funds its proportionate share of capital contributions to its unconsolidated affiliates. Such contributions will depend upon ETP’s unconsolidated affiliates’ capital requirements, such as for funding capital projects or repayment of long-term obligations. We have certain non-cancelable leases for property and equipment, which require fixed monthly rental payments and expire at various dates through 2034. The table below reflects rental expense under these operating leases included in operating expenses in the accompanying statements of operations, which include contingent rentals, and rental expense recovered through related sublease rental income: | | | | Years Ended December 31, | | Years Ended December 31, | | | 2016 | | 2015 | | 2014 | | 2017 | | 2016 | | 2015 | Rental expense(1) | | $ | 81 |
| | $ | 176 |
| | $ | 159 |
| | $ | 90 |
| | $ | 81 |
| | $ | 176 |
| Less: Sublease rental income | | (1 | ) | | (16 | ) | | (26 | ) | | — |
| | (1 | ) | | (16 | ) | Rental expense, net | | $ | 80 |
| | $ | 160 |
| | $ | 133 |
| | $ | 90 |
| | $ | 80 |
| | $ | 160 |
|
| | (1) | Includes contingent rentals totaling $26 million and $24 million for the yearsyear ended December 31, 2015 and 2014, respectively.2015. |
Future minimum lease commitments for such leases are: | | Years Ending December 31: | | | 2017 | $ | 38 |
| | 2018 | 30 |
| $ | 39 |
| 2019 | 28 |
| 36 |
| 2020 | 28 |
| 37 |
| 2021 | 35 |
| 30 |
| 2022 | | 23 |
| Thereafter | 133 |
| 92 |
| Future minimum lease commitments | 292 |
| 257 |
| Less: Sublease rental income | (14 | ) | (8 | ) | Net future minimum lease commitments | $ | 278 |
| $ | 249 |
|
Litigation and Contingencies We may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business. Natural gas and crude oil are flammable and combustible. Serious personal injury and significant property damage can arise in connection with their transportation, storage or use. In the ordinary course of business, we are sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverage and deductibles management believes are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Dakota Access Pipeline During the summer of 2016, individuals affiliated with, or sympathetic to, the Standing Rock Sioux Tribe (the “SRST”) began gathering near a construction site on the Dakota Access pipeline project in North Dakota to protest the development of the pipeline project. Some of the protesters eventually trespassed on to the construction site, tampered with equipment, and disrupted construction activity at the site. At this time, we are working with the various authorities to mitigate the effects of this largely unlawful protest. We believe that Dakota Access now has the necessary permits and approvals to perform all work on the pipeline project. In response to the protests, Dakota Access filed a lawsuit in federal court in North Dakota to restrain protestors from disrupting construction and also requested a temporary restraining order (“TRO”) against the Chairman of the SRST and the protestors. The U.S. District Court granted Dakota Access’s request for a TRO, and the defendants filed a motion to dismiss the case and dissolve the TRO. The Court later granted the defendants’ motions to dissolve the TRO. Dakota Access filed a response to the defendant’s motion to dismiss, and the Court has yet to rule. At this time, we cannot determine how long the protest will continue or how the legal action will be resolved. Construction work on the pipeline is ongoing, and, barring legal delays, we expect the final portion of the pipeline to be completed in March or April 2017. Additional protests or legal actions may arise in connection with our Dakota Access project or other projects. Trespass on to construction sites or our physical facilities, or other disruptions, could result in further damage to our assets, safety incidents, potential liability or project delays.
InOn July 25, 2016, the U.S.United States Army Corps of Engineers (“USACE”) issued permits to Dakota Access consistent with environmental and historic preservation statutes for the pipeline to make two crossings of the Missouri River in North Dakota, including a crossing of the Missouri River at Lake Oahe. TheAfter significant delay, the USACE has also issued an easementeasements to allow the pipeline to cross land owned by the USACE adjacent to the Missouri River in two locations. The SRSTAlso in July, the Standing Rock Sioux Tribe (“SRST”) filed a lawsuit in the U.S.United States District Court for the District of Columbia against the USACE challengingthat challenged the legality of the permits issued for the construction of the Dakota Access pipeline across those waterways and claimingclaimed violations of the National Historic Preservation Act (“NHPA”). The SRST also sought a preliminary injunction to rescind the USACE permits while the case is pending. Dakota Access’ moved to interveneAccess intervened in the case and that motion was granted by the Court.case. The SRST has also soughtsoon added a
request for an emergency TROtemporary restraining order (“TRO”) to stop construction on the pipeline project. On September 9, 2016, the Court denied SRST’s motion for a preliminary injunction. injunction, rendering the TRO request moot. After that decision,the September 9, 2016 ruling, the Department of the Army, the Department of Justice,DOJ, and the Department of the Interior released a joint statement stating that the USACE would not grant the easement for the land adjacent to Lake Oahe until the federal departmentsDepartment of the Army completed a review ofto determine whether it was necessary to reconsider the SRST’s claims in its lawsuit with respectUSACE’s decision under various federal statutes relevant to the USACE’s compliance with certain federal statutes in connection with its activities related to the granting of the permits. pipeline approval. The SRST appealed the denial of the preliminary injunction to the U.S.United States Court of Appeals for the D.C. Circuit and filed an emergency motion for an injunction pendingin the
appeal to the U.S. District Court. The U.S. United States District Court denied SRST’s emergency motion for an injunction pending the appeal.appeal, which was denied. The D.C. Circuit then denied the SRST’s application for an injunction pending appeal and later dismissed SRST’s appeal of the order denying the preliminary injunction motion. The SRST filed an amended complaint and added claims based on treaties between the tribes and the United States and statuesstatutes governing the use of government property. The D.C. Circuit denied the SRST’s application for a stay pending appeal and later dismissed the SRST’s appeal of the denied TRO.
In December 2016, the Department of the Army announced that, although its prior actions complied with the law, it intended to conduct further environmental review of the crossing at Lake Oahe. In JanuaryFebruary 2017, pursuantin response to a presidential memorandum, the Department of the Army decided that no further environmental review was necessary and delivered an easement to Dakota Access an easementallowing the pipeline to cross Lake Oahe. Construction at the site is ongoing. In the fall of 2016,Almost immediately, the Cheyenne River Sioux Tribe (“CRST”), which had intervened alongsidein the SRST. After USACE gave Dakota Access its final easement, the Cheyenne River Siouxlawsuit in August 2016, moved for a preliminary injunction and TRO blocking construction.to block operation of the pipeline. These motions raised, for the first time, claims based on the religious rights of the tribe.Tribe. The district courtDistrict Court denied the TRO and has yet to decide whether to grant a preliminary injunction. The SRST has also moved for summary judgment on its claims against the government based on its treaty rightsinjunction, and the National Environmental Policy Act,CRST appealed and requested an injunction pending appeal in the district court is still considering this motion. Briefing is ongoing.and the D.C. Circuit. Both courts denied the CRST’s request for an injunction pending appeal. Shortly thereafter, at CRST’s request, the D.C. Circuit dismissed CRST’s appeal. The SRST and the CRST amended their complaints to incorporate religious freedom and other claims. In addition, the Oglala and Yankton Sioux tribes (collectively, “Tribes”) have filed related lawsuits in an effort to prevent construction of the Dakota Access pipeline project. These lawsuits have been consolidated into the action initiated by the SRST. Several individual members of the Tribes have also intervened in the lawsuit asserting claims that overlap with those brought by the four Tribes. On June 14, 2017, the Court ruled on SRST’s and CRST’s motions for partial summary judgment and the USACE’s cross-motions for partial summary judgment. The Court rejected the majority of the Tribes’ assertions and granted summary judgment on most claims in favor of the USACE and Dakota Access. In particular, the Court concluded that the USACE had not violated any trust duties owed to the Tribes and had generally complied with its obligations under the Clean Water Act, the Rivers and Harbors Act, the Mineral Leasing Act, the National Environmental Policy Act (“NEPA”) and other related statutes; however, the Court remanded to the USACE three discrete issues for further analysis and explanation of its prior determinations under certain of these statutes. The Court ordered briefing to determine whether the pipeline should remain in operation during the pendency of the USACE’s review process or whether to vacate the existing permits. The USACE and Dakota Access opposed any shutdown of operations of the pipeline during this review process. On October 11, 2017, the Court issued an order allowing the pipeline to remain in operation during the pendency of the USACE’s review process. In early October 2017, USACE advised the Court that it expects to complete the additional analysis and explanation of its prior determinations requested by the Court by April 2018. On December 4, 2017, the Court imposed three conditions on continued operation of the pipeline during the remand process. First, Dakota Access must retain an independent auditor to review its compliance with the conditions and regulations governing its easements and to assess integrity threats to the pipeline. The auditor’s report is required to be filed with the Court by April 1, 2018. Second, the Court has directed Dakota Access to continue its work with the Tribes and the USACE to revise and finalize its emergency spill response planning for the section of the pipeline crossing Lake Oahe. Dakota Access is required to file the revised plan with the Court by April 1, 2018. And third, the Court has directed Dakota Access to submit bi-monthly reports during the remand period disclosing certain inspection and maintenance information related to the segment of the pipeline running between the valves on either side of the Lake Oahe crossing. The first report was filed with the court on December 29, 2017. In November 2017, the Yankton Sioux Tribe (“YST”), moved for partial summary judgment asserting claims similar to those already litigated and decided by the Court in its June 14, 2017 decision on similar motions by CRST and SRST. YST argues that the USACE and Fish and Wildlife Service violated NEPA, the Mineral Leasing Act, the Rivers and Harbors Act, and YST’s treaty and trust rights when the government granted the permits and easements necessary for the pipeline. Briefing on YST’s motion is ongoing. While we believe that the pending lawsuits are unlikely to block constructionhalt or suspend the operation of the pipeline, and that construction on the land adjacent to Lake Oahe will be completed in a timely manner, we cannot assure this outcome. Any significant delay imposed by the court will delay the receipt of revenue from this project. We cannot determine when or how these lawsuits will be resolved or the impact they may have on the Dakota Access project.
Mont Belvieu Incident On June 26, 2016, a hydrocarbon storage well located on another operator’s facility adjacent to Lone Star NGL Mont Belvieu’s (Lone Star)(“Lone Star”) facilities in Mont Belvieu, Texas experienced an over-pressurization resulting in a subsurface release. The subsurface release caused a fire at Lone Star’s South Terminal (CMB) and damage to Lone Star’s storage well operations at its South and North Terminals. Normal operations have resumed at the facilities with the exception of one of Lone Star’s storage wells. TheLone Star is still quantifying the extent of possibleits incurred and ongoing damages is still under investigation.and has or will be seeking reimbursement for these losses. MTBE Litigation Sunoco, Inc. and/or Sunoco, Inc. (R&M), (now known as Sunoco (R&M), LLC) along with other refiners, manufacturers and sellersmembers of gasoline,the petroleum industry, are defendants in lawsuits alleging MTBE contamination of groundwater. The plaintiffs, typically include water purveyors and municipalities responsible for supplying drinking water andstate-level governmental authorities. The plaintiffs primarilyentities, assert product liability claims and additional claims including nuisance, trespass, negligence, violation of environmental laws, andand/or deceptive business practices. The plaintiffs in all of the cases seek to recover compensatory damages, and in some cases also seek natural resource damages, injunctive relief, punitive damages, and attorneys’ fees. As of December 31, 2016,2017, Sunoco, Inc. is a defendant in sixseven cases, including casesone case each initiated by the States of Maryland, New Jersey, Vermont, Pennsylvania, Rhode Island, one by the Commonwealth of Pennsylvania and two others by the Commonwealth of Puerto Rico with theRico. The more recent Puerto Rico action beingis a companion case alleging damages for additional sites beyond those at issue in the initial Puerto Rico action. The actions brought by the State of Maryland and Commonwealth of Pennsylvania have also named as defendants Energy Transfer Partners, L.P., ETP Holdco Corporation, and Sunoco Partners Marketing & Terminals, L.P. Four of these cases are venuedpending in a multidistrict litigation proceeding in a New York federal court. The New Jersey, Puerto Rico,court; one is pending in federal court in Rhode Island, one is pending in state court in Vermont, and Pennsylvania cases assert natural resource damage claims.one is pending in state court in Maryland. Fact discovery has concluded with respect to an initial set of 19 sites each that will be the subject of the first trial phase in the New Jersey case and the initial Puerto Rico case. The initial set of 19 New Jersey trial sites are now pending before the United States District Judge for the District of New Jersey, the Hon. Freda L. Wolfson for the pre-trial and trial phases. Judge Wolfson then referred the case to United States Magistrate Judge for the District of New Jersey, the Hon. Lois H. Goodman. Judge Goodman conducted a status conference with all of the parties and inquired whether the parties will engage in a global mediation and instructed the parties to exchange possible mediator names. All parties agreed to participate in global settlement discussions in a global mediation forum before Hon. Garrett Brown (Ret.), a Judicial Arbitration Mediation Service mediator. The remaining portion of the New Jersey case remains in the multidistrict litigation. The first mediation session with Judge Brown is scheduled for November 2 through November 3, 2016. In early 2017, Sunoco, Inc. and two other co-defendantsSunoco, Inc. (R&M) have reached a settlement in principle with the State of New Jersey, subject toJersey. The Court approved the parties agreeingJudicial Consent Order on December 5, 2017. Dismissal of the termscase against Sunoco, Inc. and conditions of a Settlement and Release agreement. Sunoco, Inc. (R&M) is expected shortly. The Maryland complaint was filed in December 2017 but was not served until January 2018.
It is reasonably possible that a loss may be realized in the remaining cases; however, we are unable to estimate the possible loss or range of loss in excess of amounts accrued. Management believes that anAn adverse determination with respect to one or more of the MTBE cases could have a significant impact on results of operations during the period in which any saidsuch adverse determination occurs, but does not believe that any such an adverse determination likely would not have a material adverse effect on the Partnership’s consolidated financial position.
Regency Merger Litigation Following the January 26, 2015 announcement of the Regency Merger,Regency-ETP merger (the “Regency Merger”), purported Regency unitholders filed lawsuits in state and federal courts in Dallas and Delaware asserting claims relating to the Regency Merger. All but one Regency Merger-related lawsuits have been dismissed, although one lawsuit remains pending on appeal.dismissed. On June 10, 2015, Adrian Dieckman (“Dieckman”), a purported Regency unitholder, filed a class action complaint, on behalf of Regency’s common unitholdersDieckman v. Regency GP LP, et al., C.A. No. 11130-CB, in the Court of Chancery of the State of Delaware. Delaware (the “Regency Merger Litigation”), on behalf of Regency’s common unitholders against Regency GP, LP; Regency GP LLC; ETE, ETP, ETP GP, and the members of Regency’s board of directors (the “Regency Litigation Defendants”). The lawsuitRegency Merger litigation alleges that the Regency Merger breached the Regency partnership agreement because Regency’s conflicts committee was not properly formed, and the Regency Merger was not approved in good faith. Defendants filed a motion to dismiss, and onOn March 29, 2016, the Delaware courtCourt of Chancery granted the Regency Litigation Defendants’ motion and dismissedto dismiss the lawsuit. On April 26, 2016,lawsuit in its entirety. Dieckman filed his Notice of Appeal to the Supreme Court of Delaware. This appeal is styled Adrian Dieckman v. Regency GP LP, et al., No. 208, 2016, in the Supreme Court of the State of Delaware. Dieckman filed his Opening Brief on June 9, 2016, and Defendants’ filed their Answering Brief on July 29, 2016. On August 31, 2016, Dieckman filed his Reply Brief. Oral argument was held on November 16, 2016 before the Delaware Supreme Court.appealed. On January 20, 2017, Thethe Delaware Supreme Court issued an order reversingreversed the judgment of the Court of Chancery. On May 5, 2017, Plaintiff filed an Amended Verified Class Action Complaint. The Regency Litigation Defendants then filed Motions to Dismiss the Amended Complaint and a Motion to Stay Discovery on May 19, 2017. On February 20, 2018, the Court of Chancery issued an Order granting in part and denying in part the motions to dismiss, dismissing the claims against all defendants other than Regency GP, LP and Regency GP LLC. The Regency Litigation Defendants cannot predict the outcome of the Regency Merger Litigation or any lawsuits that dismissed Counts Imight be filed subsequent to the date of this filing; nor can the Regency Litigation Defendants predict the amount of time and II of Dieckman’s Complaint.expense that will be required to resolve the Regency Merger Litigation. The Regency Litigation Defendants believe the Regency Merger Litigation is without merit and intend to vigorously defend against it and any others that may be filed in connection with the Regency Merger.
Enterprise Products Partners, L.P. and Enterprise Products Operating LLC Litigation On January 27, 2014, a trial commenced between ETP against Enterprise Products Partners, L.P. and Enterprise Products Operating LLC (collectively, “Enterprise”) and Enbridge (US) Inc. Trial resulted in a verdict in favor of ETP against Enterprise that consisted of $319 million in compensatory damages and $595 million in disgorgement to ETP. The jury also found that ETP owed Enterprise $1 million under a reimbursement agreement. On July 29, 2014, the trial court entered a final judgment in favor of ETP and awarded ETP $536 million, consisting of compensatory damages, disgorgement, and pre-judgment interest. The trial court also ordered that ETP shall be entitled to recover post-judgment interest and costs of court and that Enterprise is not entitled to any net recovery on its counterclaims. Enterprise has filed a notice of appeal with the TexasCourt of Appeals. On July 18, 2017, the Court of Appeals issued its opinion and briefing by Enterprise and ETP is complete. Oral argument was held on April 20, 2016. Thereversed the trial court’s judgment. ETP’s motion for rehearing to the Court of Appeals was denied. ETP filed a petition for review with the Texas Supreme Court. Enterprise’s response is taking the briefs under advisement. In accordance with GAAP, no amounts related to the original verdict or the July 29, 2014 final judgment will be recorded in our financial statements until the appeal process is completed.due February 26, 2018. Sunoco Logistics Merger Litigation Between January 6, 2017 and February 8, 2017, sevenSeven purported ETPEnergy Transfer Partners, L.P. common unitholders (“(the “ETP Unitholder Plaintiffs”) separately filed seven putative unitholder class action lawsuits challengingagainst ETP, ETP GP, ETP LLC, the mergermembers of the ETP Board, and the disclosures madeETE (the “ETP-SXL Defendants”) in connection with the merger.announcement of the Sunoco Logistics Merger. Two of these lawsuits were voluntarily dismissed in March 2017. The five remaining lawsuits are styled (a)were consolidated as Koma v.In re Energy Transfer Partners, L.P. Shareholder Litig., et al., Case No. 3:17-cv-00060-G, in the United States District Court for the Northern District of Texas, Dallas Division (the “Koma Lawsuit”); (b) Ashraf v. Energy Transfer Partners, L.P. et al., Case No. 3:17-cv-00118-B, in the United States District Court for the Northern District of Texas, Dallas Division (the “Ashraf Lawsuit”); (c) Shure v. Energy Transfer Partners, L.P. et al., CaseC.A. No. 1:17-cv-00044-UNA,17-cv-00044-CCC, in the United States District Court for the District of Delaware (the “Shure Lawsuit”); (d) Verlin v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00045-UNA, in the United States District Court for the District of Delaware (the “Verlin Lawsuit”); (e) Duany v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00058-UNA, in the United States District Court for the District of Delaware (the “Duany Lawsuit”); (f) Epstein v. Energy Transfer Partners, L.P. et. al., Case No, 1:17-cv-00069, in the United States District Court for the District of Delaware (the “Epstein Lawsuit”) and (g) Sgnilek v. Energy Transfer Partners, L.P. et al., Case No. 1:17-cv-00141, in the United States District Court for the District of Delaware (the “Sgnilek Lawsuit” and collectively with the Koma Lawsuit, Ashraf Lawsuit, Shure Lawsuit, Verlin Lawsuit, Duany Lawsuit, and Epstein Lawsuit, the “Lawsuits”“Sunoco Logistics Merger Litigation”). The Koma Lawsuit, Ashraf Lawsuit, Duany Lawsuit, and Epstein Lawsuit are filed against ETP ETP GP, ETP GP, LLC, ETE, and the members of the ETP Board. The Shure Lawsuit and Verlin Lawsuit are filed against ETP, ETP GP, the members of the ETP Board, ETE, Sunoco Logistics, and Sunoco Logistics GP. The Sgnilek Lawsuit is filed against ETP, ETP GP, ETP GP LLC, ETE, the members of the ETP Board, Sunoco Logistics and Sunoco Logistics GP (collectively “Defendants”).
Unitholder Plaintiffs allege causes of action challenging the merger and the preliminary joint proxy statement/prospectus filed in connection with the merger. According toSunoco Logistics Merger (the “ETP-SXL Merger Proxy”). The ETP Unitholder Plaintiffs the preliminary joint proxy statement/prospectus is allegedly misleading because, among other things, it fails to disclose certain information concerning, in general, (a) the background and process that led to the merger; (b) ETE’s, ETP’s, and Sunoco Logistics’ financial projections; (c) the financial analysis and fairness opinion provided by Barclays; and (d) alleged conflicts of interest concerning Barclays, ETE, and certain officers and directors of ETP and ETE. Based on these allegations, and in general, Plaintiffs allege that (i) Defendants have violated Section 14(a)sought rescission of the Exchange ActSunoco Logistics Merger or rescissory damages for ETP unitholders, as well as an award of costs and Rule 14a-9 promulgated thereunder and (ii)attorneys’ fees. On October 5, 2017, the members ofETP-SXL Defendants filed a Motion to Dismiss the ETP Board have violated Section 20(a) of the Exchange Act. Plaintiffs in the Shure Lawsuit and Verlin Lawsuit also allege that Sunoco Logistics has violated Section 20(a) of the Exchange Act. Plaintiffs also assert, in general, that the terms of the merger (including, among other terms, the merger consideration) are unfair to ETP common unitholders and resulted from an unfair and conflicted process.
Based on these allegations, the Sgnilek Lawsuit alleges that (a) the ETP Board, ETP GP, ETP GP LLC, ETP, and ETE have breached the covenant of good faith and/or fiduciary duties, and (b) Sunoco Logistics and Sunoco Logistics GP have aided and abetted those alleged breaches.
Based on these allegations, Plaintiffs seek to enjoin Defendants from proceeding with or consummating the merger unless and until Defendants disclose the allegedly omitted information summarized above. The Koma Lawsuit and Sgnilek Lawsuit also seek to enjoin Defendants from proceeding with or consummating the merger unless and until the ETP Board adopts and implements processes to obtain the best possible terms for ETP common unitholders. To the extent that the merger is consummated before injunctive relief is granted, Plaintiffs seek to have the merger rescinded. Plaintiffs also seek damages and attorneys’ fees.
Defendants’ dates to answer, move to dismiss, or otherwiseUnitholder Plaintiffs’ claims. Rather than respond to the Lawsuits have not yet been set.Motion to Dismiss, the ETP Unitholder Plaintiffs chose to voluntarily dismiss their claims without prejudice in November 2017.
The ETP-SXL Defendants cannot predict whether the ETP Unitholder Plaintiffs will refile their claims against the ETP-SXL Defendants or what the outcome of these or any othersuch lawsuits that might be filed subsequent tobe. Nor can the date of the filing of this annual report, nor canETP-SXL Defendants predict the amount of time and expense that willwould be required to resolve such litigation.lawsuits. The ETP-SXL Defendants believe the Lawsuits areSunoco Logistics Merger Litigation was without merit and intend to defend vigorously against the Lawsuits and any other actionsfuture lawsuits challenging the merger.Sunoco Logistics Merger. Litigation filed by BP Products On April 30, 2015, BP Products North America Inc. (“BP”) filed a complaint with the FERC, BP Products North America Inc. v. Sunoco Pipeline L.P., FERC Docket No. OR15-25-000, alleging that Sunoco Pipeline L.P. (“SPLP”), a wholly-owned subsidiary of ETP, entered into certain throughput and deficiency (“T&D”) agreements with shippers other than BP regarding SPLP’s crude oil pipeline between Marysville, Michigan and Toledo, Ohio, and revised its proration policy relating to that pipeline in an unduly discriminatory manner in violation of the Interstate Commerce Act (“ICA”). The complaint asked FERC to (1) terminate the agreements with the other shippers, (2) revise the proration policy, (3) order SPLP to restore BP’s volume history to the level that existed prior to the execution of the agreements with the other shippers, and (4) order damages to BP of approximately $62 million, a figure that BP reduced in subsequent filings to approximately $41 million. SPLP denied the allegations in the complaint and asserted that neither its contracts nor proration policy were unlawful and that BP’s complaint was barred by the ICA’s two-year statute of limitations provision. Interventions were filed by the two companies with which SPLP entered into T&D agreements, Marathon Petroleum Company (“Marathon”) and PBF Holding Company and Toledo Refining Company (collectively, “PBF”). A hearing on the matter was held in November 2016. On May 26, 2017, the Administrative Law Judge Patricia E. Hurt (“ALJ”) issued its initial decision (“Initial Decision”) and found that SPLP had acted discriminatorily by entering into T&D agreements with the two shippers other than BP and recommended that the FERC (1) adopt the FERC Trial Staff’s $13 million alternative damages proposal, (2) void the T&D agreements with Marathon and PBF, (3) re-set each shipper’s volume history to the level prior to the effective date of the proration policy, and (4) investigate the proration policy. The ALJ held that BP’s claim for damages was not time-barred in its entirety, but that it was not entitled to damages more than two years prior to the filing of the complaint. On July 26, 2017, each of the parties filed with the FERC a brief on exceptions to the Initial Decision. SPLP challenged all of the Initial Decision’s primary findings (except for the adjustment to the individual shipper volume histories). BP and FERC Trial Staff challenged various aspects of the Initial Decision related to remedies and the statute of limitations issue. On September 18 and 19, 2017, all parties filed briefs opposing the exceptions of the other parties. The matter is now awaiting a decision by FERC.
Other Litigation and Contingencies We or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable and can be estimated, we accrue the contingent obligation, as well as any expected insurance recoverable amounts related to the contingency. As of December 31, 20162017 and 2015,2016, accruals of approximately $53$33 million and $40$77 million, respectively, were reflected on our consolidated balance sheets related to these contingent obligations. As new information becomes available, our estimates may change. The impact of these changes may have a significant effect on our results of operations in a single period. The outcome of these matters cannot be predicted with certainty and there can be no assurance that the outcome of a particular matter will not result in the payment of amounts that have not been accrued for the matter. Furthermore, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. No amounts have been recorded in our December 31, 20162017 or 20152016 consolidated balance sheets for contingencies and current litigation, other than amounts disclosed herein. Compliance Orders from the New Mexico Environmental Department
Regency received a Notice of Violation from the New Mexico Environmental Department on September 23, 2015 for allegations of violations of New Mexico air regulations related to Jal #3. The Partnership has accrued $250,000 related to the claims and will continue to assess its potential exposure to the allegations as the matter progresses. The Air Quality Bureau issued a Settlement Offer for Revised Notice of Violation REG-0569-1402-RI on February 7, 2017. The Settlement Agreement includes a civil penalty of $465,000. Energy Transfer and the New Mexico Environmental Department are scheduling a meeting to discuss the Settlement Offer in March 2017.
Lone Star NGL Fractionators Notice of Enforcement
Lone Star NGL Fractionators received a Notice of Enforcement from the Texas Commission on Environmental Quality on August 28, 2015 for allegations of violations of Texas air regulations related to Mont Belvieu Gas Plant. The Partnership has accrued $50,000 related to this claim as of December 31, 2016 and will continue to assess its potential exposure to the allegations as the matter progresses. As of December 31, 2016, the Agreed Order is in the approval process with the Texas Commission on Environmental Quality and includes a $21,000 Supplemental Environmental Project.
Environmental Matters Our operations are subject to extensive federal, tribal, state and local environmental and safety laws and regulations that require expenditures to ensure compliance, including related to air emissions and wastewater discharges, at operating facilities and for remediation at current and former facilities as well as waste disposal sites. Historically, our environmental compliance costs have not had a material adverse effect on our results of operations but there can be no assurance that such costs will not be material in the future or that such future compliance with existing, amended or new legal requirements will not have a material adverse effect on our business and operating results. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards.
Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of investigatory, remedial and corrective action obligations, the issuance of injunctions in affected areas and the filing of federally authorized citizen suits. Contingent losses related to all significant known environmental matters have been accrued and/or separately disclosed. However, we may revise accrual amounts prior to resolution of a particular contingency based on changes in facts and circumstances or changes in the expected outcome. Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of our liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, we believe that such costs will not have a material adverse effect on our financial position. Based on information available at this time and reviews undertaken to identify potential exposure, we believe the amount reserved for environmental matters is adequate to cover the potential exposure for cleanup costs. In February 2017, we received letters from the DOJ and Louisiana Department of Environmental Quality notifying Sunoco Pipeline L.P. (“SPLP”) and Mid-Valley Pipeline Company (“Mid-Valley”) that enforcement actions were being pursued for three crude oil releases: (a) an estimated 550 barrels released from the Colmesneil-to-Chester pipeline in Tyler County, Texas (“Colmesneil”) operated and owned by SPLP in February of 2013; (b) an estimated 4,509 barrels released from the Longview-to-Mayersville pipeline in Caddo Parish, Louisiana (a/k/a Milepost 51.5) operated by SPLP and owned by Mid-Valley in October of 2014; and (c) an estimated 40 barrels released from the Wakita 4-inch gathering line in Oklahoma operated and owned by SPLP in January of 2015. In May of this year, we presented to the DOJ, EPA and Louisiana Department of Environmental Quality a summary of the emergency response and remedial efforts taken by SPLP after the releases occurred as well as operational changes instituted by SPLP to reduce the likelihood of future releases. In July, we had a follow-up meeting with the DOJ, EPA and Louisiana Department of Environmental Quality during which the agencies presented their initial demand for civil penalties and injunctive relief. In short, the DOJ and EPA proposed federal penalties totaling $7 million for the three releases along with a demand for injunctive relief, and Louisiana Department of Environmental Quality proposed a state penalty of approximately $1 million to resolve the Caddo Parish release. Neither Texas nor Oklahoma state agencies have joined the penalty discussions at this point. We are currently working on a counteroffer to the Louisiana Department of Environmental Quality. On January 3, 2018, PADEP issued an Administrative Order to Sunoco Pipeline L.P. directing that work on the Mariner East 2 and 2X pipelines be stopped. The Administrative Order detailed alleged violations of the permits issued by PADEP in
February of 2017, during the construction of the project. Sunoco Pipeline L.P. began working with PADEP representatives immediately after the Administrative Order was issued to resolve the compliance issues. Those compliance issues could not be fully resolved by the deadline to appeal the Administrative Order, so Sunoco Pipeline L.P. took an appeal of the Administrative Order to the Pennsylvania Environmental Hearing Board on February 2, 2018. On February 8, 2018, Sunoco Pipeline L.P. entered into a Consent Order and Agreement with PADEP that (1) withdraws the Administrative Order; (2) establishes requirements for compliance with permits on a going forward basis; (3) resolves the non-compliance alleged in the Administrative Order; and (4) conditions restart of work on an agreement by Sunoco Pipeline L.P. to pay a $12.6 million civil penalty to the Commonwealth of Pennsylvania. In the Consent Order and agreement, Sunoco Pipeline L.P. admits to the factual allegations, but does not admit to the conclusions of law that were made by PADEP. PADEP also found in the Consent Order and Agreement that Sunoco Pipeline L.P. had adequately addressed the issues raised in the Administrative Order and demonstrated an ability to comply with the permits. Sunoco Pipeline L.P. concurrently filed a request to the Pennsylvania Environmental Hearing Board to discontinue the appeal of the Administrative Order. That request was granted on February 8, 2018. Environmental Remediation Our subsidiaries are responsible for environmental remediation at certain sites, including the following: Certain of our interstate pipelines conduct soil and groundwater remediation related to contamination from past uses of PCBs. PCB assessments are ongoing and, in some cases, our subsidiaries could potentially be held responsible for contamination caused by other parties. Certain gathering and processing systems are responsible for soil and groundwater remediation related to releases of hydrocarbons. Currently operating Sunoco, Inc. retail sites.
Legacy sites related to Sunoco, Inc. that are subject to environmental assessments, including formerly owned terminals and other logistics assets, retail sites that Sunoco, Inc. no longer operates, closed and/or sold refineries and other formerly owned sites. Sunoco, Inc. is potentially subject to joint and several liability for the costs of remediation at sites at which it has been identified as a potentially responsible party (“PRP”). As of December 31, 2016,2017, Sunoco, Inc. had been named as a PRP at approximately 5043 identified or potentially identifiable “Superfund” sites under federal and/or comparable state law. Sunoco, Inc. is usually one of a number of companies identified as a PRP at a site. Sunoco, Inc. has reviewed the nature and extent of its involvement at each site and other relevant circumstances and, based upon Sunoco, Inc.’s purported nexus to the sites, believes that its potential liability associated with such sites will not be significant. To the extent estimable, expected remediation costs are included in the amounts recorded for environmental matters in our consolidated balance sheets. In some circumstances, future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers. To the extent that an environmental remediation obligation is recorded by a subsidiary that applies regulatory accounting policies, amounts that are expected to be recoverable through tariffs or rates are recorded as regulatory assets on our consolidated balance sheets. The table below reflects the amounts of accrued liabilities recorded in our consolidated balance sheets related to environmental matters that are considered to be probable and reasonably estimable. Currently, we are not able to estimate possible losses or a range of possible losses in excess of amounts accrued. Except for matters discussed above, we do not have any material environmental matters assessed as reasonably possible that would require disclosure in our consolidated financial statements. | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Current | $ | 32 |
| | $ | 41 |
| $ | 36 |
| | $ | 26 |
| Non-current | 313 |
| | 326 |
| 314 |
| | 283 |
| Total environmental liabilities | $ | 345 |
| | $ | 367 |
| $ | 350 |
| | $ | 309 |
|
In 2013, we established a wholly-owned captive insurance company to bear certain risks associated with environmental obligations related to certain sites that are no longer operating. The premiums paid to the captive insurance company include estimates for environmental claims that have been incurred but not reported, based on an actuarially determined fully developed claims expense estimate. In such cases, we accrue losses attributable to unasserted claims based on the discounted estimates that are used to develop the premiums paid to the captive insurance company.
During the years ended December 31, 20162017 and 2015,2016, the Partnership recorded $43$23 million and $38$43 million, respectively, of expenditures related to environmental cleanup programs. On December 2, 2010, Sunoco, Inc. entered an Asset Sale and Purchase Agreement to sell the Toledo Refinery to Toledo Refining Company LLC (“TRC”) wherein Sunoco, Inc. retained certain liabilities associated with the pre-Closingpre-closing time period. On January 2, 2013, USEPA issued a Finding of Violation (“FOV”) to TRC and, on September 30, 2013, EPA issued an NOV/a Notice of Violation (“NOV”)/ FOV to TRC alleging Clean Air Act violations. To date, EPA has not issued an FOV or NOV/FOV to Sunoco, Inc. directly but some of EPA’s claims relate to the time period that Sunoco, Inc. operated the refinery. Specifically, EPA has claimed that the refinery flares were not operated in a manner consistent with good air pollution control practice for minimizing emissions and/or in conformance with their design, and that Sunoco, Inc. submitted semi-annual compliance reports in 2010 and 2011 andto the EPA that failed to include all of the information required by the regulations. EPA has proposed penalties in excess of $200,000 to resolve the allegations and discussions continue between the parties. The timing or outcome of this matter cannot be reasonably determined at this time, however, we do not expect there to be a material impact to our results of operations, cash flows or financial position. Our pipeline operations are subject to regulation by the U.S.United States Department of Transportation under the PHMSA, pursuant to which the PHMSA has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the PHMSA, through the Office of Pipeline Safety, has promulgated a rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” Activities under these integrity management programs involve the performance of internal pipeline inspections, pressure testing or other effective means to assess the integrity of these regulated pipeline segments, and the regulations require prompt action to address integrity issues raised by the assessment and analysis. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur future capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines; however, no estimate can be made at this time of the likely range of such expenditures. In January 2012, Sunoco Logisticswe experienced a release on itsour products pipeline in Wellington, Ohio. In connection with this release, the PHMSA issued a Corrective Action Order under which Sunoco Logistics iswe are obligated to follow specific requirements in the investigation of the release and the repair and reactivation of the pipeline. Sunoco LogisticsThis PHMSA Corrective Action Order was closed via correspondence dated November 4, 2016. No civil penalties were associated with the PHMSA Order. We also entered into an Order on Consent with the EPA regarding the environmental remediation of the release site. All requirements of the Order on Consent with the EPA have been fulfilled and the Order has been satisfied and closed. Sunoco Logistics hasWe have also received a "No“No Further Action"Action” approval from the Ohio EPA for all soil and groundwater remediation requirements. In May 2016, Sunoco Logisticswe received a proposed penalty from the EPA and U.S. Department of JusticeDOJ associated with this release, and continues to work with the involved parties to bring this matter to closure. The timing and outcome of this matter cannot be reasonably determined at this time. However, Sunoco Logistics doeswe do not expect there to be a material impact to itsour results of operations, cash flows or financial position. In 2012, the EPA issued a proposed consent agreement related to the releases that occurred at Sunoco Logistics’ pump station/tank farm in Barbers Hill, Texas and pump station/tank farm located in Cromwell, Oklahoma in 2010 and 2011, respectively. These matters were referred to the DOJ by the EPA. In November 2012, Sunoco Logistics received an initial assessment of $1.4 million associated with these releases. Sunoco Logistics is in discussions with the EPA and the DOJ on this matter to resolve the issue. The timing or outcome of this matter cannot be reasonably determined at this time. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position. In April 2015 and October 2016, the PHMSA issued separate Noticesa Notice of Probable Violation ("NOPVs"(“NOPVs”) and a Proposed Compliance Order ("PCO"(“PCO”) related to Sunoco Logistics’our West Texas Gulf pipeline in connection with repairs being carried out on the pipeline and other administrative and procedural findings. The proposed penalties arepenalty is in excess of $100,000. Sunoco Logistics doesThe case went to hearing in March 2017 and remains open with PHMSA. We do not expect there to be a material impact to itsour results of operations, cash flows or financial position.
In April 2016, the PHMSA issued a NOPV, PCO and Proposed Civil Penalty related to certain procedures carried out during construction of Sunoco Logistics’our Permian Express 2 pipeline system in Texas. The proposed penalties are in excess of $100,000. Sunoco Logistics doesThe case went to Hearing in November 2016 and remains open with PHMSA. We do not expect there to be a material impact to itsour results of operations, cash flows or financial position. In June 2016, the PHMSA issued NOPVs and a PCO in connection with alleged violations on Sunoco Logistics’ Texas crude oil pipeline system. The proposed penalties are in excess of $100,000. Sunoco Logistics does not expect there to be a material impact to its results of operations, cash flows or financial position.
In July 2016, the PHMSA issued a NOPV and PCO to our West Texas Gulf pipeline in connection with inspection and maintenance activities related to a 2013 incident on Sunoco Logistics'our crude oil pipeline near Wortham, Texas. The proposed penalties are in excess of $100,000,$100,000. The case went to hearing in March 2017 and
Sunoco Logistics is currently in discussions remains open with PHMSA to resolve these matters. The timing or outcome of these matters cannot be reasonably determined at this time, however, Sunoco Logistics doesPHMSA. We do not expect there to be a material impact to itsour results of operations, cash flows, or financial position.
In August 2017, the PHMSA issued a NOPV and a PCO in connection with alleged violations on our Nederland to Kilgore pipeline in Texas. The case remains open with PHMSA and the proposed penalties are in excess of $100,000. We do not expect there to be a material impact to our results of operations, cash flows or financial position. Our operations are also subject to the requirements of the federal OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’sOccupational Safety and Health Administration’s hazardous communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We believe that our past costs for
OSHA required activities, including general industry standards, record keeping requirements, and monitoring of occupational exposure to regulated substances have not had a material adverse effect on our results of operations but there is no assurance that such costs will not be material in the future.
| | 12. | DERIVATIVE ASSETS AND LIABILITIES: |
Commodity Price Risk We are exposed to market risks related to the volatility of commodity prices. To manage the impact of volatility from these prices, we utilize various exchange-traded and OTC commodity financial instrument contracts. These contracts consist primarily of futures, swaps and options and are recorded at fair value in our consolidated balance sheets. We use futures and basis swaps, designated as fair value hedges, to hedge our natural gas inventory stored in our Bammel storage facility. At hedge inception, we lock in a margin by purchasing gas in the spot market or off peak season and entering into a financial contract. Changes in the spreads between the forward natural gas prices and the physical inventory spot price result in unrealized gains or losses until the underlying physical gas is withdrawn and the related designated derivatives are settled. Once the gas is withdrawn and the designated derivatives are settled, the previously unrealized gains or losses associated with these positions are realized. We use futures, swaps and options to hedge the sales price of natural gas we retain for fees in our intrastate transportation and storage segment and operational gas sales on our interstate transportation and storage segment. These contracts are not designated as hedges for accounting purposes. We use NGL and crude derivative swap contracts to hedge forecasted sales of NGL and condensate equity volumes we retain for fees in our midstream segment whereby our subsidiaries generally gather and process natural gas on behalf of producers, sell the resulting residue gas and NGL volumes at market prices and remit to producers an agreed upon percentage of the proceeds based on an index price for the residue gas and NGL. These contracts are not designated as hedges for accounting purposes. We use derivatives in our liquids transportation and services segment to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes. Sunoco Logistics utilizesutilize swaps, futures and other derivative instruments to mitigate the risk associated with market movements in the price of refined products and NGLs.NGLs to manage our storage facilities and the purchase and sale of purity NGL. These contracts are not designated as hedges for accounting purposes.
We use financial commodity derivatives to take advantage of market opportunities in our trading activities which complement our transportation and storage segment’s operations and are netted in cost of products sold in our consolidated statements of operations. We also have trading and marketing activities related to power and natural gas in our all other segment which are also netted in cost of products sold. As a result of our trading activities and the use of derivative financial instruments in our transportation and storage segment, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk oversight committee, which includes members of senior management, and the limits and authorizations set forth in our commodity risk management policy.
The following table details our outstanding commodity-related derivatives: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Notional Volume | | Maturity | | Notional Volume | | Maturity | Notional Volume | | Maturity | | Notional Volume | | Maturity | Mark-to-Market Derivatives | | | | | | | | | | | | | | | (Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Fixed Swaps/Futures | (682,500 | ) | | 2017 | | (602,500 | ) | | 2016-2017 | 1,078 |
| | 2018 | | (683 | ) | | 2017 | Basis Swaps IFERC/NYMEX(1) | 2,242,500 |
| | 2017 | | (31,240,000 | ) | | 2016-2017 | 48,510 |
| | 2018-2020 | | 2,243 |
| | 2017 | Options – Calls | | 13,000 |
| | 2018 | | — |
| | — | Power (Megawatt): | | | | | | | | | Forwards | 391,880 |
| | 2017-2018 | | 357,092 |
| | 2016-2017 | 435,960 |
| | 2018-2019 | | 391,880 |
| | 2017-2018 | Futures | 109,564 |
| | 2017-2018 | | (109,791 | ) | | 2016 | (25,760 | ) | | 2018 | | 109,564 |
| | 2017-2018 | Options – Puts | (50,400 | ) | | 2017 | | 260,534 |
| | 2016 | (153,600 | ) | | 2018 | | (50,400 | ) | | 2017 | Options – Calls | 186,400 |
| | 2017 | | 1,300,647 |
| | 2016 | 137,600 |
| | 2018 | | 186,400 |
| | 2017 | Crude (Bbls) – Futures | (617,000 | ) | | 2017 | | (591,000 | ) | | 2016-2017 | | Crude (MBbls) – Futures | | — |
| | — | | (617 | ) | | 2017 | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | 10,750,000 |
| | 2017-2018 | | (6,522,500 | ) | | 2016-2017 | 4,650 |
| | 2018-2020 | | 10,750 |
| | 2017-2018 | Swing Swaps IFERC | (5,662,500 | ) | | 2017 | | 71,340,000 |
| | 2016-2017 | 87,253 |
| | 2018-2019 | | (5,663 | ) | | 2017 | Fixed Swaps/Futures | (52,652,500 | ) | | 2017-2019 | | (14,380,000 | ) | | 2016-2018 | (4,700 | ) | | 2018-2019 | | (52,653 | ) | | 2017-2019 | Forward Physical Contracts | (22,492,489 | ) | | 2017 | | 21,922,484 |
| | 2016-2017 | (145,105 | ) | | 2018-2020 | | (22,492 | ) | | 2017 | Natural Gas Liquid (Bbls) – Forwards/Swaps | (5,786,627 | ) | | 2017 | | (8,146,800 | ) | | 2016-2018 | | Refined Products (Bbls) – Futures | (2,240,000 | ) | | 2017 | | (939,000 | ) | | 2016-2017 | | Corn (Bushels) – Futures | — |
| | — | | 1,185,000 |
| | 2016 | | Natural Gas Liquid (MBbls) – Forwards/Swaps | | 6,679 |
| | 2018-2019 | | (5,787 | ) | | 2017 | Refined Products (MBbls) – Futures | | (3,783 | ) | | 2018-2019 | | (2,240 | ) | | 2017 | Fair Value Hedging Derivatives | | | | | | | | | (Non-Trading) | | | | | | | | | Natural Gas (MMBtu): | | | | | | Natural Gas (BBtu): | | | | | | Basis Swaps IFERC/NYMEX | (36,370,000 | ) | | 2017 | | (37,555,000 | ) | | 2016 | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Fixed Swaps/Futures | (36,370,000 | ) | | 2017 | | (37,555,000 | ) | | 2016 | (39,770 | ) | | 2018 | | (36,370 | ) | | 2017 | Hedged Item – Inventory | 36,370,000 |
| | 2017 | | 37,555,000 |
| | 2016 | 39,770 |
| | 2018 | | 36,370 |
| | 2017 |
| | (1) | Includes aggregate amounts for open positions related to Houston Ship Channel, Waha Hub, NGPL TexOk, West Louisiana Zone and Henry Hub locations. |
Interest Rate Risk We are exposed to market risk for changes in interest rates. To maintain a cost effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. We also manage our interest rate exposure by utilizing interest rate swaps to achieve a desired mix of fixed and variable rate debt. We also utilize forward starting interest rate swaps to lock in the rate on a portion of our anticipated debt issuances.
The following table summarizes our interest rate swaps outstanding, none of which were designated as hedges for accounting purposes: | | | | | | | | | | | | Term | | Type(1) | | Notional Amount Outstanding | December 31, 2016 | | December 31, 2015 | July 2016(2) | | Forward-starting to pay a fixed rate of 3.80% and receive a floating rate | | $ | — |
| | $ | 200 |
| July 2017(3) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | 500 |
| | 300 |
| July 2018(3) | | Forward-starting to pay a fixed rate of 4.00% and receive a floating rate | | 200 |
| | 200 |
| July 2019(3) | | Forward-starting to pay a fixed rate of 3.25% and receive a floating rate | | 200 |
| | 200 |
| December 2018 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | | 1,200 |
| | 1,200 |
| March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | 300 |
|
| | | | | | | | | | | | Term | | Type(1) | | Notional Amount Outstanding | December 31, 2017 | | December 31, 2016 | July 2017(2) | | Forward-starting to pay a fixed rate of 3.90% and receive a floating rate | | $ | — |
| | $ | 500 |
| July 2018(2) | | Forward-starting to pay a fixed rate of 3.76% and receive a floating rate | | 300 |
| | 200 |
| July 2019(2) | | Forward-starting to pay a fixed rate of 3.64% and receive a floating rate | | 300 |
| | 200 |
| July 2020(2) | | Forward-starting to pay a fixed rate of 3.52% and receive a floating rate | | 400 |
| | — |
| December 2018 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.53% | | 1,200 |
| | 1,200 |
| March 2019 | | Pay a floating rate based on a 3-month LIBOR and receive a fixed rate of 1.42% | | 300 |
| | 300 |
|
| | (1) | Floating rates are based on 3-month LIBOR. |
| | (2) | Represents the effective date. These forward-starting swaps have terms of 10 and 30 years with a mandatory termination date the same as the effective date.
|
| | (3)
| Represents the effective date. These forward-starting swaps have terms of 30 years with a mandatory termination date the same as the effective date. |
Credit Risk Credit risk refers to the risk that a counterparty may default on its contractual obligations resulting in a loss to the Partnership. Credit policies have been approved and implemented to govern the Partnership’s portfolio of counterparties with the objective of mitigating credit losses. These policies establish guidelines, controls and limits to manage credit risk within approved tolerances by mandating an appropriate evaluation of the financial condition of existing and potential counterparties, monitoring agency credit ratings, and by implementing credit practices that limit exposure according to the risk profiles of the counterparties. Furthermore, the Partnership may, at times, require collateral under certain circumstances to mitigate credit risk as necessary. The Partnership also uses industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty or affiliated group of counterparties. The Partnership’s counterparties consist of a diverse portfolio of customers across the energy industry, including petrochemical companies, commercial and industrials, oil and gas producers, municipalities, gas and electric utilities, midstream companies and independent power generators. Our overall exposure may be affected positively or negatively by macroeconomic or regulatory changes that impact our counterparties to one extent or another. Currently, management does not anticipate a material adverse effect in our financial position or results of operations as a consequence of counterparty non-performance. The Partnership has maintenance margin deposits with certain counterparties in the OTC market, primarily independent system operators, and with clearing brokers. Payments on margin deposits are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on or about the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions. Since the margin calls are made daily with the exchange brokers, the fair value of the financial derivative instruments are deemed current and netted in deposits paid to vendors within other current assets in the consolidated balance sheets. For financial instruments, failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated balance sheets and recognized in net income or other comprehensive income.
Derivative Summary The following table provides a summary of our derivative assets and liabilities: | | | Fair Value of Derivative Instruments | Fair Value of Derivative Instruments | | Asset Derivatives | | Liability Derivatives | Asset Derivatives | | Liability Derivatives | | December 31, 2016 | | December 31, 2015 | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | $ | — |
| | $ | 38 |
| | $ | (4 | ) | | $ | (3 | ) | $ | 14 |
| | $ | — |
| | $ | (2 | ) | | $ | (4 | ) | | — |
| | 38 |
| | (4 | ) | | (3 | ) | 14 |
| | — |
| | (2 | ) | | (4 | ) | Derivatives not designated as hedging instruments: | | | | | | | | | | | | | | | Commodity derivatives (margin deposits) | 338 |
| | 353 |
| | (416 | ) | | (306 | ) | 262 |
| | 338 |
| | (281 | ) | | (416 | ) | Commodity derivatives | 24 |
| | 57 |
| | (52 | ) | | (41 | ) | 44 |
| | 24 |
| | (55 | ) | | (52 | ) | Interest rate derivatives | — |
| | — |
| | (193 | ) | | (171 | ) | — |
| | — |
| | (219 | ) | | (193 | ) | Embedded derivatives in ETP Preferred Units | — |
| | — |
| | (1 | ) | | (5 | ) | | Embedded derivatives in Legacy ETP Preferred Units | | — |
| | — |
| | — |
| | (1 | ) | | 362 |
| | 410 |
| | (662 | ) | | (523 | ) | 306 |
| | 362 |
| | (555 | ) | | (662 | ) | Total derivatives | $ | 362 |
| | $ | 448 |
| | $ | (666 | ) | | $ | (526 | ) | $ | 320 |
| | $ | 362 |
| | $ | (557 | ) | | $ | (666 | ) |
The following table presents the fair value of our recognized derivative assets and liabilities on a gross basis and amounts offset on the consolidated balance sheets that are subject to enforceable master netting arrangements or similar arrangements: | | | | Asset Derivatives | | Liability Derivatives | | Asset Derivatives | | Liability Derivatives | | | Balance Sheet Location | | December 31, 2016 | | December 31, 2015 | | December 31, 2016 | | December 31, 2015 | | Balance Sheet Location | | December 31, 2017 | | December 31, 2016 | | December 31, 2017 | | December 31, 2016 | Derivatives without offsetting agreements | | Derivative assets (liabilities) | | $ | — |
| | $ | — |
| | $ | (194 | ) | | $ | (176 | ) | | Derivative liabilities | | $ | — |
| | $ | — |
| | $ | (219 | ) | | $ | (194 | ) | Derivatives in offsetting agreements: | Derivatives in offsetting agreements: | | | | | | | | | Derivatives in offsetting agreements: | | | | | | | | | OTC contracts | | Derivative assets (liabilities) | | 24 |
| | 57 |
| | (52 | ) | | (41 | ) | | Derivative assets (liabilities) | | 44 |
| | 24 |
| | (55 | ) | | (52 | ) | Broker cleared derivative contracts | | Other current assets | | 338 |
| | 391 |
| | (420 | ) | | (309 | ) | | Other current assets (liabilities) | | 276 |
| | 338 |
| | (283 | ) | | (420 | ) | | | | 362 |
| | 448 |
| | (666 | ) | | (526 | ) | | | 320 |
| | 362 |
| | (557 | ) | | (666 | ) | Offsetting agreements: | Offsetting agreements: | | | | | | | | | Offsetting agreements: | | | | | | | | | Counterparty netting | | Derivative assets (liabilities) | | (4 | ) | | (17 | ) | | 4 |
| | 17 |
| | Derivative assets (liabilities) | | (20 | ) | | (4 | ) | | 20 |
| | 4 |
| Payments on margin deposit | | Other current assets | | (338 | ) | | (309 | ) | | 338 |
| | 309 |
| | Counterparty netting | | | Other current assets (liabilities) | | (263 | ) | | (338 | ) | | 263 |
| | 338 |
| Total net derivatives | Total net derivatives | | $ | 20 |
| | $ | 122 |
| | $ | (324 | ) | | $ | (200 | ) | Total net derivatives | | $ | 37 |
| | $ | 20 |
| | $ | (274 | ) | | $ | (324 | ) |
We disclose the non-exchange traded financial derivative instruments as price risk management assets and liabilities on our consolidated balance sheets at fair value with amounts classified as either current or long-term depending on the anticipated settlement date.
The following tables summarize the amounts recognized with respect to our derivative financial instruments: | | | Location of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | | Amount of Gain/(Loss) Reclassified from AOCI into Income (Effective Portion) | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | | | Years Ended December 31, | | Years Ended December 31, | | | 2016 | | 2015 | | 2014 | | 2017 | | 2016 | | 2015 | Derivatives in cash flow hedging relationships: | | | | | | | | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | — |
| | $ | — |
| | $ | (3 | ) | Cost of products sold | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
| Total | | $ | — |
| | $ | — |
| | $ | (3 | ) | | $ | 26 |
| | $ | 14 |
| | $ | 21 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income Representing Hedge Ineffectiveness and Amount Excluded from the Assessment of Effectiveness | | | | Years Ended December 31, | | | | 2016 | | 2015 | | 2014 | Derivatives in fair value hedging relationships (including hedged item): | | | | | | | | Commodity derivatives | Cost of products sold | | $ | 14 |
| | $ | 21 |
| | $ | (8 | ) | Total | | | $ | 14 |
| | $ | 21 |
| | $ | (8 | ) |
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income on Derivatives | | | | Years Ended December 31, | | | | 2017 | | 2016 | | 2015 | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | 31 |
| | $ | (35 | ) | | $ | (11 | ) | Commodity derivatives – Non-trading | Cost of products sold | | 3 |
| | (173 | ) | | 23 |
| Interest rate derivatives | Losses on interest rate derivatives | | (37 | ) | | (12 | ) | | (18 | ) | Embedded derivatives | Other, net | | 1 |
| | 4 |
| | 12 |
| Total | | | $ | (2 | ) | | $ | (216 | ) | | $ | 6 |
|
| | | | | | | | | | | | | | | | Location of Gain/(Loss) Recognized in Income on Derivatives | | Amount of Gain (Loss) Recognized in Income on Derivatives | | | | Years Ended December 31, | | | | 2016 | | 2015 | | 2014 | Derivatives not designated as hedging instruments: | | | | | | | | Commodity derivatives – Trading | Cost of products sold | | $ | (35 | ) | | $ | (11 | ) | | $ | (6 | ) | Commodity derivatives – Non-trading | Cost of products sold | | (173 | ) | | 23 |
| | 199 |
| Interest rate derivatives | Losses on interest rate derivatives | | (12 | ) | | (18 | ) | | (157 | ) | Embedded derivatives | Other, net | | 4 |
| | 12 |
| | 3 |
| Total | | | $ | (216 | ) | | $ | 6 |
| | $ | 39 |
|
Savings and Profit Sharing Plans We and our subsidiaries sponsor defined contribution savings and profit sharing plans, which collectively cover virtually all eligible employees. Employer matching contributions are calculated using a formula based on employee contributions. We and our subsidiaries made matching contributions of $38 million, $44 million $39 million and $50$39 million to these 401(k) savings plans for the years ended December 31, 2017, 2016, 2015, and 20142015, respectively. Pension and Other Postretirement Benefit Plans Panhandle Postretirement benefits expense for the years ended December 31, 2017, 2016 and 2015 reflect the impact of changes Panhandle or its affiliates adopted as of September 30, 2013, to modify its retiree medical benefits program, effective January 1, 2014. The modification placed all eligible retirees on a common medical benefit platform, subject to limits on Panhandle’s annual contribution toward eligible retirees’ medical premiums. Prior to January 1, 2013, affiliates of Panhandle offered postretirement
health care and life insurance benefit plans (other postretirement plans) that covered substantially all employees. Effective January 1, 2013, participation in the plan was frozen and medical benefits were no longer offered to non-union employees. Effective January 1, 2014, retiree medical benefits were no longer offered to union employees. Sunoco, Inc. Sunoco, Inc. sponsors a defined benefit pension plan, which was frozen for most participants on June 30, 2010. On October 31, 2014, Sunoco, Inc. terminated the plan, and paid lump sums to eligible active and terminated vested participants in December 2015.
Sunoco, Inc. also has a plan which provides health care benefits for substantially all of its current retirees. The cost to provide the postretirement benefit plan is shared by Sunoco, Inc. and its retirees. Access to postretirement medical benefits was phased out or eliminated for all employees retiring after July 1, 2010. In March, 2012, Sunoco, Inc. established a trust for its postretirement benefit liabilities. Sunoco made a tax-deductible contribution of approximately $200 million to the trust. The funding of the trust eliminated substantially all of Sunoco, Inc.’s future exposure to variances between actual results and assumptions used to estimate retiree medical plan obligations.
Obligations and Funded Status Pension and other postretirement benefit liabilities are accrued on an actuarial basis during the years an employee provides services. The following table contains information at the dates indicated about the obligations and funded status of pension and other postretirement plans on a combined basis: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Change in benefit obligation: | | | | | | | | | | | | | | | | | | | | | | | Benefit obligation at beginning of period | $ | 20 |
| | $ | 57 |
| | $ | 180 |
| | $ | 718 |
| | $ | 65 |
| | $ | 202 |
| $ | 18 |
| | $ | 51 |
| | $ | 165 |
| | $ | 20 |
| | $ | 57 |
| | $ | 180 |
| Interest cost | 1 |
| | 2 |
| | 4 |
| | 23 |
| | 2 |
| | 4 |
| 1 |
| | 1 |
| | 4 |
| | 1 |
| | 2 |
| | 4 |
| Amendments | | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| Benefits paid, net | (1 | ) | | (7 | ) | | (21 | ) | | (46 | ) | | (8 | ) | | (20 | ) | (2 | ) | | (6 | ) | | (20 | ) | | (1 | ) | | (7 | ) | | (21 | ) | Actuarial (gain) loss and other | (2 | ) | | (1 | ) | | 2 |
| | 16 |
| | (2 | ) | | (6 | ) | 2 |
| | 1 |
| | (1 | ) | | (2 | ) | | (1 | ) | | 2 |
| Settlements | — |
| | — |
| | — |
| | (691 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Benefit obligation at end of period | 18 |
| | 51 |
| | 165 |
| | 20 |
| | 57 |
| | 180 |
| 1 |
| | 47 |
| | 155 |
| | 18 |
| | 51 |
| | 165 |
| | | | | | | | | | | | | | | | | | | | | | | | Change in plan assets: | | | | | | | | | | | | | | | | | | | | | | | Fair value of plan assets at beginning of period | 15 |
| | — |
| | 253 |
| | 598 |
| | — |
| | 265 |
| 12 |
| | — |
| | 248 |
| | 15 |
| | — |
| | 253 |
| Return on plan assets and other | (2 | ) | | — |
| | 6 |
| | 16 |
| | — |
| | — |
| 3 |
| | — |
| | 11 |
| | (2 | ) | | — |
| | 6 |
| Employer contributions | — |
| | — |
| | 10 |
| | 138 |
| | — |
| | 8 |
| 6 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| Benefits paid, net | (1 | ) | | — |
| | (21 | ) | | (46 | ) | | — |
| | (20 | ) | (2 | ) | | — |
| | (20 | ) | | (1 | ) | | — |
| | (21 | ) | Settlements | — |
| | — |
| | — |
| | (691 | ) | | — |
| | — |
| (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| Fair value of plan assets at end of period | 12 |
| | — |
| | 248 |
| | 15 |
| | — |
| | 253 |
| 1 |
| | — |
| | 249 |
| | 12 |
| | — |
| | 248 |
| | | | | | | | | | | | | | | | | | | | | | | | Amount underfunded (overfunded) at end of period | $ | 6 |
| | $ | 51 |
| | $ | (83 | ) | | $ | 5 |
| | $ | 57 |
| | $ | (73 | ) | $ | — |
| | $ | 47 |
| | $ | (94 | ) | | $ | 6 |
| | $ | 51 |
| | $ | (83 | ) | | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in the consolidated balance sheets consist of: | | | | | | | | | | | | | | | | | | | | | | | Non-current assets | $ | — |
| | $ | — |
| | $ | 108 |
| | $ | — |
| | $ | — |
| | $ | 97 |
| $ | — |
| | $ | — |
| | $ | 120 |
| | $ | — |
| | $ | — |
| | $ | 108 |
| Current liabilities | — |
| | (7 | ) | | (2 | ) | | — |
| | (9 | ) | | (2 | ) | — |
| | (8 | ) | | (2 | ) | | — |
| | (7 | ) | | (2 | ) | Non-current liabilities | (6 | ) | | (44 | ) | | (23 | ) | | (5 | ) | | (48 | ) | | (22 | ) | — |
| | (39 | ) | | (24 | ) | | (6 | ) | | (44 | ) | | (23 | ) | | $ | (6 | ) | | $ | (51 | ) | | $ | 83 |
| | $ | (5 | ) | | $ | (57 | ) | | $ | 73 |
| $ | — |
| | $ | (47 | ) | | $ | 94 |
| | $ | (6 | ) | | $ | (51 | ) | | $ | 83 |
| | | | | | | | | | | | | | | | | | | | | | | | Amounts recognized in accumulated other comprehensive income (loss) (pre-tax basis) consist of: | | | | | | | | | | | | | | | | | | | | | | | Net actuarial gain | $ | — |
| | $ | — |
| | $ | (12 | ) | | $ | 2 |
| | $ | 4 |
| | $ | (17 | ) | $ | — |
| | $ | 5 |
| | $ | (17 | ) | | $ | — |
| | $ | — |
| | $ | (12 | ) | Prior service cost | — |
| | — |
| | 14 |
| | — |
| | — |
| | 15 |
| — |
| | — |
| | 20 |
| | — |
| | — |
| | 14 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 2 |
| | $ | 4 |
| | $ | (2 | ) | $ | — |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 2 |
|
The following table summarizes information at the dates indicated for plans with an accumulated benefit obligation in excess of plan assets: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | | | Pension Benefits | | | Pension Benefits | | | | Pension Benefits | | | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits | Projected benefit obligation | $ | 18 |
| | $ | 51 |
| | N/A |
| | $ | 20 |
| | $ | 57 |
| | N/A |
| $ | 1 |
| | $ | 47 |
| | N/A |
| | $ | 18 |
| | $ | 51 |
| | N/A |
| Accumulated benefit obligation | 18 |
| | 51 |
| | $ | 165 |
| | 20 |
| | 57 |
| | $ | 180 |
| 1 |
| | 47 |
| | $ | 155 |
| | 18 |
| | 51 |
| | $ | 165 |
| Fair value of plan assets | 12 |
| | — |
| | 248 |
| | 15 |
| | — |
| | 253 |
| 1 |
| | — |
| | 249 |
| | 12 |
| | — |
| | 248 |
|
Components of Net Periodic Benefit Cost | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Net periodic benefit cost: | | | | | | | | | | | | | | | Interest cost | $ | 3 |
| | $ | 4 |
| | $ | 25 |
| | $ | 4 |
| $ | 2 |
| | $ | 4 |
| | $ | 3 |
| | $ | 4 |
| Expected return on plan assets | (1 | ) | | (8 | ) | | (16 | ) | | (8 | ) | — |
| | (9 | ) | | (1 | ) | | (8 | ) | Prior service cost amortization | — |
| | 1 |
| | — |
| | 1 |
| — |
| | 2 |
| | — |
| | 1 |
| Settlements | — |
| | — |
| | 32 |
| | — |
| — |
| | — |
| | — |
| | — |
| Net periodic benefit cost | $ | 2 |
| | $ | (3 | ) | | $ | 41 |
| | $ | (3 | ) | $ | 2 |
| | $ | (3 | ) | | $ | 2 |
| | $ | (3 | ) |
Assumptions The weighted-average assumptions used in determining benefit obligations at the dates indicated are shown in the table below: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.65 | % | | 2.34 | % | | 3.59 | % | | 2.38 | % | 3.27 | % | | 2.34 | % | | 3.65 | % | | 2.34 | % | Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
| N/A |
| | N/A |
| | N/A |
| | N/A |
|
The weighted-average assumptions used in determining net periodic benefit cost for the periods presented are shown in the table below: | | | December 31, 2016 | | December 31, 2015 | December 31, 2017 | | December 31, 2016 | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | Discount rate | 3.60 | % | | 3.06 | % | | 3.65 | % | | 2.79 | % | 3.52 | % | | 3.10 | % | | 3.60 | % | | 3.06 | % | Expected return on assets: | | | | | | | | | | | | | | | Tax exempt accounts | 3.50 | % | | 7.00 | % | | 7.50 | % | | 7.00 | % | 3.50 | % | | 7.00 | % | | 3.50 | % | | 7.00 | % | Taxable accounts | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | N/A |
| | 4.50 | % | | N/A |
| | 4.50 | % | Rate of compensation increase | N/A |
| | N/A |
| | N/A |
| | N/A |
| N/A |
| | N/A |
| | N/A |
| | N/A |
|
The long-term expected rate of return on plan assets was estimated based on a variety of factors including the historical investment return achieved over a long-term period, the targeted allocation of plan assets and expectations concerning future returns in the marketplace for both equity and fixed income securities. Current market factors such as inflation and interest rates are evaluated before long-term market assumptions are determined. Peer data and historical returns are reviewed to ensure reasonableness and appropriateness. The assumed health care cost trend rates used to measure the expected cost of benefits covered by Panhandle and Sunoco, Inc.’s other postretirement benefit plans are shown in the table below: | | | | December 31, | | December 31, | | | 2016 | | 2015 | | 2017 | | 2016 | Health care cost trend rate | | 6.73 | % | | 7.16 | % | | 7.20 | % | | 6.73 | % | Rate to which the cost trend is assumed to decline (the ultimate trend rate) | | 4.96 | % | | 5.39 | % | | 4.99 | % | | 4.96 | % | Year that the rate reaches the ultimate trend rate | | 2021 |
| | 2018 |
| | 2023 |
| | 2021 |
|
Changes in the health care cost trend rate assumptions are not expected to have a significant impact on postretirement benefits. Plan Assets For the Panhandle plans, the overall investment strategy is to maintain an appropriate balance of actively managed investments with the objective of optimizing longer-term returns while maintaining a high standard of portfolio quality and achieving proper diversification. To achieve diversity within its other postretirement plan asset portfolio, Panhandle has targeted the following asset allocations: equity of 25% to 35%, fixed income of 65% to 75% and cash and cash equivalents of up to 10%. The investment strategy of Sunoco, Inc. funded defined benefit plans is to achieve consistent positive returns, after adjusting for inflation, and to maximize long-term total return within prudent levels of risk through a combination of income and capital appreciation. The objective of this strategy is to reduce the volatility of investment returns and maintain a sufficient funded status of the plans. In anticipation of the pension plan termination, Sunoco, Inc. targeted the asset allocations to a more stable position by investing in growth assets and liability hedging assets. The fair value of the pension plan assets by asset category at the dates indicated is as follows: | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2017 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Mutual funds(1) | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| Total | $ | 1 |
| | $ | 1 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of approximately 100% equities as of December 31, 2017. |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2016 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Mutual funds(1) | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
| Total | $ | 12 |
| | $ | 12 |
| | $ | — |
| | $ | — |
|
| | (1) | Comprised of approximately 100% equities as of December 31, 2016. |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2015 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Mutual funds(1) | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
| Total | $ | 15 |
| | $ | — |
| | $ | 15 |
| | $ | — |
|
| | (1)
| Comprised of approximately 100% equities as of December 31, 2015. |
The fair value of other postretirement plan assets by asset category at the dates indicated is as follows: | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2017 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 146 |
| | 146 |
| | — |
| | — |
| Fixed income securities | 70 |
| | — |
| | 70 |
| | — |
| Total | $ | 249 |
| | $ | 179 |
| | $ | 70 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 48% equities, 51% fixed income securities and 1% cash as of December 31, 2017. |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2016 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 23 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 134 |
| | 134 |
| | — |
| | — |
| Fixed income securities | 91 |
| | — |
| | 91 |
| | — |
| Total | $ | 248 |
| | $ | 157 |
| | $ | 91 |
| | $ | — |
|
| | (1) | Primarily comprised of approximately 31% equities, 66% fixed income securities and 3% cash as of December 31, 2016. |
| | | | | | | | | | | | | | | | | | | | Fair Value Measurements at December 31, 2015 | | Fair Value Total | | Level 1 | | Level 2 | | Level 3 | Asset category: | | | | | | | | Cash and cash equivalents | $ | 18 |
| | $ | 18 |
| | $ | — |
| | $ | — |
| Mutual funds(1) | 133 |
| | 133 |
| | — |
| | — |
| Fixed income securities | 102 |
| | — |
| | 102 |
| | — |
| Total | $ | 253 |
| | $ | 151 |
| | $ | 102 |
| | $ | — |
|
| | (1)
| Primarily comprised of approximately 56% equities, 33% fixed income securities and 11% cash as of December 31, 2015. |
The Level 1 plan assets are valued based on active market quotes. The Level 2 plan assets are valued based on the net asset value per share (or its equivalent) of the investments, which was not determinable through publicly published sources but was calculated consistent with authoritative accounting guidelines. Contributions We expect to contribute $12$8 million to pension plans and $10 million to other postretirement plans in 2017.2018. The cost of the plans are funded in accordance with federal regulations, not to exceed the amounts deductible for income tax purposes. Benefit Payments Panhandle and Sunoco, Inc.’s estimate of expected benefit payments, which reflect expected future service, as appropriate, in each of the next five years and in the aggregate for the five years thereafter are shown in the table below: | | | | Pension Benefits | | | | | | | | Years | | Funded Plans | | Unfunded Plans | | Other Postretirement Benefits (Gross, Before Medicare Part D) | | Pension Benefits - Unfunded Plans (1) | | Other Postretirement Benefits (Gross, Before Medicare Part D) | 2017 | | $ | 1 |
| | $ | 7 |
| | $ | 26 |
| | 2018 | | 1 |
| | 7 |
| | 25 |
| | $ | 8 |
| | $ | 24 |
| 2019 | | 1 |
| | 6 |
| | 23 |
| | 6 |
| | 23 |
| 2020 | | 1 |
| | 6 |
| | 22 |
| | 6 |
| | 21 |
| 2021 | | 1 |
| | 5 |
| | 19 |
| | 5 |
| | 19 |
| 2022 – 2026 | | 6 |
| | 17 |
| | 39 |
| | 2022 | | | 4 |
| | 17 |
| 2023 – 2027 | | | 15 |
| | 37 |
|
(1) Expected benefit payments of funded pension plans are less than $1 million for the next ten years. The Medicare Prescription Drug Act provides for a prescription drug benefit under Medicare (“Medicare Part D”) as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Panhandle does not expect to receive any Medicare Part D subsidies in any future periods.
| | 14. | RELATED PARTY TRANSACTIONS: |
In June 2017, the Partnership acquired all of the publicly held PennTex common units through a tender offer and exercise of a limited call right, as further discussed in Note 8. ETE has agreements with subsidiaries to provide or receive various general and administrative services. ETE payspreviously paid us to provide services on its behalf and on behalf of other subsidiaries of ETE, which includesincluded the reimbursement of various operating and general and administrative expenses incurred by us on behalf of ETE and its subsidiaries. In January 2016, ETE and ETP agreed to extend the $95 million annual management fee paid to ETP through These agreements expired in 2016.
The Partnership also has related party transactions with several of its equity method investees. In addition to commercial transactions, these transactions include the provision of certain management services and leases of certain assets. The following table summarizes the affiliate revenues on our consolidated statements of operations: | | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Affiliated revenues | $ | 377 |
| | $ | 417 |
| | $ | 965 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Affiliated revenues | $ | 697 |
| | $ | 377 |
| | $ | 417 |
|
The following table summarizes the related company balances on our consolidated balance sheets: | | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Accounts receivable from related companies: | | | | | | | ETE | $ | 22 |
| | $ | 110 |
| $ | — |
| | $ | 22 |
| Sunoco LP | 96 |
| | 3 |
| 219 |
| | 96 |
| PES | 6 |
| | 10 |
| | FGT | 15 |
| | 13 |
| 11 |
| | 15 |
| Lake Charles LNG | 4 |
| | 36 |
| | Trans-Pecos Pipeline, LLC | 1 |
| | 29 |
| | Comanche Trail Pipeline, LLC | — |
| | 22 |
| | Other | 65 |
| | 45 |
| 88 |
| | 76 |
| Total accounts receivable from related companies | $ | 209 |
| | $ | 268 |
| $ | 318 |
| | $ | 209 |
| | | | | | | | Accounts payable to related companies: | | | | | | | ETE | $ | — |
| | $ | 1 |
| | Sunoco LP | 20 |
| | 5 |
| 195 |
| | 20 |
| FGT | 1 |
| | 1 |
| | Lake Charles LNG | 3 |
| | 3 |
| | Other | 19 |
| | 15 |
| 14 |
| | 23 |
| Total accounts payable to related companies | $ | 43 |
| | $ | 25 |
| $ | 209 |
| | $ | 43 |
|
| | | December 31, | December 31, | | 2016 | | 2015 | 2017 | | 2016 | Long-term notes receivable (payable) – related companies: | | | | | | | Sunoco LP | $ | 87 |
| | $ | (233 | ) | $ | 85 |
| | $ | 87 |
| Phillips 66 | (250 | ) | | — |
| — |
| | (250 | ) | Net long-term notes receivable (payable) – related companies | $ | (163 | ) | | $ | (233 | ) | $ | 85 |
| | $ | (163 | ) |
Our financial statements currently reflect the following reportable segments, which conduct their business in the United States, as follows: •intrastate transportation and storage; •interstate transportation and storage; •midstream; •liquidsNGL and refined products transportation and services; •investment in Sunoco Logistics;crude oil transportation and services; and •all other. The Partnership previously presented its retail marketing business as a separate reportable segment. Due to the transfer of the general partner interest of Sunoco LP from ETP to ETE in 2015 and completion of the dropdown of remaining Retail Marketing interests from ETP to Sunoco LP in March 2016, all of the Partnership’s retail marketing business has been deconsolidated. The only remaining retail marketing assets are the limited partner units of Sunoco LP. As of December 31, 2016,2017, the Partnership’s interest in Sunoco LP common units consisted of 43.5 million units, representing 44.3%43.6% of Sunoco LP’s total outstanding common units. Subsequent to Sunoco LP’s repurchase of a portion of its common units on February 7, 2018, our investment consists of 26.2 million units, representing 31.8% of Sunoco LP’s total outstanding common units. This equity method investment in Sunoco LP has now been aggregated into the all other segment. Consequently, the retail marketing business that was previously consolidated has also been aggregated in the all other segment for all periods presented. Intersegment and intrasegment transactions are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions.
Revenues from our intrastate transportation and storage segment are primarily reflected in natural gas sales and gathering, transportation and other fees. Revenues from our interstate transportation and storage segment are primarily reflected in gathering, transportation and other fees. Revenues from our midstream segment are primarily reflected in natural gas sales, NGL sales and gathering, transportation and other fees. Revenues from our liquidsNGL and refined products transportation and services segment are primarily reflected in NGL sales and gathering, transportation, terminalling and other fees. Revenues from our investment in Sunoco Logisticscrude oil transportation and services segment are primarily reflected in crude sales. Revenues from our all other segment are primarily reflected in refined product sales. We report Segment Adjusted EBITDA as a measure of segment performance. We define Segment Adjusted EBITDA as earnings before interest, taxes, depreciation, depletion, amortization and other non-cash items, such as non-cash compensation expense, gains and losses on disposals of assets, the allowance for equity funds used during construction, unrealized gains and losses on commodity risk management activities, non-cash impairment charges, losses on extinguishments of debt and other non-operating income or expense items. Unrealized gains and losses on commodity risk management activities include unrealized gains and losses on commodity derivatives and inventory fair value adjustments (excluding lower of cost or market adjustments). Segment Adjusted EBITDA reflects amounts for unconsolidated affiliates based on the Partnership’s proportionate ownership.
The following tables present financial information by segment: | | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Revenues: | | | | | | | | | | | Intrastate transportation and storage: | | | | | | | | | | | Revenues from external customers | $ | 2,155 |
| | $ | 1,912 |
| | $ | 2,645 |
| $ | 2,891 |
| | $ | 2,155 |
| | $ | 1,912 |
| Intersegment revenues | 458 |
| | 338 |
| | 212 |
| 192 |
| | 458 |
| | 338 |
| | 2,613 |
| | 2,250 |
| | 2,857 |
| 3,083 |
| | 2,613 |
| | 2,250 |
| Interstate transportation and storage: | | | | | | | | | | | Revenues from external customers | 946 |
| | 1,008 |
| | 1,057 |
| 915 |
| | 946 |
| | 1,008 |
| Intersegment revenues | 23 |
| | 17 |
| | 15 |
| 19 |
| | 23 |
| | 17 |
| | 969 |
| | 1,025 |
| | 1,072 |
| 934 |
| | 969 |
| | 1,025 |
| Midstream: | | | | | | | | | | | Revenues from external customers | 2,342 |
| | 2,607 |
| | 4,770 |
| 2,510 |
| | 2,342 |
| | 2,607 |
| Intersegment revenues | 2,837 |
| | 2,449 |
| | 2,053 |
| 4,433 |
| | 2,837 |
| | 2,449 |
| | 5,179 |
| | 5,056 |
| | 6,823 |
| 6,943 |
| | 5,179 |
| | 5,056 |
| Liquids transportation and services: | | | | | | | NGL and refined products transportation and services: | | | | | | | Revenues from external customers | 4,498 |
| | 3,247 |
| | 3,730 |
| 8,326 |
| | 5,973 |
| | 4,569 |
| Intersegment revenues | 299 |
| | 249 |
| | 181 |
| 322 |
| | 436 |
| | 428 |
| | 4,797 |
| | 3,496 |
| | 3,911 |
| 8,648 |
| | 6,409 |
| | 4,997 |
| Investment in Sunoco Logistics: | | | | | | | Crude oil transportation and services: | | | | | | | Revenues from external customers | 9,015 |
| | 10,302 |
| | 17,920 |
| 11,672 |
| | 7,539 |
| | 8,980 |
| Intersegment revenues | 136 |
| | 184 |
| | 168 |
| 31 |
| | — |
| | — |
| | 9,151 |
| | 10,486 |
| | 18,088 |
| 11,703 |
| | 7,539 |
| | 8,980 |
| All other: | | | | | | | | | | | Revenues from external customers | 2,871 |
| | 15,216 |
| | 25,353 |
| 2,740 |
| | 2,872 |
| | 15,216 |
| Intersegment revenues | 400 |
| | 558 |
| | 465 |
| 161 |
| | 400 |
| | 558 |
| | 3,271 |
| | 15,774 |
| | 25,818 |
| 2,901 |
| | 3,272 |
| | 15,774 |
| Eliminations | (4,153 | ) | | (3,795 | ) | | (3,094 | ) | (5,158 | ) | | (4,154 | ) | | (3,790 | ) | Total revenues | $ | 21,827 |
| | $ | 34,292 |
| | $ | 55,475 |
| $ | 29,054 |
| | $ | 21,827 |
| | $ | 34,292 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Cost of products sold: | | | | | | | | | | | Intrastate transportation and storage | $ | 1,897 |
| | $ | 1,554 |
| | $ | 2,169 |
| $ | 2,327 |
| | $ | 1,897 |
| | $ | 1,554 |
| Midstream | 3,381 |
| | 3,264 |
| | 4,893 |
| 4,761 |
| | 3,381 |
| | 3,264 |
| Liquids transportation and services | 3,673 |
| | 2,597 |
| | 3,166 |
| | Investment in Sunoco Logistics | 7,658 |
| | 9,307 |
| | 17,135 |
| | NGL and refined products transportation and services | | 6,508 |
| | 4,553 |
| | 3,431 |
| Crude oil transportation and services | | 9,826 |
| | 6,416 |
| | 8,158 |
| All other | 2,942 |
| | 14,029 |
| | 24,129 |
| 2,509 |
| | 2,942 |
| | 14,029 |
| Eliminations | (4,157 | ) | | (3,722 | ) | | (3,078 | ) | (5,130 | ) | | (4,109 | ) | | (3,722 | ) | Total cost of products sold | $ | 15,394 |
| | $ | 27,029 |
| | $ | 48,414 |
| $ | 20,801 |
| | $ | 15,080 |
| | $ | 26,714 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Depreciation, depletion and amortization: | | | | | | | | | | | Intrastate transportation and storage | $ | 144 |
| | $ | 129 |
| | $ | 125 |
| $ | 147 |
| | $ | 144 |
| | $ | 129 |
| Interstate transportation and storage | 207 |
| | 210 |
| | 203 |
| 214 |
| | 207 |
| | 210 |
| Midstream | 844 |
| | 720 |
| | 569 |
| 954 |
| | 840 |
| | 720 |
| Liquids transportation and services | 156 |
| | 126 |
| | 113 |
| | Investment in Sunoco Logistics | 446 |
| | 382 |
| | 296 |
| | NGL and refined products transportation and services | | 401 |
| | 355 |
| | 290 |
| Crude oil transportation and services | | 402 |
| | 251 |
| | 218 |
| All other | 189 |
| | 362 |
| | 363 |
| 214 |
| | 189 |
| | 362 |
| Total depreciation, depletion and amortization | $ | 1,986 |
| | $ | 1,929 |
| | $ | 1,669 |
| $ | 2,332 |
| | $ | 1,986 |
| | $ | 1,929 |
|
| | | Years Ended December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Equity in earnings (losses) of unconsolidated affiliates: | | | | | | | | | | | Intrastate transportation and storage | $ | 35 |
| | $ | 32 |
| | $ | 27 |
| $ | (156 | ) | | $ | 35 |
| | $ | 32 |
| Interstate transportation and storage | 193 |
| | 197 |
| | 196 |
| 236 |
| | 193 |
| | 197 |
| Midstream | 19 |
| | (19 | ) | | 10 |
| 20 |
| | 19 |
| | (19 | ) | Liquids transportation and services | 3 |
| | (2 | ) | | (3 | ) | | Investment in Sunoco Logistics | 34 |
| | 21 |
| | 23 |
| | NGL and refined products transportation and services | | 33 |
| | 41 |
| | 29 |
| Crude oil transportation and services | | 4 |
| | (4 | ) | | (9 | ) | All other | (225 | ) | | 240 |
| | 79 |
| 19 |
| | (225 | ) | | 239 |
| Total equity in earnings of unconsolidated affiliates | $ | 59 |
| | $ | 469 |
| | $ | 332 |
| $ | 156 |
| | $ | 59 |
| | $ | 469 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2017 | | 2016 | | 2015 | Segment Adjusted EBITDA: | | | | | | Intrastate transportation and storage | $ | 626 |
| | $ | 613 |
| | $ | 543 |
| Interstate transportation and storage | 1,098 |
| | 1,117 |
| | 1,155 |
| Midstream | 1,481 |
| | 1,133 |
| | 1,237 |
| NGL and refined products transportation and services | 1,641 |
| | 1,496 |
| | 1,179 |
| Crude oil transportation and services | 1,379 |
| | 834 |
| | 521 |
| All other | 487 |
| | 540 |
| | 882 |
| Total Segment Adjusted EBITDA | 6,712 |
| | 5,733 |
| | 5,517 |
| Depreciation, depletion and amortization | (2,332 | ) | | (1,986 | ) | | (1,929 | ) | Interest expense, net | (1,365 | ) | | (1,317 | ) | | (1,291 | ) | Gains on acquisitions | — |
| | 83 |
| | — |
| Impairment losses | (920 | ) | | (813 | ) | | (339 | ) | Losses on interest rate derivatives | (37 | ) | | (12 | ) | | (18 | ) | Non-cash unit-based compensation expense | (74 | ) | | (80 | ) | | (79 | ) | Unrealized gains (losses) on commodity risk management activities | 56 |
| | (131 | ) | | (65 | ) | Inventory valuation adjustments | — |
| | — |
| | 58 |
| Losses on extinguishments of debt | (42 | ) | | — |
| | (43 | ) | Adjusted EBITDA related to unconsolidated affiliates | (984 | ) | | (946 | ) | | (937 | ) | Equity in earnings from unconsolidated affiliates | 156 |
| | 59 |
| | 469 |
| Impairment of investments in unconsolidated affiliates | (313 | ) | | (308 | ) | | — |
| Other, net | 148 |
| | 115 |
| | 23 |
| Income before income tax benefit | $ | 1,005 |
| | $ | 397 |
| | $ | 1,366 |
|
| | | | | | | | | | | | | | Years Ended December 31, | | 2016 | | 2015 | | 2014 | Segment Adjusted EBITDA: | | | | | | Intrastate transportation and storage | $ | 613 |
| | $ | 543 |
| | $ | 559 |
| Interstate transportation and storage | 1,117 |
| | 1,155 |
| | 1,212 |
| Midstream | 1,133 |
| | 1,237 |
| | 1,318 |
| Liquids transportation and services | 968 |
| | 744 |
| | 591 |
| Investment in Sunoco Logistics | 1,233 |
| | 1,153 |
| | 971 |
| All other | 541 |
| | 882 |
| | 1,059 |
| Total Segment Adjusted EBITDA | 5,605 |
| | 5,714 |
| | 5,710 |
| Depreciation, depletion and amortization | (1,986 | ) | | (1,929 | ) | | (1,669 | ) | Interest expense, net | (1,317 | ) | | (1,291 | ) | | (1,165 | ) | Gains on acquisitions | 83 |
| | — |
| | — |
| Gain on sale of AmeriGas common units | — |
| | — |
| | 177 |
| Impairment losses | (813 | ) | | (339 | ) | | (370 | ) | Losses on interest rate derivatives | (12 | ) | | (18 | ) | | (157 | ) | Non-cash unit-based compensation expense | (80 | ) | | (79 | ) | | (68 | ) | Unrealized gains (losses) on commodity risk management activities | (131 | ) | | (65 | ) | | 112 |
| Inventory valuation adjustments | 170 |
| | (104 | ) | | (473 | ) | Losses on extinguishments of debt | — |
| | (43 | ) | | (25 | ) | Adjusted EBITDA related to discontinued operations | — |
| | — |
| | (27 | ) | Adjusted EBITDA related to unconsolidated affiliates | (946 | ) | | (937 | ) | | (748 | ) | Equity in earnings from unconsolidated affiliates | 59 |
| | 469 |
| | 332 |
| Impairment of investment in an unconsolidated affiliate | (308 | ) | | — |
| | — |
| Other, net | 114 |
| | 20 |
| | (36 | ) | Income from continuing operations before income tax expense (benefit) | $ | 438 |
| | $ | 1,398 |
| | $ | 1,593 |
|
| | | | | | | | | | | | | | December 31, | | 2017 | | 2016 | | 2015 | Assets: | | | | | | Intrastate transportation and storage | $ | 5,020 |
| | $ | 5,176 |
| | $ | 4,882 |
| Interstate transportation and storage | 13,518 |
| | 10,833 |
| | 11,345 |
| Midstream | 20,004 |
| | 17,873 |
| | 17,039 |
| NGL and refined products transportation and services | 17,600 |
| | 14,074 |
| | 11,568 |
| Crude oil transportation and services | 17,736 |
| | 15,909 |
| | 10,941 |
| All other | 4,087 |
| | 6,240 |
| | 9,353 |
| Total assets | $ | 77,965 |
| | $ | 70,105 |
| | $ | 65,128 |
|
| | | December 31, | Years Ended December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Assets: | | | | | | | Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (capital expenditures related to the Partnership’s proportionate ownership on an accrual basis): | | | | | | | Intrastate transportation and storage | $ | 5,164 |
| | $ | 4,882 |
| | $ | 4,983 |
| $ | 175 |
| | $ | 76 |
| | $ | 105 |
| Interstate transportation and storage | 10,833 |
| | 11,345 |
| | 10,779 |
| 726 |
| | 280 |
| | 866 |
| Midstream | 18,011 |
| | 17,111 |
| | 15,562 |
| 1,308 |
| | 1,255 |
| | 2,174 |
| Liquids transportation and services | 11,296 |
| | 7,235 |
| | 4,568 |
| | Investment in Sunoco Logistics | 18,819 |
| | 15,423 |
| | 13,619 |
| | NGL and refined products transportation and services | | 2,971 |
| | 2,198 |
| | 2,853 |
| Crude oil transportation and services | | 453 |
| | 1,841 |
| | 1,358 |
| All other | 6,068 |
| | 9,177 |
| | 13,007 |
| 268 |
| | 160 |
| | 811 |
| Total assets | $ | 70,191 |
| | $ | 65,173 |
| | $ | 62,518 |
| | Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) | | $ | 5,901 |
| | $ | 5,810 |
| | $ | 8,167 |
|
| | | Years Ended December 31, | December 31, | | 2016 | | 2015 | | 2014 | 2017 | | 2016 | | 2015 | Additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis): | | | | | | | Advances to and investments in unconsolidated affiliates: | | | | | | | Intrastate transportation and storage | $ | 76 |
| | $ | 105 |
| | $ | 169 |
| $ | 85 |
| | $ | 399 |
| | $ | 406 |
| Interstate transportation and storage | 280 |
| | 860 |
| | 411 |
| 2,118 |
| | 2,149 |
| | 2,516 |
| Midstream | 1,255 |
| | 2,172 |
| | 1,298 |
| 126 |
| | 111 |
| | 117 |
| Liquids transportation and services | 2,316 |
| | 2,109 |
| | 427 |
| | Investment in Sunoco Logistics | 1,739 |
| | 2,126 |
| | 2,510 |
| | NGL and refined products transportation and services | | 234 |
| | 235 |
| | 258 |
| Crude oil transportation and services | | 22 |
| | 18 |
| | 21 |
| All other | 144 |
| | 795 |
| | 679 |
| 1,231 |
| | 1,368 |
| | 1,685 |
| Total additions to property, plant and equipment excluding acquisitions, net of contributions in aid of construction costs (accrual basis) | $ | 5,810 |
| | $ | 8,167 |
| | $ | 5,494 |
| | Total advances to and investments in unconsolidated affiliates | | $ | 3,816 |
| | $ | 4,280 |
| | $ | 5,003 |
|
| | | | | | | | | | | | | | December 31, | | 2016 | | 2015 | | 2014 | Advances to and investments in unconsolidated affiliates: | | | | | | Intrastate transportation and storage | $ | 387 |
| | $ | 406 |
| | $ | 423 |
| Interstate transportation and storage | 2,149 |
| | 2,516 |
| | 2,649 |
| Midstream | 111 |
| | 117 |
| | 138 |
| Liquids transportation and services | 29 |
| | 32 |
| | 31 |
| Investment in Sunoco Logistics | 224 |
| | 247 |
| | 226 |
| All other | 1,380 |
| | 1,685 |
| | 293 |
| Total advances to and investments in unconsolidated affiliates | $ | 4,280 |
| | $ | 5,003 |
| | $ | 3,760 |
|
| | 16. | QUARTERLY FINANCIAL DATA (UNAUDITED): |
Summarized unaudited quarterly financial data is presented below. The sum of net income per Limited Partner unit by quarter does not equal the net income per limited partner unit for the year due to the computation of income allocation between the General Partner and Limited Partners and variations in the weighted average units outstanding used in computing such amounts. | | | | Quarters Ended | | | | Quarters Ended | | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | | March 31* | | June 30* | | September 30* | | December 31 | | Total Year | 2016: | | | | | | | | | | | | 2017: | | | | | | | | | | | | Revenues | | $ | 4,481 |
| | $ | 5,289 |
| | $ | 5,531 |
| | $ | 6,526 |
| | $ | 21,827 |
| | $ | 6,895 |
| | $ | 6,576 |
| | $ | 6,973 |
| | $ | 8,610 |
| | $ | 29,054 |
| Operating income (loss) | | 614 |
| | 715 |
| | 638 |
| | (165 | ) | | 1,802 |
| | Net income (loss) | | 376 |
| | 472 |
| | 138 |
| | (362 | ) | | 624 |
| | Operating income | | | 683 |
| | 736 |
| | 779 |
| | 199 |
| | 2,397 |
| Net income | | | 393 |
| | 296 |
| | 715 |
| | 1,097 |
| | 2,501 |
| Common Unitholders’ interest in net income (loss) | | (67 | ) | | 60 |
| | (241 | ) | | (762 | ) | | (1,010 | ) | | 32 |
| | (49 | ) | | 335 |
| | 668 |
| | 986 |
| Basic net income (loss) per Common Unit | | $ | (0.15 | ) | | $ | 0.10 |
| | $ | (0.49 | ) | | $ | (1.47 | ) | | $ | (2.06 | ) | | $ | 0.03 |
| | $ | (0.04 | ) | | $ | 0.29 |
| | $ | 0.57 |
| | $ | 0.94 |
| Diluted net income (loss) per Common Unit | | $ | (0.15 | ) | | $ | 0.10 |
| | $ | (0.49 | ) | | $ | (1.47 | ) | | $ | (2.06 | ) | | $ | 0.03 |
| | $ | (0.04 | ) | | $ | 0.29 |
| | $ | 0.57 |
| | $ | 0.93 |
|
| | | | Quarters Ended | | | | Quarters Ended | | | | | March 31 | | June 30 | | September 30 | | December 31 | | Total Year | | March 31* | | June 30* | | September 30* | | December 31* | | Total Year* | 2015: | | | | | | | | | | | | 2016: | | | | | | | | | | | | Revenues | | $ | 10,326 |
| | $ | 11,540 |
| | $ | 6,601 |
| | $ | 5,825 |
| | $ | 34,292 |
| | $ | 4,481 |
| | $ | 5,289 |
| | $ | 5,531 |
| | $ | 6,526 |
| | $ | 21,827 |
| Operating income | | 608 |
| | 888 |
| | 576 |
| | 187 |
| | 2,259 |
| | 598 |
| | 708 |
| | 594 |
| | (139 | ) | | 1,761 |
| Net income | | 268 |
| | 839 |
| | 393 |
| | 21 |
| | 1,521 |
| | 360 |
| | 465 |
| | 94 |
| | (336 | ) | | 583 |
| Common Unitholders’ interest in net income (loss) | | (48 | ) | | 298 |
| | 59 |
| | (327 | ) | | (18 | ) | | (71 | ) | | 58 |
| | (252 | ) | | (754 | ) | | (1,019 | ) | Basic net income (loss) per Common Unit | | $ | (0.17 | ) | | $ | 0.67 |
| | $ | 0.11 |
| | $ | (0.68 | ) | | $ | (0.09 | ) | | $ | (0.11 | ) | | $ | 0.06 |
| | $ | (0.34 | ) | | $ | (0.97 | ) | | $ | (1.38 | ) | Diluted net income (loss) per Common Unit | | $ | (0.17 | ) | | $ | 0.67 |
| | $ | 0.10 |
| | $ | (0.68 | ) | | $ | (0.10 | ) | | $ | (0.11 | ) | | $ | 0.06 |
| | $ | (0.34 | ) | | $ | (0.97 | ) | | $ | (1.38 | ) |
* As adjusted. See Note 2. A reconciliation of amounts previously reported in Forms 10-Q to the quarterly data has not been presented due to immateriality. The three months ended December 31, 20162017 and 2015 reflected the unfavorable impacts of $27 million and $120 million, respectively, related to non-cash inventory valuation adjustments primarily in our investment in Sunoco Logistics and all other segments. The three months ended December 31, 2016 and 2015 reflected the recognition of impairment losses of $920 million and $813 million, respectively. Impairment losses in 2017 were primarily related to our Trunkline, SUG Holdings, CDM, Sea Robin and $339 million, respectively.refined products reporting units. Impairment losses in 2016 were primarily related to our PEPL reporting unit, Sea Robin reporting unit and midstream midcontinent operations. In 2015, impairment losses were primarily related to Lone Star Refinery Services operations and our Transwestern pipeline. The three months ended December 31, 2017 and September 30, 2016 reflected the recognition of a non-cash impairment of our investmentinvestments in MEPsubsidiaries of $313 million and $308 million, respectively, in our interstate transportation and storage segment. For certain periods reflected above, distributions paid for the period exceeded net income attributable to partners. Accordingly, the distributions paid to the General Partner, including incentive distributions, further exceeded net income, and as a result, a net loss was allocated to the Limited Partners for the period.
| | 17. | CONSOLIDATING GUARANTOR FINANCIAL INFORMATION |
Prior to the Sunoco Logistics Merger, Sunoco Logistics Partners Operations L.P., a subsidiary of Sunoco Logistics was the issuer of multiple series of senior notes that were guaranteed by Sunoco Logistics. Subsequent to the Sunoco Logistics Merger, these notes continue to be guaranteed by the parent company. These guarantees are full and unconditional. For the purposes of this footnote, Energy Transfer Partners, L.P. is referred to as “Parent Guarantor” and Sunoco Logistics Partners Operations L.P. is referred to as “Subsidiary Issuer.” All other consolidated subsidiaries of the Partnership are collectively referred to as “Non-Guarantor Subsidiaries.”
The following supplemental condensed consolidating financial information reflects the Parent Guarantor’s separate accounts, the Subsidiary Issuer’s separate accounts, the combined accounts of the Non-Guarantor Subsidiaries, the combined consolidating adjustments and eliminations, and the Parent Guarantor’s consolidated accounts for the dates and periods indicated. For purposes of the following condensed consolidating information, the Parent Guarantor’s investments in its subsidiaries and the Subsidiary Issuer’s investments in its subsidiaries are accounted for under the equity method of accounting. To present the supplemental condensed consolidating financial information on a comparable basis, the prior period financial information has been recast as if the Sunoco Logistics Merger occurred on January 1, 2015. The consolidating financial information for the Parent Guarantor, Subsidiary Issuer and Non-Guarantor Subsidiaries are as follows: | | | | | | | | | | | | | | | | | | | | | | December 31, 2017 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash and cash equivalents | $ | — |
| | $ | (3 | ) | | $ | 309 |
| | $ | — |
| | $ | 306 |
| All other current assets | — |
| | 159 |
| | 6,063 |
| | — |
| | 6,222 |
| Property, plant and equipment | — |
| | — |
| | 58,437 |
| | — |
| | 58,437 |
| Investments in unconsolidated affiliates | 48,378 |
| | 11,648 |
| | 3,816 |
| | (60,026 | ) | | 3,816 |
| All other assets | — |
| | — |
| | 9,184 |
| | — |
| | 9,184 |
| Total assets | $ | 48,378 |
| | $ | 11,804 |
| | $ | 77,809 |
| | $ | (60,026 | ) | | $ | 77,965 |
| | | | | | | | | | | Current liabilities | (1,496 | ) | | (3,660 | ) | | 12,150 |
| | — |
| | 6,994 |
| Non-current liabilities | 21,604 |
| | 7,607 |
| | 7,609 |
| | — |
| | 36,820 |
| Noncontrolling interest | — |
| | — |
| | 5,882 |
| | — |
| | 5,882 |
| Total partners’ capital | 28,270 |
| | 7,857 |
| | 52,168 |
| | (60,026 | ) | | 28,269 |
| Total liabilities and equity | $ | 48,378 |
| | $ | 11,804 |
| | $ | 77,809 |
| | $ | (60,026 | ) | | $ | 77,965 |
|
| | | | | | | | | | | | | | | | | | | | | | December 31, 2016 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash and cash equivalents | $ | — |
| | $ | 41 |
| | $ | 319 |
| | $ | — |
| | $ | 360 |
| All other current assets | — |
| | 2 |
| | 5,281 |
| | — |
| | 5,283 |
| Property, plant and equipment | — |
| | — |
| | 50,917 |
| | — |
| | 50,917 |
| Investments in unconsolidated affiliates | 23,350 |
| | 10,664 |
| | 4,280 |
| | (34,014 | ) | | 4,280 |
| All other assets | — |
| | 5 |
| | 9,260 |
| | — |
| | 9,265 |
| Total assets | $ | 23,350 |
| | $ | 10,712 |
| | $ | 70,057 |
| | $ | (34,014 | ) | | $ | 70,105 |
| | | | | | | | | | | Current liabilities | (1,761 | ) | | (3,800 | ) | | 11,764 |
| | — |
| | 6,203 |
| Non-current liabilities | 299 |
| | 7,313 |
| | 30,148 |
| | (299 | ) | | 37,461 |
| Noncontrolling interest | — |
| | — |
| | 1,232 |
| | — |
| | 1,232 |
| Total partners’ capital | 24,812 |
| | 7,199 |
| | 26,913 |
| | (33,715 | ) | | 25,209 |
| Total liabilities and equity | $ | 23,350 |
| | $ | 10,712 |
| | $ | 70,057 |
| | $ | (34,014 | ) | | $ | 70,105 |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2017 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Revenues | $ | — |
| | $ | — |
| | $ | 29,054 |
| | $ | — |
| | $ | 29,054 |
| Operating costs, expenses, and other | — |
| | 1 |
| | 26,656 |
| | — |
| | 26,657 |
| Operating income (loss) | — |
| | (1 | ) | | 2,398 |
| | — |
| | 2,397 |
| Interest expense, net | — |
| | (156 | ) | | (1,209 | ) | | — |
| | (1,365 | ) | Equity in earnings of unconsolidated affiliates | 2,564 |
| | 1,242 |
| | 156 |
| | (3,806 | ) | | 156 |
| Impairment of investments in unconsolidated affiliate | — |
| | — |
| | (313 | ) | | — |
| | (313 | ) | Losses on interest rate derivatives | — |
| | — |
| | (37 | ) | | — |
| | (37 | ) | Other, net | — |
| | — |
| | 168 |
| | (1 | ) | | 167 |
| Income before income tax benefit | 2,564 |
| | 1,085 |
| | 1,163 |
| | (3,807 | ) | | 1,005 |
| Income tax benefit | — |
| | — |
| | (1,496 | ) | | — |
| | (1,496 | ) | Net income | 2,564 |
| | 1,085 |
| | 2,659 |
| | (3,807 | ) | | 2,501 |
| Less: Net income attributable to noncontrolling interest | — |
| | — |
| | 420 |
| | — |
| | 420 |
| Net income attributable to partners | $ | 2,564 |
| | $ | 1,085 |
| | $ | 2,239 |
| | $ | (3,807 | ) | | $ | 2,081 |
| | | | | | | | | | | Other comprehensive income (loss) | $ | — |
| | $ | — |
| | $ | (5 | ) | | $ | — |
| | $ | (5 | ) | Comprehensive income | 2,564 |
| | 1,085 |
| | 2,654 |
| | (3,807 | ) | | 2,496 |
| Comprehensive income attributable to noncontrolling interest | — |
| | — |
| | 420 |
| | — |
| | 420 |
| Comprehensive income attributable to partners | $ | 2,564 |
| | $ | 1,085 |
| | $ | 2,234 |
| | $ | (3,807 | ) | | $ | 2,076 |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2016 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Revenues | $ | — |
| | $ | — |
| | $ | 21,827 |
| | $ | — |
| | $ | 21,827 |
| Operating costs, expenses, and other | — |
| | 1 |
| | 20,065 |
| | — |
| | 20,066 |
| Operating income (loss) | — |
| | (1 | ) | | 1,762 |
| | — |
| | 1,761 |
| Interest expense, net | — |
| | (157 | ) | | (1,160 | ) | | — |
| | (1,317 | ) | Equity in earnings of unconsolidated affiliates | 554 |
| | 863 |
| | 59 |
| | (1,417 | ) | | 59 |
| Impairment of investment in unconsolidated affiliate | — |
| | — |
| | (308 | ) | | — |
| | (308 | ) | Losses on interest rate derivatives | — |
| | — |
| | (12 | ) | | — |
| | (12 | ) | Other, net | — |
| | — |
| | 214 |
| | — |
| | 214 |
| Income before income tax benefit | 554 |
| | 705 |
| | 555 |
| | (1,417 | ) | | 397 |
| Income tax benefit | — |
| | — |
| | (186 | ) | | — |
| | (186 | ) | Net income | 554 |
| | 705 |
| | 741 |
| | (1,417 | ) | | 583 |
| Less: Net income attributable to noncontrolling interest | — |
| | — |
| | 41 |
| | — |
| | 41 |
| Net income attributable to partners | $ | 554 |
| | $ | 705 |
| | $ | 700 |
| | $ | (1,417 | ) | | $ | 542 |
| | | | | | | | | | | Other comprehensive income | $ | — |
| | $ | — |
| | $ | 4 |
| | $ | — |
| | $ | 4 |
| Comprehensive income | 554 |
| | 705 |
| | 745 |
| | (1,417 | ) | | 587 |
| Comprehensive income attributable to noncontrolling interest | — |
| | — |
| | 41 |
| | — |
| | 41 |
| Comprehensive income attributable to partners | $ | 554 |
| | $ | 705 |
| | $ | 704 |
| | $ | (1,417 | ) | | $ | 546 |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2015 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Revenues | $ | — |
| | $ | — |
| | $ | 34,292 |
| | $ | — |
| | $ | 34,292 |
| Operating costs, expenses, and other | — |
| | 1 |
| | 32,064 |
| | — |
| | 32,065 |
| Operating income (loss) | — |
| | (1 | ) | | 2,228 |
| | — |
| | 2,227 |
| Interest expense, net | — |
| | (133 | ) | | (1,158 | ) | | — |
| | (1,291 | ) | Equity in earnings of unconsolidated affiliates | 1,441 |
| | 526 |
| | 469 |
| | (1,967 | ) | | 469 |
| Losses on interest rate derivatives | — |
| | — |
| | (18 | ) | | — |
| | (18 | ) | Other, net | — |
| | — |
| | (21 | ) | | — |
| | (21 | ) | Income before income tax benefit | 1,441 |
| | 392 |
| | 1,500 |
| | (1,967 | ) | | 1,366 |
| Income tax benefit | — |
| | — |
| | (123 | ) | | — |
| | (123 | ) | Net income | 1,441 |
| | 392 |
| | 1,623 |
| | (1,967 | ) | | 1,489 |
| Less: Net income attributable to noncontrolling interest | — |
| | — |
| | 53 |
| | — |
| | 53 |
| Net income attributable to partners | $ | 1,441 |
| | $ | 392 |
| | $ | 1,570 |
| | $ | (1,967 | ) | | $ | 1,436 |
| | | | | | | | | | | Other comprehensive income | $ | — |
| | $ | — |
| | $ | 60 |
| | $ | — |
| | $ | 60 |
| Comprehensive income | 1,441 |
| | 392 |
| | 1,683 |
| | (1,967 | ) | | 1,549 |
| Comprehensive income attributable to noncontrolling interest | — |
| | — |
| | 53 |
| | — |
| | 53 |
| Comprehensive income attributable to partners | $ | 1,441 |
| | $ | 392 |
| | $ | 1,630 |
| | $ | (1,967 | ) | | $ | 1,496 |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2017 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash flows from operating activities | $ | 2,564 |
| | $ | 1,047 |
| | $ | 4,681 |
| | $ | (3,807 | ) | | $ | 4,485 |
| Cash flows from investing activities | (2,240 | ) | | (1,368 | ) | | (5,672 | ) | | 3,807 |
| | (5,473 | ) | Cash flows from financing activities | (324 | ) | | 277 |
| | 981 |
| | — |
| | 934 |
| Change in cash | — |
| | (44 | ) | | (10 | ) | | — |
| | (54 | ) | Cash at beginning of period | — |
| | 41 |
| | 319 |
| | — |
| | 360 |
| Cash at end of period | $ | — |
| | $ | (3 | ) | | $ | 309 |
| | $ | — |
| | $ | 306 |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2016 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash flows from operating activities | $ | 553 |
| | $ | 675 |
| | $ | 3,492 |
| | $ | (1,417 | ) | | $ | 3,303 |
| Cash flows from investing activities | (976 | ) | | (2,400 | ) | | (4,431 | ) | | 1,417 |
| | (6,390 | ) | Cash flows from financing activities | 423 |
| | 1,729 |
| | 768 |
| | — |
| | 2,920 |
| Change in cash | — |
| | 4 |
| | (171 | ) | | — |
| | (167 | ) | Cash at beginning of period | — |
| | 37 |
| | 490 |
| | — |
| | 527 |
| Cash at end of period | $ | — |
| | $ | 41 |
| | $ | 319 |
| | $ | — |
| | $ | 360 |
|
| | | | | | | | | | | | | | | | | | | | | | Year Ended December 31, 2015 | | Parent Guarantor | | Subsidiary Issuer | | Non-Guarantor Subsidiaries | | Eliminations | | Consolidated Partnership | Cash flows from operating activities | $ | 1,441 |
| | $ | 388 |
| | $ | 2,886 |
| | $ | (1,968 | ) | | $ | 2,747 |
| Cash flows from investing activities | (2,271 | ) | | (1,815 | ) | | (5,702 | ) | | 1,968 |
| | (7,820 | ) | Cash flows from financing activities | 830 |
| | 1,363 |
| | 2,744 |
| | — |
| | 4,937 |
| Change in cash | — |
| | (64 | ) | | (72 | ) | | — |
| | (136 | ) | Cash at beginning of period | — |
| | 101 |
| | 562 |
| | — |
| | 663 |
| Cash at end of period | $ | — |
| | $ | 37 |
| | $ | 490 |
| | $ | — |
| | $ | 527 |
|
|